1407 W North Temple, Suite 310
Salt Lake City, Utah 84114
November 9, 2016
VIA ELECTRONIC FILING
AND OVERNIGHT DELIVERY
Utah Public Service Commission
Heber M. Wells Building, 4th Floor
160 East 300 South
Salt Lake City, UT 84114
Attention:
Gary Widerburg
Commission Secretary
RE:
Docket No. 14-035-114 - In the Matter of the Investigation of the Costs and
Benefits of PacifiCorp’s Net Metering Program
Pursuant to Utah Code Annotated § 54-15-105.1 (“Net Metering Statute”) and the Order issued
by the Public Service Commission of Utah (“Commission”) in this docket on November 10,
2015, Rocky Mountain Power hereby submits for filing an original and ten copies of this
Compliance Filing and Request to Complete All Analyses Required Under the Net Metering
Statute for the Evaluation of the Net Metering Program (“Compliance Filing”). The Compliance
Filing consists of the filing, direct testimony of five witnesses and exhibits, and work files
supporting the Compliance Filing. The Company will also provide an electronic version of this
filing to [email protected]. Confidential electronic materials will be provided via CD.
Rocky Mountain Power respectfully requests that all formal correspondence and requests for
additional information regarding this filing be addressed to the following:
By E-mail (preferred):
[email protected]
[email protected]
[email protected]
By regular mail:
Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
Informal inquiries may be directed to Bob Lively at (801) 220-4052.
Sincerely,
Jeffrey K. Larsen
Vice President, Regulation
CC:
Service List - Docket No. 14-035-114
CERTIFICATE OF SERVICE
I hereby certify that on this 9th of November, 2016, a true and correct copy of the
foregoing document was served by email and/or overnight mail on the following Parties
in Docket No. 14-035-114:
Division of Public Utilities
Chris Parker (C)
Division of Public Utilities
160 East 300 South, 4th Floor
Salt Lake City, UT 84111
[email protected]
William Powell (C)
Division of Public Utilities
160 East 300 South, 4th Floor
Salt Lake City, UT 84111
[email protected]
Erika Tedder (C)
Division of Public Utilities
160 East 300 South, 4th Floor
Salt Lake City, UT 84111
[email protected]
Utah Office of Consumer Services
Michele Beck (C)
Utah Office of Consumer Services
160 East 300 South, 2nd Floor
Salt Lake City, UT 84111
[email protected]
Cheryl Murray (C)
Utah Office of Consumer Services
160 East 300 South, 2nd Floor
Salt Lake City, UT 84111
[email protected]
Bela Vastag (C)
Utah Office of Consumer Services
160 East 300 South, 2nd Floor
Salt Lake City, UT 84111
[email protected]
Assistant Utah Attorney General
Patricia Schmid (C)
Assistant Attorney General
160 East 300 South, 5th Floor
P.O. Box 140857
Salt Lake City, Utah 84114-0857
[email protected]
Justin Jetter (C)
Assistant Attorney General
160 East 300 South, 5th Floor
P.O. Box 140857
Salt Lake City, Utah 84114-0857
[email protected]
Rex Olsen (C)
Assistant Attorney General
160 East 300 South, 5th Floor
P.O. Box 140857
Salt Lake City, Utah 84114-0857
[email protected]
1
The Alliance for Solar Choice
Bruce Plenk
The Alliance for Solar Choice
2958 N. St. Augustine Pl.
Tucson, AZ 85712
[email protected]
Thadeus B. Culley (C)
The Alliance for Solar Choice
2958 N. St. Augustine Pl.
Tucson, AZ 85712
[email protected]
Anne Smart
[email protected]
UCARE
Michael D. Rossetti
UCARE
13051 Shadowlands Lane
Draper, UT 84020-8785
[email protected]
Stanley T. Holmes
UCARE
13051 Shadowlands Lane
Draper, UT 84020-8785
[email protected]
Sierra Club
Travis Ritchie
Sierra Club
85 Second Street, 2nd Floor
San Francisco, CA 94105
[email protected]
Casey Roberts
Sierra Club
85 Second Street, 2nd Floor
San Francisco, CA 94105
[email protected]
Derek Nelson
[email protected]
Energy Strategies
Kevin Higgins
ENERGY STRATEGIES
215 S. State Street, #200
Salt Lake City, UT 84111
[email protected]
Neal Townsend
ENERGY STRATEGIES
215 S. State Street, #200
Salt Lake City, UT 84111
[email protected]
Utah Solar Energy Association
Elias Bishop
[email protected]
Chad Hofheins
[email protected]
Ballard Spahr
Jerold G. Oldroyd
[email protected]
Theresa A. Foxley
[email protected]
Parsons Behle & Latimer
William J. Evans
[email protected]
Vicki M. Baldwin
[email protected]
Brickfield, Burchette, Ritts & Stone, P.C.
Peter J. Mattheis
[email protected]
Eric J. Lacey
[email protected]
2
Boehm, Kurtz & Lowry
Kurt J. Boehm, Esq.
[email protected]
Jody Kyler Cohn, Esq.
[email protected]
Utah Clean Energy
Sarah Wright
Utah Clean Energy
1014 2nd Avenue
Salt Lake City, UT 84111
[email protected]
Kate Bowman
Utah Clean Energy
1014 2nd Avenue
Salt Lake City, UT 84111
[email protected]
Sophie Hayes (C)
Utah Clean Energy
1014 2nd Avenue
Salt Lake City, UT 84111
[email protected]
USAF Utility Law Field Support Center
Capt. Thomas A. Jernigan
[email protected]
Mrs. Karen White
[email protected]
PacifiCorp, dba Rocky Mountain Power
Data Request Response Center
PacifiCorp
825 NE Multnomah Street, Suite 2000
Portland, Oregon 97232
[email protected]
D. Matthew Moscon
Attorney for Rocky Mountain Power
[email protected]
Bob Lively
[email protected]
Yvonne Hogle
[email protected]
Daniel Solander
[email protected]
Tyler Poulson
[email protected]
Hatch James & Dodge
Gary A. Dodge
Hatch James & Dodge
10 West Broadway, Suite 400
Salt Lake City, UT 84101
[email protected]
Interstate Renewable Energy Council, Inc.
Sara Baldwin Auck
[email protected]
3
Vivint Solar
Stephen F. Mecham
[email protected]
Parsons Kinghorn Harris, P.C.
Jeremy R. Cook
[email protected]
E-Quant Consulting LLC
Robert Swenson
[email protected]
Keyes, Fox & Wiedman LLP
David Wooley
[email protected]
IBEW Local 57
Arthur F. Sandack, Esq
[email protected]
Callister Nebeker & McCullough
Brian W. Burnett, Esq.
[email protected]
J. Kennedy & Associates
Stephen J. Baron
[email protected]
Greeenberg Traurig
Meshach Y. Rhoades, Esq.
[email protected]
Wal-mart Stores
Steve W. Chriss
[email protected]
SW Energy Efficiency Project
Christine Brinker
[email protected]
____________________________________
Jennifer Angell
Supervisor, Regulatory Operations
4
R. Jeff Richards (7294)
Yvonne R. Hogle (7550)
Emily Wegener (12275)
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
Telephone No. (801) 220-4050
Facsimile No. (801) 220-3299
E-mail: [email protected]
E-mail: [email protected]
E-mail: [email protected]
D. Matthew Moscon (6947)
Gregory B. Monson (2294)
Stoel Rives LLP
201 South Main Street, Suite 1100
Salt Lake City, Utah 84111
Telephone No. (801) 578-6929
Facsimile No. (801) 578-6999
E-mail: [email protected]
E-mail: [email protected]
Attorneys for Rocky Mountain Power
BEFORE THE PUBLIC SERVICE COMMISSION OF UTAH
Docket No. 14-035-114
COMPLIANCE FILING AND REQUEST
TO COMPLETE ALL ANALYSES
REQUIRED UNDER THE NET
METERING STATUTE FOR THE
EVALUATION OF THE NET
METERING PROGRAM
In the Matter of the Investigation of the
Costs and Benefits of PacifiCorp’s Net
Metering Program
INTRODUCTION
Pursuant to Utah Code Ann. § 54-15-105.1 (the "Net Metering Statute") and the Order
issued by the Public Service Commission of Utah (“Commission”) in this docket on November
10, 2015 (“November 2015 Order”), Rocky Mountain Power, a division of PacifiCorp
(“Company” or “Rocky Mountain Power”), submits this Compliance Filing and Request to
Complete All Analyses Required under the Net Metering Statute for the Evaluation of the Net
1
Metering Program (“Compliance Filing”). In this Compliance Filing, the Company provides the
Commission with the actual and counterfactual cost of service studies (“ACOS” and “CFCOS”),
which were ordered by the Commission and were performed using calendar year 2015 actual data
collected from the Company’s load research study. The Company asks the Commission to:
(1)
find that the CFCOS, the ACOS, and the net metering breakout cost of service study
(“NEM Breakout COS”) are compliant with and fulfill the November 2015 Order;
(2)
find, based on the cost of service analyses, that the costs of the net metering program
under the current rate structure exceed its benefits;
(3)
find, based on the cost of service analyses, that the unique usage characteristics of
net metering customers justify segregating them into a distinct class;
(4)
determine that the current rate structure for net metering customers is unjust and
unreasonable because it does not reflect the costs imposed on and benefits contributed
to the system, and unfairly shifts costs from net metering customers to other
customers;
(5)
approve, as just and reasonable, the Company’s proposed Schedule 136, Net Metering
Service, with modifications to net metering service and Schedule 5, Residential
Service for Customer Generators, which includes a three-part tariff structure that
reflects the costs and benefits that net metering customers impose on and contribute
to the system; and
(6)
approve a waiver of Utah Admin. R. 746-312-13, pursuant to Utah Admin. R. 746312-3(2) for changes to the application fee, as explained in more detail below.
Concurrently with this filing, the Company is filing Advice 16-13 which requests the
Commission to close currently effective residential net metering Schedule 135 to new service and
2
approve and implement Schedule 135A, effective December 10, 2016, on a temporary basis until
the Commission issues its decision pursuant to the Net Metering Statute. The Company anticipates
that part of the Commission’s decision in this Compliance Filing will be to approve Schedule 136
and its related Schedule 5 tariff, for electric Company service to residential net metering customers.
SUMMARY
A. Compliance Filing
This Compliance Filing includes the studies that comply with the November 2015 Order,
enabling the Commission to complete the evaluation of the Company’s net metering program
required by the Net Metering Statute. The Net Metering Statute requires the Commission to
“determine a just and reasonable charge, credit or ratemaking structure, including new or existing
tariffs, in light of the costs and benefits of the net metering program.” Consistent with the
framework directed by the Commission in the November 2015 Order, the Company prepared the
ACOS, CFCOS and NEM Breakout COS that use calendar year 2015 actual load and production
data collected from the Company’s load research study. The ACOS, CFCOS and NEM Breakout
COS were also prepared consistent with Commission-approved standards that have evolved over
many years.1 The Company’s data demonstrates that the costs of the net metering program do, in
fact, exceed its benefits and that customers with private solar generation systems have unique load
and cost characteristics that support a new rate structure from the rest of the residential class.
Recent exponential growth of the net metering program, evident in the data supporting this filing
and described in detail below and in testimony, precipitated this Compliance Filing and the
1
Company witness Robert Meredith discusses how the cost of service studies were prepared consistent with
Commission-approved standards.
3
concurrent tariff advice letter filing, requesting immediate relief.2 The Company proposes to
replace the current rate structure with a three-part rate structure that will include a fixed monthly
charge, a demand charge, and an energy charge. Proposed Schedule 5 reflects the costs imposed
on, and the benefits contributed to, the system by net metering customers. In the interim, the
Company proposes a temporary tariff for net metering service as described in Section B below.
The Company supports renewable resources and customer options for renewable resources.
However, the options should be provided consistent with an appropriate rate structure that allows
residential customers to use private solar generation without adversely affecting other residential
customers. The combination of declining prices of private solar generation systems, continued
availability of government subsidies and the kilowatt-hour compensation for excess generation
have contributed to the rapid growth of private solar generation. This growth renders the current
ratemaking structure unsustainable; accordingly, that structure must change. As is demonstrated
by the results of the comparison of the ACOS to the CFCOS, under the current net metering
program, the costs of the net metering program exceed the benefits to the system, and results in
costs that will be unfairly borne by all other customers. For the net metering program to continue
and be sustainable in the future, its rate structure must be modified to accurately reflect its impact
on the system and to properly allocate costs between customers as part of a proper rate design.
B. Tariff Advice Filing No. 16-13
Proposed Schedule 135A will be used to provide net metering services to new net metering
customers on the same terms as Schedule 135 until the Commission’s ruling on this Compliance
Filing and approval of proposed Schedule 136, or other tariff. Under proposed Schedule 135A,
2
As part of this docket, the Commission left open the possibility of addressing the ratemaking structure of the net
metering program, “in a further phase of this docket, a general rate case or other appropriate proceeding.” November
2015 Order at 1.
4
customers who apply for residential net metering would be required to take service through a
different meter, as under the current tariff,3 and would be on notice that, when proposed Schedule
136 or another tariff is approved, they will receive service under that schedule.
The Company’s proposal offers a sustainable, long-term solution that is consistent with the
state’s policy of encouraging, and the Company’s commitment to, cost-effective renewable energy.
The proposed rate structure reflects the costs and benefits that residential net metering customers
impose on and contribute to the system, and is consistent with the cost of service analyses. It
produces rates that are “just and reasonable … in light of the costs and benefits”4 of the net
metering program and is equitable to other customers.
C. Compliance Filing Support
The Compliance Filing is supported by the testimony of the following witnesses:
Mr. Gary H. Hoogeveen provides an overview of the major components of the Company’s
filings, explains why the Company’s proposals should be adopted consistent with the state policy
of encouraging, and the Company’s commitment to, cost-effective renewable resources, and
identifies the witnesses who will present detailed testimony supporting the filings.
Ms. Joelle R. Steward explains the proposed tariff changes in this Compliance Filing,
including policy considerations of cost of service and rate design and the unique usage
characteristics and loads of net metering customers that justify their segregation into a different
class. Ms. Steward’s testimony also explains the proposed new rates for residential customer
generators that include a three-part rate structure designed to capture a monthly basic charge, a
demand charge and an energy charge. She explains that the proposed rates are based on the same
level of costs reflected in the Company’s 2014 general rate case, Docket No. 13-035-184 (“2014
3
4
Utah Code Ann. § 54-15-103(4)(a).
Utah Code Ann. § 54-15-105.1(2).
5
GRC”). Ms. Steward's testimony also supports the Company's proposed changes to the application
fees for the net metering program, including adding a fee for Level 1 applications, which will
require a waiver of rule R746-312-13. Ms. Steward’s testimony explains that the Company's
proposed changes to the fees are based on an assessment of the actual costs incurred to process
applications and that recovery of the costs to process them, particularly for Level 1, has not kept
pace with the growth in applications.
Mr. Robert M. Meredith explains the inputs and results of the ACOS, CFCOS and the NEM
Breakout COS. He also describes the load research study for private solar generation, and the
incorporation of that data into the cost of service studies.
Mr. Douglas L. Marx supports the engineering and administrative costs that are included
in the cost of service studies and explains how private solar generation facilities can impact
distribution planning and design criteria. He also explains the effects and ensuing costs and
benefits of continued, unchecked growth of private solar generation on the Company’s distribution
system. He describes the administrative costs related to net metering applications that justify the
Company’s proposed application fee.
Mr. Michael G. Wilding explains the net power costs and credits attributed to net metering
customers in the cost of service studies.
BACKGROUND
The net metering program developed from a Commission order in Docket No. 97-035-01,
in which the Commission organized a task force in the “interest of concrete proposals, well
analyzed as to the costs and benefits, and the specifics of program delivery …” with respect to
energy efficiency and renewable resources.5 That order set forth specific programs for which the
5
See In the Matter of the Investigation Into the Reasonableness of Rates and Charges of PacifiCorp, dba Utah Power
& Light Company, Report and Order (March 4, 1999); 1999 WL 35637961, at *68 (Utah P.S.C. March 4, 1999).
6
parties requested additional analysis. Included in the list were green offerings, net metering, and
energy efficiency.6 On December 23, 1999, the Energy Efficiency and Renewable Task Force
recommended that a “net metering program be established in Utah Power’s service territory.”7
Pursuant to legislation, the net metering program officially launched in 2002.8 Over the years, the
program has changed to implement amendments to net metering laws, encourage more
participation in the program by establishing a higher amount of eligible generating capacity,
incorporate statutory interconnection requirements, and change the rate credited for excess energy,
among other modifications.9
One of the more significant modifications to the net metering program dealt with a change
to the rate credited to net metering customers for excess energy in Docket No. 08-035-78. In that
docket, titled “In the Matter of the Consideration of Changes to Rocky Mountain Power’s Schedule
No. 135 - Net Metering Service,” parties requested, and the Commission approved, a change to the
rate credited for excess energy from avoided costs to a kilowatt-hour credit, which amounts to
credit for excess energy at the full retail rate.10 In the same docket, parties also requested a change
to the cap for net metering cumulative generation capacity from 0.1 percent to 20 percent of the
Company’s 2007 peak demand. Both modifications were based on perceived barriers to the
implementation of the net metering program. The Company proposed a one percent cap and
objected to the 20 percent cap because the cap appeared to give the impression of a target. The
Company also cited engineering concerns with a 20 percent cap.11 Other parties either
6
Id.
Docket No. 97-2035-01, Report of the Energy Efficiency and Renewable Task Force, at 36 (Utah P.S.C. December
23, 1999) at 36.
8
L. Utah 2002, Ch. 6. See also Docket No. 02-035-T05, Tariff Approval Letter (Utah P.S.C. June 24, 2002).
9
See Docket Nos. 08-035-78, 08-035-T04, 09-035-T03, 10-035-T04, 10-035-T12, 11-035-T05, 12-035-T09, 13-035T09, 13-035-T10, and 14-035-T06.
10
Docket No. 08-035-78, Report and Order at 13 (Utah P.S.C. February 12, 2009).
11
Id. at 6.
7
7
recommended or did not object to the 20 percent cap because of limited program participation at
the time (the enrolled capacity for net metering was 540 kilowatts as of October 31, 2008).12 In its
order approving the 20 percent cap, the Commission indicated that, to the extent the Company
“determines it is being adversely affected by net metering … the Company has the ability to
approach the Commission with information on both costs and benefits to address the issue.”13
Since then, the customer costs of installing a private solar generation system have dropped and
subsidies have become available, which, in combination with the modifications to the program,
have contributed to the popularity and growth of private solar generation in the state of Utah.
By the end of 2013, about 2,200 customers participated in the program. By the end of
calendar year 2015, that number had climbed to over 6,700 customers, a growth rate of 200 percent
in just two years. As of October 7, 2016, 7,000 more customers enrolled, with 3,500 more expected
to enroll by the end of this year, bringing the total number of net metering customers to over 17,000
by the end of 2016. In light of the subsidies embedded within the current rate structure of the net
metering program, growth highlights the fact that the current ratemaking structure is unsustainable
and, in fact, are increasingly harming other customers.
Recognizing the significant growth and increasing costs of the program on other residential
customers, Senate Bill 208 was enacted by the Utah Legislature in its 2014 Session and signed
into law on March 25, 2014. It included the Net Metering Statute, which reads:
54-15-105.1. Determination of costs and benefits - Determination of just and
reasonable charge, credit or ratemaking structure.
The governing authority shall:
(1) determine, after appropriate notice and opportunity for public comment,
whether costs that the electrical corporation or other customers will incur from a
12
13
Id.
Id. at 13.
8
net metering program will exceed the benefits of the net metering program, or
whether the benefits of the net metering program will exceed the costs; and
(2) determine a just and reasonable charge, credit, or ratemaking structure,
including new or existing tariffs, in light of the costs and benefits.
Utah Code Ann. § 54-15-105.1 (hereinafter, § 54-15-105.1(1) will be referred to as “Subsection
One” and § 54-15-105.1(2) as “Subsection Two”).
In the Company’s 2014 GRC, the Company requested approval of a proposed monthly
fixed net metering facilities charge for residential net metering customers to cover distribution and
certain customer service costs. In a notice issued April 16, 2014, following the enactment of the
Net Metering Statute, the Commission stated its intent to address the implementation of the statute
in the 2014 GRC. The Commission invited the public to submit written comments and also directed
intervenors to address the costs and benefits of the net metering program as part of their written
testimony on cost of service issues.14 Several parties filed testimony responding to the Company’s
proposed charge and provided additional testimony regarding the costs and benefits of the net
metering program.
All other issues in the 2014 GRC were ultimately settled, so the final hearings held in that
docket only concerned the proposed net metering charge. Following hearings, the Commission
issued its order, declining to approve the proposed net metering charge in a two-to-one decision.
Instead, “recognizing the importance of the issues raised by parties in the rate case,” the
Commission established the current docket to examine the costs and benefits of the Company’s
net metering program.15 The Commission also decided that it would perform the examination in
steps: first it would establish an appropriate analytical framework to implement the new statute,
14
Docket No. 13-035-184, Public Notice (Utah P.S.C. April 16, 2014).
Docket No. 14-035-114, Notices of Comment Period and Scheduling Conference, at 1; 2014 WL 6713287 at *1
(Utah P.S.C. November 21, 2014).
15
9
then it would “examine the costs and benefits that result from applying the data to the approved
analytical framework” and determine whether any proposed changes in rates are just and
reasonable. The analytical framework to be established to implement Subsection One was to
“include the types of analyses that must be performed, the components of costs and benefits to be
included in the analyses, and the sources and time period of data inputs.”16 The Commission
indicated it would examine the costs and benefits that result from applying the data to the approved
analytical framework, and ultimately make the Subsection Two determination, “in a further phase
of this docket, a general rate case or other appropriate proceeding.”17
In preparation for the hearing on Subsection One of the Commission’s process, the
Company requested that the Commission decide certain issues as a matter of law. Specifically, it
asked the Commission to rule that “(1) the benefits and costs the Commission is to consider under
[the Net Metering Statute] are limited to those accruing to RMP and its non-net metering
customers; (2) those costs and benefits must be ‘actual’ and ‘quantifiable’; and (3) the statute
excludes consideration of studies relating to benefits or costs outside of Utah.”18 On July 1, 2015,
the Commission ruled that: (1) Subsection One of the Net Metering Statute is independent of
Subsection Two; (2) the Commission would consider only the costs and benefits to current
customers in their capacity as ratepayers; and (3) the Commission would not consider “costs and
benefits that are either unquantifiable or not subject to reasonable verification.”19
16
Id. at 2.
Docket No. 14-035-114, Notices of Comment Period and Scheduling Conference (Utah P.S.C. November 21, 2014).
18
Docket No. 14-035-114, Order Re: Conclusions of Law on Statutory Interpretation and Order Denying Motion to
Strike, at 2; 2015 WL 4155503 at *2 (Utah P.S.C. July 1, 2015).
19
Id. at 17-18.
17
10
DISCUSSION
A. The ACOS, CFCOS and NEM Breakout COS Comply with the Commission’s
Direction in the November 2015 Order and Should Be Accepted.
The Commission opened the current docket on August 29, 2014, to ensure a focused,
complete and accurate evaluation of the net metering program. In an earlier phase of this docket,
the Commission established the appropriate analytical framework to examine the costs and
benefits of the net metering program. In November 2015, the Commission approved an analytical
framework and directed the Company to file the ACOS and CFCOS:
One study creates a counterfactual scenario that assumes away the existence of net
metering customers’ power generation, meaning PacifiCorp must meet net metering
customers’ full load and these customers push no energy back to the grid
[“CFCOS”)]. . . . The second cost of service study . . . should reflect PacifiCorp’s
actual cost of service inclusive of net metering customers’ participation
[(“ACOS”)]. Under this scenario, PacifiCorp meets only net metering customers’
“net load” (i.e. net metering customers’ total consumption less the amount they selfgenerate) and the model includes the excess energy net metering customers push to
the grid.20
This Compliance Filing satisfies the Commission’s directive and completes the
requirements for the Commission to perform its duties under Subsection One. The ACOS, CFCOS
and NEM Breakout COS were developed consistent with Commission approved standards that
have evolved over many years. They reflect costs the Company incurs to provide electric service
to customers who install private generation including fixed costs associated with back-office
systems like accounting, billing, customer service, and meters; costs associated with use of the
system; and costs related to the energy consumed including energy-related generation and
transmission. They demonstrate that the current rate structure unfairly shifts a portion of these
costs to other customers. 20
November 2015 Order at 5.
11
In its November 2015 Order, the Commission ordered that the CFCOS and ACOS be
“commensurate with the test period in PacifiCorp’s next general rate case.”21 In its rejection of the
Joint Parties’ proposal to use a 20-year study period, the Commission stated that a short-term study
period would be far more useful for rate setting:
We do not find this approach to be consistent with the Statute. The Division is
correct to emphasize the framework we adopt for the Subsection One analysis must
be useful for rate setting under Subsection Two. … Subsection One instructs us to
assess the impact of net metering on the utility and its “other customers.” Those
who are present customers of PacifiCorp may or may not be customers in two
decades. We believe the Legislature was careful to include the term “other
customers” in Subsection One because it was concerned about the near term impact
net metering has on the utility’s other current customers.22
Consistent with the Commission’s direction of using a short-term period for the required
analysis, and with the way general rates are set, the Company adjusted the 2015 test period cost of
service results in the NEM Breakout Study to the revenue requirement approved in the 2014 GRC
– on which all other current customer rates are based. This is also consistent with the November
2015 Order that the Subsection Two proceeding could take place “in a further phase of this docket,
a general rate case or other appropriate proceeding.”23 The exponential growth of the net metering
program and the findings from the comparison of the ACOS and CFCOS studies mandate this
Compliance Filing before the preparation of the Company’s next general rate case. Utilization of
the 2015 test period and the 2014 GRC revenue requirement is explained in more detail in the
testimony and exhibits of Ms. Steward and Mr. Meredith.
21
November 2015 Order at 7.
Id. at 14.
23
Id. at 1.
22
12
B. Net Metering Customers Have Unique Usage Characteristics that Support Creation
of a Net Metering Residential Class
Not only does the current net metering program unfairly shift a substantial portion of costs
to other customers, the bi-directional use of the distribution system are unique net metering
customer characteristics that differ from other customers. Unlike other customers, net metering
customers both import and export electricity. They also require stand-by-only service when they
are self-generating. This solar generation often does not coincide with the Company’s peak load,
thus only minimally reducing that load. Company witness Mr. Marx testifies that a net metering
customer’s peak production occurs during the spring months while their peak load, and that of
other customers, occurs during the summer months. These factors necessitate increasing the size
of the distribution facilities as a result of net metering. These unique usage characteristics justify
segregating net metering customers from the residential class into a distinct class. In this way, the
costs imposed on and benefits contributed to the system by net metering customers will be clearly
identified. In addition, net metering customers will be fairly compensated for any capacity and
energy benefits associated with their private solar generation systems.
C. The Subsection One Cost/Benefit Analysis Justifies a Different Rate Structure for Net
Metering Customers.
Once the Commission determines the costs and benefits provided to the system by net
metering, it must “determine a just and reasonable charge, credit or ratemaking structure, including
new or existing tariffs, in light of the costs and benefits.”24 The 673 percent growth25 of the net
metering program since 2013 mandates the Company’s request for the Commission to address the
Subsection Two analysis and to approve its proposed Schedule 136 and Schedule 5.
24
Utah Code Ann. § 54-15-105.1(2).
The Company used the total number of projects to determine the percentage in growth. There were 2,204 projects
on December 31, 2013 and 14,841 projects on October 31, 2016. Had capacity been used as the metric, the percentage
in growth would be 782 percent. The capacity was 14,657 on December 31, 2013 and 114,592 on October 31, 2016.
25
13
In the proposed Schedule 5 for service to residential customer generators, the Company
proposes a three-part rate structure that accounts for the unique load characteristics of net metering
customers and ensures that net metering customers pay a just and reasonable rate for service. The
rate structure includes a fixed monthly charge, a charge for demand during peak hours, and an
energy charge. The Company’s proposed three-part structure is calculated based on the Company’s
cost of service studies. These charges are based on the specific costs that the Company incurs to
provide electric service to net metering customers. The fixed monthly charge includes costs
associated with connecting to the system that do not vary with usage like accounting, billing,
customer service, meters and line transformers. The demand charge includes costs associated with
the use of the distribution, generation, and transmission systems and reflects the maximum or peak
load requirements of net metering customers. The energy charge reflects variable costs related to
the energy net metering customers consume including net power costs and a portion of generation
and transmission infrastructure. This proposed rate structure is described in more detail in the
testimony and exhibits of Ms. Steward. The Company proposes that the new Schedules 136 and 5
become effective June 1, 2017, and apply to all net metering customers enrolling in the program
on and after December 10, 2016, the proposed effective date of the concurrent filing in Tariff
Advice No. 16-13
In its concurrently filed tariff advice, the Company requests that Schedule 135 be closed to
new customers immediately (after the 30th day of the filing)26 and that customers requesting net
metering service thereafter be served under proposed Schedule 135A until the Commission
approves Schedules 136 and 5 and the new rate structure for residential customer generators.
Proposed Schedule 135A facilitates a transition to a future rate design, whether it be through
25
See Utah Admin. R. R746-405-2(E)(2).
14
Schedule 5 or some other structure. It leaves residential net metering applicants on the existing
program, but provides clear notice that this tariff is subject to change once the Commission has
fulfilled its duties under the Net Metering Statute. The Company supports keeping the current net
metering customers on the existing net metering program and rate schedule, as further explained
in Mr. Hoogeveen's testimony. In addition, current net metering customers on Schedule 135 do not
have meters that can measure on-peak demand, which will be required under proposed Schedule
136. As a result, a wholesale transition of these customers to the new schedule would be
administratively and operationally challenging. Rather than requiring these customers to replace
their meters when Schedule 136 or another rate structure is approved, the Company proposes that
they be allowed to continue to receive service under Schedule 135. The Company expects this
issue will be considered in a future proceeding. The Commission has regularly approved closing
service to existing customers under similar circumstances. See, e.g., In the Matter of Bear Lake
Comm’n, Inc., 2013 WL 4399208 (Utah P.S.C. August 8, 2013) (grandfathering emergency line
service to existing customers); In re U.S. West Comm’n, 1999 WL 35639170 (Utah P.S.C.
November 26, 1999) (grandfathering Centrex Plus service to existing customers); In Re U.S. West
Paging, Inc., 93-2026-01, 1993 WL 501443 (July 2, 1993) (grandfathering mobile telephone
service to existing customers).
CONCLUSION AND REQUEST FOR RELIEF
The Commission ordered the Company to prepare and analyze the ACOS, the CFCOS and
the NEM Breakout COS. The Company has now done so. The results of those studies, as set forth
in the testimony and exhibits supporting this Compliance Filing, bear out that the current net
metering program does not account for the actual costs and benefits that net metering customers
bring to the Company’s system. Instead, those studies show that net metering customers are
15
currently not covering their costs and will shift them to other customers or the Company if the
current rate structure is left unchanged. Further, the NEM Breakout COS shows that net metering
customers have unique characteristics that justify creating a separate net metering customer class
so that the costs and benefits those customers bring to the system can be clearly identified and
properly addressed. Based upon the foregoing and for good cause shown, Rocky Mountain Power
requests that the Commission:
(1)
find that the CFCOS, the ACOS, and the net metering breakout cost of service study
(“NEM Breakout COS”) are compliant with and fulfill the November 2015 Order;
(2)
find, based on the cost of service analyses, that the costs of the net metering program
under the current rate structure exceed its benefits;
(3)
find, based on the cost of service analyses, that the unique usage characteristics of
net metering customers justify segregating them into a distinct class;
(4)
determine that the current rate structure for net metering customers is unjust and
unreasonable because it does not reflect the costs imposed on and benefits contributed
to the system, and unfairly shifts costs from net metering customers to other
customers or to the Company;
(5)
approve the Company’s proposed Schedule 136 with modifications to net metering
service and Schedule 5, which includes a three-part tariff structure that reflects the
costs and benefits that net metering customers impose on and contribute to the
distribution system as just and reasonable, effective June 1, 2017; and
(6)
approve a waiver of Utah Admin. R. 746-312-13, pursuant to Utah Admin. R. 746312-3(2).
16
DATED: November 9, 2016.
Respectfully Submitted,
___________________________
Yvonne R. Hogle
Attorney for Rocky Mountain Power
17
Rocky Mountain Power
Docket No. 16-035-____
Witness: Gary W. Hoogeveen
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Direct Testimony of Gary W. Hoogeveen
November 2016
1
Q.
dba Rocky Mountain Power (the “Company”).
2
3
Please state your name, business address and present position with PacifiCorp,
A.
My name is Gary W. Hoogeveen. My business address is 1407 West North Temple,
4
Suite 310, Salt Lake City, Utah 84116. My present position is Senior Vice President
5
and Chief Commercial Officer of Rocky Mountain Power.
6
Qualifications
7
Q.
Please summarize your education and business experience.
8
A.
I have a B.S. degree in Physics from the University of Northern Iowa and Masters
9
and Ph.D. degrees in Space Physics from Rice University. For the last 16 years, I
10
have worked for the Berkshire Hathaway Energy family of companies. In the five
11
years immediately preceding my current position at Rocky Mountain Power, I
12
served as President and Chief Executive Officer of the Kern River Gas
13
Transmission Company headquartered in Salt Lake City.
14
Q.
What are your responsibilities with Rocky Mountain Power?
15
A.
My main responsibilities focus on community affairs, public policy and building
16
relationships with our communities. These relationships facilitate open
17
communication that allow the Company to understand the needs of our customers
18
and to develop or change policies and programs that will meet those needs and keep
19
pace with the evolving environment. We work diligently across our organization to
20
offer the services our communities and customers want, without adversely affecting
21
other customers. I have been personally involved in advancing new programs that
22
provide additional options for customers who want more renewable energy and
23
have overseen the development of those programs with the objective of balancing
Page 1 - Direct Testimony of Gary W. Hoogeveen
24
the needs of all customers and the Company's obligation to provide safe, reliable
25
and efficient electric service.
26
Purpose and Summary of Testimony
27
Q.
What is the purpose of your testimony?
28
A.
The purpose of my testimony is to introduce and support the Company’s
29
Compliance Filing and Request to Complete All Analyses Required Under the Net
30
Metering Statute for the Evaluation of the Net Metering Program ("Compliance
31
Filing"). The Compliance Filing includes the components that comply with the
32
Order issued by the Public Service Commission of Utah (“Commission”) in this
33
docket on November 10, 2015 (“November 2015 Order”), enabling the completion
34
of the evaluation of the net metering program required by Utah Code Ann. § 54-15-
35
105.1 (the "Net Metering Statute"). The Compliance Filing requests modifications
36
to the net metering program, including a new rate structure for residential net
37
metering customers. I also describe a corresponding tariff advice letter, filed
38
concurrently with the Compliance Filing, that requests to close to new service the
39
currently effective Schedule 135, Net Metering Service, and approve, in its place,
40
proposed Schedule 135A, which mirrors Schedule 135 and would be in place
41
temporarily until the Commission makes the final determination in Subsection Two
42
(as defined below) of the Net Metering Statute. I will give an overview of the major
43
components of the Company’s filings, explain why the Company’s proposals
44
should be adopted and identify the witnesses who will present the details of the
45
filings.
Page 2 - Direct Testimony of Gary W. Hoogeveen
46
Q.
Please summarize your testimony.
47
A.
My testimony provides a general overview of the Compliance Filing and the
48
concurrently-filed tariff advice filing that are intended to complete the final phases
49
of the evaluation of the Company’s net metering program, required by the Net
50
Metering Statute. The Net Metering Statute requires the Commission to "determine
51
a just and reasonable charge, credit or ratemaking structure, including new or
52
existing tariffs, in light of the costs and benefits of the net metering program."
53
Consistent with the November 2015 Order, the Company prepared actual and
54
counterfactual cost of service studies (“ACOS” and “CFCOS”) and a study with
55
net metering segregated into its own class ("NEM Breakout COS"). The studies use
56
calendar year 2015 actual data, including data collected from the Company’s load
57
research study for residential net metering customers. The ACOS and CFCOS were
58
prepared consistent with Commission-approved standards for cost of service that
59
have evolved over many years. The Company’s data demonstrates that the costs of
60
the net metering program do, in fact, exceed its benefits and that residential
61
customers with private generation systems have unique load and cost characteristics
62
that require modification from the current rate structure to avoid cost-shifting to
63
other customers. Recent exponential growth of the net metering program, evident
64
in the data supporting this filing and described in detail below and in supporting
65
testimony, precipitated this Compliance Filing and the concurrent tariff advice
66
filing, requesting immediate relief.1 This dramatic growth forms the basis for the
1
As part of this docket, the Commission left open the possibility of addressing the ratemaking structure of
the net metering program, "in a further phase of this docket, a general rate case or other appropriate
proceeding." November 2015 Order at 1.
Page 3 - Direct Testimony of Gary W. Hoogeveen
67
Company's recommendation to replace the current rate structure for residential net
68
metering customers with its proposed three-part rate structure, which includes a
69
fixed monthly charge, an on-peak demand, and an energy charge. Proposed
70
Schedule 5 reflects the costs and benefits to the system, and the unique load and
71
cost characteristics of net metering customers. In the interim, the Company also
72
proposes a transition tariff, Schedule 135A, as described below.
73
The Company supports renewable resources and customer choice for
74
additional renewable products as long as an appropriate rate structure is in place
75
that allows customers to use private generation without adversely affecting other
76
residential customers or the Company. However, the combination of declining
77
prices for private generation systems, generous government subsidies and excessive
78
retail rate compensation for their generation has contributed to exponential growth
79
that shifts costs to the Company and its other customers. This growth renders the
80
current ratemaking structure for residential net metering customers unsustainable;
81
accordingly, that structure must change to prevent adverse impacts to other
82
customers.
83
As is demonstrated by the results of the comparison of the ACOS to the
84
CFCOS, under the current net metering program, the costs of the program exceed
85
the benefits to the system, and the costs that should be paid by net metering
86
customers are shifted to other customers. With no change, this will result in
87
increasing levels of subsidies in favor of net metering customers built into other
88
customers' rates in future rate cases. In between cases, the Company bears the costs
89
resulting from the incremental growth in the number of new net metering
Page 4 - Direct Testimony of Gary W. Hoogeveen
90
customers. This is the type of situation that was contemplated in the Commission's
91
order approving the change to the net metering cumulative generation capacity to a
92
20 percent cap of the Company's 2007 peak load from 0.1 percent. In that order, the
93
Commission extended an invitation to the Company to return to the Commission if
94
the extremely generous cap of 20 percent proved to be harmful.2 For the net
95
metering program to continue, its rate structure must be corrected to accurately
96
reflect the impact of the program on the system and to properly allocate costs
97
between customers as part of proper rate design.
98
Filing Request
99
Q.
What does the Company seek in its filings?
100
A.
In this Compliance Filing, the Company requests that the Commission:
(1) Find that the CFCOS, the ACOS, and the NEM Breakout COS are
101
compliant with and fulfill the November 2015 Order;
102
(2) Find, based on the cost of service analyses, that the costs of the net metering
103
program under the current structure exceed its benefits;
104
105
(3) Find, based on the cost of service analyses, that the unique usage
106
characteristics of residential net metering customers justify segregating
107
them into a distinct class for ratemaking;
108
(4) Determine that the current rate structure for residential net metering
109
customers is unjust and unreasonable because it does not reflect the costs
110
imposed on and the benefits contributed to the system and unfairly shifts
111
costs of net metering customers to other customers;
2
Docket No. 08-035-78, Report and Order, at 13 (Utah P.S.C. February 12, 2009).
Page 5 - Direct Testimony of Gary W. Hoogeveen
112
(5) Approve and implement the Company’s net metering program
113
modifications in the new Schedule 136 for net metering service, including
114
new application fees for interconnections and elimination of the option for
115
non-residential customers to take compensation at the average retail rate for
116
excess generation, effective June 1, 2017;
117
(6) Approve and implement new rates on Electric Service Schedule 5 for
118
residential customer generators that account for their differing load
119
characteristics and ensure that net metering customers pay for the fixed
120
costs for infrastructure, backup grid reliability, and electric service they
121
require, effective June 1, 2017; and
122
(7) Approve a waiver of Utah Admin. R. 746-312-13 to implement new
123
application fees, as explained in more detail in Company witness Ms. Joelle
124
R. Steward’s testimony.
125
Because time is of the essence due to the increasing growth in net metering
126
customers, the Company also seeks, through its concurrent tariff advice filing,
127
approval to close current Schedule 135 service to prospective net metering
128
customers who apply for net metering service after December 9, 2016. In addition,
129
the Company requests approval and implementation of Schedule 135A to be
130
effective after December 9, 2016, to be in place temporarily until the Commission
131
rules on Subsection Two of the Net Metering Statute (as defined below). Schedule
132
135A differs from Schedule 135 only in that it states “Customers will be subject to
133
all changes to net metering service including changes to credits, charges or rate
134
structures offered herein and in related tariffs resulting from the final determination
Page 6 - Direct Testimony of Gary W. Hoogeveen
135
under Utah Code Ann. § 54-15-105.1 which may include, without limitation, a
136
transfer from this tariff to all new applicable service schedules approved by the
137
Commission."
138
The advice filing also includes a request for approval of a slight
139
modification to the Interconnection Agreement for Net Metering Service with the
140
Company, reflecting the shift to the new schedule at the appropriate time and
141
administrative updates. Prospective net metering customers applying for net
142
metering service after December 9, 2016, would be on notice that their rates may
143
change upon a final determination on Subsection Two of the Net Metering Statute.
144
Q.
this time?
145
146
Why does the Company believe that a change to Schedule 135 is necessary at
A.
The Net Metering Statute requires the Commission to reconsider the ratemaking
147
structure in light of the costs and benefits of the program.3 Due to the exponential
148
growth of net metering, it is imperative that the Commission consider the issue
149
immediately to prevent significant cost shifts from net metering customers to all
150
other customers. The Company’s proposed change to the current net metering tariff
151
achieves the purpose and mandate of Senate Bill 208, enacted by the Utah
152
Legislature and signed into law on March 25, 2014, including the Net Metering
153
Statute, which reads:
154
155
54-15-105.1 Determination of costs and benefits - Determination of
just and reasonable charge, credit or ratemaking structure.
156
The governing authority shall:
3
See also Utah Code Ann. § 54-4-4(1)(a)(i) and (ii) (requiring the Commission to take action if there is a
finding that "rates ... are unjust, unreasonable ... or ... insufficient.")
Page 7 - Direct Testimony of Gary W. Hoogeveen
157
158
159
160
161
(1) determine, after appropriate notice and opportunity for public
comment, whether costs that the electrical corporation or other
customers will incur from a net metering program will exceed the
benefits of the net metering program, or whether the benefits of the
net metering program will exceed the costs; and
162
163
164
(2) determine a just and reasonable charge, credit, or ratemaking
structure, including new or existing tariffs, in light of the costs and
benefits.
165
Utah Code Ann. § 54-15-105.1 (hereafter, § 54-15-105.1(1) will be referred to as
166
“Subsection One” and § 54-15-105.1(2) as “Subsection Two”).
167
The Commission opened the current docket to ensure a focused, complete,
168
and appropriate evaluation of the net metering program. In its November 2015
169
Order, the Commission approved the appropriate framework for the Subsection
170
One analysis, and directed the Company to file its ACOS, CFCOS, and NEM
171
Breakout COS. The Compliance Filing satisfies the Commission's directive. As is
172
demonstrated by the cost of service analyses, supported by the testimony and
173
exhibits of Company witness Mr. Robert M. Meredith, residential net metering
174
customers are not adequately covering the fixed costs associated with their use of
175
the grid. These costs are then shifted to all other customers. Private generation is
176
growing exponentially. In 2013, the Company was providing net metering service
177
to approximately 2,200 net metering customers. At the end of calendar year 2015,
178
approximately 6,700 of the Company’s Utah residential customers were enrolled
179
on Schedule 135. As of October 7, 2016, 7,000 additional customers have enrolled,
180
with over 3,500 more expected to enroll by the end of the year. As more customers
181
enroll in net metering, the cost shift to other customers is increasing and will
182
continue to do so if not addressed. Figure 1 below demonstrates the cumulative
Page 8 - Direct Testimony of Gary W. Hoogeveen
183
count of customers participating in net metering over the past several years as well
184
as the Company's projection for the end of 2016.
185
186
Q.
structure than other residential customers?
187
188
Why should residential net metering customers be subject to a different rate
A.
As is demonstrated by the testimony and exhibits filed by Company witnesses Ms.
189
Joelle Steward and Mr. Douglas L. Marx, the usage characteristics of net metering
190
customers differ from other residential customers, which the current rate structure
191
fails to adequately capture. Net metering customers use the grid more than other
192
customers because they both import and export electricity. In addition, because
193
peak solar generation often does not coincide with the time of the Company’s peak
194
load, net metering customers' private generation systems have only a modest ability
195
to reduce peak load. The Company incurs costs to build its system to meet peak
196
load. Mr. Marx testifies that a net metering customer’s peak production to the grid
197
occurs during the spring months, but their peak demand occurs during summer
Page 9 - Direct Testimony of Gary W. Hoogeveen
198
months. These factors result in the need to increase the size of the distribution
199
facilities as a result of net metering.
200
Q.
What rate structure is the Company proposing?
201
A.
To satisfy Subsection Two of the Net Metering Statute, the Company proposes a
202
three-part rate structure that accounts for the unique load characteristics of
203
residential net metering customers and ensures that net metering customers pay
204
their fair share of fixed costs for infrastructure and backup grid reliability. This rate
205
design appropriately matches the costs to the customers that cause them. The
206
proposed rate structure includes a fixed monthly charge, a charge for demand
207
during peak hours, and an energy charge. The Company’s proposed three-part
208
structure is calculated based on the Company’s cost of service studies. The
209
proposed rate structure is described in more detail in the testimony and exhibits of
210
Ms. Steward.
211
Q.
When does the Company propose the new rate structure take effect?
212
A.
The Company requests the new rates take effect June 1, 2017. In Subsection Two
213
of the evaluation, the Commission must determine the appropriate charge, credit or
214
ratemaking structure in light of the costs and benefits determined in Subsection
215
One. Once the cost/benefit analysis under Subsection One is accepted, and a
216
showing is made that the costs of the net metering program exceed its benefits, the
217
Commission must implement Subsection Two in accordance with the mandate of
218
the Net Metering Statute. The Company proposes that the new rate structure
219
become effective when the Commission approves Schedule 136 and Schedule 5,
220
which the Company respectfully requests be by June 1, 2017, and that it apply to
Page 10 - Direct Testimony of Gary W. Hoogeveen
221
new net metering customers on a prospective basis, as explained in detail in Ms.
222
Steward's testimony.
223
Q.
How does the Company propose to treat current net metering customers?
224
A.
The Company supports keeping the current net metering customers on the existing
225
net metering program and their current rate schedule. We acknowledge that current
226
customers made investments based on the current structure and respect the
227
customers' need for reasonable certainty for recovery of their investments. The
228
Company expects this issue to be considered in a future proceeding. Current
229
customers may voluntarily opt in to the new Schedule 5.
230
In addition, current net metering customers generally do not have meters
231
that are capable of billing the on-peak demand charge that is included in the
232
proposed rate structure. Transitioning these customers to the new schedule would
233
be operationally and administratively challenging.
234
History of Net Metering in Utah
235
Q.
What is the history of the net metering program in Utah?
236
A.
As a result of a Commission order in Docket No. 97-035-01, the Commission
237
agreed to organize a task force in the “interest of concrete proposals, well analyzed
238
as to the costs and benefits, and specifics of program delivery …” with respect to
239
energy efficiency and renewable resources.4 The order outlined specific programs
240
for which the parties requested analysis. Included in this list were green pricing, net
241
metering, and energy efficiency. On December 23, 1999, the Energy Efficiency and
4
See In the Matter of the Investigation Into the Reasonableness of Rates and Charges of PacifiCorp, dba
Utah Power & Light Company, Report and Order (March 4, 1999), 1999 WL 35637961, at *68 (Utah P.S.C.
March 4, 1999).
Page 11 - Direct Testimony of Gary W. Hoogeveen
242
Renewable Task Force recommended that a “net metering program be established
243
in Utah Power’s service territory.”5 Pursuant to legislation, the net metering
244
program officially launched in 2002.6 Over the years, the net metering program has
245
changed to implement legislative amendments to the net metering law, encourage
246
more participation in the program by establishing a higher amount of generating
247
capacity, incorporate a requirement that net metering customers sign
248
interconnection agreements, and change the rate paid for excess energy, among
249
other modifications.7
250
Q.
How have these modifications to the net metering program taken place?
251
A.
One of the more significant modifications to the net metering program dealt with a
252
change to the credit to net metering customers for excess energy in Docket No. 08-
253
035-78. In that docket, titled In the Matter of the Consideration of Changes to
254
Rocky Mountain Power’s Schedule No. 135 - Net Metering Service, parties
255
requested and the Commission approved a change to the credit for excess energy
256
from avoided costs to the kilowatt-hour method, which amounts to a credit at the
257
full retail rate.8 In the same docket, the Commission approved a modification that
258
established a higher amount of generating capacity from private solar systems from
259
0.1 percent to 20 percent of the Company's 2007 peak demand.9 Both modifications
260
were based on perceived barriers to the implementation of the net metering
261
program. While most parties either recommended or did not object to the 20 percent
5
Docket No. 97-2035-01, Report of the Energy Efficiency and Renewable Task Force, at 36 (Utah P.S.C.
December 23, 1999).
6
L. Utah 2002, Ch. 6.; See also Docket No. 02-035-T05, Tariff Approval Letter (Utah P.S.C. June 24, 2002).
7
See Docket Nos. 08-035-78, 08-035-T04, 09-035-T03, 10-035-T04, 10-035-T12, 11-035-T05, 12-035-T09,
13-035-T09, 13-035-T10, and 14-035-T06.
8
Docket No. 08-035-78, Report and Order, at 13 (Utah P.S.C. February 12, 2009).
9
Id.
Page 12 - Direct Testimony of Gary W. Hoogeveen
262
cap, the Company proposed a one-percent cap and objected to the 20 percent cap.
263
In its order approving the 20 percent cap, the Commission indicated that, to the
264
extent the Company, "determines it is being adversely affected by net metering ...
265
the Company has the ability to approach the Commission with information on both
266
costs and benefits to address the issue."10
267
Q.
in discrete cases?
268
269
Why has the Commission approved modifications to the net metering program
A.
Historically, the net metering program has been treated like the Company’s other
270
programs, including its energy efficiency programs, the Utah Solar Incentive
271
Program (“USIP”) and, more recently, its newly approved tariff programs and rates
272
for renewable energy options in Schedules 32 and 34. Changes to energy efficiency
273
programs and to USIP have typically also occurred in discrete cases. Similar to its
274
energy efficiency programs and USIP, the Company must file an annual report with
275
the Commission to provide updated information regarding, among other things, the
276
net metering program’s participation rates.
277
Q.
How has the net metering program changed from its initial implementation?
278
A.
The significant decrease in cost for private solar generation systems since its initial
279
implementation has undoubtedly been the most important factor in the growth of
280
the program. Graph 1 below shows the significant drop in the prices of solar panels
281
per watt from a high of approximately $100 in the 1970s to $0.61 in 2015.
10
Id.
Page 13 - Direct Testimony of Gary W. Hoogeveen
Graph 1. Solar panel prices11
282
283
However, government subsidies as well as the modifications I describe
284
above have also contributed to the rapid growth in solar installations. The
285
Company’s data demonstrates that private solar generation is increasingly popular
286
in Utah in particular, and is projected to grow at a similar pace for the foreseeable
287
future. This growth has highlighted the fact that the current ratemaking structure
288
for the net metering program is not sustainable and harms other customers.
289
Q.
customers?
290
291
What challenges does private solar generation pose to the Company and its
A.
As shown in the testimony and exhibits of Ms. Steward and Mr. Meredith, the
292
results of the Subsection One cost/benefit analysis performed using a comparison
293
of the ACOS and the CFCOS show that the current ratemaking structure shifts costs
11
https://cleantechnica.com/2014/09/04/solar-panel-cost-trends-10-charts/
Page 14 - Direct Testimony of Gary W. Hoogeveen
294
to other customers in the amount of $2.0 million annually. If the current ratemaking
295
structure for residential net metering does not change, the Company's data indicates
296
that the cumulative cost shift related to residential net metering will be
297
approximately $670 million over the next 20 years. With no change, this will result
298
in increasing levels of subsidies in favor of net metering customers built into other
299
customers' rates in future rate cases. In between cases, the Company bears the costs
300
resulting from the incremental growth in the number of new net metering
301
customers. This is the type of situation that was contemplated in the Commission's
302
order approving the change to the net metering cumulative generation capacity from
303
one percent to a 20 percent cap of the Company's 2007 peak load. In that order, the
304
Commission provided that the Company could come back to the Commission if
305
the extremely generous cap of 20 percent proved to be harmful, which we now
306
know that it is under the current structure.12
307
Q.
by net metering?
308
309
What has the Company proposed in the past to address the challenges posed
A.
In the Company’s 2014 general rate case in Docket No. 13-035-184 (“2014 GRC”),
310
the Company requested approval of a fixed monthly net metering facilities charge
311
for residential net metering customers to cover distribution and certain customer
312
service costs. In a notice issued April 16, 2014, the Commission stated its intent to
313
address the implementation of the Net Metering Statute in the 2014 GRC. The
314
Commission invited the public to submit written comments and also directed
315
intervenors to address the costs and benefits of the net metering program as part of
12
Docket No. 08-035-78, Report and Order, at 13 (Utah P.S.C. February 12, 2009).
Page 15 - Direct Testimony of Gary W. Hoogeveen
316
their written testimony on cost of service issues. Several parties filed testimony
317
responding to the Company’s proposed charge and provided additional testimony
318
regarding the costs and benefits of the net metering program. All other issues in the
319
case were eventually settled, and the Commission held hearings devoted solely to
320
the net metering issue. Following the hearings, the Commission issued its order in
321
the 2014 GRC. In a two-to-one decision,13 the Commission declined to approve the
322
proposed net metering charge but, “recognizing the importance of the issues raised
323
by parties in the rate case,” established the current docket to examine the costs and
324
benefits of the Company’s net metering program.14 The Commission also decided
325
that it would perform the evaluation in two steps. After establishing the appropriate
326
analytical framework, the Commission indicated it would examine the costs and
327
benefits that result from applying the data to the approved analytical framework,
328
and ultimately make the Subsection Two determination, “in a further phase of this
329
docket, a general rate case or other appropriate proceeding.”15
330
Commitment to Renewable Energy
331
Q.
Does the Company have a position on the use of renewable resources?
332
A.
Yes. The Company supports the deployment of cost-effective renewable resources.
333
Currently, the Company’s owned generating capability is comprised of
334
approximately 20 percent renewable energy including wind, solar, and
13
See Docket No. 13-035-184, Report and Order, at 78 (Utah P.S.C. August 29, 2014) (dissenting, Chairman
(then Commissioner) LeVar, stated, "I believe imposition of the proposed charge represents good public
policy, sends proper price signals to homeowners considering an investment in a residential distributed
general system, and better ensures viable and stable future growth of the residential net metering program.").
14
Docket No. 14-035-114, Notices of Comment Period and Scheduling Conference, at 1; WL 6713287 at *1
(Utah P.S.C. November 21, 2014).
15
Docket No. 14-035-114, Notices of Comment Period and Scheduling Conference (Utah P.S.C. November
21, 2014).
Page 16 - Direct Testimony of Gary W. Hoogeveen
335
geothermal.16 The Company’s parent, Berkshire Hathaway Energy (“BHE”) is the
336
owner of MidAmerican Energy Company and PacifiCorp, which are, respectively,
337
the largest and second largest, rate-regulated utility owners of wind resources in the
338
U.S. according to the American Wind Energy Association. More than 42,000 Utah
339
customers are currently enrolled in the Company’s voluntary Blue Sky renewable
340
energy program. In 2015 alone, Blue Sky customers supported 159 million
341
kilowatt-hours of western region wind energy providing benefits equivalent to
342
planting 2.2 million trees. In January 2017, the Company will launch its Subscriber
343
Solar program, which is already approximately 98 percent subscribed.
344
Q.
customers?
345
346
Does the Company support providing renewable resource service options to
A.
Yes. In response to our customers’ requests for more renewable resource options,
347
the Company created its Subscriber Solar program. This program provides many
348
advantages including: no upfront costs, no long-term commitments, no installation
349
or financing costs, and appropriate rate design for participating customers. In
350
addition, the Company recently obtained approval of Tariff Schedule 34, the
351
Renewable Energy Tariff. The Company wants to provide its customers with
352
renewable options at reasonably low costs. The Company's Subscriber Solar
353
Program, which is a utility-scale solar project (also referred to as universal solar),
354
meets both criteria. For example, wholesale universal solar can be acquired today
355
for less than $0.04/kWh, whereas retail net metering costs non-participating
16
All or some of the renewable energy attributes associated with wind, solar and geothermal facilities may
be used in future years to comply with renewable portfolio standards or other regulatory requirements or
sold to third parties in the form of renewable energy credits or other environmental commodities.
Page 17 - Direct Testimony of Gary W. Hoogeveen
356
residential customers up to $0.145 kWh. As part of its parent company – BHE –
357
Rocky Mountain Power is a nationwide leader in the development of renewable
358
energy and, as such, supports customers' desire to participate in renewable energy,
359
including net metering programs, so long as those programs do not create adverse
360
impacts to the Company or its customers.
361
Q.
Company addressing with this filing?
362
363
If the Company supports renewable energy and net metering, what is the
A.
Notwithstanding the Company’s support for renewable energy, the net metering
364
program must be implemented in a cost-effective manner and consistent with state
365
laws and policies.17 The Company supports the development of cost-effective
366
renewable energy and customers' desire to participate in renewable energy
367
programs, but it must not be at the expense of other customers or the Company.
368
Customers partially relying on self-generation through the net metering program
369
must pay their fair share of the costs to serve them, including costs associated with
370
electrical infrastructure and reliable energy when the private generation system is
371
not generating sufficient energy. In addition, the structure of the net metering
372
program must send accurate price signals to all customers in order to maximize
373
benefits to the utility’s system while, at the same time, protecting other customers
374
from unfair and unexpected cost shifting. More than 820,000 Rocky Mountain
375
Power customers are currently served in Utah with safe, reliable, and efficient
17
In addition to the mandate in the Net Metering Statute, Utah Code Ann. § 54-17-602 states “to the extent
it is cost effective to do so, beginning in 2025 the annual retail electric sales in this state … must consist of
qualifying electricity or renewable certificates in an amount equal to 20 percent of adjusted gross sales.”
Page 18 - Direct Testimony of Gary W. Hoogeveen
376
electricity. The interests of all of these customers must be considered in designing
377
the net metering rate structure.
378
Q.
of their testimony.
379
380
Please identify the witnesses supporting the Company’s filing and the subject
A.
The Company’s filing is further supported by Company witness Ms. Steward who
381
testifies about the policy considerations of cost of service and rate design; the
382
unique usage and load characteristics of net metering customers that justify their
383
separation to a different class within the residential class; the Company’s transition
384
plan I discussed briefly in my testimony above; and the Company’s proposed
385
ratemaking structure, including proposed tariffs and rate design proposals.
386
Company witness Mr. Meredith explains how the ACOS, CFCOS, and the NEM
387
Breakout COS were developed, the results of the comparison of the ACOS and
388
CFCOS, and the results of the Company's NEM Breakout COS relative to how the
389
net metering program impacts various customer classes. He also describes the load
390
research study and the incorporation of that data into the cost of service studies.
391
Company witness Mr. Marx supports the engineering and administration costs that
392
are included in the cost of service studies and explains how the Company accounts
393
for private solar generation facilities in the distribution design criteria and planning.
394
He also explains the potential effects of private solar generation on the Company’s
395
grid and distribution system. Finally, Company witness Mr. Michael G. Wilding
396
provides the net power cost benefits attributed to net metering customers.
Page 19 - Direct Testimony of Gary W. Hoogeveen
397
Q.
Please summarize your testimony
398
A.
The Company's ACOS, CFCOS and NEM Breakout COS studies are appropriate,
399
reliable and were prepared consistent with the Commission's November 2015
400
Order. The results of these studies, as set forth in the testimony and exhibits
401
supporting the Compliance Filing, bear out that the current structure of the net
402
metering program does not accurately account for the actual costs and benefits that
403
net metering customers bring to the Company's system. Rather, those studies show
404
that net metering customers are currently shifting some of their costs to other
405
customers. Further, the NEM Breakout COS study shows that net metering
406
customers have unique characteristics that justify creating a separate residential net
407
metering customer class so that the costs and benefits those customers bring to the
408
system can be clearly identified and properly addressed. Based on the foregoing,
409
the Company asks that the Commission approve the Company's proposals set forth
410
in this Compliance Filing and in the concurrent tariff advice filing which address
411
the current problems with the net metering program and offer needed changes that
412
balance the interests of all customers.
413
Q.
Does this conclude you testimony?
414
A.
Yes.
Page 20 - Direct Testimony of Gary W. Hoogeveen
Rocky Mountain Power
Docket No. 16-035-____
Witness: Joelle R. Steward
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Direct Testimony of Joelle R. Steward
November 2016
1
Q.
dba Rocky Mountain Power (“the Company”).
2
3
Please state your name, business address and present position with PacifiCorp,
A.
My name is Joelle R. Steward. My business address is 1407 West North Temple,
4
Salt Lake City, Utah 84116. My present position is Director, Rates & Regulatory
5
Affairs for the Company.
6
Qualifications
7
Q.
Briefly describe your education and professional background.
8
A.
I have a B.A. degree in Political Science from the University of Oregon and an
9
M.A. in Public Affairs from the Hubert Humphrey Institute of Public Policy at the
10
University of Minnesota. Between 1999 and March 2007, I was employed as a
11
Regulatory Analyst with the Washington Utilities and Transportation Commission.
12
I joined the Company in March 2007 as a Regulatory Manager, responsible for all
13
regulatory filings and proceedings in Oregon. In February 2012, I assumed
14
responsibilities overseeing cost of service and pricing for PacifiCorp. In May 2015,
15
I assumed my current position, with broader oversight over Rocky Mountain
16
Power’s regulatory affairs in addition to the cost of service and pricing
17
responsibilities.
18
Q.
Have you appeared as a witness in previous regulatory proceedings?
19
A.
Yes. I have testified in regulatory proceedings in Idaho, Oregon, Utah, Washington
20
and Wyoming.
Page 1 – Direct Testimony of Joelle R. Steward
21
Purpose and Summary of Testimony
22
Q.
What is the purpose of your testimony?
23
A.
My testimony explains and supports the Company's filing and the proposed new
24
tariffs – Schedule 136, Net Metering Program, and Schedule 5, Residential Service
25
for Customer Generators. I also (i) explain the Company's proposal for new or
26
updated application fees for interconnection requests based on a more current
27
assessment of the administrative costs and (ii) sponsor the conforming changes in
28
the interconnection agreements.
29
Q.
Please summarize your testimony.
30
A.
The Company has experienced extensive growth in net metering since the
31
Commission initiated this proceeding following the Company's 2014 general rate
32
case. In light of that growth, the Company implemented the framework established
33
by the Commission in the first phase of this proceeding to evaluate whether the
34
costs of the net metering program exceed the benefits, as required by Utah Code §
35
54-15-105.1(1). The framework analysis is based on calendar year 2015 results,
36
which coincides with the availability of data from the Company's load research
37
study for residential net metering. The results of this analysis show that, under the
38
current rate structure, the costs of net metering exceeded the benefits by $2.0
39
million in 2015, of which $1.7 million is related to residential net metering
40
customers. This cost impact has already increased to at least $6.5 million per year
41
due to the growth in net metering in 2016. The Company estimates that, by 2020,
42
the cost shift would be $27 million per year based on current growth projections.
43
As a result, other customers will see higher rates in the future in order to pay for
Page 2 – Direct Testimony of Joelle R. Steward
44
these costs. The analysis shows that residential net metering customers pay only
45
about 60 percent of the cost to serve them, whereas other residential customers pay
46
on average 96 percent of their costs.
47
This result is largely attributed to the current rate structure for residential
48
net metering customers. The current residential rate structure was designed to
49
recover most costs through volumetric energy rates. Net metering customers
50
currently receive compensation for their excess generation at the retail energy rate.
51
Since this retail energy rate recovers most of the fixed costs necessary to serve
52
customers, net metering customers are being compensated as much as 14.5
53
cents/kilowatt-hour ("kWh"), far in excess of the value of their energy to the
54
system. In comparison, the Company pays small power producers less than 4
55
cents/kWh for their solar output through avoided cost prices.
56
Data from the load research study shows that the profile of residential net
57
metering customers is distinctly different and, while those customers may take less
58
energy (kWh) from the grid than before, their overall demand (kW) requirements
59
are not reduced proportionally. Since most costs are driven by demand, the energy-
60
based rate structure does not adequately cover costs to serve residential customer
61
generators. The magnitude of the cost shift is not as significant for non-residential
62
net metering customers because their rate structure already better captures
63
differences in usage profiles among customers in the same class. To minimize the
64
residential cost shift, the Company is proposing a new rate schedule and rate
65
structure – Schedule 5, Residential Service for Customer Generators – for
66
residential customers who apply to participate in net metering after the effective
Page 3 – Direct Testimony of Joelle R. Steward
67
date of the proposed transitional net metering program tariff, Schedule 135A, which
68
was filed concurrently with this compliance filing.
69
For Schedule 5, the Company is proposing a three-part rate structure,
70
comprised of a monthly customer charge of $15.00; a demand charge for the peak
71
periods of 3:00 p.m. to 8:00 p.m., Monday through Friday year round, with an
72
additional peak period from 8:00 a.m. to 10:00 a.m., Monday through Friday in the
73
winter months of October through April; and an energy charge. This rate structure
74
will send a better price signal to individual customers because their rates will more
75
closely align with the way costs are allocated in the cost of service study. Similar
76
to non-residential rates, this rate structure rewards customers who use the grid more
77
efficiently (i.e., higher load factor customers) with lower average rates. Residential
78
customer generators would still receive compensation through the energy charge,
79
which more closely approximates the cost to the Company to provide the equivalent
80
energy. As such, a new residential net metering customer who uses about 1,000
81
kWh per month can still achieve bill savings between 11 percent and 60 percent,
82
from their current bill, depending on how much their generation facility is able to
83
offset their usage.
84
On Schedule 136, the Company is proposing to eliminate the option for new
85
non-residential customers to receive compensation for their excess energy at the
86
average retail rate, since this rate includes recovery of fixed costs. Non-residential
87
customers may still choose between the two other compensation options, which are
88
tied to avoided costs.
Page 4 – Direct Testimony of Joelle R. Steward
89
The Company is also proposing to increase the current net metering
90
application fees. The increases are necessary to cover the administrative costs
91
necessary to process applications. For Level 1 interconnections, the Company
92
proposes to implement a one-time application fee of $60. For Level 2 and 3
93
interconnections, the Company proposes increasing the current fees to $75 plus
94
$1.50 per kW, and $150 plus $3.00 per kW, respectively.
95
Lastly, to alleviate concerns the filing will result in increased revenues for
96
the Company outside of a general rate case, the Company is willing to defer any
97
difference in revenues between current rates and the new rates on Schedule 5. The
98
Company would make a proposal for amortization of the deferral balance in its next
99
general rate case.
100
Purpose of Filings
101
Q.
Why is the Company making this filing?
102
A.
In 2014, the Utah Legislature enacted Utah Code § 54-15-105.1 ("Net Metering
103
Statute"), requiring the Commission to determine whether the costs of net metering
104
exceed its benefits or vice versa and, if so, to determine an appropriate charge,
105
credit, or rate structure based on that determination. The Commission initially
106
considered this issue in the Company's 2014 general rate case, Docket No. 13-035-
107
184 ("2014 GRC"), but opened Docket No. 14-035-114 to make the determinations
108
mandated by the Net Metering Statute. The Company prepared the analyses set
109
forth by the Commission's November 10, 2015 Order in Docket No. 14-035-114
110
(the “November 2015 Order”) to evaluate whether the costs of net metering
111
program exceed the benefits or the benefits exceed the costs. The Company used a
Page 5 – Direct Testimony of Joelle R. Steward
112
calendar year 2015 study period (“Study Period”) for the analyses, which
113
corresponds with the data collected from the Company’s load research study for
114
residential net metering customers. Over the Study Period, the Company had an
115
average of about 5,000 net metering customers.
116
Q.
Please summarize the current and forecast growth in net metering.
117
A.
Since the Company initially raised concerns about cost shifting due to net metering
118
in the 2014 GRC, there has been an increase of over 600 percent in the number of
119
net metering participants. The Company is now seeing approximately 1000 new
120
applications each month. The vast majority -- approximately 97 percent -- are from
121
residential customers. With this growth rate, the Company projects that it will have
122
over 16,000 residential net metering customers with nearly 100 MW of private
123
customer generation in Utah by the end of 2016. Figure 1 below shows the growth
124
in net metering by residential and non-residential.
125
Page 6 – Direct Testimony of Joelle R. Steward
126
Growth in private generation is expected to continue into the future. For the
127
2017 Integrated Resource Plan, the Company commissioned an independent study
128
to project the level of private generation growth over the next two decades based
129
on updated information on technology costs, performance, incentives, and market
130
conditions. This study projects an average of 40.5 MW per year of new private
131
generation capacity in Utah over the next two decades in the base case.1
132
Q.
2015 Order.
133
134
Please summarize the analyses ordered by the Commission in the November
A.
In its November 2015 Order, the Commission established a framework that
135
evaluates whether and how the net metering program impacts rates for other
136
customers. The framework provides multiple views through two different analyses
137
for perspective on how other customers' rates may be impacted by the net metering
138
program.
139
The first analysis compares two cost of service studies over a test period;
140
one that reflects the actual cost of service with net metering customers’ participation
141
(the “ACOS” study), and one under which the Company uses its best efforts to
142
estimate what the cost of service would be if net metering customers produce no
143
electricity (the “CFCOS” study). The Commission ordered that both the ACOS and
144
CFCOS studies reflect costs and benefits at the system, state, and customer class
145
levels. The second analysis segregates net metering customers in the ACOS study
146
from the class in which they participate ("NEM Breakout COS" study). For
1
Private Generation Long-Term Resource Assessment (2017-2036), Navigant Consulting, Inc., July 29,
2016,
at
26.
http://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2017_I
RP/PacifiCorp_IRP_DG_Resource_Assessment_Final.pdf
Page 7 – Direct Testimony of Joelle R. Steward
147
example, a separate residential net metering customer class is created in the cost of
148
service study, which shows the impact net metering customers have on the
149
residential non-net metering class and how well they recover the costs to serve
150
them.
151
The Commission adopted this multi-part evaluation framework to fulfill the
152
legislative requirements set in Utah Code § 54-15-105.1(1) (“Subsection One”).
153
The Commission determined that, since Subsection One is intended to be useful for
154
rate structure setting under Utah Code § 54-15-105.1(2) (“Subsection Two”), the
155
analysis necessarily must be conducted in a manner and on a period commensurate
156
with rate setting. By relying on the cost of service model, which is a key
157
consideration in the development of rates for all customers, the Commission’s
158
framework is consistent with the legislative direction and provides practical results
159
that will inform rate structuring.
160
Q.
the Commission?
161
162
What are the results of implementing the evaluation framework directed by
A.
The analyses show that the current net metering program results in higher rates for
163
other customers. Table 1 below summarizes the results of the comparison of the
164
ACOS and CFCOS studies and shows that, for the Study Period, the net metering
165
program increases costs to customers in Utah at the system, state, and class levels.
166
Table 2 below summarizes the results for the NEM Breakout COS study. The direct
167
testimony of Company witness Mr. Robert M. Meredith explains the inputs and
168
presents the results of these analyses in more detail.
Page 8 – Direct Testimony of Joelle R. Steward
Table 1. Net Cost/(Benefit) of the Net Metering Program
169
System Level
State Level
Residential
Schedule 23
Schedule 6
Schedule 8
Schedule 10
Other Classes
Total Customer Class Level
$
$
$
$
$
$
$
Cost
Benefit
(000)
(000)
$5,010 ($1,287)
$5,010 ($2,960)
3,540 $ (1,881)
504 $
(405)
673 $
(650)
240 $
(395)
29 $
(21)
22 $
393
5,009 $ (2,960)
Net Cost/
(Benefit)
(000)
$3,722
$2,049
$ 1,659
$
100
$
23
$
(155)
$
7
$
415
$ 2,049
Table 2. Actual Cost of Service Results of Segregated Net Metering Classes
170
Residential
Schedule 23
Schedule 10
Schedule 6
Schedule 8
Parity to Cost of Service
ACOS
ACOS
W/O
NEM
ACOS
NEM
96.0%
96.1%
60.6%
107.2%
107.3%
92.2%
95.3%
95.1%
89.8%
107.7%
107.7% 109.2%
104.1%
104.0% 109.0%
These results show that, for the residential class, the current net metering
171
program results in higher rates for other residential customers.
172
173
Q.
Why does the net metering program result in higher rates for other customers?
174
A.
The primary reason is because the revenue received from net metering customers
175
does not cover the costs of serving them. This is shown explicitly in Table 2 where
176
the net metering residential class is paying only about 61 percent of their cost of
177
service. In contrast, the other residential class pays 96 percent of their cost of
178
service. Mr. Meredith’s Exhibit RMP__(RMM-1) shows that the net cost shifted to
179
other residential customers from net metering is approximately $400 per year per
Page 9 – Direct Testimony of Joelle R. Steward
180
residential net metering customer. This means that the rates for other residential
181
customers are or will be increased to cover the costs incurred to serve residential
182
net metering customers. The analyses take into account the unique characteristics
183
of net metering customers and the value provided by their private generation
184
systems. Despite the benefits created by their private generation systems, the
185
current rate structure does not adequately recover the costs to serve them and
186
essentially over-compensates residential net metering customers for their
187
generation.
188
This result is largely caused by the fact that the current residential rate
189
structure relies on recovering most costs through volumetric energy rates. As the
190
results in Tables 1 and 2 show, the magnitude of the net metering cost shifting for
191
the non-residential rate classes isn’t as significant. This disparity is due to the
192
difference in the rate structures between residential and non-residential rates that I
193
will discuss later in my testimony.
194
Q.
net metering is not addressed soon?
195
196
What is the potential impact of the cost shift to other residential customers if
A.
While the analysis for the 2015 Study Period shows a cost shift for residential net
197
metering in Utah of $1.8 million under the NEM Breakout, extrapolating that level
198
of cost shifting to current residential net metering participation as of October 7 of
199
this year produces a cost shift of $6.5 million due to the rapid growth in
200
installations. By 2020, the cost shift would be about $27 million per year based on
201
the current growth projections. At the current net metering program cap of 923 MW
202
(i.e., 20 percent of the 2007 peak load) set by the Commission in Docket No. 08-
Page 10 – Direct Testimony of Joelle R. Steward
203
035-78, the potential cost shift to other customers would be approximately $78
204
million annually. Over the next 20 years, the cumulative cost shifting related to
205
residential net metering is estimated to be approximately $667 million.
206
In order to minimize this cost shift, the Company is proposing to close the
207
current net metering program to new customers and to implement modifications to
208
the program that will mitigate cost shifting while providing more appropriate
209
compensation to net metering customers. In light of the adverse impacts on other
210
customers, the Company is proposing net metering program and residential rate
211
changes for customer generators in order to moderate future impacts.
212
Overview of Proposed Tariff Revisions
213
Q.
impacts of the net metering program on other customers.
214
215
216
217
218
219
220
Please summarize the Company’s proposed tariff revisions to address cost
A.
In conjunction with Tariff Advice No. 16-13, filed concurrently with this
Compliance Filing, the Company is requesting approval of the following:
1. Revisions to Schedule 135, Net Metering Service, to close it to new service,
effective after December 9, 2016;
2. Schedule 135A, Net Metering – Transition Service, effective after
December 9, 2016;
221
3. Schedule 136, Net Metering Program, effective June 1, 2017, for
222
modifications to the net metering program for applications received after
223
December 9, 2016; and
Page 11 – Direct Testimony of Joelle R. Steward
224
4. Schedule 5, Residential Service to Customer Generators, effective June 1,
225
2017, for new rates to residential customers who submit applications for net
226
metering after December 9, 2016, and are interconnected.
227
Exhibit RMP__(JRS-1) contains the proposed tariffs for Schedule 136 and
228
Schedule 5. In addition to these tariff changes, the Company proposes changes to
229
the application fees currently authorized by R746-312-13. The proposed
230
application fees are based on the Company’s experience and actual costs to process
231
net metering applications. Exhibit RMP__(JRS-2) contains revisions to the
232
interconnection agreements to update the application fee changes in this filing, as
233
required by R746-312-17(1)(f).
234
Q.
Please explain the Company’s proposed tariff changes in Advice No. 16-13.
235
A.
Advice No. 16-13 seeks modifications to Schedule 135, Net Metering Service, to
236
close it to new service and to implement a new Schedule 135A, Net Metering –
237
Transition Service. Schedule 135A mirrors the current Schedule 135 with the
238
exception that it includes the following provision in the Availability Section:
239
Customers will be subject to all changes to net metering service including
240
changes to credits, charges or rate structures offered herein and in related
241
tariffs resulting from the final determination under Utah Code Ann. § 54-
242
15-105.1 which may include, without limitation, a transfer from this tariff
243
to all new applicable service schedules approved by the Commission.
244
The Company proposes to have Schedule 135A in effect until the Commission
245
makes a determination on Subsection Two of the Net Metering Statute and
246
substantive modifications to the net metering program, which the Company seeks
Page 12 – Direct Testimony of Joelle R. Steward
247
in the present Compliance Filing. The Company is proposing an effective date of
248
December 10, 2016, for the tariff changes in Advice No. 16-13. The Company is
249
requesting these tariff changes for Schedules 135 and 135A to provide interim
250
service to customers that submit applications for net metering service under terms
251
consistent with the current program.
252
Q.
Why is the Company proposing the changes in Advice No. 16-13?
253
A.
To mitigate potential cost shifts to other customers, the Company proposes to
254
implement Schedule 135A as a transition tariff that will provide explicit notice to
255
new net metering applicants that there may be changes to the service and rates for
256
net metering customers following the conclusion of this proceeding. Without this
257
transition tariff and notice, the Company would expect a significant groundswell of
258
new program applications in the hopes that any program modifications would not
259
apply to net metering customers for whom applications had been received or
260
interconnections completed prior to the final Commission determination in this
261
proceeding. The advice filing includes revisions to the standard interconnection and
262
net metering service agreements to reference the tariff schedule change.
263
Q.
Please explain proposed tariff Schedule 136.
264
A.
Schedule 136 provides net metering service with modifications to address cost
265
shifting as reflected in the results of the analyses directed by the Commission. As
266
discussed by Company witness Mr. Gary Hoogeveen, since the costs of distributed
267
generation, in particular rooftop solar photovoltaic, have significantly decreased
268
over the last few years, incentives in the form of the current retail rates are no longer
269
necessary. The specific changes to the program include:
Page 13 – Direct Testimony of Joelle R. Steward
270
1. A new provision that requires residential customers who participate in the
271
net metering program to take electric service under the proposed Schedule
272
5, Residential Service for Customer Generators; and
2. Elimination of the option for large non-residential customers to receive
273
compensation for excess generation at the average retail rate.
274
275
I address each of these in more detail below. The other features of the net metering
276
program remain unchanged.
277
Overview of Schedule 5 - Electric Service for Customer Generators
278
Q.
for residential customer generators, Schedule 5.
279
280
Please summarize the Company’s proposal to implement a new rate schedule
A.
The Company is proposing a new rate structure for residential customer generators
281
who participate in the net metering program under Schedule 136. The proposed rate
282
structure will more directly capture the benefits these customers bring in rate setting
283
as well as the costs, on both a class level and individual customer level, and will
284
minimize cost shifting to other customers. Specifically, the Company is proposing
285
a rate structure similar to that used for non-residential customers, comprised of a
286
monthly customer charge, a peak demand charge, and an energy charge. Exhibit
287
RMP_(JRS-3) and Table 3 below show the proposed rates for Schedule 5.
Page 14 – Direct Testimony of Joelle R. Steward
Table 3
288
289
Q.
How were these rates calculated?
290
A.
While the ACOS and CFCOS are useful for evaluating the impacts of the net
291
metering program, the NEM Breakout COS study is more instructive in rate
292
structuring under Subsection Two in the Net Metering Statute, as the Commission
293
noted in its November 2015 Order.2 Accordingly, the Company used the cost of
294
service from the NEM Breakout COS study results presented in this filing and
295
adjusted the results to the revenue requirement and current rates approved by the
296
Commission in the Company’s 2014 GRC. In this way, the new rates on Schedule
297
5 for customer generators are consistent with the revenue requirement and rates
298
designed to recover that revenue requirement for all customers approved by the
2
November 2015 Order, at 11.
Page 15 – Direct Testimony of Joelle R. Steward
299
Commission in the 2014 GRC. The NEM Breakout COS results are used as the
300
starting point because they reflect the usage characteristics of the net metering class
301
from the 2015 load research study. The adjustment process from the current cost of
302
service study to the 2014 GRC is explained in more detail in Mr. Meredith’s direct
303
testimony.
304
Q.
metering customers?
305
306
Why is the Company proposing this new rate schedule for only residential net
A.
As shown above, the cost of service analyses demonstrate that as a result of the
307
large credit residential net metering customers receive through current rates for
308
their excess generation, other customers' rates will increase in order to recover the
309
same costs over fewer volumes. While the overall magnitude of the cost shifting is
310
relatively small now, providing a separate rate schedule and a new rate structure for
311
residential net metering customers will minimize the impact on other customers and
312
reflect the different characteristics of residential net metering customers.
313
In addition, as Mr. Meredith’s testimony shows, the cost shifting concern is
314
less significant or even non-existent for non-residential classes. As I’ll show later,
315
the rate structures for non-residential customers already send better price signals
316
and accommodate differences in load profiles for customers within the class, so
317
costs are less likely to be under-recovered. For these reasons the Company is not
318
proposing changes to the rate structures for non-residential net metering customers
319
at this time. However, I do recommend elimination of the option for compensation
320
at the average retail rate for excess energy for large non-residential customers, as
321
discussed further below.
Page 16 – Direct Testimony of Joelle R. Steward
322
Q.
from other residential customers?
323
324
How are the characteristics of residential net metering customers different
A.
Data from the Company’s load research study for residential net metering
325
customers, discussed in more detail in Mr. Meredith’s testimony, shows that
326
customers with on-site private generation have a different load profile than other
327
residential customers, but not necessarily a different peak requirement. Figures 2
328
and 3 compare the profiles from the 2015 study. Figure 2 is the average annual
329
hourly load and Figure 3 is the peak day.
330
Page 17 – Direct Testimony of Joelle R. Steward
331
332
As Figure 2 shows, while net metering customers may take less energy
333
(kWh) from the grid, their overall demand (kW) requirements from the grid may
334
remain relatively unchanged. However, since costs associated with demand are
335
recovered in the energy charges, net metering customers get credited for demand-
336
related costs through the netting process for excess generation output, even though
337
they continue to place a demand requirement on the system. In contrast to non-
338
residential customer rate designs, the residential rate structure does not adequately
339
capture the demand requirements placed on the system to serve these customers
340
because it largely relies on energy charges. Net metering customers’ usage also
341
results in lower load factors for net metering customers compared to other
342
residential customers. Lower load factors have more variability in usage and are
343
more costly to serve than flatter, more consistent usage patterns.
Page 18 – Direct Testimony of Joelle R. Steward
344
Q.
partially served by their own generation?
345
346
Aren’t net metering customers similar to small use customers if they are
A.
No. Almost all net metering customers have solar private generation systems. The
347
peak energy output of these solar systems occurs in the middle of the day prior to
348
the timing of both the system and class level peaks. As a result of this output, the
349
energy requirements for these customers are reduced, but the peak demand is either
350
unchanged or reduced very modestly. This results in lower (less efficient) load
351
factors for these customers. In contrast, the profile for all residential customers is
352
very consistent between different energy usage levels. Figure 4 below shows a
353
comparison of the profiles among different energy usage levels in the load research
354
sample for all residential customers.
355
356
In addition to lower load factors, residential net metering customers
357
fundamentally use the system differently than low energy-use residential
358
customers, since they use the energy grid not only to receive energy from the
359
Company’s facilities, but also to export excess energy that they produce to the
Page 19 – Direct Testimony of Joelle R. Steward
360
Company’s system. Table 4 below shows the difference in average characteristics
361
between residential customers with and without generation.
Table 4. Differences in Customer Characteristics
362
363
Q.
allocations and rate designs.
364
365
Please explain why demand costs are an important consideration in cost
A.
A customer class’s demand requirements – the class’s usage during the single hour
366
of each of the system coincident peaks and state distribution coincident peaks –
367
significantly influences cost incurrence and allocation. For instance, Table 5 below
368
shows the difference in cost drivers in the cost of service study for the residential
369
class in the ACOS and then the residential class in the NEM Breakout COS. Table
370
5 shows that over 60 percent of costs are allocated on demand-based measurements.
371
Most of the Company’s costs are allocated in class cost of service studies on
372
demand-based measurements because the system is designed to serve load at
373
different peaks.
374
Table 5. Residential Cost Allocation Drivers
Page 20 – Direct Testimony of Joelle R. Steward
375
Q.
problematic.
376
377
Please elaborate on why providing a credit at the current full retail rate is
A.
As the NEM Breakout COS study demonstrates (see Table 2 above), the cost of
378
service results for residential net metering customers are different than the results
379
for other residential customers; residential net metering customers contribute about
380
61 percent to the cost of serving them, compared to other customers who cover
381
about 96 percent of the costs to serve them. This difference is due to the current net
382
metering compensation approach, which provides a credit for a customer’s private
383
generation output at the full retail rate.
384
Currently, recovery of nearly all of the infrastructure costs for the electric
385
system allocated to residential customers is achieved entirely through energy rates.
386
Figure 5 below shows that while approximately 70 percent of residential costs are
387
demand- or customer-related costs, over 90 percent of the revenue comes from
388
variable energy-related charges.
389
Page 21 – Direct Testimony of Joelle R. Steward
390
As a result of current residential rate design, the credit that net metering
391
customers receive for generation output in excess of their usage includes the costs
392
for the infrastructure required to serve them. The residential retail rate ranges from
393
8.5 cents per kWh to 14.5 cents per kWh. In contrast, the Company purchases
394
power from third-party developers through avoided cost pricing at less than 4 cents
395
per kWh, so the purchase of excess output from net metering customers is more
396
costly to other customers than if the Company had generated the energy itself or
397
purchased it from a third party.
398
Proposed Rate Structure
399
Q.
Schedule 5.
400
401
402
Please describe what is included in each of the proposed rate components for
A.
The proposed rates are comprised of the following costs:
•
The monthly customer charge of $15.00 is designed to recover costs related to
403
customer services and certain components of the distribution system,
404
specifically service lines, meters, and line transformers. This customer charge
405
assumes that the Commission adopts the Company’s proposed application fee
406
for Level 1 net metering customers, discussed later in my testimony. The
407
Company proposes to recover the program administrative costs through a one-
408
time application fee rather than through base rates. The customer charge would
409
be higher if the administrative costs associated with handling applications is not
410
recovered through a separate, one-time fee.
411
412
•
The demand charge is designed to recover the remaining distribution-related
costs (substations, poles and conductors) and the demand-related generation
Page 22 – Direct Testimony of Joelle R. Steward
413
and transmission costs. The demand charge would be applied against the
414
customer’s highest demand during a 60-minute interval during the on-peak
415
periods. The Company is proposing to set the on-peak period from 3:00 p.m. to
416
8:00 p.m. during the summer months of May through September, and 8:00 a.m.
417
to 10:00 a.m. and 3:00 p.m. to 8:00 p.m. in the winter months of October
418
through April. The on-peak period is Monday through Friday, excluding
419
holidays.
•
420
The energy charge is designed to recover all remaining costs, which include net
power costs.
421
422
Q.
What are the advantages of this rate structure?
423
A.
The proposed rate structure balances the regulatory objectives of customer
424
understanding, cost causation, economic efficiency, revenue adequacy, intra-class
425
equity, and inter-class equity. While a demand charge is a new element for
426
residential customers, the Company is proposing a relatively simple structure that
427
includes just three elements –-a customer charge, a demand charge, and an energy
428
charge – in order to balance customers' ability to understand the new structure with
429
cost incurrence. Since customer generators are typically more sophisticated energy
430
customers, the concept of demand or system kW requirements should be
431
understandable because kW is typically how private generation facilities are sized
432
and purchased. Demand charges are a standard rate design element for non-
433
residential customers already, however, the Company’s proposed demand charge
434
for residential customer generators includes several elements that will make it
435
easier for residential customers to manage. The rate structure also reduces the
Page 23 – Direct Testimony of Joelle R. Steward
436
likelihood that the system costs required to serve customer generators are
437
systematically under-recovered and then shifted to other customers. The rate
438
structure rewards higher load factor customers with a lower average rate, and better
439
captures diversity within the class.
440
Q
use?
441
442
Will the rates provide a price signal to customers to encourage more efficient
A.
Yes. Including an on-peak demand charge will send a better price signal to these
443
individual customers than the current rate design because their rates will be in closer
444
alignment with the different cost categories included in the cost of service study.
445
Residential net metering customers will have an opportunity to reduce their bills by
446
responding to these prices during the specific on-peak periods. The proposed
447
demand charge sends a signal to both stagger and reduce appliance use during the
448
peak period. In the short run, customers can modify their behavior so that their peak
449
usage occurs at the same time as their generation. In the long run, customers can
450
invest in resources that better match the timing of the peak usage. For example,
451
they could install solar panels that are more westerly facing to produce more energy
452
in the afternoon and early evening, which better aligns with the Company’s peak,
453
providing more benefit by reducing overall demand.
454
Q.
Please provide an example of how the rates provide better price signals.
455
A.
Unlike the rate structure for non-residential customers, the current residential rate
456
structure with inclining energy rates directly rewards lower energy usage but not
457
more efficient usage that helps to reduce overall system costs by also reducing
458
demand. For residential customers, this signal to reduce overall demand is assumed
Page 24 – Direct Testimony of Joelle R. Steward
459
to be an incidental or accompanying result of reducing overall energy usage.
460
However, as I demonstrate above, net metering customers may reduce their energy
461
usage but not their demand, resulting in becoming lower load factor customers. The
462
proposed rate structure on Schedule 5 will better capture this change in usage and
463
reward improving load factors to achieve a lower average rate. Figure 6 below
464
shows the proposed Schedule 5 rates will provide lower average rates for higher
465
load factor customers, similar to non-residential rate structures, to reward more
466
efficient usage of the system.
Figure 6. Average Price Compared to Load Factor
467
468
Q.
Please explain why $15.00 per month is a reasonable customer charge.
469
A.
The Company is proposing to include the costs associated with customer services,
470
meters, service lines, and transformers in the customer charge. These are essentially
471
fixed costs and not subject to variability in customer usage.
Page 25 – Direct Testimony of Joelle R. Steward
472
Q.
Why should transformers be included in the customer charge for Schedule 5?
473
A.
Local distribution facilities such as transformers, poles, and conductors are
474
facilities required to provide a residential customer access to electric service
475
regardless of how much energy the customer uses. While this is true for all
476
residential customers, net metering customers place additional burdens and reliance
477
on these local facilities since they use them for both taking service from the
478
Company and to export their excess generation output to the grid. The impacts of
479
customer generation on the local distribution system, including transformers, are
480
discussed in more detail in the testimony of Mr. Douglas L. Marx.
481
Accordingly, since customer generation relies on the local distribution
482
system and can actually lead to additional costs to accommodate the output of
483
excess energy onto the system, as discussed by Mr. Marx, it would not be
484
appropriate to reflect local distribution costs in the energy credit received by net
485
metering customers for excess energy. The Company proposes to include the cost
486
of the transformers in the customer charge and the costs of the other local
487
distribution facilities in the demand charge.
488
While the Company does not dedicate one transformer per customer, like
489
meters and service lines that are included in the customer charge, the allocation
490
approach in the cost of service study reflects the assumption that transformers are
491
shared and a coincidence factor is used to recognize the diversity of usage that is
492
considered with the initial sizing. In addition, a large portion of the cost of a
493
distribution line transformer is associated with the equipment itself and does not
494
vary with the capacity of the equipment. For example, a 25 KVA single phase pad-
Page 26 – Direct Testimony of Joelle R. Steward
495
mount transformer and a 50 KVA single phase pad-mount transformer, which are
496
commonly installed in residential subdivisions, have average installed costs of
497
$4,700 and $4,827, respectively. Although, the 50 KVA transformer provides
498
double the demand capacity of the 25 KVA transformer, it only costs about 3 percent
499
more. Clearly, a large proportion of the costs of these transformers do not vary with
500
capacity and are fixed infrastructure costs necessary to serve customers.
501
Q.
Is the Company proposing a minimum bill in addition to the customer charge?
502
A.
No. The Company is proposing only a monthly customer charge of $15.00 for
503
Schedule 5 customers. All other charges on the bill will be subject to usage
504
measurements.
505
Q.
apply to Schedule 5 customers?
506
507
How did the Company calculate the demand charge and how will this charge
A.
The proposed demand charge of $9.02 per kW is designed to recover the costs of
508
demand-related generation and transmission, which are allocated in class cost of
509
service studies on system coincident peaks, and distribution substations and poles
510
and conductors, which are allocated on distribution coincident peaks. The rate was
511
calculated by dividing these costs by the kW usage during the proposed on-peak
512
hours. The proposed on-peak periods are: 3:00 p.m. to 8:00 p.m. during the summer
513
months of May through September, and 8:00 a.m. to 10:00 a.m. and 3:00 p.m. to
514
8:00 p.m. during the winter months of October through April. All weekends and
515
holidays are excluded from the on-peak hours.
Page 27 – Direct Testimony of Joelle R. Steward
516
The charge would be applied to the customer’s highest measured average
517
kW usage during a 60 minute interval during on-peak times, during each billing
518
cycle.
519
Q.
demand charge?
520
521
How did the Company select the on-peak periods proposed for the Schedule 5
A.
To determine the appropriate times under which the demand charge would apply,
522
the Company examined the timing of both system coincident and distribution
523
coincident peaks over the last five class cost of service studies filed with the
524
Commission. This showed that most peaks occurred in the late afternoon/early
525
evening timeframe in the summer months and both in the late afternoon/early
526
evening and morning during the winter. In order to keep the rate design
527
understandable and simple, the Company identified time periods that capture the
528
vast majority of those peaks for both seasons. Additionally, the Company is
529
proposing to use the same defined periods for Summer (May - September) and
530
Winter (October - April) as current rates. The proposed on-peak periods include the
531
timing of 94 percent of the peaks. Exhibit No. RMP_(JRS-4) shows the hourly
532
occurrence of peaks in the Summer and Winter seasons and the on-peak period the
533
Company selected for proposed Schedule 5.
534
Q.
residential customers?
535
536
537
How does the proposed demand charge compare to demand charges for non-
A.
To moderate the impacts and make it easier for residential customers to respond to
the price signal, the proposed charge is designed to apply over fewer hours, is
Page 28 – Direct Testimony of Joelle R. Steward
538
measured over a longer interval, and is a lower charge than non-residential demand
539
charges.
540
First, the proposed demand charge applies during a smaller window of time
541
during the day compared to non-residential rates so that customers’ energy
542
management efforts can be more targeted to those hours. During Summer, for
543
instance, customers need to pay attention to only 5 hours per day, from 3:00 p.m.
544
to 8:00 p.m. In contrast, the Summer on-peak period for Schedule 6A is 16 hours,
545
from 7:00 a.m. to 11:00 p.m., and for Schedule 8 it is 8 hours, from 1:00 p.m. to
546
9:00 p.m.
547
Second, to measure the kW usage, the Company proposes to take the
548
average kW measurement over a 60-minute interval rather than the 15-minute
549
interval used for non-residential customers. Averaging the usage over a longer
550
period will help moderate impacts of sporatic appliance usage. For instance, Exhibit
551
RMP_(JRS-5) shows an example of usage for a number of appliances during a 60-
552
minute period. Taking an average over the 60-minute interval produces a demand
553
measurement of 3.4 kW, whereas taking the measurement over the highest 15-
554
minute interval produces a measurement of 6.3 kW.
Lastly, the proposed demand charge for Schedule 5 is considerably smaller
555
than non-residential demand charges.
556
557
Q.
net metering customers?
558
559
560
Why is a time-based demand charge preferable to time-of-use energy rates for
A.
If these demand-related costs were included in time-of-use energy rates, they would
be included in the rates that customers are compensated for in their excess energy
Page 29 – Direct Testimony of Joelle R. Steward
561
output due to the netting process. Since the customer's usage during the peak period
562
contributed to these costs, these customers would be over-compensated for their
563
excess energy and costs would continue to be under-recovered and shifted to other
564
customers.
565
Q.
Please discuss the proposed energy charge.
566
A.
The energy charge recovers variable costs including net power costs and a portion
567
of the generation and transmission investments (25 percent). The generation and
568
transmission investment portion is consistent with the cost of service classification
569
methodology adopted by the Commission. For customer generators, this energy
570
charge better reflects the value of the excess kWh output by the customer facility.
571
Under net metering, any excess kWh generated by the customer at one point in time
572
will be offset against customer usage taken from the Company at another point in
573
time. This energy charge more closely approximates the cost that the Company
574
would have otherwise incurred in order to serve the customer and is a much more
575
equitable compensation value to provide customer generators.
576
Q.
customers?
577
578
Will the proposed rates on Schedule 5 still provide value to net metering
A.
Yes. Exhibit RMP__(JRS-6) shows the calculation of the average offset credit
579
under the current and proposed rates for net metering customers. The average offset
580
credit is the value in bill savings that customers receive for every kWh their
581
generation produces. Currently, the Company provides to net metering customers,
582
on average, an offset credit of 10.6 cents/kWh for their generation. Under the
583
Company’s proposed rates, net metering customers will receive an average offset
Page 30 – Direct Testimony of Joelle R. Steward
584
credit of 7.1 cents/kWh. The proposed rates still provide considerable value to
585
customer generation.
586
Q.
customers on Schedule 5 compared to current Schedule 1 residential rates?
587
588
Have you prepared examples of the potential bill impacts for net metering
A.
Yes. Exhibit No. RMP_(JRS-7) shows the comparison between the amount
589
customers currently pay at different usage levels compared to their bills under net
590
metering service and the proposed Schedule 5 rates. This shows that an average net
591
metering customer who uses approximately 1,000 kWh a month can still achieve
592
bill savings between 9 percent and about 60 percent, depending on how much of
593
their usage they are able to offset with their generation facility.
594
Q.
Will the Company provide information to customers to help them understand
595
the new rate structure on Schedule 5 and how they can better manage their
596
usage?
597
A.
Yes. The Company will work with interested parties to develop information for
598
Schedule 5 customers to help them understand the rate structure and how changes
599
in their usage will influence their bill.
600
Q.
opt-in to net metering service on Schedule 136 and Schedule 5?
601
602
Will the Company allow current net metering customers on Schedule 135 to
A.
Yes. The Company will accommodate any current residential Schedules 135 and 1
603
net metering customer to transfer to Schedule 136 and Schedule 5. If a customer
604
elects to transfer to Schedule 136, the customer will no longer be eligible to return
605
to Schedule 135.
Page 31 – Direct Testimony of Joelle R. Steward
606
Modifications to Large Non-Residential Compensation Options
607
Q.
metering customers on Schedule 135.
608
609
Please explain the current compensation options for large non-residential net
A.
Special Condition 2b in Schedule 135 provides the following options to large non-
610
residential customers for the compensation of excess energy produced by customer
611
generation facilities during a billing period:
612
(1) An Average Energy Price for the applicable calendar year according to
613
the Volumetric Non-Levelized Prices shown in Schedule 37, weighted by season
614
and on- and off-peak periods;
615
(2) A Seasonally Differentiated Energy Price for the applicable calendar
616
year according to the Non-Levelized Prices shown in Schedule 37, weighted by on-
617
and off-peak periods; and
618
(3) An average retail rate for the Electric Service Schedule applicable to the
619
net metering customer as calculated from the previous year’s Federal Energy
620
Regulation Commission Form No. 1.
621
Q.
What is the difference in the value of these options for 2016?
622
A.
Table 6 below shows difference in the compensation credit for each of these options
623
for 2016.
Page 32 – Direct Testimony of Joelle R. Steward
Table 6
624
Large Non-Residential
Options
Option 1. Average Sch 37 Price
Option 2. Seasonal Sch 37 Price
Summer
Winter
Option 3. Average Retail Price
Schedule 6
Schedule 6A
Schedule 6B
Schedule 8
Schedule 10
625
Q.
2.0345
1.8062
1.7515
1.5232
8.4498
11.7871
10.8910
7.5210
7.5619
Please explain the Company's proposed changes to the large non-residential
options in the new Schedule 136.
626
627
2016 Credit (¢/kWh)
Baseload
Fixed Solar
1.8821
1.5991
A.
The Company proposes to eliminate the third option of using the average retail
628
price for excess energy from large non-residential customers. Table 6 above shows
629
that the average retail rate credit option provides a credit far in excess of the avoided
630
cost value that other small power producers would receive for the equivalent output.
631
There is also a wide distinction on the compensation by rate schedule with
632
customers on Schedule 6A getting 57 percent more for each excess kWh compared
633
to Schedule 8 customers, even though there is no discernible difference in the value
634
to the system for a kWh generated by a customer on Schedule 6A versus Schedule
635
8.
636
Not surprisingly, Option 3 is the option selected by all large non-residential
637
net metering customers. In 2015, large non-residential customers were credited
638
approximately $141,000 for their excess energy. This is 420 percent more than the
Page 33 – Direct Testimony of Joelle R. Steward
639
avoided cost value under Options 1 or 2. In contrast to the avoided cost value, the
640
average retail rate includes recovery of fixed costs typically collected through the
641
monthly charge and demand charges. Accordingly and as I previously discussed in
642
regards to residential customers, the average retail rate over-compensates non-
643
residential customers for excess energy.
644
To create consistency between large non-residential customers and to be
645
consistent with the value provided to other small power producers, the Company
646
proposes to use Schedule 37 avoided costs prices for fixed solar facilities, under
647
either Option 1 or 2.
648
Proposed Changes to Application Fees for Net Metering
649
Q.
metering.
650
651
Please explain the Company's proposed changes to the application fees for net
A.
The Company requests that the Commission waive the fees adopted in rule R746-
652
312-133 and approve changes in the fees, including adding a fee for Level 1
653
applications, as follows:
Table 7
654
Net Metering Application Fees Current Proposed Level 1 Level 2 per kW 0 $50 $1.00 $60 $75 $1.50 Level 3 per kW $100 $2.00 $150 $3.00 3
R746-312-3(2) states: For good cause shown, the commission may waive or otherwise modify any provision
of this electrical interconnection rule.
Page 34 – Direct Testimony of Joelle R. Steward
655
These fees are based on an assessment of the actual costs incurred to process
656
applications. Recovery of the costs to process the applications for net metering,
657
particularly for Level 1, has not kept pace with the growth in applications. The
658
modest increases in fees represent movement toward recovering the administrative
659
costs incurred to process applications and make cost recovery more concurrent with
660
expense.
661
Q.
How were the current application fees established?
662
A.
The current fees were established by the Commission in the rulemaking initiated in
663
2009, Docket No. 09-R312-01, to implement standards for interconnection of
664
electric facilities in Rule R746-312, Electrical Interconnection. These rules
665
establish the terms and conditions upon which a customer may interconnect a
666
generation facility to the distribution system and the review process for the utility
667
to ensure that the interconnection will be consistent with these terms and conditions.
668
The rules identify three potential levels of review, based on the size of the facility
669
to be interconnected as well as the complexity of the review – Level 1 for facilities
670
25 kW and smaller, Level 2 for facilities greater than 25 kW or that do not otherwise
671
qualify under Level 1, and Level 3 for facilities that do not otherwise qualify under
672
Levels 1 or 2 and require a more complex review. Mr. Marx outlines the
673
administrative process for net metering applications in his direct testimony.
674
Q.
How did you calculate the proposed fees requested in this filing?
675
A.
The Company reviewed the actual costs incurred to process applications in 2015,
676
the number of applications completed for each level, and the allocation of these
677
costs by rate schedule. The allocation by rate schedule is discussed in the testimony
Page 35 – Direct Testimony of Joelle R. Steward
678
of Mr. Meredith. Exhibit RMP_(JRS-8) shows the breakdown by level and rate
679
schedule of applications processed during 2015. Out of about $560,000 in costs to
680
process the applications, the Company recovered only about $17,000 in fees from
681
Level 2 and Level 3 applications. Because the vast majority of applications, about
682
99 percent, are Level 1, the majority of the costs are related to Level 1 applications.
683
To better balance cost incurrence with recovery, the Company is proposing
684
a Level 1 fee along with increases in the fees for the other levels. Since the majority
685
of Level 1 applications are for residential customers, the calculation of the
686
Company's proposed Level 1 fee was based upon the average cost of processing a
687
residential net metering application, which was about $60. Applying the $60 fee to
688
all Level 1 applications would have produced about $474,000 of application fee
689
revenue or about 85 percent of the total $560,000 cost to process applications in
690
2015. The addition of a Level 1 fee removes about $443,000 out of the costs
691
included in proposed rates for Schedule 5. These one-time costs are more
692
appropriately recovered through a one-time fee rather than embedded into rates. If
693
the net metering application-related costs were alternatively recovered through the
694
basic charge on Schedule 5, the proposed basic charge would be higher by $8.41
695
per month.
696
To gradually move towards better recovery of all net metering application
697
fees, the Company proposes a uniform 50 percent increase to Level 2 and Level 3
698
application fees. For Level 2, the Company proposes a $25 increase to the charge
699
per application and a 50 cent increase to the per kW charge. For Level 3, the
700
Company proposes a $50 increase to the charge per application and a one dollar
Page 36 – Direct Testimony of Joelle R. Steward
701
increase to the per kW charge. Increasing the application fees will reduce the costs
702
needed in rates for other customers and retain the proportional relationship between
703
the fees by level, without creating a barrier for participation. Based on the 2015
704
costs, these increases are still conservative and will encourage the Company to find
705
efficiencies in the administrative process.
706
Deferral for Incremental Revenue from Schedule 5
707
Q.
collection of revenues to the Company?
708
709
Would approval of the proposed tariff changes in this filing result in an over-
A.
No. The Company is proposing to apply the changes to only new net metering
710
customers that file applications after approval of Schedules 136 and 5. Since the
711
current number of net metering customers exceeds the assumed number of net
712
metering customers included in the forecast in the 2014 GRC by over 600 percent,
713
current rates do not reflect the costs of serving these customers. Accordingly, the
714
Company is absorbing the costs of net metering for current customers. The
715
Company will continue to absorb these costs until a new rate case is filed and the
716
costs can be captured in rates to other customers. Approval of the new Schedule 5
717
would reduce the growing impact that will be eventually captured in rates.
718
While the Company does not expect the new structure to result in an
719
increase in income for the Company, it will result in the higher revenues than would
720
otherwise be achieved as a result of better reflecting the cost to serve net metering
721
customers. To minimize the future impact on other customers, the Company
722
proposes to defer the difference in revenue associated with the new rates on
723
Schedule 5. In this way, the filing will be revenue-neutral for the Company.
Page 37 – Direct Testimony of Joelle R. Steward
724
Q.
Please explain how the proposed deferral would work.
725
A.
For new residential net metering customers, the Company would calculate the
726
difference in revenues between current rates and Schedule 5 rates based on actual
727
billed usage. This difference could be higher or lower for each customer. At the
728
time of the Company's next rate case, the Company would make a proposal for
729
amortization of the deferral balance.
730
Q.
Does this conclude your testimony?
731
A.
Yes.
Page 38 – Direct Testimony of Joelle R. Steward
Rocky Mountain Power
Exhibit RMP___(JRS-1)
Docket No. 16-035-__
Witness: Joelle R. Steward
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Joelle R. Steward
Proposed Tariff Revisions (Schedule 136 and Schedule 5)
November 2016
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 1 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 5.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 5
STATE OF UTAH
______________
Residential Service for Customer Generators
______________
AVAILABILITY: At any point on the Company's interconnected system where there are
facilities of adequate capacity.
APPLICATION: This Schedule is for alternating current electric service for residential
purposes supplied at approximately 120 or 240 volts through one meter at a single point of delivery for
service required on the premises to any residential customer who has executed an Interconnection
Agreement under Schedule 136, Net Metering Program.
When conditions are such that service is supplied through one meter to more than one dwelling
or apartment unit, the charge for such service will be computed by multiplying the number of kWh in
each applicable usage block, the Customer Service Charge, the Power Charge and the minimum
charges by the maximum number of dwelling or apartment units that may be served.
When a portion of a dwelling is used regularly for business, professional or other gainful
purposes and 50 percent or more of the electrical energy supplied to that dwelling is being used for
residential purposes, the premises shall be subject to this or other residential rates. If 50 percent or
more of the electrical energy supplied to the premises is used for other than residential purposes, the
premises will be classified as non-residential and electric service shall be provided under the
appropriate non-residential schedule. However, if the wiring is so arranged that the service for
residential purposes can be metered separately, this Schedule will be applied to such service.
MONTHLY BILL:
Customer Service Charge:
Single phase: $15.00 per customer
Three phase: $30.00 per customer
Power Charge:
On-Peak: $9.02 per kW
Off-Peak: None
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 16-035-__
FILED: November 9, 2016
EFFECTIVE: June 1, 2017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 2 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 5.2
ELECTRIC SERVICE SCHEDULE NO. 5 - Continued
MONTHLY BILL: (continued)
Energy Charge:
3.8143¢ per kWh for all kWh
MINIMUM: Customer Service Charge plus appropriate Power and Energy Charges.
SURCHARGE ADJUSTMENT: All monthly bills shall be adjusted in accordance with
Schedule 80.
POWER: The kW as shown by or computed from the readings of Company's Power meter for
the 60-minute On-Peak period of Customer's greatest use during the month.
TIME PERIODS:
On-Peak:
Off-Peak:
October through April inclusive
8:00 a.m. to 10:00 a.m., and 3:00 p.m. to 8:00 p.m., Monday thru Friday, except
holidays.
May through September inclusive
3:00 p.m. to 8:00 p.m., Monday thru Friday, except holidays.
All other times.
Holidays include only New Year's Day, President's Day, Memorial Day, Independence Day,
Pioneer Day, Labor Day, Thanksgiving Day, and Christmas Day. When a holiday falls on a Saturday
or Sunday, the Friday before the holiday (if the holiday falls on a Saturday) or the Monday following
the holiday (if the holiday falls on a Sunday) will be considered a holiday and consequently Off-Peak.
CONNECTION FEE: Each time a Customer, eligible to receive electric service under this
Schedule, begins to receive electric service at a point of delivery not previously used, or at a point of
delivery which has been used previously by another Customer, or each time a Customer changes his
point of delivery or reconnects after voluntary disconnection to the same point of delivery, that
Customer shall be charged a connection fee of $10.00.
At the discretion of the Company, the connection fee may be waived for account holders such as
landlords and real estate agents who accept, on a temporary basis, responsibility for the accounts of
vacant residential units during the transitional time of vacancy in those cases where the cost to the
Company of the physical discontinuance and restoration of electrical service would exceed the amount
of the connection fee.
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 16-035-__
FILED: November 9, 2016
EFFECTIVE: June 1, 2017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 3 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 5.3
ELECTRIC SERVICE SCHEDULE NO. 5 - Continued
ELECTRIC SERVICE REGULATIONS: Service under this Schedule will be in accordance
with the terms of the Electric Service Agreement between the Customer and the Company. The Electric
Service Regulations of the Company on file with and approved by the Public Service Commission of
the State of Utah, including future applicable amendments, will be considered as forming a part of and
incorporated in said Agreement.
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 16-035-__
FILED: November 9, 2016
EFFECTIVE: June 1, 2017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 4 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 136.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 136
STATE OF UTAH
______________
Net Metering Program
______________
AVAILABILITY: At any point on the Company's interconnected system. Customers will
be subject to any and all changes to the net-metering program tariff.
APPLICATION: On a first-come, first-served basis to any customer that owns or leases a
customer-operated renewable generating facility or, as defined in Utah Code 54-2-1(16)(d), an
eligible customer that purchases electricity from an independent energy producer operating a
renewable generating facility, with a capacity of not more than twenty-five (25) kilowatts for a
residential facility and two (2) megawatts for a non-residential facility that is located on, or adjacent
to, the customers’ premises, is interconnected and operates in parallel with the Company’s existing
distribution facilities, is intended primarily to offset part or all of the customer’s own electrical
requirements, is controlled by an inverter capable of enabling safe and efficient synchronous coupling
with Rocky Mountain Power’s electrical system, and has executed an Interconnection Agreement for
Net Metering Service with the Company. This schedule is offered in compliance with Utah Code
Ann. § 54-15-101 to 106 and R746-312.
DEFINITIONS: Net Metering means measuring the difference between the electricity
supplied by the Company and the electricity generated by an eligible customer-generator and fed
back to the electric grid over the applicable billing period.
An Inverter means a device that converts direct current power into alternating current power
that is compatible with power generated by the Company.
Annualized Billing Period means the period commencing after the regularly scheduled meter
reading for the month of March or in the case of new Schedule 136 service the date that the customer
first takes service from Schedule 136 and ending on the regularly scheduled meter reading for the
month of March.
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 16-035-___
FILED: November 9, 2016
EFFECTIVE: June 1, 2017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 5 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 136.2
ELECTRIC SERVICE SCHEDULE NO. 136 - Continued
DEFINITIONS: (continued)
Residential Customer means any customer whose service is furnished for (1) domestic purposes
in single family dwelling units; (2) apartments where each dwelling unit is separately metered and
billed; and (3) combined family dwelling units. Residential customers do not include dwellings where
tenancy is typically less than 30 days in length, such as hotels, motels, camps, lodges and clubs.
Small Non-Residential Customer means any customer that receives electric service under
Electric Service Schedules 15 or 23.
Large Non-Residential Customer means any customer that receives electric service under
Electric Service Schedules 6, 6A, 6B, 8 or 10.
Renewable Generating Facility means a facility that uses energy derived from one of the
following:
a) solar photovoltaics;
b) solar thermal energy;
c) wind energy;
d) hydrogen;
e) organic waste;
f) hydroelectric energy;
g) waste gas and waste heat capture or recovery;
h) biomass and biomass byproducts, except for the combustion of wood that has been
treated with chemical preservatives such as creosote, pentachlorophenol, chromated
copper arsenate, or municipal waste in a solid form;
i) forest or rangeland woody debris from harvesting or thinning conducted to improve
forest or rangeland ecological health and to reduce wildfire risk;
j) agricultural residues;
k) dedicated energy crops;
l) landfill gas or biogas produced from organic matter, wastewater, anaerobic disgesters,
or municipal solid waste; or
m) geothermal energy.
MONTHLY BILL: The Electric Service Charge shall be computed in accordance with the
Monthly Billing in the applicable standard service tariff. Regardless of whether the Customer provides
excess net generation during the month, the Customer shall be billed the minimum monthly amount
from the applicable standard service tariff.
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 16-035-___
FILED: November 9, 2016
EFFECTIVE: June 1, 2017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 6 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 136.3
ELECTRIC SERVICE SCHEDULE NO. 136 - Continued
SPECIAL CONDITIONS:
1. Applications for service under this schedule will be subject to fees authorized by the Commission.
2. Residential customers participating in the Net Metering Program under this Schedule shall take
service from Schedule 5 – Residential Service for Customer Generators.
3. If the energy supplied to the Company is less than the energy purchased from the Company, the
prices specified in the Energy Charge section of the Monthly Billing of the applicable standard
service tariff shall be applied to the positive balance owed to the Company.
4. If the energy supplied to the Company is greater than the energy supplied by the Company, the
Customer shall be billed for the appropriate monthly charges and shall be credited for such Net
Metering Energy as follows:
A. Residential and Small Non-Residential Customer shall be credited for such net energy with
a cumulative kilowatt-hour credit. The credit will be deducted from the customer’s kilowatthour usage on the customer’s next monthly bill thus offsetting the customer’s next monthly
bill at the full retail rate of the customer’s rate schedule.
B. A Large Non-Residential Customer, at the time of initial enrollment under this tariff , must
elect a compensation method to receive cumulative credits for the upcoming Annualized
Billing Period from one of the following options:
(i)
An Average Energy Price for the applicable calendar year according to the
Volumetric Non-Levelized Prices shown in Schedule 37 as determined by the
following formula: 0.38 x Winter On-Peak Energy Price + 0.19 x Summer OnPeak Energy Price + 0.29 x Winter Off-Peak Energy Price + 0.14 x Summer
Off-Peak Energy Price; or
(ii)
A Seasonally Differentiated Energy Price for the applicable calendar year
according to the Non-Levelized Prices shown in Schedule 37 as determined by
the following formula: 0.57 x Summer On-Peak Energy Price + 0.43 x Summer
Off-Peak Energy Price for the regularly scheduled meter readings from June
through September and 0.57 x Winter On-Peak Energy Price + 0.43 x Winter
Off-Peak Energy Price for the regularly scheduled meter readings from October
through May:
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 16-035-___
FILED: November 9, 2016
EFFECTIVE: June 1, 2017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 7 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
OriginalSheet No. 136.4
P.S.C.U. No. 50
ELECTRIC SERVICE SCHEDULE NO. 136 – Continued
SPECIAL CONDITIONS: (continued)
A Large Non-Residential Customer may change the compensation method once per year at
the beginning of each Annualized Billing Period. The Company must receive written
change notification of any change within sixty (60) days of the beginning of the Annualized
Billing Period.
5. All unused credits accumulated by the customer-generator, except Customers taking service
under Electric Service Schedule No. 10, shall expire with the regularly scheduled meter reading
for the month of March of each year. For Customers taking service under Electric Service
Schedule No. 10, all unused credits accumulated by the customer-generator shall expire with
the regularly scheduled meter reading for the month of October of each year.
6. Upon the customer-generator’s request and within thirty (30) days notice to the Company, the
Company shall aggregate for billing purposes the meter to which the net metering facility is
physically attached (“designated meter”) with one or more meters (“additional meter”) if the
following conditions are met:
(i)
(ii)
the additional meter is located on or adjacent to premises of the customer-generator;
the additional meter is used to measure only electricity used for the customergenerator’s requirements;
(iii) the designated meter and additional meter are subject to the same rate schedule; and
(iv) the designated meter and the additional meter are served by the same primary feeder.
At the time of notice to the Company, the customer-generator must identify the specific meters
and designate a rank order for the additional meters to which net metering credits are to be
applied.
7. The customer-generator shall provide at the customer’s expense all equipment necessary to
meet applicable local and national standards regarding electrical and fire safety, power quality,
and interconnection requirements established by the National Electrical Code, the Institute of
Electrical and Electronics Engineers, and Underwriters Laboratories.
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-035-___
FILED: November 9, 2016
EFFECTIVE: June 1, 2017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 8 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 136.5
ELECTRIC SERVICE SCHEDULE NO. 136 – Continued
8. For customer-generators generation systems of 10 kilowatts or less that are inverter-based, a a
disconnect switch is not required. For all other generation systems, the customer-generator must
install and maintain a manual disconnect switch that will disconnect the generating facility from
the Company’s distribution system. The disconnect switch must be a lockable, load-break
switch that plainly indicates whether it is in the open or closed position. Except as provided in
R746-312-4(2) (a) (ii), the disconnect switch must be readily accessible to the Company at all
times and located within ten (10) feet of the Company’s meter.
9. The Company shall not be liable directly or indirectly for permitting or continuing to allow an
attachment of a net metering facility, or for the acts or omissions of the customer-generator that
cause loss or injury, including death, to any third party.
10. The Company may test and inspect an interconnection at times that the electrical corporation
considers necessary to ensure the safety of electrical workers and to preserve the integrity of
the electric power grid.
11. Unless otherwise agreed to by a separate contract, the owner of the renewable energy facility
retains ownership of the non-energy attributes associated with electricity the facility generates.
ELECTRIC SERVICE REGULATIONS: Service under this Schedule will be in accordance
with the terms of the Electric Service Agreement between the Customer and the Company. The Electric
Service Regulations of the Company on file with and approved by the Public Service Commission of
the State of Utah, including future applicable amendments, will be considered as forming a part of and
incorporated in said Agreement.
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 16-035-___
FILED: November 9, 2016
EFFECTIVE: June 1, 2017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 9 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 1365.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 1365
STATE OF UTAH
______________
Net Metering ProgramService
______________
AVAILABILITY: At any point on the Company's interconnected system. Customers will
be subject to any and all changes to the net-metering program tariff.
APPLICATION: On a first-come, first-served basis to any customer that owns or leases a
customer-operated renewable generating facility or, as defined in Utah Code 54-2-1(16)(d), an
eligible customer that purchases electricity from an independent energy producer operating a
renewable generating facility, with a capacity of not more than twenty-five (25) kilowatts for a
residential facility and two (2) megawatts for a non-residential facility that is located on, or adjacent
to, the customers’ premises, is interconnected and operates in parallel with the Company’s existing
distribution facilities, is intended primarily to offset part or all of the customer’s own electrical
requirements, is controlled by an inverter capable of enabling safe and efficient synchronous coupling
with Rocky Mountain Power’s electrical system, and has executed an Interconnection Agreement for
Net Metering Service with the Company. This schedule is offered in compliance with Utah Code
Ann. § 54-15-101 to 106 and R746-312.
DEFINITIONS: Net Metering means measuring the difference between the electricity
supplied by the Company and the electricity generated by an eligible customer-generator and fed
back to the electric grid over the applicable billing period.
An Inverter means a device that converts direct current power into alternating current power
that is compatible with power generated by the Company.
Annualized Billing Period means the period commencing after the regularly scheduled meter
reading for the month of March or in the case of new Schedule 1365 service the date that the customer
first takes service from Schedule 1365 and ending on the regularly scheduled meter reading for the
month of March.
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 163-035184___
FILED: September 5November 9, 20142016
EFFECTIVE: September 1June 1, 20142017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 10 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 43
Original Sheet No. 135.2
ELECTRIC SERVICE SCHEDULE NO. 95 - Continued
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 163-035184___
FILED: September 5November 9,
20142016
EFFECTIVE: September 1June 1, 20142017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 11 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 1365.2
ELECTRIC SERVICE SCHEDULE NO. 1365 - Continued
DEFINITIONS: (continued)
Residential Customer means any customer that receives electric service under Electric Service
Schedules 1, 2 or 3whose service is furnished for (1) domestic purposes in single family dwelling units;
(2) apartments where each dwelling unit is separately metered and billed; and (3) combined family
dwelling units. Residential customers do not include dwellings where tenancy is typically less than 30
days in length, such as hotels, motels, camps, lodges and clubs.
Small Non-Residential Customer means any customer that receives electric service under
Electric Service Schedules 15 or 23.
Large Non-Residential Customer means any customer that receives electric service under
Electric Service Schedules 6, 6A, 6B, 8 or 10.
Renewable Generating Facility means a facility that uses energy derived from one of the
following:
a) solar photovoltaics;
b) solar thermal energy;
c) wind energy;
d) hydrogen;
e) organic waste;
f) hydroelectric energy;
g) waste gas and waste heat capture or recovery;
h) biomass and biomass byproducts, except for the combustion of wood that has been
treated with chemical preservatives such as creosote, pentachlorophenol, chromated
copper arsenate, or municipal waste in a solid form;
i) forest or rangeland woody debris from harvesting or thinning conducted to improve
forest or rangeland ecological health and to reduce wildfire risk;
j) agricultural residues;
k) dedicated energy crops;
l) landfill gas or biogas produced from organic matter, wastewater, anaerobic disgesters,
or municipal solid waste; or
m) geothermal energy.
MONTHLY BILL: The Electric Service Charge shall be computed in accordance with the
Monthly Billing in the applicable standard service tariff. Regardless of whether the Customer provides
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 163-035184___
FILED: September 5November 9,
20142016
20142017
EFFECTIVE: September 1June 1,
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 12 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 1365.2
ELECTRIC SERVICE SCHEDULE NO. 1365 - Continued
excess net generation during the month, the Customer shall be billed the minimum monthly amount
from the applicable standard service tariff.
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 163-035184___
FILED: September 5November 9,
20142016
20142017
EFFECTIVE: September 1June 1,
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 13 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 1365.3
ELECTRIC SERVICE SCHEDULE NO. 1365 - Continued
SPECIAL CONDITIONS:
1. Applications for service under this schedule will be subject to fees authorized by the Commission.
2. Residential customers participating in the Net Metering Program under this Schedule shall take
service from Schedule 5 – Residential Service for Customer Generators.
1.3.If the energy supplied to the Company is less than the energy purchased from the Company, the
prices specified in the Energy Charge section of the Monthly Billing of the applicable standard
service tariff shall be applied to the positive balance owed to the Company.
2.4.If the energy supplied to the Company is greater than the energy supplied by the Company, the
Customer shall be billed for the appropriate monthly charges and shall be credited for such Net
Metering Energy as follows:
A. Residential and Small Non-Residential Customer shall be credited for such net energy with
a cumulative kilowatt-hour credit. The credit will be deducted from the customer’s kilowatthour usage on the customer’s next monthly bill thus offsetting the customer’s next monthly
bill at the full retail rate of the customer’s rate schedule.
B. A Large Non-Residential Customer, at the time of initial enrollment under this tariff , must
elect a compensation method to receive cumulative credits for the upcoming Annualized
Billing Period from one of the following options:
(i)
An Average Energy Price for the applicable calendar year according to the
Volumetric Non-Levelized Prices shown in Schedule 37 as determined by the
following formula: 0.38 x Winter On-Peak Energy Price + 0.19 x Summer OnPeak Energy Price + 0.29 x Winter Off-Peak Energy Price + 0.14 x Summer
Off-Peak Energy Price; or
(ii)
A Seasonally Differentiated Energy Price for the applicable calendar year
according to the Non-Levelized Prices shown in Schedule 37 as determined by
the following formula: 0.57 x Summer On-Peak Energy Price + 0.43 x Summer
Off-Peak Energy Price for the regularly scheduled meter readings from June
through September and 0.57 x Winter On-Peak Energy Price + 0.43 x Winter
Off-Peak Energy Price for the regularly scheduled meter readings from October
through May:; or
(iii)
An average retail rate for the Electric Service Schedule applicable to the net
metering customer as calculated from the previous year’s Federal Energy
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 1316-035184___
FILED: September 5November 9, 20142016
EFFECTIVE: September 1June 1, 20142017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 14 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 1365.3
ELECTRIC SERVICE SCHEDULE NO. 1365 - Continued
Regulation Commission Form No. 1 to be determined and available by July 1,
2009, and by July 1st of every subsequent year. Current average retail rates are
listed below:
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 1316-035184___
FILED: September 5November 9, 20142016
EFFECTIVE: September 1June 1, 20142017
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 15 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
Second RevisionOriginal of Sheet No. 1365.4
Canceling First Revision of Sheet No. 135.4
P.S.C.U. No. 50
ELECTRIC SERVICE SCHEDULE NO. 1356 -– Continued
SPECIAL CONDITIONS: (continued)
Schedule 6:
Schedule 6A:
Schedule 6B:
Schedule 8:
Schedule 10:
8. 4498¢ per kWh
11.7871¢ per kWh
10.8914¢ per kWh
7.5210¢ per kWh
7.5619¢ per kWh
A Large Non-Residential Customer may change the compensation method once per year at
the beginning of each Annualized Billing Period. The Company must receive written
change notification of any change within sixty (60) days of the beginning of the Annualized
Billing Period.
5. All unused credits accumulated by the customer-generator, except Customers taking service
under Electric Service Schedule No. 10, shall expire with the regularly scheduled meter reading
for the month of March of each year. For Customers taking service under Electric Service
Schedule No. 10, all unused credits accumulated by the customer-generator shall expire with
the regularly scheduled meter reading for the month of October of each year.
6. Upon the customer-generator’s request and within thirty (30) days notice to the Company, the
Company shall aggregate for billing purposes the meter to which the net metering facility is
physically attached (“designated meter”) with one or more meters (“additional meter”) if the
following conditions are met:
(i)
(ii)
the additional meter is located on or adjacent to premises of the customer-generator;
the additional meter is used to measure only electricity used for the customergenerator’s requirements;
(iii) the designated meter and additional meter are subject to the same rate schedule; and
(iv) the designated meter and the additional meter are served by the same primary feeder.
At the time of notice to the Company, the customer-generator must identify the specific meters
and designate a rank order for the additional meters to which net metering credits are to be
applied.
7. The customer-generator shall provide at the customer’s expense all equipment necessary to
meet applicable local and national standards regarding electrical and fire safety, power quality,
and interconnection requirements established by the National Electrical Code, the Institute of
Electrical and Electronics Engineers, and Underwriters Laboratories.
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-06035___
FILED: May 27November 9, 2016
EFFECTIVE: July 1June 1, 20176
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 16 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
Second RevisionOriginal of Sheet No. 1365.4
Canceling First Revision of Sheet No. 135.4
P.S.C.U. No. 50
ELECTRIC SERVICE SCHEDULE NO. 1356 -– Continued
(cContinued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-06035___
FILED: May 27November 9, 2016
EFFECTIVE: July 1June 1, 20176
Rocky Mountain Power
Exhibit RMP___(JRS-1) Page 17 of 17
Docket No. 16-035-__
Witness: Joelle R. Steward
P.S.C.U. No. 50
Original Sheet No. 1365.5
ELECTRIC SERVICE SCHEDULE NO. 1365 -– Continued
8. For customer-generators generation systems of 10 kilowatts or less that are inverter-based, a a
disconnect switch is not required. For all other generation systems, the customer-generator
must install and maintain a manual disconnect switch that will disconnect the generating
facility from the Company’s distribution system. The disconnect switch must be a lockable,
load-break switch that plainly indicates whether it is in the open or closed position. Except as
provided in R746-312-4(2) (a) (ii), the disconnect switch must be readily accessible to the
Company at all times and located within ten (10) feet of the Company’s meter.
9. The Company shall not be liable directly or indirectly for permitting or continuing to allow an
attachment of a net metering facility, or for the acts or omissions of the customer-generator
that cause loss or injury, including death, to any third party.
10. The Company may test and inspect an interconnection at times that the electrical corporation
considers necessary to ensure the safety of electrical workers and to preserve the integrity of
the electric power grid.
11. Unless otherwise agreed to by a separate contract, the owner of the renewable energy facility
retains ownership of the non-energy attributes associated with electricity the facility
generates.
ELECTRIC SERVICE REGULATIONS: Service under this Schedule will be in
accordance with the terms of the Electric Service Agreement between the Customer and the
Company. The Electric Service Regulations of the Company on file with and approved by the Public
Service Commission of the State of Utah, including future applicable amendments, will be considered
as forming a part of and incorporated in said Agreement.
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 163-035184___
FILED: September 5November 9, 20142016
EFFECTIVE: September 1June 1, 20142017
Rocky Mountain Power
Exhibit RMP___(JRS-2)
Docket No. 16-035-__
Witness: Joelle R. Steward
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Joelle R. Steward
Revised Interconnection Agreements (clean and redlined)
November 2016
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 1 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
We appreciate your interest in Rocky Mountain Power’s net metering program. Before
purchasing any net metering equipment, we recommend you review the requirements for
interconnecting a net metering system to Rocky Mountain Power’s electrical distribution
system. The requirements are found in the Interconnection Agreement.
To complete the process for a net metering interconnection, please follow the steps below:
1. Complete and submit the following to Rocky Mountain Power:
 Interconnection Agreement including the Application for Net Metering
Interconnection
 The inverter specification sheet
 For systems larger than 10 kW, a simple one-line diagram showing
 The location of Rocky Mountain Power’s meter
 The location of the disconnect switch
2. Rocky Mountain Power will review your agreement and application and send you a
written notification of approval either by mail or e-mail
3. Install the net metering system after you receive the written approval of your
Interconnection Agreement and Application for Net Metering from Rocky Mountain
Power
4. Obtain an inspection of your net metering system by the local city or county electrical
inspector
5. Submit the electrical inspector’s approval to Rocky Mountain Power
6. Turn on your net metering system after Rocky Mountain Power provides you written
notification the interconnection work has been completed and the net meter installed
Return completed documents to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, Utah 84125-0308
Or Email to:
[email protected]
Thank you for your interest in the net metering program. If you have questions, please call us
toll free at 1-888-221-7070 and ask for a net metering specialist.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 1 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 2 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Service ID#:___________
Request #: ___________
INTERCONNECTION AND NET METERING SERVICE AGREEMENT FOR NET
METERING FACILITY LEVEL 1 INTERCONNECTION
25 KW NAMEPLATE CAPACITY OR SMALLER
This Interconnection and Net Metering Service Agreement (“Agreement”) is made and
entered into this ___ day of _____________, 20___ by and between
____________________________, an electric customer (“Customer”), and PacifiCorp, dba
Rocky Mountain Power (“Rocky Mountain Power”), a Corporation organized and existing
under the laws of the State of Oregon. Customer and Rocky Mountain Power each may be
referred to as a “Party”, or collectively as the “Parties”.
Recitals:
Whereas, Customer has installed or intends to install a Net Metering Facility qualifying
for “Net Metering,” Utah Rate Schedule No. 135A (“Schedule 135A”), as given in Rocky
Mountain Power’s currently effective tariff as filed with the Public Service Commission of
Utah (“Commission”), on or adjacent to Customer’s premises located at
____________________________, Utah, for the purpose of generating electric energy;
Whereas, the Net Metering rate schedule may be amended from time to time, and the
Public Service Commission may alter the charge, credit, and ratemaking structure applicable to
Net Metering customers pursuant to Utah Code § 54-15-105.1;
Whereas, Customer represents to Rocky Mountain Power that Customer either owns or
leases its Net Metering Facility qualifying for Schedule 135A, or meets the exemption
requirements set forth in Utah Code § 54-2-1.16(d) because it is a county, municipality, city,
town, other political subdivision, local district, special service district, state institution of higher
education, school district, charter school, or any entity within the state system of public
education; or an entity qualifying as a charitable organization under 26 U.S.C. Sec. 501(c)(3)
operated for religious, charitable, or educational purposes that is exempt from federal income
tax and able to demonstrate its tax-exempt status;
Whereas, Customer desires to interconnect the Net Metering Facility with Rocky
Mountain Power’s distribution system consistent with the Application completed by on
_____________ ____, 20___,Customer as described in Appendix A (“Application”) of this
Agreement; and
Whereas, Customer, using its Net Metering Facility, intends to offset part or all of its
electrical requirements supplied by Rocky Mountain Power.
Now, therefore, in consideration of and subject to the mutual covenants contained
herein, the Parties agree as follows:
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 2 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 3 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 1.
Scope and Limitations of Agreement
1.1
Scope
The Agreement shall be used for all approved Level 1 Applications according to the
procedures set forth in Utah Rule 746-312 (“Rule”), as may be amended from time to
time. The Rule can be viewed at www.psc.utah.gov. The Agreement establishes
standard terms and conditions approved by the Commission under which a Level 1 Net
Metering Facility as described in Appendix A with an electric nameplate capacity of 25
kW or smaller will interconnect to, and operate in parallel with, Rocky Mountain
Power’s system.
1.2
Definitions
Terms with initial capitalization, when used in this Agreement, shall have the meanings
indicated or as specified in the Rule Section R746-312-2 and, to the extent this
Agreement conflicts with the Rule, the Rule shall take precedence.
1.3
Other Agreements
Nothing in this Agreement is intended to affect any other agreement between Rocky
Mountain Power and Customer or any other Interconnection Customer. However, in the
event that the provisions of the Agreement are in conflict with the provisions of any
Rocky Mountain Power Tariff, the Rocky Mountain Power Tariff shall control.
1.4
Responsibilities of the Parties
1.4.1
The Parties shall perform all obligations of the Agreement in accordance with all
applicable laws and regulations.
1.4.2
Customer will construct, operate, test, and maintain its Net Metering Facility in
accordance with the Agreement, IEEE standards (available at the following link:
http://standards.ieee.org/index.html), National Electric Code Standards
(available for purchase at http://standards.ieee.org/faqs/NESCFAQ.html#q8),
Utah state building codes (available at the following link:
http://www.dopl.utah.gov/programs/ubc/), the Rule, and other applicable
standards required by the Commission, as may be amended from time to time.
1.4.3
Each Party shall be responsible for the safe installation, maintenance, repair and
condition of their respective lines and equipment on their respective sides of the
Point of Common Coupling. Each Party shall provide interconnection facilities
that adequately protect the other Party’s facilities, personnel and other persons
from damage and injury. The allocation of responsibility for the design,
installation, operation and maintenance of interconnection facilities is prescribed
in the Rule, including but not necessarily limited to R746-312-4.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 3 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 4 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.4.4
1.5
Customer is responsible for protecting the generating equipment, inverters,
protective devices, and other system components from damage from the normal
and abnormal conditions and operations that occur on Rocky Mountain Power’s
system in delivering and restoring power; and is responsible for ensuring that the
Net Metering Facility equipment is inspected, maintained, and tested in
accordance with the manufacturer’s instructions to ensure that it is operating
correctly and safely.
Parallel Operation and Maintenance Obligations
Once the Net Metering Facility has been authorized to commence parallel operation by
an approved application and execution of this Agreement, Customer will abide by all
written provisions for operations and maintenance as required by the Rule and Rocky
Mountain Power’s tariffs, including but not necessarily limited to R746-312-4 and
Schedule 135A or its successor tariff(s).
1.6
Metering
Rocky Mountain Power shall install, own and maintain, at its sole expense, a kilowatthour meter(s) and associated equipment to measure the flow of energy in each direction,
unless otherwise authorized by the Commission. Customer hereby consents to the
installation of and operation by Rocky Mountain Power, at Rocky Mountain Power’s
expense, one or more additional meters to monitor the flow of electricity in each
direction. Such meter(s) shall be located on the premises of Customer.
1.7
1.8
Net Metering Facility Requirements, Installation, Operation
1.7.1
Customer’s Net Metering Facility must meet the requirements set forth in,
including but not necessarily limited to, the Rule, R746-312-4 and Schedule
135A or its successor tariff(s). This also applies to installation and operation of
the Net Metering Facility.
1.7.2
Customer is responsible for all costs associated with its Net Metering Facility.
Anticipated Start Date
Customer must include an anticipated start date for operation of its Net Metering
Facility in the Application. After receiving notice that the Application has been
approved, Customer must execute and return this Agreement with a copy of the
approved electric inspection to Rocky Mountain Power. Upon satisfactory completion
of all reviews and inspections of the Net Metering Facility, Customer must notify
Rocky Mountain Power at least ten (10) business days prior to starting operation of the
Net Metering Facility, either through submission of an executed Agreement or through
separate written notice. Customer shall not commence parallel operation of the Net
Metering Facility until Rocky Mountain Power executes this Agreement, installs the net
meter and notifies Customer that the Net Metering Facility is interconnected.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 4 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 5 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.9
Net Metering Facility Inspection
1.9.1
Building Code Inspection
Prior to operation in parallel with Rocky Mountain Power’s system, the Net
Metering Facility must be inspected by a local building code official to ensure
compliance with applicable local codes.
1.9.2
Inspection by Rocky Mountain Power
Rocky Mountain Power may inspect the Net Metering Facility and its
component equipment, and the documents necessary to ensure compliance with
the Rule. Customer shall notify Rocky Mountain Power prior to placing the Net
Metering Facility in service, and Rocky Mountain Power shall have the right to
have personnel present on the in-service date. If the Net Metering Facility is
subsequently modified in order to increase its gross power rating, Customer
must notify Rocky Mountain Power by submitting a new application specifying
the modifications in accordance with the level of review required for that
application.
1.10
Power Quality
Customer will design its Net Metering Facility to maintain a composite power delivery
at continuous rated power output at the Point of Common Coupling that meets the
requirements set forth in IEEE 1547, in accordance with the Rule, R746-312-4.
1.11
Net Metering Facility Testing and Maintenance
Customer shall conduct maintenance and testing on its Net Metering Facilities as set
forth in the Rule, including but not necessarily limited to R746-312-14.
1.11.1 Customer shall conduct any manufacturer-recommended testing or maintenance
at its expense.
1.11.2 Customer shall conduct any post-installation testing, at its expense, necessary to
ensure compliance with IEEE standards as set forth in the Rule or to ensure
safety. This includes replacing a major equipment component that is different
from the originally installed model.
1.11.3 When Customer performs maintenance or testing in accordance with the Rule, it
must retain written records documenting the maintenance and results of the
testing for three (3) years.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 5 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 6 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.11.4 Rocky Mountain Power shall have the right to inspect Customer’s facility after
interconnection approval is granted, at reasonable hours and with reasonable prior
notice to Customer. If Rocky Mountain Power discovers that the Net Metering Facility
is not in compliance with the Rule, Rocky Mountain Power may require Customer to
disconnect the Net Metering Facility until compliance is achieved.
1.12
Removal of Facility
Customer shall immediately notify Rocky Mountain Power if Customer removes or
ceases to operate the Net Metering Facility.
Article 2.
2.1
Review, Inspection, Testing, Disconnect Switch and Signage, and Right of
Access
Review
After determining Customer’s interconnection request is complete, in accordance with
the Rule, R746-312-8, Rocky Mountain Power will conduct a review of the proposed
interconnection using screens set forth in the Rule, R746-312-7. Rocky Mountain
Power will conduct such review within fifteen (15) days after notifying Customer that
the interconnection request is complete and will notify Customer either that the Net
Metering Facility meets all applicable criteria and the interconnection request is
approved, or the Net Metering Facility has failed to meet one or more of the applicable
criteria, the reason for failure, and the interconnection request is denied under Level 1
review. If the interconnection request is denied, Customer may resubmit the application
under the Level 2 or Level 3 review process.
2.2
Equipment Testing and Inspection
Customer must notify Rocky Mountain Power of the anticipated testing and inspection
date of the Net Metering Facility at least ten (10) business days prior to testing, either
through submittal of the Agreement, a notice of completion, or in a separate notice.
Within ten (10) business days after receipt of such required documentation, Rocky
Mountain Power will inspect the Net Metering Facility, set the new meter if required,
approve the interconnection and may arrange a witness test as set forth in the Rule,
R746-312-8(4). Rocky Mountain Power and Customer will select a date by mutual
agreement for the witness test.
Rocky Mountain Power will test and inspect the Net Metering Facility and
Interconnection Facilities prior to interconnection in accordance with IEEE Standards as
provided for in the Rule, R746-312-4. Customer shall not begin operation of its Net
Metering Facility until after inspection and testing is completed.
If a witness test is conducted and is not satisfactory, Customer must resolve any
deficiencies within thirty (30) business days or other time period as mutually agreed by
the Parties.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 6 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 7 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
2.3
Disconnect Switch and Signage
Customer shall comply with the Rule regarding disconnect switches, R746-312-4. The
disconnect switch may be located more than 10 feet from the public utility meter if
permanent instructions in letters of appropriate size are posted at the meter indicating
the precise location of the disconnect switch. Rocky Mountain Power must approve in
writing the location of the disconnect switch prior to the installation of the Net Metering
Facility.
2.4
Right of Access
As provided in the Rule, R746-312-4, Rocky Mountain Power shall have access to any
required disconnect switch at the Net Metering Facility at all times. Rocky Mountain
Power will provide reasonable notice to Customer when possible prior to using the right
of access. Additionally, as provided in Rocky Mountain Power Utah Rule 6, or its
successor tariff, Rocky Mountain Power shall have access to the metering equipment.
Article 3.
3.1
Effective Date, Term, Termination and Disconnection
Effective Date
The Agreement shall become effective upon execution by the Parties.
3.2
Term of Agreement
The Agreement will become effective on the Effective Date and will remain in effect
unless terminated in accordance with provisions of this Agreement, or Order by the
Commission.
3.3
Termination
No termination will become effective until the Parties have complied with all applicable
laws and clauses of this Agreement applicable to such termination.
3.3.1
Customer may terminate this Agreement at any time by giving Rocky Mountain
Power twenty (20) business days written notice.
3.3.2
Either Party may terminate this Agreement after default pursuant to Article 6.4
of this Agreement.
3.3.3
The Commission may Order termination of this Agreement.
3.3.4
Upon termination of this Agreement, Customer shall disconnect the Net
Metering Facility from Rocky Mountain Power’s system. The termination of
this Agreement will not relieve either Party of its liabilities and obligations,
owed or continuing at the time of termination.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 7 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 8 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
3.4
3.3.5
If Customer removes the Net Metering equipment at the Net Metering Facility
or ceases to operate its Net Metering Facility at the premises listed in Recital 1
above, this Agreement will be immediately terminated.
3.3.6
The provisions of this Article shall survive termination or expiration of this
Agreement.
Temporary Disconnection
3.4.1
Rocky Mountain Power may temporarily disconnect the Net Metering Facility
from Rocky Mountain Power’s system for so long as reasonably necessary in the
event one or more of the following conditions or events occurs:
3.4.1.1 Emergencies or to address maintenance requirements for Rocky Mountain
Power’s system.
3.4.1.2 Hazardous conditions existing on Rocky Mountain Power’s system which
may affect the safety of the general public or Rocky Mountain Power
employees due to the operation of the Net Metering Facility or protective
equipment as determined by Rocky Mountain Power.
3.4.1.3 Adverse electrical effects on the electrical equipment of Rocky Mountain
Power’s other electric customers caused by the Net Metering Facility as
determined by Rocky Mountain Power.
3.4.2
In the event that no disconnect switch is installed, Rocky Mountain Power may
physically disconnect all service to the Customer and/or all service to the
premises where the Net Metering Facility is located.
3.4.3
To the extent practicable, Rocky Mountain Power will give prior notice of any
temporary disconnection of the Net Metering Facility. If Rocky Mountain Power
is unable to give prior notice, Rocky Mountain Power will provide notice
including an explanation of the condition necessitating the disconnection at the
time of disconnection
3.4.4
Under emergency conditions, Rocky Mountain Power or Customer may
immediately suspend interconnection service and temporarily disconnect the Net
Metering Facility. Rocky Mountain Power shall notify Customer promptly when
Rocky Mountain Power becomes aware of an emergency condition that may
reasonably be expected to affect the Net Metering Facility operation. Customer
shall notify Rocky Mountain Power promptly when Customer becomes aware of
an emergency condition that may reasonably be expected to affect Rocky
Mountain Power’s system. To the extent the information is known, the
notification shall describe the emergency condition, the extent of any damage or
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 8 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 9 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
deficiency, the expected effect on the operation of both Parties’ facilities and
operations, the anticipated duration, and the necessary corrective action.
3.4.5
Customer shall make reasonable efforts to provide notice of interruption of Net
Metering Facility operation for safety and/or reliability reasons prior to the
interruption unless an emergency occurs. Emergency interruptions or temporary
terminations are subject to Section 3.4.4 above.
3.4.6
Rocky Mountain Power shall use reasonable efforts to provide Customer with
prior notice of forced outages to effect immediate repairs to Rocky Mountain
Power’s system. If prior notice is not given, Rocky Mountain Power, shall, upon
request, provide Customer written documentation after the fact explaining the
circumstances of the disconnection.
3.4.7
Customer must provide Rocky Mountain Power notice and obtain Rocky
Mountain Power’s written approval before Customer may modify its Net
Metering Facility in order to increase the electric output of the Net Metering
Facility. If Customer makes any material change without prior written
authorization of Rocky Mountain Power, Rocky Mountain Power will have the
right to temporarily disconnect the Net Metering Facility until Rocky Mountain
Power has had an opportunity to review the change(s) made to determine
whether they are acceptable. If system modifications or other equipment
installations are deemed necessary by Rocky Mountain Power to accommodate
the modified Net Metering Facility, Customer shall submit the appropriate net
metering application at that time.
3.4.8
The Parties shall cooperate with each other to restore the Net Metering Facility,
interconnection facilities, and Rocky Mountain Power’s system to their normal
operating state as soon as reasonably practicable following any disconnection
pursuant to Section 3.4.
Article 4.
Cost Responsibility
4.1
Customer shall bear the cost of any Application fee set forth by Rule, or as
otherwise approved by the Commission.
4.2
Customer shall bear the cost of any facilities, equipment, modifications and
upgrades as required by the Rule. Customer shall also be responsible for all
reasonable expenses, including overheads, associated with owning, operating,
maintaining, repairing, and replacing its Net Metering Facility.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 9 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 10 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 5.
5.1
Billing
Monthly Billing
The electric service charge shall be computed in accordance with the monthly billing in
the currently applicable service tariff. Customer will be compensated for net excess
energy in accordance with Schedule 135A or its successor tariff(s). Customer will be
transitioned to any successor tariff immediately upon approval of that tariff by the
Public Service Commission and will be subject to any charge, credit, or ratemaking
structure implemented therein.
5.2
Special Conditions
Customer must comply with the special conditions found in Schedule 135A or its
successor tariff(s).
5.3
Aggregating Meters
Aggregating Meters is allowed if certain conditions are met under the Rule, R746-3125.
Customer
designates
the
following
meters
for
aggregation:
_______________________. In the event that the Net Metering Facility supplies more
electricity to Rocky Mountain Power than the Customer uses from Rocky Mountain
Power, Rocky Mountain Power will apply any credits to the next monthly bill in
accordance with Utah Code § 54-15-104 and the Rule, R746-312-15. Customer shall
designate the order in which to apply any credits in accordance with the Rule. <<If
customer does not want to aggregate, insert “N\A” in the space above.>>
Article 6.
6.1
Assignment, Liability, Indemnity, Consequential Damages and Default
Assignment
This Agreement may be assigned by either Party with the consent of the other Party. A
Party’s consent to an assignment may not be unreasonably withheld. The assigning
Party must give the non-assigning Party written notice of the assignment at least fifteen
days (15) before the effective date of the assignment. The non-assigning Party must
submit its objection to the assignment, if any, to the assigning Party in writing at least 5
business days before the effective date of the assignment. If a written objection is not
received within that time period, the non-assigning party is deemed to consent to the
assignment.
6.1.1
Exceptions to Consent Requirement
6.1.1.1 Either Party may assign the Agreement without the consent of the other
Party to any affiliate (including a merger or acquisition of the Party with
another entity) of the assigning Party with an equal or greater credit
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 10 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 11 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
rating and with the legal authority and operational ability to satisfy the
obligations of the assigning Party under this Agreement.
6.1.1.2 Customer is entitled to assign the Agreement without the consent of
Rocky Mountain Power for collateral security purposes to aid in
obtaining financing for the Net Metering Facility.
6.1.1.3 For small generator systems that are integrated into a building facility,
the sale of the building or property will result in the automatic
assignment of this Agreement to the new owner who will be responsible
for complying with the terms and conditions of this Agreement.
6.1.2
6.2
Any attempted assignment that violates this Article is void and ineffective.
Assignment does not change or eliminate a Party’s obligations under this
Agreement. An assignee is responsible for meeting the same obligations as the
assigning Party.
Limitation of Liability and Consequential Damages
Each Party’s liability to the other Party for any loss, cost, claim, injury, liability, or
expense, including reasonable attorney’s fees, relating to or arising from any act or
omission in its performance of this Agreement, is limited to the amount of direct
damage actually incurred. Neither Party is liable to the other Party for any indirect,
special, consequential, or punitive damages.
6.3
Indemnification
Customer shall hold harmless and indemnify Rocky Mountain Power for all loss to third
parties resulting from the operation of the Net Metering Facility, except when the loss
occurs due to the negligent actions of Rocky Mountain Power.
Rocky Mountain Power shall hold harmless and indemnify Customer for all loss to third
parties resulting from the operation of Rocky Mountain Power’s system, except where
the loss occurs due to the negligent actions of Customer.
6.4
Force Majeure
6.4.1
As used in this Agreement, a Force Majeure Event shall mean “any act of God,
labor disturbance, act of the public enemy, war, acts of terrorism, insurrection,
riot, fire, storm or flood, explosion, breakage or accident to machinery or
equipment through no direct, indirect, or contributory act of a Party, any order,
regulation, or restriction imposed by governmental, military or lawfully
established civilian authorities, or any other cause beyond a Party’s control. A
Force Majeure Event does not include an act of negligence or wrongdoing.”
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 11 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 12 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
6.4.2
6.5
If a Force Majeure Event prevents a Party from fulfilling any obligations under
this Agreement, the Party affected by the Force Majeure Event (“Affected
Party”) shall promptly notify the other Party of the existence of the Force
Majeure Event. The notification must specify in reasonable detail the
circumstances of the Force Majeure Event, its expected duration, and the steps
that the Affected Party is taking to mitigate the effects of the event on its
performance, and if the initial notification was verbal, it should be promptly
followed up with a written notification. The Affected Party shall keep the other
Party informed on a continuing basis of developments relating to the Force
Majeure Event until the event ends. The Affected Party will be entitled to
suspend or modify its performance of obligations under this Agreement (other
than the obligation to make payments) only to the extent that the effect of the
Force Majeure Event cannot be reasonably mitigated. The Affected Party will
use reasonable efforts to resume its performance as soon as possible. The Parties
shall immediately report to the Commission should a Force Majeure Event
prevent performance of an action required by Rule that the Rule does not permit
the Parties to mutually waive.
Default
6.5.1
A Party is in default if the Party fails to perform an obligation required under
this Agreement (other than the payment of money). A Party is not considered in
default of this agreement if the failure to perform an obligation is caused by an
act or omission of the other Party.
6.5.2
Upon a default, the non-defaulting Party must give written notice of the default
to the defaulting party. The defaulting party has sixty (60) calendar days from
the receipt of the written default notice to cure the default. If the default is not
capable of cure within the 60-day period, the defaulting Party must begin to cure
the default within twenty (20) calendar days after receipt of the written default
notice, and must continuously and diligently complete the cure within six (6)
months of the receipt of the notice.
6.5.3
If a default is not cured as provided in 6.5.2, then the non-defaulting Party is
entitled to terminate the Agreement by written notice at any time until cure
occurs. If the non-defaulting Party chooses to terminate this Agreement, the
termination provisions in Article 3.3 apply. Alternately, the non-defaulting Party
is entitled to seek dispute resolution with the Commission in lieu of termination.
Article 7.
Insurance
Additional liability insurance is not required as a part of the Agreement if the Net Metering
Facility is in compliance with the provisions of the Application approval, the Agreement and
the standards contained in Utah Code § 54-15-106.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 12 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 13 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 8.
Dispute Resolution
Nothing in this Article shall restrict the rights of any Party to file a Complaint with the
Commission under relevant provisions of the Rule, R746-312-3(5) and applicable state law.
Article 9.
9.1
Miscellaneous
Governing Law, Regulatory Authority, and Rules
The validity, interpretation, and enforcement of this Agreement is governed by the laws
of the State of Utah. If any provision of this Agreement conflicts with any applicable
provision, as may be amended from time to time, of the Utah Code (“Code”), Utah
Administrative Rules (“Rules”), or Rocky Mountain Power’s Tariffs (“Tariff”), then the
applicable provision of the Code, Rules, or Tariff controls. Rocky Mountain Power
must provide copies of the applicable provisions of the Code, Rules, and Tariff upon the
Customer’s request.
9.2
Amendment
Additions, deletions or changes to the standard terms and conditions of this Agreement
will not be permitted unless they are mutually agreed to by the Parties and permitted by
the Rule or permitted by the Commission for good cause shown. The Parties may
amend the Agreement by a written instrument duly executed by both Parties in
accordance with the provisions of the Rule, applicable Commission Orders and
provisions of the laws of the State of Utah.
9.3
No Third Party Beneficiaries
The Agreement is not intended to and does not create rights, remedies, or benefits of
any character whatsoever in favor of any persons, corporations, associations, or entities
other than the Parties, and the obligations herein assumed are solely for the use and
benefit of the Parties, or where permitted, their successors in interest and their assigns.
9.4
Waiver
9.4.1
The failure of a Party to the Agreement to insist, on any occasion, upon strict
performance of any provision of the Agreement, will not be considered a waiver
of any obligation, right, or duty of, or imposed upon, such Party.
9.4.2
The Parties may also agree to mutually waive a Section of this Agreement
without the Commission’s approval where the Rule so provides.
9.4.3
Any waiver at any time by either Party of its rights with respect to the
Agreement shall not be deemed a continuing waiver or a waiver with respect to
any other failure to comply with any other obligation, right, duty of the
Agreement. Termination or default of this Agreement for any reason by
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 13 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 14 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Customer shall not constitute a waiver of the Customer’s legal rights to obtain
interconnection from Rocky Mountain Power. Any request for waiver of the
Agreement or any provisions thereof shall be provided in writing.
9.5
Entire Agreement
The Agreement, including any supplementary attachments that may be necessary,
constitutes the entire Agreement between the Parties with reference to the subject matter
hereof, and supersedes all prior and contemporaneous understandings or agreements,
oral or written, between the Parties with respect to the subject matter of the Agreement.
There are no other agreements, representations, warranties, or covenants that constitute
any part of the consideration for, or any condition to, either Party’s compliance with its
obligations under the Agreement.
9.6
Multiple Counterparts
This Agreement may be executed in one or more counterparts, whether electronically or
otherwise, each of which is deemed an original but all constitute one and the same
instrument.
9.7
No Partnership
The Agreement will not be interpreted or construed to create an association, joint
venture, agency relationship, or partnership between the Parties or to impose any
partnership obligation or partnership liability upon either Party. Neither Party shall have
any right, power or authority to enter into any agreement or undertaking for, or act on
behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other
Party.
9.8
Severability
If any provision or portion of the Agreement shall for any reason be held or adjudged to
be invalid or illegal or unenforceable by any court of competent jurisdiction or other
governmental authority, (1) such portion or provision shall be deemed separate and
independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable
the benefits to each Party that were affected by such ruling, and (3) the remainder of the
Agreement shall remain in full force and effect.
9.9
Subcontractors
Nothing in the Agreement shall prevent a Party from using the services of any
subcontractor, or designating a third party agent as the one responsible for a specific
obligation or act required in the Agreement (collectively subcontractors), as it deems
appropriate to perform its obligations under the Agreement; provided, however, that
each Party will require its subcontractors to comply with all applicable terms and
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 14 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 15 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
conditions of the Agreement in providing such services and each Party will remain
primarily liable to the other Party for the performance of the subcontractor.
9.10
9.9.1
The creation of any subcontract relationship shall not relieve the hiring Party of
any of its obligations under the Agreement. The hiring Party shall by fully
responsible to the other Party for the acts or omissions of any subcontractor the
hiring Party hires as if no subcontract had been made. Any applicable obligation
imposed by the Agreement upon the hiring Party shall be equally binding upon,
and will be construed as having application to, any subcontractor of such Party.
9.9.2
The obligations under this Article will not be limited in any way by any
limitation of a subcontractor’s insurance.
Reservation of Rights
Rocky Mountain Power shall have the right to make a unilateral filing with the
Commission to modify this Agreement with respect to any rates, terms and conditions,
charges, classifications of service, rule, regulation or any other applicable provision of
the Federal Power Act and the Commission’s rules and regulations thereunder, and
Customer shall have the right to make a unilateral filing with the Commission to modify
this Agreement under any applicable provision of the Federal Power Act and the
Commission’s rules and regulations; provided that each Party shall have the right to
protest any such filing by the other Party and to participate fully in any proceeding
before the Commission in which such modifications may be considered. Nothing in this
Agreement shall limit the rights of the Parties, except to the extent that the Parties
otherwise agree as provided herein.
Article 10.
10.1
Notices and Records
General
Unless otherwise provided in the Agreement, any written notice, demand, or request
required or authorized in connection with the Agreement shall be deemed properly
given if delivered in person, delivered by recognized national courier service, sent by
first class mail, postage prepaid, or by electronic mail if an electronic mail address is
provided below, to the person specified below:
If to Customer:
Customer: ______________________________________________________
Attention: _____________________________________________________________
Address: ________________________________________________________________
City: ________________________________ State: _________________ Zip: ________
Phone: (____) ______________________ Fax: (____) ___________________________
Email: _________________________________________________________________
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 15 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 16 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If to Rocky Mountain Power:
By Mail:
Rocky Mountain Power
Attention: Net Metering Group
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
Or
By email:
[email protected]
10.2
Changes to the Notice Information
Either Party may change this notice information by giving five (5) business days written
notice prior to the effective date of the change.
10.3
Records
Rocky Mountain Power will maintain a record of the Net Metering Agreement and
related Attachments, if any, for as long as the net metering arrangement is in place.
Rocky Mountain Power will provide a copy of these records to Customer within fifteen
(15) Business Days if a request is made in writing.
Article 11.
Signatures
IN WITNESSETH WHEREOF, the Parties have caused the Agreement to be executed by
their respective duly authorized representatives.
For the Customer:
By: ______________________________________________
Name: ____________________________________________
Title: _____________________________________________
Date: _____________________________________________
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 16 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 17 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
For Rocky Mountain Power:
By: ______________________________________________
Name: ____________________________________________
Title: _____________________________________________
Date: _____________________________________________
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 17 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 18 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
APPENDIX A
ROCKY MOUNTAIN POWER UTAH NET METERING APPLICATION
LEVEL 1 REVIEW
INVERTER BASED SYSTEMS, 25 KW OR SMALLER
Section 1: For Rocky Mountain Power Use Only
Customer Name: ______________________________________________________________________
Service Address: ______________________________________________________________________
City, State, Zip: _______________________________________________________________________
Customer Account No. & Request No.: ____________________________________________________
Section 2: To Be Completed By Customer
A. Applicant Information
Name: _____________________________________________________________________
Mailing Address: ____________________________________________________________
City: ___________________________________State: _________ Zip Code: ____________
Site Street Address (if different from above): ______________________________________
City: ___________________________________State: __________ Zip Code: ___________
Daytime Phone: (_____) _____________________ Fax: (_____) ______________________
Email: _____________________________________________________________________
B. System Information
System Type:
Solar
Wind
Hydro
Other (Specify): ___________________
Generation Nameplate Capacity: _____ kW (Combine DC total of wind turbines, solar panels, etc)
Inverter Controlled:
Yes
No
Inverter Manufacturer: __________ Model: _______ Number of Inverters: ___ Rating: ____ kW
Manufacturer Nameplate Inverter Total AC Capacity Rating: _________ kW
Single Phase
Three Phase
Multiple Single Phase Connected on Poly-phase
Inverter(s):
(three phase) system (Attach Inverter and Panel Technical Specifications Sheets)
Type of Service:
Single Phase
Three Phase
If Three Phase:
120/208 Volts, 4 wire 120/240 Volts, 4 wire 277/480 Volts, 4 wire
Other (Please
Specify Voltage and Number of Service Wires): _______________________________________
Meets IEEE standard 1547 & UL Subject 1741 requirements as specified in Rule:
Yes
No
Please note: A disconnect switch is not required for an inverter-based facility with a name plate
rating of not more than 10 kW.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 18 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 19 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Manual disconnect required:
Yes
No
Will the net metering facility interconnect to a switchgear?
Yes
No
Net metering facility available fault duty at the point of common coupling:__________________
For other service types, the net metering facility must not impact the Customer’s service conductors
by more than 10 kW. If a disconnect switch is installed, Customer to provide a simple one-line
diagram that shows the location of the disconnect switch and Rocky Mountain Power meter.
Customer must post metal or plastic engraved signage indicating on-site generation in accordance
with National Electric Code. The signage must be permanent and located adjacent to the meter base
and disconnect switch noting “Parallel Generation on Site” and identifying the manual disconnect
switch with the words “Manual Disconnect for Parallel Generation.”____ (Initial Here)
Electrical Inspection approval date (attach copy or provide to utility when obtained):__________
Anticipated Operational Date of Net Metering Facilities: ________________________________
C. Application Fee - $60.00
D. Additional Information
1. An equipment package will be considered certified for interconnected operation if it has been
submitted by a manufacturer to a nationally recognized testing and certification laboratory, and
has been tested and listed by the laboratory for continuous interactive operation with an electric
distribution system in compliance with the applicable IEEE and UL 1741 standards in the Rule.
2. If the equipment package has been tested and listed as an integrated package, which includes a
generator or other electric source, the equipment package will be deemed certified, and Rocky
Mountain Power will not require any further design review, testing or additional information.
3. If the equipment package includes only the interface components (switchgears, inverters, or
other interface devices), an interconnection applicant must show that the generator or other
electric source being utilized with the equipment package is compatible with the equipment
package and consistent with the testing and listing specified for the package. If the generator or
electric source being utilized with the equipment package is consistent with the testing and
listing performed by the nationally recognized testing and certification laboratory, the
equipment package will be deemed certified and Rocky Mountain Power will not require
further design review, testing or additional equipment.
4. A net metering facility must be equipped with metering equipment that can measure the flow of
electricity in both directions, comply with ANSI C12.1 standards and Utah Administrative Rule
R746-312. Rocky Mountain Power will install the required metering equipment at Rocky
Mountain Power’s expense.
5. Rocky Mountain Power will not be responsible for the cost of determining the rating of
equipment owned by the customer-generator or of equipment owned by other local customers.
6. Customer may operate the Net Metering Facility temporarily for testing and obtaining
inspection approval. Customer shall not operate the Net Metering Facility in continuous
parallel without an executed Interconnection and Net Metering Service Agreement, and
approval from Rocky Mountain Power.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 19 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 20 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
E. Customer Acknowledgment
I certify that the information provided in this Application is true. I will provide Rocky Mountain
Power a copy of the signed government electrical inspection approval document when obtained, if
not already provided with this Application.
I agree to abide by the terms of this Application and I agree to notify Rocky Mountain Power thirty
(30) days prior to modification or replacement of the System’s components or design. Any such
modification or replacement may require submission of a new Application to Rocky Mountain
Power.
I agree not to operate the Net Metering Facility in parallel with Rocky Mountain Power, except
temporarily for testing and obtaining inspection approval, until this Application is approved by
Rocky Mountain Power, until this agreement is signed by both parties, and until I have provided
Rocky Mountain Power with at least five (5) days notice of anticipated start date.
Customer or Applicant Signature & Date: ____________________________________
Please send completed application to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
or
Please scan the completed application and email
[email protected]
Section 3: To be completed by the System Installer
Installation Contractor Information/Hardware and Installation Compliance
Installation Contractor (Company Name): _________________________________________________
Contractor's License No.: ______________________ Proposed Installation Date: __________________
Mailing Address: _____________________________________________________________________
City: _____________________________________ State: ___________ Zip Code: ________________
Daytime Phone: _______________ Fax: _______________ Email: ____________________________
For inverter-controlled system, meets IEEE Standards and UL 1741 Inverters, Converters, and
Yes
No
Controllers for use in Independent Power Systems as set forth in the Rule:
If Photovoltaic System, System must be installed in compliance with IEEE Standards, Recommended
Practice for Utility Interface of Photovoltaic Systems. All System types must be installed in compliance
with applicable requirements of local electrical codes, Rocky Mountain Power and the National Electrical
Code® (NEC) and must use an anti-islanding inverter.
The System must include a manual, lockable, load-break (disconnect) switch, unless exempt under Rule
746-312-4(2), accessible at all times to Rocky Mountain Power personnel and located within 10 feet of
Rocky Mountain Power’s meter. The disconnect switch may be located more than 10 feet from Rocky
Mountain Power’s meter if permanent instructions are posted at the meter indicating the precise location of
the disconnect switch. Rocky Mountain Power must approve the location of the disconnect switch prior to
the installation of the net metering facility.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 20 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 21 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If the Net Metering Facility is designed to provide uninterruptible power to critical loads, either through
energy storage, back-up generator, or the generation source, the Net Metering Facility will include a
parallel blocking scheme for this backup source. This function may be integral to the inverter
manufacturer’s packaged system.
Does the Net Metering Facility include a parallel blocking scheme:
Yes
No
Signed (Contractor): ______________________________________ Date: _____________
Name (Print): _______________________________________________
Section 4. To be completed by Rocky Mountain Power:
A. If approving the application:
Rocky Mountain Power does not, by approval of this Application, assume any responsibility or
liability for damage to property or physical injury to persons. Further, this Application does not
constitute a dedication of the owner's System to Rocky Mountain Power electrical system
equipment or facilities.
Customer entered into an Interconnection and Net Metering Service Agreement with Rocky
Mountain Power on the ____ day of _____, 20__.
Customer satisfactorily passed Witness Tests on the ____ day of _________, 20__.
(Rocky Mountain Power may waive Witness Tests at its option; if tests are waived initial here __)
This Application is approved by Rocky Mountain Power on this ______ day of _________, 20__
Rocky Mountain Power Representative Name (Print):___________________________________
Signed (Rocky Mountain Power Representative): ______________________ Date: __________
B. If denying the application:
This application is denied by Rocky Mountain Power on this ______ day of ____________, 20__
for the following reason(s):_________________________________________________________
Rocky Mountain Power Representative Name (Print):____________________________________
Signed (Rocky Mountain Power Representative): ________________________ Date:__________
Applicant may submit a new application for Level 2 review.
Section 5: To be completed by Rocky Mountain Power Meterman
Customer Account No. _____________________________ Site ID No. : ______________________
Served from Facility Point No.: ________________________________
New Net Meter No.: ____________________________ Date net meter installed: ________________
Manual disconnect required:
Yes
No Proper location & permanent signage in place:
Yes
No
Signature/Title:_____________________________________________ Date:___________________
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 5 - Level 1
Page 21 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 22 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
We appreciate your interest in Rocky Mountain Power’s net metering program. Before
purchasing any net metering equipment, we recommend you review the requirements for
interconnecting a net metering system to Rocky Mountain Power’s electrical distribution
system. The requirements are found in the Interconnection Agreement.
To complete the process for a net metering interconnection, please follow the steps below:
1. Complete and submit the following to Rocky Mountain Power:
 Interconnection Agreement including the Application for Net Metering
Interconnection
 The inverter specification sheet
 For systems larger than 10 kW, a simple one-line diagram showing
 The location of Rocky Mountain Power’s meter
 The location of the disconnect switch
2. Rocky Mountain Power will review your agreement and application and send you a
written notification of approval either by mail or e-mail
3. Install the net metering system after you receive the written approval of your
Interconnection Agreement and Application for Net Metering from Rocky Mountain
Power
4. Obtain an inspection of your net metering system by the local city or county electrical
inspector
5. Submit the electrical inspector’s approval to Rocky Mountain Power
6. Turn on your net metering system after Rocky Mountain Power provides you written
notification the interconnection work has been completed and the net meter installed
Return completed documents to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, Utah 84125-0308
Or Email to:
[email protected]
Thank you for your interest in the net metering program. If you have questions, please call us
toll free at 1-888-221-7070 and ask for a net metering specialist.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 1 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 23 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Service ID#:___________
Request #: ___________
INTERCONNECTION AND NET METERING SERVICE AGREEMENT FOR NET
METERING FACILITY LEVEL 2 INTERCONNECTION
UP TO 2 MW NAMEPLATE CAPACITY
This Interconnection and Net Metering Service Agreement (“Agreement”) is made and
entered into this ____ day of _____________, 20___, by and between
_____________________________, an electric customer (“Customer”), and PacifiCorp, dba
Rocky Mountain Power (“Rocky Mountain Power”), a Corporation organized and existing
under the laws of the State of Oregon. Customer and Rocky Mountain Power each may be
referred to as a “Party”, or collectively as the “Parties”.
Recitals:
Whereas, Customer has installed or intends to install a Net Metering Facility qualifying
for “Net Metering,” Utah Rate Schedule No. 135A (“Schedule 135A”), as given in Rocky
Mountain Power’s currently effective tariff as filed with the Public Service Commission of
Utah (“Commission”), on or adjacent to Customer’s premises located at
____________________________, Utah, for the purpose of generating electric energy;
Whereas, the Net Metering rate schedule may be amended from time to time, and the
Public Service Commission may alter the charge, credit, and ratemaking structure applicable to
Net Metering customers pursuant to Utah Code § 54-15-105.1;
Whereas, Customer represents to Rocky Mountain Power that Customer either owns or
leases its Net Metering Facility qualifying for Schedule 135A, or meets the exemption
requirements set forth in Utah Code § 54-2-1.16(d) because it is a county, municipality, city,
town, other political subdivision, local district, special service district, state institution of higher
education, school district, charter school, or any entity within the state system of public
education; or an entity qualifying as a charitable organization under 26 U.S.C. Sec. 501(c)(3)
operated for religious, charitable, or educational purposes that is exempt from federal income
tax and able to demonstrate its tax-exempt status;
Whereas, Customer desires to interconnect the Net Metering Facility with Rocky
Mountain Power’s distribution system consistent with the Application completed by Customer
on _____________ ____, 20___, as described in as described in Appendix B (“Application”)
of this Agreement; and
Whereas, Customer, using its Net Metering Facility, intends to offset part or all of its
electrical requirements supplied by Rocky Mountain Power.
Now, therefore, in consideration of and subject to the mutual covenants contained
herein, the Parties agree as follows:
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 2 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 24 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 1.
Scope and Limitations of Agreement
1.1
Scope
The Agreement shall be used for all approved Level 2 Applications according to the
procedures set forth in Utah Administrative Rule 746-312, as may be amended from
time to time (“Rule”). The Rule can be viewed at www.psc.utah.gov. The Agreement
establishes standard terms and conditions approved by the Public Service Commission
of Utah (“Commission”) under which the Net Metering Facility with an Electric
Nameplate Capacity of 2 MW or smaller as described in Appendix B will interconnect
to, and operate in parallel with, Rocky Mountain Power’s system.
1.2
Definitions
Terms with initial capitalization, when used in this Agreement, shall have the meanings
indicated or as specified in the Rule Section R746-312-2 and, to the extent this
Agreement conflicts with the Rule, the Rule shall take precedence.
1.3
Other Agreements
Nothing in this Agreement is intended to affect any other agreement between Rocky
Mountain Power and Customer or any other Interconnection Customer. However, in the
event that the provisions of the Agreement are in conflict with the provisions of any
Rocky Mountain Power Tariff, as may be amended from time to time, the Rocky
Mountain Power Tariff, as may be amended from time to time, shall control.
1.4
Responsibilities of the Parties
1.4.1
The Parties shall perform all obligations of the Agreement in accordance with
all applicable laws and regulations.
1.4.2
Customer will construct, operate, test, and maintain its Net Metering Facility in
accordance with the Agreement, IEEE standards (available at the following link:
http://standards.ieee.org/index.html), National Electric Code Standards
(available for purchase at http://standards.ieee.org/faqs/NESCFAQ.html#q8),
Utah state building codes (available at the following link:
http://www.dopl.utah.gov/programs/ubc/), the Rule and other applicable
standards required by the Commission, as may be amended from time to time.
1.4.3
Each Party shall be responsible for the safe installation, maintenance, repair and
condition of their respective lines and appurtenances on their respective sides of
the Point of Common Coupling. Each Party shall provide interconnection
facilities that adequately protect the other Party’s facilities, personnel and other
persons from damage and injury. The allocation of responsibility for the design,
installation, operation, maintenance and ownership of interconnection facilities
is prescribed in the Rule, including but not necessarily limited to R746-312-4.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 3 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 25 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.5
1.4.4
Customer is responsible for protecting the generating equipment, inverters,
protective devices, and other system components from damage from the normal
and abnormal conditions and operations that occur on Rocky Mountain Power’s
system in delivering and restoring power; and is responsible for ensuring that
the Net Metering Facility equipment is inspected, maintained, and tested in
accordance with the manufacturer’s instructions to ensure that it is operating
correctly and safely.
1.4.5
Customer shall obtain Rocky Mountain Power’s approval of the Application
prior to commencing parallel operation of its interconnected Net Metering
Facility.
Parallel Operation and Maintenance Obligations
Once the Net Metering Facility has been authorized to commence parallel operation by
an approved application, and execution of this Agreement, Customer will abide by all
written provisions for operations and maintenance as required by the Rule and Rocky
Mountain Power’s Tariffs, including but not necessarily limited to R746-312-4 and
Schedule 135A or its successor tariff(s).
1.6
Metering
Rocky Mountain Power shall install, own and maintain, at its sole expense, a kilowatthour meter(s) and associated equipment to measure the flow of energy in each direction,
unless otherwise authorized by the Commission. Customer shall provide, at its sole
expense, adequate facilities, including, but not limited to, a current transformer
enclosure (if required), meter socket(s) and junction box, for the installation of the meter
and associated equipment.
Customer hereby consents to the installation and operation by Rocky Mountain Power
and at Rocky Mountain Power’s expense, of one or more additional meters to monitor
the flow of electricity in each direction. Such meters shall be located on the premises of
Customer.
1.7
Net Metering Facility Requirements, Installation, Operation
1.7.1
Customer’s Net Metering Facility must meet the requirements set forth in,
including but not necessarily limited to, the Rule, R746-312-4 and Schedule
135A or its successor tariff(s). This also applies to installation and operation of
the Net Metering Facility.
1.7.2
Customer is responsible for all costs associated with its Net Metering Facility
and is also responsible for all costs related to any modifications to the Net
Metering Facility that may be required by Rocky Mountain Power for purposes
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 4 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 26 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
of safety and reliability as allowed under the Rule and Rocky Mountain Power
tariffs.
1.8
Power Quality
Customer will design its Net Metering Facility to maintain a composite power delivery
at continuous rated power output at the Point of Common Coupling that meets the
requirements set forth in IEEE 1547, in accordance with the Rule, R746-312-4.
1.9
Anticipated Start Date
Customer must include an anticipated start date for operation of its Net Metering
Facility in the Application. After receiving notice that the Application has been
approved and satisfactory completion of all reviews and inspections of the Net Metering
Facility, Customer must notify Rocky Mountain Power at least ten (10) Business Days
prior to starting operation of the Facility, through either submission of an executed
Agreement or through separate written notice. Customer shall not commence parallel
operation of the Net Metering Facility until Rocky Mountain Power executes this
Agreement, installs the net meter and notifies Customer that the Net Metering Facility
is interconnected.
1.10
Net Metering Facility Inspection
1.10.1 Building Code Inspection
Prior to operation in parallel with Rocky Mountain Power’s system, the Net
Metering Facility must be inspected by a local building code official to ensure
compliance with applicable local codes.
1.10.2 Inspection by Rocky Mountain Power
Rocky Mountain Power may inspect the Net Metering Facility and its
component equipment, and the documents necessary to ensure compliance with
the Rule. Customer shall notify Rocky Mountain Power prior to placing the Net
Metering Facility in service, and Rocky Mountain Power shall have the right to
have personnel present on the in-service date. If the Net Metering Facility is
subsequently modified in order to increase its gross power rating, Customer
must notify Rocky Mountain Power by submitting a new application specifying
the modifications in accordance with the level of review required for that
application.
1.11
Net Metering Facility Testing and Maintenance
Customer shall conduct maintenance and testing on its Net Metering Facilities as set
forth in the Rule, including but not necessarily limited to R746-312-14.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 5 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 27 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.11.1 Customer shall conduct any manufacturer-recommended testing or maintenance
at its expense.
1.11.2 Customer shall conduct any post-installation testing, at its expense, necessary to
ensure compliance with IEEE standards as set forth in the Rule or to ensure
safety. This includes replacing a major equipment component that is different
from the originally installed model.
1.11.3 When Customer performs maintenance or testing in accordance with the Rule,
it must retain written records documenting the maintenance and results of the
testing for three (3) years.
1.11.4 Rocky Mountain Power shall have the right to inspect Customer’s facility after
interconnection approval is granted, at reasonable hours and with reasonable
prior notice to Customer. If Rocky Mountain Power discovers that the Net
Metering Facility is not in compliance with the Rule, Rocky Mountain Power
may require Customer to disconnect the Net Metering Facility until compliance
is achieved.
1.12
Removal of Facility
Customer shall immediately notify Rocky Mountain Power if Customer removes or
ceases to operate the Net Metering Facility.
Article 2.
2.1
Review, Inspection, Testing, Disconnect Switch and Signage, and Right of
Access
Initial Review and Additional Review
After determining Customer’s interconnection request is complete, in accordance with
the Rule, R746-312-9, Rocky Mountain Power will conduct a review of the proposed
interconnection, using screens set forth in the Rule R746-312-7. Rocky Mountain Power
will conduct such review within fifteen (15) days after notifying Customer that the
interconnection request is complete and will notify Customer either: 1) the Net Metering
Facility meets all applicable criteria and the interconnection request is approved; 2)
although the Net Metering Facility fails one or more of the screens the Net Metering
Facility may be interconnected consistent with safety, reliability, and power quality
standards and the interconnection is approved; or 3) the interconnection of the Net
Metering Facility has failed to meet one or more of the applicable criteria and the reason
for failure, or Rocky Mountain Power has not or could not determine from the initial
reviews that the Net Metering Facility may be interconnected consistent with safety
reliability, and power quality standards, or the Net Metering Facility cannot be approved
without minor modifications at minimal cost and the interconnection request is denied
unless the Customer is willing to consider minor modifications or further study.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 6 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 28 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If the initial review determines that the Net Metering Facility fails to meet one or more
applicable requirements, but additional review may enable Rocky Mountain Power to
determine that the Net Metering Facility may be interconnected consistent with safety,
reliability and power quality standards, Rocky Mountain Power will offer to perform
the additional review to determine whether minor modifications to the electric
distribution system would enable the interconnection to be made consistent with safety,
reliability and power quality standards. In this instance, Rocky Mountain Power will
provide Customer with a good faith, nonbinding estimate of costs of such additional
review and minor modifications. Rocky Mountain Power will conduct additional review
and make minor modifications after receipt of payment from Customer in accordance
with the attached Appendix A.
2.2
Equipment Testing and Inspection
Customer must notify Rocky Mountain Power of the anticipated testing and inspection
date of the Net Metering Facility at least ten (10) business days prior to testing, either
through submittal of the Agreement, a notice of completion, or in a separate notice.
Within ten (10) business days after receipt of such required documentation, Rocky
Mountain Power will inspect the Net Metering Facility, set the new meter if required,
approve the interconnection and may arrange a witness test as set forth in the Rule,
R746-312-9(5). Rocky Mountain Power and Customer will select a date by mutual
agreement for the witness tests.
Rocky Mountain Power will test and inspect the Net Metering Facility and
Interconnection Facilities prior to interconnection in accordance with IEEE Standards
as provided for in the Rule, R746-312-4. Customer shall not begin operation of its Net
Metering Facility until after inspection and testing is completed.
If a witness test is conducted and is not satisfactory, Customer must resolve any
deficiencies within forty-five (45) business days or other time period as mutually agreed
by the Parties.
2.3
Disconnect Switch and Signage
Customer shall comply with the Rule regarding disconnect switches, R746-312-4. The
disconnect switch may be located more than 10 feet from the public utility meter if
permanent instructions in letters of appropriate size are posted at the meter indicating
the precise location of the disconnect switch. Rocky Mountain Power must approve in
writing the location of the disconnect switch prior to the installation of the Net Metering
Facility.
2.4
Right of Access
As provided in the Rule, R746-312-4, Rocky Mountain Power shall have access to any
required disconnect switch at the Net Metering Facility at all times. Rocky Mountain
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 7 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 29 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Power will provide reasonable notice to Customer when possible prior to using the right
of access. Additionally, as provided in Rocky Mountain Power Utah Rule 6, or its
successor tariff, Rocky Mountain Power shall have access to the metering equipment.
Article 3.
3.1
Effective Date, Term, Termination and Disconnection
Effective Date
The Agreement shall become effective upon execution by the Parties.
3.2
Term of Agreement
The Agreement will become effective on the Effective Date and will remain in effect
unless terminated in accordance with provisions of this Agreement, or Order by the
Commission.
3.3
Termination
No termination will become effective until the Parties have complied with all applicable
laws and clauses of this Agreement applicable to such termination.
3.3.1
Customer may terminate this Agreement at any time by giving Rocky Mountain
Power twenty (20) business days written notice.
3.3.2
Either Party may terminate this Agreement after default pursuant to Article 6.4
of this Agreement.
3.3.3
The Commission may Order termination of this Agreement.
3.3.4
Upon termination of this Agreement, Customer shall disconnect the Net
Metering Facility from Rocky Mountain Power’s system. The termination of
this Agreement will not relieve either Party of its liabilities and obligations,
owed or continuing at the time of termination.
3.3.5
If Customer removes the Net Metering equipment at the Net Metering Facility
or ceases to operate its Net Metering Facility at the premise listed in the
Application, this Agreement will be immediately terminated.
3.3.6
The provisions of this Article shall survive termination or expiration of this
Agreement.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 8 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 30 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
3.4
Temporary Disconnection
3.4.1
Rocky Mountain Power may temporarily disconnect the Net Metering Facility
from Rocky Mountain Power’s system for so long as reasonably necessary in
the event one or more of the following conditions or events occurs:
3.4.1.1 Emergencies or to address maintenance requirements for Rocky
Mountain Power’s system.
3.4.1.2 Hazardous conditions existing on Rocky Mountain Power’s system
which may affect the safety of the general public or Rocky Mountain
Power employees due to the operation of the Net Metering Facility or
protective equipment as determined by Rocky Mountain Power.
3.4.1.3 Adverse electrical effects on the electrical equipment of Rocky Mountain
Power’s other electric customers caused by the Net Metering Facility as
determined by Rocky Mountain Power.
3.4.2
In the event that no disconnect switch is installed, Rocky Mountain Power may
physically disconnect all service to the Customer and/or all service to the
premises where the Net Metering Facility is located.
3.4.3
To the extent practicable, Rocky Mountain Power will give prior notice of any
temporary disconnection of the Net Metering Facility. If Rocky Mountain Power
is unable to give prior notice, Rocky Mountain Power will provide notice
including an explanation of the condition necessitating the disconnection at the
time of disconnection.
3.4.4
Under emergency conditions, Rocky Mountain Power or Customer may
immediately suspend interconnection service and temporarily disconnect the
Net Metering Facility. Rocky Mountain Power shall notify Customer promptly
when Rocky Mountain Power becomes aware of an emergency condition that
may reasonably be expected to affect the Net Metering Facility operation.
Customer shall notify Rocky Mountain Power promptly when Customer
becomes aware of an emergency condition that may reasonably be expected to
affect Rocky Mountain Power’s system. To the extent the information is known,
the notification shall describe the emergency condition, the extent of any
damage or deficiency, the expected effect on the operation of both Parties’
facilities and operations, the anticipated duration, and the necessary corrective
action.
3.4.5
Customer shall make reasonable efforts to provide notice of interruption of Net
Metering Facility operation for safety and/or reliability reasons prior to the
interruption unless an emergency occurs. Emergency interruptions or temporary
terminations are subject to Section 3.4.1 above.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 9 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 31 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
3.4.6
Rocky Mountain Power shall use reasonable efforts to provide Customer with
prior notice of forced outages to effect immediate repairs to Rocky Mountain
Power’s system. If prior notice is not given, Rocky Mountain Power, shall, upon
request, provide Customer written documentation after the fact explaining the
circumstances of the disconnection.
3.4.7
Customer must provide Rocky Mountain Power notice and obtain Rocky
Mountain Power’s written approval before Customer may modify its Net
Metering Facility in order to increase the electric output of the Net Metering
Facility. If Customer makes any material change without prior written
authorization of Rocky Mountain Power, Rocky Mountain Power will have the
right to temporarily disconnect the Net Metering Facility until Rocky Mountain
Power has had an opportunity to review the change(s) made to determine
whether they are acceptable. If any system modifications or other equipment
installations are deemed necessary by Rocky Mountain Power to accommodate
the modified Net Metering Facility, Customer shall submit the appropriate net
metering application at that time.
3.4.8
The Parties shall cooperate with each other to restore the Net Metering Facility,
Interconnection Facilities, and Rocky Mountain Power’s system to their normal
operating state as soon as reasonably practicable following any disconnection
pursuant to this section.
Article 4.
4.1
Cost Responsibility
Application Fee
Customer shall bear the cost of any Application fee provided for in the Rule, R746-31213(2), or as otherwise approved by the Commission. Customer shall remit payment with
the Application as calculated in the Application, Section 2(C).
4.2
Net Metering Facility and Interconnection Equipment
Customer shall be responsible for all costs including overheads, associated with
procuring, installing, owning, operating, maintaining, repairing, and replacing its Net
Metering Facility, any associated equipment package, and any associated
interconnection equipment or interconnection facilities required to be installed on
Customer’s side of the Point of Common Coupling.
4.3
Minor Modifications
If, under Section 2.1 of this Agreement, additional review is performed and minor
modifications to the electric distribution system are required to enable the
interconnection to be made consistent with safety, reliability and power quality
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 10 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 32 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
standards applicable to Level 2 interconnection reviews, the Customer shall pay for the
cost to procure, install, and construct, operate, maintain, repair and replace any such
Minor Modifications. A description of the minor modifications may be found in
Appendix A. The cost of the minor modifications as described on Appendix A shall be
$________. Customer shall remit payment for minor modifications prior to Rocky
Mountain Power commencing the work required for the minor modifications.
Article 5.
5.1
Billing
Monthly Billing
The electric service charge shall be computed in accordance with the monthly billing in
the currently applicable standard service tariff. Customer will be compensated for net
excess energy in accordance with Schedule 135A or its successor tariff(s). Customer
will be transitioned to any successor tariff immediately upon approval of that tariff by
the Public Service Commission and will be subject to any charge, credit, or ratemaking
structure implemented therein.
5.2
Special Conditions
Customer must comply with the special conditions found in Schedule 135A or its
successor tariff(s).
5.3
Aggregating Meters
Aggregating Meters is allowed if certain conditions are met under the Rule, R746-3125.
Customer
designates
the
following
meters
for
aggregation:
_______________________. In the event that the Net Metering Facility supplies more
electricity to Rocky Mountain Power than the Customer uses from Rocky Mountain
Power, Rocky Mountain Power will apply any credits to the next monthly bill in
accordance with Utah Code § 54-15-104 and the Rule, R746-312-15. Customer shall
designate the order in which to apply any credits in accordance with the Rule. <<If
customer does not want to aggregate, insert “N\A” in the gray box.>>
Article 6.
6.1
Assignment, Liability, Indemnity, Force Majeure, Consequential Damages
and Default
Assignment
This Agreement may be assigned by either Party with the consent of the other Party. A
Party’s consent to an assignment may not be unreasonably withheld. The assigning
Party must give the non-assigning Party written notice of the assignment at least fifteen
days (15) before the effective date of the assignment. The non-assigning Party must
submit its objection to the assignment, if any, to the assigning Party in writing at least 5
business days before the effective date of the assignment. If a written objection is not
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 11 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 33 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
received within that time period, the non-assigning party is deemed to consent to the
assignment.
6.1.1
Exceptions to the Consent Requirement
6.1.1.1 Either Party may assign the Agreement without the consent of the other
Party to any affiliate (including a merger or acquisition of the Party with
another entity), of the assigning Party with an equal or greater credit
rating and with the legal authority and operational ability to satisfy the
obligations of the assigning Party under this Agreement.
6.1.1.2 Customer-Generator is entitled to assign the Agreement, without the
consent of Rocky Mountain Power, for collateral security purposes to aid
in obtaining financing for the Net Metering Facility.
6.1.1.3 For Net Metering systems that are integrated into a building facility, the
sale of the building or property will result in the automatic assignment
of this Agreement to the new owner who will be responsible for
complying with the terms and conditions of this Agreement.
6.1.2
6.2
Any attempted assignment that violates this Article is void and ineffective.
Assignment does not change or eliminate a Party’s obligations under this
Agreement. An assignee is responsible for meeting the same obligations as the
assigning Party.
Limitation of Liability and Consequential Damages
Each Party’s liability to the other Party for any loss, cost, claim, injury, liability, or
expense, including reasonable attorney’s fees, relating to or arising from any act or
omission in the performance of this Agreement, is limited to the amount of direct
damage actually incurred. Neither Party is liable to the other Party for any indirect,
special, consequential, or punitive damages.
6.3
Indemnification
Customer shall hold harmless and indemnify Rocky Mountain Power for all loss to third
parties resulting from the operation of the Net Metering Facility, except when the loss
occurs due to the negligent actions of Rocky Mountain Power.
Rocky Mountain Power shall hold harmless and indemnify Customer for all loss to third
parties resulting from the operation of Rocky Mountain Power’s system, except where
the loss occurs due to the negligent actions of Customer.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 12 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 34 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
6.4
6.5
Force Majeure
6.4.1
As used in this Agreement, a Force Majeure Event shall mean “any act of God,
labor disturbance, act of the public enemy, war, acts of terrorism, insurrection,
riot, fire, storm or flood, explosion, breakage or accident to machinery or
equipment through no direct, indirect, or contributory act of a Party, any order,
regulation, or restriction imposed by governmental, military or lawfully
established civilian authorities, or any other cause beyond a Party’s control. A
Force Majeure Event does not include an act of negligence or wrongdoing.”
6.4.2
If a Force Majeure Event prevents a Party from fulfilling any obligations under
this Agreement, the Party affected by the Force Majeure Event (“Affected
Party”) shall promptly notify the other Party of the existence of the Force
Majeure Event. The notification must specify in reasonable detail the
circumstances of the Force Majeure Event, its expected duration, and the steps
that the Affected Party is taking to mitigate the effects of the event on its
performance, and if the initial notification was verbal, it should be promptly
followed up with a written notification. The Affected Party shall keep the other
Party informed on a continuing basis of developments relating to the Force
Majeure Event until the event ends. The Affected Party will be entitled to
suspend or modify its performance of obligations under this Agreement (other
than the obligation to make payments) only to the extent that the effect of the
Force Majeure Event cannot be reasonably mitigated. The Affected Party will
use reasonable efforts to resume its performance as soon as possible. The Parties
shall immediately report to the Commission should a Force Majeure Event
prevent performance of an action required by Rule that the Rule does not permit
the Parties to mutually waive.
Default
6.5.1
A Party is in default if the Party fails to perform an obligation required under
this Agreement (other than the payment of money). A Party is not considered in
default of this agreement if the failure to perform an obligation is caused by an
act or omission of the other Party or is the result of a Force Majeure as defined
in this Agreement.
6.5.2
Upon a default, the non-defaulting Party must give written notice of the default
to the defaulting party. The defaulting party has sixty (60) calendar days from
the receipt of the written default notice to cure the default. If the default is not
capable of cure within the 60-day period, the defaulting Party must begin to cure
the default within twenty (20) calendar days after receipt of the written default
notice, and must continuously and diligently complete the cure within six (6)
months of the receipt of the notice.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 13 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 35 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
6.5.3
Article 7.
If a default is not cured as provided for in 6.5.2, then the non-defaulting Party is
entitled to terminate the Agreement by written notice at any time until cure
occurs. If the non-defaulting Party chooses to terminate this Agreement, the
termination provisions in Article 3.3 apply. Alternately, the non-defaulting Party
is entitled to seek dispute resolution with the Commission in lieu of termination.
Insurance
Additional liability insurance is not required as a part of the Agreement if the Net Metering
Facility is in compliance with the provisions of the Application approval, the Agreement and
the standards contained in Utah Code § 54-15-106.
Article 8.
Dispute Resolution
8.1
Nothing in this Article shall restrict the rights of any Party to file a complaint with the
Commission under relevant provisions of the Rule and applicable state law.
8.2
Pursuit of dispute resolution may not affect a Customer with regard to consideration of
an Interconnection Request or a Customer’s queue position.
Article 9.
9.1
Miscellaneous
Governing Law, Regulatory Authority and Rules
The validity, interpretation, and enforcement of this Agreement is governed by the laws
of the State of Utah. If any provision of this Agreement conflicts with any applicable
provision, as may be amended from time to time, of the Utah Code (“Code”), Utah
Administrative Rules (“Rules”), or Rocky Mountain Power’s Tariffs (“Tariff”), then the
applicable provision of the Code, Rules, or Tariff controls. Rocky Mountain Power must
provide copies of the applicable provisions of the Code, Rules, and Tariff upon the
Customer’s request.
9.2
Amendment
Additions, deletions or changes to the standard terms and conditions of this Agreement
will not be permitted unless they are mutually agreed to by the Parties and permitted by
the Rule or permitted by the Commission for good cause shown. The Parties may amend
the Agreement by a written instrument duly executed by both Parties in accordance with
the provisions of the Rule and applicable Commission Orders and provisions of the laws
of the State of Utah.
9.3
No Third Party Beneficiaries
The Agreement is not intended to and does not create rights, remedies, or benefits of
any character whatsoever in favor of any persons, corporations, associations, or entities
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 14 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 36 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
other than the Parties, and the obligations herein assumed are solely for the use and
benefit of the Parties, or where permitted, their successors in interest and their assigns.
9.4
9.5
Waiver
9.4.1
The failure of a Party to the Agreement to insist, on any occasion, upon strict
performance of any provision of the Agreement, will not be considered a waiver
of any obligation, right, or duty of, or imposed upon, such Party.
9.4.2
The Parties may also agree to mutually waive a Section of this Agreement
without the Commission’s approval where the Rule so provides.
9.4.3
Any waiver at any time by either Party of its rights with respect to the Agreement
shall not be deemed a continuing waiver or a wavier with respect to any other
failure to comply with any other obligation, right, duty of the Agreement.
Termination or default of this Agreement for any reason by Customer shall not
constitute a waiver of the Customer’s legal rights to obtain interconnection from
Rocky Mountain Power. Any request for waiver of the Agreement or any
provisions thereof shall be provided in writing.
Entire Agreement
The Agreement, including any supplementary attachments that may be necessary,
constitutes the entire Agreement between the Parties with reference to the subject matter
hereof, and supersedes all prior and contemporaneous understandings or agreements,
oral or written, between the Parties with respect to the subject matter of the Agreement.
There are no other agreements, representations, warranties, or covenants that constitute
any part of the consideration for, or any condition to, either Party’s compliance with its
obligations under the Agreement.
9.6
Multiple Counterparts
This Agreement may be executed in one or more counterparts, whether electronically
or otherwise, each of which is deemed an original but all constitute one and the same
instrument.
9.7
No Partnership
The Agreement will not be interpreted or construed to create an association, joint
venture, agency relationship, or partnership between the Parties or to impose any
partnership obligation or partnership liability upon either Party. Neither Party shall have
any right, power or authority to enter into any agreement or undertaking for, or act on
behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other
Party.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 15 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 37 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
9.8
Severability
If any provision or portion of the Agreement shall for any reason be held or adjudged to
be invalid or illegal or unenforceable by any court of competent jurisdiction or other
governmental authority, (1) such portion or provision shall be deemed separate and
independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable
the benefits to each Party that were affected by such ruling, and (3) the remainder of the
Agreement shall remain in full force and effect.
9.9
Subcontractors
Nothing in the Agreement shall prevent a Party from using the services of any
subcontractor, or designating a third party agent as one responsible for a specific
obligation or act required in the Agreement (collectively “subcontractors”), as it deems
appropriate to perform its obligations under the Agreement; provided, however, that
each Party will require its subcontractors to comply with all applicable terms and
conditions of the Agreement in providing such services and each Party will remain
primarily liable to the other Party for the performance of the subcontractor.
9.10
9.9.1
The creation of any subcontract relationship shall not relieve the hiring Party of
any of its obligations under the Agreement. The hiring Party shall by fully
responsible to the other Party for the acts or omissions of any subcontractor the
hiring Party hires as if no subcontract had been made. Any applicable obligation
imposed by the Agreement upon the hiring Party shall be equally binding upon,
and will be construed as having application to, any subcontractor of such Party.
9.9.2
The obligations under this Article will not be limited in any way by any
limitation of a subcontractor’s insurance.
Reservation of Rights
Rocky Mountain Power shall have the right to make a unilateral filing with the
Commission to modify this Interconnection Agreement with respect to any rates, terms
and conditions, charges, classifications of service, rule, regulation or any other
applicable provision of the Federal Power Act and the Commission’s rules and
regulations thereunder, and Customer shall have the right to make a unilateral filing
with the Commission to modify this Agreement under any applicable provision of the
Federal Power Act and the Commission’s rules and regulations; provided that each Party
shall have the right to protest any such filing by the other Party and to participate fully
in any proceeding before the governing authority in which such modifications may be
considered. Nothing in this Agreement shall limit the rights of the Parties, except to the
extent that the Parties otherwise agree as provided herein.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 16 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 38 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 10.
10.1
Notices and Records
General
Unless otherwise provided in the Agreement, any written notice, demand, or request
required or authorized in connection with the Agreement shall be deemed properly given
if delivered in person, delivered by recognized national courier service, sent by first
class mail, postage prepaid, or by electronic mail if an electronic mail address is
provided below to the person specified below:
If to Customer:
Customer: ______________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: ________________________________ State: _________________ Zip: ________
Phone: (____) ________________________ Fax: (____) _________________________
Email: __________________________________________________________________
If to Rocky Mountain Power:
By Mail:
Rocky Mountain Power
Attention: Net Metering Group
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
Or
By email:
[email protected]
10.2
Records
Rocky Mountain Power will maintain a record of the Interconnection Agreement and
related Attachments, if any, for as long as the interconnection is in place. Rocky
Mountain Power will provide a copy of these records to Customer within fifteen (15)
Business Days upon written request.
10.3
Billing and Payment
Billings and payments shall be sent to the addresses below (complete if different from
Section 10.1 above):
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 17 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 39 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If to Customer:
Customer: ______________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: _______________________________ State: _______________ Zip: ___________
10.4
Designated Operating Representative
The Parties will designate one operating representative each to conduct the
communications that may be necessary or convenient for the administration of the
operations provisions of the Agreement. This person will also serve as the point of
contact with respect to operations and maintenance of the Party’s facilities (complete if
different from Section 10.1 above):
Customer’s Operating Representative:
Name: __________________________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: _______________________________ State: _______________ Zip: ___________
Phone: (____) _______________________ Fax: (____) __________________________
Email: __________________________________________________________________
10.5
Changes to the Notice Information
Either Party may change this notice information by giving five (5) business days written
notice prior to the effective date of the change.
Article 11.
Signatures
IN WITNESSETH WHEREOF, the Parties have caused the Agreement to be executed by
their respective duly authorized representatives.
For the Customer:
For Rocky Mountain Power:
By: _____________________________
By: _____________________________
Name: ___________________________
Name: ___________________________
Title: ____________________________
Title: ____________________________
Date: ____________________________
Date: ____________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 18 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 40 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Appendix A
Minor Modifications
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 19 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 41 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
APPENDIX B
ROCKY MOUNTAIN POWER UTAH NET METERING APPLICATION
LEVEL 2 REVIEW
CAPACITY OF 2 MW OR LESS
Section 1: For Rocky Mountain Power Use Only
Customer Name: _________________________________________________________________________
Service Address: _________________________________________________________________________
City, State, Zip: __________________________________________________________________________
Customer Account No. & Request No.:________________________________________________________
Interconnection Agreement Acknowledgement (Date): ___________________________________________
Application fee: $__________________ Date Paid: _____________________________________________
Section 2: To Be Completed By Customer
A. Applicant Information
Name: ___________________________________________________________________________
Mailing Address: ___________________________________________________________________
City: __________________________________________State: _________ Zip Code: ____________
Site Street Address (if different from above): _____________________________________________
City: __________________________________________State: __________ Zip Code: ___________
Daytime Phone: (_____) ________________________ Fax: (_____) __________________________
Email: ____________________________________________________________________________
B. System Information
System Type:
Solar
Wind
Hydro
Other (Specify): _________________________
Generation Nameplate Capacity: ______________ kW (Combine DC total of wind turbines, solar
panels, etc. or AC rating if an inverter is not utilized)
Inverter Manufacturer: ___________ Model: _______ Number of Inverters: _____ Rating: _____ kW
Manufacturer Nameplate Inverter Total AC Capacity Rating: _________ kW
Inverter(s):
Single Phase
Three Phase
Multiple Single Phase Connected on Poly-phase
(three phase) system (Attach Inverter and Panel Technical Specifications Sheets)
Type:
Induction
Type of Service:
Inverter
Single Phase
Synchronous
__________________Other
Three Phase
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 20 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 42 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If Three Phase Transformer:
Indicate Type:
Wye
Delta
Indicate Voltage and Number of Service Wires:
120/208 Volts, 4 wire 120/240 Volts, 4 wire 277/480 Volts, 4 wire
Other ___________
________________________________________________________________________________
Other Information:_________________________________________________________________
________________________________________________________________________________
Self Contained Location: ___________________________________________________________
Outdoor Manual AC Disconnect Switch Location (show Disconnect Switch and Rocky Mountain
Power Meter Location on Site Plan), unless exempt under Utah Administrative Rule 746-312-4(2):
________________________________________________________________________________
System Location (show all protective devices on One Line Diagram):_________________________
Will the net metering facility interconnect to a switchgear?
Yes
No
Customer must post metal or plastic engraved signage indicating on-site generation in accordance with
the National Electric Code. The signage must be permanent and located adjacent to the meter base and
disconnect switch noting “Parallel Generation on Site” and identifying the manual disconnect switch
with the words “Manual Disconnect for Parallel Generation.” _____ (Initial Here)
One Line Diagram Attached:
Installation Test Plan attached:
Yes
Yes
No
Site Plan Attached:
Yes
No
No
Anticipated Operational Date of Net Metering Facilities: __________________________________
(Rocky Mountain Power must be notified at least ten (10) business days prior to starting operation.)
Net metering facility available fault duty at the point of common coupling:_____________________
(A Rocky Mountain Power Engineer may contact you for additional information)
Electrical Inspection approval date (attach copy or provide to utility when obtained):_____________
C. Application Fees
$
75.00
+ $ __________
$ __________
Base
$1.50 x ____ kW of Net Metering Facility’s capacity
TOTAL APPLICATION FEE
D. Additional Information
1.
An equipment package will be considered certified for interconnected operation if it has been
submitted by a manufacturer to a nationally recognized testing and certification laboratory, and
has been tested and listed by the laboratory for continuous interactive operation with an electric
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 21 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 43 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
2.
3.
4.
5.
6.
7.
distribution system in compliance with the applicable IEEE and UL 1741 standards, as set forth
in the Rule.
If the equipment package has been tested and listed as an integrated package, which includes a
generator or other electric source, the equipment package will be deemed certified, and Rocky
Mountain Power will not require any further design review, testing or additional information.
If the equipment package includes only the interface components (switchgears, inverters, or
other interface devices), an interconnection applicant must show that the generator or other
electric source being utilized with the equipment package is compatible with the equipment
package and consistent with the testing and listing specified for the package. If the generator or
electric source being utilized with the equipment package is consistent with the testing and
listing performed by the nationally recognized testing and certification laboratory, the
equipment package will be deemed certified and Rocky Mountain Power will not require
further design review, testing or additional equipment.
A net metering facility must be equipped with metering equipment that can measure the flow of
electricity in both directions, comply with ANSI C12.1 standards and Rule 746-312. Rocky
Mountain Power will install the required metering equipment at Rocky Mountain Power’s
expense.
Rocky Mountain Power will not be responsible for the cost of determining the rating of
equipment owned by the customer-generator or of equipment owned by other local customers.
Customer may operate the Net Metering Facility temporarily for testing and obtaining
inspection approval. Customer shall not operate the Net Metering Facility in continuous
parallel without an executed Interconnection and Net Metering Service Agreement, and
approval from Rocky Mountain Power.
Customer will pay to Rocky Mountain Power at the time of application the applicable
Application fee of $75.00 plus $1.50 per kilowatt of the net metering facility’s capacity.
Customer-generator will pay to Rocky Mountain Power all costs of minor modifications or
additional review as set forth in Rule 746-312 prior to commencement of work.
E. Customer Acknowledgment
I certify that the information provided in this Application is true. I will provide Rocky Mountain Power
a copy of the signed government electrical inspection approval document when obtained, if not already
provided with this Application.
I agree to abide by the terms of this Application and I agree to notify Rocky Mountain Power thirty (30)
days prior to modification or replacement of the System’s components or design. Any such
modification or replacement may require submission of a new Application to Rocky Mountain Power.
I agree not to operate the Net Metering Facility in parallel with Rocky Mountain Power, except
temporarily for testing and obtaining inspection approval, until this Application is approved by Rocky
Mountain Power, until this agreement is signed by both parties, and until I have provided Rocky
Mountain Power with at least five (5) days notice of anticipated start date.
Customer or Applicant Signature & Date: ____________________________________
Please send completed application to:
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 22 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 44 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
or
Please scan the completed application and email
[email protected]
Section 3. To be completed by System Installer
Installation Contractor Information/Hardware and Installation Compliance
Installation Contractor (Company Name): ______________________________________________________
Contractor's License No.: _______________________________ Proposed Installation Date: _____________
Mailing Address: _________________________________________________________________________
City: ______________________________________________ State: _________ Zip Code: _____________
Daytime Phone: ________________ Fax: _____________ Email: __________________________________
For inverter-controlled system, meets IEEE Standards and UL 1741 Inverters, Converters, and
Controllers for use in Independent Power Systems as set forth in the Rule:
Yes
No
For induction or synchronous device, meets IEEE Standard 1547 and IEEE/ANSI Standard C37.90
Yes
No
requirements as set forth in the Rule:
If Photovoltaic System, System must be installed in compliance with IEEE Standards, Recommended Practice
for Utility Interface of Photovoltaic Systems. All System types must be installed in compliance with applicable
requirements of local electrical codes, Rocky Mountain Power and the National Electrical Code® (NEC) and
must use an anti-islanding inverter.
The System must include a manual, lockable, load-break (disconnect) switch, unless exempt under Rule 746312-4(2), accessible at all times to Rocky Mountain Power personnel and located within 10 feet of Rocky
Mountain Power’s meter. The disconnect switch may be located more than 10 feet from Rocky Mountain
Power’s meter if permanent instructions are posted at the meter indicating the precise location of the disconnect
switch. Rocky Mountain Power must approve the location of the disconnect switch prior to the installation of
the net metering facility.
If the Net Metering Facility is designed to provide uninterruptible power to critical loads, either through energy
storage, back-up generator, or the generation source, the Net Metering Facility will include a parallel blocking
scheme for this backup source. This function may be integral to the inverter manufacturer’s packaged system.
Does the Net Metering Facility include a parallel blocking scheme:
Yes
No
Signed (Contractor): ______________________________________ Date: _____________
Name (Print): _______________________________________________
Section 4. To be completed by Rocky Mountain Power:
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 23 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 45 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
A.
If approving the application:
Rocky Mountain Power does not, by approval of this Application, assume any responsibility or liability
for damage to property or physical injury to persons. Further, this Application does not constitute a
dedication of the owner's System to Rocky Mountain Power electrical system equipment or facilities.
Customer entered into an Interconnection and Net Metering Service Agreement with Rocky Mountain
Power on the ____ day of _____, 20__.
Customer satisfactorily passed Witness Tests on the ___ day of ________, 20___
(Rocky Mountain Power may waive Witness Tests at its option; if tests are waived initial here ______).
This Application is approved by Rocky Mountain Power on this _____ day of ______________, 20__
Rocky Mountain Power Representative Name (Print): ______________________________________
Signed (Rocky Mountain Power Representative): __________________________ Date: ___________
B. If denying the application:
This application is denied by Rocky Mountain Power on this _____ day of ____________, 20__ for the
following reason(s):__________________________________________________________________
Rocky Mountain Power Representative Name (Print): ______________________________________
Signed (Rocky Mountain Power Representative): ________________________ Date:____________
Applicant may submit a new application for Level 3 review.
Section 5. To be completed by Rocky Mountain Power Meterman
Customer Account No. __________________________________ Site ID No.: _______________________
Served from Facility Point No.: ________________________________
New Net Meter No.: ____________________________ Date net meter installed: ______________________
Manual disconnect location and permanent signage in place unless system is less than 10 kW:
Yes
No
Signature/Title: _________________________________________ Date: ___________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 24 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 46 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
We appreciate your interest in Rocky Mountain Power’s net metering program. Before
purchasing any net metering equipment, we recommend you review the requirements for
interconnecting a net metering system to Rocky Mountain Power’s electrical distribution system.
The requirements are found in the Interconnection Agreement.
To complete the process for a net metering interconnection, please follow the steps below:
1. Complete and submit the following to Rocky Mountain Power:
 Interconnection Agreement including the Application for Net Metering
Interconnection
 The inverter specification sheet
 For systems larger than 10 kW, a simple one-line diagram showing
 The location of Rocky Mountain Power’s meter
 The location of the disconnect switch
2. Rocky Mountain Power will review your agreement and application and send you a
written notification of approval either by mail or e-mail
3. Install the net metering system after you receive the written approval of your
Interconnection Agreement and Application for Net Metering from Rocky Mountain
Power
4. Obtain an inspection of your net metering system by the local city or county electrical
inspector
5. Submit the electrical inspector’s approval to Rocky Mountain Power
6. Turn on your net metering system after Rocky Mountain Power provides you written
notification the interconnection work has been completed and the net meter installed
Return completed documents to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, Utah 84125-0308
Or Email to:
[email protected]
Thank you for your interest in the net metering program. If you have questions, please call us toll
free at 1-888-221-7070 and ask for a net metering specialist.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 1 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 47 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Service ID#:___________
Request #: ___________
INTERCONNECTION AND NET METERING SERVICE AGREEMENT FOR NET
METERING FACILITY
LEVEL 3 INTERCONNECTION
UP TO 2 MW NAMEPLATE CAPACITY
This Interconnection and Net Metering Service Agreement (“Agreement”) is made and
entered into this ____ day of _____________, 20___, by and between
____________________________, an electric customer (“Customer”), and PacifiCorp, dba
Rocky Mountain Power (“Rocky Mountain Power”), a Corporation organized and existing under
the laws of the State of Oregon. Customer and Rocky Mountain Power each may be referred to
as a “Party”, or collectively as the “Parties”.
Recitals:
Whereas, Customer has installed or intends to install a Net Metering Facility qualifying
for “Net Metering,” Utah Rate Schedule No. 135A (“Schedule 135A”), as given in Rocky
Mountain Power’s currently effective tariff as filed with the Public Service Commission of Utah
(“Commission”), on or adjacent to Customer’s premises located at
____________________________, Utah, for the purpose of generating electric energy;
Whereas, the Net Metering rate schedule may be amended from time to time, and the
Public Service Commission may alter the charge, credit, and ratemaking structure applicable to
Net Metering customers pursuant to Utah Code § 54-15-105.1;
Whereas, Customer represents to Rocky Mountain Power that Customer either owns or
leases its Net Metering Facility qualifying for Schedule 135A, or meets the exemption
requirements set forth in Utah Code § 54-2-1.16(d) because it is a county, municipality, city,
town, other political subdivision, local district, special service district, state institution of higher
education, school district, charter school, or any entity within the state system of public
education; or an entity qualifying as a charitable organization under 26 U.S.C. Sec. 501(c)(3)
operated for religious, charitable, or educational purposes that is exempt from federal income tax
and able to demonstrate its tax-exempt status;
Whereas, Customer desires to interconnect the Net Metering Facility with Rocky
Mountain Power’s distribution system consistent with the Application completed by Customer
on _____________ ____, 20___, as described in as described in Appendix C (“Application”) of
this Agreement; and
Whereas, Customer, using its Net Metering Facility, intends to offset part or all of its
electrical requirements supplied by Rocky Mountain Power.
Now, therefore, in consideration of and subject to the mutual covenants contained herein, the
Parties agree as follows:
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 2 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 48 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 1. Scope and Limitations of Agreement
1.1 Scope
The Agreement shall be used for all Level 3 Applications according to the procedures set
forth in Utah Administrative Rule R746-312, as may be amended from time to time
(“Rule”). The Rule can be viewed at www.psc.utah.gov. The Agreement establishes
standard terms and conditions approved by the Public Service Commission of Utah
(“Commission”) under which the Net Metering Facility with an Electric Nameplate
Capacity of 2 MW or smaller as described in Appendix C will interconnect to, and
operate in parallel with, Rocky Mountain Power’s system.
1.2 Definitions
Terms with initial capitalization, when used in this Agreement, shall have the meanings
indicated or as specified in the Rule Section R746-312-2 and, to the extent this
Agreement conflicts with the Rule, the Rule shall take precedence.
1.3 Other Agreements
Nothing in this Agreement is intended to affect any other agreement between Rocky
Mountain Power and Customer or any other Interconnection Customer. However, in the
event that the provisions of the Agreement are in conflict with the provisions of any
Rocky Mountain Power Tariff, as may be amended from time to time the Rocky
Mountain Power Tariff, as may be amended from time to time, shall control.
1.4 Responsibilities of the Parties
1.4.1 The Parties shall perform all obligations of the Agreement in accordance with all
applicable laws and regulations.
1.4.2 Customer will construct, own, operate, test, and maintain its Net Metering Facility
in accordance with the Agreement, IEEE Standards (available at the following
link: http://standards.ieee.org/index.html), National Electric Code Standards
(available for purchase at http://standards.ieee.org/faqs/NESCFAQ.html#q8), Utah
state building codes, the Rule (available at the following link:
http://www.dopl.utah.gov/programs/ubc/), and other applicable standards required
by the Commission, as may be amended from time to time.
1.4.3 Each Party shall be responsible for the safe installation, maintenance, repair and
condition of their respective lines and equipment on their respective sides of the
Point of Common Coupling. Each Party shall provide Interconnection Facilities
that adequately protect the other Party’s facilities, personnel and other persons
from damage and injury. The allocation of responsibility for the design,
installation, operation, maintenance and ownership of Interconnection Facilities is
prescribed in the Rule, including but not necessarily limited to R746-312-4.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 3 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 49 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.4.4
Customer is responsible for protecting the generating equipment, inverters,
protective devices, and other system components from damage from the normal
and abnormal conditions and operations that occur on Rocky Mountain Power’s
system in delivering and restoring power; and is responsible for ensuring that the
Net Metering Facility equipment is inspected, maintained, and tested in
accordance with the manufacturer’s instructions to ensure that it is operating
correctly and safely.
1.4.5 Customer shall obtain Rocky Mountain Power’s approval of the Application prior
to commencing parallel operation of its interconnected Net Metering Facility.
1.4.6 Customer is responsible for all costs associated with its Net Metering Facility.
1.5
Parallel Operation and Maintenance Obligations
Once the Net Metering Facility has been authorized to commence parallel operation by
an approved Application, and execution of this, Customer will abide by all written
provisions for operations and maintenance as required by the Rule and Rocky Mountain
Power’s tariffs, including but not necessarily limited to R746-312-4 and Schedule 135A
or its successor tariff(s).
1.6
Results of System Impact Study
Rocky Mountain Power completed a System Impact Study on_____________ ____,
20___. The System Impact Study shows the following minor modifications or substantial
modifications (Rocky Mountain Power to circle appropriate option) are necessary to
Customer’s Net Metering Facility prior to interconnecting with Rocky Mountain Power’s
system:
Description of necessary minor
modifications_____________________________________________________________
__________________________________________________________.
Rocky Mountain Power estimates, in good faith, that these minor modifications/
substantial modifications (Rocky Mountain Power to circle appropriate option) will cost
$__________. This is a non-binding estimate that will provide break down of
costs:___________________________________________________________________
___________________________________________________________ Customer shall
pay the actual installed cost of the minor modifications or substantial modifications
needed to interconnect the Net Metering Facility to Rocky Mountain Power’s system.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 4 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 50 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.7
Results of Interconnection Facilities Study << to be filled in upon completion of
Interconnection Facilities Study, if one is conducted. Otherwise, the text should read
“This Section intentionally left blank.”>>
Rocky Mountain Power completed a Facilities Study on _____________ ____, 20___.
The Facilities Study shows the following equipment, engineering, procurement and
construction work (including overheads) are necessary to implement the conclusion of
the System Impact Study for Customer’s Net Metering Facility to safely interconnect to
Rocky Mountain Power’s system and the time required to build and install those
facilities:
Rocky Mountain Power estimates, in good faith, that these modifications will cost
$______. This is a non-binding estimate for provide break down of
costs____________________________________________________________________
___________________________________________________________. Customer
shall pay the actual installed cost of the facilities needed to interconnect as identified in
the Facilities Study. Rocky Mountain Power estimates these facilities can be installed
by_____________ ____, 20___.
1.8
Metering
Rocky Mountain Power shall install, own and maintain, at its sole expense, a kilowatthour meter(s) and associated equipment to measure the flow of energy in each direction,
unless otherwise authorized by the Commission. Customer shall provide, at its sole
expense, adequate facilities, including, but not limited to, a current transformer enclosure
(if required), meter socket(s) and junction box, for the installation of the meter and
associated equipment.
Customer hereby consents to the installation and operation by Rocky Mountain Power
and at Rocky Mountain Power’s expense, of one or more additional meters to monitor the
flow of electricity in each direction. Such meters shall be located on the premises of
Customer.
1.9
Power Quality
Customer will design its Net Metering Facility to maintain a composite power delivery at
continuous rated power output at the Point of Common Coupling that meets the
requirements set forth in IEEE 1547, as required by the Rule, R746-312-4.
1.10
Net Metering Facility Inspection
1.10.1 Building Code Inspection
Prior to operation in parallel with Rocky Mountain Power’s system, the Net
Metering Facility must be inspected by a local building code official to ensure
compliance with applicable local codes.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 5 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 51 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.10.2 Inspection by Rocky Mountain Power
Rocky Mountain Power may inspect the Net Metering Facility and its component
equipment, and the documents necessary to ensure compliance with the Rule.
Customer shall notify Rocky Mountain Power prior to placing the Net Metering
Facility in service, and Rocky Mountain Power shall have the right to have
personnel present on the in-service date. If the Net Metering Facility is
subsequently modified in order to increase its gross power rating, Customer must
notify Rocky Mountain Power by submitting a new application specifying the
modifications in accordance with the level of review required for that application.
1.11
Anticipated Start Date
Customer must include an anticipated start date for operation of its Net Metering Facility
in the Application.
1.12
Net Metering Facility Testing and Maintenance
Customer shall conduct maintenance and testing as set forth in the Rule, including but not
necessarily limited to R746-312-14.
1.12.1 Customer shall conduct any manufacturer-recommended testing or maintenance at
its expense.
1.12.2 Customer shall conduct any post-installation testing, at its expense, necessary to
ensure compliance with IEEE standards as set forth in the Rule or to ensure
safety. This includes replacing a major equipment component that is different
from the originally installed model.
1.12.3 When Customer performs maintenance or testing in accordance with the Rule, it
must retain written records documenting the maintenance and results of the
testing for three (3) years.
1.13
1.12.4 Rocky Mountain Power shall have the right to inspect Customer’s Net Metering
Facility after interconnection approval is granted, at reasonable hours and with
reasonable prior notice to Customer. If Rocky Mountain Power discovers that the
Net Metering Facility is not in compliance with the Rule, Rocky Mountain Power
may require Customer to disconnect the Net Metering Facility until compliance is
achieved.
Removal of Facility
Customer shall immediately notify Rocky Mountain Power if Customer removes or
ceases to operate the Net Metering Facility.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 6 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 52 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 2.
2.1
Review, Inspection, Testing, Disconnect Switch and Signage, and Right of
Access
Review
After determining Customer’s interconnection request is complete, in accordance with
the Rule, R746-312-10, Rocky Mountain Power will conduct meetings and studies and
provide estimates set forth in the Rule, R746-312-10. Upon completion of the required
studies and receipt of agreement of the Customer to pay for required interconnection
facilities and upgrades, Rocky Mountain Power will approve the Interconnection request.
2.2
Equipment Testing and Inspection
Customer must notify Rocky Mountain Power of the anticipated testing and inspection
date of the Net Metering Facility at least ten (10) business days prior to testing, either
through submittal of the Agreement, a notice of completion, or in a separate notice.
Within ten (10) business days after receipt of such required documentation, Rocky
Mountain Power will conduct any required inspection or witness test of the Net Metering
Facility, set the new meter if required, approve the Interconnection, and provide written
notification to the Customer of the final interconnection authorization/approval and that
the generating facility is authorized/approved for parallel operation.
If Rocky Mountain Power and Customer, by mutual agreement, select a date for the
required inspection and/or witness testing which would prevent Rocky Mountain Power
from providing final written notice within ten (10) days of receipt of required
documentation as specified above, and if the Net Metering Facility satisfactorily passes
the required inspection and/or witness tests, Rocky Mountain Power shall notify
Customer within three (3) business days after the tests and/or inspections that either the
interconnection is approved and the Net Metering Facility may begin operation or the
interconnection facilities study identified necessary construction that has not been
completed, the date upon which the construction will be completed and the date when the
Net Metering Facility may begin operation or state any other reason why the
commissioning tests are not satisfactory.
If the witness tests are not satisfactory, Customer must resolve any deficiencies within
sixty (60) business days or other time period as mutually agreed by the Parties.
2.3
Disconnect Switch and Signage
Customer shall comply with the Rule regarding disconnect switches, R746-312-4. The
disconnect switch may be located more than 10 feet from the public utility meter if
permanent instructions in letters of appropriate size are posted at the meter indicating the
precise location of the disconnect switch. Rocky Mountain Power must approve in
writing the location of the disconnect switch prior to the installation of the Net Metering
Facility.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 7 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 53 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
2.4 Right of Access
As provided in the Rule, R746-312-4, Rocky Mountain Power shall have access to any
required disconnect switch at the Net Metering Facility at all times. Rocky Mountain
Power will provide reasonable notice to Customer when possible prior to using its right
of access. Additionally, as provided in Rocky Mountain Power Utah Rule 6, or its
successor tariff, Rocky Mountain Power shall have access to the metering equipment.
Article 3.
3.1
Effective Date, Term, Termination and Disconnection
Effective Date
The Agreement shall become effective upon execution by the Parties.
3.2
Term of Agreement
The Agreement will become effective on the Effective Date and will remain in effect
unless terminated in accordance with provisions of this Agreement, or Order by the
Commission.
3.3
Termination
No termination will become effective until the Parties have complied with all applicable
laws and clauses of this Agreement applicable to such termination.
3.3.1
Customer may terminate this Agreement at any time by giving Rocky Mountain
Power twenty (20) business days written notice.
3.3.2
Either Party may terminate this Agreement after default pursuant to Article 5.4 of
this Agreement.
3.3.3
The Commission may Order termination of this Agreement.
3.3.4
Upon termination of this Agreement, Customer shall disconnect the Net Metering
Facility from Rocky Mountain Power’s system. The termination of this
Agreement will not relieve either Party of its liabilities and obligations, owed or
continuing at the time of termination.
If Customer removes the Net Metering equipment at the Net Metering Facility or
ceases to operate its Net Metering Facility at the premise listed in the Application,
this Agreement will be immediately terminated.
3.3.5
3.3.6
The provisions of this Article shall survive termination or expiration of this
Agreement.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 8 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 54 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
3.4
Temporary Disconnection
3.4.1
Rocky Mountain Power may temporarily disconnect the Net Metering Facility
from Rocky Mountain Power’s system for so long as reasonably necessary
without prior notice to Customer in the event one or more of the following
conditions or events occurs:
3.4.1.1
Emergencies or to address maintenance requirements for Rocky
Mountain Power’s system.
3.4.1.2
Hazardous conditions existing on Rocky Mountain Power’s system
which may affect the safety of the general public or Rocky Mountain
Power employees due to the operation of the Net Metering Facility or
protective equipment as determined by Rocky Mountain Power.
3.4.1.3
Adverse electrical effects on the electrical equipment of Rocky
Mountain Power’s other electric customers caused by the Net Metering
Facility as determined by Rocky Mountain Power.
3.4.2
In the event that no disconnect switch is installed, Rocky Mountain Power may
physically disconnect all service to the Customer or all service to the premises
where the Net Metering Facility is located, or both.
3.4.3
To the extent practicable, Rocky Mountain Power will give prior notice of any
temporary disconnection of the Net Metering Facility. If Rocky Mountain Power
is unable to give prior notice, Rocky Mountain Power will provide notice
including an explanation of the condition necessitating the disconnection at the
time of disconnection.
3.4.4
Under emergency conditions, Rocky Mountain Power shall notify Customer
promptly when Rocky Mountain Power becomes aware of an emergency
condition that may reasonably be expected to affect the Net Metering operation.
Customer shall notify Rocky Mountain Power promptly when it becomes aware
of an emergency condition that may reasonably be expected to affect Rocky
Mountain Power’s system. To the extent the information is known, the
notification shall describe the emergency condition, the extent of any damage or
deficiency, the expected effect on the operation of both Parties’ facilities and
operations, the anticipated duration, and the necessary corrective action.
3.4.5
Customer shall make reasonable efforts to provide notice of interruption of Net
Metering Facility operation for safety and/or reliability reasons prior to the
interruption unless an emergency occurs. Emergency interruptions or temporary
terminations are subject to Section 3.4.4 above.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 9 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 55 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
3.4.6
Rocky Mountain Power shall use reasonable efforts to provide Customer with
prior notice of forced outages to effect immediate repairs to Rocky Mountain
Power’s system. If prior notice is not given, Rocky Mountain Power, shall, upon
request, provide Customer written documentation after the fact explaining the
circumstances of the disconnection.
3.4.7
Customer must provide Rocky Mountain Power notice and obtain Rocky
Mountain Power’s written approval before Customer may modify its Net
Metering Facility in order to increase the electric output of the Net Metering
Facility. If Customer makes any material change without prior written
authorization of Rocky Mountain Power, Rocky Mountain Power will have the
right to temporarily disconnect the Net Metering Facility until Rocky Mountain
Power has had an opportunity to review the change(s) made to determine whether
they are acceptable. If any system modifications or other equipment installations
are deemed necessary by Rocky Mountain Power to accommodate the modified
Net Metering Facility, Customer shall submit the appropriate net metering
application at that time.
3.4.8
The Parties shall cooperate with each other to restore the Net Metering Facility,
Interconnection Facilities, and Rocky Mountain Power’s system to their normal
operating state as soon as reasonably practicable following any disconnection
pursuant to this section.
Article 4.
4.1
Cost Responsibility
Application Fee
Customer shall bear the cost of any Application fee provided for in the Rule, R746-31213(2), or as otherwise approved by the Commission. Customer shall remit payment with
the Application as calculated in Appendix C, the Application, Section 2.C.
4.2
Net Metering Facility and Interconnection Equipment
Customer shall be responsible for all costs, including overheads, associated with
procuring, installing, owning, operating, maintaining, repairing, and replacing its Net
Metering Facility, any associated equipment package, and any associated interconnection
equipment or interconnection facilities required to be installed on Customer’s side of the
Point of Common Coupling as detailed in the results of the System Impact Study or
Facilities Study, or both.
4.3
Minor Modifications
This section shall apply if the System Impact Study performed pursuant to Section 1.6
above shows that minor modifications to the electric distribution system are required to
enable the interconnection to be made consistent with safety, reliability and power quality
standards applicable to Level 3 interconnection reviews. The Customer shall pay for the
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 10 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 56 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
cost to procure, install, and construct, operate, maintain, repair and replace any such
minor modifications. A description of the minor modifications may be found in Appendix
A. The cost of the minor modifications as described on Appendix A shall be $_______.
Customer shall remit payment for minor modifications prior to Rocky Mountain Power
commencing the work required for the minor modifications.
4.4
4.5
Substantial Modifications
4.4.1
This section shall apply if the System Impact Study performed pursuant to Section
1.6 above or the Facilities Study performed pursuant to Section 1.7 above, or
both, shows that substantial modifications to the electric distribution system are
required to enable the interconnection to be made consistent with safety,
reliability and power quality standards applicable to Level 3 interconnection
reviews. The Customer shall pay for the cost to procure, install, and construct,
operate, maintain, repair and replace any such substantial modifications. A
description of the substantial modifications may be found in Appendix B. The
cost of the substantial modifications as described on Appendix B shall be
$_______.
4.4.2
Before beginning substantial modifications to accommodate the interconnection
of the Net Metering Facility to Rocky Mountain Power’s system, Rocky
Mountain Power may require that Customer pay a deposit of not more than 50%
of the estimated cost of procuring, installing and constructing equipment and
facilities to be procured, installed or constructed by Rocky Mountain Power.
Payment
Rocky Mountain Power may require progress payments from Customer or Rocky
Mountain Power may wait until construction and installation of all equipment and
facilities are complete and the total actual cost of such equipment and facilities has been
established and then provide Customer with a statement indicating whether actual cost
was more or less than the deposit paid by Customer-Generator. If actual costs exceed the
deposit, Rocky Mountain Power will invoice Customer-Generator for the balance and
Customer-Generator shall pay any such invoice within 30 days of receipt. If actual costs
are less than the deposit, Rocky Mountain Power will refund the difference to CustomerGenerator.
Article 5.
5.1
Billing
Monthly Billing
The electric service charge shall be computed in accordance with the monthly billing in
the currently applicable standard service tariff. Customer will be compensated for net
excess energy in accordance with Schedule 135A or its successor tariff(s). Customer will
be transitioned to any successor tariff immediately upon approval of that tariff by the
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 11 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 57 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Public Service Commission and will be subject to any charge, credit, or ratemaking
structure implemented therein.
5.2
Special Conditions
Customer must comply with the special conditions found in Schedule 135A or its
successor tariff(s).
5.3
Aggregating Meters
Aggregating Meters is allowed if certain conditions are met under the Rule, R746-312-5.
Customer designates the following meters for aggregation: _______________________.
In the event that the Net Metering Facility supplies more electricity to Rocky Mountain
Power than the Customer uses from Rocky Mountain Power, Rocky Mountain Power will
apply any credits to the next monthly bill in accordance with Utah Code § 54-15-104 and
the Rule, R746-312-15. Customer shall designate the order in which to apply any credits
in accordance with the Rule. <<If customer does not want to aggregate, insert “N\A” in
the gray box.>>
Article 6.
6.1
Assignment, Liability, Indemnity, Force Majeure, Consequential Damages
and Default
Assignment
This Agreement may be assigned by either Party with the consent of the other Party. A
Party’s consent to an assignment may not be unreasonably withheld. The assigning Party
must give the non-assigning Party written notice of the assignment at least fifteen days
(15) before the effective date of the assignment. The non-assigning Party must submit its
objection to the assignment, if any, to the assigning Party in writing at least 5 business
days before the effective date of the assignment. If a written objection is not received
within that time period, the non-assigning party is deemed to consent to the assignment.
6.1.1 Exceptions to the Consent Requirement
6.1.1.1 Either Party may assign the Agreement without the consent of the other
Party to any affiliate (including a merger or acquisition of the Party with
another entity), of the assigning Party with an equal or greater credit rating
and with the legal authority and operational ability to satisfy the
obligations of the assigning Party under this Agreement.
6.1.1.2 Customer-Generator is entitled to assign the Agreement, without the
consent of Rocky Mountain Power, for collateral security purposes to aid
in obtaining financing for the Net Metering Facility.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 12 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 58 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
6.1.1.3 For Net Metering systems that are integrated into a building facility, the
sale of the building or property will result in the automatic assignment of
this Agreement to the new owner who will be responsible for complying
with the terms and conditions of this Agreement.
6.1.2
6.2
Any attempted assignment that violates this Article is void and ineffective.
Assignment does not change or eliminate a Party’s obligations under this
Agreement. An assignee is responsible for meeting the same obligations as the
assigning Party.
Limitation of Liability and Consequential Damages
Each Party’s liability to the other Party for any loss, cost, claim, injury, liability, or
expense, including reasonable attorney’s fees, relating to or arising from any act or
omission in its performance of this Agreement, is limited to the amount of direct damage
actually incurred. Neither Party is liable to the other Party for any indirect, special,
consequential, or punitive damages.
6.3
Indemnification
Customer shall hold harmless and indemnify Rocky Mountain Power for all loss to third
parties resulting from the operation of the Net Metering Facility, except when the loss
occurs due to the negligent actions of Rocky Mountain Power.
Rocky Mountain Power shall hold harmless and indemnify Customer for all loss to third
parties resulting from the operation of Rocky Mountain Power’s system, except where
the loss occurs due to the negligent actions of Customer.
6.4 Force Majeure
6.4.1
As used in this Agreement, a Force Majeure Event shall mean “any act of God,
labor disturbance, act of the public enemy, war, acts of terrorism, insurrection,
riot, fire, storm or flood, explosion, breakage or accident to machinery or
equipment through no direct, indirect, or contributory act of a Party, any order,
regulation, or restriction imposed by governmental, military or lawfully
established civilian authorities, or any other cause beyond a Party’s control. A
Force Majeure Event does not include an act of negligence or wrongdoing.”
6.4.2
If a Force Majeure Event prevents a Party from fulfilling any obligations under
this Agreement, the Party affected by the Force Majeure Event (“Affected Party”)
shall promptly notify the other Party of the existence of the Force Majeure Event.
The notification must specify in reasonable detail the circumstances of the Force
Majeure Event, the expected duration, and the steps that the Affected Party is
taking to mitigate the effects of the event on its performance, and if the initial
notification was verbal, it should be promptly followed up with a written
notification. The Affected Party shall keep the other Party informed on a
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 13 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 59 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
continuing basis of developments relating to the Force Majeure Event until the
event ends. The Affected Party will be entitled to suspend or modify its
performance of obligations under this Agreement (other than the obligation to
make payments) only to the extent that the effect of the Force Majeure Event
cannot be reasonably mitigated. The Affected Party will use reasonable efforts to
resume its performance as soon as possible. The Parties shall immediately report
to the Commission should a Force Majeure Event prevent performance of an
action required by Rule that the Rule does not permit the Parties to mutually
waive.
6.5
Default
6.5.1
A Party is in default if the Party fails to perform an obligation required under this
Agreement (other than the payment of money). A Party is not considered in
default of this agreement if the failure to perform an obligation is caused by an act
or omission of the other Party or is the result of a Force Majeure as defined in this
Agreement.
6.5.2
Upon a default, the non-defaulting Party must give written notice of the default to
the defaulting party. The defaulting party has sixty (60) calendar days from the
receipt of the written default notice to cure the default. If the default is not capable
of cure within the 60-day period, the defaulting Party must begin to cure the
default within twenty (20) calendar days after receipt of the written default notice,
and must continuously and diligently complete the cure within six (6) months of
the receipt of the notice.
6.5.3
If a default is not cured as provided for in 6.5.2, then the non-defaulting Party is
entitled to terminate the Agreement by written notice at any time until cure
occurs. If the non-defaulting Party chooses to terminate this Agreement, the
termination provisions in Article 3.3 apply. Alternately, the non-defaulting Party
is entitled to seek dispute resolution with the Commission in lieu of termination.
Article 7.
Insurance
Additional liability insurance is not required as a part of the Agreement if the Net Metering
Facility is in compliance with the provisions of the Application approval, the Agreement and the
standards contained in Utah Code § 54-15-106.
Article 8.
Dispute Resolution
8.1
Nothing in this Article shall restrict the rights of any Party to file a Complaint with the
Commission under relevant provisions of the Rule and applicable state law.
8.2
Pursuit of dispute resolution may not affect Customer with regard to consideration of an
Interconnection Request or Customer’s queue position.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 14 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 60 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 9.
9.1
Miscellaneous
Governing Law, Regulatory Authority and Rules
The validity, interpretation, and enforcement of this Agreement is governed by the laws
of the State of Utah. If any provision of this Agreement conflicts with any applicable
provision, as may be amended from time to time, of the Utah Code (“Code”), Utah
Administrative Rules (“Rules”), or Rocky Mountain Power’s Tariffs (“Tariff”), then the
applicable provision of the Code, Rules, or Tariff controls. Rocky Mountain Power must
provide copies of the applicable provisions of the Code, Rules, and Tariff upon the
Customer’s request.
9.2
Amendment
Additions, deletions or changes to the standard terms and conditions of this Agreement
will not be permitted unless they are mutually agreed to by the Parties and permitted by
the Rule or permitted by the Commission for good cause shown. The Parties may amend
the Agreement by a written instrument duly executed by both Parties in accordance with
the provisions of the Rule and applicable Commission Orders and provisions of the laws
of the State of Utah.
9.3
No Third Party Beneficiaries
The Agreement is not intended to and does not create rights, remedies, or benefits of any
character whatsoever in favor of any persons, corporations, associations, or entities other
than the Parties, and the obligations herein assumed are solely for the use and benefit of
the Parties, or where permitted, their successors in interest or their assigns.
9.4
Waiver
9.4.1 The failure of a Party to the Agreement to insist, on any occasion, upon strict
performance of any provision of the Agreement, will not be considered a waiver
of any obligation, right, or duty of, or imposed upon, such Party.
9.4.2
The Parties may agree to mutually waive a Section of this Agreement without the
Commission’s approval in accordance with the Rule.
9.4.3
Any waiver at any time by either Party of its rights with respect to the Agreement
shall not be deemed a continuing waiver or a wavier with respect to any other
failure to comply with any other obligation, right, or duty of the Agreement.
Termination or default of this Agreement for any reason by Customer shall not
constitute a waiver of the Customer’s legal rights to obtain interconnection from
Rocky Mountain Power. Any request for waiver of the Agreement or any
provisions thereof shall be provided in writing.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 15 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 61 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
9.5
Entire Agreement
The Agreement, including any supplementary attachments that may be necessary,
constitutes the entire Agreement between the Parties with reference to the subject matter
hereof, and supersedes all prior and contemporaneous understandings or agreements, oral
or written, between the Parties with respect to the subject matter of the Agreement. There
are no other agreements, representations, warranties, or covenants that constitute any part
of the consideration for, or any condition to, either Party’s compliance with its
obligations under the Agreement.
9.6
Multiple Counterparts
This Agreement may be executed in one or more counterparts, whether electronically or
otherwise, each of which is deemed an original but all constitute one and the same
instrument.
9.7
No Partnership
The Agreement will not be interpreted or construed to create an association, joint venture,
agency relationship, or partnership between the Parties or to impose any partnership
obligation or partnership liability upon either Party. Neither Party shall have any right,
power or authority to enter into any agreement or undertaking for, or act on behalf of, or
to act as or be an agent or representative of, or to otherwise bind, the other Party.
9.8
Severability
If any provision or portion of the Agreement shall for any reason be held or adjudged to
be invalid or illegal or unenforceable by any court of competent jurisdiction or other
governmental authority, (1) such portion or provision shall be deemed separate and
independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable
the benefits to each Party that were affected by such ruling, and (3) the remainder of the
Agreement shall remain in full force and effect.
9.9
Subcontractors
Nothing in the Agreement shall prevent a Party from using the services of any
subcontractor, or designating a third party agent as one responsible for a specific
obligation or act required in the Agreement (collectively subcontractors), as it deems
appropriate to perform its obligations under the Agreement; provided, however, that each
Party will require its subcontractors to comply with all applicable terms and conditions of
the Agreement in providing such services and each Party will remain primarily liable to
the other Party for the performance of the subcontractor.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 16 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 62 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
9.10
9.9.1
The creation of any subcontract relationship shall not relieve the hiring Party of
any of its obligations under the Agreement. The hiring Party shall be fully
responsible to the other Party for the acts or omissions of any subcontractor the
hiring Party hires as if no subcontract had been made. Any applicable obligation
imposed by the Agreement upon the hiring Party shall be equally binding upon,
and will be construed as having application to, any subcontractor of such Party.
9.9.2
The obligations under this Article will not be limited in any way by any limitation
of a subcontractor’s insurance.
Reservation of Rights
Rocky Mountain Power shall have the right to make a unilateral filing with the
Commission to modify this Agreement with respect to any rates, terms and conditions,
charges, classifications of service, rule, regulation or any other applicable provision of
the Federal Power Act and the Commission’s rules and regulations thereunder, and
Customer shall have the right to make a unilateral filing with Commission to modify this
Agreement under any applicable provision of the Federal Power Act and the
Commission’s rules and regulations; provided that each Party shall have the right to
protest any such filing by the other Party and to participate fully in any proceeding before
the Commission in which such modifications may be considered. Nothing in this
Agreement shall limit the rights of the Parties, except to the extent that the Parties
otherwise agree as provided herein.
Article 10.
10.1
Notices and Records
General
Unless otherwise provided in the Agreement, any written notice, demand, or request
required or authorized in connection with the Agreement shall be deemed properly given
if delivered in person, delivered by recognized national courier service, sent by first class
mail, postage prepaid, or by electronic mail if an electronic mail address is provided
below to the person specified below:
If to Customer:
Customer: ______________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: ________________________________ State: _________________ Zip: ________
Phone: (___) _______________________ Fax: (____) ___________________________
Email: __________________________________________________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 17 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 63 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If to Rocky Mountain Power:
By Mail:
Rocky Mountain Power
Attention: Net Metering Group
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
Or
By email:
[email protected]
10.2
Records
Rocky Mountain Power will maintain a record of all Interconnection Agreements and
related Attachments, if any, for as long as the interconnection is in place. Rocky
Mountain Power will provide a copy of these records to Customer within fifteen (15)
Business Days upon written request.
10.3
Billing and Payment
Billings and payments shall be sent to the addresses below (complete if different from
Section 9.1 above):
If to Customer:
Customer: ______________________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: _______________________________ State: _______________ Zip: ___________
10.4
Designated Operating Representative
The Parties will designate an operating representative each to conduct the
communications that may be necessary or convenient for the administration of the
operations provisions of the Agreement. This person will also serve as the point of
contact with respect to operations and maintenance of the Party’s facilities (complete if
different from Section 9.1 above):
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 18 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 64 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Customer’s Operating Representative:
Name: __________________________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: ______________________________ State: ________________ Zip: ___________
Phone: (____) _______________________ Fax: (____) __________________________
Email: __________________________________________________________________
10.5
Changes to the Notice Information
Either Party may change this notice information by giving five (5) business days written
notice prior to the effective date of the change.
Article 11.
Signatures
IN WITNESSETH WHEREOF, the Parties have caused the Agreement to be executed by their
respective duly authorized representatives.
For the Customer:
For Rocky Mountain Power:
By: _____________________________
By: _____________________________
Name: ___________________________
Name: ___________________________
Title: ____________________________
Title: ____________________________
Date: ____________________________
Date: ____________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 19 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 65 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Appendix A
Minor Modifications
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 20 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 66 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Appendix B
Substantial Modifications
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 21 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 67 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
APPENDIX C
ROCKY MOUNTAIN POWER UTAH NET METERING APPLICATION
LEVEL 3 REVIEW
CAPACITY OF 2 MW OR LESS
Section 1: For Rocky Mountain Power Use Only
Customer Name: _________________________________________________________________________
Service Address: _________________________________________________________________________
City, State, Zip: ___________________________________________________________________________
Customer Account No. and Request No.: _______________________________________________________
Interconnection Agreement Acknowledgement (Date): ____________________________________________
Application fee: $______________________________ Date Paid ___________________________________
Section 2: To Be Completed By Customer
A. Applicant Information
Name: ___________________________________________________________________________
Mailing Address: __________________________________________________________________
City: __________________________________________State: _________ Zip Code: ____________
Site Street Address (if different from above): _____________________________________________
City: __________________________________________State: __________ Zip Code: ___________
Daytime Phone: (_____) ________________________ Fax: (_____) __________________________
Email: ____________________________________________________________________________
B. System Information
System Type:
Solar
Wind
Hydro
Other (Specify): _________________________
Generation Nameplate Capacity: ______________ kW (Combine DC total of wind turbines, solar
panels, etc. or AC rating if an inverter is not utilized)
Inverter Manufacturer: ___________ Model: ________ Number of Inverters: _____ Rating: _____ kW
Manufacturer Nameplate Inverter Total AC Capacity Rating: _________ kW
Inverter(s):
Single Phase
Three Phase
Multiple Single Phase Connected on Poly-phase
(three phase) system – (Attach Inverter and Panel Technical Specifications Sheets)
Type:
Induction
Type of Service:
Inverter
Single Phase
Synchronous
__________________Other
Three Phase
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 22 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 68 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If Three Phase Transformer:
Indicate Type:
Wye
Delta
Indicate Voltage and Number of Service Wires:
120/208 Volts, 4 wire 120/240 Volts, 4 wire 277/480 Volts, 4 wire
Other ___________
________________________________________________________________________________
Other Information:__________________________________________________________________
_________________________________________________________________________________
Self Contained Location: ____________________________________________________________
Outdoor Manual AC Disconnect Switch Location (show Disconnect Switch and Rocky Mountain
Power Meter Location on Site Plan), unless exempt under Utah Administrative Rule 746-312-4(2):
__________________________________________________________________________________
System Location (show all protective devices on One Line Diagram):___________________________
Will the net metering facility interconnect to a switchgear?
Yes
No
Customer must post metal or plastic engraved signage indicating on-site generation in accordance with
National Electric Code. The signage must be permanent and located adjacent to the meter base and
disconnect switch noting “Parallel Generation on Site” and identifying the manual disconnect switch
with the words “Manual Disconnect for Parallel Generation.” _____ (Initial Here)
One Line Diagram Attached:
Installation Test Plan attached:
Yes
Yes
No
Site Plan Attached:
Yes
No
No
Anticipated Operational Date of Net Metering Facilities: _____________________________________
(Rocky Mountain Power must be notified at least ten (10) business days prior to starting operation.)
Net metering facility available fault duty at the point of common coupling: ________________
(A Rocky Mountain Power Engineer may contact you for additional information)
Electrical Inspection approval date (attach copy or provide to utility when obtained):__________
C. Application Fees
$ 150.00 Base
+ $ __________
$ __________
$3.00 x _____ kW of net metering facility’s capacity
TOTAL APPLICATION FEE
D. Additional Information
1.
An equipment package will be considered certified for interconnected operation if it has been
submitted by a manufacturer to a nationally recognized testing and certification laboratory, and
has been tested and listed by the laboratory for continuous interactive operation with an electric
distribution system in compliance with the applicable IEEE and UL 1741 standards, as set forth
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 23 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 69 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
2.
3.
4.
5.
6.
7.
in the Rule.
If the equipment package has been tested and listed as an integrated package, which includes a
generator or other electric source, the equipment package will be deemed certified, and Rocky
Mountain Power will not require any further design review, testing or additional information.
If the equipment package includes only the interface components (switchgears, inverters, or
other interface devices), an interconnection applicant must show that the generator or other
electric source being utilized with the equipment package is compatible with the equipment
package and consistent with the testing and listing specified for the package. If the generator or
electric source being utilized with the equipment package is consistent with the testing and
listing performed by the nationally recognized testing and certification laboratory, the equipment
package will be deemed certified and Rocky Mountain Power will not require further design
review, testing or additional equipment.
A net metering facility must be equipped with metering equipment that can measure the flow of
electricity in both directions, comply with ANSI C12.1 standards and Utah Administrative Rule
R746-312. Rocky Mountain Power will install the required metering equipment at Rocky
Mountain Power’s expense.
Rocky Mountain Power will not be responsible for the cost of determining the rating of
equipment owned by the customer-generator or of equipment owned by other local customers.
Customer may operate the Net Metering Facility temporarily for testing and obtaining inspection
approval. Customer shall not operate the Net Metering Facility in continuous parallel without an
executed Interconnection and Net Metering Service Agreement, and approval from Rocky
Mountain Power.
Customer will pay to Rocky Mountain Power at the time of application the applicable
Application fee of $150.00 plus $3.00 per kilowatt of the net metering facility’s capacity; and
costs of modifications or additional review as set forth in Utah Administrative Rule R746-312
prior to commencement of work.
E. Customer Acknowledgment
I certify that the information provided in this Application is true. I will provide Rocky Mountain Power a
copy of the signed government electrical inspection approval document when obtained, if not already
provided with this Application.
I agree to abide by the terms of this Application and I agree to notify Rocky Mountain Power thirty (30)
days prior to modification or replacement of the System’s components or design. Any such modification
or replacement may require submission of a new Application to Rocky Mountain Power.
I agree not to operate the Net Metering Facility in parallel with Rocky Mountain Power, except
temporarily for testing and obtaining inspection approval, until this Application is approved by Rocky
Mountain Power, until this agreement is signed by both parties, and until I have provided Rocky
Mountain Power with at least five (5) days notice of anticipated start date.
Customer or Applicant Signature & Date: ____________________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 24 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 70 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Please send completed application to:
Rocky Mountain Power
Attention: Customer Generation
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
or
Please scan the completed application and email
[email protected]
Section 3. To be completed by System Installer
Installation Contractor Information/Hardware and Installation Compliance
Installation Contractor (Company Name): _______________________________________________________
Contractor's License No.: ____________________________ Proposed Installation Date: _________________
Mailing Address: __________________________________________________________________________
City: ____________________________________________ State: __________ Zip Code: _______________
Daytime Phone: _________________ Fax: _________________Email: ______________________________
For inverter-controlled system, meets IEEE Standards and UL 1741 Inverters, Converters, and
Controllers for use in Independent Power Systems as set forth in the Rule:
Yes
No
For induction or synchronous device, meets IEEE Standard 1547 and IEEE/ANSI Standard C37.90 requirements
as set forth in the Rule:
Yes
No
If Photovoltaic System, System must be installed in compliance with IEEE Standards, Recommended Practice
for Utility Interface of Photovoltaic Systems. All System types must be installed in compliance with applicable
requirements of local electrical codes, Rocky Mountain Power and the National Electrical Code® (NEC) and
must use an anti-islanding inverter.
The System must include a manual, lockable, load-break (disconnect) switch, unless exempt under Utah
Administrative Rule 746-312-4(2), accessible at all times to Rocky Mountain Power personnel and located
within 10 feet of Rocky Mountain Power’s meter. The disconnect switch may be located more than 10 feet from
Rocky Mountain Power’s meter if permanent instructions are posted at the meter indicating the precise location
of the disconnect switch. Rocky Mountain Power must approve the location of the disconnect switch prior to the
installation of the net metering facility.
If the Net Metering Facility is designed to provide uninterruptible power to critical loads, either through energy
storage, back-up generator, or the generation source, the Net Metering Facility will include a parallel blocking
scheme for this backup source. This function may be integral to the inverter manufacturer’s packaged system.
Does the Net Metering Facility include a parallel blocking scheme:
Yes
No
Signed (Contractor): ________________________________________ Date: _________________
Name (Print): _______________________________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 25 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 71 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Section 4. To be completed by Rocky Mountain Power:
A. If approving the application:
Rocky Mountain Power does not, by approval of this Application, assume any responsibility or liability
for
damage to property or physical injury to persons. Further, this Application does not constitute a
dedication of the owner's System to Rocky Mountain Power electrical system equipment or facilities.
Customer-Generator entered into an Interconnection and Net Metering Service Agreement with Rocky
Mountain Power on the ____ day of _____, 20__.
Customer-Generator satisfactorily passed Witness Tests on the ____ day of _________, 20__.
(Rocky Mountain Power may waive Witness Tests at its option; if tests are waived initial here ____)
This Application is approved by Rocky Mountain Power on this ______ day of ______________, 20__
Rocky Mountain Power Representative Name (Print): _______________________________________
Signed (Rocky Mountain Power Representative): ________________________ Date: ____________
B. If denying the application:
This application is denied by Rocky Mountain Power on this ______ day of ____________, 20__ for
the following reason(s): _______________________________________________________________
Rocky Mountain Power Representative Name (Print): _______________________________________
Signed (Rocky Mountain Power Representative): ___________________________ Date: __________
Section 5. To be completed by Rocky Mountain Power Meterman
Customer Account No. ______________________________ Site ID No. : ___________________________
Served from Facility Point No.: ________________________________
New Net Meter No.: ___________________________ Date net meter installed: _______________________
Manual disconnect device in proper location and permanent signage in place:
Yes
No
Signature/Title: ________________________________________ Date: ____________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 26 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 72 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
We appreciate your interest in Rocky Mountain Power’s net metering program. Before
purchasing any net metering equipment, we recommend you review the requirements for
interconnecting a net metering system to Rocky Mountain Power’s electrical distribution
system. The requirements are found in the Interconnection Agreement.
To complete the process for a net metering interconnection, please follow the steps below:
1. Complete and submit the following to Rocky Mountain Power:
 Interconnection Agreement including the Application for Net Metering
Interconnection
 The inverter specification sheet
 For systems larger than 10 kW, a simple one-line diagram showing
 The location of Rocky Mountain Power’s meter
 The location of the disconnect switch
2. Rocky Mountain Power will review your agreement and application and send you a
written notification of approval either by mail or e-mail
3. Install the net metering system after you receive the written approval of your
Interconnection Agreement and Application for Net Metering from Rocky Mountain
Power
4. Obtain an inspection of your net metering system by the local city or county electrical
inspector
5. Submit the electrical inspector’s approval to Rocky Mountain Power
6. Turn on your net metering system after Rocky Mountain Power provides you written
notification the interconnection work has been completed and the net meter installed
Return completed documents to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, Utah 84125-0308
Or Email to:
[email protected]
Thank you for your interest in the net metering program. If you have questions, please call us
toll free at 1-888-221-7070 and ask for a net metering specialist.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 1 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 73 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Service ID#:___________
Request #: ___________
INTERCONNECTION AND NET METERING SERVICE AGREEMENT FOR NET
METERING FACILITY LEVEL 1 INTERCONNECTION
25 KW NAMEPLATE CAPACITY OR SMALLER
This Interconnection and Net Metering Service Agreement (“Agreement”) is made and
entered into this ___ day of _____________, 20___ by and between
____________________________, an electric customer (“Customer”), and PacifiCorp, dba
Rocky Mountain Power (“Rocky Mountain Power”), a Corporation organized and existing
under the laws of the State of Oregon. Customer and Rocky Mountain Power each may be
referred to as a “Party”, or collectively as the “Parties”.
Recitals:
Whereas, Customer has installed or intends to install a Net Metering Facility qualifying
for “Net Metering,” Utah Rate Schedule No. 135A (“Schedule 135A”), as given in Rocky
Mountain Power’s currently effective tariff as filed with the Public Service Commission of
Utah (“Commission”), on or adjacent to Customer’s premises located at
____________________________, Utah, for the purpose of generating electric energy;
Whereas, the Net Metering rate schedule may be amended from time to time, and the
Public Service Commission may alter the charge, credit, and ratemaking structure applicable to
Net Metering customers pursuant to Utah Code § 54-15-105.1;
Whereas, Customer represents to Rocky Mountain Power that Customer either owns or
leases its Net Metering Facility qualifying for Schedule 135A, or meets the exemption
requirements set forth in Utah Code § 54-2-1.16(d) because it is a county, municipality, city,
town, other political subdivision, local district, special service district, state institution of higher
education, school district, charter school, or any entity within the state system of public
education; or an entity qualifying as a charitable organization under 26 U.S.C. Sec. 501(c)(3)
operated for religious, charitable, or educational purposes that is exempt from federal income
tax and able to demonstrate its tax-exempt status;
Whereas, Customer desires to interconnect the Net Metering Facility with Rocky
Mountain Power’s distribution system consistent with the Application completed by on
_____________ ____, 20___,Customer as described in Appendix A (“Application”) of this
Agreement; and
Whereas, Customer, using its Net Metering Facility, intends to offset part or all of its
electrical requirements supplied by Rocky Mountain Power.
Now, therefore, in consideration of and subject to the mutual covenants contained
herein, the Parties agree as follows:
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 2 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 74 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 1.
Scope and Limitations of Agreement
1.1
Scope
The Agreement shall be used for all approved Level 1 Applications according to the
procedures set forth in Utah Rule 746-312 (“Rule”), as may be amended from time to
time. The Rule can be viewed at www.psc.utah.gov. The Agreement establishes
standard terms and conditions approved by the Commission under which a Level 1 Net
Metering Facility as described in Appendix A with an electric nameplate capacity of 25
kW or smaller will interconnect to, and operate in parallel with, Rocky Mountain
Power’s system.
1.2
Definitions
Terms with initial capitalization, when used in this Agreement, shall have the meanings
indicated or as specified in the Rule Section R746-312-2 and, to the extent this
Agreement conflicts with the Rule, the Rule shall take precedence.
1.3
Other Agreements
Nothing in this Agreement is intended to affect any other agreement between Rocky
Mountain Power and Customer or any other Interconnection Customer. However, in the
event that the provisions of the Agreement are in conflict with the provisions of any
Rocky Mountain Power Tariff, the Rocky Mountain Power Tariff shall control.
1.4
Responsibilities of the Parties
1.4.1
The Parties shall perform all obligations of the Agreement in accordance with all
applicable laws and regulations.
1.4.2
Customer will construct, operate, test, and maintain its Net Metering Facility in
accordance with the Agreement, IEEE standards (available at the following link:
http://standards.ieee.org/index.html), National Electric Code Standards
(available for purchase at http://standards.ieee.org/faqs/NESCFAQ.html#q8),
Utah state building codes (available at the following link:
http://www.dopl.utah.gov/programs/ubc/), the Rule, and other applicable
standards required by the Commission, as may be amended from time to time.
1.4.3
Each Party shall be responsible for the safe installation, maintenance, repair and
condition of their respective lines and equipment on their respective sides of the
Point of Common Coupling. Each Party shall provide interconnection facilities
that adequately protect the other Party’s facilities, personnel and other persons
from damage and injury. The allocation of responsibility for the design,
installation, operation and maintenance of interconnection facilities is prescribed
in the Rule, including but not necessarily limited to R746-312-4.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 3 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 75 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.4.4
1.5
Customer is responsible for protecting the generating equipment, inverters,
protective devices, and other system components from damage from the normal
and abnormal conditions and operations that occur on Rocky Mountain Power’s
system in delivering and restoring power; and is responsible for ensuring that the
Net Metering Facility equipment is inspected, maintained, and tested in
accordance with the manufacturer’s instructions to ensure that it is operating
correctly and safely.
Parallel Operation and Maintenance Obligations
Once the Net Metering Facility has been authorized to commence parallel operation by
an approved application and execution of this Agreement, Customer will abide by all
written provisions for operations and maintenance as required by the Rule and Rocky
Mountain Power’s tariffs, including but not necessarily limited to R746-312-4 and
Schedule 135A or its successor tariff(s).
1.6
Metering
Rocky Mountain Power shall install, own and maintain, at its sole expense, a kilowatthour meter(s) and associated equipment to measure the flow of energy in each direction,
unless otherwise authorized by the Commission. Customer hereby consents to the
installation of and operation by Rocky Mountain Power, at Rocky Mountain Power’s
expense, one or more additional meters to monitor the flow of electricity in each
direction. Such meter(s) shall be located on the premises of Customer.
1.7
1.8
Net Metering Facility Requirements, Installation, Operation
1.7.1
Customer’s Net Metering Facility must meet the requirements set forth in,
including but not necessarily limited to, the Rule, R746-312-4 and Schedule
135A or its successor tariff(s). This also applies to installation and operation of
the Net Metering Facility.
1.7.2
Customer is responsible for all costs associated with its Net Metering Facility.
Anticipated Start Date
Customer must include an anticipated start date for operation of its Net Metering
Facility in the Application. After receiving notice that the Application has been
approved, Customer must execute and return this Agreement with a copy of the
approved electric inspection to Rocky Mountain Power. Upon satisfactory completion
of all reviews and inspections of the Net Metering Facility, Customer must notify
Rocky Mountain Power at least ten (10) business days prior to starting operation of the
Net Metering Facility, either through submission of an executed Agreement or through
separate written notice. Customer shall not commence parallel operation of the Net
Metering Facility until Rocky Mountain Power executes this Agreement, installs the net
meter and notifies Customer that the Net Metering Facility is interconnected.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 4 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 76 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.9
Net Metering Facility Inspection
1.9.1
Building Code Inspection
Prior to operation in parallel with Rocky Mountain Power’s system, the Net
Metering Facility must be inspected by a local building code official to ensure
compliance with applicable local codes.
1.9.2
Inspection by Rocky Mountain Power
Rocky Mountain Power may inspect the Net Metering Facility and its
component equipment, and the documents necessary to ensure compliance with
the Rule. Customer shall notify Rocky Mountain Power prior to placing the Net
Metering Facility in service, and Rocky Mountain Power shall have the right to
have personnel present on the in-service date. If the Net Metering Facility is
subsequently modified in order to increase its gross power rating, Customer
must notify Rocky Mountain Power by submitting a new application specifying
the modifications in accordance with the level of review required for that
application.
1.10
Power Quality
Customer will design its Net Metering Facility to maintain a composite power delivery
at continuous rated power output at the Point of Common Coupling that meets the
requirements set forth in IEEE 1547, in accordance with the Rule, R746-312-4.
1.11
Net Metering Facility Testing and Maintenance
Customer shall conduct maintenance and testing on its Net Metering Facilities as set
forth in the Rule, including but not necessarily limited to R746-312-14.
1.11.1 Customer shall conduct any manufacturer-recommended testing or maintenance
at its expense.
1.11.2 Customer shall conduct any post-installation testing, at its expense, necessary to
ensure compliance with IEEE standards as set forth in the Rule or to ensure
safety. This includes replacing a major equipment component that is different
from the originally installed model.
1.11.3 When Customer performs maintenance or testing in accordance with the Rule, it
must retain written records documenting the maintenance and results of the
testing for three (3) years.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 5 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 77 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.11.4 Rocky Mountain Power shall have the right to inspect Customer’s facility after
interconnection approval is granted, at reasonable hours and with reasonable prior
notice to Customer. If Rocky Mountain Power discovers that the Net Metering Facility
is not in compliance with the Rule, Rocky Mountain Power may require Customer to
disconnect the Net Metering Facility until compliance is achieved.
1.12
Removal of Facility
Customer shall immediately notify Rocky Mountain Power if Customer removes or
ceases to operate the Net Metering Facility.
Article 2.
2.1
Review, Inspection, Testing, Disconnect Switch and Signage, and Right of
Access
Review
After determining Customer’s interconnection request is complete, in accordance with
the Rule, R746-312-8, Rocky Mountain Power will conduct a review of the proposed
interconnection using screens set forth in the Rule, R746-312-7. Rocky Mountain
Power will conduct such review within fifteen (15) days after notifying Customer that
the interconnection request is complete and will notify Customer either that the Net
Metering Facility meets all applicable criteria and the interconnection request is
approved, or the Net Metering Facility has failed to meet one or more of the applicable
criteria, the reason for failure, and the interconnection request is denied under Level 1
review. If the interconnection request is denied, Customer may resubmit the application
under the Level 2 or Level 3 review process.
2.2
Equipment Testing and Inspection
Customer must notify Rocky Mountain Power of the anticipated testing and inspection
date of the Net Metering Facility at least ten (10) business days prior to testing, either
through submittal of the Agreement, a notice of completion, or in a separate notice.
Within ten (10) business days after receipt of such required documentation, Rocky
Mountain Power will inspect the Net Metering Facility, set the new meter if required,
approve the interconnection and may arrange a witness test as set forth in the Rule,
R746-312-8(4). Rocky Mountain Power and Customer will select a date by mutual
agreement for the witness test.
Rocky Mountain Power will test and inspect the Net Metering Facility and
Interconnection Facilities prior to interconnection in accordance with IEEE Standards as
provided for in the Rule, R746-312-4. Customer shall not begin operation of its Net
Metering Facility until after inspection and testing is completed.
If a witness test is conducted and is not satisfactory, Customer must resolve any
deficiencies within thirty (30) business days or other time period as mutually agreed by
the Parties.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 6 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 78 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
2.3
Disconnect Switch and Signage
Customer shall comply with the Rule regarding disconnect switches, R746-312-4. The
disconnect switch may be located more than 10 feet from the public utility meter if
permanent instructions in letters of appropriate size are posted at the meter indicating
the precise location of the disconnect switch. Rocky Mountain Power must approve in
writing the location of the disconnect switch prior to the installation of the Net Metering
Facility.
2.4
Right of Access
As provided in the Rule, R746-312-4, Rocky Mountain Power shall have access to any
required disconnect switch at the Net Metering Facility at all times. Rocky Mountain
Power will provide reasonable notice to Customer when possible prior to using the right
of access. Additionally, as provided in Rocky Mountain Power Utah Rule 6, or its
successor tariff, Rocky Mountain Power shall have access to the metering equipment.
Article 3.
3.1
Effective Date, Term, Termination and Disconnection
Effective Date
The Agreement shall become effective upon execution by the Parties.
3.2
Term of Agreement
The Agreement will become effective on the Effective Date and will remain in effect
unless terminated in accordance with provisions of this Agreement, or Order by the
Commission.
3.3
Termination
No termination will become effective until the Parties have complied with all applicable
laws and clauses of this Agreement applicable to such termination.
3.3.1
Customer may terminate this Agreement at any time by giving Rocky Mountain
Power twenty (20) business days written notice.
3.3.2
Either Party may terminate this Agreement after default pursuant to Article 6.4
of this Agreement.
3.3.3
The Commission may Order termination of this Agreement.
3.3.4
Upon termination of this Agreement, Customer shall disconnect the Net
Metering Facility from Rocky Mountain Power’s system. The termination of
this Agreement will not relieve either Party of its liabilities and obligations,
owed or continuing at the time of termination.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 7 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 79 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
3.4
3.3.5
If Customer removes the Net Metering equipment at the Net Metering Facility
or ceases to operate its Net Metering Facility at the premises listed in Recital 1
above, this Agreement will be immediately terminated.
3.3.6
The provisions of this Article shall survive termination or expiration of this
Agreement.
Temporary Disconnection
3.4.1
Rocky Mountain Power may temporarily disconnect the Net Metering Facility
from Rocky Mountain Power’s system for so long as reasonably necessary in the
event one or more of the following conditions or events occurs:
3.4.1.1 Emergencies or to address maintenance requirements for Rocky Mountain
Power’s system.
3.4.1.2 Hazardous conditions existing on Rocky Mountain Power’s system which
may affect the safety of the general public or Rocky Mountain Power
employees due to the operation of the Net Metering Facility or protective
equipment as determined by Rocky Mountain Power.
3.4.1.3 Adverse electrical effects on the electrical equipment of Rocky Mountain
Power’s other electric customers caused by the Net Metering Facility as
determined by Rocky Mountain Power.
3.4.2
In the event that no disconnect switch is installed, Rocky Mountain Power may
physically disconnect all service to the Customer and/or all service to the
premises where the Net Metering Facility is located.
3.4.3
To the extent practicable, Rocky Mountain Power will give prior notice of any
temporary disconnection of the Net Metering Facility. If Rocky Mountain Power
is unable to give prior notice, Rocky Mountain Power will provide notice
including an explanation of the condition necessitating the disconnection at the
time of disconnection
3.4.4
Under emergency conditions, Rocky Mountain Power or Customer may
immediately suspend interconnection service and temporarily disconnect the Net
Metering Facility. Rocky Mountain Power shall notify Customer promptly when
Rocky Mountain Power becomes aware of an emergency condition that may
reasonably be expected to affect the Net Metering Facility operation. Customer
shall notify Rocky Mountain Power promptly when Customer becomes aware of
an emergency condition that may reasonably be expected to affect Rocky
Mountain Power’s system. To the extent the information is known, the
notification shall describe the emergency condition, the extent of any damage or
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 8 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 80 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
deficiency, the expected effect on the operation of both Parties’ facilities and
operations, the anticipated duration, and the necessary corrective action.
3.4.5
Customer shall make reasonable efforts to provide notice of interruption of Net
Metering Facility operation for safety and/or reliability reasons prior to the
interruption unless an emergency occurs. Emergency interruptions or temporary
terminations are subject to Section 3.4.4 above.
3.4.6
Rocky Mountain Power shall use reasonable efforts to provide Customer with
prior notice of forced outages to effect immediate repairs to Rocky Mountain
Power’s system. If prior notice is not given, Rocky Mountain Power, shall, upon
request, provide Customer written documentation after the fact explaining the
circumstances of the disconnection.
3.4.7
Customer must provide Rocky Mountain Power notice and obtain Rocky
Mountain Power’s written approval before Customer may modify its Net
Metering Facility in order to increase the electric output of the Net Metering
Facility. If Customer makes any material change without prior written
authorization of Rocky Mountain Power, Rocky Mountain Power will have the
right to temporarily disconnect the Net Metering Facility until Rocky Mountain
Power has had an opportunity to review the change(s) made to determine
whether they are acceptable. If system modifications or other equipment
installations are deemed necessary by Rocky Mountain Power to accommodate
the modified Net Metering Facility, Customer shall submit the appropriate net
metering application at that time.
3.4.8
The Parties shall cooperate with each other to restore the Net Metering Facility,
interconnection facilities, and Rocky Mountain Power’s system to their normal
operating state as soon as reasonably practicable following any disconnection
pursuant to Section 3.4.
Article 4.
Cost Responsibility
4.1
Customer shall bear the cost of any Application fee set forth by Rule, or as
otherwise approved by the Commission.
4.2
Customer shall bear the cost of any facilities, equipment, modifications and
upgrades as required by the Rule. Customer shall also be responsible for all
reasonable expenses, including overheads, associated with owning, operating,
maintaining, repairing, and replacing its Net Metering Facility.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 9 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 81 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 5.
5.1
Billing
Monthly Billing
The electric service charge shall be computed in accordance with the monthly billing in
the applicable standard currently applicable service tariff applicable to Net Metering
customers. Customer will be compensated for net excess energy in accordance with
Schedule 135A or its successor tariff(s). Customer will be transitioned to any successor
tariff immediately upon approval of that tariff by the Public Service Commission and
will be subject to any charge, credit, or ratemaking structure implemented therein.
5.2
Special Conditions
Customer must comply with the special conditions found in Schedule 135A or its
successor tariff(s).
5.3
Aggregating Meters
Aggregating Meters is allowed if certain conditions are met under the Rule, R746-3125.
Customer
designates
the
following
meters
for
aggregation:
_______________________. In the event that the Net Metering Facility supplies more
electricity to Rocky Mountain Power than the Customer uses from Rocky Mountain
Power, Rocky Mountain Power will apply any credits to the next monthly bill in
accordance with Utah Code § 54-15-104 and the Rule, R746-312-15. Customer shall
designate the order in which to apply any credits in accordance with the Rule. <<If
customer does not want to aggregate, insert “N\A” in the space above.>>
Article 6.
6.1
Assignment, Liability, Indemnity, Consequential Damages and Default
Assignment
This Agreement may be assigned by either Party with the consent of the other Party. A
Party’s consent to an assignment may not be unreasonably withheld. The assigning
Party must give the non-assigning Party written notice of the assignment at least fifteen
days (15) before the effective date of the assignment. The non-assigning Party must
submit its objection to the assignment, if any, to the assigning Party in writing at least 5
business days before the effective date of the assignment. If a written objection is not
received within that time period, the non-assigning party is deemed to consent to the
assignment.
6.1.1
Exceptions to Consent Requirement
6.1.1.1 Either Party may assign the Agreement without the consent of the other
Party to any affiliate (including a merger or acquisition of the Party with
another entity) of the assigning Party with an equal or greater credit
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 10 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 82 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
rating and with the legal authority and operational ability to satisfy the
obligations of the assigning Party under this Agreement.
6.1.1.2 Customer is entitled to assign the Agreement without the consent of
Rocky Mountain Power for collateral security purposes to aid in
obtaining financing for the Net Metering Facility.
6.1.1.3 For small generator systems that are integrated into a building facility,
the sale of the building or property will result in the automatic
assignment of this Agreement to the new owner who will be responsible
for complying with the terms and conditions of this Agreement.
6.1.2
6.2
Any attempted assignment that violates this Article is void and ineffective.
Assignment does not change or eliminate a Party’s obligations under this
Agreement. An assignee is responsible for meeting the same obligations as the
assigning Party.
Limitation of Liability and Consequential Damages
Each Party’s liability to the other Party for any loss, cost, claim, injury, liability, or
expense, including reasonable attorney’s fees, relating to or arising from any act or
omission in its performance of this Agreement, is limited to the amount of direct
damage actually incurred. Neither Party is liable to the other Party for any indirect,
special, consequential, or punitive damages.
6.3
Indemnification
Customer shall hold harmless and indemnify Rocky Mountain Power for all loss to third
parties resulting from the operation of the Net Metering Facility, except when the loss
occurs due to the negligent actions of Rocky Mountain Power.
Rocky Mountain Power shall hold harmless and indemnify Customer for all loss to third
parties resulting from the operation of Rocky Mountain Power’s system, except where
the loss occurs due to the negligent actions of Customer.
6.4
Force Majeure
6.4.1
As used in this Agreement, a Force Majeure Event shall mean “any act of God,
labor disturbance, act of the public enemy, war, acts of terrorism, insurrection,
riot, fire, storm or flood, explosion, breakage or accident to machinery or
equipment through no direct, indirect, or contributory act of a Party, any order,
regulation, or restriction imposed by governmental, military or lawfully
established civilian authorities, or any other cause beyond a Party’s control. A
Force Majeure Event does not include an act of negligence or wrongdoing.”
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 11 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 83 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
6.4.2
6.5
If a Force Majeure Event prevents a Party from fulfilling any obligations under
this Agreement, the Party affected by the Force Majeure Event (“Affected
Party”) shall promptly notify the other Party of the existence of the Force
Majeure Event. The notification must specify in reasonable detail the
circumstances of the Force Majeure Event, its expected duration, and the steps
that the Affected Party is taking to mitigate the effects of the event on its
performance, and if the initial notification was verbal, it should be promptly
followed up with a written notification. The Affected Party shall keep the other
Party informed on a continuing basis of developments relating to the Force
Majeure Event until the event ends. The Affected Party will be entitled to
suspend or modify its performance of obligations under this Agreement (other
than the obligation to make payments) only to the extent that the effect of the
Force Majeure Event cannot be reasonably mitigated. The Affected Party will
use reasonable efforts to resume its performance as soon as possible. The Parties
shall immediately report to the Commission should a Force Majeure Event
prevent performance of an action required by Rule that the Rule does not permit
the Parties to mutually waive.
Default
6.5.1
A Party is in default if the Party fails to perform an obligation required under
this Agreement (other than the payment of money). A Party is not considered in
default of this agreement if the failure to perform an obligation is caused by an
act or omission of the other Party.
6.5.2
Upon a default, the non-defaulting Party must give written notice of the default
to the defaulting party. The defaulting party has sixty (60) calendar days from
the receipt of the written default notice to cure the default. If the default is not
capable of cure within the 60-day period, the defaulting Party must begin to cure
the default within twenty (20) calendar days after receipt of the written default
notice, and must continuously and diligently complete the cure within six (6)
months of the receipt of the notice.
6.5.3
If a default is not cured as provided in 6.5.2, then the non-defaulting Party is
entitled to terminate the Agreement by written notice at any time until cure
occurs. If the non-defaulting Party chooses to terminate this Agreement, the
termination provisions in Article 3.3 apply. Alternately, the non-defaulting Party
is entitled to seek dispute resolution with the Commission in lieu of termination.
Article 7.
Insurance
Additional liability insurance is not required as a part of the Agreement if the Net Metering
Facility is in compliance with the provisions of the Application approval, the Agreement and
the standards contained in Utah Code § 54-15-106.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 12 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 84 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 8.
Dispute Resolution
Nothing in this Article shall restrict the rights of any Party to file a Complaint with the
Commission under relevant provisions of the Rule, R746-312-3(5) and applicable state law.
Article 9.
9.1
Miscellaneous
Governing Law, Regulatory Authority, and Rules
The validity, interpretation, and enforcement of this Agreement is governed by the laws
of the State of Utah. If any provision of this Agreement conflicts with any applicable
provision, as may be amended from time to time, of the Utah Code (“Code”), Utah
Administrative Rules (“Rules”), or Rocky Mountain Power’s Tariffs (“Tariff”), then the
applicable provision of the Code, Rules, or Tariff controls. Rocky Mountain Power
must provide copies of the applicable provisions of the Code, Rules, and Tariff upon the
Customer’s request.
9.2
Amendment
Additions, deletions or changes to the standard terms and conditions of this Agreement
will not be permitted unless they are mutually agreed to by the Parties and permitted by
the Rule or permitted by the Commission for good cause shown. The Parties may
amend the Agreement by a written instrument duly executed by both Parties in
accordance with the provisions of the Rule, applicable Commission Orders and
provisions of the laws of the State of Utah.
9.3
No Third Party Beneficiaries
The Agreement is not intended to and does not create rights, remedies, or benefits of
any character whatsoever in favor of any persons, corporations, associations, or entities
other than the Parties, and the obligations herein assumed are solely for the use and
benefit of the Parties, or where permitted, their successors in interest and their assigns.
9.4
Waiver
9.4.1
The failure of a Party to the Agreement to insist, on any occasion, upon strict
performance of any provision of the Agreement, will not be considered a waiver
of any obligation, right, or duty of, or imposed upon, such Party.
9.4.2
The Parties may also agree to mutually waive a Section of this Agreement
without the Commission’s approval where the Rule so provides.
9.4.3
Any waiver at any time by either Party of its rights with respect to the
Agreement shall not be deemed a continuing waiver or a waiver with respect to
any other failure to comply with any other obligation, right, duty of the
Agreement. Termination or default of this Agreement for any reason by
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 13 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 85 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Customer shall not constitute a waiver of the Customer’s legal rights to obtain
interconnection from Rocky Mountain Power. Any request for waiver of the
Agreement or any provisions thereof shall be provided in writing.
9.5
Entire Agreement
The Agreement, including any supplementary attachments that may be necessary,
constitutes the entire Agreement between the Parties with reference to the subject matter
hereof, and supersedes all prior and contemporaneous understandings or agreements,
oral or written, between the Parties with respect to the subject matter of the Agreement.
There are no other agreements, representations, warranties, or covenants that constitute
any part of the consideration for, or any condition to, either Party’s compliance with its
obligations under the Agreement.
9.6
Multiple Counterparts
This Agreement may be executed in one or more counterparts, whether electronically or
otherwise, each of which is deemed an original but all constitute one and the same
instrument.
9.7
No Partnership
The Agreement will not be interpreted or construed to create an association, joint
venture, agency relationship, or partnership between the Parties or to impose any
partnership obligation or partnership liability upon either Party. Neither Party shall have
any right, power or authority to enter into any agreement or undertaking for, or act on
behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other
Party.
9.8
Severability
If any provision or portion of the Agreement shall for any reason be held or adjudged to
be invalid or illegal or unenforceable by any court of competent jurisdiction or other
governmental authority, (1) such portion or provision shall be deemed separate and
independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable
the benefits to each Party that were affected by such ruling, and (3) the remainder of the
Agreement shall remain in full force and effect.
9.9
Subcontractors
Nothing in the Agreement shall prevent a Party from using the services of any
subcontractor, or designating a third party agent as the one responsible for a specific
obligation or act required in the Agreement (collectively subcontractors), as it deems
appropriate to perform its obligations under the Agreement; provided, however, that
each Party will require its subcontractors to comply with all applicable terms and
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 14 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 86 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
conditions of the Agreement in providing such services and each Party will remain
primarily liable to the other Party for the performance of the subcontractor.
9.10
9.9.1
The creation of any subcontract relationship shall not relieve the hiring Party of
any of its obligations under the Agreement. The hiring Party shall by fully
responsible to the other Party for the acts or omissions of any subcontractor the
hiring Party hires as if no subcontract had been made. Any applicable obligation
imposed by the Agreement upon the hiring Party shall be equally binding upon,
and will be construed as having application to, any subcontractor of such Party.
9.9.2
The obligations under this Article will not be limited in any way by any
limitation of a subcontractor’s insurance.
Reservation of Rights
Rocky Mountain Power shall have the right to make a unilateral filing with the
Commission to modify this Agreement with respect to any rates, terms and conditions,
charges, classifications of service, rule, regulation or any other applicable provision of
the Federal Power Act and the Commission’s rules and regulations thereunder, and
Customer shall have the right to make a unilateral filing with the Commission to modify
this Agreement under any applicable provision of the Federal Power Act and the
Commission’s rules and regulations; provided that each Party shall have the right to
protest any such filing by the other Party and to participate fully in any proceeding
before the Commission in which such modifications may be considered. Nothing in this
Agreement shall limit the rights of the Parties, except to the extent that the Parties
otherwise agree as provided herein.
Article 10.
10.1
Notices and Records
General
Unless otherwise provided in the Agreement, any written notice, demand, or request
required or authorized in connection with the Agreement shall be deemed properly
given if delivered in person, delivered by recognized national courier service, sent by
first class mail, postage prepaid, or by electronic mail if an electronic mail address is
provided below, to the person specified below:
If to Customer:
Customer: ______________________________________________________
Attention: _____________________________________________________________
Address: ________________________________________________________________
City: ________________________________ State: _________________ Zip: ________
Phone: (____) ______________________ Fax: (____) ___________________________
Email: _________________________________________________________________
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 15 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 87 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If to Rocky Mountain Power:
By Mail:
Rocky Mountain Power
Attention: Net Metering Group
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
Or
By email:
[email protected]
10.2
Changes to the Notice Information
Either Party may change this notice information by giving five (5) business days written
notice prior to the effective date of the change.
10.3
Records
Rocky Mountain Power will maintain a record of the Net Metering Agreement and
related Attachments, if any, for as long as the net metering arrangement is in place.
Rocky Mountain Power will provide a copy of these records to Customer within fifteen
(15) Business Days if a request is made in writing.
Article 11.
Signatures
IN WITNESSETH WHEREOF, the Parties have caused the Agreement to be executed by
their respective duly authorized representatives.
For the Customer:
By: ______________________________________________
Name: ____________________________________________
Title: _____________________________________________
Date: _____________________________________________
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 16 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 88 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
For Rocky Mountain Power:
By: ______________________________________________
Name: ____________________________________________
Title: _____________________________________________
Date: _____________________________________________
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 17 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 89 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
APPENDIX A
ROCKY MOUNTAIN POWER UTAH NET METERING APPLICATION
LEVEL 1 REVIEW
INVERTER BASED SYSTEMS, 25 KW OR SMALLER
Section 1: For Rocky Mountain Power Use Only
Customer Name: ______________________________________________________________________
Service Address: ______________________________________________________________________
City, State, Zip: _______________________________________________________________________
Customer Account No. & Request No.: ____________________________________________________
Section 2: To Be Completed By Customer
A. Applicant Information
Name: _____________________________________________________________________
Mailing Address: ____________________________________________________________
City: ___________________________________State: _________ Zip Code: ____________
Site Street Address (if different from above): ______________________________________
City: ___________________________________State: __________ Zip Code: ___________
Daytime Phone: (_____) _____________________ Fax: (_____) ______________________
Email: _____________________________________________________________________
B. System Information
System Type:
Solar
Wind
Hydro
Other (Specify): ___________________
Generation Nameplate Capacity: _____ kW (Combine DC total of wind turbines, solar panels, etc)
Inverter Controlled:
Yes
No
Inverter Manufacturer: __________ Model: _______ Number of Inverters: ___ Rating: ____ kW
Manufacturer Nameplate Inverter Total AC Capacity Rating: _________ kW
Single Phase
Three Phase
Multiple Single Phase Connected on Poly-phase
Inverter(s):
(three phase) system (Attach Inverter and Panel Technical Specifications Sheets)
Type of Service:
Single Phase
Three Phase
If Three Phase:
120/208 Volts, 4 wire 120/240 Volts, 4 wire 277/480 Volts, 4 wire
Other (Please
Specify Voltage and Number of Service Wires): _______________________________________
Meets IEEE standard 1547 & UL Subject 1741 requirements as specified in Rule:
Yes
No
Please note: A disconnect switch is not required for an inverter-based facility with a name plate
rating of not more than 10 kW.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 18 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 90 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Manual disconnect required:
Yes
No
Will the net metering facility interconnect to a switchgear?
Yes
No
Net metering facility available fault duty at the point of common coupling:__________________
For other service types, the net metering facility must not impact the Customer’s service conductors
by more than 10 kW. If a disconnect switch is installed, Customer to provide a simple one-line
diagram that shows the location of the disconnect switch and Rocky Mountain Power meter.
Customer must post metal or plastic engraved signage indicating on-site generation in accordance
with National Electric Code. The signage must be permanent and located adjacent to the meter base
and disconnect switch noting “Parallel Generation on Site” and identifying the manual disconnect
switch with the words “Manual Disconnect for Parallel Generation.”____ (Initial Here)
Electrical Inspection approval date (attach copy or provide to utility when obtained):__________
Anticipated Operational Date of Net Metering Facilities: ________________________________
C. Application Fee - $60.00
C.D.
Additional Information
1. An equipment package will be considered certified for interconnected operation if it has been
submitted by a manufacturer to a nationally recognized testing and certification laboratory, and
has been tested and listed by the laboratory for continuous interactive operation with an electric
distribution system in compliance with the applicable IEEE and UL 1741 standards in the Rule.
2. If the equipment package has been tested and listed as an integrated package, which includes a
generator or other electric source, the equipment package will be deemed certified, and Rocky
Mountain Power will not require any further design review, testing or additional information.
3. If the equipment package includes only the interface components (switchgears, inverters, or
other interface devices), an interconnection applicant must show that the generator or other
electric source being utilized with the equipment package is compatible with the equipment
package and consistent with the testing and listing specified for the package. If the generator or
electric source being utilized with the equipment package is consistent with the testing and
listing performed by the nationally recognized testing and certification laboratory, the
equipment package will be deemed certified and Rocky Mountain Power will not require
further design review, testing or additional equipment.
4. A net metering facility must be equipped with metering equipment that can measure the flow of
electricity in both directions, comply with ANSI C12.1 standards and Utah Administrative Rule
R746-312. Rocky Mountain Power will install the required metering equipment at Rocky
Mountain Power’s expense.
5. Rocky Mountain Power will not be responsible for the cost of determining the rating of
equipment owned by the customer-generator or of equipment owned by other local customers.
6. Customer may operate the Net Metering Facility temporarily for testing and obtaining
inspection approval. Customer shall not operate the Net Metering Facility in continuous
parallel without an executed Interconnection and Net Metering Service Agreement, and
approval from Rocky Mountain Power.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 19 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 91 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
DE.
Customer Acknowledgment
I certify that the information provided in this Application is true. I will provide Rocky Mountain
Power a copy of the signed government electrical inspection approval document when obtained, if
not already provided with this Application.
I agree to abide by the terms of this Application and I agree to notify Rocky Mountain Power thirty
(30) days prior to modification or replacement of the System’s components or design. Any such
modification or replacement may require submission of a new Application to Rocky Mountain
Power.
I agree not to operate the Net Metering Facility in parallel with Rocky Mountain Power, except
temporarily for testing and obtaining inspection approval, until this Application is approved by
Rocky Mountain Power, until this agreement is signed by both parties, and until I have provided
Rocky Mountain Power with at least five (5) days notice of anticipated start date.
Customer or Applicant Signature & Date: ____________________________________
Please send completed application to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
or
Please scan the completed application and email
[email protected]
Section 3: To be completed by the System Installer
Installation Contractor Information/Hardware and Installation Compliance
Installation Contractor (Company Name): _________________________________________________
Contractor's License No.: ______________________ Proposed Installation Date: __________________
Mailing Address: _____________________________________________________________________
City: _____________________________________ State: ___________ Zip Code: ________________
Daytime Phone: _______________ Fax: _______________ Email: ____________________________
For inverter-controlled system, meets IEEE Standards and UL 1741 Inverters, Converters, and
Yes
No
Controllers for use in Independent Power Systems as set forth in the Rule:
If Photovoltaic System, System must be installed in compliance with IEEE Standards, Recommended
Practice for Utility Interface of Photovoltaic Systems. All System types must be installed in compliance
with applicable requirements of local electrical codes, Rocky Mountain Power and the National Electrical
Code® (NEC) and must use an anti-islanding inverter.
The System must include a manual, lockable, load-break (disconnect) switch, unless exempt under Rule
746-312-4(2), accessible at all times to Rocky Mountain Power personnel and located within 10 feet of
Rocky Mountain Power’s meter. The disconnect switch may be located more than 10 feet from Rocky
Mountain Power’s meter if permanent instructions are posted at the meter indicating the precise location of
the disconnect switch. Rocky Mountain Power must approve the location of the disconnect switch prior to
the installation of the net metering facility.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 20 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 92 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If the Net Metering Facility is designed to provide uninterruptible power to critical loads, either through
energy storage, back-up generator, or the generation source, the Net Metering Facility will include a
parallel blocking scheme for this backup source. This function may be integral to the inverter
manufacturer’s packaged system.
Does the Net Metering Facility include a parallel blocking scheme:
Yes
No
Signed (Contractor): ______________________________________ Date: _____________
Name (Print): _______________________________________________
Section 4. To be completed by Rocky Mountain Power:
A. If approving the application:
Rocky Mountain Power does not, by approval of this Application, assume any responsibility or
liability for damage to property or physical injury to persons. Further, this Application does not
constitute a dedication of the owner's System to Rocky Mountain Power electrical system
equipment or facilities.
Customer entered into an Interconnection and Net Metering Service Agreement with Rocky
Mountain Power on the ____ day of _____, 20__.
Customer satisfactorily passed Witness Tests on the ____ day of _________, 20__.
(Rocky Mountain Power may waive Witness Tests at its option; if tests are waived initial here __)
This Application is approved by Rocky Mountain Power on this ______ day of _________, 20__
Rocky Mountain Power Representative Name (Print):___________________________________
Signed (Rocky Mountain Power Representative): ______________________ Date: __________
B. If denying the application:
This application is denied by Rocky Mountain Power on this ______ day of ____________, 20__
for the following reason(s):_________________________________________________________
Rocky Mountain Power Representative Name (Print):____________________________________
Signed (Rocky Mountain Power Representative): ________________________ Date:__________
Applicant may submit a new application for Level 2 review.
Section 5: To be completed by Rocky Mountain Power Meterman
Customer Account No. _____________________________ Site ID No. : ______________________
Served from Facility Point No.: ________________________________
New Net Meter No.: ____________________________ Date net meter installed: ________________
Manual disconnect required:
Yes
No Proper location & permanent signage in place:
Yes
No
Signature/Title:_____________________________________________ Date:___________________
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 3 5 - Level 1
Page 21 of 21
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 93 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
We appreciate your interest in Rocky Mountain Power’s net metering program. Before
purchasing any net metering equipment, we recommend you review the requirements for
interconnecting a net metering system to Rocky Mountain Power’s electrical distribution
system. The requirements are found in the Interconnection Agreement.
To complete the process for a net metering interconnection, please follow the steps below:
1. Complete and submit the following to Rocky Mountain Power:
 Interconnection Agreement including the Application for Net Metering
Interconnection
 The inverter specification sheet
 For systems larger than 10 kW, a simple one-line diagram showing
 The location of Rocky Mountain Power’s meter
 The location of the disconnect switch
2. Rocky Mountain Power will review your agreement and application and send you a
written notification of approval either by mail or e-mail
3. Install the net metering system after you receive the written approval of your
Interconnection Agreement and Application for Net Metering from Rocky Mountain
Power
4. Obtain an inspection of your net metering system by the local city or county electrical
inspector
5. Submit the electrical inspector’s approval to Rocky Mountain Power
6. Turn on your net metering system after Rocky Mountain Power provides you written
notification the interconnection work has been completed and the net meter installed
Return completed documents to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, Utah 84125-0308
Or Email to:
[email protected]
Thank you for your interest in the net metering program. If you have questions, please call us
toll free at 1-888-221-7070 and ask for a net metering specialist.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 1 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 94 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Service ID#:___________
Request #: ___________
INTERCONNECTION AND NET METERING SERVICE AGREEMENT FOR NET
METERING FACILITY LEVEL 2 INTERCONNECTION
UP TO 2 MW NAMEPLATE CAPACITY
This Interconnection and Net Metering Service Agreement (“Agreement”) is made and
entered into this ____ day of _____________, 20___, by and between
_____________________________, an electric customer (“Customer”), and PacifiCorp, dba
Rocky Mountain Power (“Rocky Mountain Power”), a Corporation organized and existing
under the laws of the State of Oregon. Customer and Rocky Mountain Power each may be
referred to as a “Party”, or collectively as the “Parties”.
Recitals:
Whereas, Customer has installed or intends to install a Net Metering Facility qualifying
for “Net Metering,” Utah Rate Schedule No. 135A (“Schedule 135A”), as given in Rocky
Mountain Power’s currently effective tariff as filed with the Public Service Commission of
Utah (“Commission”), on or adjacent to Customer’s premises located at
____________________________, Utah, for the purpose of generating electric energy;
Whereas, the Net Metering rate schedule may be amended from time to time, and the
Public Service Commission may alter the charge, credit, and ratemaking structure applicable to
Net Metering customers pursuant to Utah Code § 54-15-105.1;
Whereas, Customer represents to Rocky Mountain Power that Customer either owns or
leases its Net Metering Facility qualifying for Schedule 135A, or meets the exemption
requirements set forth in Utah Code § 54-2-1.16(d) because it is a county, municipality, city,
town, other political subdivision, local district, special service district, state institution of higher
education, school district, charter school, or any entity within the state system of public
education; or an entity qualifying as a charitable organization under 26 U.S.C. Sec. 501(c)(3)
operated for religious, charitable, or educational purposes that is exempt from federal income
tax and able to demonstrate its tax-exempt status;
Whereas, Customer desires to interconnect the Net Metering Facility with Rocky
Mountain Power’s distribution system consistent with the Application completed by Customer
on _____________ ____, 20___, as described in as described in Appendix B (“Application”)
of this Agreement; and
Whereas, Customer, using its Net Metering Facility, intends to offset part or all of its
electrical requirements supplied by Rocky Mountain Power.
Now, therefore, in consideration of and subject to the mutual covenants contained
herein, the Parties agree as follows:
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 2 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 95 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 1.
Scope and Limitations of Agreement
1.1
Scope
The Agreement shall be used for all approved Level 2 Applications according to the
procedures set forth in Utah Administrative Rule 746-312, as may be amended from
time to time (“Rule”). . The Rule can be viewed at www.psc.utah.gov. The Agreement
establishes standard terms and conditions approved by the Public Service Commission
of Utah (“Commission”) under which the Net Metering Facility with an Electric
Nameplate Capacity of 2 MW or smaller as described in Appendix B will interconnect
to, and operate in parallel with, Rocky Mountain Power’s system.
1.2
Definitions
Terms with initial capitalization, when used in this Agreement, shall have the meanings
indicated or as specified in the Rule Section R746-312-2 and, to the extent this
Agreement conflicts with the Rule, the Rule shall take precedence.
1.3
Other Agreements
Nothing in this Agreement is intended to affect any other agreement between Rocky
Mountain Power and Customer or any other Interconnection Customer. However, in the
event that the provisions of the Agreement are in conflict with the provisions of any
Rocky Mountain Power Tariff, as may be amended from time to time, the Rocky
Mountain Power Tariff, as may be amended from time to time, shall control.
1.4
Responsibilities of the Parties
1.4.1
The Parties shall perform all obligations of the Agreement in accordance with
all applicable laws and regulations.
1.4.2
Customer will construct, operate, test, and maintain its Net Metering Facility in
accordance with the Agreement, IEEE standards (available at the following link:
http://standards.ieee.org/index.html), National Electric Code Standards
(available for purchase at http://standards.ieee.org/faqs/NESCFAQ.html#q8),
Utah state building codes (available at the following link:
http://www.dopl.utah.gov/programs/ubc/), the Rule and other applicable
standards required by the Commission, as may be amended from time to time.
1.4.3
Each Party shall be responsible for the safe installation, maintenance, repair and
condition of their respective lines and appurtenances on their respective sides of
the Point of Common Coupling. Each Party shall provide interconnection
facilities that adequately protect the other Party’s facilities, personnel and other
persons from damage and injury. The allocation of responsibility for the design,
installation, operation, maintenance and ownership of interconnection facilities
is prescribed in the Rule, including but not necessarily limited to R746-312-4.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 3 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 96 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.5
1.4.4
Customer is responsible for protecting the generating equipment, inverters,
protective devices, and other system components from damage from the normal
and abnormal conditions and operations that occur on Rocky Mountain Power’s
system in delivering and restoring power; and is responsible for ensuring that
the Net Metering Facility equipment is inspected, maintained, and tested in
accordance with the manufacturer’s instructions to ensure that it is operating
correctly and safely.
1.4.5
Customer shall obtain Rocky Mountain Power’s approval of the Application
prior to commencing parallel operation of its interconnected Net Metering
Facility.
Parallel Operation and Maintenance Obligations
Once the Net Metering Facility has been authorized to commence parallel operation by
an approved application, and execution of this Agreement, Customer will abide by all
written provisions for operations and maintenance as required by the Rule and Rocky
Mountain Power’s Tariffs, including but not necessarily limited to R746-312-4 and
Schedule 135A or its successor tariff(s).
1.6
Metering
Rocky Mountain Power shall install, own and maintain, at its sole expense, a kilowatthour meter(s) and associated equipment to measure the flow of energy in each direction,
unless otherwise authorized by the Commission. Customer shall provide, at its sole
expense, adequate facilities, including, but not limited to, a current transformer
enclosure (if required), meter socket(s) and junction box, for the installation of the meter
and associated equipment.
Customer hereby consents to the installation and operation by Rocky Mountain Power
and at Rocky Mountain Power’s expense, of one or more additional meters to monitor
the flow of electricity in each direction. Such meters shall be located on the premises of
Customer.
1.7
Net Metering Facility Requirements, Installation, Operation
1.7.1
Customer’s Net Metering Facility must meet the requirements set forth in,
including but not necessarily limited to, the Rule, R746-312-4 and Schedule
135A or its successor tariff(s). This also applies to installation and operation of
the Net Metering Facility.
1.7.2
Customer is responsible for all costs associated with its Net Metering Facility
and is also responsible for all costs related to any modifications to the Net
Metering Facility that may be required by Rocky Mountain Power for purposes
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 4 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 97 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
of safety and reliability as allowed under the Rule and Rocky Mountain Power
tariffs.
1.8
Power Quality
Customer will design its Net Metering Facility to maintain a composite power delivery
at continuous rated power output at the Point of Common Coupling that meets the
requirements set forth in IEEE 1547, in accordance with the Rule, R746-312-4.
1.9
Anticipated Start Date
Customer must include an anticipated start date for operation of its Net Metering
Facility in the Application. After receiving notice that the Application has been
approved and satisfactory completion of all reviews and inspections of the Net Metering
Facility, Customer must notify Rocky Mountain Power at least ten (10) Business Days
prior to starting operation of the Facility, through either submission of an executed
Agreement or through separate written notice. Customer shall not commence parallel
operation of the Net Metering Facility until Rocky Mountain Power executes this
Agreement, installs the net meter and notifies Customer that the Net Metering Facility
is interconnected.
1.10
Net Metering Facility Inspection
1.10.1 Building Code Inspection
Prior to operation in parallel with Rocky Mountain Power’s system, the Net
Metering Facility must be inspected by a local building code official to ensure
compliance with applicable local codes.
1.10.2 Inspection by Rocky Mountain Power
Rocky Mountain Power may inspect the Net Metering Facility and its
component equipment, and the documents necessary to ensure compliance with
the Rule. Customer shall notify Rocky Mountain Power prior to placing the Net
Metering Facility in service, and Rocky Mountain Power shall have the right to
have personnel present on the in-service date. If the Net Metering Facility is
subsequently modified in order to increase its gross power rating, Customer
must notify Rocky Mountain Power by submitting a new application specifying
the modifications in accordance with the level of review required for that
application.
1.11
Net Metering Facility Testing and Maintenance
Customer shall conduct maintenance and testing on its Net Metering Facilities as set
forth in the Rule, including but not necessarily limited to R746-312-14.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 5 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 98 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.11.1 Customer shall conduct any manufacturer-recommended testing or maintenance
at its expense.
1.11.2 Customer shall conduct any post-installation testing, at its expense, necessary to
ensure compliance with IEEE standards as set forth in the Rule or to ensure
safety. This includes replacing a major equipment component that is different
from the originally installed model.
1.11.3 When Customer performs maintenance or testing in accordance with the Rule,
it must retain written records documenting the maintenance and results of the
testing for three (3) years.
1.11.4 Rocky Mountain Power shall have the right to inspect Customer’s facility after
interconnection approval is granted, at reasonable hours and with reasonable
prior notice to Customer. If Rocky Mountain Power discovers that the Net
Metering Facility is not in compliance with the Rule, Rocky Mountain Power
may require Customer to disconnect the Net Metering Facility until compliance
is achieved.
1.12
Removal of Facility
Customer shall immediately notify Rocky Mountain Power if Customer removes or
ceases to operate the Net Metering Facility.
Article 2.
2.1
Review, Inspection, Testing, Disconnect Switch and Signage, and Right of
Access
Initial Review and Additional Review
After determining Customer’s interconnection request is complete, in accordance with
the Rule, R746-312-9, Rocky Mountain Power will conduct a review of the proposed
interconnection, using screens set forth in the Rule R746-312-7. Rocky Mountain Power
will conduct such review within fifteen (15) days after notifying Customer that the
interconnection request is complete and will notify Customer either: 1) the Net Metering
Facility meets all applicable criteria and the interconnection request is approved; 2)
although the Net Metering Facility fails one or more of the screens the Net Metering
Facility may be interconnected consistent with safety, reliability, and power quality
standards and the interconnection is approved; or 3) the interconnection of the Net
Metering Facility has failed to meet one or more of the applicable criteria and the reason
for failure, or Rocky Mountain Power has not or could not determine from the initial
reviews that the Net Metering Facility may be interconnected consistent with safety
reliability, and power quality standards, or the Net Metering Facility cannot be approved
without minor modifications at minimal cost and the interconnection request is denied
unless the Customer is willing to consider minor modifications or further study.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 6 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 99 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If the initial review determines that the Net Metering Facility fails to meet one or more
applicable requirements, but additional review may enable Rocky Mountain Power to
determine that the Net Metering Facility may be interconnected consistent with safety,
reliability and power quality standards, Rocky Mountain Power will offer to perform
the additional review to determine whether minor modifications to the electric
distribution system would enable the interconnection to be made consistent with safety,
reliability and power quality standards. In this instance, Rocky Mountain Power will
provide Customer with a good faith, nonbinding estimate of costs of such additional
review and minor modifications. Rocky Mountain Power will conduct additional review
and make minor modifications after receipt of payment from Customer in accordance
with the attached Appendix A.
2.2
Equipment Testing and Inspection
Customer must notify Rocky Mountain Power of the anticipated testing and inspection
date of the Net Metering Facility at least ten (10) business days prior to testing, either
through submittal of the Agreement, a notice of completion, or in a separate notice.
Within ten (10) business days after receipt of such required documentation, Rocky
Mountain Power will inspect the Net Metering Facility, set the new meter if required,
approve the interconnection and may arrange a witness test as set forth in the Rule,
R746-312-9(5). Rocky Mountain Power and Customer will select a date by mutual
agreement for the witness tests.
Rocky Mountain Power will test and inspect the Net Metering Facility and
Interconnection Facilities prior to interconnection in accordance with IEEE Standards
as provided for in the Rule, R746-312-4. Customer shall not begin operation of its Net
Metering Facility until after inspection and testing is completed.
If a witness test is conducted and is not satisfactory, Customer must resolve any
deficiencies within forty-five (45) business days or other time period as mutually agreed
by the Parties.
2.3
Disconnect Switch and Signage
Customer shall comply with the Rule regarding disconnect switches, R746-312-4. The
disconnect switch may be located more than 10 feet from the public utility meter if
permanent instructions in letters of appropriate size are posted at the meter indicating
the precise location of the disconnect switch. Rocky Mountain Power must approve in
writing the location of the disconnect switch prior to the installation of the Net Metering
Facility.
2.4
Right of Access
As provided in the Rule, R746-312-4, Rocky Mountain Power shall have access to any
required disconnect switch at the Net Metering Facility at all times. Rocky Mountain
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 7 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 100 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Power will provide reasonable notice to Customer when possible prior to using the right
of access. Additionally, as provided in Rocky Mountain Power Utah Rule 6, or its
successor tariff, Rocky Mountain Power shall have access to the metering equipment.
Article 3.
3.1
Effective Date, Term, Termination and Disconnection
Effective Date
The Agreement shall become effective upon execution by the Parties.
3.2
Term of Agreement
The Agreement will become effective on the Effective Date and will remain in effect
unless terminated in accordance with provisions of this Agreement, or Order by the
Commission.
3.3
Termination
No termination will become effective until the Parties have complied with all applicable
laws and clauses of this Agreement applicable to such termination.
3.3.1
Customer may terminate this Agreement at any time by giving Rocky Mountain
Power twenty (20) business days written notice.
3.3.2
Either Party may terminate this Agreement after default pursuant to Article 6.4
of this Agreement.
3.3.3
The Commission may Order termination of this Agreement.
3.3.4
Upon termination of this Agreement, Customer shall disconnect the Net
Metering Facility from Rocky Mountain Power’s system. The termination of
this Agreement will not relieve either Party of its liabilities and obligations,
owed or continuing at the time of termination.
3.3.5
If Customer removes the Net Metering equipment at the Net Metering Facility
or ceases to operate its Net Metering Facility at the premise listed in the
Application, this Agreement will be immediately terminated.
3.3.6
The provisions of this Article shall survive termination or expiration of this
Agreement.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 8 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 101 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
3.4
Temporary Disconnection
3.4.1
Rocky Mountain Power may temporarily disconnect the Net Metering Facility
from Rocky Mountain Power’s system for so long as reasonably necessary in
the event one or more of the following conditions or events occurs:
3.4.1.1 Emergencies or to address maintenance requirements for Rocky
Mountain Power’s system.
3.4.1.2 Hazardous conditions existing on Rocky Mountain Power’s system
which may affect the safety of the general public or Rocky Mountain
Power employees due to the operation of the Net Metering Facility or
protective equipment as determined by Rocky Mountain Power.
3.4.1.3 Adverse electrical effects on the electrical equipment of Rocky Mountain
Power’s other electric customers caused by the Net Metering Facility as
determined by Rocky Mountain Power.
3.4.2
In the event that no disconnect switch is installed, Rocky Mountain Power may
physically disconnect all service to the Customer and/or all service to the
premises where the Net Metering Facility is located.
3.4.3
To the extent practicable, Rocky Mountain Power will give prior notice of any
temporary disconnection of the Net Metering Facility. If Rocky Mountain Power
is unable to give prior notice, Rocky Mountain Power will provide notice
including an explanation of the condition necessitating the disconnection at the
time of disconnection.
3.4.4
Under emergency conditions, Rocky Mountain Power or Customer may
immediately suspend interconnection service and temporarily disconnect the
Net Metering Facility. Rocky Mountain Power shall notify Customer promptly
when Rocky Mountain Power becomes aware of an emergency condition that
may reasonably be expected to affect the Net Metering Facility operation.
Customer shall notify Rocky Mountain Power promptly when Customer
becomes aware of an emergency condition that may reasonably be expected to
affect Rocky Mountain Power’s system. To the extent the information is known,
the notification shall describe the emergency condition, the extent of any
damage or deficiency, the expected effect on the operation of both Parties’
facilities and operations, the anticipated duration, and the necessary corrective
action.
3.4.5
Customer shall make reasonable efforts to provide notice of interruption of Net
Metering Facility operation for safety and/or reliability reasons prior to the
interruption unless an emergency occurs. Emergency interruptions or temporary
terminations are subject to Section 3.4.1 above.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 9 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 102 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
3.4.6
Rocky Mountain Power shall use reasonable efforts to provide Customer with
prior notice of forced outages to effect immediate repairs to Rocky Mountain
Power’s system. If prior notice is not given, Rocky Mountain Power, shall, upon
request, provide Customer written documentation after the fact explaining the
circumstances of the disconnection.
3.4.7
Customer must provide Rocky Mountain Power notice and obtain Rocky
Mountain Power’s written approval before Customer may modify its Net
Metering Facility in order to increase the electric output of the Net Metering
Facility. If Customer makes any material change without prior written
authorization of Rocky Mountain Power, Rocky Mountain Power will have the
right to temporarily disconnect the Net Metering Facility until Rocky Mountain
Power has had an opportunity to review the change(s) made to determine
whether they are acceptable. If any system modifications or other equipment
installations are deemed necessary by Rocky Mountain Power to accommodate
the modified Net Metering Facility, Customer shall submit the appropriate net
metering application at that time.
3.4.8
The Parties shall cooperate with each other to restore the Net Metering Facility,
Interconnection Facilities, and Rocky Mountain Power’s system to their normal
operating state as soon as reasonably practicable following any disconnection
pursuant to this section.
Article 4.
4.1
Cost Responsibility
Application Fee
Customer shall bear the cost of any Application fee provided for in the Rule, R746-31213(2), or as otherwise approved by the Commission. Customer shall remit payment with
the Application as calculated in the Application, Section 2(C).
4.2
Net Metering Facility and Interconnection Equipment
Customer shall be responsible for all costs including overheads, associated with
procuring, installing, owning, operating, maintaining, repairing, and replacing its Net
Metering Facility, any associated equipment package, and any associated
interconnection equipment or interconnection facilities required to be installed on
Customer’s side of the Point of Common Coupling.
4.3
Minor Modifications
If, under Section 2.1 of this Agreement, additional review is performed and minor
modifications to the electric distribution system are required to enable the
interconnection to be made consistent with safety, reliability and power quality
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 10 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 103 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
standards applicable to Level 2 interconnection reviews, the Customer shall pay for the
cost to procure, install, and construct, operate, maintain, repair and replace any such
Minor Modifications. A description of the minor modifications may be found in
Appendix A. The cost of the minor modifications as described on Appendix A shall be
$________. Customer shall remit payment for minor modifications prior to Rocky
Mountain Power commencing the work required for the minor modifications.
Article 5.
5.1
Billing
Monthly Billing
The electric service charge shall be computed in accordance with the monthly billing in
the currently applicable standard service tariff. Customer will be compensated for net
excess energy in accordance with Schedule 135A or its successor tariff(s). Customer
will be transitioned to any successor tariff immediately upon approval of that tariff by
the Public Service Commission and will be subject to any charge, credit, or ratemaking
structure implemented therein.
5.2
Special Conditions
Customer must comply with the special conditions found in Schedule 135A or its
successor tariff(s).
5.3
Aggregating Meters
Aggregating Meters is allowed if certain conditions are met under the Rule, R746-3125.
Customer
designates
the
following
meters
for
aggregation:
_______________________. In the event that the Net Metering Facility supplies more
electricity to Rocky Mountain Power than the Customer uses from Rocky Mountain
Power, Rocky Mountain Power will apply any credits to the next monthly bill in
accordance with Utah Code § 54-15-104 and the Rule, R746-312-15. Customer shall
designate the order in which to apply any credits in accordance with the Rule. <<If
customer does not want to aggregate, insert “N\A” in the gray box.>>
Article 6.
6.1
Assignment, Liability, Indemnity, Force Majeure, Consequential Damages
and Default
Assignment
This Agreement may be assigned by either Party with the consent of the other Party. A
Party’s consent to an assignment may not be unreasonably withheld. The assigning
Party must give the non-assigning Party written notice of the assignment at least fifteen
days (15) before the effective date of the assignment. The non-assigning Party must
submit its objection to the assignment, if any, to the assigning Party in writing at least 5
business days before the effective date of the assignment. If a written objection is not
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 11 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 104 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
received within that time period, the non-assigning party is deemed to consent to the
assignment.
6.1.1
Exceptions to the Consent Requirement
6.1.1.1 Either Party may assign the Agreement without the consent of the other
Party to any affiliate (including a merger or acquisition of the Party with
another entity), of the assigning Party with an equal or greater credit
rating and with the legal authority and operational ability to satisfy the
obligations of the assigning Party under this Agreement.
6.1.1.2 Customer-Generator is entitled to assign the Agreement, without the
consent of Rocky Mountain Power, for collateral security purposes to aid
in obtaining financing for the Net Metering Facility.
6.1.1.3 For Net Metering systems that are integrated into a building facility, the
sale of the building or property will result in the automatic assignment
of this Agreement to the new owner who will be responsible for
complying with the terms and conditions of this Agreement.
6.1.2
6.2
Any attempted assignment that violates this Article is void and ineffective.
Assignment does not change or eliminate a Party’s obligations under this
Agreement. An assignee is responsible for meeting the same obligations as the
assigning Party.
Limitation of Liability and Consequential Damages
Each Party’s liability to the other Party for any loss, cost, claim, injury, liability, or
expense, including reasonable attorney’s fees, relating to or arising from any act or
omission in the performance of this Agreement, is limited to the amount of direct
damage actually incurred. Neither Party is liable to the other Party for any indirect,
special, consequential, or punitive damages.
6.3
Indemnification
Customer shall hold harmless and indemnify Rocky Mountain Power for all loss to third
parties resulting from the operation of the Net Metering Facility, except when the loss
occurs due to the negligent actions of Rocky Mountain Power.
Rocky Mountain Power shall hold harmless and indemnify Customer for all loss to third
parties resulting from the operation of Rocky Mountain Power’s system, except where
the loss occurs due to the negligent actions of Customer.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 12 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 105 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
6.4
6.5
Force Majeure
6.4.1
As used in this Agreement, a Force Majeure Event shall mean “any act of God,
labor disturbance, act of the public enemy, war, acts of terrorism, insurrection,
riot, fire, storm or flood, explosion, breakage or accident to machinery or
equipment through no direct, indirect, or contributory act of a Party, any order,
regulation, or restriction imposed by governmental, military or lawfully
established civilian authorities, or any other cause beyond a Party’s control. A
Force Majeure Event does not include an act of negligence or wrongdoing.”
6.4.2
If a Force Majeure Event prevents a Party from fulfilling any obligations under
this Agreement, the Party affected by the Force Majeure Event (“Affected
Party”) shall promptly notify the other Party of the existence of the Force
Majeure Event. The notification must specify in reasonable detail the
circumstances of the Force Majeure Event, its expected duration, and the steps
that the Affected Party is taking to mitigate the effects of the event on its
performance, and if the initial notification was verbal, it should be promptly
followed up with a written notification. The Affected Party shall keep the other
Party informed on a continuing basis of developments relating to the Force
Majeure Event until the event ends. The Affected Party will be entitled to
suspend or modify its performance of obligations under this Agreement (other
than the obligation to make payments) only to the extent that the effect of the
Force Majeure Event cannot be reasonably mitigated. The Affected Party will
use reasonable efforts to resume its performance as soon as possible. The Parties
shall immediately report to the Commission should a Force Majeure Event
prevent performance of an action required by Rule that the Rule does not permit
the Parties to mutually waive.
Default
6.5.1
A Party is in default if the Party fails to perform an obligation required under
this Agreement (other than the payment of money). A Party is not considered in
default of this agreement if the failure to perform an obligation is caused by an
act or omission of the other Party or is the result of a Force Majeure as defined
in this Agreement.
6.5.2
Upon a default, the non-defaulting Party must give written notice of the default
to the defaulting party. The defaulting party has sixty (60) calendar days from
the receipt of the written default notice to cure the default. If the default is not
capable of cure within the 60-day period, the defaulting Party must begin to cure
the default within twenty (20) calendar days after receipt of the written default
notice, and must continuously and diligently complete the cure within six (6)
months of the receipt of the notice.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 13 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 106 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
6.5.3
Article 7.
If a default is not cured as provided for in 6.5.2, then the non-defaulting Party is
entitled to terminate the Agreement by written notice at any time until cure
occurs. If the non-defaulting Party chooses to terminate this Agreement, the
termination provisions in Article 3.3 apply. Alternately, the non-defaulting Party
is entitled to seek dispute resolution with the Commission in lieu of termination.
Insurance
Additional liability insurance is not required as a part of the Agreement if the Net Metering
Facility is in compliance with the provisions of the Application approval, the Agreement and
the standards contained in Utah Code § 54-15-106.
Article 8.
Dispute Resolution
8.1
Nothing in this Article shall restrict the rights of any Party to file a complaint with the
Commission under relevant provisions of the Rule and applicable state law.
8.2
Pursuit of dispute resolution may not affect a Customer with regard to consideration of
an Interconnection Request or a Customer’s queue position.
Article 9.
9.1
Miscellaneous
Governing Law, Regulatory Authority and Rules
The validity, interpretation, and enforcement of this Agreement is governed by the laws
of the State of Utah. If any provision of this Agreement conflicts with any applicable
provision, as may be amended from time to time, of the Utah Code (“Code”), Utah
Administrative Rules (“Rules”), or Rocky Mountain Power’s Tariffs (“Tariff”), then the
applicable provision of the Code, Rules, or Tariff controls. Rocky Mountain Power must
provide copies of the applicable provisions of the Code, Rules, and Tariff upon the
Customer’s request.
9.2
Amendment
Additions, deletions or changes to the standard terms and conditions of this Agreement
will not be permitted unless they are mutually agreed to by the Parties and permitted by
the Rule or permitted by the Commission for good cause shown. The Parties may amend
the Agreement by a written instrument duly executed by both Parties in accordance with
the provisions of the Rule and applicable Commission Orders and provisions of the laws
of the State of Utah.
9.3
No Third Party Beneficiaries
The Agreement is not intended to and does not create rights, remedies, or benefits of
any character whatsoever in favor of any persons, corporations, associations, or entities
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 14 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 107 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
other than the Parties, and the obligations herein assumed are solely for the use and
benefit of the Parties, or where permitted, their successors in interest and their assigns.
9.4
9.5
Waiver
9.4.1
The failure of a Party to the Agreement to insist, on any occasion, upon strict
performance of any provision of the Agreement, will not be considered a waiver
of any obligation, right, or duty of, or imposed upon, such Party.
9.4.2
The Parties may also agree to mutually waive a Section of this Agreement
without the Commission’s approval where the Rule so provides.
9.4.3
Any waiver at any time by either Party of its rights with respect to the Agreement
shall not be deemed a continuing waiver or a wavier with respect to any other
failure to comply with any other obligation, right, duty of the Agreement.
Termination or default of this Agreement for any reason by Customer shall not
constitute a waiver of the Customer’s legal rights to obtain interconnection from
Rocky Mountain Power. Any request for waiver of the Agreement or any
provisions thereof shall be provided in writing.
Entire Agreement
The Agreement, including any supplementary attachments that may be necessary,
constitutes the entire Agreement between the Parties with reference to the subject matter
hereof, and supersedes all prior and contemporaneous understandings or agreements,
oral or written, between the Parties with respect to the subject matter of the Agreement.
There are no other agreements, representations, warranties, or covenants that constitute
any part of the consideration for, or any condition to, either Party’s compliance with its
obligations under the Agreement.
9.6
Multiple Counterparts
This Agreement may be executed in one or more counterparts, whether electronically
or otherwise, each of which is deemed an original but all constitute one and the same
instrument.
9.7
No Partnership
The Agreement will not be interpreted or construed to create an association, joint
venture, agency relationship, or partnership between the Parties or to impose any
partnership obligation or partnership liability upon either Party. Neither Party shall have
any right, power or authority to enter into any agreement or undertaking for, or act on
behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other
Party.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 15 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 108 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
9.8
Severability
If any provision or portion of the Agreement shall for any reason be held or adjudged to
be invalid or illegal or unenforceable by any court of competent jurisdiction or other
governmental authority, (1) such portion or provision shall be deemed separate and
independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable
the benefits to each Party that were affected by such ruling, and (3) the remainder of the
Agreement shall remain in full force and effect.
9.9
Subcontractors
Nothing in the Agreement shall prevent a Party from using the services of any
subcontractor, or designating a third party agent as one responsible for a specific
obligation or act required in the Agreement (collectively “subcontractors”), as it deems
appropriate to perform its obligations under the Agreement; provided, however, that
each Party will require its subcontractors to comply with all applicable terms and
conditions of the Agreement in providing such services and each Party will remain
primarily liable to the other Party for the performance of the subcontractor.
9.10
9.9.1
The creation of any subcontract relationship shall not relieve the hiring Party of
any of its obligations under the Agreement. The hiring Party shall by fully
responsible to the other Party for the acts or omissions of any subcontractor the
hiring Party hires as if no subcontract had been made. Any applicable obligation
imposed by the Agreement upon the hiring Party shall be equally binding upon,
and will be construed as having application to, any subcontractor of such Party.
9.9.2
The obligations under this Article will not be limited in any way by any
limitation of a subcontractor’s insurance.
Reservation of Rights
Rocky Mountain Power shall have the right to make a unilateral filing with the
Commission to modify this Interconnection Agreement with respect to any rates, terms
and conditions, charges, classifications of service, rule, regulation or any other
applicable provision of the Federal Power Act and the Commission’s rules and
regulations thereunder, and Customer shall have the right to make a unilateral filing
with the Commission to modify this Agreement under any applicable provision of the
Federal Power Act and the Commission’s rules and regulations; provided that each Party
shall have the right to protest any such filing by the other Party and to participate fully
in any proceeding before the governing authority in which such modifications may be
considered. Nothing in this Agreement shall limit the rights of the Parties, except to the
extent that the Parties otherwise agree as provided herein.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 16 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 109 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 10.
10.1
Notices and Records
General
Unless otherwise provided in the Agreement, any written notice, demand, or request
required or authorized in connection with the Agreement shall be deemed properly given
if delivered in person, delivered by recognized national courier service, sent by first
class mail, postage prepaid, or by electronic mail if an electronic mail address is
provided below to the person specified below:
If to Customer:
Customer: ______________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: ________________________________ State: _________________ Zip: ________
Phone: (____) ________________________ Fax: (____) _________________________
Email: __________________________________________________________________
If to Rocky Mountain Power:
By Mail:
Rocky Mountain Power
Attention: Net Metering Group
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
Or
By email:
[email protected]
10.2
Records
Rocky Mountain Power will maintain a record of the Interconnection Agreement and
related Attachments, if any, for as long as the interconnection is in place. Rocky
Mountain Power will provide a copy of these records to Customer within fifteen (15)
Business Days upon written request.
10.3
Billing and Payment
Billings and payments shall be sent to the addresses below (complete if different from
Section 10.1 above):
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 17 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 110 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If to Customer:
Customer: ______________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: _______________________________ State: _______________ Zip: ___________
10.4
Designated Operating Representative
The Parties will designate one operating representative each to conduct the
communications that may be necessary or convenient for the administration of the
operations provisions of the Agreement. This person will also serve as the point of
contact with respect to operations and maintenance of the Party’s facilities (complete if
different from Section 10.1 above):
Customer’s Operating Representative:
Name: __________________________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: _______________________________ State: _______________ Zip: ___________
Phone: (____) _______________________ Fax: (____) __________________________
Email: __________________________________________________________________
10.5
Changes to the Notice Information
Either Party may change this notice information by giving five (5) business days written
notice prior to the effective date of the change.
Article 11.
Signatures
IN WITNESSETH WHEREOF, the Parties have caused the Agreement to be executed by
their respective duly authorized representatives.
For the Customer:
For Rocky Mountain Power:
By: _____________________________
By: _____________________________
Name: ___________________________
Name: ___________________________
Title: ____________________________
Title: ____________________________
Date: ____________________________
Date: ____________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 18 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 111 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Appendix A
Minor Modifications
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 19 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 112 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
APPENDIX B
ROCKY MOUNTAIN POWER UTAH NET METERING APPLICATION
LEVEL 2 REVIEW
CAPACITY OF 2 MW OR LESS
Section 1: For Rocky Mountain Power Use Only
Customer Name: _________________________________________________________________________
Service Address: _________________________________________________________________________
City, State, Zip: __________________________________________________________________________
Customer Account No. & Request No.:________________________________________________________
Interconnection Agreement Acknowledgement (Date): ___________________________________________
Application fee: $__________________ Date Paid: _____________________________________________
Section 2: To Be Completed By Customer
A. Applicant Information
Name: ___________________________________________________________________________
Mailing Address: ___________________________________________________________________
City: __________________________________________State: _________ Zip Code: ____________
Site Street Address (if different from above): _____________________________________________
City: __________________________________________State: __________ Zip Code: ___________
Daytime Phone: (_____) ________________________ Fax: (_____) __________________________
Email: ____________________________________________________________________________
B. System Information
System Type:
Solar
Wind
Hydro
Other (Specify): _________________________
Generation Nameplate Capacity: ______________ kW (Combine DC total of wind turbines, solar
panels, etc. or AC rating if an inverter is not utilized)
Inverter Manufacturer: ___________ Model: _______ Number of Inverters: _____ Rating: _____ kW
Manufacturer Nameplate Inverter Total AC Capacity Rating: _________ kW
Inverter(s):
Single Phase
Three Phase
Multiple Single Phase Connected on Poly-phase
(three phase) system (Attach Inverter and Panel Technical Specifications Sheets)
Type:
Induction
Type of Service:
Inverter
Single Phase
Synchronous
__________________Other
Three Phase
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 20 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 113 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If Three Phase Transformer:
Indicate Type:
Wye
Delta
Indicate Voltage and Number of Service Wires:
120/208 Volts, 4 wire 120/240 Volts, 4 wire 277/480 Volts, 4 wire
Other ___________
________________________________________________________________________________
Other Information:_________________________________________________________________
________________________________________________________________________________
Self Contained Location: ___________________________________________________________
Outdoor Manual AC Disconnect Switch Location (show Disconnect Switch and Rocky Mountain
Power Meter Location on Site Plan), unless exempt under Utah Administrative Rule 746-312-4(2):
________________________________________________________________________________
System Location (show all protective devices on One Line Diagram):_________________________
Will the net metering facility interconnect to a switchgear?
Yes
No
Customer must post metal or plastic engraved signage indicating on-site generation in accordance with
the National Electric Code. The signage must be permanent and located adjacent to the meter base and
disconnect switch noting “Parallel Generation on Site” and identifying the manual disconnect switch
with the words “Manual Disconnect for Parallel Generation.” _____ (Initial Here)
One Line Diagram Attached:
Installation Test Plan attached:
Yes
Yes
No
Site Plan Attached:
Yes
No
No
Anticipated Operational Date of Net Metering Facilities: __________________________________
(Rocky Mountain Power must be notified at least ten (10) business days prior to starting operation.)
Net metering facility available fault duty at the point of common coupling:_____________________
(A Rocky Mountain Power Engineer may contact you for additional information)
Electrical Inspection approval date (attach copy or provide to utility when obtained):_____________
C. Application Fees
$
750.00
+ $ __________
$ __________
Base
$1.050 x ____ kW of Net Metering Facility’s capacity
TOTAL APPLICATION FEE
D. Additional Information
1.
An equipment package will be considered certified for interconnected operation if it has been
submitted by a manufacturer to a nationally recognized testing and certification laboratory, and
has been tested and listed by the laboratory for continuous interactive operation with an electric
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 21 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 114 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
2.
3.
4.
5.
6.
7.
distribution system in compliance with the applicable IEEE and UL 1741 standards, as set forth
in the Rule.
If the equipment package has been tested and listed as an integrated package, which includes a
generator or other electric source, the equipment package will be deemed certified, and Rocky
Mountain Power will not require any further design review, testing or additional information.
If the equipment package includes only the interface components (switchgears, inverters, or
other interface devices), an interconnection applicant must show that the generator or other
electric source being utilized with the equipment package is compatible with the equipment
package and consistent with the testing and listing specified for the package. If the generator or
electric source being utilized with the equipment package is consistent with the testing and
listing performed by the nationally recognized testing and certification laboratory, the
equipment package will be deemed certified and Rocky Mountain Power will not require
further design review, testing or additional equipment.
A net metering facility must be equipped with metering equipment that can measure the flow of
electricity in both directions, comply with ANSI C12.1 standards and Rule 746-312. Rocky
Mountain Power will install the required metering equipment at Rocky Mountain Power’s
expense.
Rocky Mountain Power will not be responsible for the cost of determining the rating of
equipment owned by the customer-generator or of equipment owned by other local customers.
Customer may operate the Net Metering Facility temporarily for testing and obtaining
inspection approval. Customer shall not operate the Net Metering Facility in continuous
parallel without an executed Interconnection and Net Metering Service Agreement, and
approval from Rocky Mountain Power.
Customer will pay to Rocky Mountain Power at the time of application the applicable
Application fee of $5075.00 plus $1.00 50 per kilowatt of the net metering facility’s capacity.
Customer-generator will pay to Rocky Mountain Power all costs of minor modifications or
additional review as set forth in Rule 746-312 prior to commencement of work.
E. Customer Acknowledgment
I certify that the information provided in this Application is true. I will provide Rocky Mountain Power
a copy of the signed government electrical inspection approval document when obtained, if not already
provided with this Application.
I agree to abide by the terms of this Application and I agree to notify Rocky Mountain Power thirty (30)
days prior to modification or replacement of the System’s components or design. Any such
modification or replacement may require submission of a new Application to Rocky Mountain Power.
I agree not to operate the Net Metering Facility in parallel with Rocky Mountain Power, except
temporarily for testing and obtaining inspection approval, until this Application is approved by Rocky
Mountain Power, until this agreement is signed by both parties, and until I have provided Rocky
Mountain Power with at least five (5) days notice of anticipated start date.
Customer or Applicant Signature & Date: ____________________________________
Please send completed application to:
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 22 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 115 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
or
Please scan the completed application and email
[email protected]
Section 3. To be completed by System Installer
Installation Contractor Information/Hardware and Installation Compliance
Installation Contractor (Company Name): ______________________________________________________
Contractor's License No.: _______________________________ Proposed Installation Date: _____________
Mailing Address: _________________________________________________________________________
City: ______________________________________________ State: _________ Zip Code: _____________
Daytime Phone: ________________ Fax: _____________ Email: __________________________________
For inverter-controlled system, meets IEEE Standards and UL 1741 Inverters, Converters, and
Controllers for use in Independent Power Systems as set forth in the Rule:
Yes
No
For induction or synchronous device, meets IEEE Standard 1547 and IEEE/ANSI Standard C37.90
Yes
No
requirements as set forth in the Rule:
If Photovoltaic System, System must be installed in compliance with IEEE Standards, Recommended Practice
for Utility Interface of Photovoltaic Systems. All System types must be installed in compliance with applicable
requirements of local electrical codes, Rocky Mountain Power and the National Electrical Code® (NEC) and
must use an anti-islanding inverter.
The System must include a manual, lockable, load-break (disconnect) switch, unless exempt under Rule 746312-4(2), accessible at all times to Rocky Mountain Power personnel and located within 10 feet of Rocky
Mountain Power’s meter. The disconnect switch may be located more than 10 feet from Rocky Mountain
Power’s meter if permanent instructions are posted at the meter indicating the precise location of the disconnect
switch. Rocky Mountain Power must approve the location of the disconnect switch prior to the installation of
the net metering facility.
If the Net Metering Facility is designed to provide uninterruptible power to critical loads, either through energy
storage, back-up generator, or the generation source, the Net Metering Facility will include a parallel blocking
scheme for this backup source. This function may be integral to the inverter manufacturer’s packaged system.
Does the Net Metering Facility include a parallel blocking scheme:
Yes
No
Signed (Contractor): ______________________________________ Date: _____________
Name (Print): _______________________________________________
Section 4. To be completed by Rocky Mountain Power:
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 23 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 116 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
A.
If approving the application:
Rocky Mountain Power does not, by approval of this Application, assume any responsibility or liability
for damage to property or physical injury to persons. Further, this Application does not constitute a
dedication of the owner's System to Rocky Mountain Power electrical system equipment or facilities.
Customer entered into an Interconnection and Net Metering Service Agreement with Rocky Mountain
Power on the ____ day of _____, 20__.
Customer satisfactorily passed Witness Tests on the ___ day of ________, 20___
(Rocky Mountain Power may waive Witness Tests at its option; if tests are waived initial here ______).
This Application is approved by Rocky Mountain Power on this _____ day of ______________, 20__
Rocky Mountain Power Representative Name (Print): ______________________________________
Signed (Rocky Mountain Power Representative): __________________________ Date: ___________
B. If denying the application:
This application is denied by Rocky Mountain Power on this _____ day of ____________, 20__ for the
following reason(s):__________________________________________________________________
Rocky Mountain Power Representative Name (Print): ______________________________________
Signed (Rocky Mountain Power Representative): ________________________ Date:____________
Applicant may submit a new application for Level 3 review.
Section 5. To be completed by Rocky Mountain Power Meterman
Customer Account No. __________________________________ Site ID No.: _______________________
Served from Facility Point No.: ________________________________
New Net Meter No.: ____________________________ Date net meter installed: ______________________
Manual disconnect location and permanent signage in place unless system is less than 10 kW:
Yes
No
Signature/Title: _________________________________________ Date: ___________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Level 2
Page 24 of 24
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 117 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
We appreciate your interest in Rocky Mountain Power’s net metering program. Before
purchasing any net metering equipment, we recommend you review the requirements for
interconnecting a net metering system to Rocky Mountain Power’s electrical distribution system.
The requirements are found in the Interconnection Agreement.
To complete the process for a net metering interconnection, please follow the steps below:
1. Complete and submit the following to Rocky Mountain Power:
 Interconnection Agreement including the Application for Net Metering
Interconnection
 The inverter specification sheet
 For systems larger than 10 kW, a simple one-line diagram showing
 The location of Rocky Mountain Power’s meter
 The location of the disconnect switch
2. Rocky Mountain Power will review your agreement and application and send you a
written notification of approval either by mail or e-mail
3. Install the net metering system after you receive the written approval of your
Interconnection Agreement and Application for Net Metering from Rocky Mountain
Power
4. Obtain an inspection of your net metering system by the local city or county electrical
inspector
5. Submit the electrical inspector’s approval to Rocky Mountain Power
6. Turn on your net metering system after Rocky Mountain Power provides you written
notification the interconnection work has been completed and the net meter installed
Return completed documents to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, Utah 84125-0308
Or Email to:
[email protected]
Thank you for your interest in the net metering program. If you have questions, please call us toll
free at 1-888-221-7070 and ask for a net metering specialist.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 1 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 118 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Service ID#:___________
Request #: ___________
INTERCONNECTION AND NET METERING SERVICE AGREEMENT FOR NET
METERING FACILITY
LEVEL 3 INTERCONNECTION
UP TO 2 MW NAMEPLATE CAPACITY
This Interconnection and Net Metering Service Agreement (“Agreement”) is made and
entered into this ____ day of _____________, 20___, by and between
____________________________, an electric customer (“Customer”), and PacifiCorp, dba
Rocky Mountain Power (“Rocky Mountain Power”), a Corporation organized and existing under
the laws of the State of Oregon. Customer and Rocky Mountain Power each may be referred to
as a “Party”, or collectively as the “Parties”.
Recitals:
Whereas, Customer has installed or intends to install a Net Metering Facility qualifying
for “Net Metering,” Utah Rate Schedule No. 135A (“Schedule 135A”), as given in Rocky
Mountain Power’s currently effective tariff as filed with the Public Service Commission of Utah
(“Commission”), on or adjacent to Customer’s premises located at
____________________________, Utah, for the purpose of generating electric energy;
Whereas, the Net Metering rate schedule may be amended from time to time, and the
Public Service Commission may alter the charge, credit, and ratemaking structure applicable to
Net Metering customers pursuant to Utah Code § 54-15-105.1;
Whereas, Customer represents to Rocky Mountain Power that Customer either owns or
leases its Net Metering Facility qualifying for Schedule 135A, or meets the exemption
requirements set forth in Utah Code § 54-2-1.16(d) because it is a county, municipality, city,
town, other political subdivision, local district, special service district, state institution of higher
education, school district, charter school, or any entity within the state system of public
education; or an entity qualifying as a charitable organization under 26 U.S.C. Sec. 501(c)(3)
operated for religious, charitable, or educational purposes that is exempt from federal income tax
and able to demonstrate its tax-exempt status;
Whereas, Customer desires to interconnect the Net Metering Facility with Rocky
Mountain Power’s distribution system consistent with the Application completed by Customer
on _____________ ____, 20___, as described in as described in Appendix C (“Application”) of
this Agreement; and
Whereas, Customer, using its Net Metering Facility, intends to offset part or all of its
electrical requirements supplied by Rocky Mountain Power.
Now, therefore, in consideration of and subject to the mutual covenants contained herein, the
Parties agree as follows:
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 2 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 119 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 1. Scope and Limitations of Agreement
1.1 Scope
The Agreement shall be used for all Level 3 Applications according to the procedures set
forth in Utah Administrative Rule R746-312, as may be amended from time to time
(“Rule”). The Rule can be viewed at www.psc.utah.gov. The Agreement establishes
standard terms and conditions approved by the Public Service Commission of Utah
(“Commission”) under which the Net Metering Facility with an Electric Nameplate
Capacity of 2 MW or smaller as described in Appendix C will interconnect to, and
operate in parallel with, Rocky Mountain Power’s system.
1.2 Definitions
Terms with initial capitalization, when used in this Agreement, shall have the meanings
indicated or as specified in the Rule Section R746-312-2 and, to the extent this
Agreement conflicts with the Rule, the Rule shall take precedence.
1.3 Other Agreements
Nothing in this Agreement is intended to affect any other agreement between Rocky
Mountain Power and Customer or any other Interconnection Customer. However, in the
event that the provisions of the Agreement are in conflict with the provisions of any
Rocky Mountain Power Tariff, as may be amended from time to time the Rocky
Mountain Power Tariff, as may be amended from time to time, shall control.
1.4 Responsibilities of the Parties
1.4.1 The Parties shall perform all obligations of the Agreement in accordance with all
applicable laws and regulations.
1.4.2 Customer will construct, own, operate, test, and maintain its Net Metering Facility
in accordance with the Agreement, IEEE Standards (available at the following
link: http://standards.ieee.org/index.html), National Electric Code Standards
(available for purchase at http://standards.ieee.org/faqs/NESCFAQ.html#q8), Utah
state building codes, the Rule (available at the following link:
http://www.dopl.utah.gov/programs/ubc/), and other applicable standards required
by the Commission, as may be amended from time to time.
1.4.3 Each Party shall be responsible for the safe installation, maintenance, repair and
condition of their respective lines and equipment on their respective sides of the
Point of Common Coupling. Each Party shall provide Interconnection Facilities
that adequately protect the other Party’s facilities, personnel and other persons
from damage and injury. The allocation of responsibility for the design,
installation, operation, maintenance and ownership of Interconnection Facilities is
prescribed in the Rule, including but not necessarily limited to R746-312-4.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 3 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 120 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.4.4
Customer is responsible for protecting the generating equipment, inverters,
protective devices, and other system components from damage from the normal
and abnormal conditions and operations that occur on Rocky Mountain Power’s
system in delivering and restoring power; and is responsible for ensuring that the
Net Metering Facility equipment is inspected, maintained, and tested in
accordance with the manufacturer’s instructions to ensure that it is operating
correctly and safely.
1.4.5 Customer shall obtain Rocky Mountain Power’s approval of the Application prior
to commencing parallel operation of its interconnected Net Metering Facility.
1.4.6 Customer is responsible for all costs associated with its Net Metering Facility.
1.5
Parallel Operation and Maintenance Obligations
Once the Net Metering Facility has been authorized to commence parallel operation by
an approved Application, and execution of this, Customer will abide by all written
provisions for operations and maintenance as required by the Rule and Rocky Mountain
Power’s tariffs, including but not necessarily limited to R746-312-4 and Schedule 135A
or its successor tariff(s).
1.6
Results of System Impact Study
Rocky Mountain Power completed a System Impact Study on_____________ ____,
20___. The System Impact Study shows the following minor modifications or substantial
modifications (Rocky Mountain Power to circle appropriate option) are necessary to
Customer’s Net Metering Facility prior to interconnecting with Rocky Mountain Power’s
system:
Description of necessary minor
modifications_____________________________________________________________
__________________________________________________________.
Rocky Mountain Power estimates, in good faith, that these minor modifications/
substantial modifications (Rocky Mountain Power to circle appropriate option) will cost
$__________. This is a non-binding estimate that will provide break down of
costs:___________________________________________________________________
___________________________________________________________ Customer shall
pay the actual installed cost of the minor modifications or substantial modifications
needed to interconnect the Net Metering Facility to Rocky Mountain Power’s system.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 4 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 121 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.7
Results of Interconnection Facilities Study << to be filled in upon completion of
Interconnection Facilities Study, if one is conducted. Otherwise, the text should read
“This Section intentionally left blank.”>>
Rocky Mountain Power completed a Facilities Study on _____________ ____, 20___.
The Facilities Study shows the following equipment, engineering, procurement and
construction work (including overheads) are necessary to implement the conclusion of
the System Impact Study for Customer’s Net Metering Facility to safely interconnect to
Rocky Mountain Power’s system and the time required to build and install those
facilities:
Rocky Mountain Power estimates, in good faith, that these modifications will cost
$______. This is a non-binding estimate for provide break down of
costs____________________________________________________________________
___________________________________________________________. Customer
shall pay the actual installed cost of the facilities needed to interconnect as identified in
the Facilities Study. Rocky Mountain Power estimates these facilities can be installed
by_____________ ____, 20___.
1.8
Metering
Rocky Mountain Power shall install, own and maintain, at its sole expense, a kilowatthour meter(s) and associated equipment to measure the flow of energy in each direction,
unless otherwise authorized by the Commission. Customer shall provide, at its sole
expense, adequate facilities, including, but not limited to, a current transformer enclosure
(if required), meter socket(s) and junction box, for the installation of the meter and
associated equipment.
Customer hereby consents to the installation and operation by Rocky Mountain Power
and at Rocky Mountain Power’s expense, of one or more additional meters to monitor the
flow of electricity in each direction. Such meters shall be located on the premises of
Customer.
1.9
Power Quality
Customer will design its Net Metering Facility to maintain a composite power delivery at
continuous rated power output at the Point of Common Coupling that meets the
requirements set forth in IEEE 1547, as required by the Rule, R746-312-4.
1.10
Net Metering Facility Inspection
1.10.1 Building Code Inspection
Prior to operation in parallel with Rocky Mountain Power’s system, the Net
Metering Facility must be inspected by a local building code official to ensure
compliance with applicable local codes.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 5 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 122 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
1.10.2 Inspection by Rocky Mountain Power
Rocky Mountain Power may inspect the Net Metering Facility and its component
equipment, and the documents necessary to ensure compliance with the Rule.
Customer shall notify Rocky Mountain Power prior to placing the Net Metering
Facility in service, and Rocky Mountain Power shall have the right to have
personnel present on the in-service date. If the Net Metering Facility is
subsequently modified in order to increase its gross power rating, Customer must
notify Rocky Mountain Power by submitting a new application specifying the
modifications in accordance with the level of review required for that application.
1.11
Anticipated Start Date
Customer must include an anticipated start date for operation of its Net Metering Facility
in the Application.
1.12
Net Metering Facility Testing and Maintenance
Customer shall conduct maintenance and testing as set forth in the Rule, including but not
necessarily limited to R746-312-14.
1.12.1 Customer shall conduct any manufacturer-recommended testing or maintenance at
its expense.
1.12.2 Customer shall conduct any post-installation testing, at its expense, necessary to
ensure compliance with IEEE standards as set forth in the Rule or to ensure
safety. This includes replacing a major equipment component that is different
from the originally installed model.
1.12.3 When Customer performs maintenance or testing in accordance with the Rule, it
must retain written records documenting the maintenance and results of the
testing for three (3) years.
1.13
1.12.4 Rocky Mountain Power shall have the right to inspect Customer’s Net Metering
Facility after interconnection approval is granted, at reasonable hours and with
reasonable prior notice to Customer. If Rocky Mountain Power discovers that the
Net Metering Facility is not in compliance with the Rule, Rocky Mountain Power
may require Customer to disconnect the Net Metering Facility until compliance is
achieved.
Removal of Facility
Customer shall immediately notify Rocky Mountain Power if Customer removes or
ceases to operate the Net Metering Facility.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 6 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 123 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 2.
2.1
Review, Inspection, Testing, Disconnect Switch and Signage, and Right of
Access
Review
After determining Customer’s interconnection request is complete, in accordance with
the Rule, R746-312-10, Rocky Mountain Power will conduct meetings and studies and
provide estimates set forth in the Rule, R746-312-10. Upon completion of the required
studies and receipt of agreement of the Customer to pay for required interconnection
facilities and upgrades, Rocky Mountain Power will approve the Interconnection request.
2.2
Equipment Testing and Inspection
Customer must notify Rocky Mountain Power of the anticipated testing and inspection
date of the Net Metering Facility at least ten (10) business days prior to testing, either
through submittal of the Agreement, a notice of completion, or in a separate notice.
Within ten (10) business days after receipt of such required documentation, Rocky
Mountain Power will conduct any required inspection or witness test of the Net Metering
Facility, set the new meter if required, approve the Interconnection, and provide written
notification to the Customer of the final interconnection authorization/approval and that
the generating facility is authorized/approved for parallel operation.
If Rocky Mountain Power and Customer, by mutual agreement, select a date for the
required inspection and/or witness testing which would prevent Rocky Mountain Power
from providing final written notice within ten (10) days of receipt of required
documentation as specified above, and if the Net Metering Facility satisfactorily passes
the required inspection and/or witness tests, Rocky Mountain Power shall notify
Customer within three (3) business days after the tests and/or inspections that either the
interconnection is approved and the Net Metering Facility may begin operation or the
interconnection facilities study identified necessary construction that has not been
completed, the date upon which the construction will be completed and the date when the
Net Metering Facility may begin operation or state any other reason why the
commissioning tests are not satisfactory.
If the witness tests are not satisfactory, Customer must resolve any deficiencies within
sixty (60) business days or other time period as mutually agreed by the Parties.
2.3
Disconnect Switch and Signage
Customer shall comply with the Rule regarding disconnect switches, R746-312-4. The
disconnect switch may be located more than 10 feet from the public utility meter if
permanent instructions in letters of appropriate size are posted at the meter indicating the
precise location of the disconnect switch. Rocky Mountain Power must approve in
writing the location of the disconnect switch prior to the installation of the Net Metering
Facility.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 7 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 124 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
2.4 Right of Access
As provided in the Rule, R746-312-4, Rocky Mountain Power shall have access to any
required disconnect switch at the Net Metering Facility at all times. Rocky Mountain
Power will provide reasonable notice to Customer when possible prior to using its right
of access. Additionally, as provided in Rocky Mountain Power Utah Rule 6, or its
successor tariff, Rocky Mountain Power shall have access to the metering equipment.
Article 3.
3.1
Effective Date, Term, Termination and Disconnection
Effective Date
The Agreement shall become effective upon execution by the Parties.
3.2
Term of Agreement
The Agreement will become effective on the Effective Date and will remain in effect
unless terminated in accordance with provisions of this Agreement, or Order by the
Commission.
3.3
Termination
No termination will become effective until the Parties have complied with all applicable
laws and clauses of this Agreement applicable to such termination.
3.3.1
Customer may terminate this Agreement at any time by giving Rocky Mountain
Power twenty (20) business days written notice.
3.3.2
Either Party may terminate this Agreement after default pursuant to Article 5.4 of
this Agreement.
3.3.3
The Commission may Order termination of this Agreement.
3.3.4
Upon termination of this Agreement, Customer shall disconnect the Net Metering
Facility from Rocky Mountain Power’s system. The termination of this
Agreement will not relieve either Party of its liabilities and obligations, owed or
continuing at the time of termination.
If Customer removes the Net Metering equipment at the Net Metering Facility or
ceases to operate its Net Metering Facility at the premise listed in the Application,
this Agreement will be immediately terminated.
3.3.5
3.3.6
The provisions of this Article shall survive termination or expiration of this
Agreement.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 8 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 125 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
3.4
Temporary Disconnection
3.4.1
Rocky Mountain Power may temporarily disconnect the Net Metering Facility
from Rocky Mountain Power’s system for so long as reasonably necessary
without prior notice to Customer in the event one or more of the following
conditions or events occurs:
3.4.1.1
Emergencies or to address maintenance requirements for Rocky
Mountain Power’s system.
3.4.1.2
Hazardous conditions existing on Rocky Mountain Power’s system
which may affect the safety of the general public or Rocky Mountain
Power employees due to the operation of the Net Metering Facility or
protective equipment as determined by Rocky Mountain Power.
3.4.1.3
Adverse electrical effects on the electrical equipment of Rocky
Mountain Power’s other electric customers caused by the Net Metering
Facility as determined by Rocky Mountain Power.
3.4.2
In the event that no disconnect switch is installed, Rocky Mountain Power may
physically disconnect all service to the Customer or all service to the premises
where the Net Metering Facility is located, or both.
3.4.3
To the extent practicable, Rocky Mountain Power will give prior notice of any
temporary disconnection of the Net Metering Facility. If Rocky Mountain Power
is unable to give prior notice, Rocky Mountain Power will provide notice
including an explanation of the condition necessitating the disconnection at the
time of disconnection.
3.4.4
Under emergency conditions, Rocky Mountain Power shall notify Customer
promptly when Rocky Mountain Power becomes aware of an emergency
condition that may reasonably be expected to affect the Net Metering operation.
Customer shall notify Rocky Mountain Power promptly when it becomes aware
of an emergency condition that may reasonably be expected to affect Rocky
Mountain Power’s system. To the extent the information is known, the
notification shall describe the emergency condition, the extent of any damage or
deficiency, the expected effect on the operation of both Parties’ facilities and
operations, the anticipated duration, and the necessary corrective action.
3.4.5
Customer shall make reasonable efforts to provide notice of interruption of Net
Metering Facility operation for safety and/or reliability reasons prior to the
interruption unless an emergency occurs. Emergency interruptions or temporary
terminations are subject to Section 3.4.4 above.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 9 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 126 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
3.4.6
Rocky Mountain Power shall use reasonable efforts to provide Customer with
prior notice of forced outages to effect immediate repairs to Rocky Mountain
Power’s system. If prior notice is not given, Rocky Mountain Power, shall, upon
request, provide Customer written documentation after the fact explaining the
circumstances of the disconnection.
3.4.7
Customer must provide Rocky Mountain Power notice and obtain Rocky
Mountain Power’s written approval before Customer may modify its Net
Metering Facility in order to increase the electric output of the Net Metering
Facility. If Customer makes any material change without prior written
authorization of Rocky Mountain Power, Rocky Mountain Power will have the
right to temporarily disconnect the Net Metering Facility until Rocky Mountain
Power has had an opportunity to review the change(s) made to determine whether
they are acceptable. If any system modifications or other equipment installations
are deemed necessary by Rocky Mountain Power to accommodate the modified
Net Metering Facility, Customer shall submit the appropriate net metering
application at that time.
3.4.8
The Parties shall cooperate with each other to restore the Net Metering Facility,
Interconnection Facilities, and Rocky Mountain Power’s system to their normal
operating state as soon as reasonably practicable following any disconnection
pursuant to this section.
Article 4.
4.1
Cost Responsibility
Application Fee
Customer shall bear the cost of any Application fee provided for in the Rule, R746-31213(2), or as otherwise approved by the Commission. Customer shall remit payment with
the Application as calculated in Appendix C, the Application, Section 2.C.
4.2
Net Metering Facility and Interconnection Equipment
Customer shall be responsible for all costs, including overheads, associated with
procuring, installing, owning, operating, maintaining, repairing, and replacing its Net
Metering Facility, any associated equipment package, and any associated interconnection
equipment or interconnection facilities required to be installed on Customer’s side of the
Point of Common Coupling as detailed in the results of the System Impact Study or
Facilities Study, or both.
4.3
Minor Modifications
This section shall apply if the System Impact Study performed pursuant to Section 1.6
above shows that minor modifications to the electric distribution system are required to
enable the interconnection to be made consistent with safety, reliability and power quality
standards applicable to Level 3 interconnection reviews. The Customer shall pay for the
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 10 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 127 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
cost to procure, install, and construct, operate, maintain, repair and replace any such
minor modifications. A description of the minor modifications may be found in Appendix
A. The cost of the minor modifications as described on Appendix A shall be $_______.
Customer shall remit payment for minor modifications prior to Rocky Mountain Power
commencing the work required for the minor modifications.
4.4
4.5
Substantial Modifications
4.4.1
This section shall apply if the System Impact Study performed pursuant to Section
1.6 above or the Facilities Study performed pursuant to Section 1.7 above, or
both, shows that substantial modifications to the electric distribution system are
required to enable the interconnection to be made consistent with safety,
reliability and power quality standards applicable to Level 3 interconnection
reviews. The Customer shall pay for the cost to procure, install, and construct,
operate, maintain, repair and replace any such substantial modifications. A
description of the substantial modifications may be found in Appendix B. The
cost of the substantial modifications as described on Appendix B shall be
$_______.
4.4.2
Before beginning substantial modifications to accommodate the interconnection
of the Net Metering Facility to Rocky Mountain Power’s system, Rocky
Mountain Power may require that Customer pay a deposit of not more than 50%
of the estimated cost of procuring, installing and constructing equipment and
facilities to be procured, installed or constructed by Rocky Mountain Power.
Payment
Rocky Mountain Power may require progress payments from Customer or Rocky
Mountain Power may wait until construction and installation of all equipment and
facilities are complete and the total actual cost of such equipment and facilities has been
established and then provide Customer with a statement indicating whether actual cost
was more or less than the deposit paid by Customer-Generator. If actual costs exceed the
deposit, Rocky Mountain Power will invoice Customer-Generator for the balance and
Customer-Generator shall pay any such invoice within 30 days of receipt. If actual costs
are less than the deposit, Rocky Mountain Power will refund the difference to CustomerGenerator.
Article 5.
5.1
Billing
Monthly Billing
The electric service charge shall be computed in accordance with the monthly billing in
the currently applicable standard service tariff. Customer will be compensated for net
excess energy in accordance with Schedule 135A or its successor tariff(s). Customer will
be transitioned to any successor tariff immediately upon approval of that tariff by the
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 11 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 128 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Public Service Commission and will be subject to any charge, credit, or ratemaking
structure implemented therein.
5.2
Special Conditions
Customer must comply with the special conditions found in Schedule 135A or its
successor tariff(s).
5.3
Aggregating Meters
Aggregating Meters is allowed if certain conditions are met under the Rule, R746-312-5.
Customer designates the following meters for aggregation: _______________________.
In the event that the Net Metering Facility supplies more electricity to Rocky Mountain
Power than the Customer uses from Rocky Mountain Power, Rocky Mountain Power will
apply any credits to the next monthly bill in accordance with Utah Code § 54-15-104 and
the Rule, R746-312-15. Customer shall designate the order in which to apply any credits
in accordance with the Rule. <<If customer does not want to aggregate, insert “N\A” in
the gray box.>>
Article 6.
6.1
Assignment, Liability, Indemnity, Force Majeure, Consequential Damages
and Default
Assignment
This Agreement may be assigned by either Party with the consent of the other Party. A
Party’s consent to an assignment may not be unreasonably withheld. The assigning Party
must give the non-assigning Party written notice of the assignment at least fifteen days
(15) before the effective date of the assignment. The non-assigning Party must submit its
objection to the assignment, if any, to the assigning Party in writing at least 5 business
days before the effective date of the assignment. If a written objection is not received
within that time period, the non-assigning party is deemed to consent to the assignment.
6.1.1 Exceptions to the Consent Requirement
6.1.1.1 Either Party may assign the Agreement without the consent of the other
Party to any affiliate (including a merger or acquisition of the Party with
another entity), of the assigning Party with an equal or greater credit rating
and with the legal authority and operational ability to satisfy the
obligations of the assigning Party under this Agreement.
6.1.1.2 Customer-Generator is entitled to assign the Agreement, without the
consent of Rocky Mountain Power, for collateral security purposes to aid
in obtaining financing for the Net Metering Facility.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 12 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 129 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
6.1.1.3 For Net Metering systems that are integrated into a building facility, the
sale of the building or property will result in the automatic assignment of
this Agreement to the new owner who will be responsible for complying
with the terms and conditions of this Agreement.
6.1.2
6.2
Any attempted assignment that violates this Article is void and ineffective.
Assignment does not change or eliminate a Party’s obligations under this
Agreement. An assignee is responsible for meeting the same obligations as the
assigning Party.
Limitation of Liability and Consequential Damages
Each Party’s liability to the other Party for any loss, cost, claim, injury, liability, or
expense, including reasonable attorney’s fees, relating to or arising from any act or
omission in its performance of this Agreement, is limited to the amount of direct damage
actually incurred. Neither Party is liable to the other Party for any indirect, special,
consequential, or punitive damages.
6.3
Indemnification
Customer shall hold harmless and indemnify Rocky Mountain Power for all loss to third
parties resulting from the operation of the Net Metering Facility, except when the loss
occurs due to the negligent actions of Rocky Mountain Power.
Rocky Mountain Power shall hold harmless and indemnify Customer for all loss to third
parties resulting from the operation of Rocky Mountain Power’s system, except where
the loss occurs due to the negligent actions of Customer.
6.4 Force Majeure
6.4.1
As used in this Agreement, a Force Majeure Event shall mean “any act of God,
labor disturbance, act of the public enemy, war, acts of terrorism, insurrection,
riot, fire, storm or flood, explosion, breakage or accident to machinery or
equipment through no direct, indirect, or contributory act of a Party, any order,
regulation, or restriction imposed by governmental, military or lawfully
established civilian authorities, or any other cause beyond a Party’s control. A
Force Majeure Event does not include an act of negligence or wrongdoing.”
6.4.2
If a Force Majeure Event prevents a Party from fulfilling any obligations under
this Agreement, the Party affected by the Force Majeure Event (“Affected Party”)
shall promptly notify the other Party of the existence of the Force Majeure Event.
The notification must specify in reasonable detail the circumstances of the Force
Majeure Event, the expected duration, and the steps that the Affected Party is
taking to mitigate the effects of the event on its performance, and if the initial
notification was verbal, it should be promptly followed up with a written
notification. The Affected Party shall keep the other Party informed on a
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 13 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 130 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
continuing basis of developments relating to the Force Majeure Event until the
event ends. The Affected Party will be entitled to suspend or modify its
performance of obligations under this Agreement (other than the obligation to
make payments) only to the extent that the effect of the Force Majeure Event
cannot be reasonably mitigated. The Affected Party will use reasonable efforts to
resume its performance as soon as possible. The Parties shall immediately report
to the Commission should a Force Majeure Event prevent performance of an
action required by Rule that the Rule does not permit the Parties to mutually
waive.
6.5
Default
6.5.1
A Party is in default if the Party fails to perform an obligation required under this
Agreement (other than the payment of money). A Party is not considered in
default of this agreement if the failure to perform an obligation is caused by an act
or omission of the other Party or is the result of a Force Majeure as defined in this
Agreement.
6.5.2
Upon a default, the non-defaulting Party must give written notice of the default to
the defaulting party. The defaulting party has sixty (60) calendar days from the
receipt of the written default notice to cure the default. If the default is not capable
of cure within the 60-day period, the defaulting Party must begin to cure the
default within twenty (20) calendar days after receipt of the written default notice,
and must continuously and diligently complete the cure within six (6) months of
the receipt of the notice.
6.5.3
If a default is not cured as provided for in 6.5.2, then the non-defaulting Party is
entitled to terminate the Agreement by written notice at any time until cure
occurs. If the non-defaulting Party chooses to terminate this Agreement, the
termination provisions in Article 3.3 apply. Alternately, the non-defaulting Party
is entitled to seek dispute resolution with the Commission in lieu of termination.
Article 7.
Insurance
Additional liability insurance is not required as a part of the Agreement if the Net Metering
Facility is in compliance with the provisions of the Application approval, the Agreement and the
standards contained in Utah Code § 54-15-106.
Article 8.
Dispute Resolution
8.1
Nothing in this Article shall restrict the rights of any Party to file a Complaint with the
Commission under relevant provisions of the Rule and applicable state law.
8.2
Pursuit of dispute resolution may not affect Customer with regard to consideration of an
Interconnection Request or Customer’s queue position.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 14 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 131 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Article 9.
9.1
Miscellaneous
Governing Law, Regulatory Authority and Rules
The validity, interpretation, and enforcement of this Agreement is governed by the laws
of the State of Utah. If any provision of this Agreement conflicts with any applicable
provision, as may be amended from time to time, of the Utah Code (“Code”), Utah
Administrative Rules (“Rules”), or Rocky Mountain Power’s Tariffs (“Tariff”), then the
applicable provision of the Code, Rules, or Tariff controls. Rocky Mountain Power must
provide copies of the applicable provisions of the Code, Rules, and Tariff upon the
Customer’s request.
9.2
Amendment
Additions, deletions or changes to the standard terms and conditions of this Agreement
will not be permitted unless they are mutually agreed to by the Parties and permitted by
the Rule or permitted by the Commission for good cause shown. The Parties may amend
the Agreement by a written instrument duly executed by both Parties in accordance with
the provisions of the Rule and applicable Commission Orders and provisions of the laws
of the State of Utah.
9.3
No Third Party Beneficiaries
The Agreement is not intended to and does not create rights, remedies, or benefits of any
character whatsoever in favor of any persons, corporations, associations, or entities other
than the Parties, and the obligations herein assumed are solely for the use and benefit of
the Parties, or where permitted, their successors in interest or their assigns.
9.4
Waiver
9.4.1 The failure of a Party to the Agreement to insist, on any occasion, upon strict
performance of any provision of the Agreement, will not be considered a waiver
of any obligation, right, or duty of, or imposed upon, such Party.
9.4.2
The Parties may agree to mutually waive a Section of this Agreement without the
Commission’s approval in accordance with the Rule.
9.4.3
Any waiver at any time by either Party of its rights with respect to the Agreement
shall not be deemed a continuing waiver or a wavier with respect to any other
failure to comply with any other obligation, right, or duty of the Agreement.
Termination or default of this Agreement for any reason by Customer shall not
constitute a waiver of the Customer’s legal rights to obtain interconnection from
Rocky Mountain Power. Any request for waiver of the Agreement or any
provisions thereof shall be provided in writing.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 15 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 132 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
9.5
Entire Agreement
The Agreement, including any supplementary attachments that may be necessary,
constitutes the entire Agreement between the Parties with reference to the subject matter
hereof, and supersedes all prior and contemporaneous understandings or agreements, oral
or written, between the Parties with respect to the subject matter of the Agreement. There
are no other agreements, representations, warranties, or covenants that constitute any part
of the consideration for, or any condition to, either Party’s compliance with its
obligations under the Agreement.
9.6
Multiple Counterparts
This Agreement may be executed in one or more counterparts, whether electronically or
otherwise, each of which is deemed an original but all constitute one and the same
instrument.
9.7
No Partnership
The Agreement will not be interpreted or construed to create an association, joint venture,
agency relationship, or partnership between the Parties or to impose any partnership
obligation or partnership liability upon either Party. Neither Party shall have any right,
power or authority to enter into any agreement or undertaking for, or act on behalf of, or
to act as or be an agent or representative of, or to otherwise bind, the other Party.
9.8
Severability
If any provision or portion of the Agreement shall for any reason be held or adjudged to
be invalid or illegal or unenforceable by any court of competent jurisdiction or other
governmental authority, (1) such portion or provision shall be deemed separate and
independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable
the benefits to each Party that were affected by such ruling, and (3) the remainder of the
Agreement shall remain in full force and effect.
9.9
Subcontractors
Nothing in the Agreement shall prevent a Party from using the services of any
subcontractor, or designating a third party agent as one responsible for a specific
obligation or act required in the Agreement (collectively subcontractors), as it deems
appropriate to perform its obligations under the Agreement; provided, however, that each
Party will require its subcontractors to comply with all applicable terms and conditions of
the Agreement in providing such services and each Party will remain primarily liable to
the other Party for the performance of the subcontractor.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 16 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 133 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
9.10
9.9.1
The creation of any subcontract relationship shall not relieve the hiring Party of
any of its obligations under the Agreement. The hiring Party shall be fully
responsible to the other Party for the acts or omissions of any subcontractor the
hiring Party hires as if no subcontract had been made. Any applicable obligation
imposed by the Agreement upon the hiring Party shall be equally binding upon,
and will be construed as having application to, any subcontractor of such Party.
9.9.2
The obligations under this Article will not be limited in any way by any limitation
of a subcontractor’s insurance.
Reservation of Rights
Rocky Mountain Power shall have the right to make a unilateral filing with the
Commission to modify this Agreement with respect to any rates, terms and conditions,
charges, classifications of service, rule, regulation or any other applicable provision of
the Federal Power Act and the Commission’s rules and regulations thereunder, and
Customer shall have the right to make a unilateral filing with Commission to modify this
Agreement under any applicable provision of the Federal Power Act and the
Commission’s rules and regulations; provided that each Party shall have the right to
protest any such filing by the other Party and to participate fully in any proceeding before
the Commission in which such modifications may be considered. Nothing in this
Agreement shall limit the rights of the Parties, except to the extent that the Parties
otherwise agree as provided herein.
Article 10.
10.1
Notices and Records
General
Unless otherwise provided in the Agreement, any written notice, demand, or request
required or authorized in connection with the Agreement shall be deemed properly given
if delivered in person, delivered by recognized national courier service, sent by first class
mail, postage prepaid, or by electronic mail if an electronic mail address is provided
below to the person specified below:
If to Customer:
Customer: ______________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: ________________________________ State: _________________ Zip: ________
Phone: (___) _______________________ Fax: (____) ___________________________
Email: __________________________________________________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 17 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 134 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If to Rocky Mountain Power:
By Mail:
Rocky Mountain Power
Attention: Net Metering Group
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
Or
By email:
[email protected]
10.2
Records
Rocky Mountain Power will maintain a record of all Interconnection Agreements and
related Attachments, if any, for as long as the interconnection is in place. Rocky
Mountain Power will provide a copy of these records to Customer within fifteen (15)
Business Days upon written request.
10.3
Billing and Payment
Billings and payments shall be sent to the addresses below (complete if different from
Section 9.1 above):
If to Customer:
Customer: ______________________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: _______________________________ State: _______________ Zip: ___________
10.4
Designated Operating Representative
The Parties will designate an operating representative each to conduct the
communications that may be necessary or convenient for the administration of the
operations provisions of the Agreement. This person will also serve as the point of
contact with respect to operations and maintenance of the Party’s facilities (complete if
different from Section 9.1 above):
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 18 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 135 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Customer’s Operating Representative:
Name: __________________________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: ______________________________ State: ________________ Zip: ___________
Phone: (____) _______________________ Fax: (____) __________________________
Email: __________________________________________________________________
10.5
Changes to the Notice Information
Either Party may change this notice information by giving five (5) business days written
notice prior to the effective date of the change.
Article 11.
Signatures
IN WITNESSETH WHEREOF, the Parties have caused the Agreement to be executed by their
respective duly authorized representatives.
For the Customer:
For Rocky Mountain Power:
By: _____________________________
By: _____________________________
Name: ___________________________
Name: ___________________________
Title: ____________________________
Title: ____________________________
Date: ____________________________
Date: ____________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 19 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 136 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Appendix A
Minor Modifications
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 20 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 137 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Appendix B
Substantial Modifications
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 21 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 138 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
APPENDIX C
ROCKY MOUNTAIN POWER UTAH NET METERING APPLICATION
LEVEL 3 REVIEW
CAPACITY OF 2 MW OR LESS
Section 1: For Rocky Mountain Power Use Only
Customer Name: _________________________________________________________________________
Service Address: _________________________________________________________________________
City, State, Zip: ___________________________________________________________________________
Customer Account No. and Request No.: _______________________________________________________
Interconnection Agreement Acknowledgement (Date): ____________________________________________
Application fee: $______________________________ Date Paid ___________________________________
Section 2: To Be Completed By Customer
A. Applicant Information
Name: ___________________________________________________________________________
Mailing Address: __________________________________________________________________
City: __________________________________________State: _________ Zip Code: ____________
Site Street Address (if different from above): _____________________________________________
City: __________________________________________State: __________ Zip Code: ___________
Daytime Phone: (_____) ________________________ Fax: (_____) __________________________
Email: ____________________________________________________________________________
B. System Information
System Type:
Solar
Wind
Hydro
Other (Specify): _________________________
Generation Nameplate Capacity: ______________ kW (Combine DC total of wind turbines, solar
panels, etc. or AC rating if an inverter is not utilized)
Inverter Manufacturer: ___________ Model: ________ Number of Inverters: _____ Rating: _____ kW
Manufacturer Nameplate Inverter Total AC Capacity Rating: _________ kW
Inverter(s):
Single Phase
Three Phase
Multiple Single Phase Connected on Poly-phase
(three phase) system – (Attach Inverter and Panel Technical Specifications Sheets)
Type:
Induction
Type of Service:
Inverter
Single Phase
Synchronous
__________________Other
Three Phase
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 22 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 139 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
If Three Phase Transformer:
Indicate Type:
Wye
Delta
Indicate Voltage and Number of Service Wires:
120/208 Volts, 4 wire 120/240 Volts, 4 wire 277/480 Volts, 4 wire
Other ___________
________________________________________________________________________________
Other Information:__________________________________________________________________
_________________________________________________________________________________
Self Contained Location: ____________________________________________________________
Outdoor Manual AC Disconnect Switch Location (show Disconnect Switch and Rocky Mountain
Power Meter Location on Site Plan), unless exempt under Utah Administrative Rule 746-312-4(2):
__________________________________________________________________________________
System Location (show all protective devices on One Line Diagram):___________________________
Will the net metering facility interconnect to a switchgear?
Yes
No
Customer must post metal or plastic engraved signage indicating on-site generation in accordance with
National Electric Code. The signage must be permanent and located adjacent to the meter base and
disconnect switch noting “Parallel Generation on Site” and identifying the manual disconnect switch
with the words “Manual Disconnect for Parallel Generation.” _____ (Initial Here)
One Line Diagram Attached:
Installation Test Plan attached:
Yes
Yes
No
Site Plan Attached:
Yes
No
No
Anticipated Operational Date of Net Metering Facilities: _____________________________________
(Rocky Mountain Power must be notified at least ten (10) business days prior to starting operation.)
Net metering facility available fault duty at the point of common coupling: ________________
(A Rocky Mountain Power Engineer may contact you for additional information)
Electrical Inspection approval date (attach copy or provide to utility when obtained):__________
C. Application Fees
$ 1050.00
+ $ __________
$ __________
Base
$3.00 x _____ kW of net metering facility’s capacity
TOTAL APPLICATION FEE
D. Additional Information
1.
An equipment package will be considered certified for interconnected operation if it has been
submitted by a manufacturer to a nationally recognized testing and certification laboratory, and
has been tested and listed by the laboratory for continuous interactive operation with an electric
distribution system in compliance with the applicable IEEE and UL 1741 standards, as set forth
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 23 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 140 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
2.
3.
4.
5.
6.
7.
in the Rule.
If the equipment package has been tested and listed as an integrated package, which includes a
generator or other electric source, the equipment package will be deemed certified, and Rocky
Mountain Power will not require any further design review, testing or additional information.
If the equipment package includes only the interface components (switchgears, inverters, or
other interface devices), an interconnection applicant must show that the generator or other
electric source being utilized with the equipment package is compatible with the equipment
package and consistent with the testing and listing specified for the package. If the generator or
electric source being utilized with the equipment package is consistent with the testing and
listing performed by the nationally recognized testing and certification laboratory, the equipment
package will be deemed certified and Rocky Mountain Power will not require further design
review, testing or additional equipment.
A net metering facility must be equipped with metering equipment that can measure the flow of
electricity in both directions, comply with ANSI C12.1 standards and Utah Administrative Rule
R746-312. Rocky Mountain Power will install the required metering equipment at Rocky
Mountain Power’s expense.
Rocky Mountain Power will not be responsible for the cost of determining the rating of
equipment owned by the customer-generator or of equipment owned by other local customers.
Customer may operate the Net Metering Facility temporarily for testing and obtaining inspection
approval. Customer shall not operate the Net Metering Facility in continuous parallel without an
executed Interconnection and Net Metering Service Agreement, and approval from Rocky
Mountain Power.
Customer will pay to Rocky Mountain Power at the time of application the applicable
Application fee of $1500.00 plus $23.00 per kilowatt of the net metering facility’s capacity; and
costs of modifications or additional review as set forth in Utah Administrative Rule R746-312
prior to commencement of work.
E. Customer Acknowledgment
I certify that the information provided in this Application is true. I will provide Rocky Mountain Power a
copy of the signed government electrical inspection approval document when obtained, if not already
provided with this Application.
I agree to abide by the terms of this Application and I agree to notify Rocky Mountain Power thirty (30)
days prior to modification or replacement of the System’s components or design. Any such modification
or replacement may require submission of a new Application to Rocky Mountain Power.
I agree not to operate the Net Metering Facility in parallel with Rocky Mountain Power, except
temporarily for testing and obtaining inspection approval, until this Application is approved by Rocky
Mountain Power, until this agreement is signed by both parties, and until I have provided Rocky
Mountain Power with at least five (5) days notice of anticipated start date.
Customer or Applicant Signature & Date: ____________________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 24 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 141 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Please send completed application to:
Rocky Mountain Power
Attention: Customer Generation
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
or
Please scan the completed application and email
[email protected]
Section 3. To be completed by System Installer
Installation Contractor Information/Hardware and Installation Compliance
Installation Contractor (Company Name): _______________________________________________________
Contractor's License No.: ____________________________ Proposed Installation Date: _________________
Mailing Address: __________________________________________________________________________
City: ____________________________________________ State: __________ Zip Code: _______________
Daytime Phone: _________________ Fax: _________________Email: ______________________________
For inverter-controlled system, meets IEEE Standards and UL 1741 Inverters, Converters, and
Controllers for use in Independent Power Systems as set forth in the Rule:
Yes
No
For induction or synchronous device, meets IEEE Standard 1547 and IEEE/ANSI Standard C37.90 requirements
as set forth in the Rule:
Yes
No
If Photovoltaic System, System must be installed in compliance with IEEE Standards, Recommended Practice
for Utility Interface of Photovoltaic Systems. All System types must be installed in compliance with applicable
requirements of local electrical codes, Rocky Mountain Power and the National Electrical Code® (NEC) and
must use an anti-islanding inverter.
The System must include a manual, lockable, load-break (disconnect) switch, unless exempt under Utah
Administrative Rule 746-312-4(2), accessible at all times to Rocky Mountain Power personnel and located
within 10 feet of Rocky Mountain Power’s meter. The disconnect switch may be located more than 10 feet from
Rocky Mountain Power’s meter if permanent instructions are posted at the meter indicating the precise location
of the disconnect switch. Rocky Mountain Power must approve the location of the disconnect switch prior to the
installation of the net metering facility.
If the Net Metering Facility is designed to provide uninterruptible power to critical loads, either through energy
storage, back-up generator, or the generation source, the Net Metering Facility will include a parallel blocking
scheme for this backup source. This function may be integral to the inverter manufacturer’s packaged system.
Does the Net Metering Facility include a parallel blocking scheme:
Yes
No
Signed (Contractor): ________________________________________ Date: _________________
Name (Print): _______________________________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 25 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-2) Page 142 of 142
Docket No. 16-035-__
Witness: Joelle R. Steward
Section 4. To be completed by Rocky Mountain Power:
A. If approving the application:
Rocky Mountain Power does not, by approval of this Application, assume any responsibility or liability
for
damage to property or physical injury to persons. Further, this Application does not constitute a
dedication of the owner's System to Rocky Mountain Power electrical system equipment or facilities.
Customer-Generator entered into an Interconnection and Net Metering Service Agreement with Rocky
Mountain Power on the ____ day of _____, 20__.
Customer-Generator satisfactorily passed Witness Tests on the ____ day of _________, 20__.
(Rocky Mountain Power may waive Witness Tests at its option; if tests are waived initial here ____)
This Application is approved by Rocky Mountain Power on this ______ day of ______________, 20__
Rocky Mountain Power Representative Name (Print): _______________________________________
Signed (Rocky Mountain Power Representative): ________________________ Date: ____________
B. If denying the application:
This application is denied by Rocky Mountain Power on this ______ day of ____________, 20__ for
the following reason(s): _______________________________________________________________
Rocky Mountain Power Representative Name (Print): _______________________________________
Signed (Rocky Mountain Power Representative): ___________________________ Date: __________
Section 5. To be completed by Rocky Mountain Power Meterman
Customer Account No. ______________________________ Site ID No. : ___________________________
Served from Facility Point No.: ________________________________
New Net Meter No.: ___________________________ Date net meter installed: _______________________
Manual disconnect device in proper location and permanent signage in place:
Yes
No
Signature/Title: ________________________________________ Date: ____________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 - Level 3
Page 26 of 26
Rocky Mountain Power
Exhibit RMP___(JRS-3)
Docket No. 16-035-__
Witness: Joelle R. Steward
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Joelle R. Steward
Proposed Rates - Schedule 5
November 2016
$3,768,412
$912,073
$2,023,901
23,911,758
23,911,758
228,598
52,335
348
Billed Units
3.8143
$9.02
$15.00
$30.00
$785,025
$10,440
$912,066
$3,769,485
$2,061,954
*On‐peak periods with 60 minute interval:
October ‐ April 8:00 a.m. to 10:00 a.m., 3:00 p.m. to 8:00 p.m. Monday‐Friday, except holidays.
May ‐ September 3:00 p.m. to 8:00 p.m., Monday‐Friday, except holidays.
Customer Charge
1 Phase
3 Phase
Demand Charge
On-peak ($/kW)*
Energy Charge
All kWh (¢\kWh)
Total
COS Rev
$832,438
Proposed
Price
Revenue
Rocky Mountain Power - State of Utah
Blocking Based on Adjusted Actuals
Base Period 12 Months Ending December 2015
Schedule No. 135 - Residential Service - Net Metering
Rocky Mountain Power
Exhibit RMP___(JRS-3) Page 1 of 1
Docket No. 16-035-__
Witness: Joelle R. Steward
Rocky Mountain Power
Exhibit RMP___(JRS-4)
Docket No. 16-035-__
Witness: Joelle R. Steward
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Joelle R. Steward
Peak Period Occurrences
November 2016
Rocky Mountain Power
Exhibit RMP___(JRS-4) Page 1 of 1
Docket No. 16-035-__
Witness: Joelle R. Steward
Hourly Occurrence of Peaks from Last Five Filed Cost of Service Studies
(Docket No. 11-035-200, Docket No. 13-035-184, 2013 Annual, 2014 Annual, 2015 Annual)
Count
Summer Months (May - Sept)
20
18
16
14
12
10
8
6
4
2
0
1
3
5
7
9 11 13 15 17 19 21 23
MST Hour Ending
System Coincident Peaks
Distribution Coincident Peaks
Count
Winter Months (Oct - Apr)
20
18
16
14
12
10
8
6
4
2
0
1
3
5
7
9 11 13 15 17 19 21 23
MST Hour Ending
System Coincident Peaks
Distribution Coincident Peaks
Rocky Mountain Power
Exhibit RMP___(JRS-5)
Docket No. 16-035-__
Witness: Joelle R. Steward
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Joelle R. Steward
Example of Interval Demand Measurements
November 2016
kW
0
1
2
3
4
5
6
7
8
9
10
1
6
16
21
26
Lights
Television
Cooking stove Microwave
11
36
Washer/Dryer
Vacuum
Minutes
31
46
Central A/C
41
51
56
Average Demand:
Over 15 Minutes is 6.3 kW
Over 30 Minutes is 4.9 kW
Over 60 Minutes is 3.4 kW
Example of Appliance Usage During an Hour
Rocky Mountain Power
Exhibit RMP___(JRS-5) Page 1 of 1
Docket No. 16-035-__
Witness: Joelle R. Steward
Rocky Mountain Power
Exhibit RMP___(JRS-6)
Docket No. 16-035-__
Witness: Joelle R. Steward
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Joelle R. Steward
Calculation of Offset Credit
November 2016
Units
$000
MWh
¢/kWh
Line
4
5
6
Description
Bill Credits Under Proposed Rates
Private Generation Production
Offset Credit
Units
$000
MWh
¢/kWh
Line Description
1
Bill Credits
2
Private Generation Production
3
Offset Credit
Offset Credit Level with Proposed Rates
Current Offset Credit Level
Residential Offset Credits from Private Generation
Value
1,996
28,304
0.0705
Value
2,987
28,304
0.1055
Rocky Mountain Power
Exhibit RMP___(JRS-6) Page 1 of 1
Docket No. 16-035-__
Witness: Joelle R. Steward
Rocky Mountain Power
Exhibit RMP___(JRS-7)
Docket No. 16-035-__
Witness: Joelle R. Steward
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Joelle R. Steward
Bill Impact Summary
November 2016
Rocky Mountain Power
116
29%
977
1.47
% of DG Production to Full Requirements Energy Usage
0%
0%
10%
25%
50%
75%
100%
Present Proposed % Change Proposed % Change Proposed % Change Proposed % Change Proposed % Change Proposed % Change
$55.4
$55
-2%
$53
-5%
$49
-11%
$44
-20%
$39
-29%
$34.23
-38%
$84.6
$84
-1%
$71
-16%
$67
-21%
$59
-30%
$51
-39%
$34.23
-60%
$113.9
$103
-9%
$99
-13%
$84
-26%
$74
-35%
$63
-44%
$43.74
-62%
$146.3
$123
-16%
$118
-19%
$110
-25%
$88
-40%
$75
-48%
$53.26
-64%
$178.8
$143
-20%
$137
-24%
$127
-29%
$103
-43%
$88
-51%
$62.77
-65%
$211.2
$162
-23%
$155
-26%
$145
-32%
$117
-44%
$90
-57%
$72.28
-66%
$243.6
$192
-21%
$174
-29%
$162
-34%
$132
-46%
$102
-58%
$81.80
-66%
$308.5
$231
-25%
$221
-28%
$196
-36%
$161
-48%
$126
-59%
$91.31
-70%
$373.4
$270
-28%
$258
-31%
$230
-38%
$190
-49%
$150
-60% $110.34
-70%
Assumptions
1. Average monthly DG generation kWh/kW
2. Average on-peak load factor %
3. Average monthly Full kWh for Residential NM customer
4. DG demand impact index: on-peak kW/MWh
5. Estimated on-peak kW = Full kWh/(730*29%) - DG MWh x 1.47
Full Requirements
Monthly kWh
500
750
1,000
1,250
1,500
1,750
2,000
2,500
3,000
Rocky Mountain Power
Monthly Billing Comparison
Schedule 136 - State of Utah
Bill Savings from Proposed Schedule 5 Rates for New Residential NEM Customers
Rocky Mountain Power
Exhibit RMP___(JRS-7) Page 1 of 1
Docket No. 16-035-__
Witness: Joelle R. Steward
Exhibit RMP___(JRS-8)
Docket No. 16-035-__
Witness: Joelle R. Steward
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Joelle R. Steward
Proposed Application Fee Calculation
November 2016
Application Fee Costs
Administration Cost
Initial Setup Customer Service Cost
Engineering Cost
Total Cost Related to Net Metering Application
Application Quantity
Tier 1 Applications
Tier 2 Applications
Tier 3 Applications
Total Application Quantity
% of Applications in Tier 2 or 3
Application Fee Revenue
KW in Tier 2 Applications
KW in Tier 3 Applications
Price per KW (Tier 1)
Price per KW (Tier 2)
Price per KW (Tier 3)
Price per Tier 1 Application
Price per Tier 2 Application
Price per Tier 3 Application
Tier 2 and 3 Revenue
Cost per Application
Proposed Application Fee Revenue
Proposed Price per KW (Tier 1)
Proposed Price per KW (Tier 2)
Proposed Price per KW (Tier 3)
Proposed Price per Tier 1 Application
Proposed Price per Tier 2 Application
Proposed Price per Tier 3 Application
Proposed Tier 1, 2, and 3 Revenue
Difference Between Costs and Proposed Fee Revenue
Costs to be Recovered Through an Application Fee
$16,110
$481
$16,051
$32,641
284
66
350
18.9%
4,104
$0.00
$1.00
$2.00
$0.00
$50.00
$100.00
$7,404
$93.26
$0.00
$1.50
$3.00
$60.00
$75.00
$150.00
$28,147
$4,495
7,381
2
7,383
0.0%
38
$0.00
$1.00
$2.00
$0.00
$50.00
$100.00
$138
$59.90
$0.00
$1.50
$3.00
$60.00
$75.00
$150.00
$443,067
-$819
$0.00
$1.50
$3.00
$60.00
$75.00
$150.00
$22,021
$42,601
2,626
1,002
$0.00
$1.00
$2.00
$0.00
$50.00
$100.00
$5,880
$265.93
220
21
2
243
9.5%
$19,667
$379
$44,576
$64,622
$0.00
$1.50
$3.00
$60.00
$75.00
$150.00
$2,418
$741
1,242
$0.00
$1.00
$2.00
$0.00
$50.00
$100.00
$1,292
$351.03
9
11.1%
-
8
1
$671
$12
$2,476
$3,159
$0.00
$1.50
$3.00
$60.00
$75.00
$150.00
$3,951
$14,230
1,224
$0.00
$1.00
$2.00
$0.00
$50.00
$100.00
$2,274
$606.01
30
70.0%
9
21
$7,048
$126
$11,006
$18,180
General Small General Large
General
Dist. NEM
Dist. NEM
+1 MW NEM Irrigation
Sch 23-135
Sch 6-135
Sch 8-135
Sch 10
$198,752
$17,797
$225,698
$442,247
Residential
Net Metering
$0.00
$1.50
$3.00
$60.00
$75.00
$150.00
$499,603
$61,247
9,234
1,002
$0.00
$1.00
$2.00
$0.00
$50.00
$100.00
$16,988
$69.98
7,902
111
2
8,015
1.4%
$242,248
$18,795
$299,807
$560,850
Total
Rocky Mountain Power
Exhibit RMP___(JRS-8) Page 1 of 1
Docket No. 16-035-__
Witness: Joelle R. Steward
Rocky Mountain Power
Docket No. 16-035-____
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Direct Testimony of Robert M. Meredith
November 2016
1
Q.
dba Rocky Mountain Power (“the Company”).
2
3
Please state your name, business address and present position with PacifiCorp
A.
My name is Robert M. Meredith. My business address is 825 NE Multnomah St,
4
Suite 2000, Portland, Oregon, 97232. My present position is Manager, Pricing and
5
Cost of Service.
6
Qualifications
7
Q.
Please describe your education and professional background.
8
A.
I graduated magna cum laude from Oregon State University in 2004 with a
9
Bachelor of Science degree in Business Administration and a minor in Economics.
10
In addition to my formal education, I have attended various industry-related
11
seminars. I have worked for the Company for twelve years in various roles of
12
increasing responsibility in the Customer Service, Regulation, and Integrated
13
Resource Planning departments. I have over six years of experience preparing cost
14
of service and pricing related analyses for all of the six states that PacifiCorp serves.
15
I assumed my present position in March 2016.
16
Q.
Have you testified in previous regulatory proceedings?
17
A.
Yes. I have previously filed testimony on behalf of the Company in regulatory
proceedings in California and Washington.
18
19
Summary
20
Q.
What is the purpose of your testimony?
21
A.
The purpose of my testimony is to present and support the Company’s cost of
22
service analyses that were prepared to comply with the Commission’s order issued
23
November 10, 2015, in Docket No. 14-035-114 in which the Commission
Page 1 - Direct Testimony of Robert M. Meredith
24
established a framework for determining the costs and benefits of the net metering
25
program (“November 2015 Order”). My testimony demonstrates that the
26
Company's cost of service studies are accurate and reliable, and are consistent with
27
Commission-approved standards that have been approved over the years,1 and
28
should be accepted by the Commission.
29
Q.
Please summarize your testimony.
30
A.
To comply with the November 2015 Order, the Company prepared two cost of
31
service analyses: one that compares the costs and benefits of the net metering
32
program by examining the difference with and without the existence of the net
33
metering program, referred to in the order as the actual cost of service ("ACOS")
34
and counterfactual cost of service ("CFCOS"); and another that examines the results
35
of segregating net metering customers into separate classes in the class cost of
36
service study, referred to by the Company as the net metering breakout cost of
37
service ("NEM Breakout COS"). The results of both analyses demonstrate that, as
38
the net metering program is currently structured, the costs of the program exceed
39
its benefits. In particular, the revenue received from residential net metering
40
customers is insufficient to cover their cost of service, which will shift costs onto
41
other customers whose rates will ultimately increase.
1
See In the Matter of PacifiCorp's Financial Reports, 2016, Annual Cost of Service Study - 2015, Docket No.
16-035-15 (in reviewing PacifiCorp's June 2016 Annual Cost of Service Study, the Commission stated,
[b]ased on the Commission's review ... and the recommendation of the Division, the Commission
acknowledges PacifiCorp's COS Study and Model.")
Page 2 - Direct Testimony of Robert M. Meredith
42
Cost of Service Analyses - Summary of Results
43
Q.
What was the purpose of the Commission’s November 2015 Order?
44
A.
The Legislature enacted Utah Code § 54-15-105.1, which requires the
Commission to perform the following two tasks:
45
(1)
46
Determine, after appropriate notice and opportunity for public
47
comment, whether costs that the electrical corporation or other
48
customers will incur from a net metering program will exceed the
49
benefits of the net metering program, or whether the benefits of the
50
net metering program will exceed the costs; and
(2)
51
Determine a just and reasonable charge, credit, or ratemaking
52
structure, including new or existing tariffs, in light of the costs and
53
benefits.
54
Utah Code Ann. § 54-15-105.1 (hereinafter, § 54-15-105.1(1) will be referred to as
55
"Subsection One" and § 54-15-105.1(2) as "Subsection Two"). The November 2015
56
Order established the appropriate structure for the Commission to perform the
57
Subsection One analysis.
58
Counterfactual Cost of Service Compared to Actual Cost of Service
59
Q.
2015 Order?
60
61
What cost of service analysis did the Commission require in its November
A.
The Commission required the Company to show the cost of service at the system,
62
state, and customer class levels by comparing an actual cost of service (“ACOS”)
63
study with a counterfactual cost of service (“CFCOS”) study. The Commission
64
directed the Company to “use its best efforts to estimate what its cost of service
Page 3 - Direct Testimony of Robert M. Meredith
65
would be if net metering customers produced no electricity, drawing their entire
66
load from PacifiCorp and providing no surplus energy to the system.”2 Showing
67
cost of service at the system, state, and customer class levels requires the use of the
68
Company's jurisdictional allocation model ("JAM").
69
Q.
November 2015 Order?
70
71
How did the Company perform the cost of service analysis required by the
A.
Using the 12-month historical period ended December 31, 2015, the results of a
72
counterfactual JAM ("CFJAM") and a CFCOS were compared to the results of the
73
actual JAM ("AJAM") and the ACOS Study. The AJAM is the model used to
74
prepare the December 2015 results of operations, in Docket No. 16-035-15, but
75
with a revision to the Utah customer count used in calculating the Customer
76
Number ("CN") factor that was identified as a result of the Division of Public
77
Utilities' ("DPU") review.3 The ACOS study is the same as the 2015 Annual Cost
78
of Service Study, which is based upon the December 2015 results of operations, but
79
with minor changes made to incorporate the Commission's direction in their
80
correspondence dated October 25, 2016, and using the AJAM.
The CFJAM assumes that the net metering program does not exist and
81
relative to the AJAM, includes:
82
•
83
Higher net power costs to supply the energy that would have been generated
by net metering customers’ private generation, as shown in Company
84
2
November 2015 Order.
The CN in the 2015 Results of Operations JAM inadvertently included a double count for the Company’s
Cool Keeper customers which resulted in overstating the number of billings. For further information, see the
DPU's action request filed with the Commission on September 29, 2016.
3
Page 4 - Direct Testimony of Robert M. Meredith
85
witness Mr. Michael G. Wilding’s testimony, which includes a description
86
of how net power costs were estimated.
87
•
Higher net power costs to account for line losses associated with delivering
energy from more remote sources.
88
89
•
Removal of bill credits related to private generation.
90
•
Lower engineering and administrative costs required to interconnect net
metering customers.
91
92
•
Lower customer service and billing costs.
93
•
Lower metering costs.
94
•
Higher allocations of system costs to Utah to reflect higher demands and
95
energy for the state.
96
Later in my testimony, I describe how the changes in bill credits, line losses,
97
customer service and billing costs, administrative costs, engineering costs, and
98
metering costs were developed.
99
The CFCOS uses the CFJAM and includes higher revenues, higher energy,
100
and higher demands for each customer class with net metering customers. This
101
includes residential service on Schedules 1, 2, and 3, Schedule 23, Schedule 6,
102
Schedule 8, and Schedule 10. Later in my testimony I describe how the Company
103
developed the change in energy and demand used in the CFCOS. To hold the rate
104
of return constant between the CFCOS and the ACOS, a $2.0 million rate decrease
105
is applied to the results of the CFCOS, which was calculated by comparing the
106
difference in results between the CFJAM and AJAM.
Page 5 - Direct Testimony of Robert M. Meredith
107
Q.
What are the results of the analysis?
108
A.
Exhibit RMP___(RMM-1) shows the overall results of the Subsection One analysis
109
ordered by the Commission. In this exhibit, the difference between the CFCOS and
110
ACOS are shown at the system, state, and class levels. Positive values are net costs
111
(increases in costs) and negative values are net benefits (decreases in costs).
112
Page 1 shows the difference between costs and benefits of the net metering
113
program at the system level. For costs, values are shown for increased metering
114
cost, increased engineering/administration costs, increased customer service/billing
115
cost, and net metering bill credits. For benefits, the estimated impact of lower net
116
power cost and value of avoided line losses are shown. Overall, the analysis shows
117
a net cost to the system of the net metering program of $3.7 million or about $70.40
118
per megawatt hour (“MWh”).
119
Page 2 shows the difference between costs and benefits of the net metering
120
program at the Utah state level. All of the costs and benefits from page 1 are
121
included plus an additional benefit for lower interjurisdictional allocation to the
122
state. At the state level, the analysis shows a net cost to Utah for the net metering
123
program of $2.0 million or about $38.76 per MWh.
124
Page 3 shows the difference in costs and benefits of the net metering
125
program at the customer class level. Each of the costs and benefits on page 3 are
126
the same in total as those shown on page 2. An overwhelming majority of the net
127
cost to Utah is attributable to residential net metering customers. At the customer
128
class level, the analysis shows a net cost to residential customers for the net
129
metering program of $1.7 million or about $58.60 per MWh. For Schedule 8, the
Page 6 - Direct Testimony of Robert M. Meredith
130
analysis shows a slight net benefit of $0.16 million. For Schedules 23, 6, and 10,
131
the analysis shows a net cost of $0.1 million, $0.02 million, and $0.01 million
132
respectively. For other classes that do not participate in net metering, the analysis
133
shows a $0.4 million net cost. Table 1 below summarizes the net cost or (benefit)
134
of the net metering program at the system, state, and customer class levels.
135
Table 1. Net Cost/(Benefit) of the Net Metering Program at the
System, State, and Customer Class Levels
Cost
System Level
State Level
Residential
Schedule 23
Schedule 6
Schedule 8
Schedule 10
Other Classes
Total Customer Class Level
136
Q.
$
$
$
$
$
$
$
$
$
(000)
(1,287)
(2,960)
(1,881)
(405)
(650)
(395)
(21)
393
(2,960)
Net Cost/
(Benefit)
(000)
$
3,722
$
2,049
$
1,659
$
100
$
23
$
(155)
$
7
$
415
$
2,049
How do the summary results from the ACOS study and the CFCOS study
compare?
137
138
$
$
$
$
$
$
$
$
$
(000)
5,010
5,010
3,540
504
673
240
29
22
5,009
Benefit
A.
Exhibit RMP___(RMM-2) shows the summary of results from the ACOS study, the
139
CFCOS study, and the difference between the two studies. It summarizes, both by
140
customer group and function, the results of the class cost of service studies for the
141
12-months ended December 31, 2015. Page 1 of Exhibit RMP__(RMM-2) presents
142
results for the ACOS study. Page 2 shows the results for the CFCOS study. Page 3
143
shows the difference in results between two studies.
Page 7 - Direct Testimony of Robert M. Meredith
144
Q.
with Commission-approved standards. Please explain.
145
146
Previously you stated that the cost of service studies were performed consistent
A.
As required, the Company annually files a cost of service study, which is reviewed
147
by the DPU and is available to any other interested party. The DPU makes a
148
recommendation to the Commission based on the results of its review. The
149
Company filed its cost of service study for the calendar year 2015 results in June
150
2016. On October 25, 2016, the Commission issued an acknowledgment letter
151
stating, "[b]ased on the Commission's review of PacifiCorp's filing and the
152
recommendation of the Division, the Commission acknowledges PacifiCorp's COS
153
Study and Model. The Commission requests PacifiCorp evaluate the Division's and
154
the Commission's observations and make appropriate changes to the COS model in
155
future COS model filings."4
156
Q.
Do the cost of service studies filed in this case include the changes the
Commission requested be made to all future cost of service model filings?
157
158
A.
159
CFCOS Study Inputs - Load Changes
160
Q.
In the CFCOS, how did the Company estimate the increase in energy
consumption associated with the assumption of no private generation?
161
162
Yes.
A.
Estimating the increase in energy consumption and corresponding change in
163
revenue for the CFCOS requires comparing the current level of energy and revenue
164
that is billed to net metering customers with the level of energy and revenue
165
assuming no private generation. The current net amount of energy usage and
4
Supra, note 1.
Page 8 - Direct Testimony of Robert M. Meredith
166
associated net revenue that is billed to net metering customers is known and used
167
in the ACOS. Estimating the level of energy and revenue without private generation
168
requires estimating what the energy consumption would be for net metering
169
customers if they were full requirements customers. Figure 1 illustrates how full
170
requirements usage is determined for net metering customers.
171
172
The bills for net metering customers are based upon the energy delivered to them
173
from the energy grid, net of the energy exported from their private generation
174
system to the grid. Both of these values, which are represented by (B) and (D) in
175
Figure 1, are measured by a bi-directional meter. Private generation production,
176
represented as (E) in Figure 1, is estimated by multiplying a standardized
177
production profile by the nameplate capacity of each customer's generation system
178
on a monthly basis. To develop full requirements energy usage, shown as (A) in
179
Figure 1, the difference between (E) and (D) is added to (B). The total full
Page 9 - Direct Testimony of Robert M. Meredith
180
requirements energy for net metering customers in the Residential and Schedules
181
23, 6, 8, and 10 classes was estimated by applying this calculation.
182
Q.
How did the Company develop the standardized production profile?
183
A.
By December 2014, the Company had installed 52 load research profile meters on
184
residential customers with private generation systems. Of those 52 customers, the
185
Company received permission to install 36 production profile meters that measure
186
the generation from their private generation systems on a 15 minute-interval basis.
187
The Company then converted the production profiles for each private generation
188
system into a generic shape where the highest 15 minute reading was considered to
189
have a value of one. The Company divided all other values by the highest reading
190
such that each other period was a fraction of one. Establishing this generic shape
191
allows the profile to be scalable by the installed capacity of private generation
192
systems. The Company averaged the generic production shapes of all the private
193
generation systems for each county, and established an overall standardized
194
production shape for the state by weighting each county’s generic profile by the
195
overall nameplate installed private generation capacity in each county as of
196
December 31, 2015.
197
Q.
other outside data source?
198
199
Did the Company benchmark the standardized production shape against any
A.
Yes. The Company compared the standardized production shape to hourly shapes
200
from National Renewable Energy Laboratory’s (“NREL”) online PVWatts®
201
calculator. The Company compared the two samples by performing a linear
202
regression. A regression assesses whether the predictor variables (the Company's
Page 10 - Direct Testimony of Robert M. Meredith
203
production shape) account for variability in a dependent variable (the PVWatts®
204
production shape). The Company can measure how representative the sample data
205
is to the PVWatts® data by treating the PVWatts® generation data as the dependent
206
variable and the production sample data as the independent variable.
207
Based on the Company's findings, the regression has an Adjusted R-
208
squared of 0.994 (a perfect correlation would be 1.0). This indicates that the
209
model is a good predictor of the dependent variable. Further, the regression has a
210
Durbin-Watson statistic of 2.082, signifying that autocorrelation has been
211
corrected within the model (a value of 2.0 would indicate complete absence of
212
autocorrelation). The regression coefficient and elasticity are 1.036 and 0.942
213
(again, a perfect correlation would be 1.0), respectively. This indicates the two
214
sets of data behave similarly.
215
Further, the two independent samples are highly correlated with a
216
correlation coefficient of 0.984. This demonstrates that the hourly shape of the
217
NREL sample is similar to the shape of the standardized production profile. Exhibit
218
RMP ___(RMM-3) provides a description of the Company’s benchmarking to the
219
NREL data analysis.
220
A visual comparison of the Company's production curve and the PVWatts®
221
curve also demonstrates that both curves have a similar shape and behavior. Figure
222
2 below shows the average hourly solar production for the Company's estimate
223
compared to the output from NREL data during the 2015 peak month of June:
Page 11 - Direct Testimony of Robert M. Meredith
224
Figure 2. June 2015 Average Hourly Solar Production from Company and NREL
Data
225
Q.
Please explain what Exhibit RMP___(RMM-4) shows.
226
A.
Exhibit RMP___(RMM-4) shows how the difference in energy sales between the
227
CFCOS and the ACOS studies is calculated. The billed energy for net metering
228
customers during the period was 188,410 MWh. The full requirements energy
229
usage for net metering customers is estimated to be 239,706 MWh. The overall
230
difference between the CFCOS and ACOS energy sales is 51,297 MWh.
231
Q.
Given the standardized production shape and the known nameplate capacity
232
for customer private solar generation, what is the Company's estimate of
233
private generation production?
234
235
A.
The Company's estimate of private generation production for the period is 52,877
MWh and is shown on Exhibit RMP ___ (RMM-4).
Page 12 - Direct Testimony of Robert M. Meredith
236
Q.
the same as estimated private generation production?
237
238
Why is the difference in energy sales between the CFCOS and the ACOS not
A.
While the difference in energy sales between the CFCOS and ACOS is close to the
239
estimated private generation production (51,297 MWh versus 52,877 MWh), they
240
are not the same. The difference is the result of net metering energy banking, which
241
I discuss below. For residential and small non-residential net metering customers,
242
if the energy exported from the customer to the energy grid is more than the energy
243
delivered from the energy grid to the customer during the billing month, the
244
Company credits a customer with a kilowatt-hour credit that is applied to future
245
bills until the end of the net metering program year. In any given billing period, net
246
metering customers may be making energy deposits or withdrawals into and out of
247
their bank. The overall quantity of energy reflected in the ACOS represents billed
248
energy which considers the impact of energy banking. The CFCOS contains the
249
estimated energy for net metering customers assuming full requirements usage,
250
which does not include any impact from banking.
251
Q.
would exist if there were no private generation?
252
253
In the CFCOS, how did the Company estimate the increase in demand that
A.
The Company modified the hourly, Utah state border loads, and class loads that
254
were used in the ACOS by the estimated private generation production profile that
255
I described earlier in my testimony. For Utah border loads, this expansion by the
256
estimated production profile is at the input level, accounting for line losses. The
257
Company bases interjurisdictional allocations upon border loads that measure all
258
load coming into a jurisdiction as well as all load flowing out of a jurisdiction. Since
Page 13 - Direct Testimony of Robert M. Meredith
259
private generation production would stay within the state and would consequently
260
reduce state load for interjurisdictional allocations, the allocation factors in the
261
CFCOS were modified to reflect what allocation factors would have been, absent
262
private generation. For the CFCOS, the Company expanded customer class loads
263
by the full private generation production profile to be consistent with how loads
264
were developed for the CFJAM.
265
Q.
for the CFCOS analysis?
266
267
How did the Company determine and apply line losses to private generation
A.
To bring private generation to the input level, nameplate installed capacity was
268
determined by month for customers served at the secondary voltage level and the
269
primary voltage level. The Company then expanded private generation by class by
270
the loss factor used in the recently acknowledged 2015 cost of service study for
271
these quantities of nameplate capacity. Bringing private generation to the input
272
level, increases it from 52,877 MWh to 57,784 MWh. The estimated change in net
273
power cost between the ACOS and CFCOS described in Mr. Wilding’s testimony
274
reflects private generation at the input level.
275
CFCOS Study Inputs - Bill Credits
276
Q.
How did you calculate the removal of bill credits for the CFCOS?
277
A.
The Company segmented the change in energy between actual billed energy and
278
full requirements energy into energy blocks by season (Summer and Winter) and
279
by on-peak and off-peak periods, as applicable. The Company then estimated the
280
removal of bill credits (revenue difference between actual billed revenue and full
281
requirements revenue) by multiplying the changes in energy by the corresponding
Page 14 - Direct Testimony of Robert M. Meredith
282
energy charges. For residential net metering customers, the Company estimated full
283
requirements energy for each monthly bill to determine the levels of energy
284
consumption that would occur in the different tier block usage levels that apply to
285
residential energy charges. The Company then applied the change in the proportion
286
of energy in each tier block energy charge to the overall estimated change in energy
287
to estimate bill credits for the residential class.
288
Exhibit RMP___(RMM-5) shows bill credits related to the net metering
289
program (the estimated difference in revenue between the CFCOS and ACOS) by
290
rate schedule. This exhibit demonstrates overall bill credits associated with the net
291
metering program of approximately $4.2 million.
292
CFCOS Study Inputs - Customer Service and Billing Costs
293
Q.
costs?
294
295
How did the Company develop net metering customer service and billing
A.
The Company sorted customer service and billing costs related to the net metering
296
program into three categories:
297
1. Phone calls, including customer inquiries and requests related to the net
298
299
300
301
302
metering program.
2. Initial setup, including requests for a meter exchange and setting up customers
on the net metering program in the Company’s billing system.
3. Ongoing support, including back office work necessary to correctly bill
customers participating in the net metering program.
303
Developing the costs related to each of these areas required obtaining estimates
304
from Company personnel involved in the day-to-day operations at the call centers
Page 15 - Direct Testimony of Robert M. Meredith
305
regarding the total time spent on each of these activities. Those figures were then
306
multiplied by the fully-loaded hourly cost for a call center agent.
307
To determine the proportions of these costs that are related to the different
308
customer classes, the overall cost estimates for each activity were spread based
309
upon an appropriate driver for those costs. Since phone calls were primarily for
310
customers who were considering participation in the net metering program, this cost
311
was allocated on the number of applications in the period. Initial setup cost was
312
allocated based upon the number of interconnections during the period. Since
313
ongoing support is related to the number of bills, this cost was allocated by the
314
average bills during the period. Exhibit RMP___(RMM-6) shows the customer
315
service and billing costs related to the net metering program by customer class.
316
CFCOS Study Inputs - Program Administration
317
Q.
How did the Company develop net metering program administrative costs?
318
A.
The Company dedicates a department to the administration of the various net
319
metering programs it oversees and implements across the six states that it serves.
320
This includes the handling and processing of interconnection applications. The
321
overall expense of this department was multiplied by the proportion of workload
322
dedicated to the net metering program in Utah. This expense was reduced by the
323
application fees that were collected in 2015 for larger non-residential
324
interconnections. Page 1 in Exhibit RMP___(RMM-7) to my testimony shows net
325
administrative expense related to the net metering program by customer class.
326
Pages 2 and 3 of Exhibit RMP___(RMM-7) show how the Company determined
327
administrative expense by state and rate schedule.
Page 16 - Direct Testimony of Robert M. Meredith
328
Q.
program?
329
330
How did the Company develop engineering costs related to the net metering
A.
Engineers review the technical details of the interconnection applications to ensure
331
that private generation systems can safely and reliably interconnect to the
332
Company’s distribution system. To develop the engineering costs related to the net
333
metering program, the estimated time it takes to review an application was
334
multiplied by the fully-loaded hourly cost of a field engineer which was then
335
multiplied by the number of applications in 2015. The estimated time for review
336
for each application varied by rate schedule to reflect differences in the complexity
337
of review. Exhibit RMP___(RMM-8) to my testimony shows engineering expense
338
related to the net metering program by customer class.
339
CFCOS Study Inputs - Meter Costs
340
Q.
the net metering program?
341
342
How did the Company develop the change in metering costs associated with
A.
To accurately bill net metering customers, the bi-directional flow of energy must
343
be measured. The Company estimated the costs to replace and reprogram meters
344
accordingly. Pages 1 and 2 of Exhibit RMP___(RMM-9) show the costs of
345
metering related to the net metering program by customer class. Page 3 of Exhibit
346
RMP___(RMM-9) shows the calculation of meter depreciation and deferred tax
347
impacts.
Page 17 - Direct Testimony of Robert M. Meredith
348
CFCOS Study - Results
349
Q.
CFCOS and the ACOS?
350
351
What is the overall conclusion you draw from the comparison between the
A.
The analysis shows that the costs that the Company or other customers incur from
352
the net metering program do in fact exceed the benefits of that program, which will
353
result in higher rates for other customers.
354
Q.
class in the analysis comparing the CFCOS to the ACOS?
355
356
What conclusions can you make from the difference in results by customer
A.
Most of the net cost of the net metering program is attributable to the residential
357
class. For all other customer classes, except Schedule 8, the net metering program
358
is also a net cost. The net benefit shown for Schedule 8 is only $0.16 million or
359
about 8 percent of the overall $2.0 million net cost for Utah. The results for
360
Schedule 8 are primarily related to the low average cost of bill credits for these
361
customers which reflects the Company's conservative assumption not to estimate
362
any change in demand charges.
363
Actual Cost of Service with Net Metering Separately Broken Out
364
Q.
service analysis did the Commission require in its November 2015 Order?
365
366
Along with a comparison of the CFCOS and the ACOS, what other cost of
A.
The Commission also required the Company to prepare a cost of service study
367
under which the Company “will segregate net metering customers from the class in
368
which they presently participate and reflect the resulting class cost of service to the
Page 18 - Direct Testimony of Robert M. Meredith
369
net metering customers as a separate class and show the impact their segregation
370
has on the class in which they would otherwise participate.”5
371
Q.
How did the Company prepare the NEM Breakout COS?
372
A.
Starting with the class ACOS study, separate classes were created for the residential
373
class and Schedules 23, 6, 8, and 10 net metering customers (“NEM classes”). For
374
these different NEM classes, the characteristics of their cost of service were
375
identified, removed from the overall class from which they were separated, and
376
applied to the NEM classes. The characteristics for the NEM classes include
377
different customer counts, revenues, energy values, system coincident peak demand
378
values, distribution coincident peak demand values, non-coincident peak demand
379
values, number of customers per transformer, and metering costs.
380
NEM Breakout COS - Demands
381
Q.
How did the Company develop demand values for the NEM classes?
382
A.
For the residential net metering class, demand values were based upon the load
383
research study previously discussed. Each of these load research meters measured
384
delivered and exported energy on a 15-minute-interval basis. The overall profile
385
from these load research meters was scaled to the delivered and exported energy
386
volumes on a monthly basis. The Company developed various monthly system
387
coincident and distribution coincident peaks from this profile. The Company
388
determined non-coincident peak on a monthly basis by averaging the non-
389
coincident peaks for each of the sample profile meters and scaling by the overall
390
number of customers in the population.
5
November 2015 Order.
Page 19 - Direct Testimony of Robert M. Meredith
391
System coincident peaks and distribution coincident peaks were based upon
392
energy deliveries to the customer. Non-coincident peak was based upon the
393
maximum of either energy delivery or energy export. The Company allocates line
394
transformers and secondary lines based upon each class’s annual maximum non-
395
coincident peak which is then weighted by a coincidence factor. Using the
396
maximum of either delivered or exported non-coincident peak for each customer
397
accurately reflects those customers’ usage of these localized facilities, which are
398
typically used by a small number of customers and must be sized to meet the
399
demands imposed upon the equipment in either direction.
400
For the Schedules 23, 6, and 10 net metering classes, the standard profile
401
that was developed for the ACOS study for their whole class, which includes both
402
net metering and non-net metering customers, was adjusted to the overall energy
403
volume for estimated full requirements usage of the net metering customers on a
404
monthly basis to create full requirements profiles. Their estimated private
405
generation production profile was then overlaid on top of that estimated full
406
requirements profile to estimate delivered and exported energy on an hourly basis.
407
For Schedule 8, demand values are based upon the readings from profile meters
408
that are installed for all customers of this size.
409
Q.
customers?
410
411
How did the Company first develop the sample of residential net metering
A.
Exhibit RMP___(RMM-10) explains the process by which the Company selected
412
sample meters for inclusion into the load research study. Basically, meters were
413
selected based upon their net energy usage reported from the billing system.
Page 20 - Direct Testimony of Robert M. Meredith
414
Q.
develop loads for the NEM Breakout COS?
415
416
Did the Company use all sample meters from the study’s original design to
A.
No. Sixty-two (62) meters were initially included in the study. Since ten of the
417
original meters were for customers with wind-based private generation and 99
418
percent of all private generation capacity is solar, the Company used the data from
419
the 52 meters for customers with solar-based private generation to develop loads
420
for the NEM Breakout COS.
421
Q.
Were the strata breakpoints and weightings discussed in Exhibit
422
RMP___(RMM-10) the same as those ultimately used to develop loads for the
423
NEM Breakout COS?
424
A.
No. The strata breakpoints discussed in Exhibit RMP___(RMM-10) were based
425
upon the billed or net energy of the total population of residential net metering
426
customers at the time the sample was designed. To develop loads for the NEM
427
Breakout COS, the Company used delivered energy to inform the strata
428
weightings and breakpoints, because delivered energy is an indication of the
429
customer’s usage of the system, as opposed to net energy that is a billing-related
430
construct.
431
NEM Breakout COS - Direct Assignments and Energy
432
Q.
NEM Breakout COS for the NEM Classes?
433
434
What other important differences did the Company incorporate into the
A.
While developing the CFCOS study, the Company identified engineering,
435
administration, and customer service/billing related costs that are directly
436
attributable to serving and interconnecting net metering customers. These costs
Page 21 - Direct Testimony of Robert M. Meredith
437
which are shown on Exhibit RMP___(RMM-6), Exhibit RMP___(RMM-7), and
438
Exhibit RMP___(RMM-8) were directly assigned to the different NEM classes.
439
Also NEM classes are allocated energy-related costs for the energy that is delivered
440
to them and receive credit to their cost of service for the excess generation that they
441
deliver to the Company.
442
Q.
costs based upon their delivered energy instead of their net energy?
443
444
Why does the Company allocate to net metering customers energy-related
A.
Net metering customers use the system in a way that is fundamentally different than
445
other customers. Unlike other customers who consume only energy that is delivered
446
to them from the energy grid, net metering customers may at different times be
447
receiving energy from the energy grid, consuming their own private generation
448
onsite, or exporting the excess energy from their private generation to the energy
449
grid. Like with any other customer, the Company allocates its costs based upon the
450
volumes of energy and the magnitude of demands the Company delivers to net
451
metering customers. Inasmuch as net metering customers consume their own
452
private generation onsite, the profile and overall quantity of energy delivered to
453
them is reduced and the allocation of costs is also consequently reduced. The
454
concept of net energy is a billing construct that is used for net metering. Net energy
455
does not reflect a net metering customer’s physical time-based relationship with the
456
energy grid. Even though a net metering customer may produce as much total
457
energy as that customer consumes over a period of time, in real time that customer
458
still relies upon the energy grid to both import and export energy. The NEM
Page 22 - Direct Testimony of Robert M. Meredith
459
Breakout COS study appropriately assigns costs to net metering customers based
460
upon their usage of the Company’s system.
461
Q.
energy in the NEM Breakout COS study.
462
463
Please describe how net metering customers receive credit for their excess
A.
For the energy that net metering customers export to the energy grid from their
464
private generation systems, a credit for their exported energy is assigned to them
465
based upon the difference in monthly net power cost associated with private
466
generation that was calculated for the CFCOS analysis. Company witness Mr.
467
Wilding’s testimony provides a description of the net power cost analysis. The
468
Company increases the credits applied for exported energy to reflect avoided line
469
losses. The overall annual excess credit also considers each NEM class’s impact
470
from energy banking. For energy deposits into customers' net metering bank, the
471
excess energy credits are reduced. For energy withdrawal from customers' net
472
metering bank, excess energy credits are increased. Exhibit RMP___(RMM-11)
473
includes the calculation of excess energy credits for each NEM class. In total the
474
value of the energy credits for all NEM classes is $553,067.
475
Q.
impact of net metering banking?
476
477
Why does the Company adjust excess energy credits to account for the
A.
In a class cost of service study, the ultimate result of the study is a comparison of
478
whether the revenues provided from each class are less than, more than, or equal to
479
each class’s cost of service. Within the annual period that is used for a cost of
480
service study, revenue from net metering customers is based upon billed energy that
481
includes some out-of-period impact from net metering energy banking. For
Page 23 - Direct Testimony of Robert M. Meredith
482
example, in the 12 months ended December 31, 2015, some energy credits from
483
excess energy banked in 2014 are applied to bills that occur in 2015. Conversely,
484
some excess energy that is banked in 2015 will be applied to bills in 2016. Ignoring
485
the effect of net metering energy banking would create a mismatch between
486
revenues and cost of service. Subtracting the excess energy, which includes both
487
the energy exported as well as the impact of banking, from the delivered energy
488
produces the billed energy upon which revenues are determined and upon which
489
the total energy in the ACOS is based.
490
Q.
service of the NEM classes.
491
492
Please describe how the Company applies excess energy credits to the cost of
A.
The Company directly assigns excess credits to each NEM class. It allocates an
493
offsetting cost for the excess credits to all classes based upon Factor 30 - Energy.
494
Both the excess credits and the offsetting costs are functionalized to the Production
495
function.
496
Q.
Why is there an offsetting cost for the excess credits?
497
A.
To balance out the credits directly assigned to net metering customers in the cost of
498
service model, it was necessary to include a cost that offsets that credit. The excess
499
credits in the NEM Breakout COS reflect a fair value of the energy that net metering
500
customers export to the energy grid for other customers to use. All customers,
501
including net metering customers, benefit from this excess generation in the form
502
of reduced net power cost. It is reasonable that all customers receive an increased
503
allocation of cost proportional to that benefit to offset the value assigned to the
504
NEM classes for their exported energy. With this treatment of excess energy,
Page 24 - Direct Testimony of Robert M. Meredith
505
customers are economically indifferent between whether they receive a kilowatt
506
hour from a private generation system or from some other source.
507
Q.
the basis of energy?
508
509
A.
Q.
Why does the Company allocate the offsetting cost for excess credits to NEM
classes as well as to the other non-net metering classes?
512
513
The offsetting cost of the excess energy credits is allocated on energy because the
majority of net power costs including fuel are allocated on the basis of energy.
510
511
Why does the Company allocate the offsetting cost for the excess credits on
A.
Private generation that is exported to the energy grid may be consumed by both
514
customers who do not participate in net metering as well as those who do. Also net
515
power costs in total are reduced as a result of exported private generation. It is
516
reasonable to assign some of the offsetting cost of excess energy to net metering
517
customers in proportion to the energy that is delivered to them.
518
NEM Breakout COS - Results
519
Q.
Are there any challenges with the NEM Breakout COS study?
520
A.
Yes. While the Company has a load research study for residential net metering with
521
a full year of profile data, the Company does not have the same information for
522
Schedules 6, 10, and 23 net metering customers.
523
Q.
Why did the Company create segregated NEM classes for Schedules 6, 10,
524
and 23 in the NEM Breakout COS study if load research studies were not
525
available?
526
527
A.
The Company prepared this information to comply with the November 2015 Order.
The information for Schedules 6, 10, and 23 net metering customers attempts to
Page 25 - Direct Testimony of Robert M. Meredith
528
show an estimate of their cost of service with separate class treatment and provides
529
some context regarding the general magnitude of cost shifting that may exist for
530
these customers.
531
Q.
Please identify and explain Exhibit RMP___(RMM-12).
532
A.
Exhibit RMP___(RMM-12) shows the summary of results from the NEM Breakout
533
COS study in the same format as the studies that are presented in Exhibit
534
RMP___(RMM-2), but with results shown for the NEM classes. Exhibit
535
RMP___(RMM-12) shows that residential net metering customers and Schedules
536
6, 8, 10 and 23 net metering customers require a 65.05 percent, -8.43 percent, -8.30
537
percent, 11.42 percent, and 8.42 percent change to present revenues, respectively.
538
Q.
Please identify and explain Exhibit RMP___(RMM-13).
539
A.
Exhibit RMP___(RMM-13) shows the difference in cost of service results for each
540
class between the NEM Breakout COS and the ACOS. This satisfies the November
541
2015 Order’s requirement for the Company to “show the impact their segregation
542
has on the class in which they would otherwise participate.”6 Exhibit
543
RMP___(RMM-13) indicates that the costs for the residential class would be
544
reduced by $1.1 million if net metering customers were excluded from their class,
545
whereas the costs for Schedules 6, 8, and 10 customers would increase by $0.3
546
million, $0.2 million, and $0.04 million, respectively.
6
Id.
Page 26 - Direct Testimony of Robert M. Meredith
547
Q.
Do the results of the NEM Breakout COS study mean that the net metering
548
program as currently structured is a significant benefit for Schedules 6, 8, and
549
10?
550
A.
No, not necessarily. The analysis shows how the cost of service results vary for
551
specific groups of net metering customers relative to other customers within the
552
same class. For Schedules 6, 8, and 10, the seemingly favorable results may not be
553
so much an indication of the benefit (or cost savings) related to the net metering
554
program as it may be an indication of the characteristics of net metering customers.
555
As a percentage of their overall full requirements energy usage, private generation
556
production for customers on Schedules 6, 8, and 10 is quite small relative to the
557
residential and Schedule 23 classes. See Table 2 below:
Table 2. Private Generation Relative to Full Requirements Usage
558
NEM Class
Residential Net Metering
Schedule 23 Net Metering
Schedule 6 Net Metering
Schedule 8 Net Metering
Schedule 10 Net Metering
559
Q.
Estimated
Private
Generation
Production
(MWh)
28,304
6,012
12,342
5,736
484
Private Generation
Relative to Full
Requirements
Energy Usage
(%)
55%
60%
13%
7%
28%
What is the overall conclusion that you draw from the results of the NEM
Breakout COS?
560
561
Full
Requirements
Energy Usage
(MWh)
51,468
9,971
98,655
77,889
1,724
A.
The cost of serving residential net metering customers is significantly different than
562
the cost of serving other residential customers. On a percentage basis, the revenue
563
collected from residential net metering customers is vastly insufficient to cover the
564
costs of serving them.
Page 27 - Direct Testimony of Robert M. Meredith
565
While the results for other non-residential classes are different between the
566
classes with and without net metering, those differences are far less striking than
567
the clear contrast for residential customers. An examination of parity ratios, which
568
is the percentage of revenue relative to cost of service, reveals that revenues
569
collected from non-residential net metering rate schedules are within a reasonable
570
range (approximately 90 - 110 percent), but revenues collected from the residential
571
net metering schedule are quite far off from parity with cost of service
572
(approximately 60 percent). Table 3 below shows the parity ratios for all rate
573
schedules which have net metering customers for the actual cost of service, both
574
with net metering included and broken out separately.
Table 3. Revenue to Cost of Service Parity Ratios
575
ACOS
Residential
Schedule 23
Schedule 10
Schedule 6
Schedule 8
576
Q.
96.0%
107.2%
95.3%
107.7%
104.1%
96.1%
107.3%
95.1%
107.7%
104%
60.6%
92.2%
89.8%
109.2%
109%
How do the results for residential customers from the comparison between the
CFCOS and the ACOS compare to the results for the NEM Breakout COS?
577
578
Parity to Cost of Service
ACOS W/O
ACOS NEM
A.
Both analyses demonstrate a similar result for residential net metering customers.
579
As shown on Exhibit RMP___(RMM-1), the analysis which compares the CFCOS
580
to the ACOS shows that the cost to the residential class of the net metering program
581
is $1.7 million. The NEM Breakout COS results in Exhibit RMP___(RMM-12)
582
show that the residential net metering class requires a $1.8 million increase to
Page 28 - Direct Testimony of Robert M. Meredith
583
present revenues in order for the class to earn the jurisdictional average rate of
584
return.
585
586
Adjusting the NEM Breakout COS Results to the Same Basis as the Last General
Rate Case
587
Q.
residential net metering?
588
589
Upon what level of revenue requirement is it appropriate to design rates for
A.
Company witness Ms. Joelle R. Steward’s testimony describes the Company’s
590
proposed rate design for new residential net metering customers who submit net
591
metering applications after December 9, 2016. The revenue requirement upon
592
which those rates are designed is the same as the revenue requirement for the
593
residential net metering class in the NEM Breakout COS, but adjusted downward
594
to the same level of costs that were in Docket No. 13-035-184, the last general rate
595
case ("2014 GRC"). While the analysis comparing the CFCOS to the ACOS
596
provides useful information regarding the costs and benefits of the net metering
597
program, the NEM Breakout COS provides a more specific examination of the level
598
of revenue required to bring residential net metering customers to full cost of
599
service. Adjusting the NEM Breakout COS results for the residential net metering
600
class to the level used in the 2014 GRC ensures that rates for this class are set upon
601
the same basis as for all other customers.
602
Q.
the same level of costs in the 2014 GRC?
603
604
How was the revenue requirement from the NEM Breakout COS adjusted to
A.
Exhibit RMP___(RMM-14) shows how the NEM Breakout COS results for the
605
residential net metering class were adjusted to the level of costs from the 2014
606
GRC. The class cost of service study that was filed in the 2014 GRC was modified
Page 29 - Direct Testimony of Robert M. Meredith
607
so that the overall cost of service for the residential class was adjusted to the step 2
608
revenue of $684,856,2267. Column A in Exhibit RMP___(RMM-14) shows the unit
609
costs for the residential class from this study. Column B in Exhibit RMP___(RMM-
610
14) shows the unit costs for "other" residential customers from the NEM Breakout
611
COS. Column C in Exhibit RMP___(RMM-14) shows the unit costs for residential
612
net metering customers from the NEM Breakout COS. Column D in Exhibit
613
RMP___(RMM-14) shows the proportion of residential net metering revenue
614
requirement to overall residential revenue requirement from the NEM Breakout
615
COS for each sub-functional cost category. Sub-functional cost categories within
616
the units costs of the cost of service study include Production-Demand, Production-
617
Energy, Transmission-Demand, Transmission-Energy, Distribution-Substations,
618
Distribution - Poles and Conductor, Distribution - Services, Distribution - Meter,
619
Retail, and Miscellaneous. Column E in Exhibit RMP___(RMM-14) shows the
620
application of the proportions in Column D to the overall residential revenue
621
requirement from the 2014 GRC in Column A by each sub-functional cost category
622
and adds each of the costs for those categories. Exhibit RMP___(RMM-14) shows
623
a total of $4,210,660 for the total in Column E, which represents an eight percent
624
reduction in the revenue requirement for the residential net metering class relative
625
to the results from the NEM Breakout COS.
7
The step 2 price change became effective September 1, 2015 and reflects the currently effective base
revenues for the Company.
Page 30 - Direct Testimony of Robert M. Meredith
626
Conclusion
627
Q.
What is your recommendation for the Commission?
628
A.
The Company recommends that the Commission issue an order finding that the
629
results of both of the analyses that I presented are accurate, reliable and are
630
consistent with the November 2015 Order.
631
Q.
Does this conclude your direct testimony?
632
A.
Yes.
Page 31 - Direct Testimony of Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-1)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Costs and Benefits of the Net Metering Program
November 2016
Rocky Mountain Power
State of Utah
12 Months Ended Dec 2015
Costs and Benefits of the Net Metering Program at the
PacifiCorp System Level
Unit
$000
$000
$000
$000
System
$161
$528
$83
$4,237
$000
$5,010
Benefits Lower Net Power Costs
Lower Line Losses
$000
$000
($1,168)
($119)
Total Benefit
$000
($1,287)
Net Cost /(Benefit)
$000
$3,722
Net Metering Energy Production
MWh
52,877
$/MWh
$70.40
Costs Increased Metering Cost
Increased Engineering/Administration
Increased Customer Service/Billing Cost
Bill Credits
Total Cost
Net Cost /(Benefit)
Rocky Mountain Power
Exhibit RMP___(RMM-1) Page 1 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
State of Utah
12 Months Ended Dec 2015
Costs and Benefits of the Net Metering Program at the
State of Utah Jurisdictional Level
Unit
$000
$000
$000
$000
State
$161
$528
$83
$4,237
$000
$5,010
$000
$000
$000
($1,168)
($1,673)
($119)
Total Benefit
$000
($2,960)
Net Cost /(Benefit)
$000
$2,049
Net Metering Energy Production
MWh
52,877
$/MWh
$38.76
Costs Increased Metering Cost
Increased Engineering/Administration
Increased Customer Service/Billing Cost
Bill Credits
Total Cost
Benefits Lower Net Power Costs
Lower Interjurisdictional Allocation
Lower Line Losses
Net Cost /(Benefit)
Rocky Mountain Power
Exhibit RMP___(RMM-1) Page 2 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
4,390
754,063
0.58%
$377.83
MWh
$/MWh
#
#
%
$/Customer/Year
Net Metering Energy Production
Net Cost /(Benefit)
28,304
$1,659
194
15,598
1.24%
$1.85
12,342
$23
($650)
($315)
($303)
($32)
$673
Schedule 6
$17
$76
$2
$578
8
250
3.07%
($26.96)
5,736
($155)
($395)
($143)
($237)
($15)
$240
Schedule 8
$2
$17
$0
$221
$305.44
$118.25
($20,169)
$576.66
13
3,354
0.39%
$15.46
484
$7
($21)
($11)
($10)
($1)
$29
Schedule 10
$2
$4
$0
$22
Net Cost /(Benefit) per Net Metering Customer
327
84,785
0.39%
$16.59
6,012
$100
($405)
($134)
($257)
($14)
$504
Schedule 23
$19
$48
$8
$429
N/A
N/A
12,543
N/A
N/A
N/A
$415
$393
$111
$271
$11
$22
Other Classes
$8
$13
$1
($0)
$415.62
4,931
870,593
0.57%
$38.76
52,877
$2,049
($2,959)
($1,168)
($1,673)
($118)
$5,009
Total
$161
$528
$83
$4,237
This summary shows that the net cost of the net metering program for the residential class in 2015 was $1.7 million, or $58.60 per MWh of net metering energy production. This results in an annual net
cost of $377.83 per residential net metering customer.
Net Metering Customer Count
Total Customer Count
Net Metering Customers as a Proportion of Total
$58.60
$000
Net Cost /(Benefit)
($1,881)
$000
Total Benefit
($675)
($1,137)
($69)
$3,540
Residential
$112
$369
$72
$2,987
$000
$000
$000
$000
Unit
$000
$000
$000
$000
Benefits Lower Net Power Costs
Lower Class Allocation
Lower Line Losses
Total Cost
Costs Increased Metering Cost
Increased Engineering/Administration
Increased Customer Service/Billing Cost
Bill Credits
Rocky Mountain Power
State of Utah
12 Months Ended Dec 2015
Costs and Benefits of the Net Metering Program at the
Customer Class Level
Rocky Mountain Power
Exhibit RMP___(RMM-1) Page 3 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-2)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Summary of Results for ACOS and CFCOS
November 2016
1
6
8
7,11,12
9
10
15
15
23
SpC
SpC
1
2
3
4
5
6
7
8
9
10
11
Footnotes :
Column C :
Column D :
Column E :
Column F :
Column G :
Column H :
Column I :
Column J :
Column K :
Column L :
Column M :
12
Schedule
No.
Line
No.
A
1,924,164,165
722,768,968
533,598,118
154,416,644
11,464,577
274,856,221
17,790,044
749,867
1,299,357
136,301,217
27,835,175
43,083,978
Annual
Revenue
C
7.56%
6.84%
9.03%
8.37%
13.49%
6.24%
6.70%
10.69%
16.87%
8.89%
3.59%
7.07%
E
Rate of
Return
Index
D
Return on
Rate
Base
1.00
0.90
1.19
1.11
1.78
0.82
0.89
1.41
2.23
1.18
0.48
0.93
F
1,924,164,165
753,134,240
495,607,035
148,401,480
9,189,663
292,446,983
18,665,894
653,949
933,992
127,155,013
34,002,137
43,973,781
Total
Cost of
Service
G
1,297,521,618
436,475,060
348,886,702
108,153,715
3,432,666
241,723,062
12,284,228
347,942
724,228
80,398,458
27,944,711
37,150,844
Production
Cost of
Service
Annual revenues based on January 2015 thru December 2015 data.
Calculated Return on Ratebase per January 2015 thru December 2015 Embedded Cost of Service Study
Rate of Return Index. Rate of return by rate schedule, divided by Utah Jurisdiction's normalized rate of return.
Calculated Full Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study
Calculated Generation Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Transmission Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Distribution Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Retail Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Miscellaneous Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Increase or Decrease Required to Move From Annual Revenue to Full Cost of Service Dollars.
Increase or Decrease Required to Move From Annual Revenue to Full Cost of Service Percent.
Total Utah Jurisdiction
Residential
General Service - Large
General Service - Over 1 MW
Street & Area Lighting
General Service - High Voltage
Irrigation
Traffic Signals
Outdoor Lighting
General Service - Small
Customer 1
Customer 2
Description
B
Rocky Mountain Power
Actual Cost Of Service By Rate Schedule
State of Utah
12 Months Ended Dec 2015
2010 Protocol (Non Wgt)
7.56% = Earned Return on Rate Base
H
282,217,001
102,407,582
74,992,811
22,370,680
536,090
49,344,860
2,525,492
65,799
108,653
17,629,481
5,759,093
6,476,460
Transmission
Cost of
Service
I
302,714,369
180,687,794
68,043,229
17,250,025
4,926,384
189,471
3,778,197
156,863
80,392
27,421,288
81,451
99,274
Distribution
Cost of
Service
J
33,400,393
30,142,568
1,544,364
5,753
258,268
44,276
(3,963)
80,803
17,456
1,131,617
83,896
95,357
Retail
Cost of
Service
K
8,310,784
3,421,235
2,139,929
621,306
36,254
1,145,314
81,940
2,542
3,262
574,169
132,987
151,846
Misc
Cost of
Service
L
(0)
30,365,272
(37,991,083)
(6,015,164)
(2,274,915)
17,590,762
875,850
(95,918)
(365,365)
(9,146,204)
6,166,962
889,803
Increase
(Decrease)
to = ROR
M
0.00%
4.20%
-7.12%
-3.90%
-19.84%
6.40%
4.92%
-12.79%
-28.12%
-6.71%
22.16%
2.07%
Percentage
Change from
Current Revenues
Rocky Mountain Power
Exhibit RMP___(RMM-2) Page 1 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
1
6
8
7,11,12
9
10
15
15
23
SpC
SpC
1
2
3
4
5
6
7
8
9
10
11
Footnotes :
Column C :
Column D :
Column E :
Column F :
Column G :
Column H :
Column I :
Column J :
Column K :
Column L :
Column M :
12
Schedule
No.
Line
No.
A
1,928,401,585
725,755,615
534,176,006
154,637,763
11,464,578
274,856,220
17,812,538
749,866
1,299,358
136,730,488
27,835,175
43,083,978
Annual
Revenue
C
7.58%
6.88%
9.03%
8.35%
14.33%
6.25%
6.71%
10.74%
16.89%
8.90%
3.60%
7.08%
E
Rate of
Return
Index
D
Return on
Rate
Base
1.00
0.91
1.19
1.10
1.89
0.82
0.88
1.42
2.23
1.17
0.47
0.93
F
1,926,352,189
754,462,147
496,162,036
148,777,226
8,916,551
292,331,142
18,680,912
652,337
933,492
127,484,531
33,988,467
43,963,347
Total
Cost of
Service
G
1,299,905,499
437,945,762
349,486,989
108,456,328
3,198,163
241,655,247
12,306,209
347,842
724,187
80,702,235
27,936,507
37,146,029
Production
Cost of
Service
Annual revenues based on January 2015 thru December 2015 data.
Calculated Return on Ratebase per January 2015 thru December 2015 Embedded Cost of Service Study
Rate of Return Index. Rate of return by rate schedule, divided by Utah Jurisdiction's normalized rate of return.
Calculated Full Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study
Calculated Generation Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Transmission Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Distribution Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Retail Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Miscellaneous Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Increase or Decrease Required to Move From Annual Revenue to Full Cost of Service Dollars.
Increase or Decrease Required to Move From Annual Revenue to Full Cost of Service Percent.
Total Utah Jurisdiction
Residential
General Service - Large
General Service - Over 1 MW
Street & Area Lighting
General Service - High Voltage
Irrigation
Traffic Signals
Outdoor Lighting
General Service - Small
Customer 1
Customer 2
Description
B
H
282,649,490
102,692,687
75,090,162
22,427,634
511,451
49,306,132
2,529,485
65,737
108,569
17,691,233
5,754,565
6,471,834
Transmission
Cost of
Service
Rocky Mountain Power
Counterfactual Cost Of Service By Rate Schedule
State of Utah
12 Months Ended Dec 2015
2010 Protocol (Non Wgt)
7.56% = Target Return on Rate Base
I
302,383,164
180,516,771
67,907,980
17,264,592
4,916,375
183,301
3,767,900
156,242
80,202
27,410,035
80,976
98,789
Distribution
Cost of
Service
J
33,102,808
29,882,860
1,537,545
6,601
254,936
43,384
(4,586)
79,980
17,279
1,105,984
83,692
95,133
Retail
Cost of
Service
K
8,311,228
3,424,067
2,139,359
622,072
35,626
1,143,078
81,904
2,535
3,256
575,045
132,727
151,560
Misc
Cost of
Service
L
(2,049,396)
28,706,532
(38,013,970)
(5,860,537)
(2,548,027)
17,474,922
868,374
(97,529)
(365,866)
(9,245,957)
6,153,292
879,369
Increase
(Decrease)
to = ROR
M
-0.11%
3.96%
-7.12%
-3.79%
-22.23%
6.36%
4.88%
-13.01%
-28.16%
-6.76%
22.11%
2.04%
Percentage
Change from
Current Revenues
Rocky Mountain Power
Exhibit RMP___(RMM-2) Page 2 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
1
6
8
7,11,12
9
10
15
15
23
SpC
SpC
1
2
3
4
5
6
7
8
9
10
11
Footnotes :
Column C :
Column D :
Column E :
Column F :
Column G :
Column H :
Column I :
Column J :
Column K :
Column L :
Column M :
12
Schedule
No.
Line
No.
A
4,237,420
2,986,647
577,888
221,119
1
(1)
22,494
(1)
1
429,271
0
0
Annual
Revenue
C
0.02%
0.04%
0.00%
-0.02%
0.84%
0.01%
0.01%
0.06%
0.02%
0.01%
0.01%
0.01%
E
Rate of
Return
Index
D
Return on
Rate
Base
0.00
0.00
(0.00)
(0.01)
0.11
(0.00)
(0.00)
0.00
(0.00)
(0.00)
(0.00)
(0.00)
F
2,188,024
1,327,908
555,001
375,747
(273,111)
(115,841)
15,018
(1,612)
(500)
329,518
(13,671)
(10,434)
Total
Cost of
Service
G
2,383,881
1,470,701
600,287
302,613
(234,503)
(67,815)
21,981
(100)
(41)
303,777
(8,205)
(4,815)
Production
Cost of
Service
Annual revenues based on January 2015 thru December 2015 data.
Calculated Return on Ratebase per January 2015 thru December 2015 Embedded Cost of Service Study
Rate of Return Index. Rate of return by rate schedule, divided by Utah Jurisdiction's normalized rate of return.
Calculated Full Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study
Calculated Generation Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Transmission Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Distribution Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Retail Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Miscellaneous Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Increase or Decrease Required to Move From Annual Revenue to Full Cost of Service Dollars.
Increase or Decrease Required to Move From Annual Revenue to Full Cost of Service Percent.
Total Utah Jurisdiction
Residential
General Service - Large
General Service - Over 1 MW
Street & Area Lighting
General Service - High Voltage
Irrigation
Traffic Signals
Outdoor Lighting
General Service - Small
Customer 1
Customer 2
Description
B
432,489
285,105
97,351
56,954
(24,639)
(38,727)
3,993
(62)
(84)
61,751
(4,527)
(4,626)
Transmission
Cost of
Service
H
Rocky Mountain Power
Counterfactual Cost Of Service less Actual Cost of Service By Rate Schedule
State of Utah
12 Months Ended Dec 2015
2010 Protocol (Non Wgt)
7.56% = Target Return on Rate Base
I
(331,205)
(171,023)
(135,249)
14,567
(10,009)
(6,170)
(10,297)
(621)
(191)
(11,253)
(475)
(484)
Distribution
Cost of
Service
J
(297,585)
(259,708)
(6,819)
848
(3,332)
(893)
(622)
(822)
(177)
(25,633)
(204)
(224)
Retail
Cost of
Service
K
444
2,832
(569)
765
(629)
(2,236)
(36)
(7)
(6)
876
(260)
(286)
Misc
Cost of
Service
L
(2,049,396)
(1,658,740)
(22,887)
154,628
(273,112)
(115,840)
(7,476)
(1,611)
(501)
(99,753)
(13,671)
(10,434)
Increase
(Decrease)
to = ROR
M
-0.11%
-0.25%
0.00%
0.11%
-2.38%
-0.04%
-0.05%
-0.21%
-0.04%
-0.05%
-0.05%
-0.02%
Percentage
Change from
Current Revenues
Rocky Mountain Power
Exhibit RMP___(RMM-2) Page 3 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-3)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Benchmark of Utah Residential Distributed Generation Production Shape to National
Renewable Energy Laboratory’s PVWatts® Distributed Generation Shape
November 2016
Rocky Mountain Power
Exhibit RMP___(RMM-3) Page 1 of 5
Docket No. 16-035-__
Witness: Robert M. Meredith
Benchmark of Utah Residential Distributed Generation Production Shape to National
Renewable Energy Laboratory’s PVWatts® Distributed Generation Shape
Prepared and Published by the Load Research Group
October 6, 2016
Rocky Mountain Power
Exhibit RMP___(RMM-3) Page 2 of 5
Docket No. 16-035-__
Witness: Robert M. Meredith
Background
In order to benchmark the residential distributed generation production shape, the Company
compared our findings to the hourly shapes from National Renewable Energy Laboratory’s
(“NREL”) online PVWatts® calculator. NREL's PVWatts® Calculator is a web-based application
developed by NREL that estimates the electricity production of a grid-connected roof- or
ground-mounted photovoltaic system. PVWatts® uses a number of sub-models to predict overall
system performance, and includes several built-in parameters.1 PVWatts® requires hourly data
for one year for two components of solar irradiance (beam and diffuse), ambient dry bulb
temperature, and wind speed at 10 meters above the ground. The PVWatts® web application
interacts with three online databases to access solar resource data and does not allow users to
specify their own weather data. Typical year solar resource data uses a single year's worth of
hourly data to represent solar radiation and meteorological data collected over a historical period
of multiple years. Each PVWatts® typical year file contains months of data selected from
different years in the data collection period. For example, data for a given site might contain
1995 data for the month of February, 2001 data for March, 1998 data for April.2
As illustrated in Figure A-1, both the residential distributed generation production curve and the
PVWatts® curve exhibit similar behavior and shape. However, the residential distributed
generation curve during the months of May and December are lower than the PVWatts® curve. A
possible explanation for this was found by evaluating average hourly cloud cover data for Salt
Lake City over the 8am to 7pm timeframe. The Company found that, on average, the percentage
of cloud cover on an hourly basis in Salt Lake City during May 2015 was 67 percent.3 Whereas,
the five-year average for May over the 2011 to 2015 period is 55 percent. Indicating that May
2015 was cloudier than normal. Similarly, the percentage of cloud cover on an hourly basis over
the 8am to 7pm timeframe was 66 percent for Salt Lake City in December 2015. Whereas, the
five-year average for December over the 2011 to 2015 period is 60 percent.4
Dobos, Aron P., September 2014, NREL, PVWatts® Version 5 Manual, Website (http://pvwatts.nrel.gov/pvwatts.php) accessed October 4, 2016. 2
PVWatts®, PVWatts® Documentation/Solar Resource Data, Website (http://pvwatts.nrel.gov/pvwatts.php#help_resource_typicalyear) accessed October 6, 2016. 3
MDA Federal Weather Data, Salt Lake City Airport 4
Ibid. 1
Rocky Mountain Power
Exhibit RMP___(RMM-3) Page 3 of 5
Docket No. 16-035-__
Witness: Robert M. Meredith
Figure A-1
Hourly Average Power Generation for Utah NEM and NREL 0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
01‐01
01‐09
01‐17
02‐01
02‐09
02‐17
03‐01
03‐09
03‐17
04‐01
04‐09
04‐17
05‐01
05‐09
05‐17
06‐01
06‐09
06‐17
07‐01
07‐09
07‐17
08‐01
08‐09
08‐17
09‐01
09‐09
09‐17
10‐01
10‐09
10‐17
11‐01
11‐09
11‐17
12‐01
12‐09
12‐17
0
NREL
Company
In order to provide more than a visual comparison of the two data, the Company, elected to
compare the two samples by constructing a linear regression. A regression assesses whether the
predictor variables (the Company residential distributed generation production shape) account
for variability in a dependent variable (the PVWatts® production shape). By treating the
PVWatts® generation data as the dependent variable and the residential distributed generation
production sample data as the independent variable the Company can measure how
representative the sample data is to the PVWatts® data.
The regression model produces numerous statistics that provide an indication of how
representative the two datasets are of one another. A description of these statistics and how they
indicate a relationship between the data are provided below.
Regression Model Fit 
Adjusted R-squared, or the coefficient of determination, is a statistical measure of how
close the data are to the fitted regression line. The Adjusted R-squared value corrects for
inflation of the R-squared value due to the number of variables in the model. It is the
percentage of the total variation in the dependent variable explained by the regression
model and is measured on a scale of 0 to 1. An Adjusted R-squared value of 1 indicates
the dependent variable is entirely determined by the independent variables. As provided
in Table A-1, the regression has an Adjusted R-squared of 0.994, indicating that the
model is a good predictor of the dependent variable.

Durbin-Watson statistic is used to test for the presence of autocorrelation in residuals and
is measured on a scale of 0 to 4. Autocorrelation means the residuals (the actual values of
Rocky Mountain Power
Exhibit RMP___(RMM-3) Page 4 of 5
Docket No. 16-035-__
Witness: Robert M. Meredith
the dependent variable minus the predicted values) from the regression are not mutually
independent. If they are correlated, then least-squares regression underestimates the
standard error of the coefficients and the predictors could appear significant when they
may not be. A low (0) and high (4) Durbin-Watson statistic indicates the presence of
autocorrelation; whereas, a Durbin-Watson statistic of 2 specifies that autocorrelation has
been removed from the regression. As provided in Table A-1, the regression has a
Durbin-Watson statistic of 2.082, indicating that autocorrelation has been corrected
within the model.
Regression Results

The regression coefficient represents the slope of the linear regression. If the coefficient
is significant (i.e., the t-value is significant), the coefficient indicates that for every 1.0unit change in the independent variable, the prediction of the dependent variable will
change by the coefficient’s value. For example, as provided in Table A-1, the
independent variable (Company) coefficient is 1.036 and statistically significant.
Therefore, for each 1.0-unit increase in the independent variable, the predicted value of
the dependent variable will increase by 1.036 units, indicating the two sets of data behave
similarly.

Elasticity is a measure of how responsive a variable is based on the change in another
variable. Specifically, elasticity is the percentage change in the dependent variable due to
a percent change in the independent variable. An elasticity of 1.0 indicates that for a 1.0
percent change in the independent variable there is a corresponding 1.0 percent change in
the dependent variable. As provided in Table A-1, the coefficient has an elasticity of
0.942, indicating that a 1.0 percent change in the independent variables will result in a
0.942 percent change in the dependent variable, indicating the two sets of data behave
similarly.

Correlation coefficient is a measure of the strength of the degree of association between
to random variables and ranges in value from -1 to 1. As provided in Table A-1, the
correlation coefficient of 0.984 indicates a strong degree of association between the
independent and dependent variable and that the data behave similarly.
Rocky Mountain Power
Exhibit RMP___(RMM-3) Page 5 of 5
Docket No. 16-035-__
Witness: Robert M. Meredith
Table A-1
Regression Results
Variable CONST Company AR(1) AR(2) Variable Company Model Statistics Adjusted Observations R‐Squared Adjusted R‐Squared Sum of Squared Errors Mean Squared Error Std. Error of Regression Durbin‐Watson Statistic Correlation Table NREL Company Coefficient Standard Error
0.005
0.005
1.036
0.021
1.252
0.049
‐0.419
0.048
Coefficient Mean 1.036
0.187
286 0.994 0.994 0.12 0 0.02 2.082 NREL T‐Stat 1.145 50.283 25.476 ‐8.659 Elasticity 0.942 Company 1
0.984
0.984
1
P‐Value 25.34%
0.00%
0.00%
0.00%
Rocky Mountain Power
Exhibit RMP___(RMM-4)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Difference in Energy Sales Between CFCOS and ACOS
November 2016
Line
No.
Residential
General Service-Distribution-Small
General Service-Distribution
General Service-Distribution > 1,000 kW
Irrigation
Total Sales to Net Metering Customers
1
2
3
4
5
6
Description
(1)
135
23-135
6-135
8-135
10-135
Tariff
Sch
No.
(1)
4,931
4,390
327
194
8
13
Average
No. of
Customers
Actual
(2)
188,410
23,912
4,692
86,284
72,182
1,340
Actual Billed
Energy
(MWh)
(3)
211,497
39,124
7,175
91,321
72,329
1,549
Energy Delivered from
the Energy Grid
to the Customer
(MWh)
(4)
24,668
15,961
3,216
5,007
175
309
Energy Exported
from Private Generation
to the Energy Grid
(MWh)
(5)
52,877
28,304
6,012
12,342
5,736
484
Estimated
Private Generation
Production
(MWh)
(6)
Difference in Energy Sales Between Counterfactual Cost of Service and Actual Cost of Service
Rocky Mountain Power
State of Utah
12 Months Ending December 2015
239,706
51,468
9,971
98,655
77,889
1,724
51,297
27,556
5,279
12,371
5,707
384
Full Requirements Difference Between
Energy Usage
CFCOS and ACOS
(MWh)
(MWh)
(7)
(8)
(4) + [(6) - (5)]
(7) - (3)
Rocky Mountain Power
Exhibit RMP___(RMM-4) Page 1 of 1
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-5)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Bill Credits Related to the Net Metering Program
November 2016
Line
No.
135
6-135
23-135
6-135
6A-135
8-135
23-135
6-135
6A-135
23-135
10-135
Residential
Residential
General Service-Distribution
General Service-Distribution-Small
Total Residential
Commercial
General Service-Distribution
General Service-Distribution-Energy TOD
General Service-Distribution > 1,000 kW
General Service-Distribution-Small
Total Commercial
Industrial
General Service-Distribution
General Service-Distribution-Energy TOD
General Service-Distribution-Small
Total Industrial
Irrigation
Irrigation
Total Irrigation
Total Bill Credits
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Description
(1)
Tariff
Sch
No.
(2)
4,931
13
13
7
7
11
25
154
19
8
277
457
4,390
6
40
4,436
Average
No. of
Customers
Actual
(3)
239,706
1,724
1,724
3,154
5,354
542
9,051
85,384
3,653
77,889
8,940
175,865
51,468
1,110
489
53,066
MWh
Actual
(4)
$20,903
$133
$133
$328
$620
$45
$993
$7,007
$402
$5,609
$833
$13,851
$5,765
$110
$50
$5,925
Revenues
($000)
Actual
(5)
CFCOS
Without DG
Bill Credits Related to the Net Metering Program
Rocky Mountain Power
State of Utah
12 Months Ending December 2015
188,410
1,340
1,340
2,823
3,617
242
6,682
76,337
2,516
72,182
4,206
155,241
23,912
991
244
25,147
MWh
Actual
(6)
ACOS
With DG
$16,665
$111
$111
$316
$467
$23
$806
$6,683
$317
$5,387
$448
$12,836
$2,778
$106
$28
$2,912
Revenues
($000)
Actual
(7)
51,297
384
384
331
1,737
300
2,369
9,047
1,137
5,707
4,734
20,624
27,556
119
245
27,919
MWh
Actual
(8)
$4,237
$22
$22
$12
$153
$22
$187
$324
$84
$221.1
$385
$1,015
$2,987
$4
$22
$3,013
Revenues
($000)
Actual
(9)
Difference
Rocky Mountain Power
Exhibit RMP___(RMM-5) Page 1 of 1
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-6)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Customer Service and Billing Cost Related to Utah Net Metering Program
November 2016
8,015
3,127
4,945
7,383
2,961
4,390
350
80
327
243
63
194
9
2
7
30
21
28
FERC Account
Total Cost for Utah Cost Related to Residential Cost Related to Schedule 23 Cost Related to Schedule 6 Cost Related to Schedule 8 Cost Related to Schedule 10
903
$13,686
$12,607
$598
$415
$15
$51
903
$18,795
$17,797
$481
$379
$12
$126
903
$50,510
$44,843
$3,336
$1,977
$68
$286
903
$82,991
$75,247
$4,415
$2,771
$95
$463
Notes
To determine the proportion of each cost category that is related to the different customer classes, overall cost estimates for each activity are spread based upon appropriate drivers for those costs.
The cost for phone calls is allocated on the number of applications in the period, since the cost is primarily for customers who are considering participation in the net metering program. Initial setup cost is allocated based upon the number of interconnections during the period. Ongoing support is allocated by the average bills during the period.
2015 Applications
2015 Interconnections
2015 Net Metering Customers
Description
Phone Calls
Initial Setup
Ongoing Support
Total
Customer Service and Billing Cost Related to Utah Net Metering Program
12 Months Ending December 31, 2015
Rocky Mountain Power
Exhibit RMP___(RMM-6) Page 1 of 1
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-7)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Administration Cost Related to Utah Net Metering Program
November 2016
Description
Estimated Incremental Cost of Administration
Application Fee Revenue
Net Estimated Incremental Cost of Administration
Administration Cost Related to Utah Net Metering Program
12 Months Ending December 31, 2015
FERC Total Cost for Cost Related to Cost Related to Cost Related to Cost Related to Cost Related to Accounting Utah
Residential
Schedule 23
Schedule 6
Schedule 8
Schedule 10
903 $242,247.73
$198,751.88
$16,109.57
$19,667.11
$671.23
$7,047.94
903 ($16,988.46)
($137.90)
($7,404.43)
($5,880.37)
($1,292.00)
($2,273.76)
903 $225,259.27
$198,613.98
$8,705.14
$13,786.74
($620.77)
$4,774.18
Rocky Mountain Power
Exhibit RMP___(RMM-7) Page 1 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
Customer Generation Administrative Expense
$242,248
$1,812
$2,148
Utah
Wyoming
Idaho
3,127 17 32
1.15 1.59 1.00
3,609 27 32
Description
Interconnection Count
Complexity Weighting
Weighted Interconnection Count
$46,382
$12,149
$3,021
$307,760
Oregon
Washington
California
Total
539 141 43 3,899
1.28 1.28 1.05
691 181 45 4,585
Cost Related to Cost Related to Cost Related to Cost Related to Schedule 23
Schedule 6
Schedule 8
Schedule 10
80 63 2 21 3 5 5
5
240 293 10 105 $16,109.57
$19,667.11
$671.23
$7,047.94
Cost Related to Total Cost for Utah Residential
3,127 2,961 1
3,609 2,961 $242,247.73
$198,751.88
Description
Interconnection Count
Complexity Weighting
Weighted Interconnection Count
Estimated Incremental Cost of Administration
State and Class Allocation of Net Metering Administration Cost
12 Months Ending December 31, 2015
Rocky Mountain Power
Exhibit RMP___(RMM-7) Page 2 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-7) Page 3 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
Administration Complexity Weighting Factors by State
12 Months Ending December 31, 2015
Utah
Schedule
08NETMT135
08NMT06135
08NMT10135
08NMT23135
08NMT6A135
08RNM06135
08RNM23135
08NMT08135
Total
Wyoming
Interconnections
2,961
51
21
66
11
1
14
2
3,127
Complexity Weighting
1
5
5
3
3
5
3
5
State Complexity Weighting
Weighted Interconnections
2,961
255
105
198
33
5
42
10
3,609
1.15
Idaho
Schedule
07NETMT135
Total
Complexity Weighted Interconnections
Interconnections Weighting
32
1 32
Complexity Weighting
1
3
3
17
Weighted Interconnections
12
12
3
27
State Complexity Weighting
32
32
Schedule
01NETMT135
01NMT23135
01NMT28135
01NMT41135
01NMTOU135
01RNETM023
01NMU41135
01NMT41215
Total
1.00
State Complexity Weighting
Washington
Total
Total
Interconnections
12
4
1
1.59
Oregon
State Complexity Weighting
Schedule
02NETMT135
02NMT24135
02NMT36135
02NMT48135
Schedule
05NETMT135
05NMT25135
05NMT28135
Interconnections
478
26
18
3
3
7
3
1
539
Complexity Weighting
1
3
5
3
1
3
3
3
Weighted Interconnections
478
78
90
9
3
21
9
3
691
1.28
California
Interconnections
125
12
3
1
141
State Complexity Weighting
Complexity Weighting
1
3
5
5
Weighted Interconnections
125
36
15
5
Schedule
06NETMT135
06NMT32135
Complexity Weighted Interconnections Weighting Interconnections
42 1 42
1 3 3
181
Total
43
1.28
State Complexity Weighting
45
1.05
The complexity weightings are based upon the Company's estimates of time it takes to process net metering applications from customers on
various rate schedules.
Rocky Mountain Power
Exhibit RMP___(RMM-8)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Engineering Cost Related to Utah Net Metering Program
November 2016
Description
Cost of Engineer ($/hour)
Application Review Time (Hours)
Cost of Engineering for Each Interconnection
2015 Applications
Estimated Incremental Cost of Engineering
Engineering Cost Related to Utah Net Metering Program
12 Months Ending December 31, 2015
91.72
580
Cost Related to Schedule 23
Cost Related to Schedule 6
Cost Related to Schedule 8
Cost Related to Schedule 10
0.33 0.50 2.00 3.00 4.00
$45.86
$183.44
$275.16
$366.88
$30.57
7,383 350 243 9 30
$299,808
$225,698
$16,051
$44,576
$2,476
$11,006
FERC Account Total Cost for Utah Cost Related to Residential
Rocky Mountain Power
Exhibit RMP___(RMM-8) Page 1 of 1
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-9)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Metering Cost Related to Utah Net Metering Program
November 2016
Meter Capital Cost per Installation in 2002
Meter Capital Cost per Installation in 2003
Meter Capital Cost per Installation in 2004
Meter Capital Cost per Installation in 2005
Meter Capital Cost per Installation in 2006
Meter Capital Cost per Installation in 2007
Meter Capital Cost per Installation in 2008
Meter Capital Cost per Installation in 2009
Meter Capital Cost per Installation in 2010
Meter Capital Cost per Installation in 2011
Meter Capital Cost per Installation in 2012
Meter Capital Cost per Installation in 2013
Meter Capital Cost per Installation in 2014
Meter Capital Cost per Installation in 2015
Interconnections in 2002
Interconnections in 2003
Interconnections in 2004
Interconnections in 2005
Interconnections in 2006
Interconnections in 2007
Interconnections in 2008
Interconnections in 2009
Interconnections in 2010
Interconnections in 2011
Interconnections in 2012
Interconnections in 2013
Interconnections in 2014
Interconnections in 2015
Description
Estimated Incremental Cost of Reprogramming Meters
Percent of Meters to Reprogram versus Replace Metering Cost Related to Utah Net Metering Program
12 Months Ending December 31, 2015
FERC Account Total Cost for Utah ‐
‐
‐
‐
‐
1
‐
7
18
30
24
29
53
63
$419.64
$419.07
$419.07
$411.15
$411.15
$411.15
$411.15
$411.15
$411.15
$417.96
$417.96
$417.96
$417.96
$417.96
‐
‐
1
2
‐
3
29
13
17
31
25
46
65
80
$353.84
$353.84
$353.84
$341.71
$341.71
$341.71
$341.71
$341.71
$341.71
$364.92
$364.92
$364.92
$364.92
$364.92
1
4
3
49
14
60
184
112
198
274
393
607
1,232
2,961
$162.23
$163.12
$163.12
$153.08
$153.14
$176.25
$188.31
$188.31
$188.31
$188.31
$188.31
$188.31
$188.31
$188.31
$506.60
$506.60
$506.60
$489.03
$489.03
$489.03
$489.03
$489.03
$489.03
$451.20
$451.20
$451.20
$451.20
$451.20
‐
‐
‐
‐
‐
‐
‐
1
‐
‐
3
2
‐
2
$419.64
$419.07
$419.07
$411.15
$411.15
$411.15
$411.15
$411.15
$411.15
$417.96
$417.96
$417.96
$417.96
$417.96
‐
‐
‐
1
‐
‐
‐
‐
‐
‐
1
‐
5
21
Cost Related to Cost Related to Cost Related to Cost Related to Cost Related to Residential Schedule 23 Schedule 6 Schedule 8 Schedule 10 $237.00
$237.00
$237.00
N/A
$237.00
0%
20%
47%
43%
4%
Rocky Mountain Power
Exhibit RMP___(RMM-9) Page 1 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
$38,841.40
403
586
Reprogramming Cost Expense in 2015
$0.00
$3,792.00
$7,110.00
Deprecia on expense is determined from the deprecia on in 2015.
To determine accumulated depreciation for meters, the capital for each year is depreciated by the currently effective depreciation rates for each year and
summed across all years. Data reflects a 13 month average, as is used in the results of operations reports.
To determine gross meter plant, the number of installed meters for each year are multiplied by the cost of a meter capable of measuring bi‐directional energy
flows for the year and summed across all years from 2002 through 2015. Data reflects a 13 month average, as is used in the results of operations reports.
Notes
To measure the bi‐directional flow of energy for a net metering customer, the meter for residential customers is replaced. Some of the meters installed for
non‐residential customers may be capable of measuring bi‐directional flows of energy, but need to be reprogrammed to do so.
For non‐residential customers, the meter is therefore either replaced or reprogrammed. The proportions that were reprogrammed versus replaced for each
non‐residential customer class are assumed to be the same as the proportions of meters currently in place that are capable of being reprogrammed or which
would have to be replaced. To determine meter reprogramming expense for 2015, the number of interconnections during 2015 are multiplied by the estimated
proportion of meters that need to be reprogrammed which are multiplied by the estimated cost of reprogramming.
$11,376.00
$995,933.41
‐$74,167.82
$237.00
$237.00
Total Cost for Cost Related to Cost Related to Cost Related to Cost Related to Cost Related to Utah Residential Schedule 23 Schedule 6 Schedule 8 Schedule 10 $162.23
$162.23
$0.00
$0.00
$0.00
$0.00
$652.46
$0.00
$0.00
$0.00
$0.00
$652.46
$0.00
$0.00
$0.00
$843.19
$489.35
$353.84
$683.41
$0.00
$0.00
$411.15
$8,595.33
$7,500.77
$2,144.01
$2,144.01
$0.00
$0.00
$0.00
$0.00
$10,574.71
$683.41
$411.15
$0.00
$0.00
$11,669.27
$7,859.27
$0.00
$0.00
$0.00
$42,508.55
$34,649.28
$3,417.07
$1,644.58
$489.03
$0.00
$26,641.55
$21,090.87
$37,285.64
$4,783.90
$4,111.46
$0.00
$0.00
$46,181.00
$51,597.30
$9,123.00
$6,687.36
$0.00
$0.00
$67,407.66
$74,006.35
$7,298.40
$5,433.48
$902.40
$417.96
$88,058.59
$134,527.61
$114,304.97
$13,502.04
$6,269.40
$451.20
$0.00
$231,999.55
$18,975.84
$11,702.88
$0.00
$2,089.80
$264,768.07
$603,547.78
$557,589.82
$23,354.88
$13,792.68
$451.20
$8,359.20
370
108370
FERC Account Meters Gross Plant (13‐month average)
Accumulated Depreciation (13‐month average)
Accumulated Deferred Income Tax Balance (ADIT)
Depreciation Expense
Description
Estimated Incremental Metering Capital Cost in 2002
Estimated Incremental Metering Capital Cost in 2003
Estimated Incremental Metering Capital Cost in 2004
Estimated Incremental Metering Capital Cost in 2005
Estimated Incremental Metering Capital Cost in 2006
Estimated Incremental Metering Capital Cost in 2007
Estimated Incremental Metering Capital Cost in 2008
Estimated Incremental Metering Capital Cost in 2009
Estimated Incremental Metering Capital Cost in 2010
Estimated Incremental Metering Capital Cost in 2011
Estimated Incremental Metering Capital Cost in 2012
Estimated Incremental Metering Capital Cost in 2013
Estimated Incremental Metering Capital Cost in 2014
Estimated Incremental Metering Capital Cost in 2015
Metering Cost Related to Utah Net Metering Program
12 Months Ending December 31, 2015
Rocky Mountain Power
Exhibit RMP___(RMM-9) Page 2 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
Year End 13‐month average
$1,297,707 $ 995,933
2002 through 2004
2005 through 2007
2008 through 2010
2011 through 2013
2014 through 2015
Totals
Tax Data:
$38,841
Account 403 ‐ Depreciation Expense
1,658
22,408
115,332
289,995
868,316
1,297,709
Plant in
Service
$38,841
‐$95,387 $ (74,168)
Account 108370 ‐ Accumulated Depreciation
$41
2004
$5
$22
$14
$198
2005
$5
$22
$28
$143
Depreciation Rates:
64
874
4,498
11,310
22,095
38,841
39
1,001
2,832
7,211
322,648
333,731
(12)
50
(634)
(1,555)
114,064
111,913
SCHMAT
SCHMDT
41010
Book
Tax
Def Inc
Depreciation Depreciation Tax Exp
$16
$3
Account 370 ‐ Gross Plant
2003
$5
$11
Estimated Incremental Metering Capital Cost in 2002
Estimated Incremental Metering Capital Cost in 2003
Estimated Incremental Metering Capital Cost in 2004
Estimated Incremental Metering Capital Cost in 2005
Estimated Incremental Metering Capital Cost in 2006
Estimated Incremental Metering Capital Cost in 2007
Estimated Incremental Metering Capital Cost in 2008
Estimated Incremental Metering Capital Cost in 2009
Estimated Incremental Metering Capital Cost in 2010
Estimated Incremental Metering Capital Cost in 2011
Estimated Incremental Metering Capital Cost in 2012
Estimated Incremental Metering Capital Cost in 2013
Estimated Incremental Metering Capital Cost in 2014
Estimated Incremental Metering Capital Cost in 2015
2002
$3
Total Cost for Utah
$162
$652
$843
$8,595
$2,144
$11,669
$42,509
$26,642
$46,181
$67,408
$88,059
$134,528
$264,768
$603,548
Metering Depreciation Related to Utah Net Metering Program
12 Months Ending December 31, 2015
(280)
(1,737)
(21,049)
(63,965)
(107,202)
(194,233)
282 ADIT
13‐month
Average
$376
2006
$5
$22
$28
$285
$36
4/1/2000
4/1/2003
1/1/2008
1/1/2014
$605
2007
$5
$22
$28
$285
$71
$194
3.79%
3.32%
3.25%
3.90%
$1,473
2008
$5
$21
$27
$279
$70
$379
$691
$2,597
2009
$5
$21
$27
$279
$70
$379
$1,382
$433
$3,780
2010
$5
$21
$27
$279
$70
$379
$1,382
$866
$750
$5,626
2011
$5
$21
$27
$279
$70
$379
$1,382
$866
$1,501
$1,095
$8,152
2012
$5
$21
$27
$279
$70
$379
$1,382
$866
$1,501
$2,191
$1,431
$11,769
2013
$5
$21
$27
$279
$70
$379
$1,382
$866
$1,501
$2,191
$2,862
$2,186
$21,909
2014
$6
$25
$33
$335
$84
$455
$1,658
$1,039
$1,801
$2,629
$3,434
$5,247
$5,163
2015
$6
$25
$33
$335
$84
$455
$1,658
$1,039
$1,801
$2,629
$3,434
$5,247
$10,326
$11,769
$38,841
Total
$74
$276
$328
$3,060
$692
$3,379
$10,914
$5,974
$8,855
$10,735
$11,161
$12,679
$15,489
$11,769
$95,387
Rocky Mountain Power
Exhibit RMP___(RMM-9) Page 3 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-10)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Sampling Plans, Procedures and Selections for the Profile Metering Sample
of Utah Residential Distributed Generation
November 2016
Rocky Mountain Power
Exhibit RMP___(RMM-10) Page 1 of 11
Docket No. 16-035-__
Witness: Robert M. Meredith
0 KY' MOUNTAIN
WER
Sampling Plans, Procedures and Selections
For the Profile Metering Sample of
Utah Residential Distributed Generation
2014
Prepared and Published by the
Load Research Group
May2014
Rocky Mountain Power
Exhibit RMP___(RMM-10) Page 2 of 11
Docket No. 16-035-__
Witness: Robert M. Meredith
May 9, 2014
Executive Summary
This sample design was prepared in support of the Load Research Company Cost-ofService commitment, with the intent of installing a load study on the Company's Utah
Residential Distributed Generation Class. All sample designs were prepared in
accordance with PURPA standards and, as such, are expected to provide estimates of
system peak demand that achieve, at a minimum, ±10% precision at the 90% confidence
level.
The recommended sample design for this study incorporates four strata and calls for the
installation of 62 load recorders. Based on the level of recorders installed, the sample
design estimates an achieved precision level of ±10% at the 95% confidence level. The
strata boundaries for this sample are based upon the "cumulative square root off" rule as
defined in studies by Dalenius/Hodges. Appendix 1 contains a listing of both primary
and alternate sample sites selected for this study. These sites have been cross referenced
against current installations, and any duplicates have been noted.
Scott D. Thornton
Manager, Load Research
Rocky Mountain Power
Exhibit RMP___(RMM-10) Page 3 of 11
Docket No. 16-035-__
Witness: Robert M. Meredith
Utah Residential DG (2014)
Load Recorder Study
Sampling Procedures
This paper describes the procedures used to develop the 2014 Utah Residential
Distributed Generation Load Study. This study will provide load data for use in support
of cost studies and price filings before the Utah Public Service Commission, and for use
in studies of customer demand characteristics. The goal of this sample design is to
provide relative precision of± 10% at the 95% confidence level for an estimate of
demand at the time of the monthly system peak hours.
Recorders will be placed in service effective no later than August 1st, 2014, and will be
monitored on a continuous basis to insure no significant deviation from billing records.
Sampling Plan for Utah
This sampling plan includes several steps:
1.
2.
3.
4.
5.
6.
7.
8.
9.
Formalization of the sample parameters;
Specification of the target variable;
Choice of the stratification variable;
Choice of method for estimating kW;
Choice of the number of strata;
Construction of the strata boundaries
Allocation of sample points to each stratum;
Selection of primary sample sites;
Selection of alternate sample sites.
Formalization of the sample parameters
This is a new load study, designed to provide estimates ofload characteristics for the
residential distributed generation population in Utah. Input data to be utilized in this
design includes billing data for the period June 2013 through March 2014. The design
will be based on a stratified random, single-dimensional sampling schema.
In this approach, customers with similar characteristics are grouped together into
non-overlapping, homogeneous groups called "strata," and individual samples are
selected from each stratum.
Rocky Mountain Power
Exhibit RMP___(RMM-10) Page 4 of 11
Docket No. 16-035-__
Witness: Robert M. Meredith
The strata are defined according to a user-specified demographic or usage variable called
the "design variable." For continuous variables such as usage, the Dalenius-Hodges rule
is used to define the strata boundaries. The Neyman allocation procedure is used to
determine the optimum sample size for each stratum. (In Neyman allocation, the sample
size for each stratum is determined according to its population proportion and the
standard deviation. Data from prior load research studies, if available, may also be used
to determine the mean and the standard deviation.) A simple random sample is then
selected from each stratum.
Because customer-to-customer variation is the basic determinant of sample size (the more
the variation, the larger the sample), fewer sampling units need to be selected from a
population that has been stratified into homogeneous groups than if the units were merely
selected from the entire population at random. In other words, because the variation
within a stratum is less than for the entire population, fewer sample points are required to
obtain the same accuracy level.
Stratification is a good choice when you need to economize with a smaller sample size,
yet maintain a specified level of accuracy. It is also useful when you need data for
specific demographic sets within the population (types of business, location, etc.).
However, stratification has some aspects which may make it inappropriate for certain
situations, i.e., since not all customers have the same chance of being selected, the sample
may not be as flexible. Therefore, if you wish to use the sample to perform analyses and
answer questions not anticipated in the original design, you may have to employ Domains
Analysis to ensure that original sample weights are taken into consideration.
Also, over time, some customers will change their characteristics and will migrate out of
their strata. However, the strata assignments must remain fixed throughout the analysis
period. For that reason, samples must be replaced periodically to keep them up to date.
S~edfication
of the target variable
Load studies in the state of Utah are used primarily to support cost allocation studies. For
this current study, a sample design was prepared based on average delivered customer
energy (billed kWh) over a designated 10 month period.
Bill frequency counts, by usage level, are summarized into standardized usage blocks to
identify the ideal monthly breakpoints for the design. Utilizing the process defined by
Dalenius-Hodges, these breakpoints are then averaged into strata to facilitate further
analysis (see Table A).
Billing data for the 10 months ending March 2014 were used to determine appropriate
stratification.
2
Rocky Mountain Power
Exhibit RMP___(RMM-10) Page 5 of 11
Docket No. 16-035-__
Witness: Robert M. Meredith
Choice of the Stratification Variable
A potential stratifying variable, according to Cochran, should meet four criteria 1:
1. The population is composed of institutions varying widely in size.
2. The principle variables to be measured are closely related to the sizes of the
institutions.
3. A good measure ofsize is available for setting up the strata.
Average monthly billing kWh (KWH_MNTH), which is the average monthly energy
registered over a given consecutive month period, was selected as the best available
variable for this purpose. As reporting of monthly customer usage for this group presents
the netted amount (delivery to the customer - delivery from the customer), it does
presents issues not normally dealt with. Customer usage may be reflected as a negative
value for instance. Or the much more likely scenario in which the usage delivered is
understated because of power delivered back to the Company. This will make validation
of sample results difficult. Nonetheless, the variable is readily available for all customers
in this class, with a range from -1,058 to 16,008 kWh for any given customer in this
group.
Choice of Method for Estimating kW
To estimate a peak demand for a population using MPU, the mean peak demand value
from the sample is multiplied by the number of elements in the entire population. Use of
the MPU method provides an unbiased estimate.
For ratio estimation, the ratio of the target variable over the auxiliary variable is
calculated for the sample. This ratio is then multiplied by the total annual billed kWh for
the population to get the estimated total group peak demand. Because energy usage and
peak demand are correlated, a ratio estimate will have a smaller variance than a MPU
estimate. However, a ratio estimate may be slightly biased.
With stratified sample designs, ratio estimators can be computed in two ways: separately
for each stratum, or a combined ratio can be computed over all strata. Separate ratio
estimation tends to result in smaller variance. However, the combined ratio method is
more appropriate when stratum sample sizes are small, because the risk of bias is
reduced.
Table B details the sample size required for the Utah Residential Distributed Generation
Load Study using a mean-per-unit method, assuming a four strata design, with modified
allocation utilizing the Tschprow/Neyman method.
1
William G. Cochran, "Sampling Techniques", Third Edition, Wiley, pg.IOI
3
Rocky Mountain Power
Exhibit RMP___(RMM-10) Page 6 of 11
Docket No. 16-035-__
Witness: Robert M. Meredith
Choke of the Number of Strata
As the number of strata increases, precision of the estimate of the total contribution to
demand (kW) at system peak also increases. However, the increase in precision per
additional stratum diminishes after a relatively small number of strata2. Desire for
simplicity and a reasonable number of sites in each stratum lead to a preference for a
small number of strata. If a minimum number of sites policy is followed (eg.10 sites
minimum per stratum), then the addition of strata can actually lead to more, rather than
fewer, total sites. If such a policy is not followed, the result can be strata with so few
recorders that confidence in sample estimates is at risk from unexpected data problems,
variance estimates may not be sufficiently precise for future sample design purposes, and
the sample may not be robust enough to be useful when analysis needs change.
A final decision on the number of strata requires actual cost comparison of potential
stratification schemes to evaluate effectiveness versus cost. For this study, a four strata
scheme was employed. The method described below was used to compare stratification
approaches.
Construction of Strata Boundaries
Various methods might be used for definition of strata boundaries. Cochran found the
"cumulative square root of f'' 3 rule, as defined by Dalenius and Hodges (1959), to be
superior in a comparative study of such methods applied to actual distributions exhibiting
a range of skewness.
With the Dalenius-Hodges procedure, the program divides the population in the
Frequency Distribution File into short intervals. Each interval has frequency f and
interval length u. The quantity .Yu! is summed over all the intervals, and this cumulative
-!uf is divided by a user-defined number of strata to give the optimum length of each
stratum.
Steps in calculating strata boundaries under the "cumulative -!uf' rule are as follows.
First, tabulate frequencies of the stratifying variable. For these studies, average monthly
energy (KWH_MNTH) from customer billing records for the ten months ending March,
2014 were used. All Utah Residential DG customers, whose month end status was
active, were included in this procedure, and in population figures for the sample design.
Second, multiply the number of customers in each interval by the interval factor. Third,
take the square root of these frequencies. Fourth, cumulatively sum the square roots.
The resulting distribution of adjusted cumulative square roots of frequency is then
partitioned into equal intervals by dividing by the number of strata. The final
stratification scheme of four strata is presented in Exhibit 1, and shows the optimal
boundaries resulting from the above procedure, after adjustments made to accommodate
prior cost analysis requirements (if any).
2
3
William G. Cochran, "Sampling Techniques", Third Edition, Wiley, Pg. 132
William G. Cochran, "Sampling Techniques'', Third Edition, Wiley, Pgs. 129-130
4
Rocky Mountain Power
Exhibit RMP___(RMM-10) Page 7 of 11
Docket No. 16-035-__
Witness: Robert M. Meredith
Allocation of Sample Points to Each Stratum
Once the stratum boundaries have been determined, sample points (i.e., load recorders)
must be assigned to the strata. The Tschprow-Neyman allocation procedure4 allocates an
optimal sampling rate to each stratum. Optimal allocation techniques minimize the
variance of the population estimates by increasing the sample proportion in the strata
having larger variances. This produces a sampling rate for each stratum which is
proportional to the standard deviation within the stratum. The analogous procedure for a
ratio sampling plan is allocation in proportion to the square root of the residual variance.
Average billing energy was selected as both the target and stratification variables. These
data were used to provide estimates for the new Utah Residential DG sample design. For
the mean-per-unit method, the variance within each stratum was the ordinary variance of
the mean.
Minimum recorder allocations and data loss adjustments are required for each stratum to
maintain adequate data in case of recorder failure and to provide data for analysis of load
characteristics other than the primary target variable, should such analysis be necessary.
Minimums ranging from 5 to 15 sites per stratum have been used in past studies. In the
present studies, a minimum of 10 sites was used. A minimum on the high side was
selected, despite improvements in data quality due to solid state recording equipment,
because changing requirements for load research and other areas using this data may
require unanticipated applications, and because overall sample efficiencies are bringing
these studies in well below the budgeted number of sites, even with the 10 site minimum.
The final allocation ofrecorders reflected an additional ten percent data loss adjustment
per stratum over the optimal or minimum allocation.
Budget approval was received which allowed us to install 62 network meters for this
study. An analysis of customers selected to participate in this load study indicates that 0
sites currently have load profile metering installed. The four strata design selected calls
for the installation of 45 recorders to meet design standards. We supplemented this
amount to reflect total installations of 62 meters. This design selected should achieve ±
10% Relative Accuracy at the 95% Confidence Level on estimates of the target variable.
Sample Selection
Systematic sample selections were used for each stratum to ensure a representative
distribution. For practical reasons, inactive customers and customers with no kWh meter
installed (usually certain types oflighting customers with very predictable demand and
consumption, indicated by absence of a kWh meter number) were eliminated from the
sampling frame. Eligible customers were then sorted by stratum and by average monthly
billed energy (KWH_MNTH) within stratum. The number of customers available in the
sampling frame for each stratum was then divided by the number of recorders allocated to
that stratum (N1/n11), yielding the sampling interval size. A five digit random number
4
William G. Cochran, "Sampling Techniques", Third Edition, Wiley, pgs. 96-99
5
Rocky Mountain Power
Exhibit RMP___(RMM-10) Page 8 of 11
Docket No. 16-035-__
Witness: Robert M. Meredith
between 0 and 1 was chosen for each stratum, and multiplied by the stratum interval size
to obtain the starting selection point for each stratum (Table C). Beginning with this site,
additional sites were selected at the given sampling intervals to obtain the desired number
of sample sites. This procedure was repeated four times to provide a list of alternate
selection sites.
The list of primary and alternate selection sites for this sample are contained in Appendix
1. This list was compared against current Utah profile metering installations to check for
duplicates. Duplicates between the design and production systems were noted and
updated in the Appendix.
6
Rocky Mountain Power
Exhibit RMP___(RMM-10) Page 9 of 11
Docket No. 16-035-__
Witness: Robert M. Meredith
Utah Residential DG DH Worksheet
Four Strata
0
50
100
150
200
250
300
350
400
450
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1750
2000
2250
2500
2750
3000
3250
3500
3750
4250
4500
5000
5500
6000
7500
9000
Range
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
to
50
100
150
200
250
300
350
400
450
500
600
700
800
900
1000
1100
1200
1300
1400
1500
1750
2000
2250
2500.
2750
3000
3250
3500
3750
4250
4500
5000
5500
6000
7500
9000
15000
Total N
Customer
Count
Interval
Factor
f
µ
107
61
78
107
95
133
93
87
96
80
129
88
71
63
55
44
32
21
24
17
32
11
12
13
5
7
2
3
2
1
1
1
2
2
1
~lf
107
61
78
107
95
133
93
87
96
80
258
176
142
126
110
88
64
42
48
34
160
55
60
65
25
35
10
15
10
10
5
10
20
20
30
30
120
1
1
1
2
2
2
2
2
2
2
2
2
2
5
5
5
5
5
5
5
5
5
10
5
10
10
10
30
30
120
1,578
2
3
4
5
4
73.1
146.2
219.2
5
58.5
116.9
175.4
233.8
SAMPLING ST/ Avg. kWh 1 Mean kW 2 St. Dev
1
2
3
4
5
6
204.1
594.3
1,229.5.
3,317.1
10.3
7.8
8.8
10.3
9.7
11.5
9.6
9.3
9.8
8.9
16.1
13.3
11.9
11.2
10.5
9.4
8.0
6.5
6.9
5.8
12.6
7.4
7.7
8.1
5.0
5.9
3.2
3.9
3.2
3.2
2.2
3.2
4.5
4.5
5.5
5.5
11.0
cum --./µf
10.3
18.2
27.0
37.3
47.1
58.6
68.3
77.6
87.4
96.3
112.4
125.7
137.6
148.8
159.3
168.7
176.7
183.1
190.1
195.9
208.6
216.0
223.7
231.8
236.8
242.7
245.9
249.7
252.9
256.1
258.3
261.4
265.9
270.4
275.9
281.3
292.3
761
527
236
54
1,578
BOUNDARIES INDICATED FOR STRATA:
3
97.4
194.9
-lµf
6
48.7
97.4
146.2
194.9
243.6
1
115.8
141.8
266.5
2,078.2
1 Biiiing records for April 2013 through March 2014
Table A
1
2
3
4
0-400
401 - 900
901 - 2,000
GT 2,000
EST POP MEAN (wtd by N)
STRATUM
STRATUM
STRATUM
STRATUM
kWh
kWh
kWh
kWh
0.000
1,578
761
527
236
54
PopN
c
Standard
Deviation
115.800
141.800
266.500
2078.200
13409.6400
20107.2400
71022.2500
4318915.2400
e
Variance
of Mean
d
!Relative Conf. Int.
MPU Est of kW
Conf. Interval
#DIV/O!
Table B
0
97984.06073
953.438753
279.046712
244.453980
169.027887
260.910174
#DIV/O!
#DIV/O!
~DIV?b!
0.0000
0
0
60.520495
80528.49857
95501.34111
95%
1.96
95%
1.96
41085.96866 30.87780357
1,688,056,820
543,766,649
418, 154,803
341,320,020
384,815,348
MEAN KW
Adj. n
45
12
10
8
15
h
Optimal
Allocation
g*h total
95%
1.96
48725.17403
49991.86772
Standard Error
95%
1.96
2,374,142,585
2,499, 186,838
Total Variance
694,849,754
608, 710,945
420,893,636
649,688,250
694,849,754
608,710,945
545,937,890
649,688,250
Desired Conf. Level
(z two tailed)
1.0000
0.2607
0.2211
0.1861
0.3321
g
Proprtn.
rowf/
sum f
TOTAL KW
TOTAL KW
Adjusted n (col. Final (col. J
337969
88124
74729
62894
112223
f
Wtd.
Devtns.
c*e
1
2
3
4
Variance
contributed
by strata:
TOTAL KW
Optimal n (col. h)
RELATIVE PRECISION OF SAMPLE KW ESTIMATE
594.298
204.1
594.3
1,229.5
3,317.1
Sample
Sample
Mean kW Mean kWh
UTAH RESIDENTIAL DG LOAD STUDY DESIGN OPTION (2014)
FOUR STRATA, MEAN-PER-UNIT DESIGN
b
a
I
Sample
Estimate
45
47
12
10
10
15
i
Optimal
with
Attrition
-62
15
14
12
21
62
Adj Sample
Estimate
c
j
Final
with
Attrition
I
Rocky Mountain Power
Exhibit RMP___(RMM-10) Page 10 of 11
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-10) Page 11 of 11
Docket No. 16-035-__
Witness: Robert M. Meredith
Utah Residential DG Sample Selection Parameters
Active Customers with kWh Meters
For the 12 Months Ending March 2014
2
Stratum
Sampling
Frame
3
5
4
761
527
236
54
Sample
15
14
12
21
Interval
50.73
37.64
19.67
2.57
Primary
Random No.( 1J
Start
0.28885
15
0.60446
23
0.93179
18
0.74182
2
Alternate 1
Random No.(1J
Start
0.00035
1
0.14860
6
0.01623
1
0.47069
1
Alternate 2
Random No.(1J
Start
0.62603
32
0.02792
1
0.35359
7
0.75281
2
Alternate 3
Random No.( 1J
Start
0.21875
11
0.83566
31
0.79521
16
0.20098
1
Alternate 4
Random No.( 1)
Start
0.89793
46
0.64829
24
0.61813
12
0.14148
1
Random Starts
1
( )
Random numbers from Excel's random function.
Table C
6
Rocky Mountain Power
Exhibit RMP___(RMM-11)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Value of Excess NEM Credits
November 2016
Jul-15
Aug-15
Sep-15
Oct-15
Nov-15
Dec-15
Total
Exported Energy (MWh)
Net Power Cost ($/MWh)
Line Losses ($/MWh)
Energy Value from Exported Energy ($)
Average Energy Value from Exported Energy ($)
NEM Credits from Banking (MWh)
Energy Value from NEM Credits from Banking ($)
Energy Value from Excess NEM Credits ($)
0
$17.51
$1.62
$0.00
0
$18.70
$1.74
$0.00
0
$17.61
$1.63
$0.00
(27) 11 16
Irrigation‐NEM ‐ Schedule 10‐135
137
22
32
22
$17.82
$24.88
$31.32
$32.64
$1.65
$2.31
$2.91
$3.03
$2,674.43
$595.83 $1,086.75
$768.10
(0) (0) (0) (0) 6
0
$19.49
$1.81
$0.00
30
$19.05
$1.77
$624.87
40
$17.42
$1.62
$753.03
0 309
$15.94
$1.48
$0.00
$7,115.61
$23.04
(20) (46) (40) (0) (100)
‐$2,298.62
$4,817.00
27
$20.95
$1.94
$612.58
General Service ‐ Over 1 MW‐NEM ‐ Schedule 8‐135
‐
1 9 49 42 53 16 0 0 2 1 1 175
$19.49
$17.51
$18.70
$17.61
$17.82
$24.88
$31.32
$32.64
$20.95
$19.05
$17.42
$15.94
$1.81
$1.62
$1.74
$1.63
$1.65
$2.31
$2.91
$3.03
$1.94
$1.77
$1.62
$1.48
$0.00
$28.16
$186.14
$938.94
$814.97 $1,448.36
$531.38
$6.05
$3.36
$39.68
$28.01
$20.04
$4,045.10
$23.13
4 10 (1) (0) 6 (35) 15 4 (14) (15) (3) (0) (29)
‐$665.52
$3,379.58
Jun-15
Exported Energy (MWh)
Net Power Cost ($/MWh)
Line Losses ($/MWh)
Energy Value from Exported Energy ($)
Average Energy Value from Exported Energy ($)
NEM Credits from Banking (MWh)
Energy Value from NEM Credits from Banking ($)
Energy Value from Excess NEM Credits ($)
May-15
General Service ‐ Large‐NEM ‐ Schedule 6‐135
130 197 349 512 569 517 597 538 431 451 389 329 5,007
$19.49
$17.51
$18.70
$17.61
$17.82
$24.88
$31.32
$32.64
$20.95
$19.05
$17.42
$15.94
$1.81
$1.62
$1.74
$1.63
$1.65
$2.31
$2.91
$3.03
$1.94
$1.77
$1.62
$1.48
$2,762.34 $3,778.69 $7,129.55 $9,844.93 $11,074.02 $14,051.38 $20,428.76 $19,174.98 $9,867.19 $9,392.64
$7,410.68
$5,721.56
$120,636.70
$24.09
254 108 9 (72) (52) (166) (32) (71) (76) (9) 35 100 30
$710.90
$121,347.61
Apr-15
Exported Energy (MWh)
Net Power Cost ($/MWh)
Line Losses ($/MWh)
Energy Value from Exported Energy ($)
Average Energy Value from Exported Energy ($)
NEM Credits from Banking (MWh)
Energy Value from NEM Credits from Banking ($)
Energy Value from Excess NEM Credits ($)
Mar-15
Residential‐NEM ‐ Schedule 1‐135
303 602 1,196 1,539 1,427 2,051 1,521 1,734 1,275 1,653 1,621 1,040 15,961
$19.49
$17.51
$18.70
$17.61
$17.82
$24.88
$31.32
$32.64
$20.95
$19.05
$17.42
$15.94
$1.81
$1.62
$1.74
$1.63
$1.65
$2.31
$2.91
$3.03
$1.94
$1.77
$1.62
$1.48
$6,457.51 $11,512.60 $24,446.46 $29,606.12 $27,784.02 $55,745.27 $52,049.48 $61,872.53 $29,192.73 $34,406.30 $30,860.19 $18,114.32
$382,047.50
$23.94
207 (19) (115) (419) (428) (204) (7) (155) (63) (197) 78 573 (749)
‐$17,919.88
$364,127.62
Feb-15
Exported Energy (MWh)
Net Power Cost ($/MWh)
Line Losses ($/MWh)
Energy Value from Exported Energy ($)
Average Energy Value from Exported Energy ($)
NEM Credits from Banking (MWh)
Energy Value from NEM Credits from Banking ($)
Energy Value from Excess NEM Credits ($)
Jan-15
PacifiCorp
Cost Of Service By Rate Schedule
State of Utah
2010 Protocol (Non Wgt)
12 Months Ended December 2015
Value of Excess NEM Credits
Rocky Mountain Power
Exhibit RMP___(RMM-11) Page 1 of 2
Docket No. 16-035-__
Witness: Robert M. Meredith
0
53
373
$17.61
$1.63
$7,180.35
Apr-15
268
$20.95
$1.94
$6,147.37
General Service ‐ Small ‐ NEM ‐ Schedule 23‐135
354
260
353
371
$17.82
$24.88
$31.32
$32.64
$1.65
$2.31
$2.91
$3.03
$6,892.68 $7,071.01 $12,093.09 $13,228.36
Jul-15
Sep-15
Jun-15
Aug-15
May-15
271
$19.05
$1.77
$5,639.48
Oct-15
267
$17.42
$1.62
$5,088.63
Nov-15
Dec-15
Total
175 3,216
$15.94
$1.48
$3,041.61
$76,931.79
$23.92
(63) (123) (115) (183) (83) (90) (106) (77) (33) 87 (733)
‐$17,536.15
$59,395.64
249
$18.70
$1.74
$5,090.78
Mar-15
52,877
57,784
9.28%
Net Metering Production Loss Factor
Total
532 975 1,803 2,472 2,529 2,903 2,518 2,664 2,001 2,407 2,319 1,545 24,668
$19.49
$17.51
$18.70
$17.61
$17.82
$24.88
$31.32
$32.64
$20.95
$19.05
$17.42
$15.94
$1.81
$1.62
$1.74
$1.63
$1.65
$2.31
$2.91
$3.03
$1.94
$1.77
$1.62
$1.48
$11,334.50 $18,663.23 $36,852.92 $47,570.34 $49,240.11 $78,911.85 $86,189.46 $95,050.02 $45,823.24 $50,102.96 $44,140.54 $26,897.53
$590,776.71
$23.86
518 99 (169) (615) (583) (614) (95) (297) (280) (344) 38 760 (1,581)
‐$37,709.26
$553,067.45
175
$17.51
$1.62
$3,343.79
Feb-15
99
$19.49
$1.81
$2,114.65
Net Metering Production MWh @ sales
Net Metering Production MWh @ input
Exported Energy (MWh)
Net Power Cost ($/MWh)
Line Losses ($/MWh)
Energy Value from Exported Energy ($)
Average Energy Value from Exported Energy ($)
NEM Credits from Banking (MWh)
Energy Value from NEM Credits from Banking ($)
Energy Value from Excess NEM Credits ($)
Exported Energy (MWh)
Net Power Cost ($/MWh)
Line Losses ($/MWh)
Energy Value from Exported Energy ($)
Average Energy Value from Exported Energy ($)
NEM Credits from Banking (MWh)
Energy Value from NEM Credits from Banking ($)
Energy Value from Excess NEM Credits ($)
Jan-15
PacifiCorp
Cost Of Service By Rate Schedule
State of Utah
2010 Protocol (Non Wgt)
12 Months Ended December 2015
Value of Excess NEM Credits
Rocky Mountain Power
Exhibit RMP___(RMM-11) Page 2 of 2
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-12)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Summary of Results for NEM Breakout COS
November 2016
Footnotes :
Column C :
Column D :
Column E :
Column F :
Column G :
Column H :
Column I :
Column J :
Column K :
Column L :
Column M :
1
1-135
6
6-135
8
8-135
7,11,12
9
10
10-135
15
15
23
23-135
SpC
SpC
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Schedule
No.
Line
No.
A
1,924,164,161
719,990,943
2,778,025
525,707,898
7,890,216
149,029,192
5,387,429
11,464,575
274,856,221
17,679,271
110,799
749,867
1,299,357
135,802,412
498,803
27,835,175
43,083,978
Annual
Revenue
C
7.56%
6.86%
0.35%
9.05%
9.31%
8.37%
9.40%
13.52%
6.24%
6.65%
5.44%
10.74%
16.90%
8.91%
6.17%
3.60%
7.08%
1.00
0.91
0.05
1.20
1.23
1.11
1.24
1.79
0.83
0.88
0.72
1.42
2.23
1.18
0.82
0.48
0.94
E
Rate of
Return
Index
D
Return on
Rate
Base
F
1,924,164,161
749,260,727
4,585,118
488,017,093
7,225,176
143,254,255
4,940,518
9,177,892
292,345,306
18,595,989
123,448
652,463
933,408
126,559,932
540,815
33,990,518
43,961,504
Total
Cost of
Service
G
1,297,464,907
434,755,608
2,097,092
343,639,590
5,010,595
104,339,609
3,680,363
3,432,162
241,662,693
12,213,206
70,325
347,850
724,111
80,097,558
312,634
27,937,609
37,143,903
Production
Cost of
Service
H
I
Distribution
Cost of
Service
J
Retail
Cost of
Service
K
Misc
Cost of
Service
L
Increase
(Decrease)
to = ROR
282,186,013 302,802,029 33,400,429 8,310,784
0
101,968,491 179,453,383 29,678,446 3,404,799 29,269,784
560,651
1,479,274
427,802
20,298
1,807,093
73,835,631 66,920,645 1,514,311 2,106,915 (37,690,806)
1,099,092
1,045,043
38,993
31,453
(665,040)
21,571,258 16,628,685
115,578
599,125 (5,774,937)
747,730
602,516
(111,043)
20,953
(446,911)
535,685
4,918,789
255,014
36,243 (2,286,683)
49,310,527
183,922
43,537 1,144,627 17,489,085
2,510,146
3,746,993
44,234
81,410
916,718
14,555
32,837
5,252
479
12,649
65,747
156,467
79,860
2,539
(97,404)
108,563
80,216
17,258
3,260
(365,949)
17,556,512 27,238,589 1,095,725
571,547 (9,242,480)
74,605
134,771
16,328
2,478
42,012
5,755,112
81,047
83,842
132,908
6,155,343
6,471,708
98,851
95,293
151,750
877,526
Transmission
Cost of
Service
Annual revenues based on January 2015 thru December 2015 data.
Calculated Return on Ratebase per January 2015 thru December 2015 Embedded Cost of Service Study
Rate of Return Index. Rate of return by rate schedule, divided by Utah Jurisdiction's normalized rate of return.
Calculated Full Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study
Calculated Generation Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Transmission Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Distribution Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Retail Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Calculated Miscellaneous Cost of Service at Jurisdictional Rate of Return per the January 2015 thru December 2015 Embedded COS Study.
Increase or Decrease Required to Move From Annual Revenue to Full Cost of Service Dollars.
Increase or Decrease Required to Move From Annual Revenue to Full Cost of Service Percent.
Total Utah Jurisdiction
Residential
Residential-NEM
General Service - Large
General Service - Large-NEM
General Service - Over 1 MW
General Service - Over 1 MW-NEM
Street & Area Lighting
General Service - High Voltage
Irrigation
Irrigation-NEM
Traffic Signals
Outdoor Lighting
General Service - Small
General Service - Small - NEM
Customer 1
Customer 2
Description
B
Rocky Mountain Power
Cost Of Service By Rate Schedule
State of Utah
12 Months Ended Dec 2015
2010 Protocol (Non Wgt)
7.56% = Earned Return on Rate Base
M
0.00%
4.07%
65.05%
-7.17%
-8.43%
-3.88%
-8.30%
-19.95%
6.36%
5.19%
11.42%
-12.99%
-28.16%
-6.81%
8.42%
22.11%
2.04%
Percentage
Change from
Current Revenues
Rocky Mountain Power
Exhibit RMP___(RMM-12) Page 1 of 1
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-13)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
NEM Breakout COS Compared to ACOS
November 2016
Schedule
No.
1
1-135
6
6-135
8
8-135
10
10-135
23
23-135
Line
No.
1
2
3
4
5
6
7
8
9
10
A
Residential
Residential-NEM
General Service - Large
General Service - Large-NEM
General Service - Over 1 MW
General Service - Over 1 MW-NEM
Irrigation
Irrigation-NEM
General Service - Small
General Service - Small - NEM
Description
B
(9,146,204)
875,850
(6,015,164)
(37,991,083)
29,269,784
1,807,093
(37,690,806)
(665,040)
(5,774,937)
(446,911)
916,718
12,649
(9,242,480)
42,012
NEM Breakout
Increase
(Decrease)
to = ROR
ACOS
Increase
(Decrease)
to = ROR
30,365,272
D
C
Rocky Mountain Power
NEM Breakout Cost Of Service Compared to Actual Cost of Service
State of Utah
12 Months Ended Dec 2015
2010 Protocol (Non Wgt)
(96,277)
40,868
240,227
300,277
(1,095,488)
NEM Breakout less ACOS
Increase
(Decrease)
to = ROR
E
Rocky Mountain Power
Exhibit RMP___(RMM-13) Page 1 of 1
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Exhibit RMP___(RMM-14)
Docket No. 16-035-__
Witness: Robert M. Meredith
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Robert M. Meredith
Determination of Residential Net Metering Cost of Service At the Same
Basis as Rates Set in Docket No. 13-084-184
November 2016
52
51
50
49
48
47
46
45
44
43
42
41
40
39
38
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36
35
34
33
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31
30
29
28
27
26
25
24
23
22
21
20
19
18
17
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Row
TRANSMISSION-TOTAL
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
PRODUCTION-ENERGY
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
PRODUCTION-DEMAND
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
PRODUCTION-TOTAL
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
Per NCP kW
Per KWH
Per Customer
PTDRM TOTAL
Revenue Requirement
UNITS
NCP kW
Annual KWH
Average Customers
Load Factor
CP Load Factor
Description
(B)
(A)
38.94%
36.14%
101,968,491
1.82
0.016
136.02
33.27%
91,359,991
1.60
0.015
123.35
29.03%
195,254,430
3.48
0.030
260.45
27.99%
192,414,357
3.38
0.031
259.80
38.33%
239,501,178
4.27
0.037
319.47
34.99%
186,193,456
3.27
0.030
251.40
33.51%
434,755,608
7.75
0.067
579.93
31.04%
378,607,813
6.64
0.061
511.19
13.36
0.115
999.45
749,260,727
37.04%
12.01
0.110
924.69
684,856,226
56,098,384
6,523,256,321
749,673
16%
63%
Sch 1
Non-Net Metering
Sch 1
@ Step 2 Revenue
57,008,525
6,203,851,850
740,636
15%
63%
Actual 2015
Cost of Service Study
With Net Metering
Broken Out
Docket No.
13-035-184
Residential
560,651
1.45
0.014
127.71
0.20%
813,817
2.10
0.021
185.38
0.12%
1,283,275
3.31
0.033
292.32
0.21%
2,097,092
5.41
0.054
477.70
0.16%
11.82
0.117
1,044.45
4,585,118
0.24%
387,862
39,124,078
4,390
14%
(C)
Sch 1
Net Metering
Actual 2015
Cost of Service Study
With Net Metering
Broken Out
0.415%
0.533%
(C) / [(B) + (C)]
(D)
Net Metering as a
Percentage of
Overall Residential
Actual 2015
Cost of Service Study
With Net Metering
Broken Out
Rocky Mountain Power
State of Utah
Determination of Residential Net Metering Cost of Service
At the Same Basis as Rates Set in Docket No. 13-084-184
500,700
1.29
0.013
114.05
798,651
2.06
0.020
181.93
992,329
0.025
226.04
1,790,980
4.62
0.046
407.97
10.86
0.108
959.15
4,210,660
387,862
39,124,078
4,390
15%
63%
(E)
Sch 1
Net Metering
@ GRC Level
54 + 60
48 / 17
48 / 18
48 / 19
(D) * (A)
42 / 17
42 / 18
42 / 19
(D) * (A)
36 / 17
36 / 18
36 / 19
36 + 42
30 / 17
30 / 18
30 / 19
30 + 48 + 66 + 102 + 108
24 / 17
24 / 18
24 / 19
(F)
Calculation
Rocky Mountain Power
Exhibit RMP___(RMM-14) Page 1 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
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84
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60
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54
53
Row
DISTRIBUTION-TRANSFORMER
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
DISTRIBUTION- P & C
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
DISTRIBUTION-SUBSTATION
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
DISTRIBUTION-TOTAL
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
TRANSMISSION-ENERGY
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
TRANSMISSION-DEMAND
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
Description
60.69%
37,905,232
0.68
0.006
50.56
59.50%
33,141,338
0.58
0.005
44.75
56.78%
88,107,442
1.57
0.014
117.53
56.86%
81,971,962
1.44
0.013
110.68
51.91%
23,392,948
0.42
0.004
31.20
49.83%
33,930,114
0.60
0.005
45.81
59.26%
179,453,383
3.20
0.028
239.38
58.04%
178,074,251
3.12
0.029
240.43
28.54%
19,109,453
0.34
0.003
25.49
28.20%
18,534,141
0.33
0.003
25.02
38.50%
82,859,038
1.48
0.013
110.53
(B)
(A)
34.86%
Sch 1
Non-Net Metering
Sch 1
@ Step 2 Revenue
72,825,850
1.28
0.012
98.33
Actual 2015
Cost of Service Study
With Net Metering
Broken Out
Docket No.
13-035-184
Residential
0.21%
0.49%
117,663
0.30
0.003
26.80
0.18%
442,988
1.14
0.011
100.91
396,520
1.02
0.010
90.32
0.63%
678,793
1.75
0.017
154.62
0.44%
168,951
0.44
0.004
38.49
0.37%
1,479,274
3.81
0.038
336.96
(C)
Sch 1
Net Metering
Actual 2015
Cost of Service Study
With Net Metering
Broken Out
1.035%
0.765%
0.717%
0.612%
0.532%
(C) / [(B) + (C)]
(D)
Net Metering as a
Percentage of
Overall Residential
Actual 2015
Cost of Service Study
With Net Metering
Broken Out
Rocky Mountain Power
State of Utah
Determination of Residential Net Metering Cost of Service
At the Same Basis as Rates Set in Docket No. 13-084-184
113,422
0.29
0.003
25.84
387,278
1.00
0.010
88.22
343,097
0.88
0.009
78.15
626,696
1.62
0.016
142.76
243,297
0.63
0.006
55.42
1,444,361
3.72
0.037
329.01
(E)
Sch 1
Net Metering
@ GRC Level
(D) * (A)
84 / 17
84 / 18
84 / 19
(D) * (A)
78 / 17
78 / 18
78 / 19
(D) * (A)
72 / 17
72 / 18
72 / 19
72 + 78 + 84 + 90 + 96
66 / 17
66 / 18
66 / 19
(D) * (A)
60 / 17
60 / 18
60 / 19
(D) * (A)
54 / 17
54 / 18
54 / 19
(F)
Calculation
Rocky Mountain Power
Exhibit RMP___(RMM-14) Page 2 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
DISTRIBUTION-METER
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
DISTRIBUTION-SERVICE
Revenue Requirement
Per NCP kW
Per KWH
Per Customer
Description
109
108
107
MISC - Total
Revenue Requirement
Per NCP kW
110 Per KWH
111 Per Customer
106
103
102
101
RETAIL-TOTAL
Revenue Requirement
Per NCP kW
104 Per KWH
105 Per Customer
100
99
98
97
96
95
94
93
92
91
90
89
Row
40.97%
3,404,799
0.06
0.001
4.54
39.24%
5,855,141
0.10
0.001
7.91
88.86%
29,678,446
0.53
0.005
39.59
93.84%
30,959,030
0.54
0.005
41.80
70.30%
5,874,123
0.10
0.001
7.84
70.78%
7,590,759
0.13
0.001
10.25
76.13%
24,173,638
0.43
0.004
32.25
(B)
(A)
76.18%
Sch 1
Non-Net Metering
Sch 1
@ Step 2 Revenue
21,440,077
0.38
0.003
28.95
Actual 2015
Cost of Service Study
With Net Metering
Broken Out
Docket No.
13-035-184
Residential
(C)
20,298
0.05
0.001
4.62
0.24%
427,802
1.10
0.011
97.45
1.28%
61,064
0.16
0.002
13.91
0.73%
173,945
0.45
0.004
39.62
0.55%
Sch 1
Net Metering
Actual 2015
Cost of Service Study
With Net Metering
Broken Out
0.593%
1.421%
1.029%
0.714%
(C) / [(B) + (C)]
(D)
Net Metering as a
Percentage of
Overall Residential
Actual 2015
Cost of Service Study
With Net Metering
Broken Out
Rocky Mountain Power
State of Utah
Determination of Residential Net Metering Cost of Service
At the Same Basis as Rates Set in Docket No. 13-084-184
(E)
34,699
0.09
0.001
7.90
439,920
1.13
0.011
100.21
78,097
0.20
0.002
17.79
153,173
0.39
0.004
34.89
Sch 1
Net Metering
@ GRC Level
(D) * (A)
108 / 17
108 / 18
108 / 19
(D) * (A)
102 / 17
102 / 18
102 / 19
(D) * (A)
96 / 17
96 / 18
96 / 19
(D) * (A)
90 / 17
90 / 18
90 / 19
(F)
Calculation
Rocky Mountain Power
Exhibit RMP___(RMM-14) Page 3 of 3
Docket No. 16-035-__
Witness: Robert M. Meredith
Rocky Mountain Power
Docket No. 16-035-____
Witness: Douglas L. Marx
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Direct Testimony of Douglas L. Marx
November 2016
1
Q.
dba Rocky Mountain Power (“the Company”).
2
3
Please state your name, business address and present position with PacifiCorp,
A.
My name is Douglas L. Marx. My business address is 1407 West North Temple,
4
Salt Lake City, UT 84095. I am the director of Engineering Standards and Technical
5
Services for Rocky Mountain Power (“RMP”).
6
Qualifications
7
Q.
Briefly describe your educational and professional background.
8
A.
I have worked for the Company for 35 years in various engineering, operations and
9
management positions. I hold a bachelor’s degree in electrical engineering from the
10
University of Utah and a master’s degree in business administration from Utah
11
State University. I am a licensed professional engineer in the state of Utah.
12
Q.
Please describe your present duties.
13
A.
I oversee all non-routine technical studies including distributed generation, power
14
quality and smart grid reports. I am responsible for the development of all material
15
and equipment specifications and standards used in the construction and
16
maintenance of the transmission and distribution systems.
17
Purpose and Summary of Testimony
18
Q.
What is the purpose of your testimony in this proceeding?
19
A.
In support of the Company's need to ensure adequate cost recovery from residential
20
customers with private generation, I present the operational issues associated with
21
private customer generation, specifically rooftop solar, and the system changes that
22
will be required with increasing levels of distributed generation on the electrical
Page 1 - Direct Testimony of Douglas L. Marx
23
distribution system. In addition, I explain the process and costs incurred in
24
reviewing interconnection requests for net metering applications in support of the
25
proposed changes to the application fees.
26
Q.
Please summarize your testimony.
27
A.
My testimony demonstrates that rooftop solar generation does not reduce the peak
28
demand on the distribution system to a degree that could warrant a reduction in
29
infrastructure. Instead, rooftop solar may actually increase the requirements for
30
infrastructure at the local level. Further, residential net metering customers use the
31
electric grid at a level higher than other residential customers. The total amount of
32
energy transferred to and from the electric grid by net metering customers can
33
exceed the amount of energy delivered to other customers by a significant amount.
34
In addition, the Company incurs additional costs associated with applications for
35
rooftop solar generation and their interconnection.
36
System Impacts
37
Q.
Please describe the studies you have done on neighborhood rooftop solar.
38
A.
In 2014 in Docket No. 13-035-184 ("2014 GRC"), I presented the results of a
39
neighborhood rooftop solar study for the area served by the Northeast #16 circuit.
40
This study evaluated the viability of rooftop solar to offset utility infrastructure
41
upgrades by modeling high efficiency solar panels on every viable roof space on
42
the circuit. The study showed that, under a best case scenario, solar generation
Page 2 - Direct Testimony of Douglas L. Marx
43
offsets only seven percent of the peak demand on the circuit, which means that the
44
utility still needed to provide 93 percent of customers' demand.1
45
In response to questions raised about the relevance of the findings of the
46
Northeast #16 study to other locations within the Salt Lake valley, the Company
47
initiated a new study in 2015. We selected the Bingham #11 circuit located in the
48
southwest quadrant of the valley in South Jordan, Utah. A copy of the study report
49
is attached as Exhibit RMP__ (DLM-1). This study shows that the effects of rooftop
50
solar reduced the peak circuit loading by only 3.6 percent. Due to this small
51
reduction, and considering the interaction between variable customer load and
52
variations in solar production due to cloud cover and other interference, our
53
distribution planning guidelines will continue to be based on peak load
54
requirements without including solar generation reductions.
55
Q.
distribution infrastructure?
56
57
Can increased levels of rooftop solar generation reduce the size of local
A.
No. As the studies show, increasing levels of rooftop solar can actually force the
58
Company to increase the local distribution system including distribution
59
transformers, secondary cables and service conductors to handle the excess
60
generation. If customers install the level of rooftop solar required to offset their
61
annual electric energy usage, also known as net zero-electric energy customers, the
62
Company will need to increase the size of the local distribution system to handle
63
the reverse energy flow delivered to the grid by the customers.
1
See Docket No. 13-035-184, Rebuttal Testimony of Douglas L. Marx (June 2014).
Page 3 - Direct Testimony of Douglas L. Marx
64
The peak output for the rooftop solar systems in Utah will occur during the
65
spring months, typically April or May. This is the time of year the solar insolation
66
is approaching its peak level for the year, and the ambient temperatures are
67
relatively moderate. This combination allows the solar system to maximize its
68
output. As the temperatures increase through June and July, the output will actually
69
decrease. This decrease occurs at the same time a residential customer’s load is
70
reaching its peak demand, typically July. The peak demand typically occurs in the
71
evening when the rooftop solar system’s output is near its lowest point of
72
production for the day.
73
To handle the higher level of energy flow experienced in the spring months,
74
the local distribution system must be sized to accommodate the greater of the two
75
values. Consequently, the system may be sized up to 30 percent greater than normal.
76
In a few cases, the reverse power flow could approach 50 percent more as compared
77
to the customers’ peak load demand.
78
If a customer installs the level of rooftop solar required to offset all of their
79
energy usage, including conversion of their gas appliances and gasoline vehicles to
80
electric, the magnitude of exported energy demand can be much greater and the
81
reverse flow effect becomes even more dramatic.
82
Q.
generation without any modification?
83
84
85
Is the distribution system capable of handling increasing levels of distributed
A.
No. In addition to the local distribution system, increasing levels of distributed
generation will require several changes. Advanced metering to monitor the system,
Page 4 - Direct Testimony of Douglas L. Marx
86
updates in regulator, relay and recloser controls to account for two-way power
87
flows and protect the system, increased levels of voltage management equipment
88
and dead-line checking systems will be required. Retrofitting these systems can
89
range in price from a few thousand dollars per device to several hundred thousand
90
per substation for updated protection schemes. Most of these increased costs were
91
discussed in my rebuttal testimony filed in the 2014 GRC.
92
Q.
compared to other customers.
93
94
Please explain how a net metering customer uses the electric grid as
A.
Figure 1 below illustrates the power flow between the electric grid and a net
95
metering customer. The figure demonstrates that the net metering customer utilizes
96
the grid 24 hours per day except for two instantaneous points, shown by the small
97
circles, when the direction of current flow changes from energy delivered to energy
98
received. What the figure does not do is quantify the absolute level of grid
99
utilization by the customer.
Page 5 - Direct Testimony of Douglas L. Marx
Figure 1
100
101
I have already explained that a net metering customer’s peak utilization of
102
the local distribution system occurs during the spring months and can be much
103
higher than their summer peak load demand. This effect necessitates an increase in
104
size of the local distribution facilities in order to accommodate the peak output for
105
the solar facility. To illustrate the magnitude of grid utilization, one must calculate
106
the absolute value of the energy flow between the customer and the electric grid.
107
The absolute value is the sum of energy at the point of interconnection irrespective
108
of the direction of flow. This is the level of energy that the Company must manage
109
on each customer’s behalf.
110
The average Utah residential customer consumes approximately 8,601
111
kilowatt-hours of energy annually. The absolute value of the energy flow for the
Page 6 - Direct Testimony of Douglas L. Marx
112
electric net-zero energy customer used in this example is 11,558 kWh. This equates
113
to a 134 percent higher level of energy managed on their behalf than for other
114
customers. If customers install rooftop solar at a level to offset all of their energy
115
usage on a net basis, including gas appliances and vehicles, the level of managed
116
energy increases even more dramatically.
117
Proposed Application Fee
118
Q.
Please explain the costs associated with processing net metering applications.
119
A.
There are two cost categories associated with net metering applications: application
120
processing and interconnection. Four departments are involved with the review and
121
processing of net metering applications: customer call center, customer generation,
122
and engineering and operations. The costs associated with each department are
123
discussed below.
124
The customer call center incurs costs associated with creating work
125
requests, handling customer information calls, processing net meter exchanges and
126
production meter installs within the customer service system, handling suspended
127
statements and reviewing related reports.
128
The customer generation department incurs costs related to application
129
processing, database entry, billing, tracking, mapping and other regulatory
130
reporting requirements. With the increase in applications, the need to automate the
131
application process and receive payments must be part of the solution. These costs
132
are incurred whether the customer’s generation system is ultimately connected or
133
not.
Page 7 - Direct Testimony of Douglas L. Marx
134
Once the application is accepted and entered, each application is reviewed
135
by engineering to determine if the interconnection will create operational issues.
136
These issues are typically limited to equipment and component overload or voltage
137
and reliability problems. If the engineering review shows that system issues will
138
occur, in accordance with applicable Commission rules, the customer must pay for
139
the necessary corrections before her application is approved and before we will
140
interconnect the generation system.
141
After the net metering application has been approved and the rooftop solar
142
installation is completed, there are further costs associated with completing the
143
interconnection and setting up the correct configurations within our Customer
144
Service System ("CSS") for the net metering customer.
145
The operations department is responsible for completing the interconnect
146
process with an inspection and installation of the net meter as well as constructing
147
any required system modifications. If any issues are noted during the inspection,
148
the installation of the net meter is postponed until all noted deficiencies have been
149
corrected. After the meter exchange is completed at the customer's premise, the
150
customer service group creates a virtual meter in CSS to reflect the measured
151
delivered energy to the grid from the customer’s solar panels. The operations
152
department then reviews the CSS system to validate the exchange, and verifies
153
billing determinants are accurate to ensure a correct bill is presented.
Page 8 - Direct Testimony of Douglas L. Marx
154
Q.
2, and 3?
155
156
Are there differences in processing net metering applications under Levels 1,
A.
Yes. The key difference is the time that may be required by the engineering
157
department to review the application for operational issues. Level 1 is defined as
158
distributed energy systems of 25 kilowatts or smaller that operate with an inverter.
159
These are the systems most commonly used in residential and small commercial
160
applications. For Level 1 applications, the distribution system components
161
generally reviewed are the service conductor, secondary cables and the distribution
162
transformer and, in some circumstances, the distribution feeder and protection
163
schemes. Level 2 is defined as systems 2 megawatts or less that don't otherwise
164
qualify for Level 1. Level 3 is defined as systems 20 megawatts or less that don't
165
otherwise qualify for Level 1 or 2.
166
The time required to review each application varies by complexity and
167
location. While Level 1 interconnections are typically less complex to review, the
168
majority of time spent by the engineering department is spent on Level 1 due to the
169
volume of applications. Approximately eighty percent of applications reviewed are
170
satisfied at Level 1.
171
The customer call center and customer generation group costs are similar to
172
Level 1 for Level 2 and Level 3 applications. The engineering time for these higher
173
level reviews are significant. These reviews can be as simple as a grounding review
174
but can evolve into full system impact studies and require anywhere from two times
175
up to and sometimes greater than eight times to review as a Level 1.
Page 9 - Direct Testimony of Douglas L. Marx
176
Level 2 reviews can be completed with a fairly simple engineering analysis
177
and usually without using complex electrical models. The existing generation
178
levels, along with the proposed new generation, are compared to several limits
179
including circuit peak load, daytime light load, fault current at the point of
180
interconnection as well as existing circuit protection schemes. A review of the
181
grounding and protection requirements is also completed at this time. If any limits
182
are exceeded, the application fails the analysis and referred to a Level 3 review.
183
A Level 3 review expands upon the Level 2 analysis by including those
184
results in complex engineering models that provide a detailed analysis of the
185
interaction of the proposed generation with the electric system and with other
186
generation points currently operating on the circuit. Load flow, short circuit, and
187
protection scheme analysis studies are typical, and may require project
188
management to develop and scope the solution before the application is approved.
189
Once approved and accepted by the customer, the operations department
190
will complete the interconnect process as noted above, including constructing any
191
required system modifications.
192
Q.
Are net metering applications increasing?
193
A.
Yes. The volume of applications throughout Rocky Mountain Power has increased
194
exponentially since 2011. Most of this increase is in the Utah service territory. The
195
following Figure 2 shows the actual number of new customer generators by year
196
through 2015 and the forecasted level for 2016.
Page 10 - Direct Testimony of Douglas L. Marx
Figure 2
197
198
Q.
What is the impact of this increase on the Company?
199
A.
Due to the current level of applications, we have begun investigating ways to
200
automate the application process in order to both manage the volume to meet our
201
customers’ expectations and to reduce the overall costs associated with processing
202
these applications.
203
In addition, as the number of installations increase, the impact to the
204
distribution system will increase and drive the required upgrades and modifications
205
discussed earlier in my testimony. This includes protection and control systems,
206
voltage regulations, transformer upgrades, etc. A change to operating equipment
207
standards will be required to make them fully functional when two-way energy
208
flows become more common.
Page 11 - Direct Testimony of Douglas L. Marx
209
Q.
Are you aware of other states that have application fees for Level 1?
210
A.
Yes. Net metering application fees are not new to the industry. For example, the
211
state of California provides for the collection of application fees for solar
212
installations. Fees up to $150 per Level 1 application to cover administration and
213
engineering expenses have been reported. In the state of Washington, Pacific Power
214
collects $100 from each applicant installing a system rated less than 25 kilowatts
215
and $500 for systems rated from 25 to 100 kilowatts.
216
Conclusion
217
Q.
Please summarize your testimony.
218
A.
Rooftop solar generation does not reduce the distribution peak demand experienced
219
by the electric grid to a degree that could warrant a reduction in infrastructure and
220
could actually increase the base requirements for infrastructure at the local level.
221
Furthermore, the total amount of energy transferred to and from the electric grid by
222
residential net metering customers exceeds that of other customers by a significant
223
amount. This is energy that must be stored, accounted for and managed by the
224
Company on the customer’s behalf. In addition, the Company incurs significant
225
costs associated with applications for rooftop solar generation and their
226
interconnection.
227
Q.
Does this conclude your direct testimony?
228
A.
Yes.
Page 12 - Direct Testimony of Douglas L. Marx
Rocky Mountain Power
Exhibit RMP___(DLM-1)
Docket No. 16-035-__
Witness: Douglas L. Marx
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Douglas L. Marx
2015 Distribution Rooftop Solar Study - Bingham #11
November 2016
Rocky Mountain Power
Exhibit RMP___(DLM-1) Page 1 of 11
Docket No. 16-035-__
Witness: Douglas L. Marx
June 26, 2015
asd DISTRIBUTION ROOFTOP SOLAR STUDY Prepared By: Rohit Nair P.E., Senior Engineer Contributors: Juan Luna, Senior GIS Analyst Jake Barker, Manager Rocky Mountain Power Rocky Mountain Power
Exhibit RMP___(DLM-1) Page 2 of 11
Docket No. 16-035-__
Witness: Douglas L. Marx
Table of Contents
EXECUTIVE SUMMARY .......................................................................................................................... 3
INTRODUCTION ........................................................................................................................................ 4 SOLAR INSOLATION IN UTAH ............................................................................................................... 4 MODELING OF ROOFTOP SOLAR PHOTOVOLTAIC SYSTEM ..................................................... 5 1: The Solar Model ............................................................................................................................... 5 2: The Rooftop Model ........................................................................................................................... 5 3: The Photovoltaic Panel Model ......................................................................................................... 6 ESTIMATING NUMBER OF PANELS PER ROOFTOP .......................................................................... 6 SOLAR GENERATION CALCULATIONS ............................................................................................... 7 DISTRIBUTION CIRCUIT LOADING ...................................................................................................... 8 IMPACT OF SOLAR GENERATION ON DISTRIBUTION CIRCUIT LOADING ................................. 9 CONCLUSION ............................................................................................................................................. 9 APPENDIX A – Quick Facts .................................................................................................................... 111 2 | P a g e
Rocky Mountain Power Rocky Mountain Power
Exhibit RMP___(DLM-1) Page 3 of 11
Docket No. 16-035-__
Witness: Douglas L. Marx
EXECUTIVE SUMMARY
Rocky Mountain Power performed a study to estimate the potential for rooftop solar generation to
offset the daily peak load and provide benefits for reduced infrastructure. The study specifically
targeted the southwest quadrant of the Salt Lake valley in order to provide a comparison to a
similar study completed in 2010 based in the northeast quadrant. Several circuits in the area were
considered and Bingham #11 circuit in South Jordan, Utah was selected for the study. Quick facts
for the study area can be found in Appendix A.
The study was performed using publicly available GIS and solar modeling tools to estimate the
maximum amount of rooftop solar generation that would be produced and delivered to the
distribution circuit. This was done by identifying rooftops in the area served by the Bingham #11
distribution circuit, determining the maximum panels that could be installed and calculating the
annual solar radiation received. The solar generation profile was developed based on measured
solar insolation levels in Salt Lake City in addition to information available on the National
Renewable Energy Laboratory website.
The study estimated the maximum generation of the rooftop panels in the study area at 9.01
megawatts (AC) occurring at solar noon on May 13. The circuit peak demand occurred on July 14
at 5:30 pm mountain standard time. Comparing the solar production with the circuit profile shows
that the rooftop solar reduces the circuit peak demand by less than 7%.
Considering the interaction between variable customer load and variations in solar production due
to cloud cover and other interference, our distribution planning guidelines will continue to be based
on peak load requirements and not consider solar generation reductions.
3 | P a g e
Rocky Mountain Power
Exhibit RMP___(DLM-1) Page 4 of 11
Docket No. 16-035-__
Witness: Douglas L. Marx
INTRODUCTION
Rocky Mountain Power “The Company” is experiencing growing levels of distributed energy
resources being interconnected to its distribution system. Distributed energy resources generally
include rooftop solar panels, energy storage devices, fuel cells, microturbines, small wind, and
combined heat and power systems. These “behind-the-meter” power generation and storage
resources are usually located on an end-use customer’s premises and operated for the purpose of
supplying all or a portion of the customer’s electric load. At Rocky Mountain Power,
interconnection requests for distributed energy resources are categorized based on size, type of
technology, voltage of the distribution or transmission lines being connected to and the type of
financial relationship the customer has with the utility, either net metering or Qualified Facility.
The growth of distributed energy resources has been primarily due to cost reductions in
technology, performance improvements and the company’s net-metering policy. In the past few
years, Rocky Mountain Power has experienced an exponential growth in net-metering
applications, especially in the state of Utah.
SOLAR INSOLATION IN UTAH
Tthe National Renewable Electricity Laboratory
(NREL) estimated that the Salt Lake City area will
average between 5 and 5.8 kilowatt-hours per
square meter per day (kWh/m²/day.)
The model input values are taken from insolation
measurements provided by a network of hundreds
of meteorological stations. In Utah, Salt Lake
County insolation potential is considered just above
average. Solar insolation intensity increases with
southward direction. Figure 1 shows NREL’s
annual solar potential map for Utah.
Factors such as slope, aspect, shading, changing
solar positions, and weather conditions must be
considered in order to generate useful estimates for Figure 1: NREL Direct Normal Insolation 10‐Degree
GRID for Utah (kw/h/m2)
individual roof surfaces. The Company developed
monthly solar insolation models using the ArcGIS
Area Solar Insolation tool and half meter resolution LiDAR data. This approach yields high‐
resolution results that identify roof faces that have the best characteristics for installation of
photovoltaic (PV) panels based on roof slope, shading, area, and estimated solar insolation.
Further, based on measured solar insolation data in addition to data extracted from the NREL
PVWatts database, fifteen minute generation profile was developed to understand the potential
contribution of solar generation towards circuit load.
Rocky Mountain Power
Exhibit RMP___(DLM-1) Page 5 of 11
Docket No. 16-035-__
Witness: Douglas L. Marx
Rocky Mountain Power MODELING OF ROOFTOP SOLAR PHOTOVOLTAIC SYSTEM The typical method used to estimate the number of photovoltaic panels per rooftop is calculated
by merely dividing the total rooftop area by the area of an individual solar panel. However, this
approach has the potential to overestimate the number of panels per rooftop since it does not take
into account roof shapes, objects, obstructions, shadows, etc. To avoid such an overestimation, the
company developed a comprehensive solar model that consists of the following three parts:
1: The Solar Model
The solar model uses to estimate daily insolation averages per month and per year. This model
calculates solar ESRI’s Solar Insolation tools insolation values using 0.5 meter resolution
elevation data derived from LiDAR, radiation parameters from NASA, and atmospheric factors
based on local climate.
The output from this part of the model is a half meter resolution grid where each cell represents
the estimated average insolation for a half square meter.
2: The Rooftop Model
The model uses elevation data derived from half meter resolution LiDAR gathered from Utah
Automated Geographic Reference Center (UAGRC). The model also uses an algorithm to extract
rooftop outlines and calculate roof aspects and pitches. The model identifies objects such as
chimneys, dormers, etc. that would hinder the installation of solar photovoltaic panels. Focal
standard deviations and flow of fluids were calculated for this purpose using GIS software.
Figure 2 shows color coded roof aspects where red indicates roofs facing north, green facing
south, blue facing west and yellow facing east.
Figure 2: Calculated roof aspects 5 | P a g e
Rocky Mountain Power
Exhibit RMP___(DLM-1) Page 6 of 11
Docket No. 16-035-__
Witness: Douglas L. Marx
Rocky Mountain Power 3: The Photovoltaic Panel Model
The next part of the model simulates solar panel installations by overlaying solar panels with a
specific dimension over all rooftops while removing solar panels that can’t be fitted due to an
obstruction, change of pitch or aspect.
This study used dimensions for the Kyocera 250 watt photovoltaic panel. Figure 3 shows
modeled solar panel installations on rooftops for a particular residential area served by the
Bingham#11 distribution circuit.
Figure 3: Modeled solar panel installations ESTIMATING NUMBER OF PANELS PER ROOFTOP
The study used Kyocera 250 watt solar panels with dimensions of 1 meter by 1.6 meters to estimate
the total number of photovoltaic panels that could be installed on each rooftop. The calculation
took into account roof aspect, changes in shape, and other objects that may interfere with
installation. The model also eliminated irregular roof areas where standard solar panels cannot fit.
The rooftops identified in this study were found to be able to accommodate an estimated 42,439
panels with a total installed ac generation capacity of 9.01 megawatts at peak production. Figure
4 illustrates the total estimated number of panels for rooftops and the corresponding ac power
generation capacity for respective orientations.
6 | P a g e
Rocky Mountain Power
Exhibit RMP___(DLM-1) Page 7 of 11
Docket No. 16-035-__
Witness: Douglas L. Marx
Rocky Mountain Power 14000
3
12000
2.5
10000
2
8000
1.5
6000
1
4000
Megawatts
Number of solar panels
Calculated Rooftop Solar Capacity
0.5
2000
0
0
Flat
East
West
Adjusted Number of Panels
North
South
Installed AC Capacity
Figure 4: Total number of photovoltaic panels installed and corresponding installed capacity (AC) SOLAR GENERATION CALCULATIONS
A hybrid approach was used to generate solar generation curves for the rooftop installations.
Measured data from a flat roof solar installation in Salt Lake City was used for flat roofs and
information from NREL PV Watts® database was used for all other rooftop solar panels
identified in this study. Figure 5 shows a solar generation profile for a peak solar day and
includes generation from all solar panels identified in this study.
Solar Generation Profile
May 13, 2014
8
4
2
0
0:00
1:00
2:00
3:00
4:00
5:00
6:00
7:00
8:00
9:00
10:00
11:00
12:00
13:00
14:00
15:00
16:00
17:00
18:00
19:00
20:00
21:00
22:00
23:00
Megawatts
6
Figure 5: Calculated solar generation curve
7 | P a g e
Rocky Mountain Power
Exhibit RMP___(DLM-1) Page 8 of 11
Docket No. 16-035-__
Witness: Douglas L. Marx
Rocky Mountain Power DISTRIBUTION CIRCUIT LOADING
The circuit loading data for the Bingham #11 distribution circuit is shown in Figure 6. The circuit
serves 2,244 customers with a peak demand of 9.95 megawatts that occurred on July 14, 2014 at
5:30 pm Mountain Standard Time.
Distribution Circuit Loading
Bingham#11
10
8
6
4
2
0
Figure 6: Distribution Circuit Loading for Bingham#11 8 | P a g e Rocky Mountain Power
Exhibit RMP___(DLM-1) Page 9 of 11
Docket No. 16-035-__
Witness: Douglas L. Marx
Rocky Mountain Power IMPACT OF SOLAR GENERATION ON DISTRIBUTION CIRCUIT LOADING
The energy generated from solar photovoltaic systems is accounted for as a reduction in system
demand as it reduces the amount of energy that the company must supply to the circuit from other
generation resources. The more solar energy generated by solar photovoltaic panels, the more
demand is driven down. The less solar power generated, the greater the demand on other energy
resources to supply the required energy on the circuit. Further, due to various reasons, reduction
of peak demand on a distribution circuit is of particular significance.
Figure 8 shows the circuit load profile on July 14, 2014 along with the estimated generation profile.
The net difference between the load and the solar generation is the resultant circuit loading and
shown with the black line. On the peak demand day, as shown in the chart, the solar generation
reduces the overall circuit peak demand by only 6.8%. This is an insignificant reduction
considering the large number of rooftop photovoltaic panels identified for installation in this study.
Distribution Circuit Loading
Bingham#11
12
10
Circuit peak reduction = 6.8%
8
Megawatts
6
4
2
‐2
0:00
1:00
2:00
3:00
4:00
5:00
6:00
7:00
8:00
9:00
10:00
11:00
12:00
13:00
14:00
15:00
16:00
17:00
18:00
19:00
20:00
21:00
22:00
23:00
0
‐4
Circuit Loading without solar
Total Solar
New Circuit Loading with solar
Figure 7: Solar contribution to distribution circuit loading CONCLUSION
This study provides an overview of the complex techniques used to identify potential rooftops in
a specific geographical location that can accommodate photovoltaic panels to generate electricity.
Based on simulations, the approximate solar generation potential for customers connected to the
Bingham#11 distribution circuit in South Jordan, Utah was found to be approximately 9.01
9 | P a g e Rocky Mountain Power Rocky Mountain Power
Exhibit RMP___(DLM-1) Page 10 of 11
Docket No. 16-035-__
Witness: Douglas L. Marx
megawatts (ac). Further, this study clearly shows that for the identified study area, solar generation
reduces the circuit peak demand by only 6.8%. It should be noted that solar contribution to circuit
demand might vary significantly from minute to minute when the variability of customer load is
combined with the solar generation volatility caused by cloud transients. Considering the
insignificant reduction in peak demand and the potential volatility in solar generation levels, the
distribution planner will continue to plan infrastructure improvements for circuit peak loading
without consideration for the contribution from solar photovoltaic generation.
10 | P a g e Rocky Mountain Power Rocky Mountain Power
Exhibit RMP___(DLM-1) Page 11 of 11
Docket No. 16-035-__
Witness: Douglas L. Marx
APPENDIX A – Quick Facts
Study Area – Bingham 11 Study Service Area (approximate boundaries): EAST – WEST – NORTH – SOUTH – 2865 West 4500 West 10400 South 11800 South Maximum Solar Output – 7.77 MW (May 13, 1200 hrs) Bingham 11 Feeder: Capacity = 10.32 MW 2014 Peak = 9.95 MW (July 14, 1730 hrs) 2015 Projection = 10.15 MW Bingham Substation (Xfmr #1): Capacity = 25 MVA 2014 Peak = 17.82 MW 2015 Projection = 19.26 MW Critical Loads: District Shopping Center Map of Study Area: 11 | P a g e Rocky Mountain Power
Docket No. 16-035-____
Witness: Michael G. Wilding
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Direct Testimony of Michael G. Wilding
November 2016
1
Q.
dba Rocky Mountain Power (“the Company”).
2
3
Please state your name, business address and present position with PacifiCorp,
A.
My name is Michael G. Wilding. My business address is 825 NE Multnomah Street,
Suite 600, Portland, Oregon 97232. My title is Manager, Net Power Costs.
4
5
Qualifications
6
Q.
Briefly describe your education and business experience.
7
A.
I received a Master of Accounting from Weber State University and a Bachelor of
8
Science degree in accounting from Utah State University. I am a Certified Public
9
Accountant licensed in the state of Utah. Prior to joining the Company, I was
10
employed as an internal auditor for Intermountain Healthcare and as an auditor for
11
the Utah State Tax Commission. I have been employed by the Company since
12
February 2014.
13
Q.
Have you testified in previous regulatory proceedings?
14
A.
Yes. I have filed testimony in proceedings before the public utility commissions in
Utah, Wyoming, Idaho, California, and Oregon.
15
16
Purpose of Testimony
17
Q.
What is the purpose of your testimony in this proceeding?
18
A.
My testimony presents and supports the Company’s net power cost ("NPC")
19
analysis of the net metering program (the "Program") for the 12-month period from
20
January 1, 2015 through December 31, 2015 (“Study Period”).
Page 1 - Direct Testimony of Michael G. Wilding
21
Q.
your testimony?
22
23
Have you provided detailed support for the NPC analysis of the Program with
A.
Yes. Exhibit RMP___(MGW-1) includes a detailed NPC analysis of the Program
for the Study Period.
24
25
Net Power Cost Analysis of the Net Metering Program
26
Q.
analysis of the Program.
27
28
Please provide an overview of the framework the Company used in its NPC
A.
The framework of the NPC analysis of the Program calculated the NPC benefits of
29
the Program by assuming a system with no private generation from net metering
30
customers. To do this, the Company first projected the change in generation and
31
market transactions that would have taken place if net metering customers had not
32
generated any power, i.e., took full requirements service from the Company. Next,
33
the Company multiplied the actual costs of generation and market transactions by
34
the incremental changes in generation and market transactions to estimate the net
35
benefit to the system resulting from private generation. The actual costs are taken
36
from the 2015 Adjusted Actual NPC ("Actual NPC") as reported in the Docket No.
37
16-035-01 ("2016 EBA"). Finally, the integration costs approved by the
38
Commission in Docket No. 12-035-100 (the "QF Docket") were deducted from that
39
amount.1
1
See Docket No. 12-035-100, Order on Phase II Issues, at 34 (Utah P.S.C. August 16, 2013). In the QF
Docket, the Commission approved, among other things, solar integration charges the equivalent of 65 percent
and 50 percent of wind integration charges for fixed solar and tracking solar resources, respectively, from the
Company's 2012 Wind Integration Study (the "Phase II Order").
Page 2 - Direct Testimony of Michael G. Wilding
40
Q.
Study Period.
41
42
Please describe the Company’s NPC analysis for the Program during the
A.
Using the Company's Generation and Regulation Initiative Decision Tools
43
("GRID") production cost model to calculate energy changes in system generation
44
and market transactions, the NPC analysis involved comparing the results of two
45
GRID studies. The first GRID study is the Company’s Utah Schedule 37 filing
46
dated April 30, 2015 (“Base Study”). The second GRID study increases Company
47
system load by 58 gigawatt-hours ("GWh"), which is the estimated amount of
48
energy needed to replace generation from Utah net metering customers (the "No
49
NEM Study"), as discussed in the testimony of Company witness Mr. Robert M.
50
Meredith. In other words the No NEM Study removed private generation from the
51
GRID analysis, but made no other changes. Table 1 below shows the difference in
52
energy between the Base Study and the No NEM Study by NPC component for
53
system generation and market transactions.
54
TABLE 1
Change in Generation/Market Transactions (GWh)
NPC Component
Base Study
No NEM Study
Change
Percentage Change
System Balancing Sales
(7,427)
(7,404)
22
39%
System Balancing Purchases
3,841
3,858
17
30%
Coal Generation
37,729
37,746
17
29%
Natural Gas Generation
12,890
12,891
1
2%
Total
47,033
47,090
58
100%
55
The Company’s NPC analysis of the Program is calculated on a monthly
56
basis applying the percentage change (the weight) of the energy to the 2015 actual
57
unit costs of each NPC component. The No NEM Study showed energy changes to
58
the following NPC components: (i) system balancing purchases/sales ("market
Page 3 - Direct Testimony of Michael G. Wilding
59
transactions"), (ii) coal fuel expense, and (iii) natural gas fuel expense. Therefore,
60
the benefit of NEM on a dollar per megawatt-hour basis ("$/MWh") is the weighted
61
aggregate of the market transactions, coal fuel expense, and natural gas fuel
62
expense less the avoided integration costs. The $/MWh benefit is then multiplied
63
by the estimated NEM generation to arrive at the total NPC benefit.
64
Q.
NPC analysis of the Program?
65
66
Have you provided any other exhibits to your testimony that are related to the
A.
Yes, the following exhibits also support the NPC analysis of the Program:
•
67
Confidential Exhibit RMP___(MGW-2): Base GRID Study, the
Company’s Utah Schedule 37 filing dated April 30, 2015.
68
69
•
Confidential Exhibit RMP___(MGW-3): No Net Metering Study.
70
•
Exhibit RMP___(MGW-4): 2015 Actual Net Power Costs.
71
Q.
Please summarize the results of the NPC analysis.
72
A.
Based on the NPC analysis, and as discussed in more detail below, the Company
73
estimates that, for the Study Period, system NPC would increase by approximately
74
$1.3 million if the Company were required to supply the energy that was otherwise
75
generated by net metering customers. This overall result is the aggregation of the
76
NPC calculations the Company conducted over 12 monthly periods. To
77
demonstrate the NPC analysis of the Program for each month, I will walk through
78
the analysis using January 2015 (the first month of the Study Period) as an example.
Page 4 - Direct Testimony of Michael G. Wilding
79
Determining the Necessary Energy From Each Source
80
Q.
Please describe how the Company determined the amount of energy to include
81
in the No NEM Study to account for the assumed condition that there was no
82
private generation.
83
A.
The Company estimated the amount of energy generated by net metering customers
84
and prepared a production profile as discussed in the testimony of Mr. Meredith.
85
According to that methodology, the Company determined that private generation
86
under the Program and avoided line losses was approximately 58 GWh during the
87
Study Period. The Company used this figure to establish the overall energy it would
88
need to include in the No NEM Study. For January 2015, Mr. Meredith calculated
89
the amount of private generation that would need to be replaced in the No NEM
90
Study to be 1,989 MWh.
91
Q.
How did you use the energy estimates prepared by Mr. Meredith?
92
A.
The energy estimates and production profile from net metering customers were run
93
through the GRID model for the No NEM Study. In that study, the GRID model
94
determined how to replace energy otherwise provided by private generation using
95
market transactions (both decreased sales and increased purchases), coal
96
generation, and natural gas generation. As an example, the change in production
97
between the Base Study and the No NEM Study for January 2015 is shown in Table
98
2 below:
Page 5 - Direct Testimony of Michael G. Wilding
TABLE 2
99
100
Market Transactions
101
Q.
Please describe the market transactions component of the NPC Analysis.
102
A.
The actual Palo Verde (“PV”) monthly market price was used for the market
103
transactions (or system balancing sales and purchases) component of the NPC
104
analyses. The actual monthly PV price is shaped to the same profile as private
105
generation and is calculated using the same ratio of heavy load hours (“HLH”) and
106
light load hours (“LLH”). For example, in January 2015, the actual PV market price
107
was $25.54/MWh, based on approximately 85 percent HLH and 15 percent LLH.
108
Q.
Were any adjustments made to the actual monthly PV market price?
109
A.
Yes. The actual monthly PV market price must be adjusted because the change in
110
market transactions occurred in multiple markets. To make this adjustment, I first
111
compared the unit cost of the change in market transactions between GRID studies
112
to the Base Study PV price (the Base Study PV price uses the same HLH/LLH
113
ratio). For January 2015, the unit cost of the change between the Base Study and
114
the No NEM Study was $22.85/MWh ($32,753 / 1,433 MWh) and the Base Study
115
PV market price was $25.54/MWh.
Page 6 - Direct Testimony of Michael G. Wilding
116
The change in the value of the market transactions between the Base Study
117
and the No NEM Study for January 2015 was 89.5 percent of the Base Study PV
118
market price ($22.85 / $25.54). Therefore, the same percentage is applied to the
119
actual monthly PV market price adjustments and results in a Program benefit related
120
to market transactions of $22.89/MWh (Line 28 of Exhibit RMP_MGW-1).
121
Coal Fuel Expense
122
Q.
Please describe the coal fuel expense component of the NPC analysis.
123
A.
For coal generation, the Company used the actual unit cost of coal generation each
124
month. The unit cost of coal generation was $19.60/MWh for January 2015, as
125
shown on Line 32 of Exhibit RMP ___ (MGW-1).
126
Natural Gas Fuel Expense
127
Q.
Please describe the natural gas fuel expense component of the NPC analysis.
128
A.
For natural gas generation, the Company used the actual unit cost of natural gas
129
generation each month. Thus, natural gas generation was $35.14/MWh for January
130
2015, as shown on Line 33 of Exhibit RMP ___ (MGW-1).
131
Integration Costs
132
Q.
Please describe the effect of integration costs on the NPC analysis.
133
A.
Integration costs represent the costs associated with integrating private generation
134
from the Program into the Company’s system, including additional reserves
135
required due to the intermittency of that private generation. This represents an
136
increase to NPC when a customer adds private generation. Likewise, if private
137
generation is removed from the system, there would be no need for integration and
Page 7 - Direct Testimony of Michael G. Wilding
138
additional reserve requirements, decreasing NPC. Consistent with the
139
Commission's Order in the QF Docket, the Company used solar integration costs
140
in the NPC analysis of $2.83/MWh.2
141
NPC Analysis Results
142
Q.
What are the results of the NPC analysis for January 2015?
143
A.
For the month of January 2015, the NPC analysis resulted in a net benefit of
$19.49/MWh or $38,772 as shown in Table 33 below.
144
TABLE 3
145
146
Q.
the 12-months of the Study Period?
147
148
What is the cumulative benefit of private generation under the Program for
A.
Assuming an estimate of 58 GWh of power from private generation under the
Program that would need to be replaced, NPC would increase by $22.28/MWh or
149
2
Docket No. 12-035-100, Order on Phase II Issues, at 34 (Utah P.S.C. August 16, 2013).
Figures shown in Table 3 are rounded and electronic workpapers supporting the calculation have been
provided with the filing.
3
Page 8 - Direct Testimony of Michael G. Wilding
150
$1.3 million as seen in Lines 39 and 40, respectively, of Exhibit RMP___(MGW-
151
1).
152
Q.
Does this conclude your direct testimony?
153
A.
Yes.
Page 9 - Direct Testimony of Michael G. Wilding
Rocky Mountain Power
Exhibit RMP___(MGW-1)
Docket No. 16-035-__
Witness: Michael G. Wilding
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Michael G. Wilding
NPC Analysis
November 2016
∑ Lines 6:9
UT Net Metering Generation HLH
UT Net Metering Generation LLH
Base Palo Verde HLH
Base Palo Verde LLH
Energy (MWh 000)
Line 31 / Line 33
Line 32 / Line 34
Exhibit RMP___(MGW-4) Row 289
Exhibit RMP___(MGW-4) Row 300
Exhibit RMP___(MGW-4) Row 139
Exhibit RMP___(MGW-4) Row 150
∑ Lines 34:37
Line 24 * Line 35
Line 25 * Line 36
Line 22 * Line 23* Line 30
40 Total NPC Benefit of Net Metering Generation
Line 39 * Line 10
NPC Benefit of Net Metering Generation
Unit Value of Solar - Purchases/Sales
Integration Cost - Fixed Solar
Unit Value of Solar - Coal
Unit Value of Solar - Gas
Integration Cost - Fixed Solar
Total Unit Value of Solar $/MWH
NPC Unit Benefit of Net Metering Generation
32 Coal Fuel Burn Expense
33 Natural Gas Fuel Burn Expense
Actual Unit Costs ($)/(MWh)
30 Coal Generation
31 Natural Gas Generation
(Line 26 * Line 28 +Line 27 * Line 29) / (Line 26 + Line 27)
Line 27 * Line 22
Line 16
Line 17
Line 20 / Line 21
(Line 16 * Line 18 +Line 17 * Line 19) / (Line 16 + Line 17)
(Line 1 + Line 2) / (Line 6 + Line 7)
2015 Actual NPC
Actual Palo Verde Market Price
UT Net Metering Generation HLH
UT Net Metering Generation LLH
Actual Palo Verde HLH
Actual Palo Verde LLH
Line 6 / Line 10
Line 7 / Line 10
Line 8 / Line 10
Line 9 / Line 10
∑ Lines 16:19
Market Transactions
Base Palo Verde Market Price
System Balancing Sales
System Balancing Purchases
Coal Generation
Gas Generation
Total
Dollars ($000)
Line 1 / Line 6
Line 2 / Line 7
Line 3 / Line 8
Line 4 / Line 9
Line 5 / Line 10
Percentage Change or Weight of NPC Component
System Balancing Sales
System Balancing Purchases
Coal Fuel Burn Expense
Gas Fuel Burn Expense
Total Unit Costs $/MWH
Unit Costs ($)/(MWh) of Change Between Base Study and No NEM Study
System Balancing Sales
System Balancing Purchases
Coal Generation
Gas Generation
UT Net Metering Solar Generation
28 Coal Fuel Burn Expense
29 Natural Gas Fuel Burn Expense
34
35
36
37
38
39
∑ Lines 1:4
Change in Energy Between Base Study and No NEM Study
27 Actual Palo Verde Market Price
28 Adjusted Actual Palo Verde Market Price
23
24
25
26
Reference
Change in Net Power Costs Between Base Study and No NEM Study
Dollars ($)
System Balancing Sales
System Balancing Purchases
Coal Fuel Burn Expense
Gas Fuel Burn Expense
Change in Net Power Cost
20 Base Palo Verde Market Price
21 Unit Cost Change of Market Transactions
Unit Cost Change of Market Transactions
22 Compared to Base Palo Verde Market Price
16
17
18
19
16
17
18
19
20
11
12
13
14
15
6
7
8
9
10
1
2
3
4
5
Line
No.
Exhibit RMP___(MGW-1)
Net Power Cost Analysis of the Net Metering Program
Study Period: January - December 2015
$
$/MWh
$/MWh
$/MWh
$/MWh
$/MWh
$/MWh
$/MWh
$/MWh
MWh ('000s)
MWh ('000s)
$ ('000s)
$ ('000s)
$/MWh
$/MWh
MWh
MWh
$/MWh
$/MWh
%
$/MWh
$/MWh
MWh
MWh
$/MWh
$/MWh
%
%
%
%
%
$/MWh
$/MWh
$/MWh
$/MWh
$/MWh
MWh
MWh
MWh
MWh
MWh
$
$
$
$
$
Units
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
38,772
2.95
13.55
5.03
0.80
(2.83)
19.49
19.60
35.14
3,657
692
71,690
24,309
25.58
22.89
1,697
292
25.79
24.42
89.5%
25.54
22.85
1,697
292
25.79
24.10
12.87%
59.19%
25.66%
2.28%
100%
22.92
22.83
22.83
20.71
22.79
256
1,177
510
45
1,989
5,869
26,884
11,650
937
45,340
Jan-15
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
55,445
2.54
9.75
6.39
1.67
(2.83)
17.51
19.34
39.37
3,166
492
61,222
19,353
23.73
19.59
2,638
529
24.17
21.54
82.5%
23.72
19.57
2,638
529
24.17
21.45
12.98%
49.76%
33.02%
4.23%
100%
19.97
19.47
19.95
18.54
19.65
411
1,576
1,046
134
3,166
8,209
30,678
20,859
2,483
62,230
Feb-15
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
86,824
2.47
8.90
7.65
2.51
(2.83)
18.70
19.94
40.40
3,540
492
70,591
19,892
24.59
20.52
3,890
753
25.07
22.08
83.4%
24.56
20.49
3,890
753
25.07
21.90
12.04%
43.38%
38.36%
6.22%
100%
21.61
20.18
20.17
18.58
20.25
559
2,014
1,781
289
4,642
12,076
40,649
35,924
5,366
94,015
Mar-15
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
92,039
9.12
6.14
3.83
1.34
(2.83)
17.61
19.67
31.38
3,333
588
65,574
18,448
23.71
20.02
4,493
734
24.05
21.61
84.4%
23.65
19.97
4,493
734
24.00
21.50
45.53%
30.69%
19.49%
4.28%
100%
19.89
20.10
19.94
12.50
19.65
2,380
1,604
1,019
224
5,227
47,324
32,244
20,319
2,797
102,683
Apr-15
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
91,155
6.46
6.28
6.97
0.94
(2.83)
17.82
19.72
29.49
3,394
722
66,951
21,287
23.36
20.73
3,968
1,147
24.04
21.02
88.7%
25.52
22.64
3,968
1,147
26.75
21.25
31.16%
30.33%
35.34%
3.17%
100%
23.13
22.13
21.39
22.82
22.20
1,594
1,551
1,808
162
5,115
$ 36,868
$ 34,334
$ 38,666
$
3,706
$ 113,573
May-15
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
164,156
6.75
17.15
4.01
(0.20)
(2.83)
24.88
19.32
28.13
3,618
872
69,888
24,536
30.39
29.89
5,673
925
31.72
22.24
98.4%
27.48
27.03
5,673
925
28.50
21.25
22.58%
57.38%
20.76%
-0.72%
100%
26.52
27.23
21.94
(0.50)
26.17
1,490
3,786
1,370
(47)
6,599
39,515
103,092
30,063
24
172,694
Jun-15
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
208,780
23.63
9.19
1.04
0.29
(2.83)
31.32
19.47
28.61
3,627
996
70,614
28,498
32.48
35.06
5,562
1,103
34.02
24.72
107.9%
32.97
35.59
5,562
1,103
34.65
24.50
67.41%
26.21%
5.37%
1.02%
100%
35.06
36.92
25.22
34.12
35.01
4,493
1,747
358
68
6,665
157,538
64,497
9,020
2,319
233,374
Jul-15
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
210,010
23.01
11.32
1.31
(0.17)
(2.83)
32.64
19.36
29.67
3,716
939
71,953
27,849
33.40
36.60
5,423
1,010
34.98
24.91
109.6%
32.94
36.10
5,423
1,010
34.32
25.49
62.87%
30.94%
6.78%
-0.59%
100%
35.99
36.31
23.17
(0.70)
35.44
4,045
1,990
436
(38)
6,433
145,566
72,274
10,100
26
227,966
Aug-15
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
129,292
13.61
1.53
8.77
(0.12)
(2.83)
20.95
18.62
29.30
3,450
907
64,237
26,574
28.61
28.39
5,055
1,115
29.72
23.56
99.2%
28.94
28.72
5,055
1,115
30.03
24.01
47.93%
5.37%
47.09%
-0.40%
100%
29.09
25.40
23.08
11.55
26.13
2,957
332
2,906
(24)
6,170
86,041
8,422
67,054
(282)
161,236
Sep-15
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
107,494
9.30
2.87
8.95
0.77
(2.83)
19.05
18.75
28.07
3,164
818
59,312
22,964
26.23
24.56
4,917
726
26.90
21.70
93.6%
27.62
25.86
4,917
726
28.05
24.72
37.87%
11.67%
47.72%
2.74%
100%
25.73
26.30
22.56
14.08
23.96
2,137
658
2,693
155
5,643
54,968
17,317
60,742
2,178
135,205
Oct-15
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
67,773
5.76
3.13
9.63
1.73
(2.83)
17.42
18.84
26.45
3,021
830
56,905
21,945
22.21
21.00
2,970
921
22.69
20.65
94.5%
26.35
24.91
2,970
921
27.23
23.52
27.42%
14.89%
51.14%
6.55%
100%
25.09
24.56
21.64
22.15
23.06
1,067
579
1,990
255
3,891
26,775
14,226
43,065
5,643
89,709
Nov-15
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
35,761
$
9.12
1.83
8.29
(0.47)
(2.83)
15.94 $
18.89
26.21
3,613
879
68,248
23,024
21.22
18.90
1,894
350
21.59
19.21
89.1%
26.70
23.79
1,894
350
27.23
23.76
48.23%
9.70%
43.88%
-1.81%
100%
23.93
23.09
22.26
15.83
23.26
1,082
218
985
(41)
2,244
25,896
5,025
21,920
(642)
52,200
Dec-15
1,287,503
22.28
19.30
30.21
41,301
9,226
797,186
278,679
57,785
Total
Rocky Mountain Power
Exhibit RMP___(MGW-1) Page 1 of 1
Docket No. 16-035-__
Witness: Michael G. Wilding
REDACTED
Rocky Mountain Power
Exhibit RMP___(MGW-2)
Docket No. 16-035-__
Witness: Michael G. Wilding
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
REDACTED
Exhibit Accompanying Direct Testimony of Michael G. Wilding
Base GRID Study: Utah Schedule 37 filing Dated April 30, 2015
November 2016
THIS EXHIBIT IS CONFIDENTIAL
IN ITS ENTIRETY AND IS PROVIDED
UNDER SEPARATE COVER REDACTED
Rocky Mountain Power
Exhibit RMP___(MGW-3)
Docket No. 16-035-__
Witness: Michael G. Wilding
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
REDACTED
Exhibit Accompanying Direct Testimony of Michael G. Wilding
No Net Metering GRID Study
November 2016
THIS EXHIBIT IS CONFIDENTIAL
IN ITS ENTIRETY AND IS PROVIDED
UNDER SEPARATE COVER Rocky Mountain Power
Exhibit RMP___(MGW-4)
Docket No. 16-035-__
Witness: Michael G. Wilding
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF UTAH
ROCKY MOUNTAIN POWER
____________________________________________
Exhibit Accompanying Direct Testimony of Michael G. Wilding
2015 Actual Net Power Cost
November 2016
$
Sub Total Long Term Firm Purchases
PURCHASED POWER & NET INTERCHANGE
Long Term Firm Purchases
APS Supplemental
$
Combine Hills Wind
Deseret Purchase
Douglas PUD Settlement
Eagle Mountain - UAMPS/UMPA
Gemstate
Georgia-Pacific Camas
Hermiston Purchase
Hurricane Purchase
IPP Purchase
MagCorp Reserves
Nucor
P4 Production
PGE Cove
Rock River Wind
Small Purchases east
Small Purchases west
Three Buttes Wind
Top of the World Wind
Tri-State Purchase
Wolverine Creek Wind
Total Special Sales For Resale
Total Long Term Firm Sales
Total Short Term Firm Sales
Total Secondary Sales
Special Sales For Resale
Long Term Firm Sales
Black Hills
BPA Wind
Hurricane Sale
LADWP (IPP Layoff)
Leaning Juniper Revenue
SMUD
UMPA II
251,024,443
1,669,317 $
4,233,142
31,175,407
2,224,195
1,717,288
2,556,143
4,474,866
65,178,585
124,722
26,570,488
6,564,146
6,273,000
19,806,635
148,515
4,175,495
42,287
18,682,592
37,624,530
9,497,794
8,285,296
258,918,757
47,636,194
211,282,563 $
-
13,832,185 $
2,169,073
15,340
26,570,488
43,065
(4,485,948)
9,491,990
Total
Exhibit RMP___(MGW-4)
2015 Actual Net Power Cost
As reported in:
Utah Energy Balancing Account Mechanism
Workpaper (2.3) - Adjusted Actual Net Power Cost
23,740,564
150,254 $
202,963
2,958,660
199,763
261,000
593,599
5,602,898
13,163
2,526,408
544,790
521,050
1,666,980
31,000
457,859
3,629
2,185,451
4,572,609
785,134
463,356
29,170,259
4,552,158
24,618,101 $
-
1,189,243 $
243,484
1,040
2,526,408
336
(1,576)
593,224
Jan-15
21,455,235
188,450 $
298,817
2,499,978
332,592
257,700
536,996
4,565,789
13,982
2,470,568
495,143
521,050
1,716,980
31,000
545,470
3,419
1,703,297
3,761,688
740,999
771,319
28,812,449
3,299,900
25,512,549 $
-
1,064,338 $
190,005
1,170
2,470,568
1,912
(990,222)
562,129
Feb-15
21,906,930
230,017 $
340,652
2,784,921
354,819
98,158
261,800
567,204
4,640,625
9,419
2,442,788
535,482
521,050
1,666,980
(12,485)
411,351
4,634
1,829,865
3,623,431
783,623
812,597
26,987,332
3,088,771
23,898,561 $
-
1,064,554 $
185,592
1,300
2,442,788
1,602
(1,200,196)
593,131
Mar-15
19,607,472
224,728 $
387,297
2,873,880
201,354
108,011
257,700
581,574
4,638,832
8,424
2,118,108
494,763
521,050
1,666,980
11,000
326,838
3,337
1,194,093
2,361,309
790,580
837,614
17,409,077
3,307,219
14,101,858 $
-
1,090,086 $
174,337
1,235
2,118,108
3,448
(662,971)
582,976
Apr-15
20,625,056
99,280 $
325,807
2,168,653
252,783
161,620
257,700
546,283
5,815,073
6,669
2,517,328
535,647
521,050
1,666,980
11,000
224,051
3,012
1,405,511
2,776,594
794,201
535,816
11,514,369
4,342,538
7,171,831 $
-
1,212,363 $
138,881
1,235
2,517,328
4,749
(119,712)
587,693
May-15
18,942,832
343,502 $
85,222
2,724,506
153,896
214,814
257,700
366,796
5,917,717
6,728
2,213,043
537,821
521,050
1,666,980
11,000
143,684
3,126
777,841
1,595,787
866,794
534,826
14,360,894
4,239,727
10,121,167 $
-
1,214,192 $
(24,780)
1,365
2,213,043
5,774
(102,781)
932,914
Dollars
Jun-15
19,210,437
143,946 $
449,149
2,696,565
142,017
244,318
257,700
430,828
5,700,157
11,525
2,226,795
560,280
521,050
1,666,980
11,000
223,583
3,316
970,646
1,572,652
850,739
527,192
17,285,828
5,215,196
12,070,632 $
-
1,191,108 $
149,915
1,430
2,226,795
6,395
(141,166)
1,780,719
Jul-15
20,001,426
164,916 $
440,711
2,862,425
208,889
217,528
276,000
189,068
5,895,189
12,812
2,236,375
575,305
521,050
1,666,980
11,000
181,676
4,655
935,478
2,168,521
850,361
582,489
20,818,994
4,886,320
15,932,674 $
-
1,206,109 $
140,500
1,430
2,236,375
5,178
(104,105)
1,400,832
Aug-15
18,703,316
51,341 $
332,871
2,495,300
138,322
205,813
257,700
5,924,024
13,455
994,890
555,178
526,150
1,666,980
11,000
205,614
3,246
1,269,628
2,530,691
767,789
753,324
23,829,088
2,944,032
20,885,056 $
-
1,170,861 $
190,594
1,300
994,890
4,081
(210,730)
793,036
Sep-15
19,289,944
26,847 $
330,331
2,553,885
111,043
151,261
125,600
4,891,110
10,238
2,248,015
576,778
526,150
1,666,980
11,000
375,928
3,147
1,379,207
2,837,611
808,398
656,414
23,845,153
3,681,430
20,163,723 $
-
1,182,434 $
216,340
1,300
2,248,015
2,967
(563,152)
593,527
Oct-15
22,697,198
41,787 $
448,507
2,228,111
102,694
127,416
(20,757)
5,653,551
7,371
2,270,055
571,783
526,150
1,666,980
11,000
491,276
3,292
2,408,378
4,648,323
735,081
776,201
19,567,702
3,907,562
15,660,140 $
-
1,171,739 $
258,122
1,300
2,270,055
3,148
(379,798)
582,996
Nov-15
24,844,033
4,251
590,816
2,328,525
26,022
188,350
106,300
662,520
5,933,620
10,940
2,306,115
581,177
526,150
1,419,855
11,000
588,165
3,473
2,623,197
5,175,314
724,095
1,034,149
25,317,611
4,171,340
21,146,271
-
1,075,159
306,083
1,235
2,306,115
3,474
(9,539)
488,812
Dec-15
Rocky Mountain Power
Exhibit RMP___(MGW-4) Page 1 of 7
Docket No. 16-035-__
Witness: Michael G. Wilding
Total Purchased Power & Net Interchange
$
568,213,995
153,681,772 $
304,094
5,400,000
Total Storage & Exchange
404,260,687
1,655,013
3,539,220 $
2,007,659
(3,891,866)
151,581,231
5,400,000
-
Total Short Term Firm Purchases
Total Secondary Purchases
$
4,909,460 $
5,706,446
22,551,685
2,941,316
406,735
463,986
13,234,356
639,901
173,973
3,788,267
1,721
6,311,933
1,372,923
401,384
2,274,828
7,899,282
11,908,767
14,356,367
10,724,359
3,977,161
3,510,784
1,091,841
2,302,612
28,030,957
881,438
1,453,247
29,961
235,543
4,567,442
4,567,442
Storage & Exchange
APS Exchange
BPA Exchange
BPA FC II Wind
BPA FC IV Wind
BPA So. Idaho
Cowlitz Swift
EWEB FC I
PSCO FC III
PSCo Exchange
Redding Exchange
SCL State Line
Total Long Term Firm Purchases
Total Mid-Columbia Contracts
Mid-Columbia Contracts
Douglas - Wells
Grant Surplus
Grant Reasonable
Total Qualifying Facilities
$
Total Seasonal Purchased Power
Qualifying Facilities
QF California
QF Idaho
QF Oregon
QF Utah
QF Washington
QF Wyoming
Biomass One QF
Chevron Wind QF
DCFP QF
Evergreen BioPower QF
ExxonMobil QF
Five Pine Wind QF
Foote Creek III Wind QF
Kennecott Refinery QF
Kennecott Smelter QF
Mountain Wind 1 QF
Mountain Wind 2 QF
North Point Wind QF
Oregon Wind Farm QF
Power County North Wind QF
Power County South Wind QF
Roseburg Dillard QF
SF Phosphates QF
Spanish Fork Wind 2 QF
Sunnyside QF
Tesoro QF
Threemile Canyon Wind QF
US Magnesium QF
Utah Pavant Solar
Utah Red Hills Solar
$
$
Seasonal Purchased Power
Constellation 2013-2016
$
$
45,622,745
9,341,096 $
158,739
450,000
450,000
-
-
35,672,910
58,954
303,338 $
167,305
(411,689)
11,873,392
383,591 $
357,620
2,232,321
131,059
9,938
36,143
1,373,734
68,667
2,137
278,402
272,431
155,576
13,994
1,033,169
1,379,222
519,008
336,926
282,500
263,079
42,651
189,067
2,471,343
40,815
-
-
$
$
45,164,895
9,585,253 $
26,732
450,000
450,000
-
-
35,102,911
58,954
303,338 $
167,305
(411,689)
13,588,722
613,161 $
412,424
2,079,866
130,584
8,985
45,068
1,369,768
77,525
8,355
277,408
562,688
173,807
1,034,829
1,450,828
1,184,298
660,410
438,739
393,958
58,406
176,274
2,217,831
127,588
85,923
-
-
$
46,065,368
9,408,716
15,391
450,000
450,000
-
-
36,191,261
1,208,954
$
$
303,338 $
167,305
738,311
13,075,377
517,795 $
348,683
2,083,699
140,937
9,764
57,107
1,184,980
97,155
4,145
349,688
1,721
569,400
192,860
15,837
659,247
980,912
1,323,953
716,205
378,618
326,400
98,187
195,826
2,488,705
235,993
97,560
-
-
$
39,938,947
8,056,787
15,958
450,000
450,000
-
-
31,416,202
(42,644)
$
$
303,338 $
167,305
(513,287)
11,851,374
476,699 $
387,802
2,213,376
165,716
33,277
32,692
1,349,747
34,809
9,566
326,666
534,668
81,278
35,720
544,887
819,233
1,196,979
990,722
320,887
288,821
101,211
154,033
1,500,147
121,059
131,379
-
-
$
$
31,827,729
(168,317) $
8,071
450,000
450,000
-
-
31,537,975
58,954
303,338 $
167,305
(411,689)
10,853,966
398,493 $
610,037
2,058,277
159,834
46,791
27,604
782,532
43,208
18,295
331,609
303,016
54,478
57,566
69,406
313,461
501,596
673,385
995,405
176,434
156,838
153,517
132,633
2,489,652
149,820
150,078
-
-
$
$
57,204,324
26,802,916 $
9,974
450,000
450,000
-
-
29,941,434
58,954
303,338 $
167,305
(411,689)
10,939,648
365,294 $
587,508
1,881,372
173,783
73,947
22,348
791,338
22,566
28,778
366,967
343,886
39,352
53,989
276,226
312,003
536,400
774,537
977,986
190,948
147,998
150,892
158,800
2,448,651
63,726
150,351
-
-
1,574,456
$
70,913,580
37,183,252 $
13,267
450,000
450,000
-
-
31,692,604
58,954
303,338 $
167,305
(411,689)
12,423,213
342,968 $
524,298
1,773,878
228,779
79,243
29,432
754,749
50,884
25,651
356,251
452,616
93,478
43,185
292,391
505,673
909,758
1,074,040
1,306,219
270,455
232,561
133,429
260,499
2,494,428
6,339
182,010
-
1,574,456 $
1,629,374
$
$
54,166,562
19,332,222 $
15,702
450,000
450,000
-
-
32,739,264
58,954
303,338 $
167,305
(411,689)
12,678,884
354,860 $
359,539
1,706,265
508,167
70,851
28,208
685,595
46,809
27,096
372,810
498,589
87,525
63,610
361,310
536,636
921,129
1,280,775
1,186,496
315,233
273,825
75,555
276,689
2,471,509
8,991
160,814
-
1,629,374
1,366,720
$
$
44,464,625
11,633,739 $
10,116
450,000
450,000
-
-
31,004,050
56,852
301,236 $
167,305
(411,689)
12,243,882
377,268 $
428,242
1,636,083
82,120
49,826
30,448
866,649
42,660
15,298
321,570
614,933
93,280
47,995
389,990
558,303
858,731
1,549,529
903,563
311,216
267,400
55,451
170,615
2,439,206
22,839
110,668
-
1,366,720
$
44,462,737
12,336,452 $
11,629
450,000
450,000
-
-
31,667,764
56,852
301,236 $
167,305
(411,689)
12,320,969
374,269 $
613,248
1,477,031
522,928
12,259
35,393
1,349,090
39,494
19,899
325,550
549,839
98,430
49,616
319,585
525,245
763,304
1,313,910
801,592
356,225
321,045
62,280
198,191
2,061,308
28,423
102,817
-
(3,108) $
(3,108)
$
44,360,126
7,586,606
9,219
450,000
450,000
-
-
36,314,302
56,852
$
$
301,236 $
167,305
(411,689)
13,560,252
320,263 $
548,767
1,543,068
346,251
5,723
50,693
1,307,232
62,446
14,402
292,338
589,970
127,780
19,873
269,497
861,141
1,301,237
1,313,212
758,242
423,918
362,575
96,834
200,564
2,450,904
57,464
119,408
116,450
-
-
44,022,356
2,583,051
9,296
450,000
450,000
-
-
40,980,009
(35,576)
208,808
167,305
(411,689)
16,171,552
384,798
528,280
1,866,450
351,159
6,129
68,850
1,418,943
53,677
351
189,008
1,019,898
175,080
296,423
1,014,687
1,486,418
2,152,740
1,090,593
511,989
476,282
63,430
189,421
2,497,272
59,196
121,424
29,961
119,093
-
Rocky Mountain Power
Exhibit RMP___(MGW-4) Page 2 of 7
Docket No. 16-035-__
Witness: Michael G. Wilding
NET POWER COST
Total Other Generation Expense
Other Generation Expense
Blundell
Black Cap Solar
Total Gas Fuel Burn Expense
Gas Fuel Burn Expense
Chehalis
Currant Creek
Gadsby
Gadsby CT
Hermiston
Lake Side 1
Lake Side 2
Total Coal Fuel Burn Expense
$
$
1,537,015,925
5,212,711
5,102,428 $
110,283
278,678,518
36,529,831 $
69,244,606
6,252,323
3,233,408
26,628,707
66,140,092
70,649,550
797,186,270
8,267,839 $
58,186,217
15,663,881
18,012,713
58,264,775
12,932,324
154,578,849
111,852,653
232,232,677
98,705,741
28,488,602
$
Coal Fuel Burn Expense
Carbon
Cholla
Colstrip
Craig
Dave Johnston
Hayden
Hunter
Huntington
Jim Bridger
Naughton
Wyodak
142,513,515 $
4,129,672
146,643,187
$
Total Wheeling & U. of F. Expense
Wheeling & U. of F. Expense
Firm Wheeling
Non-Firm Wheeling
$
124,508,536
386,352
382,165 $
4,187
24,308,644
3,442,998
7,175,424
1,452
213,858
2,381,396
5,023,901
6,069,615
71,689,837
2,693,783 $
4,660,476
1,216,478
1,359,945
5,270,394
1,265,628
15,220,510
11,321,151
16,322,374
10,233,891
2,125,206
11,671,217
11,613,101 $
58,116
$
109,415,845
521,834
518,120 $
3,714
19,353,152
1,267,871
4,816,712
232,564
1,355,795
8,012,004
3,668,206
61,221,909
2,220,133 $
2,807,220
826,970
1,336,857
4,685,115
1,068,639
12,208,853
10,157,679
15,365,170
8,750,839
1,794,434
11,966,503
11,612,493 $
354,011
$
121,850,003
300,044
293,896 $
6,148
19,891,679
1,412,314
7,134,706
268,391
1,488,006
2,663,556
6,924,706
70,591,442
2,175,270 $
4,612,993
1,417,460
1,687,508
4,816,904
942,758
11,371,996
11,158,540
20,119,362
9,683,482
2,605,169
11,988,802
11,720,265 $
268,537
$
118,390,688
563,414
555,283 $
8,132
18,447,927
1,402,285
5,098,876
52,591
337,563
1,483,630
2,775,161
7,297,821
65,573,935
1,178,434 $
4,889,763
1,374,666
1,743,103
4,270,610
519,910
12,184,339
10,424,397
20,875,260
5,682,382
2,431,071
11,275,542
11,153,555 $
121,986
$
120,591,062
639,528
627,971 $
11,558
21,286,799
1,050,112
5,401,617
51,515
184,886
2,630,201
7,045,388
4,923,080
66,951,034
219 $
5,094,514
1,053,990
1,776,837
3,957,038
892,671
13,249,823
10,508,320
21,892,823
5,980,348
2,544,450
11,400,340
11,171,549 $
228,791
$
149,880,400
335,172
315,066 $
20,106
24,536,495
3,244,918
4,784,964
1,034,880
151,997
2,652,179
6,464,605
6,202,952
69,888,010
$
6,207,723
1,507,047
1,505,830
4,943,187
1,125,258
13,303,105
10,089,331
22,122,323
6,488,198
2,596,008
12,277,292
11,473,375 $
803,917
$
165,874,798
614,225
594,112 $
20,113
28,497,932
5,308,154
5,617,929
2,034,029
236,718
2,489,126
5,577,331
7,234,645
70,614,108
$
6,148,425
1,457,874
1,739,145
4,537,738
912,518
12,910,569
8,984,112
23,849,136
7,994,448
2,080,143
12,520,781
11,930,384 $
590,398
$
146,185,314
365,395
350,768 $
14,628
27,848,592
3,168,811
6,022,164
1,841,511
392,629
2,607,792
6,210,748
7,604,937
71,953,458
$
5,175,777
1,461,471
1,790,785
5,495,046
1,294,435
12,874,308
10,425,749
21,161,287
9,524,133
2,750,467
12,670,300
12,375,095 $
295,205
$
124,344,011
383,312
373,668 $
9,645
26,574,146
4,096,968
5,539,790
1,190,437
247,925
2,787,862
6,906,769
5,804,395
64,237,450
$
5,454,998
1,499,275
1,115,354
4,705,182
1,208,689
12,829,988
7,032,248
18,895,472
9,085,098
2,411,145
12,513,565
12,055,443 $
458,122
115,387,905
381,310
374,696 $
6,614
22,963,976
4,831,858 $
6,253,660
(430)
448,198
1,744,942
5,837,463
3,848,284
59,312,150
$
5,420,481
1,403,026
1,087,089
5,222,818
1,325,243
12,689,382
5,378,599
16,494,445
8,012,022
2,279,044
12,112,886
11,510,638 $
602,248
$
115,898,185
324,088
320,343 $
3,744
21,944,967
3,800,858
6,170,092
8,494
324,335
2,408,932
4,298,634
4,933,623
56,905,045
$
2,325,878
1,086,053
1,425,166
5,037,310
1,328,050
12,293,066
5,560,018
16,634,072
8,934,596
2,280,836
11,931,662
11,634,368 $
297,294
124,689,179
398,036
396,342
1,694
23,024,209
3,502,682
5,228,672
37,845
194,345
2,598,846
5,324,532
6,137,287
68,247,893
5,387,968
1,359,572
1,445,094
5,323,431
1,048,524
13,442,908
10,812,508
18,500,952
8,336,305
2,590,630
14,314,296
14,263,248
51,049
Rocky Mountain Power
Exhibit RMP___(MGW-4) Page 3 of 7
Docket No. 16-035-__
Witness: Michael G. Wilding
Total Requirements
Total Special Sales For Resale
Total Long Term Firm Sales
Total Short Term Firm Sales
Total Secondary Sales
Special Sales For Resale
Long Term Firm Sales
Black Hills
BPA Wind
Hurricane Sale
LADWP (IPP Layoff)
SMUD
UMPA II
NET SYSTEM LOAD
Check
99,239
722,529
-
29,229
3,310
16
52,824
(75)
13,935
5,216,791
(0.00)
38,614
818,383
-
22,879
2,583
18
47,668
(47,131)
12,597
4,413,770
0.00
29,270
772,361
-
22,890
2,523
20
47,031
(57,125)
13,931
4,719,954
(0.00)
31,644
618,986
-
24,188
2,370
19
23,128
(31,555)
13,494
4,564,264
0.00
85,923
326,507
-
29,130
1,888
19
52,370
(11,181)
13,697
4,640,985
0.00
95,426
364,010
-
29,146
1,344
21
48,210
(4,892)
21,597
5,319,907
(0.00)
113,703
445,491
-
28,015
2,038
22
48,497
(6,719)
41,850
5,494,039
(0.00)
107,625
555,652
-
28,750
1,910
22
48,976
(4,955)
32,922
5,350,899
0.00
87,147
734,320
-
27,023
2,591
20
49,183
(10,030)
18,360
4,707,457
(0.00)
67,253
736,142
-
27,590
2,941
20
49,558
(26,804)
13,948
4,575,008
(0.00)
75,964
621,299
-
27,066
3,509
20
49,942
(18,077)
13,504
4,844,669
(0.00)
88,258
903,862
-
22,334
4,161
19
52,463
(454)
9,735
5,258,614
0.00
8,539,607
821,768
856,997
801,631
650,630
412,430
459,436
559,194
663,277
821,467
803,395
697,263
992,120
============= ============= ============= ============= ============= ============= ============= ============= ============= ============= ============= ============= =============
67,645,964
6,038,559
5,270,767
5,521,585
5,214,893
5,053,415
5,779,343
6,053,232
6,014,176
5,528,924
5,378,402
5,541,932
6,250,735
920,066
7,619,541
-
318,240
31,168
236
569,850
(218,998)
219,570
59,106,356
0
Rocky Mountain Power
Exhibit RMP___(MGW-4) Page 4 of 7
Docket No. 16-035-__
Witness: Michael G. Wilding
52,126
99,864
254,983
44,920
10,315
10,695
152,593
37,035
7,202
56,473
57
90,752
62,479
12,769
70,402
140,487
183,055
207,502
147,468
57,345
50,378
32,759
45,915
418,218
27,528
19,540
1,392
12,281
Qualifying Facilities
QF California
QF Idaho
QF Oregon
QF Utah
QF Washington
QF Wyoming
Biomass One QF
Chevron Wind QF
DCFP QF
Evergreen BioPower QF
ExxonMobil QF
Five Pine Wind QF
Foote Creek III Wind QF
Kennecott Refinery QF
Kennecott Smelter QF
Mountain Wind 1 QF
Mountain Wind 2 QF
North Point Wind QF
Oregon Wind Farm QF
Power County North Wind QF
Power County South Wind QF
Roseburg Dillard QF
SF Phosphates QF
Spanish Fork Wind 2 QF
Sunnyside QF
Tesoro QF
Threemile Canyon Wind QF
US Magnesium QF
Utah Pavant Solar
Utah Red Hills Solar
2,306,533
122,421
Total Seasonal Purchased Power
Total Qualifying Facilities
122,421
3,923,200
Seasonal Purchased Power
Constellation 2013-2016
Sub Total Long Term Firm Purchases
176,939
2,857
6,117
24,206
2,212
282
868
19,126
4,127
69
4,142
4,038
7,722
445
17,167
20,367
7,704
4,541
4,149
3,870
1,280
3,351
37,753
546
-
-
-
371,176
200,027
4,598
6,790
22,662
1,995
252
1,146
18,882
3,877
294
4,148
8,003
7,702
17,802
22,393
16,882
8,831
6,285
5,644
1,752
3,222
31,727
4,005
1,134
-
-
-
292,686
207,344
5,469
6,194
23,070
2,182
277
1,393
16,990
3,508
531
5,205
57
9,483
6,872
504
12,363
16,065
22,271
9,670
6,327
5,426
2,946
3,776
38,119
7,354
1,289
-
-
-
316,477
184,135
5,056
6,773
24,606
2,747
850
695
18,830
2,239
529
4,840
9,170
4,306
1,136
11,505
15,325
20,605
13,472
5,514
4,971
3,037
3,172
19,245
3,757
1,754
-
-
-
267,093
166,108
4,516
10,787
24,560
2,693
1,176
539
2,714
802
4,950
5,762
3,111
1,831
2,148
6,319
9,068
12,904
13,852
3,308
2,930
4,606
2,704
38,161
4,623
2,042
-
-
-
317,679
166,542
4,254
10,698
21,914
3,015
1,831
391
1,589
934
5,436
6,192
2,136
1,717
8,549
6,077
8,201
14,212
13,485
3,428
2,619
4,527
4,187
37,148
1,991
2,009
-
-
-
323,090
173,879
4,039
8,352
20,100
3,473
1,968
466
2,252
810
5,292
6,107
3,224
1,374
9,049
7,983
10,615
14,630
18,270
3,652
3,114
4,003
4,149
38,266
216
2,474
-
41,151
41,151
316,354
184,049
4,145
5,908
19,260
6,521
1,764
433
9,698
1,919
995
5,584
6,276
2,926
2,024
11,182
7,957
10,804
16,218
16,318
3,930
3,419
2,267
4,377
37,673
293
2,157
-
41,345
41,345
336,474
194,499
4,481
8,789
18,504
4,675
1,243
616
12,084
2,187
599
4,808
8,569
4,095
1,527
12,070
9,528
12,578
21,673
12,827
4,345
3,708
1,664
4,745
36,917
742
1,527
-
40,000
40,000
326,332
186,297
4,399
10,296
17,362
6,814
337
791
18,694
2,343
903
4,864
7,185
5,012
1,578
9,891
9,989
13,264
17,194
10,916
4,661
4,204
1,869
3,795
27,681
904
1,354
-
(75)
(75)
285,492
220,786
3,723
9,686
18,017
4,398
162
1,348
18,472
4,686
723
4,385
8,317
6,902
632
8,341
16,253
21,664
18,589
10,439
5,922
5,056
2,905
3,813
37,197
1,793
1,620
5,743
-
-
360,318
245,929
4,588
9,474
20,723
4,196
174
2,008
19,817
5,594
13
2,818
11,651
8,471
9,174
17,545
22,711
24,620
14,847
5,823
5,416
1,903
4,622
38,331
1,848
1,632
1,392
6,538
-
-
410,029
============= ============= ============= ============= ============= ============= ============= ============= ============= ============= ============= ============= =============
PURCHASED POWER & NET INTERCHANGE
Long Term Firm Purchases
APS Supplemental
80,830
8,550
12,700
10,950
13,150
5,750
13,310
5,020
5,750
1,950
1,200
2,050
450
Combine Hills Wind
91,036
4,365
6,426
7,326
8,329
7,007
1,833
9,659
9,478
7,159
7,104
9,645
12,706
Deseret Purchase
511,279
59,957
37,894
51,600
55,879
21,957
48,694
47,350
55,328
37,669
40,487
24,817
29,647
Douglas PUD Settlement
66,010
5,836
9,773
10,527
6,186
7,766
4,728
4,159
6,196
3,996
3,187
2,895
761
Eagle Mountain - UAMPS/UMPA
64,170
4,208
4,650
6,811
8,029
7,905
7,465
7,198
5,797
5,194
6,913
Gemstate
40,781
5,335
9,905
15,258
10,283
Georgia-Pacific Camas
45,774
6,072
5,493
5,802
5,949
5,588
3,752
4,407
1,934
6,777
Hermiston Purchase
51,300
59,405
61,069
114,728
121,992
106,776
115,755
132,188
80,323
121,078
137,168
1,200,393
98,613
Hurricane Purchase
1,919
203
215
145
130
103
104
177
197
207
158
113
168
IPP Purchase
569,850
52,824
47,668
47,031
23,128
52,370
48,210
48,497
48,976
49,183
49,558
49,942
52,463
MagCorp Reserves
Nucor
P4 Production
PGE Cove
12,000
1,014
942
1,012
990
1,014
990
1,014
1,014
990
1,014
992
1,014
Rock River Wind
117,698
12,905
15,374
11,594
9,212
6,315
4,050
6,302
5,132
5,795
10,595
13,890
16,534
Small Purchases east
685
30
27
48
29
27
25
331
49
29
28
29
33
Small Purchases west
Three Buttes Wind
294,027
34,255
26,697
28,681
18,716
22,030
12,192
15,214
14,663
19,902
21,707
38,166
41,805
Top of the World Wind
570,069
69,282
56,995
54,900
35,777
42,070
24,179
23,828
32,856
38,344
42,994
70,429
78,414
Tri-State Purchase
113,780
9,280
7,878
9,232
9,453
9,568
11,874
11,364
11,352
8,729
10,019
7,690
7,341
Wolverine Creek Wind
142,899
7,992
13,303
14,015
14,447
9,241
9,224
9,093
10,046
12,993
11,321
13,387
17,836
Rocky Mountain Power
Exhibit RMP___(MGW-4) Page 5 of 7
Docket No. 16-035-__
Witness: Michael G. Wilding
Total Purchased Power & Net Interchange
11,356,233
4,717,580
(19,328)
(10,822)
Total Storage & Exchange
Total Short Term Firm Purchases
Total Secondary Purchases
(344)
151
(25,671)
(389)
4,806
(472)
11,097
Storage & Exchange
APS Exchange
BPA Exchange
BPA FC II Wind
BPA FC IV Wind
BPA So. Idaho
Cowlitz Swift
EWEB FC I
PSCO FC III
PSCo Exchange
Redding Exchange
SCL State Line
6,546,382
316,649
Total Mid-Columbia Contracts
Total Long Term Firm Purchases
228,377
88,272
-
Mid-Columbia Contracts
Douglas - Wells
Grant Surplus
Grant Reasonable
988,518
287,159
(699)
126,479
142,848
(375)
(4,903)
(26)
32
8,548
(19,645)
575,579
27,464
18,429
9,035
-
1,010,853
442,498
(10,813)
60,670
69,120
462
(7,913)
(415)
12
6,672
(7,268)
518,499
25,786
19,841
5,945
-
985,752
411,810
(10,510)
28,380
(467)
4,018
(92)
3,486
7,435
14,000
556,072
32,252
23,098
9,154
-
837,201
360,481
(8,952)
6,116
(1,785)
(10,652)
332
5,932
12,289
479,555
28,327
20,196
8,131
-
532,000
92,505
3,844
(77,310)
(77,989)
(912)
4,628
132
2
(2,565)
(607)
512,962
29,175
21,438
7,737
-
924,372
548,965
1,250
(142,516)
(138,570)
(824)
9,467
(526)
375
(4,546)
(7,893)
516,674
27,042
20,062
6,980
-
1,038,519
620,701
(593)
(138,857)
(142,848)
984
3,099
439
65
(6,405)
5,809
516,117
25,884
19,300
6,584
-
1,040,935
591,755
(3,056)
(140,029)
(142,848)
(269)
(1,055)
(99)
77
(5,862)
10,027
550,919
30,396
22,090
8,306
-
860,566
367,610
2,302
(90,156)
(69,118)
1,004
(9,342)
(84)
32
(4,210)
(8,438)
540,810
19,979
14,287
5,692
-
1,054,831
495,530
6,130
61,754
78,336
679
(1,981)
1,192
314
(10,624)
(6,162)
491,491
19,702
13,939
5,763
-
1,106,525
342,661
12,501
145,659
137,883
802
(2,799)
(992)
294
5,690
4,781
605,704
24,600
17,596
7,004
-
976,160
155,903
(10,730)
148,987
142,842
851
(8,238)
(250)
117
(537)
14,202
682,000
26,042
18,101
7,941
-
Rocky Mountain Power
Exhibit RMP___(MGW-4) Page 6 of 7
Docket No. 16-035-__
Witness: Michael G. Wilding
2,912,239
259,703
8,934
339,706
81,453
289,386
108,844
186,746
250,864
188,567
298,777
137,842
78,271
261,284
296,563
64,063
Total Hydro Generation
Other Generation
Blundell
Black Cap Solar
Dunlap I Wind
Foote Creek I Wind
Glenrock Wind
Glenrock III Wind
Goodnoe Wind
High Plains Wind
Leaning Juniper 1
Marengo I Wind
Marengo II Wind
McFadden Ridge Wind
Rolling Hills Wind
Seven Mile Wind
Seven Mile II Wind
Check
Check
2,673,647
238,592
Total Resources
23,659
409
45,539
8,647
34,741
12,797
8,081
26,703
5,761
17,346
6,231
7,584
30,879
35,422
7,466
429,624
418,402
11,222
691,745
75,839
206,170
(452)
1,154
98,795
180,636
129,603
3,657,407
120,044
213,880
107,036
89,789
440,574
54,410
742,117
596,440
692,956
447,548
152,613
19,809
474
37,412
6,748
25,047
10,063
10,708
28,532
11,963
23,400
10,920
8,964
23,634
32,858
7,060
344,485
328,369
16,116
491,613
(1,220)
122,578
(349)
1,421
51,424
239,964
77,795
3,166,223
109,061
115,263
85,062
82,115
419,434
46,220
651,342
517,572
618,966
396,558
124,630
21,268
780
31,759
6,591
28,369
10,931
9,827
26,626
12,340
26,112
12,168
8,301
26,284
26,988
5,772
249,325
235,179
14,146
492,365
7,849
184,383
(374)
2,370
59,540
51,814
186,783
3,540,027
112,827
192,991
99,844
103,128
423,670
43,184
579,371
561,887
811,872
426,605
184,648
15,455
944
24,171
6,191
18,187
6,938
15,167
17,347
17,427
29,460
13,982
6,109
16,486
21,559
4,585
242,495
228,207
14,288
587,960
20,072
168,639
(132)
3,568
61,200
84,241
250,372
3,333,229
51,934
211,502
93,681
105,348
364,889
23,609
652,122
549,873
835,050
266,968
178,253
21,324
960
18,954
4,934
21,949
7,859
15,915
16,457
20,319
16,216
7,486
5,085
18,974
16,612
3,585
208,629
173,327
35,302
721,927
(153)
183,136
(279)
1,423
114,978
186,354
236,468
3,394,230
(286)
230,835
89,592
96,126
369,823
38,845
682,801
557,949
794,264
344,196
190,085
21,829
1,196
13,171
3,511
11,925
4,546
17,223
10,992
18,065
19,747
9,002
3,566
10,036
12,116
2,586
205,367
170,817
34,550
872,239
113,039
164,123
16,135
2,077
122,228
237,658
216,979
3,617,853
(204)
266,859
104,750
95,349
428,447
45,736
708,797
528,460
859,571
401,835
178,253
23,165
1,112
18,311
5,326
17,509
6,234
22,297
14,629
23,593
27,646
13,031
4,845
14,369
18,473
3,975
176,950
136,630
40,320
996,138
231,044
182,143
30,783
3,304
106,974
181,159
260,731
3,627,111
(197)
261,395
101,739
101,768
402,671
39,667
693,067
491,886
950,804
431,938
152,373
22,705
1,042
14,876
4,991
15,875
5,820
21,842
12,617
21,086
23,933
12,132
4,438
13,688
14,763
3,071
125,852
92,752
33,100
938,519
100,045
203,662
28,629
5,923
115,981
220,274
264,005
3,715,991
(144)
218,621
103,314
106,171
473,567
54,915
704,318
578,289
826,315
455,162
195,463
22,992
802
21,227
6,770
20,843
7,282
15,602
18,260
15,756
20,671
7,815
5,985
18,090
19,656
4,417
105,192
86,238
18,954
907,032
150,786
179,034
16,010
3,276
132,458
200,926
224,542
3,449,966
(120)
230,973
103,480
71,374
432,999
50,842
753,202
457,537
745,187
427,244
177,248
24,125
638
24,119
7,683
19,918
7,363
14,586
21,942
12,426
26,089
11,487
6,739
18,196
24,113
5,199
116,826
111,791
5,035
817,979
201,750
213,292
(538)
5,416
80,459
222,738
94,862
3,164,144
(139)
223,379
107,681
62,677
461,525
57,361
711,535
262,719
669,893
448,200
159,313
20,575
398
42,136
9,167
34,852
13,476
17,187
22,135
14,149
27,709
13,144
6,714
32,970
36,844
7,840
285,214
276,884
8,330
829,810
111,902
245,325
(432)
3,427
121,306
229,144
119,138
3,021,087
(229)
93,733
99,563
77,895
454,561
55,012
702,933
313,395
657,702
406,527
159,995
22,797
179
48,031
10,894
40,171
15,535
18,311
34,624
15,682
40,448
20,444
9,941
37,678
37,159
8,507
422,280
415,051
7,229
878,594
82,040
204,621
(73)
1,508
137,410
237,512
215,576
3,613,299
(219)
240,043
96,815
77,245
468,810
45,129
754,008
572,311
733,193
446,540
179,424
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
(0)
0
(0)
0
0
0
(0)
2,851,003
271,265
257,592
254,116
214,008
196,629
159,511
214,515
192,879
206,168
224,623
299,296
360,401
============= ============= ============= ============= ============= ============= ============= ============= ============= ============= ============= ============= =============
67,645,964
6,038,559
5,270,767
5,521,585
5,214,893
5,053,415
5,779,343
6,053,232
6,014,176
5,528,924
5,378,402
5,541,932
6,250,735
============= ============= ============= ============= ============= ============= ============= ============= ============= ============= ============= ============= =============
9,225,921
Total Gas Generation
Hydro Generation
West Hydro
East Hydro
Total Other Generation
1,092,993
2,257,106
88,928
34,867
1,202,753
2,272,420
2,276,854
41,300,567
392,328
2,499,474
1,192,557
1,068,985
5,140,970
554,930
8,335,613
5,988,318
9,195,773
4,899,321
2,032,298
Gas Generation
Chehalis
Currant Creek
Gadsby
Gadsby CT
Hermiston
Lake Side 1
Lake Side 2
Total Coal Generation
Coal Generation
Carbon
Cholla
Colstrip
Craig
Dave Johnston
Hayden
Hunter
Huntington
Jim Bridger
Naughton
Wyodak
Rocky Mountain Power
Exhibit RMP___(MGW-4) Page 7 of 7
Docket No. 16-035-__
Witness: Michael G. Wilding
1407 W. North Temple, Suite 330
Salt Lake City, Utah 84116
November 9, 2016
VIA ELECTRONIC FILING
AND OVERNIGHT DELIVERY
Public Service Commission of Utah
Heber M. Wells Building, 4th Floor
160 East 300 South
Salt Lake City, UT 84114
Attention:
Gary Widerburg
Commission Secretary
Re:
Advice No. 16-13
Revisions to Schedule 135, Net Metering Service
Proposal for new Schedule 135A, Net Metering - Transition Service
Enclosed for filing are originals and five copies of proposed tariff sheets associated with Tariff
P.S.C.U No. 50 of PacifiCorp, d.b.a. Rocky Mountain Power, applicable to electric service in the
State of Utah. Pursuant to the requirement of Rule R746-405-1(D), Rocky Mountain Power (the
“Company”) states that the proposed tariff sheets do not constitute a violation of state law or
Commission rule. The Company will also provide an electronic version of this filing and the
accompanying workpapers to [email protected]. The Company respectfully requests an effective date
of December 10, 2016 for the proposed tariff changes, as explained in more detail below.
Fifth Revision of Sheet No. B.1
1st Revision Sheet No. 135.1
Original Sheet No. 135A.1E
Original Sheet No. 135A.2E
Original Sheet No. 135A.3E
Original Sheet No. 135A.4E
Original Sheet No. 135A.5E
Index
Schedule 135
Schedule 135A
Schedule 135A
Schedule 135A
Schedule 135A
Schedule 135A
Electric Service Schedules
Net Metering Service
Net Metering - Transition Service
Net Metering - Transition Service
Net Metering - Transition Service
Net Metering - Transition Service
Net Metering - Transition Service
Through this filing the Company is requesting modifications to Schedule 135, Net Metering
Service, to close it to new service. In its place, the Company seeks approval of Electric Service
Schedule No. 135A, Net Metering - Transition Service, which mirrors the current Schedule 135
with the exception of the following language which is added to the Availability Section:
Customers will be subject to all changes to net metering service including
changes to credits, charges or rate structures offered herein and in related
Public Service Commission of Utah
November 9, 2016
Page 2
tariffs resulting from the final determination under Utah Code Ann. § 5415-105.1 which may include, without limitation, a transfer from this tariff
to all new applicable service schedules approved by the Commission.
Residential customers who apply for net metering service after December 9, 2016, will take service
pursuant to Schedule 135A until the Commission rules on the Company’s proposals set forth in its
Compliance Filing and Request to Complete All Analyses Required Under the Net Metering
Statute for the Evaluation of the Net Metering Program (“Compliance Filing”), filed concurrently
with this tariff advice filing. Proposed Schedule 135A does not “increase rates, charges or
conditions, change classifications which result in increases in rates and charges or make changes
which result in lesser service or more restrictive conditions at the same rate or charge.” Therefore,
Commission Rule R746-405-2(E) provides the Commission authority to implement Schedule
135A 30 days from the date of this filing.
Background
The Commission has been actively reviewing and evaluating the Company’s residential net
metering service in Utah since late 2013. For example, the Company proposed a fixed net metering
facilities charge on net metering customers to cover distribution and certain customer service costs
when it filed its 2014 general rate case, Docket No. 13-035-184 (the “2014 GRC”). In a notice
issued April 16, 2014, following the enactment of Utah Code Ann. § 54-15-105.1 (“Net Metering
Statute”),1 the Commission stated its intent to address the implementation of the statute in the 2014
GRC.
All other issues in the 2014 GRC were ultimately settled later that year, so the final hearings held
in that docket only concerned the proposed fixed net metering facilities charge and implementation
of the Net Metering Statute. Following hearings, the Commission issued its order, declining to
approve the proposed net metering charge and declining to determine the costs and benefits of the
net metering program. Rather, “recognizing the importance of the issues raised by parties in the
rate case,” the Commission established a separate, on-going docket to examine the costs and
1
54-15-105.1.
Determination of costs and benefits - Determination of just and reasonable charge, credit or
ratemaking structure.
The governing authority shall:
(1) determine, after appropriate notice and opportunity for public comment, whether costs that the electrical
corporation or other customers will incur from a net metering program will exceed the benefits of the net
metering program, or whether the benefits of the net metering program will exceed the costs; and
(2) determine a just and reasonable charge, credit, or ratemaking structure, including new or existing tariffs,
in light of the costs and benefits.
Utah Code Ann. § 54-15-105.1(1) shall be referred to as “Subsection One,” and § 54-15-105.1(2) shall be referred to
as “Subsection Two.”
Public Service Commission of Utah
November 9, 2016
Page 3
benefits of the Company’s net metering program.2 The Commission also decided that it would
perform the examination in steps: first it would establish an appropriate analytical framework to
implement the Net Metering Statute, then it would “examine the costs and benefits that result from
applying the data to the approved analytical framework” and determine whether any proposed
change in rate is just and reasonable. The analytical framework to be established to implement
Subsection One was to “include the types of analyses that must be performed, the components of
costs and benefits to be included in the analyses, and the sources and time period of data inputs.”3
The Commission indicated it would examine the costs and benefits that result from applying the
approved analytical framework to the data, and ultimately make the Subsection Two
determination, “in a further phase of this docket, a general rate case or other appropriate
proceeding.”4 The Company has filed its Compliance Filing to provide the Commission with all
of the information needed to complete the referenced Subsection One and Two determinations.
In the meantime, the net metering program has experienced exponential growth since the
Company’s initial request for a fixed net metering facilities charge in the 2014 GRC. For example,
by the end of 2013, 2,200 customers were participating in the program. By the end of calendar
year 2015, that number had climbed to approximately 6,700 customers, a growth rate of 200
percent in just two years. As of October 7, 2016, 7,000 more customers enrolled, with over 3,500
more expected to enroll by the end of this year, bringing the total number of net-metering
customers to over 17,000 by the end of 2016, a 160 percent growth in just one year.
Tariff Advice Letter Requests
Consistent with the determinations the Company seeks in its Compliance Filing, in this tariff
advice letter, the Company requests that Schedule 135, Net Metering Service, be closed to new
customers after December 9, 2016, and that customers requesting residential net metering service
after December 9, 2016 be served under proposed Schedule 135A until the Commission makes a
final determination under the Net Metering Statute.
Proposed Schedule 135A facilitates a transition to a future program that includes an updated rate
design for residential customer generators. It leaves the same service, conditions and rates in place
for new residential net metering applicants that are available under the existing tariff, but provides
clear notice that transition tariff, Schedule 135A, is subject to change once the Commission has
fulfilled its duties under the Net Metering Statute. As part of the Compliance Filing, the Company
requests approval of proposed Schedules 5 and 136 for net metering service. Proposed Schedule 5
reflects the elements of the Company’s proposed rate structure. Not only will this change facilitate
transition to a new rate structure, it will provide important data to help further refine rates and rate
structures for net metering customers in the future.
2
Docket No. 14-035-114, Notices of Comment Period and Scheduling Conference, 2014 WL 6713287 at *1 (Utah
P.S.C. November 21, 2014).
3
Id.
4
Id. at *2.
Public Service Commission of Utah
November 9, 2016
Page 4
The Company supports keeping the current net metering customers on the existing net metering
program and their current rate schedule. We acknowledge that current customers made investments
based on the current structure and respect the customers' need for reasonable certainty for recovery
of their investments. The Company expects this issue to be considered in a future proceeding.
However, current customers may voluntarily opt in to the new Schedule 5.
In addition, current net metering customers generally do not have meters that are capable of billing
the on-peak demand charge that is included in the proposed rate structure in the Compliance Filing.
Transitioning these customers to the new schedule would be operationally and administratively
challenging.
The Commission has approved closing service to existing customers under similar circumstances.
See, e.g., In the Matter of Bear Lake Comm’n, Inc., 2013 WL 4399208 (Utah P.S.C. August 8,
2013) (grandfathering emergency line service to existing customers); In re U.S. West Comm’n,
1999 WL 35639170 (Utah P.S.C. November 26, 1999) (grandfathering Centrex Plus service to
existing customers); In Re U.S. West Paging, Inc., 93-2026-01, 1993 WL 501443 (July 2, 1993)
(grandfathering mobile telephone service to existing customers).
In addition to seeking approval of transition tariff, Schedule 135A, the Company is also seeking
approval of minor, necessary modifications to the currently effective residential and commercial
interconnection agreements which set forth the interconnection requirements for net metering
customers. The modifications clarify that new customers will be subject to any changes made to
net metering service, consistent with the Commission’s ruling in the Company’s concurrent
Compliance Filing. The specific changes are reflected in a form redlined interconnection
agreement, attached to this tariff filing as Exhibit A.
Change to Schedule 135
Like current Schedule 135, Schedule 135A includes the terms and conditions under which the
Company offers net metering service. All of the terms and conditions are the same as those in
current Schedule 135, with the exception of the addition of the highlighted second sentence in the
following section:
AVAILABILITY: At any point on the Company’s interconnected system. Customers will be
subject to all changes to net metering service including changes to credits, charges or rate
structures offered herein and in related tariffs resulting from the final determination under
Utah Code Ann. § 54-15-105.1 which may include, without limitation, a transfer from this
tariff to all new applicable service schedules approved by the Commission.
Rocky Mountain Power respectfully requests that all formal correspondence and requests for
additional information regarding this filing be addressed to the following:
By E-mail (preferred):
[email protected]
[email protected]
Public Service Commission of Utah
November 9, 2016
Page 5
By regular mail:
Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
Informal inquiries may be directed to Bob Lively at (801) 220-4052.
Sincerely,
Jeffrey K. Larsen
Vice President, Regulation
cc:
Division of Public Utilities
Office of Consumer Services
Enclosures
Redlined and Clean Tariff Sheets
Schedule 135 – Net Metering Service
New Schedule 135A – Net Metering – Transition Service
Fifth Revision of Sheet No. B.1
Canceling Fourth Revision of Sheet No. B.1
P.S.C.U. No. 50
ELECTRIC SERVICE SCHEDULES
STATE OF UTAH
Schedule No.
80
Summary of Effective Rate Adjustments
91
Surcharge To Fund Low Income Residential Lifeline Program
92
Low Income Residential Lifeline Program Surcharge Refund Credit
94
Energy Balancing Account (EBA) Pilot Program
98
REC Revenue Adjustment
105
Irrigation Load Control Program
107
Solar Incentive Program
110
New Homes Program
111
Home Energy Savings Incentive Program
114
Air Conditioner Direct Load Control Program (Cool Keeper Program)
118
Low Income Weatherization
135
Net Metering Service*
135A Net Metering – Transition Service
140
Non-Residential Energy Efficiency
193
Demand Side Management (DSM) Cost Adjustment
195
Solar Incentive Program Cost Adjustment
300
Regulation Charges
Sheet No.
80
91
92
94.1- 94.10
98
105.1 - 105.2
107.1 - 107.6
110.1 - 110.3
111.1 - 111.7
114.1 - 114.5
118.1 - 118.6
135.1 - 135.5
135A.1 - 135A.5
140.1 - 140.25
193.1 - 193.2
195.1 - 195.2
300.1 - 300.4
Schedule Numbers not listed are not currently used.
*These Schedules are not available to new customers or premises.
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-13
FILED: November 9, 2016
EFFECTIVE: December 10, 2016
First Revision of Sheet No. 135.1
Canceling Original Sheet No. 135.1
P.S.C.U. No. 50
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 135
STATE OF UTAH
______________
Net Metering Service
No New Service
______________
AVAILABILITY: At any point on the Company's interconnected system.
customers will be served under this Schedule.
No new
APPLICATION: To customers that own or lease a customer-operated renewable generating
facility or, as defined in Utah Code 54-2-1(16)(d), an eligible customer that purchases electricity from
an independent energy producer operating a renewable generating facility, with a capacity of not
more than twenty-five (25) kilowatts for a residential facility and two (2) megawatts for a nonresidential facility that is located on, or adjacent to, the customers’ premises, is interconnected and
operates in parallel with the Company’s existing distribution facilities, is intended primarily to offset
part or all of the customer’s own electrical requirements, is controlled by an inverter capable of
enabling safe and efficient synchronous coupling with Rocky Mountain Power’s electrical system,
and has executed an Interconnection Agreement for Net Metering Service with the Company. This
schedule is offered in compliance with Utah Code Ann. § 54-15-101 to 106 and R746-312.
DEFINITIONS: Net Metering means measuring the difference between the electricity
supplied by the Company and the electricity generated by an eligible customer-generator and fed
back to the electric grid over the applicable billing period.
An Inverter means a device that converts direct current power into alternating current power
that is compatible with power generated by the Company.
Annualized Billing Period means the period commencing after the regularly scheduled meter
reading for the month of March or in the case of new Schedule 135 service the date that the customer
first takes service from Schedule 135 and ending on the regularly scheduled meter reading for the
month of March.
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-13
FILED: November 9, 2016
EFFECTIVE: December 10, 2016
P.S.C.U. No. 50
Original Sheet No. 135A.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 135A
STATE OF UTAH
______________
Net Metering – Transition Service
______________
AVAILABILITY: At any point on the Company's interconnected system. Customers will
be subject to all changes to net metering service including changes to credits, charges or rate
structures offered herein and in related tariffs resulting from the final determination under Utah Code
Ann. § 54-15-105.1 which may include, without limitation, a transfer from this tariff to all new
applicable service schedules approved by the Commission.
APPLICATION: On a first-come, first-served basis to any customer that owns or leases a
customer-operated renewable generating facility or, as defined in Utah Code 54-2-1(16)(d), an
eligible customer that purchases electricity from an independent energy producer operating a
renewable generating facility, with a capacity of not more than twenty-five (25) kilowatts for a
residential facility and two (2) megawatts for a non-residential facility that is located on, or adjacent
to, the customers’ premises, is interconnected and operates in parallel with the Company’s existing
distribution facilities, is intended primarily to offset part or all of the customer’s own electrical
requirements, is controlled by an inverter capable of enabling safe and efficient synchronous coupling
with Rocky Mountain Power’s electrical system, and has executed an Interconnection Agreement for
Net Metering Service with the Company. This schedule is offered in compliance with Utah Code
Ann. § 54-15-101 to 106 and R746-312.
DEFINITIONS: Net Metering means measuring the difference between the electricity
supplied by the Company and the electricity generated by an eligible customer-generator and fed
back to the electric grid over the applicable billing period.
An Inverter means a device that converts direct current power into alternating current power
that is compatible with power generated by the Company.
Annualized Billing Period means the period commencing after the regularly scheduled meter
reading for the month of March or in the case of new Schedule 135A service the date that the customer
first takes service from Schedule 135A and ending on the regularly scheduled meter reading for the
month of March.
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-13
FILED: November 9, 2016
EFFECTIVE: December 10, 2016
P.S.C.U. No. 50
Original Sheet No. 135A.2
ELECTRIC SERVICE SCHEDULE NO. 135A - Continued
DEFINITIONS (continued)
Residential Customer means any customer that receives electric service under Electric Service
Schedules 1, 2 or 3.
Small Non-Residential Customer means any customer that receives electric service under
Electric Service Schedules 15 or 23.
Large Non-Residential Customer means any customer that receives electric service under
Electric Service Schedules 6, 6A, 6B, 8 or 10.
Renewable Generating Facility means a facility that uses energy derived from one of the
following:
a) solar photovoltaics;
b) solar thermal energy;
c) wind energy;
d) hydrogen;
e) organic waste;
f) hydroelectric energy;
g) waste gas and waste heat capture or recovery;
h) biomass and biomass byproducts, except for the combustion of wood that has been
treated with chemical preservatives such as creosote, pentachlorophenol, chromated
copper arsenate, or municipal waste in a solid form;
i) forest or rangeland woody debris from harvesting or thinning conducted to improve
forest or rangeland ecological health and to reduce wildfire risk;
j) agricultural residues;
k) dedicated energy crops;
l) landfill gas or biogas produced from organic matter, wastewater, anaerobic disgesters,
or municipal solid waste; or
m) geothermal energy.
MONTHLY BILL: The Electric Service Charge shall be computed in accordance with the
Monthly Billing in the applicable standard service tariff. Regardless of whether the Customer provides
excess net generation during the month, the Customer shall be billed the minimum monthly amount
from the applicable standard service tariff.
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-13
FILED: November 9, 2016
EFFECTIVE: December 10, 2016
P.S.C.U. No. 50
Original Sheet No. 135A.3
ELECTRIC SERVICE SCHEDULE NO. 135A - Continued
SPECIAL CONDITIONS:
1. If the energy supplied to the Company is less than the energy purchased from the Company, the
prices specified in the Energy Charge section of the Monthly Billing of the applicable standard
service tariff shall be applied to the positive balance owed to the Company.
2. If the energy supplied to the Company is greater than the energy supplied by the Company, the
Customer shall be billed for the appropriate monthly charges and shall be credited for such Net
Metering Energy as follows:
A. Residential and Small Non-Residential Customer shall be credited for such net energy with
a cumulative kilowatt-hour credit. The credit will be deducted from the customer’s kilowatthour usage on the customer’s next monthly bill thus offsetting the customer’s next monthly
bill at the full retail rate of the customer’s rate schedule.
B. A Large Non-Residential Customer, at the time of initial enrollment under this tariff , must
elect a compensation method to receive cumulative credits for the upcoming Annualized
Billing Period from one of the following options:
(i)
An Average Energy Price for the applicable calendar year according to the
Volumetric Non-Levelized Prices shown in Schedule 37 as determined by the
following formula: 0.38 x Winter On-Peak Energy Price + 0.19 x Summer OnPeak Energy Price + 0.29 x Winter Off-Peak Energy Price + 0.14 x Summer
Off-Peak Energy Price; or
(ii)
A Seasonally Differentiated Energy Price for the applicable calendar year
according to the Non-Levelized Prices shown in Schedule 37 as determined by
the following formula: 0.57 x Summer On-Peak Energy Price + 0.43 x Summer
Off-Peak Energy Price for the regularly scheduled meter readings from June
through September and 0.57 x Winter On-Peak Energy Price + 0.43 x Winter
Off-Peak Energy Price for the regularly scheduled meter readings from October
through May; or
(iii)
An average retail rate for the Electric Service Schedule applicable to the net
metering customer as calculated from the previous year’s Federal Energy
Regulation Commission Form No. 1 to be determined and available by July 1,
2009, and by July 1st of every subsequent year. Current average retail rates are
listed below:
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-13
FILED: November 9, 2016
EFFECTIVE: December 10, 2016
P.S.C.U. No. 50
Original Sheet No. 135A.4
ELECTRIC SERVICE SCHEDULE NO. 135A - Continued
SPECIAL CONDITIONS (continued)
Schedule 6:
Schedule 6A:
Schedule 6B:
Schedule 8:
Schedule 10:
8. 4498¢ per kWh
11.7871¢ per kWh
10.8914¢ per kWh
7.5210¢ per kWh
7.5619¢ per kWh
A Large Non-Residential Customer may change the compensation method once per year at
the beginning of each Annualized Billing Period. The Company must receive written
change notification of any change within sixty (60) days of the beginning of the Annualized
Billing Period.
3. All unused credits accumulated by the customer-generator, except Customers taking service
under Electric Service Schedule No. 10, shall expire with the regularly scheduled meter reading
for the month of March of each year. For Customers taking service under Electric Service
Schedule No. 10, all unused credits accumulated by the customer-generator shall expire with
the regularly scheduled meter reading for the month of October of each year.
4. Upon the customer-generator’s request and within thirty (30) days notice to the Company, the
Company shall aggregate for billing purposes the meter to which the net metering facility is
physically attached (“designated meter”) with one or more meters (“additional meter”) if the
following conditions are met:
(i) the additional meter is located on or adjacent to premises of the customer-generator;
(ii) the additional meter is used to measure only electricity used for the customergenerator’s requirements;
(iii) the designated meter and additional meter are subject to the same rate schedule; and
(iv) the designated meter and the additional meter are served by the same primary
feeder.
At the time of notice to the Company, the customer-generator must identify the specific meters
and designate a rank order for the additional meters to which net metering credits are to be
applied.
5. The customer-generator shall provide at the customer’s expense all equipment necessary to
meet applicable local and national standards regarding electrical and fire safety, power quality,
and interconnection requirements established by the National Electrical Code, the Institute of
Electrical and Electronics Engineers, and Underwriters Laboratories.
(Continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-13
FILED: November 9, 2016
EFFECTIVE: December 10, 2016
P.S.C.U. No. 50
Original Sheet No. 135A.5
ELECTRIC SERVICE SCHEDULE NO. 135A - Continued
6. For customer-generators generation systems of 10 kilowatts or less that are inverter-based, a
disconnect switch is not required. For all other generation systems, the customer-generator must
install and maintain a manual disconnect switch that will disconnect the generating facility from
the Company’s distribution system. The disconnect switch must be a lockable, load-break
switch that plainly indicates whether it is in the open or closed position. Except as provided in
R746-312-4(2) (a) (ii), the disconnect switch must be readily accessible to the Company at all
times and located within ten (10) feet of the Company’s meter.
7. The Company shall not be liable directly or indirectly for permitting or continuing to allow an
attachment of a net metering facility, or for the acts or omissions of the customer-generator that
cause loss or injury, including death, to any third party.
8. The Company may test and inspect an interconnection at times that the electrical corporation
considers necessary to ensure the safety of electrical workers and to preserve the integrity of
the electric power grid.
9. Unless otherwise agreed to by a separate contract, the owner of the renewable energy facility
retains ownership of the non-energy attributes associated with electricity the facility generates.
ELECTRIC SERVICE REGULATIONS: Service under this Schedule will be in accordance
with the terms of the Electric Service Agreement between the Customer and the Company. The Electric
Service Regulations of the Company on file with and approved by the Public Service Commission of
the State of Utah, including future applicable amendments, will be considered as forming a part of and
incorporated in said Agreement.
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-13
FILED: November 9, 2016
EFFECTIVE: December 10, 2016
Fourth Fifth Revision of Sheet No. B.1
Canceling Third Fourth Revision of Sheet No. B.1
P.S.C.U. No. 50
ELECTRIC SERVICE SCHEDULES
STATE OF UTAH
Schedule No.
80
Summary of Effective Rate Adjustments
91
Surcharge To Fund Low Income Residential Lifeline Program
92
Low Income Residential Lifeline Program Surcharge Refund Credit
94
Energy Balancing Account (EBA) Pilot Program
98
REC Revenue Adjustment
105
Irrigation Load Control Program
107
Solar Incentive Program
110
New Homes Program
111
Home Energy Savings Incentive Program
114
Air Conditioner Direct Load Control Program (Cool Keeper Program)
118
Low Income Weatherization
135
Net Metering Service*
135A Net Metering – Transition Service
140
Non-Residential Energy Efficiency
193
Demand Side Management (DSM) Cost Adjustment
195
Solar Incentive Program Cost Adjustment
300
Regulation Charges
Sheet No.
80
91
92
94.1- 94.10
98
105.1 - 105.2
107.1 - 107.6
110.1 - 110.3
111.1 - 111.7
114.1 - 114.5
118.1 - 118.6
135.1 - 135.5
135A.1 - 135A.5
140.1 - 140.25
193.1 - 193.2
195.1 - 195.2
300.1 - 300.4
Schedule Numbers not listed are not currently used.
*These Schedules are not available to new customers or premises.
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-0213
FILED: February 5November 9, 2016
EFFECTIVE: March 6December 10, 2016
First Revision of Sheet No. 135.1
Canceling Original Sheet No. 135.1
P.S.C.U. No. 50
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 135
STATE OF UTAH
______________
Net Metering Service
No New Service
______________
AVAILABILITY: At any point on the Company's interconnected system.
customers will be served under this Schedule.
No new
APPLICATION: On a first-come, first-served basis to anyTo customers that owns or leases
a customer-operated renewable generating facility or, as defined in Utah Code 54-2-1(16)(d), an
eligible customer that purchases electricity from an independent energy producer operating a
renewable generating facility, with a capacity of not more than twenty-five (25) kilowatts for a
residential facility and two (2) megawatts for a non-residential facility that is located on, or adjacent
to, the customers’ premises, is interconnected and operates in parallel with the Company’s existing
distribution facilities, is intended primarily to offset part or all of the customer’s own electrical
requirements, is controlled by an inverter capable of enabling safe and efficient synchronous coupling
with Rocky Mountain Power’s electrical system, and has executed an Interconnection Agreement for
Net Metering Service with the Company. This schedule is offered in compliance with Utah Code
Ann. § 54-15-101 to 106 and R746-312.
DEFINITIONS: Net Metering means measuring the difference between the electricity
supplied by the Company and the electricity generated by an eligible customer-generator and fed
back to the electric grid over the applicable billing period.
An Inverter means a device that converts direct current power into alternating current power
that is compatible with power generated by the Company.
Annualized Billing Period means the period commencing after the regularly scheduled meter
reading for the month of March or in the case of new Schedule 135 service the date that the customer
first takes service from Schedule 135 and ending on the regularly scheduled meter reading for the
month of March.
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 13-035184Advice No. 16-13
FILED: September November 95, 20142016
EFFECTIVE: September December 1041, 20142016
P.S.C.U. No. 43
Original Sheet No. 135.2
ELECTRIC SERVICE SCHEDULE NO. 95 - Continued
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 13-035184Advice No. 16-13
FILED: September November 95,
20142016
EFFECTIVE: September December 1041, 20142016
P.S.C.U. No. 50
Original Sheet No. 135A.1
ROCKY MOUNTAIN POWER
ELECTRIC SERVICE SCHEDULE NO. 135A
STATE OF UTAH
______________
Net Metering – Transition Service
______________
AVAILABILITY: At any point on the Company's interconnected system. Customers will
be subject to all changes to net metering service including changes to credits, charges or rate
structures offered herein and in related tariffs resulting from the final determination under Utah Code
Ann. § 54-15-105.1 which may include, without limitation, a transfer from this tariff to all new
applicable service schedules approved by the Commission.
APPLICATION: On a first-come, first-served basis to any customer that owns or leases a
customer-operated renewable generating facility or, as defined in Utah Code 54-2-1(16)(d), an
eligible customer that purchases electricity from an independent energy producer operating a
renewable generating facility, with a capacity of not more than twenty-five (25) kilowatts for a
residential facility and two (2) megawatts for a non-residential facility that is located on, or adjacent
to, the customers’ premises, is interconnected and operates in parallel with the Company’s existing
distribution facilities, is intended primarily to offset part or all of the customer’s own electrical
requirements, is controlled by an inverter capable of enabling safe and efficient synchronous coupling
with Rocky Mountain Power’s electrical system, and has executed an Interconnection Agreement for
Net Metering Service with the Company. This schedule is offered in compliance with Utah Code
Ann. § 54-15-101 to 106 and R746-312.
DEFINITIONS: Net Metering means measuring the difference between the electricity
supplied by the Company and the electricity generated by an eligible customer-generator and fed
back to the electric grid over the applicable billing period.
An Inverter means a device that converts direct current power into alternating current power
that is compatible with power generated by the Company.
Annualized Billing Period means the period commencing after the regularly scheduled meter
reading for the month of March or in the case of new Schedule 135A service the date that the customer
first takes service from Schedule 135A and ending on the regularly scheduled meter reading for the
month of March.
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 13-035184Advice No. 16-13
FILED: September 5November 9, 20142016
EFFECTIVE: September 1December 410, 20142016
P.S.C.U. No. 43
Original Sheet No. 135.2
ELECTRIC SERVICE SCHEDULE NO. 95 - Continued
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 13-035184Advice No. 16-13
FILED: September 5November 9,
20142016
EFFECTIVE: September 1December 410, 20142016
P.S.C.U. No. 50
Original Sheet No. 135A.2
ELECTRIC SERVICE SCHEDULE NO. 135A - Continued
DEFINITIONS (continued)
Residential Customer means any customer that receives electric service under Electric Service
Schedules 1, 2 or 3.
Small Non-Residential Customer means any customer that receives electric service under
Electric Service Schedules 15 or 23.
Large Non-Residential Customer means any customer that receives electric service under
Electric Service Schedules 6, 6A, 6B, 8 or 10.
Renewable Generating Facility means a facility that uses energy derived from one of the
following:
a) solar photovoltaics;
b) solar thermal energy;
c) wind energy;
d) hydrogen;
e) organic waste;
f) hydroelectric energy;
g) waste gas and waste heat capture or recovery;
h) biomass and biomass byproducts, except for the combustion of wood that has been
treated with chemical preservatives such as creosote, pentachlorophenol, chromated
copper arsenate, or municipal waste in a solid form;
i) forest or rangeland woody debris from harvesting or thinning conducted to improve
forest or rangeland ecological health and to reduce wildfire risk;
j) agricultural residues;
k) dedicated energy crops;
l) landfill gas or biogas produced from organic matter, wastewater, anaerobic disgesters,
or municipal solid waste; or
m) geothermal energy.
MONTHLY BILL: The Electric Service Charge shall be computed in accordance with the
Monthly Billing in the applicable standard service tariff. Regardless of whether the Customer provides
excess net generation during the month, the Customer shall be billed the minimum monthly amount
from the applicable standard service tariff.
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 13-035184Advice No. 16-13
FILED: September 5November 9,
20142016
1December 410, 20142016
EFFECTIVE: September
P.S.C.U. No. 50
Original Sheet No. 135A.2
ELECTRIC SERVICE SCHEDULE NO. 135A - Continued
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 13-035184Advice No. 16-13
FILED: September 5November 9,
20142016
1December 410, 20142016
EFFECTIVE: September
P.S.C.U. No. 50
Original Sheet No. 135A.3
ELECTRIC SERVICE SCHEDULE NO. 135A - Continued
SPECIAL CONDITIONS:
1. If the energy supplied to the Company is less than the energy purchased from the Company, the
prices specified in the Energy Charge section of the Monthly Billing of the applicable standard
service tariff shall be applied to the positive balance owed to the Company.
2. If the energy supplied to the Company is greater than the energy supplied by the Company, the
Customer shall be billed for the appropriate monthly charges and shall be credited for such Net
Metering Energy as follows:
A. Residential and Small Non-Residential Customer shall be credited for such net energy with
a cumulative kilowatt-hour credit. The credit will be deducted from the customer’s kilowatthour usage on the customer’s next monthly bill thus offsetting the customer’s next monthly
bill at the full retail rate of the customer’s rate schedule.
B. A Large Non-Residential Customer, at the time of initial enrollment under this tariff , must
elect a compensation method to receive cumulative credits for the upcoming Annualized
Billing Period from one of the following options:
(i)
An Average Energy Price for the applicable calendar year according to the
Volumetric Non-Levelized Prices shown in Schedule 37 as determined by the
following formula: 0.38 x Winter On-Peak Energy Price + 0.19 x Summer OnPeak Energy Price + 0.29 x Winter Off-Peak Energy Price + 0.14 x Summer
Off-Peak Energy Price; or
(ii)
A Seasonally Differentiated Energy Price for the applicable calendar year
according to the Non-Levelized Prices shown in Schedule 37 as determined by
the following formula: 0.57 x Summer On-Peak Energy Price + 0.43 x Summer
Off-Peak Energy Price for the regularly scheduled meter readings from June
through September and 0.57 x Winter On-Peak Energy Price + 0.43 x Winter
Off-Peak Energy Price for the regularly scheduled meter readings from October
through May; or
(iii)
An average retail rate for the Electric Service Schedule applicable to the net
metering customer as calculated from the previous year’s Federal Energy
Regulation Commission Form No. 1 to be determined and available by July 1,
2009, and by July 1st of every subsequent year. Current average retail rates are
listed below:
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 13-035184Advice No. 16-13
FILED: September 5November 9, 20142016
EFFECTIVE: September 1December 410, 20142016
P.S.C.U. No. 50
Original Sheet No. 135A.3
ELECTRIC SERVICE SCHEDULE NO. 135A - Continued
(continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 13-035184Advice No. 16-13
FILED: September 5November 9, 20142016
EFFECTIVE: September 1December 410, 20142016
Second Revision of Sheet No. 135.4
OriginalCanceling First Revision of Sheet No. 135A.4
P.S.C.U. No. 50
ELECTRIC SERVICE SCHEDULE NO. 135A - Continued
SPECIAL CONDITIONS (continued)
Schedule 6:
Schedule 6A:
Schedule 6B:
Schedule 8:
Schedule 10:
8. 4498¢ per kWh
11.7871¢ per kWh
10.8914¢ per kWh
7.5210¢ per kWh
7.5619¢ per kWh
A Large Non-Residential Customer may change the compensation method once per year at
the beginning of each Annualized Billing Period. The Company must receive written
change notification of any change within sixty (60) days of the beginning of the Annualized
Billing Period.
3. All unused credits accumulated by the customer-generator, except Customers taking service
under Electric Service Schedule No. 10, shall expire with the regularly scheduled meter reading
for the month of March of each year. For Customers taking service under Electric Service
Schedule No. 10, all unused credits accumulated by the customer-generator shall expire with
the regularly scheduled meter reading for the month of October of each year.
4. Upon the customer-generator’s request and within thirty (30) days notice to the Company, the
Company shall aggregate for billing purposes the meter to which the net metering facility is
physically attached (“designated meter”) with one or more meters (“additional meter”) if the
following conditions are met:
(i) the additional meter is located on or adjacent to premises of the customer-generator;
(ii) the additional meter is used to measure only electricity used for the customergenerator’s requirements;
(iii) the designated meter and additional meter are subject to the same rate schedule; and
(iv) the designated meter and the additional meter are served by the same primary
feeder.
At the time of notice to the Company, the customer-generator must identify the specific meters
and designate a rank order for the additional meters to which net metering credits are to be
applied.
5. The customer-generator shall provide at the customer’s expense all equipment necessary to
meet applicable local and national standards regarding electrical and fire safety, power quality,
and interconnection requirements established by the National Electrical Code, the Institute of
Electrical and Electronics Engineers, and Underwriters Laboratories.
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-0613
FILED: May 27November 9, 2016
2016
EFFECTIVE: July 1December 410,
Second Revision of Sheet No. 135.4
OriginalCanceling First Revision of Sheet No. 135A.4
P.S.C.U. No. 50
ELECTRIC SERVICE SCHEDULE NO. 135A - Continued
(Continued)
Issued by authority of Report and Order of the Public Service Commission of Utah in Advice No. 16-0613
FILED: May 27November 9, 2016
2016
EFFECTIVE: July 1December 410,
P.S.C.U. No. 50
Original Sheet No. 135A.5
ELECTRIC SERVICE SCHEDULE NO. 135A - Continued
6. For customer-generators generation systems of 10 kilowatts or less that are inverter-based, a a
disconnect switch is not required. For all other generation systems, the customer-generator must
install and maintain a manual disconnect switch that will disconnect the generating facility from
the Company’s distribution system. The disconnect switch must be a lockable, load-break
switch that plainly indicates whether it is in the open or closed position. Except as provided in
R746-312-4(2) (a) (ii), the disconnect switch must be readily accessible to the Company at all
times and located within ten (10) feet of the Company’s meter.
7. The Company shall not be liable directly or indirectly for permitting or continuing to allow an
attachment of a net metering facility, or for the acts or omissions of the customer-generator that
cause loss or injury, including death, to any third party.
8. The Company may test and inspect an interconnection at times that the electrical corporation
considers necessary to ensure the safety of electrical workers and to preserve the integrity of
the electric power grid.
9. Unless otherwise agreed to by a separate contract, the owner of the renewable energy facility
retains ownership of the non-energy attributes associated with electricity the facility generates.
ELECTRIC SERVICE REGULATIONS: Service under this Schedule will be in accordance
with the terms of the Electric Service Agreement between the Customer and the Company. The Electric
Service Regulations of the Company on file with and approved by the Public Service Commission of
the State of Utah, including future applicable amendments, will be considered as forming a part of and
incorporated in said Agreement.
Issued by authority of Report and Order of the Public Service Commission of Utah in Docket No. 13-035184Advice No. 16-13
FILED: September 5November 9,
20142016
1December 410, 20142016
EFFECTIVE: September
EXHIBIT A
Redlined
Rocky Mountain Power Interconnection
and Net Metering Agreements
Utah Forms
Ver. 4 - Level 1, Level 2, and Level 3
We appreciate your interest in Rocky Mountain Power’s net metering program. Before
purchasing any net metering equipment, we recommend you review the requirements for
interconnecting a net metering system to Rocky Mountain Power’s electrical distribution
system. The requirements are found in the Interconnection Agreement.
To complete the process for a net metering interconnection, please follow the steps below:
1. Complete and submit the following to Rocky Mountain Power:
 Interconnection Agreement including the Application for Net Metering
Interconnection
 The inverter specification sheet
 For systems larger than 10 kW, a simple one-line diagram showing
• The location of Rocky Mountain Power’s meter
• The location of the disconnect switch
2. Rocky Mountain Power will review your agreement and application and send you a
written notification of approval either by mail or e-mail
3. Install the net metering system after you receive the written approval of your
Interconnection Agreement and Application for Net Metering from Rocky Mountain
Power
4. Obtain an inspection of your net metering system by the local city or county electrical
inspector
5. Submit the electrical inspector’s approval to Rocky Mountain Power
6. Turn on your net metering system after Rocky Mountain Power provides you written
notification the interconnection work has been completed and the net meter installed
Return completed documents to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, Utah 84125-0308
Or Email to:
[email protected]
Thank you for your interest in the net metering program. If you have questions, please call us
toll free at 1-888-221-7070 and ask for a net metering specialist.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 1 of 21
Service ID#:___________
Request #: ___________
INTERCONNECTION AND NET METERING SERVICE AGREEMENT FOR NET
METERING FACILITY LEVEL 1 INTERCONNECTION
25 KW NAMEPLATE CAPACITY OR SMALLER
This Interconnection and Net Metering Service Agreement (“Agreement”) is made and
entered into this ___ day of _____________, 20___ by and between
____________________________, an electric customer (“Customer”), and PacifiCorp, dba
Rocky Mountain Power (“Rocky Mountain Power”), a Corporation organized and existing
under the laws of the State of Oregon. Customer and Rocky Mountain Power each may be
referred to as a “Party”, or collectively as the “Parties”.
Recitals:
Whereas, Customer has installed or intends to install a Net Metering Facility qualifying
for “Net Metering,” Utah Rate Schedule No. 135A (“Schedule 135A”), as given in Rocky
Mountain Power’s currently effective tariff as filed with the Public Service Commission of
Utah (“Commission”), on or adjacent to Customer’s premises located at
____________________________, Utah, for the purpose of generating electric energy;
Whereas, the Net Metering rate schedule may be amended from time to time, and the
Public Service Commission may alter the charge, credit, and ratemaking structure applicable to
Net Metering customers pursuant to Utah Code § 54-15-105.1;
Whereas, Customer represents to Rocky Mountain Power that Customer either owns or
leases its Net Metering Facility qualifying for Schedule 135A, or meets the exemption
requirements set forth in Utah Code § 54-2-1.16(d) because it is a county, municipality, city,
town, other political subdivision, local district, special service district, state institution of higher
education, school district, charter school, or any entity within the state system of public
education; or an entity qualifying as a charitable organization under 26 U.S.C. Sec. 501(c)(3)
operated for religious, charitable, or educational purposes that is exempt from federal income
tax and able to demonstrate its tax-exempt status;
Whereas, Customer desires to interconnect the Net Metering Facility with Rocky
Mountain Power’s distribution system consistent with the Application completed by on
_____________ ____, 20___,Customer as described in Appendix A (“Application”) of this
Agreement; and
Whereas, Customer, using its Net Metering Facility, intends to offset part or all of its
electrical requirements supplied by Rocky Mountain Power.
Now, therefore, in consideration of and subject to the mutual covenants contained
herein, the Parties agree as follows:
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 2 of 21
Article 1.
Scope and Limitations of Agreement
1.1
Scope
The Agreement shall be used for all approved Level 1 Applications according to the
procedures set forth in Utah Rule 746-312 (“Rule”), as may be amended from time to
time. The Rule can be viewed at www.psc.utah.gov. The Agreement establishes
standard terms and conditions approved by the Commission under which a Level 1 Net
Metering Facility as described in Appendix A with an electric nameplate capacity of 25
kW or smaller will interconnect to, and operate in parallel with, Rocky Mountain
Power’s system.
1.2
Definitions
Terms with initial capitalization, when used in this Agreement, shall have the meanings
indicated or as specified in the Rule Section R746-312-2 and, to the extent this
Agreement conflicts with the Rule, the Rule shall take precedence.
1.3
Other Agreements
Nothing in this Agreement is intended to affect any other agreement between Rocky
Mountain Power and Customer or any other Interconnection Customer. However, in the
event that the provisions of the Agreement are in conflict with the provisions of any
Rocky Mountain Power Tariff, the Rocky Mountain Power Tariff shall control.
1.4
Responsibilities of the Parties
1.4.1
The Parties shall perform all obligations of the Agreement in accordance with all
applicable laws and regulations.
1.4.2
Customer will construct, operate, test, and maintain its Net Metering Facility in
accordance with the Agreement, IEEE standards (available at the following link:
http://standards.ieee.org/index.html), National Electric Code Standards
(available for purchase at http://standards.ieee.org/faqs/NESCFAQ.html#q8),
Utah state building codes (available at the following link:
http://www.dopl.utah.gov/programs/ubc/), the Rule, and other applicable
standards required by the Commission, as may be amended from time to time.
1.4.3
Each Party shall be responsible for the safe installation, maintenance, repair and
condition of their respective lines and equipment on their respective sides of the
Point of Common Coupling. Each Party shall provide interconnection facilities
that adequately protect the other Party’s facilities, personnel and other persons
from damage and injury. The allocation of responsibility for the design,
installation, operation and maintenance of interconnection facilities is prescribed
in the Rule, including but not necessarily limited to R746-312-4.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 3 of 21
1.4.4
1.5
Customer is responsible for protecting the generating equipment, inverters,
protective devices, and other system components from damage from the normal
and abnormal conditions and operations that occur on Rocky Mountain Power’s
system in delivering and restoring power; and is responsible for ensuring that the
Net Metering Facility equipment is inspected, maintained, and tested in
accordance with the manufacturer’s instructions to ensure that it is operating
correctly and safely.
Parallel Operation and Maintenance Obligations
Once the Net Metering Facility has been authorized to commence parallel operation by
an approved application and execution of this Agreement, Customer will abide by all
written provisions for operations and maintenance as required by the Rule and Rocky
Mountain Power’s tariffs, including but not necessarily limited to R746-312-4 and
Schedule 135A or its successor tariff(s).
1.6
Metering
Rocky Mountain Power shall install, own and maintain, at its sole expense, a kilowatthour meter(s) and associated equipment to measure the flow of energy in each direction,
unless otherwise authorized by the Commission. Customer hereby consents to the
installation of and operation by Rocky Mountain Power, at Rocky Mountain Power’s
expense, one or more additional meters to monitor the flow of electricity in each
direction. Such meter(s) shall be located on the premises of Customer.
1.7
1.8
Net Metering Facility Requirements, Installation, Operation
1.7.1
Customer’s Net Metering Facility must meet the requirements set forth in,
including but not necessarily limited to, the Rule, R746-312-4 and Schedule
135A or its successor tariff(s). This also applies to installation and operation of
the Net Metering Facility.
1.7.2
Customer is responsible for all costs associated with its Net Metering Facility.
Anticipated Start Date
Customer must include an anticipated start date for operation of its Net Metering
Facility in the Application. After receiving notice that the Application has been
approved, Customer must execute and return this Agreement with a copy of the
approved electric inspection to Rocky Mountain Power. Upon satisfactory completion
of all reviews and inspections of the Net Metering Facility, Customer must notify
Rocky Mountain Power at least ten (10) business days prior to starting operation of the
Net Metering Facility, either through submission of an executed Agreement or through
separate written notice. Customer shall not commence parallel operation of the Net
Metering Facility until Rocky Mountain Power executes this Agreement, installs the net
meter and notifies Customer that the Net Metering Facility is interconnected.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 4 of 21
1.9
Net Metering Facility Inspection
1.9.1
Building Code Inspection
Prior to operation in parallel with Rocky Mountain Power’s system, the Net
Metering Facility must be inspected by a local building code official to ensure
compliance with applicable local codes.
1.9.2
Inspection by Rocky Mountain Power
Rocky Mountain Power may inspect the Net Metering Facility and its
component equipment, and the documents necessary to ensure compliance with
the Rule. Customer shall notify Rocky Mountain Power prior to placing the Net
Metering Facility in service, and Rocky Mountain Power shall have the right to
have personnel present on the in-service date. If the Net Metering Facility is
subsequently modified in order to increase its gross power rating, Customer
must notify Rocky Mountain Power by submitting a new application specifying
the modifications in accordance with the level of review required for that
application.
1.10
Power Quality
Customer will design its Net Metering Facility to maintain a composite power delivery
at continuous rated power output at the Point of Common Coupling that meets the
requirements set forth in IEEE 1547, in accordance with the Rule, R746-312-4.
1.11
Net Metering Facility Testing and Maintenance
Customer shall conduct maintenance and testing on its Net Metering Facilities as set
forth in the Rule, including but not necessarily limited to R746-312-14.
1.11.1 Customer shall conduct any manufacturer-recommended testing or maintenance
at its expense.
1.11.2 Customer shall conduct any post-installation testing, at its expense, necessary to
ensure compliance with IEEE standards as set forth in the Rule or to ensure
safety. This includes replacing a major equipment component that is different
from the originally installed model.
1.11.3 When Customer performs maintenance or testing in accordance with the Rule, it
must retain written records documenting the maintenance and results of the
testing for three (3) years.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 5 of 21
1.12
1.11.4 Rocky Mountain Power shall have the right to inspect Customer’s facility after
interconnection approval is granted, at reasonable hours and with reasonable
prior notice to Customer. If Rocky Mountain Power discovers that the Net
Metering Facility is not in compliance with the Rule, Rocky Mountain Power
may require Customer to disconnect the Net Metering Facility until compliance
is achieved.
Removal of Facility
Customer shall immediately notify Rocky Mountain Power if Customer removes or
ceases to operate the Net Metering Facility.
Article 2.
2.1
Review, Inspection, Testing, Disconnect Switch and Signage, and Right of
Access
Review
After determining Customer’s interconnection request is complete, in accordance with
the Rule, R746-312-8, Rocky Mountain Power will conduct a review of the proposed
interconnection using screens set forth in the Rule, R746-312-7. Rocky Mountain
Power will conduct such review within fifteen (15) days after notifying Customer that
the interconnection request is complete and will notify Customer either that the Net
Metering Facility meets all applicable criteria and the interconnection request is
approved, or the Net Metering Facility has failed to meet one or more of the applicable
criteria, the reason for failure, and the interconnection request is denied under Level 1
review. If the interconnection request is denied, Customer may resubmit the application
under the Level 2 or Level 3 review process.
2.2
Equipment Testing and Inspection
Customer must notify Rocky Mountain Power of the anticipated testing and inspection
date of the Net Metering Facility at least ten (10) business days prior to testing, either
through submittal of the Agreement, a notice of completion, or in a separate notice.
Within ten (10) business days after receipt of such required documentation, Rocky
Mountain Power will inspect the Net Metering Facility, set the new meter if required,
approve the interconnection and may arrange a witness test as set forth in the Rule,
R746-312-8(4). Rocky Mountain Power and Customer will select a date by mutual
agreement for the witness test.
Rocky Mountain Power will test and inspect the Net Metering Facility and
Interconnection Facilities prior to interconnection in accordance with IEEE Standards as
provided for in the Rule, R746-312-4. Customer shall not begin operation of its Net
Metering Facility until after inspection and testing is completed.
If a witness test is conducted and is not satisfactory, Customer must resolve any
deficiencies within thirty (30) business days or other time period as mutually agreed by
the Parties.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 6 of 21
2.3
Disconnect Switch and Signage
Customer shall comply with the Rule regarding disconnect switches, R746-312-4. The
disconnect switch may be located more than 10 feet from the public utility meter if
permanent instructions in letters of appropriate size are posted at the meter indicating
the precise location of the disconnect switch. Rocky Mountain Power must approve in
writing the location of the disconnect switch prior to the installation of the Net Metering
Facility.
2.4
Right of Access
As provided in the Rule, R746-312-4, Rocky Mountain Power shall have access to any
required disconnect switch at the Net Metering Facility at all times. Rocky Mountain
Power will provide reasonable notice to Customer when possible prior to using the right
of access. Additionally, as provided in Rocky Mountain Power Utah Rule 6, or its
successor tariff, Rocky Mountain Power shall have access to the metering equipment.
Article 3.
3.1
Effective Date, Term, Termination and Disconnection
Effective Date
The Agreement shall become effective upon execution by the Parties.
3.2
Term of Agreement
The Agreement will become effective on the Effective Date and will remain in effect
unless terminated in accordance with provisions of this Agreement, or Order by the
Commission.
3.3
Termination
No termination will become effective until the Parties have complied with all applicable
laws and clauses of this Agreement applicable to such termination.
3.3.1
Customer may terminate this Agreement at any time by giving Rocky Mountain
Power twenty (20) business days written notice.
3.3.2
Either Party may terminate this Agreement after default pursuant to Article 6.4
of this Agreement.
3.3.3
The Commission may Order termination of this Agreement.
3.3.4
Upon termination of this Agreement, Customer shall disconnect the Net
Metering Facility from Rocky Mountain Power’s system. The termination of
this Agreement will not relieve either Party of its liabilities and obligations,
owed or continuing at the time of termination.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 7 of 21
3.4
3.3.5
If Customer removes the Net Metering equipment at the Net Metering Facility
or ceases to operate its Net Metering Facility at the premises listed in Recital 1
above, this Agreement will be immediately terminated.
3.3.6
The provisions of this Article shall survive termination or expiration of this
Agreement.
Temporary Disconnection
3.4.1
Rocky Mountain Power may temporarily disconnect the Net Metering Facility
from Rocky Mountain Power’s system for so long as reasonably necessary in the
event one or more of the following conditions or events occurs:
3.4.1.1 Emergencies or to address maintenance requirements for Rocky Mountain
Power’s system.
3.4.1.2 Hazardous conditions existing on Rocky Mountain Power’s system which
may affect the safety of the general public or Rocky Mountain Power
employees due to the operation of the Net Metering Facility or protective
equipment as determined by Rocky Mountain Power.
3.4.1.3 Adverse electrical effects on the electrical equipment of Rocky Mountain
Power’s other electric customers caused by the Net Metering Facility as
determined by Rocky Mountain Power.
3.4.2
In the event that no disconnect switch is installed, Rocky Mountain Power may
physically disconnect all service to the Customer and/or all service to the
premises where the Net Metering Facility is located.
3.4.3
To the extent practicable, Rocky Mountain Power will give prior notice of any
temporary disconnection of the Net Metering Facility. If Rocky Mountain Power
is unable to give prior notice, Rocky Mountain Power will provide notice
including an explanation of the condition necessitating the disconnection at the
time of disconnection
3.4.4
Under emergency conditions, Rocky Mountain Power or Customer may
immediately suspend interconnection service and temporarily disconnect the Net
Metering Facility. Rocky Mountain Power shall notify Customer promptly when
Rocky Mountain Power becomes aware of an emergency condition that may
reasonably be expected to affect the Net Metering Facility operation. Customer
shall notify Rocky Mountain Power promptly when Customer becomes aware of
an emergency condition that may reasonably be expected to affect Rocky
Mountain Power’s system. To the extent the information is known, the
notification shall describe the emergency condition, the extent of any damage or
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 8 of 21
deficiency, the expected effect on the operation of both Parties’ facilities and
operations, the anticipated duration, and the necessary corrective action.
3.4.5
Customer shall make reasonable efforts to provide notice of interruption of Net
Metering Facility operation for safety and/or reliability reasons prior to the
interruption unless an emergency occurs. Emergency interruptions or temporary
terminations are subject to Section 3.4.4 above.
3.4.6
Rocky Mountain Power shall use reasonable efforts to provide Customer with
prior notice of forced outages to effect immediate repairs to Rocky Mountain
Power’s system. If prior notice is not given, Rocky Mountain Power, shall, upon
request, provide Customer written documentation after the fact explaining the
circumstances of the disconnection.
3.4.7
Customer must provide Rocky Mountain Power notice and obtain Rocky
Mountain Power’s written approval before Customer may modify its Net
Metering Facility in order to increase the electric output of the Net Metering
Facility. If Customer makes any material change without prior written
authorization of Rocky Mountain Power, Rocky Mountain Power will have the
right to temporarily disconnect the Net Metering Facility until Rocky Mountain
Power has had an opportunity to review the change(s) made to determine
whether they are acceptable. If system modifications or other equipment
installations are deemed necessary by Rocky Mountain Power to accommodate
the modified Net Metering Facility, Customer shall submit the appropriate net
metering application at that time.
3.4.8
The Parties shall cooperate with each other to restore the Net Metering Facility,
interconnection facilities, and Rocky Mountain Power’s system to their normal
operating state as soon as reasonably practicable following any disconnection
pursuant to Section 3.4.
Article 4.
Cost Responsibility
Customer shall bear the cost of any facilities, equipment, modifications and upgrades as
required by the Rule. Customer shall also be responsible for all reasonable expenses, including
overheads, associated with owning, operating, maintaining, repairing, and replacing its Net
Metering Facility.
Article 5.
5.1
Billing
Monthly Billing
The electric service charge shall be computed in accordance with the monthly billing in
the applicable standard currently applicable service tariff applicable to Net Metering
customers. Customer will be compensated for net excess energy in accordance with
Schedule 135A or its successor tariff(s). Customer will be transitioned to any successor
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 9 of 21
tariff immediately upon approval of that tariff by the Public Service Commission and
will be subject to any charge, credit, or ratemaking structure implemented therein.
5.2
Special Conditions
Customer must comply with the special conditions found in Schedule 135A or its
successor tariff(s).
5.3
Aggregating Meters
Aggregating Meters is allowed if certain conditions are met under the Rule, R746-3125.
Customer
designates
the
following
meters
for
aggregation:
_______________________. In the event that the Net Metering Facility supplies more
electricity to Rocky Mountain Power than the Customer uses from Rocky Mountain
Power, Rocky Mountain Power will apply any credits to the next monthly bill in
accordance with Utah Code § 54-15-104 and the Rule, R746-312-15. Customer shall
designate the order in which to apply any credits in accordance with the Rule. <<If
customer does not want to aggregate, insert “N\A” in the space above.>>
Article 6.
6.1
Assignment, Liability, Indemnity, Consequential Damages and Default
Assignment
This Agreement may be assigned by either Party with the consent of the other Party. A
Party’s consent to an assignment may not be unreasonably withheld. The assigning
Party must give the non-assigning Party written notice of the assignment at least fifteen
days (15) before the effective date of the assignment. The non-assigning Party must
submit its objection to the assignment, if any, to the assigning Party in writing at least 5
business days before the effective date of the assignment. If a written objection is not
received within that time period, the non-assigning party is deemed to consent to the
assignment.
6.1.1
Exceptions to Consent Requirement
6.1.1.1 Either Party may assign the Agreement without the consent of the other
Party to any affiliate (including a merger or acquisition of the Party with
another entity) of the assigning Party with an equal or greater credit
rating and with the legal authority and operational ability to satisfy the
obligations of the assigning Party under this Agreement.
6.1.1.2 Customer is entitled to assign the Agreement without the consent of
Rocky Mountain Power for collateral security purposes to aid in
obtaining financing for the Net Metering Facility.
6.1.1.3 For small generator systems that are integrated into a building facility,
the sale of the building or property will result in the automatic
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 10 of 21
assignment of this Agreement to the new owner who will be responsible
for complying with the terms and conditions of this Agreement.
6.1.2
6.2
Any attempted assignment that violates this Article is void and ineffective.
Assignment does not change or eliminate a Party’s obligations under this
Agreement. An assignee is responsible for meeting the same obligations as the
assigning Party.
Limitation of Liability and Consequential Damages
Each Party’s liability to the other Party for any loss, cost, claim, injury, liability, or
expense, including reasonable attorney’s fees, relating to or arising from any act or
omission in its performance of this Agreement, is limited to the amount of direct
damage actually incurred. Neither Party is liable to the other Party for any indirect,
special, consequential, or punitive damages.
6.3
Indemnification
Customer shall hold harmless and indemnify Rocky Mountain Power for all loss to third
parties resulting from the operation of the Net Metering Facility, except when the loss
occurs due to the negligent actions of Rocky Mountain Power.
Rocky Mountain Power shall hold harmless and indemnify Customer for all loss to third
parties resulting from the operation of Rocky Mountain Power’s system, except where
the loss occurs due to the negligent actions of Customer.
6.4
Force Majeure
6.4.1
As used in this Agreement, a Force Majeure Event shall mean “any act of God,
labor disturbance, act of the public enemy, war, acts of terrorism, insurrection,
riot, fire, storm or flood, explosion, breakage or accident to machinery or
equipment through no direct, indirect, or contributory act of a Party, any order,
regulation, or restriction imposed by governmental, military or lawfully
established civilian authorities, or any other cause beyond a Party’s control. A
Force Majeure Event does not include an act of negligence or wrongdoing.”
6.4.2
If a Force Majeure Event prevents a Party from fulfilling any obligations under
this Agreement, the Party affected by the Force Majeure Event (“Affected
Party”) shall promptly notify the other Party of the existence of the Force
Majeure Event. The notification must specify in reasonable detail the
circumstances of the Force Majeure Event, its expected duration, and the steps
that the Affected Party is taking to mitigate the effects of the event on its
performance, and if the initial notification was verbal, it should be promptly
followed up with a written notification. The Affected Party shall keep the other
Party informed on a continuing basis of developments relating to the Force
Majeure Event until the event ends. The Affected Party will be entitled to
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 11 of 21
suspend or modify its performance of obligations under this Agreement (other
than the obligation to make payments) only to the extent that the effect of the
Force Majeure Event cannot be reasonably mitigated. The Affected Party will
use reasonable efforts to resume its performance as soon as possible. The Parties
shall immediately report to the Commission should a Force Majeure Event
prevent performance of an action required by Rule that the Rule does not permit
the Parties to mutually waive.
6.5
Default
6.5.1
A Party is in default if the Party fails to perform an obligation required under
this Agreement (other than the payment of money). A Party is not considered in
default of this agreement if the failure to perform an obligation is caused by an
act or omission of the other Party.
6.5.2
Upon a default, the non-defaulting Party must give written notice of the default
to the defaulting party. The defaulting party has sixty (60) calendar days from
the receipt of the written default notice to cure the default. If the default is not
capable of cure within the 60-day period, the defaulting Party must begin to cure
the default within twenty (20) calendar days after receipt of the written default
notice, and must continuously and diligently complete the cure within six (6)
months of the receipt of the notice.
6.5.3
If a default is not cured as provided in 6.5.2, then the non-defaulting Party is
entitled to terminate the Agreement by written notice at any time until cure
occurs. If the non-defaulting Party chooses to terminate this Agreement, the
termination provisions in Article 3.3 apply. Alternately, the non-defaulting Party
is entitled to seek dispute resolution with the Commission in lieu of termination.
Article 7.
Insurance
Additional liability insurance is not required as a part of the Agreement if the Net Metering
Facility is in compliance with the provisions of the Application approval, the Agreement and
the standards contained in Utah Code § 54-15-106.
Article 8.
Dispute Resolution
Nothing in this Article shall restrict the rights of any Party to file a Complaint with the
Commission under relevant provisions of the Rule, R746-312-3(5) and applicable state law.
Article 9.
9.1
Miscellaneous
Governing Law, Regulatory Authority, and Rules
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 12 of 21
The validity, interpretation, and enforcement of this Agreement is governed by the laws
of the State of Utah. If any provision of this Agreement conflicts with any applicable
provision, as may be amended from time to time, of the Utah Code (“Code”), Utah
Administrative Rules (“Rules”), or Rocky Mountain Power’s Tariffs (“Tariff”), then the
applicable provision of the Code, Rules, or Tariff controls. Rocky Mountain Power
must provide copies of the applicable provisions of the Code, Rules, and Tariff upon the
Customer’s request.
9.2
Amendment
Additions, deletions or changes to the standard terms and conditions of this Agreement
will not be permitted unless they are mutually agreed to by the Parties and permitted by
the Rule or permitted by the Commission for good cause shown. The Parties may
amend the Agreement by a written instrument duly executed by both Parties in
accordance with the provisions of the Rule, applicable Commission Orders and
provisions of the laws of the State of Utah.
9.3
No Third Party Beneficiaries
The Agreement is not intended to and does not create rights, remedies, or benefits of
any character whatsoever in favor of any persons, corporations, associations, or entities
other than the Parties, and the obligations herein assumed are solely for the use and
benefit of the Parties, or where permitted, their successors in interest and their assigns.
9.4
9.5
Waiver
9.4.1
The failure of a Party to the Agreement to insist, on any occasion, upon strict
performance of any provision of the Agreement, will not be considered a waiver
of any obligation, right, or duty of, or imposed upon, such Party.
9.4.2
The Parties may also agree to mutually waive a Section of this Agreement
without the Commission’s approval where the Rule so provides.
9.4.3
Any waiver at any time by either Party of its rights with respect to the
Agreement shall not be deemed a continuing waiver or a waiver with respect to
any other failure to comply with any other obligation, right, duty of the
Agreement. Termination or default of this Agreement for any reason by
Customer shall not constitute a waiver of the Customer’s legal rights to obtain
interconnection from Rocky Mountain Power. Any request for waiver of the
Agreement or any provisions thereof shall be provided in writing.
Entire Agreement
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 13 of 21
The Agreement, including any supplementary attachments that may be necessary,
constitutes the entire Agreement between the Parties with reference to the subject matter
hereof, and supersedes all prior and contemporaneous understandings or agreements,
oral or written, between the Parties with respect to the subject matter of the Agreement.
There are no other agreements, representations, warranties, or covenants that constitute
any part of the consideration for, or any condition to, either Party’s compliance with its
obligations under the Agreement.
9.6
Multiple Counterparts
This Agreement may be executed in one or more counterparts, whether electronically or
otherwise, each of which is deemed an original but all constitute one and the same
instrument.
9.7
No Partnership
The Agreement will not be interpreted or construed to create an association, joint
venture, agency relationship, or partnership between the Parties or to impose any
partnership obligation or partnership liability upon either Party. Neither Party shall have
any right, power or authority to enter into any agreement or undertaking for, or act on
behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other
Party.
9.8
Severability
If any provision or portion of the Agreement shall for any reason be held or adjudged to
be invalid or illegal or unenforceable by any court of competent jurisdiction or other
governmental authority, (1) such portion or provision shall be deemed separate and
independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable
the benefits to each Party that were affected by such ruling, and (3) the remainder of the
Agreement shall remain in full force and effect.
9.9
Subcontractors
Nothing in the Agreement shall prevent a Party from using the services of any
subcontractor, or designating a third party agent as the one responsible for a specific
obligation or act required in the Agreement (collectively subcontractors), as it deems
appropriate to perform its obligations under the Agreement; provided, however, that
each Party will require its subcontractors to comply with all applicable terms and
conditions of the Agreement in providing such services and each Party will remain
primarily liable to the other Party for the performance of the subcontractor.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 14 of 21
9.10
9.9.1
The creation of any subcontract relationship shall not relieve the hiring Party of
any of its obligations under the Agreement. The hiring Party shall by fully
responsible to the other Party for the acts or omissions of any subcontractor the
hiring Party hires as if no subcontract had been made. Any applicable obligation
imposed by the Agreement upon the hiring Party shall be equally binding upon,
and will be construed as having application to, any subcontractor of such Party.
9.9.2
The obligations under this Article will not be limited in any way by any
limitation of a subcontractor’s insurance.
Reservation of Rights
Rocky Mountain Power shall have the right to make a unilateral filing with the
Commission to modify this Agreement with respect to any rates, terms and conditions,
charges, classifications of service, rule, regulation or any other applicable provision of
the Federal Power Act and the Commission’s rules and regulations thereunder, and
Customer shall have the right to make a unilateral filing with the Commission to modify
this Agreement under any applicable provision of the Federal Power Act and the
Commission’s rules and regulations; provided that each Party shall have the right to
protest any such filing by the other Party and to participate fully in any proceeding
before the Commission in which such modifications may be considered. Nothing in this
Agreement shall limit the rights of the Parties, except to the extent that the Parties
otherwise agree as provided herein.
Article 10.
10.1
Notices and Records
General
Unless otherwise provided in the Agreement, any written notice, demand, or request
required or authorized in connection with the Agreement shall be deemed properly
given if delivered in person, delivered by recognized national courier service, sent by
first class mail, postage prepaid, or by electronic mail if an electronic mail address is
provided below, to the person specified below:
If to Customer:
Customer: ______________________________________________________
Attention: _____________________________________________________________
Address: ________________________________________________________________
City: ________________________________ State: _________________ Zip: ________
Phone: (____) ______________________ Fax: (____) ___________________________
Email: _________________________________________________________________
If to Rocky Mountain Power:
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 15 of 21
By Mail:
Rocky Mountain Power
Attention: Net Metering Group
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
Or
By email:
[email protected]
10.2
Changes to the Notice Information
Either Party may change this notice information by giving five (5) business days written
notice prior to the effective date of the change.
10.3
Records
Rocky Mountain Power will maintain a record of the Net Metering Agreement and
related Attachments, if any, for as long as the net metering arrangement is in place.
Rocky Mountain Power will provide a copy of these records to Customer within fifteen
(15) Business Days if a request is made in writing.
Article 11.
Signatures
IN WITNESSETH WHEREOF, the Parties have caused the Agreement to be executed by
their respective duly authorized representatives.
For the Customer:
By: ______________________________________________
Name: ____________________________________________
Title: _____________________________________________
Date: _____________________________________________
For Rocky Mountain Power:
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 16 of 21
By: ______________________________________________
Name: ____________________________________________
Title: _____________________________________________
Date: _____________________________________________
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 17 of 21
APPENDIX A
ROCKY MOUNTAIN POWER UTAH NET METERING APPLICATION
LEVEL 1 REVIEW
INVERTER BASED SYSTEMS, 25 KW OR SMALLER
Section 1: For Rocky Mountain Power Use Only
Customer Name: ______________________________________________________________________
Service Address: ______________________________________________________________________
City, State, Zip: _______________________________________________________________________
Customer Account No. & Request No.: ____________________________________________________
Section 2: To Be Completed By Customer
A. Applicant Information
Name: _____________________________________________________________________
Mailing Address: ____________________________________________________________
City: ___________________________________State: _________ Zip Code: ____________
Site Street Address (if different from above): ______________________________________
City: ___________________________________State: __________ Zip Code: ___________
Daytime Phone: (_____) _____________________ Fax: (_____) ______________________
Email: _____________________________________________________________________
B. System Information
System Type:
Solar
Wind
Hydro
Other (Specify): ___________________
Generation Nameplate Capacity: _____ kW (Combine DC total of wind turbines, solar panels, etc)
Inverter Controlled:
Yes
No
Inverter Manufacturer: __________ Model: _______ Number of Inverters: ___ Rating: ____ kW
Manufacturer Nameplate Inverter Total AC Capacity Rating: _________ kW
Inverter(s):
Single Phase
Three Phase
Multiple Single Phase Connected on Polyphase (three phase) system (Attach Inverter and Panel Technical Specifications Sheets)
Type of Service:
Single Phase
Three Phase
If Three Phase:
120/208 Volts, 4 wire 120/240 Volts, 4 wire 277/480 Volts, 4 wire
Other (Please
Specify Voltage and Number of Service Wires): _______________________________________
Meets IEEE standard 1547 & UL Subject 1741 requirements as specified in Rule:
Yes
No
Please note: A disconnect switch is not required for an inverter-based facility with a name plate
rating of not more than 10 kW.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 18 of 21
Manual disconnect required:
Yes
No
Will the net metering facility interconnect to a switchgear?
Yes
No
Net metering facility available fault duty at the point of common coupling:__________________
For other service types, the net metering facility must not impact the Customer’s service
conductors by more than 10 kW. If a disconnect switch is installed, Customer to provide a simple
one-line diagram that shows the location of the disconnect switch and Rocky Mountain Power
meter.
Customer must post metal or plastic engraved signage indicating on-site generation in accordance
with National Electric Code. The signage must be permanent and located adjacent to the meter
base and disconnect switch noting “Parallel Generation on Site” and identifying the manual
disconnect switch with the words “Manual Disconnect for Parallel Generation.”____ (Initial Here)
Electrical Inspection approval date (attach copy or provide to utility when obtained):__________
Anticipated Operational Date of Net Metering Facilities: ________________________________
C. Additional Information
1. An equipment package will be considered certified for interconnected operation if it has been
submitted by a manufacturer to a nationally recognized testing and certification laboratory,
and has been tested and listed by the laboratory for continuous interactive operation with an
electric distribution system in compliance with the applicable IEEE and UL 1741 standards in
the Rule.
2. If the equipment package has been tested and listed as an integrated package, which includes
a generator or other electric source, the equipment package will be deemed certified, and
Rocky Mountain Power will not require any further design review, testing or additional
information.
3. If the equipment package includes only the interface components (switchgears, inverters, or
other interface devices), an interconnection applicant must show that the generator or other
electric source being utilized with the equipment package is compatible with the equipment
package and consistent with the testing and listing specified for the package. If the generator
or electric source being utilized with the equipment package is consistent with the testing and
listing performed by the nationally recognized testing and certification laboratory, the
equipment package will be deemed certified and Rocky Mountain Power will not require
further design review, testing or additional equipment.
4. A net metering facility must be equipped with metering equipment that can measure the flow
of electricity in both directions, comply with ANSI C12.1 standards and Utah Administrative
Rule R746-312. Rocky Mountain Power will install the required metering equipment at
Rocky Mountain Power’s expense.
5. Rocky Mountain Power will not be responsible for the cost of determining the rating of
equipment owned by the customer-generator or of equipment owned by other local customers.
6. Customer may operate the Net Metering Facility temporarily for testing and obtaining
inspection approval. Customer shall not operate the Net Metering Facility in continuous
parallel without an executed Interconnection and Net Metering Service Agreement, and
approval from Rocky Mountain Power.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 19 of 21
D. Customer Acknowledgment
I certify that the information provided in this Application is true. I will provide Rocky Mountain
Power a copy of the signed government electrical inspection approval document when obtained, if
not already provided with this Application.
I agree to abide by the terms of this Application and I agree to notify Rocky Mountain Power
thirty (30) days prior to modification or replacement of the System’s components or design. Any
such modification or replacement may require submission of a new Application to Rocky
Mountain Power.
I agree not to operate the Net Metering Facility in parallel with Rocky Mountain Power, except
temporarily for testing and obtaining inspection approval, until this Application is approved by
Rocky Mountain Power, until this agreement is signed by both parties, and until I have provided
Rocky Mountain Power with at least five (5) days notice of anticipated start date.
Customer or Applicant Signature & Date: ____________________________________
Please send completed application to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
or
Please scan the completed application and email
[email protected]
Section 3: To be completed by the System Installer
Installation Contractor Information/Hardware and Installation Compliance
Installation Contractor (Company Name): _________________________________________________
Contractor's License No.: ______________________ Proposed Installation Date: __________________
Mailing Address: _____________________________________________________________________
City: _____________________________________ State: ___________ Zip Code: ________________
Daytime Phone: _______________ Fax: _______________ Email: ____________________________
For inverter-controlled system, meets IEEE Standards and UL 1741 Inverters, Converters, and
Controllers for use in Independent Power Systems as set forth in the Rule:
Yes
No
If Photovoltaic System, System must be installed in compliance with IEEE Standards, Recommended
Practice for Utility Interface of Photovoltaic Systems. All System types must be installed in compliance
with applicable requirements of local electrical codes, Rocky Mountain Power and the National Electrical
Code® (NEC) and must use an anti-islanding inverter.
The System must include a manual, lockable, load-break (disconnect) switch, unless exempt under Rule
746-312-4(2), accessible at all times to Rocky Mountain Power personnel and located within 10 feet of
Rocky Mountain Power’s meter. The disconnect switch may be located more than 10 feet from Rocky
Mountain Power’s meter if permanent instructions are posted at the meter indicating the precise location
of the disconnect switch. Rocky Mountain Power must approve the location of the disconnect switch prior
to the installation of the net metering facility.
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 20 of 21
If the Net Metering Facility is designed to provide uninterruptible power to critical loads, either through
energy storage, back-up generator, or the generation source, the Net Metering Facility will include a
parallel blocking scheme for this backup source. This function may be integral to the inverter
manufacturer’s packaged system.
Does the Net Metering Facility include a parallel blocking scheme:
Yes
No
Signed (Contractor): ______________________________________ Date: _____________
Name (Print): _______________________________________________
Section 4. To be completed by Rocky Mountain Power:
A. If approving the application:
Rocky Mountain Power does not, by approval of this Application, assume any responsibility or
liability for damage to property or physical injury to persons. Further, this Application does not
constitute a dedication of the owner's System to Rocky Mountain Power electrical system
equipment or facilities.
Customer entered into an Interconnection and Net Metering Service Agreement with Rocky
Mountain Power on the ____ day of _____, 20__.
Customer satisfactorily passed Witness Tests on the ____ day of _________, 20__.
(Rocky Mountain Power may waive Witness Tests at its option; if tests are waived initial here __)
This Application is approved by Rocky Mountain Power on this ______ day of _________, 20__
Rocky Mountain Power Representative Name (Print):___________________________________
Signed (Rocky Mountain Power Representative): ______________________ Date: __________
B. If denying the application:
This application is denied by Rocky Mountain Power on this ______ day of ____________, 20__
for the following reason(s):_________________________________________________________
Rocky Mountain Power Representative Name (Print):____________________________________
Signed (Rocky Mountain Power Representative): ________________________ Date:__________
Applicant may submit a new application for Level 2 review.
Section 5: To be completed by Rocky Mountain Power Meterman
Customer Account No. _____________________________ Site ID No. : ______________________
Served from Facility Point No.: ________________________________
New Net Meter No.: ____________________________ Date net meter installed: ________________
Manual disconnect required:
Yes
No Proper location & permanent signage in place:
Yes
No
Signature/Title:_____________________________________________ Date:___________________
Rocky Mountain Power Interconnection and Net Metering Agreement
Utah Form Ver. 34 - Level 1
Page 21 of 21
We appreciate your interest in Rocky Mountain Power’s net metering program. Before
purchasing any net metering equipment, we recommend you review the requirements for
interconnecting a net metering system to Rocky Mountain Power’s electrical distribution
system. The requirements are found in the Interconnection Agreement.
To complete the process for a net metering interconnection, please follow the steps below:
1. Complete and submit the following to Rocky Mountain Power:
 Interconnection Agreement including the Application for Net Metering
Interconnection
 The inverter specification sheet
 For systems larger than 10 kW, a simple one-line diagram showing
• The location of Rocky Mountain Power’s meter
• The location of the disconnect switch
2. Rocky Mountain Power will review your agreement and application and send you a
written notification of approval either by mail or e-mail
3. Install the net metering system after you receive the written approval of your
Interconnection Agreement and Application for Net Metering from Rocky Mountain
Power
4. Obtain an inspection of your net metering system by the local city or county electrical
inspector
5. Submit the electrical inspector’s approval to Rocky Mountain Power
6. Turn on your net metering system after Rocky Mountain Power provides you written
notification the interconnection work has been completed and the net meter installed
Return completed documents to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, Utah 84125-0308
Or Email to:
[email protected]
Thank you for your interest in the net metering program. If you have questions, please call us
toll free at 1-888-221-7070 and ask for a net metering specialist.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 4 - Level 2
Utah Level 2
Page 1 of 25
Service ID#:___________
Request #: ___________
INTERCONNECTION AND NET METERING SERVICE AGREEMENT FOR NET
METERING FACILITY LEVEL 2 INTERCONNECTION
UP TO 2 MW NAMEPLATE CAPACITY
This Interconnection and Net Metering Service Agreement (“Agreement”) is made and
entered into this ____ day of _____________, 20___, by and between
_____________________________, an electric customer (“Customer”), and PacifiCorp, dba
Rocky Mountain Power (“Rocky Mountain Power”), a Corporation organized and existing
under the laws of the State of Oregon. Customer and Rocky Mountain Power each may be
referred to as a “Party”, or collectively as the “Parties”.
Recitals:
Whereas, Customer has installed or intends to install a Net Metering Facility qualifying
for “Net Metering,” Utah Rate Schedule No. 135A (“Schedule 135A”), as given in Rocky
Mountain Power’s currently effective tariff as filed with the Public Service Commission of
Utah (“Commission”), on or adjacent to Customer’s premises located at
____________________________, Utah, for the purpose of generating electric energy;
Whereas, the Net Metering rate schedule may be amended from time to time, and the
Public Service Commission may alter the charge, credit, and ratemaking structure applicable to
Net Metering customers pursuant to Utah Code § 54-15-105.1;
Whereas, Customer represents to Rocky Mountain Power that Customer either owns or
leases its Net Metering Facility qualifying for Schedule 135A, or meets the exemption
requirements set forth in Utah Code § 54-2-1.16(d) because it is a county, municipality, city,
town, other political subdivision, local district, special service district, state institution of higher
education, school district, charter school, or any entity within the state system of public
education; or an entity qualifying as a charitable organization under 26 U.S.C. Sec. 501(c)(3)
operated for religious, charitable, or educational purposes that is exempt from federal income
tax and able to demonstrate its tax-exempt status;
Whereas, Customer desires to interconnect the Net Metering Facility with Rocky
Mountain Power’s distribution system consistent with the Application completed by Customer
on _____________ ____, 20___, as described in as described in Appendix B (“Application”)
of this Agreement; and
Whereas, Customer, using its Net Metering Facility, intends to offset part or all of its
electrical requirements supplied by Rocky Mountain Power.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 4 - Level 2
Utah Level 2
Page 2 of 25
Now, therefore, in consideration of and subject to the mutual covenants contained
herein, the Parties agree as follows:
Article 1.
Scope and Limitations of Agreement
1.1
Scope
The Agreement shall be used for all approved Level 2 Applications according to the
procedures set forth in Utah Administrative Rule 746-312, as may be amended from
time to time (“Rule”). . The Rule can be viewed at www.psc.utah.gov. The Agreement
establishes standard terms and conditions approved by the Public Service Commission
of Utah (“Commission”) under which the Net Metering Facility with an Electric
Nameplate Capacity of 2 MW or smaller as described in Appendix B will interconnect
to, and operate in parallel with, Rocky Mountain Power’s system.
1.2
Definitions
Terms with initial capitalization, when used in this Agreement, shall have the meanings
indicated or as specified in the Rule Section R746-312-2 and, to the extent this
Agreement conflicts with the Rule, the Rule shall take precedence.
1.3
Other Agreements
Nothing in this Agreement is intended to affect any other agreement between Rocky
Mountain Power and Customer or any other Interconnection Customer. However, in the
event that the provisions of the Agreement are in conflict with the provisions of any
Rocky Mountain Power Tariff, as may be amended from time to time, the Rocky
Mountain Power Tariff, as may be amended from time to time, shall control.
1.4
Responsibilities of the Parties
1.4.1
The Parties shall perform all obligations of the Agreement in accordance with
all applicable laws and regulations.
1.4.2
Customer will construct, operate, test, and maintain its Net Metering Facility in
accordance with the Agreement, IEEE standards (available at the following
link: http://standards.ieee.org/index.html), National Electric Code Standards
(available for purchase at http://standards.ieee.org/faqs/NESCFAQ.html#q8),
Utah state building codes (available at the following link:
http://www.dopl.utah.gov/programs/ubc/), the Rule and other applicable
standards required by the Commission, as may be amended from time to time.
1.4.3
Each Party shall be responsible for the safe installation, maintenance, repair and
condition of their respective lines and appurtenances on their respective sides of
the Point of Common Coupling. Each Party shall provide interconnection
facilities that adequately protect the other Party’s facilities, personnel and other
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 4 - Level 2
Utah Level 2
Page 3 of 25
persons from damage and injury. The allocation of responsibility for the design,
installation, operation, maintenance and ownership of interconnection facilities
is prescribed in the Rule, including but not necessarily limited to R746-312-4.
1.5
1.4.4
Customer is responsible for protecting the generating equipment, inverters,
protective devices, and other system components from damage from the normal
and abnormal conditions and operations that occur on Rocky Mountain Power’s
system in delivering and restoring power; and is responsible for ensuring that
the Net Metering Facility equipment is inspected, maintained, and tested in
accordance with the manufacturer’s instructions to ensure that it is operating
correctly and safely.
1.4.5
Customer shall obtain Rocky Mountain Power’s approval of the Application
prior to commencing parallel operation of its interconnected Net Metering
Facility.
Parallel Operation and Maintenance Obligations
Once the Net Metering Facility has been authorized to commence parallel operation by
an approved application, and execution of this Agreement, Customer will abide by all
written provisions for operations and maintenance as required by the Rule and Rocky
Mountain Power’s Tariffs, including but not necessarily limited to R746-312-4 and
Schedule 135A or its successor tariff(s).
1.6
Metering
Rocky Mountain Power shall install, own and maintain, at its sole expense, a kilowatthour meter(s) and associated equipment to measure the flow of energy in each direction,
unless otherwise authorized by the Commission. Customer shall provide, at its sole
expense, adequate facilities, including, but not limited to, a current transformer
enclosure (if required), meter socket(s) and junction box, for the installation of the meter
and associated equipment.
Customer hereby consents to the installation and operation by Rocky Mountain Power
and at Rocky Mountain Power’s expense, of one or more additional meters to monitor
the flow of electricity in each direction. Such meters shall be located on the premises of
Customer.
1.7
Net Metering Facility Requirements, Installation, Operation
1.7.1
Customer’s Net Metering Facility must meet the requirements set forth in,
including but not necessarily limited to, the Rule, R746-312-4 and Schedule
135A or its successor tariff(s). This also applies to installation and operation of
the Net Metering Facility.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 4 - Level 2
Utah Level 2
Page 4 of 25
1.7.2
1.8
Customer is responsible for all costs associated with its Net Metering Facility
and is also responsible for all costs related to any modifications to the Net
Metering Facility that may be required by Rocky Mountain Power for purposes
of safety and reliability as allowed under the Rule and Rocky Mountain Power
tariffs.
Power Quality
Customer will design its Net Metering Facility to maintain a composite power delivery
at continuous rated power output at the Point of Common Coupling that meets the
requirements set forth in IEEE 1547, in accordance with the Rule, R746-312-4.
1.9
Anticipated Start Date
Customer must include an anticipated start date for operation of its Net Metering
Facility in the Application. After receiving notice that the Application has been
approved and satisfactory completion of all reviews and inspections of the Net Metering
Facility, Customer must notify Rocky Mountain Power at least ten (10) Business Days
prior to starting operation of the Facility, through either submission of an executed
Agreement or through separate written notice. Customer shall not commence parallel
operation of the Net Metering Facility until Rocky Mountain Power executes this
Agreement, installs the net meter and notifies Customer that the Net Metering Facility
is interconnected.
1.10
Net Metering Facility Inspection
1.10.1 Building Code Inspection
Prior to operation in parallel with Rocky Mountain Power’s system, the Net
Metering Facility must be inspected by a local building code official to ensure
compliance with applicable local codes.
1.10.2 Inspection by Rocky Mountain Power
Rocky Mountain Power may inspect the Net Metering Facility and its
component equipment, and the documents necessary to ensure compliance with
the Rule. Customer shall notify Rocky Mountain Power prior to placing the Net
Metering Facility in service, and Rocky Mountain Power shall have the right to
have personnel present on the in-service date. If the Net Metering Facility is
subsequently modified in order to increase its gross power rating, Customer
must notify Rocky Mountain Power by submitting a new application specifying
the modifications in accordance with the level of review required for that
application.
1.11
Net Metering Facility Testing and Maintenance
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 4 - Level 2
Utah Level 2
Page 5 of 25
Customer shall conduct maintenance and testing on its Net Metering Facilities as set
forth in the Rule, including but not necessarily limited to R746-312-14.
1.11.1 Customer shall conduct any manufacturer-recommended testing or maintenance
at its expense.
1.11.2 Customer shall conduct any post-installation testing, at its expense, necessary to
ensure compliance with IEEE standards as set forth in the Rule or to ensure
safety. This includes replacing a major equipment component that is different
from the originally installed model.
1.11.3 When Customer performs maintenance or testing in accordance with the Rule,
it must retain written records documenting the maintenance and results of the
testing for three (3) years.
1.11.4 Rocky Mountain Power shall have the right to inspect Customer’s facility after
interconnection approval is granted, at reasonable hours and with reasonable
prior notice to Customer. If Rocky Mountain Power discovers that the Net
Metering Facility is not in compliance with the Rule, Rocky Mountain Power
may require Customer to disconnect the Net Metering Facility until compliance
is achieved.
1.12
Removal of Facility
Customer shall immediately notify Rocky Mountain Power if Customer removes or
ceases to operate the Net Metering Facility.
Article 2.
2.1
Review, Inspection, Testing, Disconnect Switch and Signage, and Right of
Access
Initial Review and Additional Review
After determining Customer’s interconnection request is complete, in accordance with
the Rule, R746-312-9, Rocky Mountain Power will conduct a review of the proposed
interconnection, using screens set forth in the Rule R746-312-7. Rocky Mountain Power
will conduct such review within fifteen (15) days after notifying Customer that the
interconnection request is complete and will notify Customer either: 1) the Net Metering
Facility meets all applicable criteria and the interconnection request is approved; 2)
although the Net Metering Facility fails one or more of the screens the Net Metering
Facility may be interconnected consistent with safety, reliability, and power quality
standards and the interconnection is approved; or 3) the interconnection of the Net
Metering Facility has failed to meet one or more of the applicable criteria and the reason
for failure, or Rocky Mountain Power has not or could not determine from the initial
reviews that the Net Metering Facility may be interconnected consistent with safety
reliability, and power quality standards, or the Net Metering Facility cannot be approved
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 4 - Level 2
Utah Level 2
Page 6 of 25
without minor modifications at minimal cost and the interconnection request is denied
unless the Customer is willing to consider minor modifications or further study.
If the initial review determines that the Net Metering Facility fails to meet one or more
applicable requirements, but additional review may enable Rocky Mountain Power to
determine that the Net Metering Facility may be interconnected consistent with safety,
reliability and power quality standards, Rocky Mountain Power will offer to perform
the additional review to determine whether minor modifications to the electric
distribution system would enable the interconnection to be made consistent with safety,
reliability and power quality standards. In this instance, Rocky Mountain Power will
provide Customer with a good faith, nonbinding estimate of costs of such additional
review and minor modifications. Rocky Mountain Power will conduct additional review
and make minor modifications after receipt of payment from Customer in accordance
with the attached Appendix A.
2.2
Equipment Testing and Inspection
Customer must notify Rocky Mountain Power of the anticipated testing and inspection
date of the Net Metering Facility at least ten (10) business days prior to testing, either
through submittal of the Agreement, a notice of completion, or in a separate notice.
Within ten (10) business days after receipt of such required documentation, Rocky
Mountain Power will inspect the Net Metering Facility, set the new meter if required,
approve the interconnection and may arrange a witness test as set forth in the Rule,
R746-312-9(5). Rocky Mountain Power and Customer will select a date by mutual
agreement for the witness tests.
Rocky Mountain Power will test and inspect the Net Metering Facility and
Interconnection Facilities prior to interconnection in accordance with IEEE Standards
as provided for in the Rule, R746-312-4. Customer shall not begin operation of its Net
Metering Facility until after inspection and testing is completed.
If a witness test is conducted and is not satisfactory, Customer must resolve any
deficiencies within forty-five (45) business days or other time period as mutually agreed
by the Parties.
2.3
Disconnect Switch and Signage
Customer shall comply with the Rule regarding disconnect switches, R746-312-4. The
disconnect switch may be located more than 10 feet from the public utility meter if
permanent instructions in letters of appropriate size are posted at the meter indicating
the precise location of the disconnect switch. Rocky Mountain Power must approve in
writing the location of the disconnect switch prior to the installation of the Net Metering
Facility.
2.4
Right of Access
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As provided in the Rule, R746-312-4, Rocky Mountain Power shall have access to any
required disconnect switch at the Net Metering Facility at all times. Rocky Mountain
Power will provide reasonable notice to Customer when possible prior to using the right
of access. Additionally, as provided in Rocky Mountain Power Utah Rule 6, or its
successor tariff, Rocky Mountain Power shall have access to the metering equipment.
Article 3.
3.1
Effective Date, Term, Termination and Disconnection
Effective Date
The Agreement shall become effective upon execution by the Parties.
3.2
Term of Agreement
The Agreement will become effective on the Effective Date and will remain in effect
unless terminated in accordance with provisions of this Agreement, or Order by the
Commission.
3.3
Termination
No termination will become effective until the Parties have complied with all applicable
laws and clauses of this Agreement applicable to such termination.
3.4
3.3.1
Customer may terminate this Agreement at any time by giving Rocky Mountain
Power twenty (20) business days written notice.
3.3.2
Either Party may terminate this Agreement after default pursuant to Article 6.4
of this Agreement.
3.3.3
The Commission may Order termination of this Agreement.
3.3.4
Upon termination of this Agreement, Customer shall disconnect the Net
Metering Facility from Rocky Mountain Power’s system. The termination of
this Agreement will not relieve either Party of its liabilities and obligations,
owed or continuing at the time of termination.
3.3.5
If Customer removes the Net Metering equipment at the Net Metering Facility
or ceases to operate its Net Metering Facility at the premise listed in the
Application, this Agreement will be immediately terminated.
3.3.6
The provisions of this Article shall survive termination or expiration of this
Agreement.
Temporary Disconnection
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3.4.1
Rocky Mountain Power may temporarily disconnect the Net Metering Facility
from Rocky Mountain Power’s system for so long as reasonably necessary in
the event one or more of the following conditions or events occurs:
3.4.1.1 Emergencies or to address maintenance requirements for Rocky
Mountain Power’s system.
3.4.1.2 Hazardous conditions existing on Rocky Mountain Power’s system
which may affect the safety of the general public or Rocky Mountain
Power employees due to the operation of the Net Metering Facility or
protective equipment as determined by Rocky Mountain Power.
3.4.1.3 Adverse electrical effects on the electrical equipment of Rocky Mountain
Power’s other electric customers caused by the Net Metering Facility as
determined by Rocky Mountain Power.
3.4.2
In the event that no disconnect switch is installed, Rocky Mountain Power may
physically disconnect all service to the Customer and/or all service to the
premises where the Net Metering Facility is located.
3.4.3
To the extent practicable, Rocky Mountain Power will give prior notice of any
temporary disconnection of the Net Metering Facility. If Rocky Mountain Power
is unable to give prior notice, Rocky Mountain Power will provide notice
including an explanation of the condition necessitating the disconnection at the
time of disconnection.
3.4.4
Under emergency conditions, Rocky Mountain Power or Customer may
immediately suspend interconnection service and temporarily disconnect the
Net Metering Facility. Rocky Mountain Power shall notify Customer promptly
when Rocky Mountain Power becomes aware of an emergency condition that
may reasonably be expected to affect the Net Metering Facility operation.
Customer shall notify Rocky Mountain Power promptly when Customer
becomes aware of an emergency condition that may reasonably be expected to
affect Rocky Mountain Power’s system. To the extent the information is known,
the notification shall describe the emergency condition, the extent of any
damage or deficiency, the expected effect on the operation of both Parties’
facilities and operations, the anticipated duration, and the necessary corrective
action.
3.4.5
Customer shall make reasonable efforts to provide notice of interruption of Net
Metering Facility operation for safety and/or reliability reasons prior to the
interruption unless an emergency occurs. Emergency interruptions or temporary
terminations are subject to Section 3.4.1 above.
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3.4.6
Rocky Mountain Power shall use reasonable efforts to provide Customer with
prior notice of forced outages to effect immediate repairs to Rocky Mountain
Power’s system. If prior notice is not given, Rocky Mountain Power, shall, upon
request, provide Customer written documentation after the fact explaining the
circumstances of the disconnection.
3.4.7
Customer must provide Rocky Mountain Power notice and obtain Rocky
Mountain Power’s written approval before Customer may modify its Net
Metering Facility in order to increase the electric output of the Net Metering
Facility. If Customer makes any material change without prior written
authorization of Rocky Mountain Power, Rocky Mountain Power will have the
right to temporarily disconnect the Net Metering Facility until Rocky Mountain
Power has had an opportunity to review the change(s) made to determine
whether they are acceptable. If any system modifications or other equipment
installations are deemed necessary by Rocky Mountain Power to accommodate
the modified Net Metering Facility, Customer shall submit the appropriate net
metering application at that time.
3.4.8
The Parties shall cooperate with each other to restore the Net Metering Facility,
Interconnection Facilities, and Rocky Mountain Power’s system to their normal
operating state as soon as reasonably practicable following any disconnection
pursuant to this section.
Article 4.
4.1
Cost Responsibility
Application Fee
Customer shall bear the cost of any Application fee provided for in the Rule, R746-31213(2), or as otherwise approved by the Commission. Customer shall remit payment with
the Application as calculated in the Application, Section 2(C).
4.2
Net Metering Facility and Interconnection Equipment
Customer shall be responsible for all costs including overheads, associated with
procuring, installing, owning, operating, maintaining, repairing, and replacing its Net
Metering Facility, any associated equipment package, and any associated
interconnection equipment or interconnection facilities required to be installed on
Customer’s side of the Point of Common Coupling.
4.3
Minor Modifications
If, under Section 2.1 of this Agreement, additional review is performed and minor
modifications to the electric distribution system are required to enable the
interconnection to be made consistent with safety, reliability and power quality
standards applicable to Level 2 interconnection reviews, the Customer shall pay for the
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cost to procure, install, and construct, operate, maintain, repair and replace any such
Minor Modifications. A description of the minor modifications may be found in
Appendix A. The cost of the minor modifications as described on Appendix A shall be
$________. Customer shall remit payment for minor modifications prior to Rocky
Mountain Power commencing the work required for the minor modifications.
Article 5.
5.1
Billing
Monthly Billing
The electric service charge shall be computed in accordance with the monthly billing in
the currently applicable standard service tariff. Customer will be compensated for net
excess energy in accordance with Schedule 135A or its successor tariff(s). Customer
will be transitioned to any successor tariff immediately upon approval of that tariff by
the Public Service Commission and will be subject to any charge, credit, or ratemaking
structure implemented therein.
5.2
Special Conditions
Customer must comply with the special conditions found in Schedule 135A or its
successor tariff(s).
5.3
Aggregating Meters
Aggregating Meters is allowed if certain conditions are met under the Rule, R746-3125.
Customer
designates
the
following
meters
for
aggregation:
_______________________. In the event that the Net Metering Facility supplies more
electricity to Rocky Mountain Power than the Customer uses from Rocky Mountain
Power, Rocky Mountain Power will apply any credits to the next monthly bill in
accordance with Utah Code § 54-15-104 and the Rule, R746-312-15. Customer shall
designate the order in which to apply any credits in accordance with the Rule. <<If
customer does not want to aggregate, insert “N\A” in the gray box.>>
Article 6.
6.1
Assignment, Liability, Indemnity, Force Majeure, Consequential Damages
and Default
Assignment
This Agreement may be assigned by either Party with the consent of the other Party. A
Party’s consent to an assignment may not be unreasonably withheld. The assigning
Party must give the non-assigning Party written notice of the assignment at least fifteen
days (15) before the effective date of the assignment. The non-assigning Party must
submit its objection to the assignment, if any, to the assigning Party in writing at least 5
business days before the effective date of the assignment. If a written objection is not
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received within that time period, the non-assigning party is deemed to consent to the
assignment.
6.1.1
Exceptions to the Consent Requirement
6.1.1.1 Either Party may assign the Agreement without the consent of the other
Party to any affiliate (including a merger or acquisition of the Party with
another entity), of the assigning Party with an equal or greater credit
rating and with the legal authority and operational ability to satisfy the
obligations of the assigning Party under this Agreement.
6.1.1.2 Customer-Generator is entitled to assign the Agreement, without the
consent of Rocky Mountain Power, for collateral security purposes to aid
in obtaining financing for the Net Metering Facility.
6.1.1.3 For Net Metering systems that are integrated into a building facility, the
sale of the building or property will result in the automatic assignment
of this Agreement to the new owner who will be responsible for
complying with the terms and conditions of this Agreement.
6.1.2
6.2
Any attempted assignment that violates this Article is void and ineffective.
Assignment does not change or eliminate a Party’s obligations under this
Agreement. An assignee is responsible for meeting the same obligations as the
assigning Party.
Limitation of Liability and Consequential Damages
Each Party’s liability to the other Party for any loss, cost, claim, injury, liability, or
expense, including reasonable attorney’s fees, relating to or arising from any act or
omission in the performance of this Agreement, is limited to the amount of direct
damage actually incurred. Neither Party is liable to the other Party for any indirect,
special, consequential, or punitive damages.
6.3
Indemnification
Customer shall hold harmless and indemnify Rocky Mountain Power for all loss to third
parties resulting from the operation of the Net Metering Facility, except when the loss
occurs due to the negligent actions of Rocky Mountain Power.
Rocky Mountain Power shall hold harmless and indemnify Customer for all loss to third
parties resulting from the operation of Rocky Mountain Power’s system, except where
the loss occurs due to the negligent actions of Customer.
6.4
Force Majeure
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6.5
6.4.1
As used in this Agreement, a Force Majeure Event shall mean “any act of God,
labor disturbance, act of the public enemy, war, acts of terrorism, insurrection,
riot, fire, storm or flood, explosion, breakage or accident to machinery or
equipment through no direct, indirect, or contributory act of a Party, any order,
regulation, or restriction imposed by governmental, military or lawfully
established civilian authorities, or any other cause beyond a Party’s control. A
Force Majeure Event does not include an act of negligence or wrongdoing.”
6.4.2
If a Force Majeure Event prevents a Party from fulfilling any obligations under
this Agreement, the Party affected by the Force Majeure Event (“Affected
Party”) shall promptly notify the other Party of the existence of the Force
Majeure Event. The notification must specify in reasonable detail the
circumstances of the Force Majeure Event, its expected duration, and the steps
that the Affected Party is taking to mitigate the effects of the event on its
performance, and if the initial notification was verbal, it should be promptly
followed up with a written notification. The Affected Party shall keep the other
Party informed on a continuing basis of developments relating to the Force
Majeure Event until the event ends. The Affected Party will be entitled to
suspend or modify its performance of obligations under this Agreement (other
than the obligation to make payments) only to the extent that the effect of the
Force Majeure Event cannot be reasonably mitigated. The Affected Party will
use reasonable efforts to resume its performance as soon as possible. The Parties
shall immediately report to the Commission should a Force Majeure Event
prevent performance of an action required by Rule that the Rule does not permit
the Parties to mutually waive.
Default
6.5.1
A Party is in default if the Party fails to perform an obligation required under
this Agreement (other than the payment of money). A Party is not considered in
default of this agreement if the failure to perform an obligation is caused by an
act or omission of the other Party or is the result of a Force Majeure as defined
in this Agreement.
6.5.2
Upon a default, the non-defaulting Party must give written notice of the default
to the defaulting party. The defaulting party has sixty (60) calendar days from
the receipt of the written default notice to cure the default. If the default is not
capable of cure within the 60-day period, the defaulting Party must begin to cure
the default within twenty (20) calendar days after receipt of the written default
notice, and must continuously and diligently complete the cure within six (6)
months of the receipt of the notice.
6.5.3
If a default is not cured as provided for in 6.5.2, then the non-defaulting Party is
entitled to terminate the Agreement by written notice at any time until cure
occurs. If the non-defaulting Party chooses to terminate this Agreement, the
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termination provisions in Article 3.3 apply. Alternately, the non-defaulting Party
is entitled to seek dispute resolution with the Commission in lieu of termination.
Article 7.
Insurance
Additional liability insurance is not required as a part of the Agreement if the Net Metering
Facility is in compliance with the provisions of the Application approval, the Agreement and
the standards contained in Utah Code § 54-15-106.
Article 8.
Dispute Resolution
8.1
Nothing in this Article shall restrict the rights of any Party to file a complaint with the
Commission under relevant provisions of the Rule and applicable state law.
8.2
Pursuit of dispute resolution may not affect a Customer with regard to consideration of
an Interconnection Request or a Customer’s queue position.
Article 9.
9.1
Miscellaneous
Governing Law, Regulatory Authority and Rules
The validity, interpretation, and enforcement of this Agreement is governed by the laws
of the State of Utah. If any provision of this Agreement conflicts with any applicable
provision, as may be amended from time to time, of the Utah Code (“Code”), Utah
Administrative Rules (“Rules”), or Rocky Mountain Power’s Tariffs (“Tariff”), then the
applicable provision of the Code, Rules, or Tariff controls. Rocky Mountain Power must
provide copies of the applicable provisions of the Code, Rules, and Tariff upon the
Customer’s request.
9.2
Amendment
Additions, deletions or changes to the standard terms and conditions of this Agreement
will not be permitted unless they are mutually agreed to by the Parties and permitted by
the Rule or permitted by the Commission for good cause shown. The Parties may amend
the Agreement by a written instrument duly executed by both Parties in accordance with
the provisions of the Rule and applicable Commission Orders and provisions of the laws
of the State of Utah.
9.3
No Third Party Beneficiaries
The Agreement is not intended to and does not create rights, remedies, or benefits of
any character whatsoever in favor of any persons, corporations, associations, or entities
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other than the Parties, and the obligations herein assumed are solely for the use and
benefit of the Parties, or where permitted, their successors in interest and their assigns.
9.4
9.5
Waiver
9.4.1
The failure of a Party to the Agreement to insist, on any occasion, upon strict
performance of any provision of the Agreement, will not be considered a waiver
of any obligation, right, or duty of, or imposed upon, such Party.
9.4.2
The Parties may also agree to mutually waive a Section of this Agreement
without the Commission’s approval where the Rule so provides.
9.4.3
Any waiver at any time by either Party of its rights with respect to the Agreement
shall not be deemed a continuing waiver or a wavier with respect to any other
failure to comply with any other obligation, right, duty of the Agreement.
Termination or default of this Agreement for any reason by Customer shall not
constitute a waiver of the Customer’s legal rights to obtain interconnection from
Rocky Mountain Power. Any request for waiver of the Agreement or any
provisions thereof shall be provided in writing.
Entire Agreement
The Agreement, including any supplementary attachments that may be necessary,
constitutes the entire Agreement between the Parties with reference to the subject matter
hereof, and supersedes all prior and contemporaneous understandings or agreements,
oral or written, between the Parties with respect to the subject matter of the Agreement.
There are no other agreements, representations, warranties, or covenants that constitute
any part of the consideration for, or any condition to, either Party’s compliance with its
obligations under the Agreement.
9.6
Multiple Counterparts
This Agreement may be executed in one or more counterparts, whether electronically
or otherwise, each of which is deemed an original but all constitute one and the same
instrument.
9.7
No Partnership
The Agreement will not be interpreted or construed to create an association, joint
venture, agency relationship, or partnership between the Parties or to impose any
partnership obligation or partnership liability upon either Party. Neither Party shall have
any right, power or authority to enter into any agreement or undertaking for, or act on
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behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other
Party.
9.8
Severability
If any provision or portion of the Agreement shall for any reason be held or adjudged to
be invalid or illegal or unenforceable by any court of competent jurisdiction or other
governmental authority, (1) such portion or provision shall be deemed separate and
independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable
the benefits to each Party that were affected by such ruling, and (3) the remainder of the
Agreement shall remain in full force and effect.
9.9
Subcontractors
Nothing in the Agreement shall prevent a Party from using the services of any
subcontractor, or designating a third party agent as one responsible for a specific
obligation or act required in the Agreement (collectively “subcontractors”), as it deems
appropriate to perform its obligations under the Agreement; provided, however, that
each Party will require its subcontractors to comply with all applicable terms and
conditions of the Agreement in providing such services and each Party will remain
primarily liable to the other Party for the performance of the subcontractor.
9.10
9.9.1
The creation of any subcontract relationship shall not relieve the hiring Party of
any of its obligations under the Agreement. The hiring Party shall by fully
responsible to the other Party for the acts or omissions of any subcontractor the
hiring Party hires as if no subcontract had been made. Any applicable obligation
imposed by the Agreement upon the hiring Party shall be equally binding upon,
and will be construed as having application to, any subcontractor of such Party.
9.9.2
The obligations under this Article will not be limited in any way by any
limitation of a subcontractor’s insurance.
Reservation of Rights
Rocky Mountain Power shall have the right to make a unilateral filing with the
Commission to modify this Interconnection Agreement with respect to any rates, terms
and conditions, charges, classifications of service, rule, regulation or any other
applicable provision of the Federal Power Act and the Commission’s rules and
regulations thereunder, and Customer shall have the right to make a unilateral filing
with the Commission to modify this Agreement under any applicable provision of the
Federal Power Act and the Commission’s rules and regulations; provided that each Party
shall have the right to protest any such filing by the other Party and to participate fully
in any proceeding before the governing authority in which such modifications may be
considered. Nothing in this Agreement shall limit the rights of the Parties, except to the
extent that the Parties otherwise agree as provided herein.
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Article 10.
10.1
Notices and Records
General
Unless otherwise provided in the Agreement, any written notice, demand, or request
required or authorized in connection with the Agreement shall be deemed properly given
if delivered in person, delivered by recognized national courier service, sent by first
class mail, postage prepaid, or by electronic mail if an electronic mail address is
provided below to the person specified below:
If to Customer:
Customer: ______________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: ________________________________ State: _________________ Zip: ________
Phone: (____) ________________________ Fax: (____) _________________________
Email: __________________________________________________________________
If to Rocky Mountain Power:
By Mail:
Rocky Mountain Power
Attention: Net Metering Group
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
Or
By email:
[email protected]
10.2
Records
Rocky Mountain Power will maintain a record of the Interconnection Agreement and
related Attachments, if any, for as long as the interconnection is in place. Rocky
Mountain Power will provide a copy of these records to Customer within fifteen (15)
Business Days upon written request.
10.3
Billing and Payment
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Billings and payments shall be sent to the addresses below (complete if different from
Section 10.1 above):
If to Customer:
Customer: ______________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: _______________________________ State: _______________ Zip: ___________
10.4
Designated Operating Representative
The Parties will designate one operating representative each to conduct the
communications that may be necessary or convenient for the administration of the
operations provisions of the Agreement. This person will also serve as the point of
contact with respect to operations and maintenance of the Party’s facilities (complete if
different from Section 10.1 above):
Customer’s Operating Representative:
Name: __________________________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: _______________________________ State: _______________ Zip: ___________
Phone: (____) _______________________ Fax: (____) __________________________
Email: __________________________________________________________________
10.5
Changes to the Notice Information
Either Party may change this notice information by giving five (5) business days written
notice prior to the effective date of the change.
Article 11.
Signatures
IN WITNESSETH WHEREOF, the Parties have caused the Agreement to be executed by
their respective duly authorized representatives.
For the Customer:
For Rocky Mountain Power:
By: _____________________________
By: _____________________________
Name: ___________________________
Name: ___________________________
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Title: ____________________________
Title: ____________________________
Date: ____________________________
Date: ____________________________
Appendix A
Minor Modifications
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APPENDIX B
ROCKY MOUNTAIN POWER UTAH NET METERING APPLICATION
LEVEL 2 REVIEW
CAPACITY OF 2 MW OR LESS
Section 1: For Rocky Mountain Power Use Only
Customer Name: _________________________________________________________________________
Service Address: _________________________________________________________________________
City, State, Zip: __________________________________________________________________________
Customer Account No. & Request No.:________________________________________________________
Interconnection Agreement Acknowledgement (Date): ___________________________________________
Application fee: $__________________ Date Paid: _____________________________________________
Section 2: To Be Completed By Customer
A. Applicant Information
Name: ___________________________________________________________________________
Mailing Address: ___________________________________________________________________
City: __________________________________________State: _________ Zip Code: ____________
Site Street Address (if different from above): _____________________________________________
City: __________________________________________State: __________ Zip Code: ___________
Daytime Phone: (_____) ________________________ Fax: (_____) __________________________
Email: ____________________________________________________________________________
B. System Information
System Type:
Solar
Wind
Hydro
Other (Specify): _________________________
Generation Nameplate Capacity: ______________ kW (Combine DC total of wind turbines, solar
panels, etc. or AC rating if an inverter is not utilized)
Inverter Manufacturer: ___________ Model: _______ Number of Inverters: _____ Rating: _____ kW
Manufacturer Nameplate Inverter Total AC Capacity Rating: _________ kW
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Inverter(s):
Single Phase
Three Phase
Multiple Single Phase Connected on Poly-phase
(three phase) system (Attach Inverter and Panel Technical Specifications Sheets)
Type:
Induction
Type of Service:
Inverter
Single Phase
Synchronous
__________________Other
Three Phase
If Three Phase Transformer:
Indicate Type:
Wye
Delta
Indicate Voltage and Number of Service Wires:
120/208 Volts, 4 wire 120/240 Volts, 4 wire 277/480 Volts, 4 wire
Other ___________
________________________________________________________________________________
Other Information:_________________________________________________________________
________________________________________________________________________________
Self Contained Location: ___________________________________________________________
Outdoor Manual AC Disconnect Switch Location (show Disconnect Switch and Rocky Mountain
Power Meter Location on Site Plan), unless exempt under Utah Administrative Rule 746-312-4(2):
________________________________________________________________________________
System Location (show all protective devices on One Line Diagram):_________________________
Will the net metering facility interconnect to a switchgear?
Yes
No
Customer must post metal or plastic engraved signage indicating on-site generation in accordance with
the National Electric Code. The signage must be permanent and located adjacent to the meter base and
disconnect switch noting “Parallel Generation on Site” and identifying the manual disconnect switch
with the words “Manual Disconnect for Parallel Generation.” _____ (Initial Here)
One Line Diagram Attached:
Installation Test Plan attached:
Yes
Yes
No
Site Plan Attached:
Yes
No
No
Anticipated Operational Date of Net Metering Facilities: __________________________________
(Rocky Mountain Power must be notified at least ten (10) business days prior to starting operation.)
Net metering facility available fault duty at the point of common coupling:_____________________
(A Rocky Mountain Power Engineer may contact you for additional information)
Electrical Inspection approval date (attach copy or provide to utility when obtained):_____________
C. Application Fees
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$
50.00
+ $ __________
$ __________
Base
$1.00 x ____ kW of Net Metering Facility’s capacity
TOTAL APPLICATION FEE
D. Additional Information
1.
2.
3.
4.
5.
6.
7.
An equipment package will be considered certified for interconnected operation if it has been
submitted by a manufacturer to a nationally recognized testing and certification laboratory, and
has been tested and listed by the laboratory for continuous interactive operation with an electric
distribution system in compliance with the applicable IEEE and UL 1741 standards, as set forth
in the Rule.
If the equipment package has been tested and listed as an integrated package, which includes a
generator or other electric source, the equipment package will be deemed certified, and Rocky
Mountain Power will not require any further design review, testing or additional information.
If the equipment package includes only the interface components (switchgears, inverters, or
other interface devices), an interconnection applicant must show that the generator or other
electric source being utilized with the equipment package is compatible with the equipment
package and consistent with the testing and listing specified for the package. If the generator or
electric source being utilized with the equipment package is consistent with the testing and
listing performed by the nationally recognized testing and certification laboratory, the
equipment package will be deemed certified and Rocky Mountain Power will not require
further design review, testing or additional equipment.
A net metering facility must be equipped with metering equipment that can measure the flow of
electricity in both directions, comply with ANSI C12.1 standards and Rule 746-312. Rocky
Mountain Power will install the required metering equipment at Rocky Mountain Power’s
expense.
Rocky Mountain Power will not be responsible for the cost of determining the rating of
equipment owned by the customer-generator or of equipment owned by other local customers.
Customer may operate the Net Metering Facility temporarily for testing and obtaining
inspection approval. Customer shall not operate the Net Metering Facility in continuous
parallel without an executed Interconnection and Net Metering Service Agreement, and
approval from Rocky Mountain Power.
Customer will pay to Rocky Mountain Power at the time of application the applicable
Application fee of $50.00 plus $1.00 per kilowatt of the net metering facility’s capacity.
Customer-generator will pay to Rocky Mountain Power all costs of minor modifications or
additional review as set forth in Rule 746-312 prior to commencement of work.
E. Customer Acknowledgment
I certify that the information provided in this Application is true. I will provide Rocky Mountain Power
a copy of the signed government electrical inspection approval document when obtained, if not already
provided with this Application.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 4 - Level 2
Utah Level 2
Page 22 of 25
I agree to abide by the terms of this Application and I agree to notify Rocky Mountain Power thirty (30)
days prior to modification or replacement of the System’s components or design. Any such
modification or replacement may require submission of a new Application to Rocky Mountain Power.
I agree not to operate the Net Metering Facility in parallel with Rocky Mountain Power, except
temporarily for testing and obtaining inspection approval, until this Application is approved by Rocky
Mountain Power, until this agreement is signed by both parties, and until I have provided Rocky
Mountain Power with at least five (5) days notice of anticipated start date.
Customer or Applicant Signature & Date: ____________________________________
Please send completed application to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
or
Please scan the completed application and email
[email protected]
Section 3. To be completed by System Installer
Installation Contractor Information/Hardware and Installation Compliance
Installation Contractor (Company Name): ______________________________________________________
Contractor's License No.: _______________________________ Proposed Installation Date: _____________
Mailing Address: _________________________________________________________________________
City: ______________________________________________ State: _________ Zip Code: _____________
Daytime Phone: ________________ Fax: _____________ Email: __________________________________
For inverter-controlled system, meets IEEE Standards and UL 1741 Inverters, Converters, and
Yes
No
Controllers for use in Independent Power Systems as set forth in the Rule:
For induction or synchronous device, meets IEEE Standard 1547 and IEEE/ANSI Standard C37.90
Yes
No
requirements as set forth in the Rule:
If Photovoltaic System, System must be installed in compliance with IEEE Standards, Recommended Practice
for Utility Interface of Photovoltaic Systems. All System types must be installed in compliance with applicable
requirements of local electrical codes, Rocky Mountain Power and the National Electrical Code® (NEC) and
must use an anti-islanding inverter.
The System must include a manual, lockable, load-break (disconnect) switch, unless exempt under Rule 746312-4(2), accessible at all times to Rocky Mountain Power personnel and located within 10 feet of Rocky
Mountain Power’s meter. The disconnect switch may be located more than 10 feet from Rocky Mountain
Power’s meter if permanent instructions are posted at the meter indicating the precise location of the disconnect
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 4 - Level 2
Utah Level 2
Page 23 of 25
switch. Rocky Mountain Power must approve the location of the disconnect switch prior to the installation of
the net metering facility.
If the Net Metering Facility is designed to provide uninterruptible power to critical loads, either through energy
storage, back-up generator, or the generation source, the Net Metering Facility will include a parallel blocking
scheme for this backup source. This function may be integral to the inverter manufacturer’s packaged system.
Does the Net Metering Facility include a parallel blocking scheme:
Yes
No
Signed (Contractor): ______________________________________ Date: _____________
Name (Print): _______________________________________________
Section 4. To be completed by Rocky Mountain Power:
A.
If approving the application:
Rocky Mountain Power does not, by approval of this Application, assume any responsibility or liability
for damage to property or physical injury to persons. Further, this Application does not constitute a
dedication of the owner's System to Rocky Mountain Power electrical system equipment or facilities.
Customer entered into an Interconnection and Net Metering Service Agreement with Rocky Mountain
Power on the ____ day of _____, 20__.
Customer satisfactorily passed Witness Tests on the ___ day of ________, 20___
(Rocky Mountain Power may waive Witness Tests at its option; if tests are waived initial here ______).
This Application is approved by Rocky Mountain Power on this _____ day of ______________, 20__
Rocky Mountain Power Representative Name (Print): ______________________________________
Signed (Rocky Mountain Power Representative): __________________________ Date: ___________
B. If denying the application:
This application is denied by Rocky Mountain Power on this _____ day of ____________, 20__ for the
following reason(s):__________________________________________________________________
Rocky Mountain Power Representative Name (Print): ______________________________________
Signed (Rocky Mountain Power Representative): ________________________ Date:____________
Applicant may submit a new application for Level 3 review.
Section 5. To be completed by Rocky Mountain Power Meterman
Customer Account No. __________________________________ Site ID No.: _______________________
Served from Facility Point No.: ________________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 4 - Level 2
Utah Level 2
Page 24 of 25
New Net Meter No.: ____________________________ Date net meter installed: ______________________
Manual disconnect location and permanent signage in place unless system is less than 10 kW:
Yes
No
Signature/Title: _________________________________________ Date: ___________________________
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 4 - Level 2
Utah Level 2
Page 25 of 25
We appreciate your interest in Rocky Mountain Power’s net metering program. Before
purchasing any net metering equipment, we recommend you review the requirements for
interconnecting a net metering system to Rocky Mountain Power’s electrical distribution system.
The requirements are found in the Interconnection Agreement.
To complete the process for a net metering interconnection, please follow the steps below:
1. Complete and submit the following to Rocky Mountain Power:
 Interconnection Agreement including the Application for Net Metering
Interconnection
 The inverter specification sheet
 For systems larger than 10 kW, a simple one-line diagram showing
• The location of Rocky Mountain Power’s meter
• The location of the disconnect switch
2. Rocky Mountain Power will review your agreement and application and send you a
written notification of approval either by mail or e-mail
3. Install the net metering system after you receive the written approval of your
Interconnection Agreement and Application for Net Metering from Rocky Mountain
Power
4. Obtain an inspection of your net metering system by the local city or county electrical
inspector
5. Submit the electrical inspector’s approval to Rocky Mountain Power
6. Turn on your net metering system after Rocky Mountain Power provides you written
notification the interconnection work has been completed and the net meter installed
Return completed documents to:
Rocky Mountain Power
Customer Generation
P.O. Box 25308
Salt Lake City, Utah 84125-0308
Or Email to:
[email protected]
Thank you for your interest in the net metering program. If you have questions, please call us toll
free at 1-888-221-7070 and ask for a net metering specialist.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 54 - Level 3
Page 1 of 27
Service ID#:___________
Request #: ___________
INTERCONNECTION AND NET METERING SERVICE AGREEMENT FOR NET
METERING FACILITY
LEVEL 3 INTERCONNECTION
UP TO 2 MW NAMEPLATE CAPACITY
This Interconnection and Net Metering Service Agreement (“Agreement”) is made and
entered into this ____ day of _____________, 20___, by and between
____________________________, an electric customer (“Customer”), and PacifiCorp, dba
Rocky Mountain Power (“Rocky Mountain Power”), a Corporation organized and existing under
the laws of the State of Oregon. Customer and Rocky Mountain Power each may be referred to
as a “Party”, or collectively as the “Parties”.
Recitals:
Whereas, Customer has installed or intends to install a Net Metering Facility qualifying
for “Net Metering,” Utah Rate Schedule No. 135A (“Schedule 135A”), as given in Rocky
Mountain Power’s currently effective tariff as filed with the Public Service Commission of Utah
(“Commission”), on or adjacent to Customer’s premises located at
____________________________, Utah, for the purpose of generating electric energy;
Whereas, the Net Metering rate schedule may be amended from time to time, and the
Public Service Commission may alter the charge, credit, and ratemaking structure applicable to
Net Metering customers pursuant to Utah Code § 54-15-105.1;
Whereas, Customer represents to Rocky Mountain Power that Customer either owns or
leases its Net Metering Facility qualifying for Schedule 135A, or meets the exemption
requirements set forth in Utah Code § 54-2-1.16(d) because it is a county, municipality, city, town,
other political subdivision, local district, special service district, state institution of higher
education, school district, charter school, or any entity within the state system of public education;
or an entity qualifying as a charitable organization under 26 U.S.C. Sec. 501(c)(3) operated for
religious, charitable, or educational purposes that is exempt from federal income tax and able to
demonstrate its tax-exempt status;
Whereas, Customer desires to interconnect the Net Metering Facility with Rocky
Mountain Power’s distribution system consistent with the Application completed by Customer
on _____________ ____, 20___, as described in as described in Appendix C (“Application”) of
this Agreement; and
Whereas, Customer, using its Net Metering Facility, intends to offset part or all of its
electrical requirements supplied by Rocky Mountain Power.
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Utah Form Ver. 3 54 - Level 3
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Now, therefore, in consideration of and subject to the mutual covenants contained herein, the
Parties agree as follows:
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Utah Form Ver. 3 54 - Level 3
Page 3 of 27
Article 1. Scope and Limitations of Agreement
1.1 Scope
The Agreement shall be used for all Level 3 Applications according to the procedures set
forth in Utah Administrative Rule R746-312, as may be amended from time to time
(“Rule”). The Rule can be viewed at www.psc.utah.gov. The Agreement establishes
standard terms and conditions approved by the Public Service Commission of Utah
(“Commission”) under which the Net Metering Facility with an Electric Nameplate
Capacity of 2 MW or smaller as described in Appendix C will interconnect to, and
operate in parallel with, Rocky Mountain Power’s system.
1.2 Definitions
Terms with initial capitalization, when used in this Agreement, shall have the meanings
indicated or as specified in the Rule Section R746-312-2 and, to the extent this Agreement
conflicts with the Rule, the Rule shall take precedence.
1.3 Other Agreements
Nothing in this Agreement is intended to affect any other agreement between Rocky
Mountain Power and Customer or any other Interconnection Customer. However, in the
event that the provisions of the Agreement are in conflict with the provisions of any Rocky
Mountain Power Tariff, as may be amended from time to time the Rocky Mountain Power
Tariff, as may be amended from time to time, shall control.
1.4 Responsibilities of the Parties
1.4.1 The Parties shall perform all obligations of the Agreement in accordance with all
applicable laws and regulations.
1.4.2 Customer will construct, own, operate, test, and maintain its Net Metering Facility
in accordance with the Agreement, IEEE Standards (available at the following
link: http://standards.ieee.org/index.html), National Electric Code Standards
(available for purchase at http://standards.ieee.org/faqs/NESCFAQ.html#q8), Utah
state building codes, the Rule (available at the following link:
http://www.dopl.utah.gov/programs/ubc/), and other applicable standards required
by the Commission, as may be amended from time to time.
1.4.3 Each Party shall be responsible for the safe installation, maintenance, repair and
condition of their respective lines and equipment on their respective sides of the
Point of Common Coupling. Each Party shall provide Interconnection Facilities that
adequately protect the other Party’s facilities, personnel and other persons from
damage and injury. The allocation of responsibility for the design,
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 54 - Level 3
Page 4 of 27
installation, operation, maintenance and ownership of Interconnection Facilities is
prescribed in the Rule, including but not necessarily limited to R746-312-4.
1.4.4
Customer is responsible for protecting the generating equipment, inverters,
protective devices, and other system components from damage from the normal and
abnormal conditions and operations that occur on Rocky Mountain Power’s system
in delivering and restoring power; and is responsible for ensuring that the Net
Metering Facility equipment is inspected, maintained, and tested in accordance
with the manufacturer’s instructions to ensure that it is operating correctly and
safely.
1.4.5 Customer shall obtain Rocky Mountain Power’s approval of the Application prior to
commencing parallel operation of its interconnected Net Metering Facility.
1.4.6 Customer is responsible for all costs associated with its Net Metering Facility.
1.5
Parallel Operation and Maintenance Obligations
Once the Net Metering Facility has been authorized to commence parallel operation by an
approved Application, and execution of this, Customer will abide by all written provisions
for operations and maintenance as required by the Rule and Rocky Mountain Power’s
tariffs, including but not necessarily limited to R746-312-4 and Schedule 135A or its
successor tariff(s).
1.6
Results of System Impact Study
Rocky Mountain Power completed a System Impact Study on_____________ ____,
20___. The System Impact Study shows the following minor modifications or substantial
modifications (Rocky Mountain Power to circle appropriate option) are necessary to
Customer’s Net Metering Facility prior to interconnecting with Rocky Mountain Power’s
system:
Description of necessary minor
modifications_____________________________________________________________
__________________________________________________________.
Rocky Mountain Power estimates, in good faith, that these minor modifications/
substantial modifications (Rocky Mountain Power to circle appropriate option) will cost
$__________. This is a non-binding estimate that will provide break down of
costs:___________________________________________________________________
___________________________________________________________ Customer shall
pay the actual installed cost of the minor modifications or substantial modifications
needed to interconnect the Net Metering Facility to Rocky Mountain Power’s system.
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 54 - Level 3
Page 5 of 27
1.7
Results of Interconnection Facilities Study << to be filled in upon completion of
Interconnection Facilities Study, if one is conducted. Otherwise, the text should read “This
Section intentionally left blank.”>>
Rocky Mountain Power completed a Facilities Study on _____________ ____, 20___.
The Facilities Study shows the following equipment, engineering, procurement and
construction work (including overheads) are necessary to implement the conclusion of
the System Impact Study for Customer’s Net Metering Facility to safely interconnect to
Rocky Mountain Power’s system and the time required to build and install those
facilities:
Rocky Mountain Power estimates, in good faith, that these modifications will cost
$______. This is a non-binding estimate for provide break down of
costs____________________________________________________________________
___________________________________________________________. Customer
shall pay the actual installed cost of the facilities needed to interconnect as identified in
the Facilities Study. Rocky Mountain Power estimates these facilities can be installed
by_____________ ____, 20___.
1.8
Metering
Rocky Mountain Power shall install, own and maintain, at its sole expense, a kilowatt-hour
meter(s) and associated equipment to measure the flow of energy in each direction, unless
otherwise authorized by the Commission. Customer shall provide, at its sole expense,
adequate facilities, including, but not limited to, a current transformer enclosure (if
required), meter socket(s) and junction box, for the installation of the meter and associated
equipment.
Customer hereby consents to the installation and operation by Rocky Mountain Power and
at Rocky Mountain Power’s expense, of one or more additional meters to monitor the flow
of electricity in each direction. Such meters shall be located on the premises of Customer.
1.9
Power Quality
Customer will design its Net Metering Facility to maintain a composite power delivery at
continuous rated power output at the Point of Common Coupling that meets the
requirements set forth in IEEE 1547, as required by the Rule, R746-312-4.
1.10
Net Metering Facility Inspection
1.10.1 Building Code Inspection
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 54 - Level 3
Page 6 of 27
Prior to operation in parallel with Rocky Mountain Power’s system, the Net
Metering Facility must be inspected by a local building code official to ensure
compliance with applicable local codes.
1.10.2 Inspection by Rocky Mountain Power
Rocky Mountain Power may inspect the Net Metering Facility and its component
equipment, and the documents necessary to ensure compliance with the Rule.
Customer shall notify Rocky Mountain Power prior to placing the Net Metering
Facility in service, and Rocky Mountain Power shall have the right to have
personnel present on the in-service date. If the Net Metering Facility is
subsequently modified in order to increase its gross power rating, Customer must
notify Rocky Mountain Power by submitting a new application specifying the
modifications in accordance with the level of review required for that application.
1.11
Anticipated Start Date
Customer must include an anticipated start date for operation of its Net Metering Facility
in the Application.
1.12
Net Metering Facility Testing and Maintenance
Customer shall conduct maintenance and testing as set forth in the Rule, including but not
necessarily limited to R746-312-14.
1.12.1 Customer shall conduct any manufacturer-recommended testing or maintenance at
its expense.
1.12.2 Customer shall conduct any post-installation testing, at its expense, necessary to
ensure compliance with IEEE standards as set forth in the Rule or to ensure safety.
This includes replacing a major equipment component that is different from the
originally installed model.
1.12.3 When Customer performs maintenance or testing in accordance with the Rule, it
must retain written records documenting the maintenance and results of the testing
for three (3) years.
1.12.4 Rocky Mountain Power shall have the right to inspect Customer’s Net Metering
Facility after interconnection approval is granted, at reasonable hours and with
reasonable prior notice to Customer. If Rocky Mountain Power discovers that the
Net Metering Facility is not in compliance with the Rule, Rocky Mountain Power
may require Customer to disconnect the Net Metering Facility until compliance is
achieved.
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Utah Form Ver. 3 54 - Level 3
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1.13
Removal of Facility
Customer shall immediately notify Rocky Mountain Power if Customer removes or ceases
to operate the Net Metering Facility.
Article 2.
2.1
Review, Inspection, Testing, Disconnect Switch and Signage, and Right of
Access
Review
After determining Customer’s interconnection request is complete, in accordance with the
Rule, R746-312-10, Rocky Mountain Power will conduct meetings and studies and provide
estimates set forth in the Rule, R746-312-10. Upon completion of the required studies and
receipt of agreement of the Customer to pay for required interconnection facilities and
upgrades, Rocky Mountain Power will approve the Interconnection request.
2.2
Equipment Testing and Inspection
Customer must notify Rocky Mountain Power of the anticipated testing and inspection date
of the Net Metering Facility at least ten (10) business days prior to testing, either through
submittal of the Agreement, a notice of completion, or in a separate notice. Within ten (10)
business days after receipt of such required documentation, Rocky Mountain Power will
conduct any required inspection or witness test of the Net Metering Facility, set the new
meter if required, approve the Interconnection, and provide written notification to the
Customer of the final interconnection authorization/approval and that the generating
facility is authorized/approved for parallel operation.
If Rocky Mountain Power and Customer, by mutual agreement, select a date for the
required inspection and/or witness testing which would prevent Rocky Mountain Power
from providing final written notice within ten (10) days of receipt of required
documentation as specified above, and if the Net Metering Facility satisfactorily passes the
required inspection and/or witness tests, Rocky Mountain Power shall notify Customer
within three (3) business days after the tests and/or inspections that either the
interconnection is approved and the Net Metering Facility may begin operation or the
interconnection facilities study identified necessary construction that has not been
completed, the date upon which the construction will be completed and the date when the
Net Metering Facility may begin operation or state any other reason why the
commissioning tests are not satisfactory.
If the witness tests are not satisfactory, Customer must resolve any deficiencies within sixty
(60) business days or other time period as mutually agreed by the Parties.
2.3
Disconnect Switch and Signage
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Utah Form Ver. 3 54 - Level 3
Page 8 of 27
Customer shall comply with the Rule regarding disconnect switches, R746-312-4. The
disconnect switch may be located more than 10 feet from the public utility meter if
permanent instructions in letters of appropriate size are posted at the meter indicating the
precise location of the disconnect switch. Rocky Mountain Power must approve in writing
the location of the disconnect switch prior to the installation of the Net Metering Facility.
2.4 Right of Access
As provided in the Rule, R746-312-4, Rocky Mountain Power shall have access to any
required disconnect switch at the Net Metering Facility at all times. Rocky Mountain Power
will provide reasonable notice to Customer when possible prior to using its right of access.
Additionally, as provided in Rocky Mountain Power Utah Rule 6, or its successor tariff,
Rocky Mountain Power shall have access to the metering equipment.
Article 3.
3.1
Effective Date, Term, Termination and Disconnection
Effective Date
The Agreement shall become effective upon execution by the Parties.
3.2
Term of Agreement
The Agreement will become effective on the Effective Date and will remain in effect unless
terminated in accordance with provisions of this Agreement, or Order by the Commission.
3.3
Termination
No termination will become effective until the Parties have complied with all applicable
laws and clauses of this Agreement applicable to such termination.
3.3.1
Customer may terminate this Agreement at any time by giving Rocky Mountain
Power twenty (20) business days written notice.
3.3.2
Either Party may terminate this Agreement after default pursuant to Article 5.4 of
this Agreement.
3.3.3
The Commission may Order termination of this Agreement.
3.3.4
Upon termination of this Agreement, Customer shall disconnect the Net Metering
Facility from Rocky Mountain Power’s system. The termination of this Agreement
will not relieve either Party of its liabilities and obligations, owed or continuing at
the time of termination.
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Utah Form Ver. 3 54 - Level 3
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3.4
3.3.5
If Customer removes the Net Metering equipment at the Net Metering Facility or
ceases to operate its Net Metering Facility at the premise listed in the Application,
this Agreement will be immediately terminated.
3.3.6
The provisions of this Article shall survive termination or expiration of this
Agreement.
Temporary Disconnection
3.4.1
Rocky Mountain Power may temporarily disconnect the Net Metering Facility from
Rocky Mountain Power’s system for so long as reasonably necessary without prior
notice to Customer in the event one or more of the following conditions or events
occurs:
3.4.1.1
Emergencies or to address maintenance requirements for Rocky
Mountain Power’s system.
3.4.1.2
Hazardous conditions existing on Rocky Mountain Power’s system
which may affect the safety of the general public or Rocky Mountain
Power employees due to the operation of the Net Metering Facility or
protective equipment as determined by Rocky Mountain Power.
3.4.1.3
Adverse electrical effects on the electrical equipment of Rocky
Mountain Power’s other electric customers caused by the Net Metering
Facility as determined by Rocky Mountain Power.
3.4.2
In the event that no disconnect switch is installed, Rocky Mountain Power may
physically disconnect all service to the Customer or all service to the premises
where the Net Metering Facility is located, or both.
3.4.3
To the extent practicable, Rocky Mountain Power will give prior notice of any
temporary disconnection of the Net Metering Facility. If Rocky Mountain Power
is unable to give prior notice, Rocky Mountain Power will provide notice
including an explanation of the condition necessitating the disconnection at the
time of disconnection.
3.4.4
Under emergency conditions, Rocky Mountain Power shall notify Customer
promptly when Rocky Mountain Power becomes aware of an emergency
condition that may reasonably be expected to affect the Net Metering operation.
Customer shall notify Rocky Mountain Power promptly when it becomes aware
of an emergency condition that may reasonably be expected to affect Rocky
Mountain Power’s system. To the extent the information is known, the
notification shall describe the emergency condition, the extent of any damage or
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 54 - Level 3
Page 10 of 27
deficiency, the expected effect on the operation of both Parties’ facilities and
operations, the anticipated duration, and the necessary corrective action.
3.4.5
Customer shall make reasonable efforts to provide notice of interruption of Net
Metering Facility operation for safety and/or reliability reasons prior to the
interruption unless an emergency occurs. Emergency interruptions or temporary
terminations are subject to Section 3.4.4 above.
3.4.6
Rocky Mountain Power shall use reasonable efforts to provide Customer with prior
notice of forced outages to effect immediate repairs to Rocky Mountain Power’s
system. If prior notice is not given, Rocky Mountain Power, shall, upon request,
provide Customer written documentation after the fact explaining the
circumstances of the disconnection.
3.4.7
Customer must provide Rocky Mountain Power notice and obtain Rocky Mountain
Power’s written approval before Customer may modify its Net Metering Facility in
order to increase the electric output of the Net Metering Facility. If Customer makes
any material change without prior written authorization of Rocky Mountain Power,
Rocky Mountain Power will have the right to temporarily disconnect the Net
Metering Facility until Rocky Mountain Power has had an opportunity to review
the change(s) made to determine whether they are acceptable. If any system
modifications or other equipment installations are deemed necessary by Rocky
Mountain Power to accommodate the modified Net Metering Facility, Customer
shall submit the appropriate net metering application at that time.
3.4.8
The Parties shall cooperate with each other to restore the Net Metering Facility,
Interconnection Facilities, and Rocky Mountain Power’s system to their normal
operating state as soon as reasonably practicable following any disconnection
pursuant to this section.
Article 4.
4.1
Cost Responsibility
Application Fee
Customer shall bear the cost of any Application fee provided for in the Rule, R746-31213(2), or as otherwise approved by the Commission. Customer shall remit payment with
the Application as calculated in Appendix C, the Application, Section 2.C.
4.2
Net Metering Facility and Interconnection Equipment
Customer shall be responsible for all costs, including overheads, associated with procuring,
installing, owning, operating, maintaining, repairing, and replacing its Net Metering
Facility, any associated equipment package, and any associated interconnection
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 54 - Level 3
Page 11 of 27
equipment or interconnection facilities required to be installed on Customer’s side of the
Point of Common Coupling as detailed in the results of the System Impact Study or
Facilities Study, or both.
4.3
Minor Modifications
This section shall apply if the System Impact Study performed pursuant to Section 1.6
above shows that minor modifications to the electric distribution system are required to
enable the interconnection to be made consistent with safety, reliability and power quality
standards applicable to Level 3 interconnection reviews. The Customer shall pay for the
cost to procure, install, and construct, operate, maintain, repair and replace any such
minor modifications. A description of the minor modifications may be found in Appendix
A. The cost of the minor modifications as described on Appendix A shall be $_______.
Customer shall remit payment for minor modifications prior to Rocky Mountain Power
commencing the work required for the minor modifications.
4.4
4.5
Substantial Modifications
4.4.1
This section shall apply if the System Impact Study performed pursuant to Section
1.6 above or the Facilities Study performed pursuant to Section 1.7 above, or
both, shows that substantial modifications to the electric distribution system are
required to enable the interconnection to be made consistent with safety,
reliability and power quality standards applicable to Level 3 interconnection
reviews. The Customer shall pay for the cost to procure, install, and construct,
operate, maintain, repair and replace any such substantial modifications. A
description of the substantial modifications may be found in Appendix B. The
cost of the substantial modifications as described on Appendix B shall be
$_______.
4.4.2
Before beginning substantial modifications to accommodate the interconnection of
the Net Metering Facility to Rocky Mountain Power’s system, Rocky Mountain
Power may require that Customer pay a deposit of not more than 50% of the
estimated cost of procuring, installing and constructing equipment and facilities to
be procured, installed or constructed by Rocky Mountain Power.
Payment
Rocky Mountain Power may require progress payments from Customer or Rocky
Mountain Power may wait until construction and installation of all equipment and facilities
are complete and the total actual cost of such equipment and facilities has been established
and then provide Customer with a statement indicating whether actual cost was more or
less than the deposit paid by Customer-Generator. If actual costs exceed the deposit, Rocky
Mountain Power will invoice Customer-Generator for the balance and
Rocky Mountain Power Interconnection and Net Metering Service Agreement
Utah Form Ver. 3 54 - Level 3
Page 12 of 27
Customer-Generator shall pay any such invoice within 30 days of receipt. If actual costs
are less than the deposit, Rocky Mountain Power will refund the difference to CustomerGenerator.
Article 5.
5.1
Billing
Monthly Billing
The electric service charge shall be computed in accordance with the monthly billing in the
currently applicable standard service tariff. Customer will be compensated for net excess
energy in accordance with Schedule 135A or its successor tariff(s). Customer will be
transitioned to any successor tariff immediately upon approval of that tariff by the Public
Service Commission and will be subject to any charge, credit, or ratemaking structure
implemented therein.
5.2
Special Conditions
Customer must comply with the special conditions found in Schedule 135A or its successor
tariff(s).
5.3
Aggregating Meters
Aggregating Meters is allowed if certain conditions are met under the Rule, R746-312-5.
Customer designates the following meters for aggregation: _______________________.
In the event that the Net Metering Facility supplies more electricity to Rocky Mountain
Power than the Customer uses from Rocky Mountain Power, Rocky Mountain Power will
apply any credits to the next monthly bill in accordance with Utah Code § 54-15-104 and
the Rule, R746-312-15. Customer shall designate the order in which to apply any credits
in accordance with the Rule. <<If customer does not want to aggregate, insert “N\A” in
the gray box.>>
Article 6.
6.1
Assignment, Liability, Indemnity, Force Majeure, Consequential Damages
and Default
Assignment
This Agreement may be assigned by either Party with the consent of the other Party. A
Party’s consent to an assignment may not be unreasonably withheld. The assigning Party
must give the non-assigning Party written notice of the assignment at least fifteen days (15)
before the effective date of the assignment. The non-assigning Party must submit its
objection to the assignment, if any, to the assigning Party in writing at least 5 business days
before the effective date of the assignment. If a written objection is not received within that
time period, the non-assigning party is deemed to consent to the assignment.
6.1.1
Exceptions to the Consent Requirement
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6.1.1.1 Either Party may assign the Agreement without the consent of the other
Party to any affiliate (including a merger or acquisition of the Party with
another entity), of the assigning Party with an equal or greater credit rating
and with the legal authority and operational ability to satisfy the obligations
of the assigning Party under this Agreement.
6.1.1.2 Customer-Generator is entitled to assign the Agreement, without the
consent of Rocky Mountain Power, for collateral security purposes to aid in
obtaining financing for the Net Metering Facility.
6.1.1.3 For Net Metering systems that are integrated into a building facility, the sale
of the building or property will result in the automatic assignment of this
Agreement to the new owner who will be responsible for complying with
the terms and conditions of this Agreement.
6.1.2
6.2
Any attempted assignment that violates this Article is void and ineffective.
Assignment does not change or eliminate a Party’s obligations under this
Agreement. An assignee is responsible for meeting the same obligations as the
assigning Party.
Limitation of Liability and Consequential Damages
Each Party’s liability to the other Party for any loss, cost, claim, injury, liability, or expense,
including reasonable attorney’s fees, relating to or arising from any act or omission in its
performance of this Agreement, is limited to the amount of direct damage actually incurred.
Neither Party is liable to the other Party for any indirect, special, consequential, or punitive
damages.
6.3
Indemnification
Customer shall hold harmless and indemnify Rocky Mountain Power for all loss to third
parties resulting from the operation of the Net Metering Facility, except when the loss
occurs due to the negligent actions of Rocky Mountain Power.
Rocky Mountain Power shall hold harmless and indemnify Customer for all loss to third
parties resulting from the operation of Rocky Mountain Power’s system, except where the
loss occurs due to the negligent actions of Customer.
6.4 Force Majeure
6.4.1
As used in this Agreement, a Force Majeure Event shall mean “any act of God,
labor disturbance, act of the public enemy, war, acts of terrorism, insurrection, riot,
fire, storm or flood, explosion, breakage or accident to machinery or equipment
through no direct, indirect, or contributory act of a Party, any order,
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regulation, or restriction imposed by governmental, military or lawfully established
civilian authorities, or any other cause beyond a Party’s control. A Force Majeure
Event does not include an act of negligence or wrongdoing.”
6.4.2
6.5
If a Force Majeure Event prevents a Party from fulfilling any obligations under this
Agreement, the Party affected by the Force Majeure Event (“Affected Party”) shall
promptly notify the other Party of the existence of the Force Majeure Event. The
notification must specify in reasonable detail the circumstances of the Force
Majeure Event, the expected duration, and the steps that the Affected Party is taking
to mitigate the effects of the event on its performance, and if the initial notification
was verbal, it should be promptly followed up with a written notification. The
Affected Party shall keep the other Party informed on a continuing basis of
developments relating to the Force Majeure Event until the event ends. The
Affected Party will be entitled to suspend or modify its performance of obligations
under this Agreement (other than the obligation to make payments) only to the
extent that the effect of the Force Majeure Event cannot be reasonably mitigated.
The Affected Party will use reasonable efforts to resume its performance as soon
as possible. The Parties shall immediately report to the Commission should a Force
Majeure Event prevent performance of an action required by Rule that the Rule
does not permit the Parties to mutually waive.
Default
6.5.1
A Party is in default if the Party fails to perform an obligation required under this
Agreement (other than the payment of money). A Party is not considered in default
of this agreement if the failure to perform an obligation is caused by an act or
omission of the other Party or is the result of a Force Majeure as defined in this
Agreement.
6.5.2
Upon a default, the non-defaulting Party must give written notice of the default to
the defaulting party. The defaulting party has sixty (60) calendar days from the
receipt of the written default notice to cure the default. If the default is not capable
of cure within the 60-day period, the defaulting Party must begin to cure the default
within twenty (20) calendar days after receipt of the written default notice, and must
continuously and diligently complete the cure within six (6) months of the receipt
of the notice.
6.5.3
If a default is not cured as provided for in 6.5.2, then the non-defaulting Party is
entitled to terminate the Agreement by written notice at any time until cure occurs.
If the non-defaulting Party chooses to terminate this Agreement, the termination
provisions in Article 3.3 apply. Alternately, the non-defaulting Party is entitled to
seek dispute resolution with the Commission in lieu of termination.
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Article 7.
Insurance
Additional liability insurance is not required as a part of the Agreement if the Net Metering Facility
is in compliance with the provisions of the Application approval, the Agreement and the standards
contained in Utah Code § 54-15-106.
Article 8.
Dispute Resolution
8.1
Nothing in this Article shall restrict the rights of any Party to file a Complaint with the
Commission under relevant provisions of the Rule and applicable state law.
8.2
Pursuit of dispute resolution may not affect Customer with regard to consideration of an
Interconnection Request or Customer’s queue position.
Article 9.
9.1
Miscellaneous
Governing Law, Regulatory Authority and Rules
The validity, interpretation, and enforcement of this Agreement is governed by the laws of
the State of Utah. If any provision of this Agreement conflicts with any applicable
provision, as may be amended from time to time, of the Utah Code (“Code”), Utah
Administrative Rules (“Rules”), or Rocky Mountain Power’s Tariffs (“Tariff”), then the
applicable provision of the Code, Rules, or Tariff controls. Rocky Mountain Power must
provide copies of the applicable provisions of the Code, Rules, and Tariff upon the
Customer’s request.
9.2
Amendment
Additions, deletions or changes to the standard terms and conditions of this Agreement will
not be permitted unless they are mutually agreed to by the Parties and permitted by the
Rule or permitted by the Commission for good cause shown. The Parties may amend the
Agreement by a written instrument duly executed by both Parties in accordance with the
provisions of the Rule and applicable Commission Orders and provisions of the laws of the
State of Utah.
9.3
No Third Party Beneficiaries
The Agreement is not intended to and does not create rights, remedies, or benefits of any
character whatsoever in favor of any persons, corporations, associations, or entities other
than the Parties, and the obligations herein assumed are solely for the use and benefit of
the Parties, or where permitted, their successors in interest or their assigns.
9.4
Waiver
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9.5
9.4.1
The failure of a Party to the Agreement to insist, on any occasion, upon strict
performance of any provision of the Agreement, will not be considered a waiver of
any obligation, right, or duty of, or imposed upon, such Party.
9.4.2
The Parties may agree to mutually waive a Section of this Agreement without the
Commission’s approval in accordance with the Rule.
9.4.3
Any waiver at any time by either Party of its rights with respect to the Agreement
shall not be deemed a continuing waiver or a wavier with respect to any other failure
to comply with any other obligation, right, or duty of the Agreement. Termination
or default of this Agreement for any reason by Customer shall not constitute a
waiver of the Customer’s legal rights to obtain interconnection from Rocky
Mountain Power. Any request for waiver of the Agreement or any provisions
thereof shall be provided in writing.
Entire Agreement
The Agreement, including any supplementary attachments that may be necessary,
constitutes the entire Agreement between the Parties with reference to the subject matter
hereof, and supersedes all prior and contemporaneous understandings or agreements, oral
or written, between the Parties with respect to the subject matter of the Agreement. There
are no other agreements, representations, warranties, or covenants that constitute any part
of the consideration for, or any condition to, either Party’s compliance with its obligations
under the Agreement.
9.6
Multiple Counterparts
This Agreement may be executed in one or more counterparts, whether electronically or
otherwise, each of which is deemed an original but all constitute one and the same
instrument.
9.7
No Partnership
The Agreement will not be interpreted or construed to create an association, joint venture,
agency relationship, or partnership between the Parties or to impose any partnership
obligation or partnership liability upon either Party. Neither Party shall have any right,
power or authority to enter into any agreement or undertaking for, or act on behalf of, or to
act as or be an agent or representative of, or to otherwise bind, the other Party.
9.8
Severability
If any provision or portion of the Agreement shall for any reason be held or adjudged to be
invalid or illegal or unenforceable by any court of competent jurisdiction or other
governmental authority, (1) such portion or provision shall be deemed separate and
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independent, (2) the Parties shall negotiate in good faith to restore insofar as practicable
the benefits to each Party that were affected by such ruling, and (3) the remainder of the
Agreement shall remain in full force and effect.
9.9
Subcontractors
Nothing in the Agreement shall prevent a Party from using the services of any
subcontractor, or designating a third party agent as one responsible for a specific obligation
or act required in the Agreement (collectively subcontractors), as it deems appropriate to
perform its obligations under the Agreement; provided, however, that each Party will
require its subcontractors to comply with all applicable terms and conditions of the
Agreement in providing such services and each Party will remain primarily liable to the
other Party for the performance of the subcontractor.
9.10
9.9.1
The creation of any subcontract relationship shall not relieve the hiring Party of any
of its obligations under the Agreement. The hiring Party shall be fully responsible
to the other Party for the acts or omissions of any subcontractor the hiring Party
hires as if no subcontract had been made. Any applicable obligation imposed by the
Agreement upon the hiring Party shall be equally binding upon, and will be
construed as having application to, any subcontractor of such Party.
9.9.2
The obligations under this Article will not be limited in any way by any limitation
of a subcontractor’s insurance.
Reservation of Rights
Rocky Mountain Power shall have the right to make a unilateral filing with the Commission
to modify this Agreement with respect to any rates, terms and conditions, charges,
classifications of service, rule, regulation or any other applicable provision of the Federal
Power Act and the Commission’s rules and regulations thereunder, and Customer shall
have the right to make a unilateral filing with Commission to modify this Agreement under
any applicable provision of the Federal Power Act and the Commission’s rules and
regulations; provided that each Party shall have the right to protest any such filing by the
other Party and to participate fully in any proceeding before the Commission in which such
modifications may be considered. Nothing in this Agreement shall limit the rights of the
Parties, except to the extent that the Parties otherwise agree as provided herein.
Article 10.
10.1
Notices and Records
General
Unless otherwise provided in the Agreement, any written notice, demand, or request
required or authorized in connection with the Agreement shall be deemed properly given
if delivered in person, delivered by recognized national courier service, sent by first class
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mail, postage prepaid, or by electronic mail if an electronic mail address is provided below
to the person specified below:
If to Customer:
Customer: ______________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: ________________________________ State: _________________ Zip: ________
Phone: (___) _______________________ Fax: (____) ___________________________
Email: __________________________________________________________________
If to Rocky Mountain Power:
By Mail:
Rocky Mountain Power
Attention: Net Metering Group
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
Or
By email:
[email protected]
10.2
Records
Rocky Mountain Power will maintain a record of all Interconnection Agreements and
related Attachments, if any, for as long as the interconnection is in place. Rocky Mountain
Power will provide a copy of these records to Customer within fifteen (15) Business Days
upon written request.
10.3
Billing and Payment
Billings and payments shall be sent to the addresses below (complete if different from
Section 9.1 above):
If to Customer:
Customer: ______________________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: _______________________________ State: _______________ Zip: ___________
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10.4
Designated Operating Representative
The Parties will designate an operating representative each to conduct the communications
that may be necessary or convenient for the administration of the operations provisions of
the Agreement. This person will also serve as the point of contact with respect to operations
and maintenance of the Party’s facilities (complete if different from Section 9.1 above):
Customer’s Operating Representative:
Name: __________________________________________________________________
Attention (if applicable): ___________________________________________________
Address: ________________________________________________________________
City: ______________________________ State: ________________ Zip: ___________
Phone: (____) _______________________ Fax: (____) __________________________
Email: __________________________________________________________________
10.5
Changes to the Notice Information
Either Party may change this notice information by giving five (5) business days written
notice prior to the effective date of the change.
Article 11.
Signatures
IN WITNESSETH WHEREOF, the Parties have caused the Agreement to be executed by their
respective duly authorized representatives.
For the Customer:
For Rocky Mountain Power:
By: _____________________________
By: _____________________________
Name: ___________________________
Name: ___________________________
Title: ____________________________
Title: ____________________________
Date: ____________________________
Date: ____________________________
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Appendix A
Minor Modifications
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Appendix B
Substantial Modifications
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APPENDIX C
ROCKY MOUNTAIN POWER UTAH NET METERING APPLICATION
LEVEL 3 REVIEW
CAPACITY OF 2 MW OR LESS
Section 1: For Rocky Mountain Power Use Only
Customer Name: _________________________________________________________________________
Service Address: _________________________________________________________________________
City, State, Zip: ___________________________________________________________________________
Customer Account No. and Request No.: _______________________________________________________
Interconnection Agreement Acknowledgement (Date): ____________________________________________
Application fee: $______________________________ Date Paid ___________________________________
Section 2: To Be Completed By Customer
A. Applicant Information
Name: ___________________________________________________________________________
Mailing Address: __________________________________________________________________
City: __________________________________________State: _________ Zip Code: ____________
Site Street Address (if different from above): _____________________________________________
City: __________________________________________State: __________ Zip Code: ___________
Daytime Phone: (_____) ________________________ Fax: (_____) __________________________
Email: ____________________________________________________________________________
B. System Information
System Type:
Solar
Wind
Hydro
Other (Specify): _________________________
Generation Nameplate Capacity: ______________ kW (Combine DC total of wind turbines, solar
panels, etc. or AC rating if an inverter is not utilized)
Inverter Manufacturer: ___________ Model: ________ Number of Inverters: _____ Rating: _____ kW
Manufacturer Nameplate Inverter Total AC Capacity Rating: _________ kW
Inverter(s):
Single Phase
Three Phase
Multiple Single Phase Connected on Poly-phase
(three phase) system – (Attach Inverter and Panel Technical Specifications Sheets)
Type:
Induction
Type of Service:
Inverter
Single Phase
Synchronous
__________________Other
Three Phase
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If Three Phase Transformer:
Indicate Type:
Wye
Delta
Indicate Voltage and Number of Service Wires:
120/208 Volts, 4 wire 120/240 Volts, 4 wire 277/480 Volts, 4 wire
Other ___________
________________________________________________________________________________
Other Information:__________________________________________________________________
_________________________________________________________________________________
Self Contained Location: ____________________________________________________________
Outdoor Manual AC Disconnect Switch Location (show Disconnect Switch and Rocky Mountain
Power Meter Location on Site Plan), unless exempt under Utah Administrative Rule 746-312-4(2):
__________________________________________________________________________________
System Location (show all protective devices on One Line Diagram):___________________________
Will the net metering facility interconnect to a switchgear?
Yes
No
Customer must post metal or plastic engraved signage indicating on-site generation in accordance with
National Electric Code. The signage must be permanent and located adjacent to the meter base and
disconnect switch noting “Parallel Generation on Site” and identifying the manual disconnect switch
with the words “Manual Disconnect for Parallel Generation.” _____ (Initial Here)
One Line Diagram Attached:
Installation Test Plan attached:
Yes
Yes
No
Site Plan Attached:
Yes
No
No
Anticipated Operational Date of Net Metering Facilities: _____________________________________
(Rocky Mountain Power must be notified at least ten (10) business days prior to starting operation.)
Net metering facility available fault duty at the point of common coupling: ________________
(A Rocky Mountain Power Engineer may contact you for additional information)
Electrical Inspection approval date (attach copy or provide to utility when obtained):__________
C. Application Fees
$ 100.00 Base
+ $ __________
$ __________
$2.00 x _____ kW of net metering facility’s capacity
TOTAL APPLICATION FEE
D. Additional Information
1.
An equipment package will be considered certified for interconnected operation if it has been
submitted by a manufacturer to a nationally recognized testing and certification laboratory, and
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2.
3.
4.
5.
6.
7.
has been tested and listed by the laboratory for continuous interactive operation with an electric
distribution system in compliance with the applicable IEEE and UL 1741 standards, as set forth
in the Rule.
If the equipment package has been tested and listed as an integrated package, which includes a
generator or other electric source, the equipment package will be deemed certified, and Rocky
Mountain Power will not require any further design review, testing or additional information.
If the equipment package includes only the interface components (switchgears, inverters, or
other interface devices), an interconnection applicant must show that the generator or other
electric source being utilized with the equipment package is compatible with the equipment
package and consistent with the testing and listing specified for the package. If the generator or
electric source being utilized with the equipment package is consistent with the testing and
listing performed by the nationally recognized testing and certification laboratory, the equipment
package will be deemed certified and Rocky Mountain Power will not require further design
review, testing or additional equipment.
A net metering facility must be equipped with metering equipment that can measure the flow of
electricity in both directions, comply with ANSI C12.1 standards and Utah Administrative Rule
R746-312. Rocky Mountain Power will install the required metering equipment at Rocky
Mountain Power’s expense.
Rocky Mountain Power will not be responsible for the cost of determining the rating of
equipment owned by the customer-generator or of equipment owned by other local customers.
Customer may operate the Net Metering Facility temporarily for testing and obtaining inspection
approval. Customer shall not operate the Net Metering Facility in continuous parallel without an
executed Interconnection and Net Metering Service Agreement, and approval from Rocky
Mountain Power.
Customer will pay to Rocky Mountain Power at the time of application the applicable
Application fee of $100.00 plus $2.00 per kilowatt of the net metering facility’s capacity; and
costs of modifications or additional review as set forth in Utah Administrative Rule R746-312
prior to commencement of work.
E. Customer Acknowledgment
I certify that the information provided in this Application is true. I will provide Rocky Mountain Power a
copy of the signed government electrical inspection approval document when obtained, if not already
provided with this Application.
I agree to abide by the terms of this Application and I agree to notify Rocky Mountain Power thirty (30)
days prior to modification or replacement of the System’s components or design. Any such modification
or replacement may require submission of a new Application to Rocky Mountain Power.
I agree not to operate the Net Metering Facility in parallel with Rocky Mountain Power, except
temporarily for testing and obtaining inspection approval, until this Application is approved by Rocky
Mountain Power, until this agreement is signed by both parties, and until I have provided Rocky
Mountain Power with at least five (5) days notice of anticipated start date.
Customer or Applicant Signature & Date: ____________________________________
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Please send completed application to:
Rocky Mountain Power
Attention: Customer Generation
P.O. Box 25308
Salt Lake City, UT 84125-0308
Phone: (888) 221-7070
or
Please scan the completed application and email
[email protected]
Section 3. To be completed by System Installer
Installation Contractor Information/Hardware and Installation Compliance
Installation Contractor (Company Name): _______________________________________________________
Contractor's License No.: ____________________________ Proposed Installation Date: _________________
Mailing Address: __________________________________________________________________________
City: ____________________________________________ State: __________ Zip Code: _______________
Daytime Phone: _________________ Fax: _________________Email: ______________________________
For inverter-controlled system, meets IEEE Standards and UL 1741 Inverters, Converters, and
Controllers for use in Independent Power Systems as set forth in the Rule:
Yes
No
For induction or synchronous device, meets IEEE Standard 1547 and IEEE/ANSI Standard C37.90 requirements
Yes
No
as set forth in the Rule:
If Photovoltaic System, System must be installed in compliance with IEEE Standards, Recommended Practice
for Utility Interface of Photovoltaic Systems. All System types must be installed in compliance with applicable
requirements of local electrical codes, Rocky Mountain Power and the National Electrical Code® (NEC) and
must use an anti-islanding inverter.
The System must include a manual, lockable, load-break (disconnect) switch, unless exempt under Utah
Administrative Rule 746-312-4(2), accessible at all times to Rocky Mountain Power personnel and located
within 10 feet of Rocky Mountain Power’s meter. The disconnect switch may be located more than 10 feet from
Rocky Mountain Power’s meter if permanent instructions are posted at the meter indicating the precise location
of the disconnect switch. Rocky Mountain Power must approve the location of the disconnect switch prior to the
installation of the net metering facility.
If the Net Metering Facility is designed to provide uninterruptible power to critical loads, either through energy
storage, back-up generator, or the generation source, the Net Metering Facility will include a parallel blocking
scheme for this backup source. This function may be integral to the inverter manufacturer’s packaged system.
Does the Net Metering Facility include a parallel blocking scheme:
Yes
No
Signed (Contractor): ________________________________________ Date: _________________
Name (Print): _______________________________________________
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Section 4. To be completed by Rocky Mountain Power:
A. If approving the application:
Rocky Mountain Power does not, by approval of this Application, assume any responsibility or liability
for
damage to property or physical injury to persons. Further, this Application does not constitute a
dedication of the owner's System to Rocky Mountain Power electrical system equipment or facilities.
Customer-Generator entered into an Interconnection and Net Metering Service Agreement with Rocky
Mountain Power on the ____ day of _____, 20__.
Customer-Generator satisfactorily passed Witness Tests on the ____ day of _________, 20__.
(Rocky Mountain Power may waive Witness Tests at its option; if tests are waived initial here ____)
This Application is approved by Rocky Mountain Power on this ______ day of ______________, 20__
Rocky Mountain Power Representative Name (Print): _______________________________________
Signed (Rocky Mountain Power Representative): ________________________ Date: ____________
B. If denying the application:
This application is denied by Rocky Mountain Power on this ______ day of ____________, 20__ for
the following reason(s): _______________________________________________________________
Rocky Mountain Power Representative Name (Print): _______________________________________
Signed (Rocky Mountain Power Representative): ___________________________ Date: __________
Section 5. To be completed by Rocky Mountain Power Meterman
Customer Account No. ______________________________ Site ID No. : ___________________________
Served from Facility Point No.: ________________________________
New Net Meter No.: ___________________________ Date net meter installed: _______________________
Manual disconnect device in proper location and permanent signage in place:
Yes
No
Signature/Title: ________________________________________ Date: ____________________________
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