William M. Dudley
Lead - Assistant General Counsel
1800 Larimer St., Street, 11th Floor
Denver, CO 80202
Phone: 303.294.2842
Fax: 303.204.2852
Email: [email protected]
.
October 30, 2015
Ms. Kimberly D. Bose
Secretary
Federal Energy Regulatory Commission
Room 1A-East
888 First Street, N.E.
Washington, D.C. 20426
Re:
Public Service Company of Colorado
Xcel Energy Operating Companies Joint Open Access Transmission Tariff – First
Revised Volume No. 1
Proposed Tariff Revisions for Joint Dispatch Transmission Service
Docket No. ER16-___-000
Dear Ms. Bose:
Pursuant to Section 205 of the Federal Power Act (“FPA”), 16 U.S.C. § 824d, and Section
35.13 of the Federal Energy Regulatory Commission’s (“Commission” or “FERC”) regulations, 18
C.F.R. § 35.13 (2015), Xcel Energy Services Inc. (“XES”), 1 on behalf of Public Service Company
of Colorado (“PSCo”)2 hereby submits for filing revised tariff sheets to the Xcel Energy Operating
Companies Joint Open Access Transmission Tariff (“Xcel Energy OATT”) to facilitate the Joint
Dispatch Agreement (“JDA”), submitted to the Commission in a contemporaneous filing. PSCo
respectfully requests an effective date of January 1, 2016, for the enclosed revisions.
PSCo, Platte River Power Authority (“PRPA”), and Black Hills Colorado Electric Utility
Company, LP (“BHCE”) (collectively, the “Parties”) have entered into the JDA to provide the
Parties with a centralized, coordinated, intra-hour dispatch system for their generation resources,
1
XES is the service company subsidiary of Xcel Energy Inc., the holding company parent of PSCo and the
other Xcel Energy Operating Companies, namely, Northern States Power Company, a Minnesota corporation,
Northern States Power Company, a Wisconsin corporation (together the “NSP Companies”), and Southwestern
Public Service Company (“SPS”). As such, XES makes filings with, and appears in proceedings before, the
Commission on behalf of the Xcel Energy Operating Companies.
2
PSCo is the designated e-Tariff filing entity for the Xcel Energy OATT, consistent with the requirements of
Order No. 714.
Ms. Kimberly Bose
October 30, 2015
Page 2 of 10
with the overall goal of achieving more efficient and lower cost generation to serve the combined
participating load requirements within the PSCo Balancing Authority Area (“BAA”). In this filing,
PSCo proposes revision to the Xcel Energy OATT to provide the Parties with a form of non-firm
transmission service entitled Joint Dispatch Transmission Service (“JDTS”), which will be used to
deliver the energy dispatched under the JDA across the PSCo transmission system.
The Commission has previously considered a prior version of the JDA as well as revisions
to the Xcel Energy OATT to implement the transmission service for the JDA. The Commission
rejected the filings in an order issued on June 23, 2015, in Docket Nos. ER15-237-000, et al. Pub.
Serv. Co of Colorado, et al., 151 FERC ¶ 61,248 (2015) (“June Order”). In light of the guidance
provided in the June Order, the Parties have renegotiated the JDA to address the Commission’s
concerns that led to the rejection of the filings.
I.
INTRODUCTION
PSCo is a direct subsidiary of Xcel Energy, a holding company that primarily engages in
the production, transmission and distribution of electricity and the distribution of natural gas
through its four utility subsidiaries: PSCo, SPS and the NSP Companies. PSCo generates,
transmits and distributes electric power and energy throughout portions of the State of Colorado.
PSCo provides electric service to approximately 1.3 million wholesale and retail customers in
Colorado. The Company's greatest concentration of retail customers is in the Denver
metropolitan area.
PSCo is located at the eastern edge of the Western Interconnection and is a member of
the Western Electricity Coordinating Council (“WECC”). PSCo is the Transmission Provider
for the PSCo transmission system. PSCo provides Network Integration Transmission Service
(“NITS”) and Point-to-Point Transmission Services and derives rates for such services pursuant
to Attachment O-PSCo of the Xcel Energy OATT, on file with the Commission pursuant to
Order Nos. 888 3 and 890. 4
PSCo has collaborated with the other Parties to establish the JDA in order to realize cost
savings through a centralized system of energy dispatch within the PSCo BAA. The overarching
goal of joint dispatch is to achieve efficiencies through the collaborative use of the Parties’
3
See Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by
Public Utilities and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, 61 Fed. Reg. 21,540
(1996), FERC Stats. & Regs. ¶ 31,036 (1996) (Order No. 888), order on reh'g, Order No. 888-A, 62 Fed. Reg.
12,274 (1997), FERC Stats. & Regs. ¶ 31,048 (1997), order on reh'g, Order No. 888-B, 62 Fed. Reg. 64,688, 81
FERC ¶ 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part sub nom.
Transmission Access Policy Study Group, et al. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom., New York
v. FERC, 535 U.S. 1 (2002).
4
See Preventing Undue Discrimination and Undue Preference in Transmission Service, Order No. 890,
FERC Stats. & Regs. ¶ 31,241, order on reh’g, Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007), order on
reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh’g, Order No. 890-C, 126 FERC ¶ 61,228 (2009),
order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).
Ms. Kimberly Bose
October 30, 2015
Page 3 of 10
generation resources. The purpose of the instant filing is to establish tariff provisions for the
terms and conditions of JDTS, the corresponding non-firm transmission service to the Parties for
the delivery of energy under the JDA.
II.
COMMUNICATIONS
PSCo requests that all correspondence, communications, and service related to this filing
be directed to the following individuals 5:
Terri K. Eaton
Director, Federal Regulatory/Compliance
Xcel Energy Services Inc.
1800 Larimer Street
Denver, CO 80202
Tel: (303) 571-7112
Email: [email protected]
Floyd L. Norton IV
Joseph W. Lowell
Morgan, Lewis & Bockius LLP
1111 Pennsylvania Ave, N.W.
Washington, D.C. 20004
Tel: (202) 739-5620/5384
Email: [email protected]
[email protected]
Robert Staton
Control Center Manager
Xcel Energy Services Inc.
18201 West 10th Ave.
Golden, CO 80401
Tel: (303) 273-4797
Email: [email protected]
William M. Dudley
Lead - Assistant General Counsel
Xcel Energy Services Inc.
1800 Larimer Street, 11th Floor
Denver, CO 80202
Tel: (303) 294-2842
[email protected]
Daniel Ahrens
Standards of Conduct / Fed. Reg. Manager
Xcel Energy Services Inc.
1800 Larimer Street, 14th Floor
Denver, CO 80202
Tel: (303) 571-6428
Email: [email protected]
Peter Colussy
Manager, Market Operations
Xcel Energy Services Inc.
1800 Larimer, Suite 10
Denver, CO 80202
Tel: (303) 808-2607
Email: [email protected]
III.
DESCRIPTION OF PROPOSED REVISIONS
A.
5
Background
XES respectfully requests waiver of 18 C.F.R. § 385.203(b)(3) to permit the designation of more than two
individuals to receive service related to this filing.
Ms. Kimberly Bose
October 30, 2015
Page 4 of 10
The Parties developed the JDA in order to achieve efficiencies through the collaborative use
of generation resources within the PSCo BAA. The JDA and tariff revisions provide an alternative
mechanism to effectively manage the difference between scheduled and actual load, which is
currently managed in the PSCo BAA through Energy Imbalance services under Schedule 4 of the
Xcel Energy OATT. PSCo balances the system after taking into account the committed resources
from each customer that were determined prior to the start of the hour. Under joint economic
dispatch facilitated by the JDA and Joint Dispatch Transmission Service, participating generation
resources will be dispatched, subject to available transmission as described below, in the most
economic order to achieve this balance. The JDA will facilitate the real-time optimization of
generation dispatch decisions between the Parties and allocate the lowest cost generation available
in real-time to serve native load requirements. Overall, the JDA will result in an organized and
cost-effective means for the Parties to meet their own native load requirements within the PSCo
BAA.
The transmission service necessary for the JDA dispatch over the PSCo transmission system
is JDTS. The joint economic dispatch of the pooled generation resources will occur intra-hour and
will utilize Available Transfer Capability (“ATC”) that is otherwise unused after the scheduling
hour is closed; this non-firm ATC will supply the transfer capability for JDTS.
On November 1, 2014, PSCo filed the JDA in Docket No. ER15-326-000 and associated
revisions to the Xcel Energy OATT in Docket No. ER15-237-000. BHCE filed revisions to
implement JDTS under its OATT in Docket No. ER15-295-000, on October 31, 2014. BHCE also
submitted a concurrence filing to the JDA on November 5, 2014, in Docket No. ER15-348-000.
Motions to intervene or protest were filed by a number of parties. Commission staff issued letters
requesting additional information on December 16, 2014, and March 16, 2015. PSCo provided the
requested information in filings on January 15, 2015, and April 24, 2015, respectively.
In the June Order, the Commission rejected the filings of the JDA and associated tariff
revisions to implement JDTS on two grounds. First, the Commission concluded that PSCo had not
shown that the JDA’s payment structure would result in rates that are just and reasonable because
the payment structure of the JDA may create the conditions for the exercise of market power by
PSCo, which does not have market-based rate authority in the PSCo BAA. 6 Specifically, the
Commission found that because PSCo proposed to compensate generating resources based on the
System Marginal Price,7 “PSCo’s own units would be compensated at a ceiling rate derived from
the most expensive MW required to serve the aggregate loads of the Parties, instead of at cost-based
rates.”8
6
June 23 Order at P 99.
7
Under the JDA, joint dispatch energy is priced at “System Marginal Price,” which is the incremental cost of
the next most economic MW of electricity capable of being generated by a Party’s Dispatchable Unit.
8
June 23 Order at P 99.
Ms. Kimberly Bose
October 30, 2015
Page 5 of 10
Second, the Commission concluded that market-sensitive operational pricing information
the Participants would provide to PSCo may grant PSCo’s marketing function access to non-public
information that is restricted under the Standards of Conduct.9 The Commission also explained that
many of its concerns would be addressed if – instead of the PSCo marketing function – another
division of PSCo “that would be prohibited from being a conduit for sharing non-public
transmission information with PSCo’s [marketing] function” had responsibility for the dispatch
service under the JDA.10
On July 23, 2015, XES requested rehearing of these two findings of the June Order. Among
other things, XES explained that it was currently exploring the feasibility of revising aspects of the
JDA to meet the concerns in the June Order and that an expedited decision by the Commission on
rehearing would assist the JDA parties in their negotiations.11 On August 24, 2015, the
Commission issued a tolling order extending the time by which it must act on this rehearing request,
but has not yet issued a final order on the rehearing request. As described more fully in XES’s
contemporaneous filing of the revised JDA, the Parties have renegotiated the JDA to address the
Commission’s concerns that led to the rejection of the filings. Although as a practical matter the
JDA will no longer raise the concerns expressed in the June Order, XES believes that the policy
issues discussed in its request for rehearing remain important and are not mooted by this filing.
To address the concerns of the June Order, the JDA has been revised to provide that all of
PSCo’s sales under the JDA will be capped at the cost-based rates on file with the Commission in
PSCo’s Electric Coordination Services Tariff. This revision is intended to eliminate concerns that
the JDA will provide PSCo with the “flexibility of a market-based rate” and thereby allow PSCo to
exercise market power.12 Furthermore, the JDA has been revised to provide for a web portal, where
JDA members will input unit cost information used for dispatch under the JDA, and which will be
restricted to only authorized personnel. PSCo marketing function employees will not have access to
unit economic data of JDA participants, but only the resulting dispatch.
In the June Order, the Commission’s rejection of the JDA-related filings was based upon the
concerns it identified with the JDA’s structure; however, the Commission did not identify concerns
with the OATT revisions filed by XES to complement the JDA. Thus, with a modified JDA that
addresses the Commission’s concerns, XES submits revisions to the Xcel Energy OATT to
implement JDTS that are similar to the ones previously filed in Docket No. ER15-237-000.
B.
The Enclosed Revisions to the Xcel Energy OATT
9
Id. at P 100.
10
Id. at P 101.
11
Public Service Company of Colorado, Request for Rehearing, Docket Nos. ER15-237-003, et al, at pp. 1314 (Jul. 23, 2015).
12
June 23 Order at P 99.
Ms. Kimberly Bose
October 30, 2015
Page 6 of 10
The revisions to implement JDTS under the Xcel Energy OATT include a new Article V
(sections 40-43) setting forth the terms and conditions of the service, a new Schedule 15
specifying the rate for JDTS (i.e., $0), and a new form of service agreement for JDTS located in
Attachment V. JDTS and the revisions to the Xcel Energy OATT are discussed more fully in the
accompanying testimony of Ms. Terri K. Eaton.
1.
JDTS Terms and Conditions
JDTS is a non-firm transmission product provided only on an “as-available” basis for the
sole purpose of facilitating energy transfers under the JDA. JDTS is the lowest priority
transmission service, with a lower priority than other non-firm transmission service under the
Xcel Energy OATT. JDTS will only utilize non-firm ATC within the operating hour that is
otherwise unused—capability that is not being compensated currently. If there is no posted nonfirm ATC after all other procurement and scheduling deadlines for other service have passed, no
JDA transactions will occur because JDTS will not be available.
JDTS is open to other entities aside from PSCo, PRPA, and BHCE. Specifically, other
similarly-situated entities may become Parties to the JDA and take JDTS if those entities meet
the conditions for service. In order to be an eligible customer to take JDTS, an entity must:
•
Be a load serving entity within the PSCo BAA;
•
Execute the JDA with each participating transmission provider;
•
Offer generating resources that meet the dispatch criteria into the JDA pool;
•
Secure an agreement with its host transmission provider to provide corresponding
non-firm, zero rate transmission service for use by other Parties to the JDA.
If these conditions are met, a prospective JDA customer need only submit an application
to obtain JDTS. Due to the non-firm nature of JDTS, prospective JDA customers will not need
to arrange for transmission studies prior to taking JDTS.
JDTS is only to be used by load serving entities to serve their native load within the
PSCo BAA. It is not to be used as a substitute for point-to-point transmission service or NITS,
and it cannot be used for off-system sales of capacity or energy for providing direct or indirect
transmission service to a third party. For off-system purchases and sales, JDTS customers must
ensure point-to-point transmission service has been obtained, as needed, to import purchases
from outside the PSCo BAA, or to export off-system sales, in accordance with FERC
regulations.
2.
JDTS Charges
PSCo proposes to offer JDTS at a zero rate to eligible customers and no additional
transmission charges will be assessed for the receipt or delivery of energy dispatched pursuant to
the JDA. Although there is no nominal rate for the service, JDA Parties must engage in a
Ms. Kimberly Bose
October 30, 2015
Page 7 of 10
transmission exchange of JDTS on the systems where they are located with other JDA Parties. If
the prospective customer is not a transmission service provider, it must arrange with its
transmission service provider to make JDTS available on the transmission service provider’s
system in order to accommodate JDA transactions.
There are several reasons for the nominal zero price for JDTS. First, the zero price is
consistent with the low priority nature of the service as JDTS will only utilize non-firm ATC
within the operating hour that is otherwise unused by other transmission customers. Second,
each JDA Party already must maintain adequate firm network and point-to-point service on the
transmission system where it is located in the amount of its entire wholesale and retail native
load. With a zero rate, JDTS will function as a zonal or license-plate service, in which the
customer will not be responsible for additional charges beyond those it is already bearing for
transmission facilities located within its zone.
As a “license-plate” service for energy imbalance, JDTS is supported by the
Commission’s decisions on the Energy Imbalance Market (“EIM”) in the West. In Docket No.
ER14-1386-000, the Commission conditionally approved a proposal by California Independent
System Operator (“CAISO”) to facilitate the Energy Imbalance Market (“EIM”) outside of the
CAISO footprint. PacifiCorp was one of the first participants and filed revisions to its OATT in
Docket No. ER14-1578-000 to allow it to participate in the EIM. In that case, FERC
conditionally accepted PacifiCorp’s OATT revisions, but specifically rejected PacifiCorp’s
proposal to require participating resources in the EIM in PacifiCorp’s BAA to pay for additional
transmission service charges beyond what they already pay as transmission customers on
PaciCorp’s OATT. In this respect, PacifiCorp’s proposal was in conflict with CAISO’s proposal
to waive wheeling access charges for EIM exports from CAISO to PacifiCorp. As the
Commission explained:
PacifiCorp’s proposal to charge for transmission service in association
with participation in the EIM is in conflict with the proposal by CAISO to
have reciprocal transmission rates for the EIM, which we accept in the
concurrently issued order on CAISO’s EIM proposal. CAISO proposes to
assess transmission charges only in the BAA where the EIM energy sinks.
In the CAISO BAA, load, which will include EIM Transfers originating in
PacifiCorp, will continue to pay the CAISO transmission access charge;
however, CAISO proposes to waive its wheeling access charge, normally
charged on exports from CAISO, on EIM Transfers to PacifiCorp. If
PacifiCorp requires EIM resources to purchase transmission service to
participate in the EIM then that cost of transmission will be included in the
energy bids of those resources. 13
13
PacifiCorp, 147 FERC ¶ 61,227 at P 146 (2014).
Ms. Kimberly Bose
October 30, 2015
Page 8 of 10
JDTS pricing is similar to CAISO’s proposal in that there will be a $0 rate charged for
transmission service of JDA energy from the source system and this service will be provided
reciprocally among the JDA participants, who are all located in the PSCo BAA.
Finally, as noted above, although the nominal price for JDTS is zero, JDA Parties must
enter into a reciprocal transmission exchange among each other to provide the necessary JDTS to
accommodate JDA transactions. The Commission has previously recognized that transmission
exchanges are a form of “in-kind” compensation for transmission service. 14 Transmission
exchanges provide the most efficient means to accomplish the necessary transmission for JDA
transactions. The alternative of imposing express transmission fees for JDTS would eliminate
the benefits offered under the JDA to the native loads of the JDA Parties.
Charges for power losses will continue to be the responsibility of the JDTS Customer,
and these charges will be paid for each transmission system across which the JDA energy is
transferred. In other words, energy transactions delivered across two different systems will be
assessed losses by both of those systems. JDTS customers also will continue to be responsible
for ancillary service charges, with the exception of Schedule 4 (energy imbalance) and Schedule
9 (generator imbalance). Imbalance charges under Schedules 4 and 9 will become moot because
PSCo will serve as the scheduling and dispatch authority under the JDA, and will thus be
responsible for balancing the combined load and participating resources of all the Parties.
3.
Impacts to Existing Customers
PSCo expects that existing customers will not be impacted by the implementation of
JDTS. Operationally, JDTS will only utilize non-firm ATC within the operating hour that is
otherwise unused by other transmission customers. JDA transactions will not be allowed to
exceed the available ATC after all other firm and non-firm transmission scheduling deadlines
have passed.
During the proceedings in Docket Nos. ER15-237-000, et al., certain parties questioned
whether JDTS would result in a reduction in revenue credits from non-firm transmission service
to PSCO’s firm transmission customers. There is no reason to conclude that any such reduction
would occur. Parties to the JDA are required to have available sufficient resources to serve load
plus reserves for every hour under the JDA. In advance of the intra-hour dispatch under the
JDA, parties will not know whether their resources will be dispatched up or down in real-time.
Therefore, parties will continue to look for opportunities to lower their dispatch costs through
economic purchases. Parties will also look for opportunities to lock in margins from economic
sales. Transmission will have to be procured for both economic purchases and sales—just as it is
today.
While PSCo expects all JDA parties to continue to engage in economic purchases and
sales just as they do today, even if that were not the case and the JDA Parties no longer utilized
14
See, e.g., Central Iowa Power Cooperative, Inc. v. FERC, 606 F.2d 1156, 1172 (D. C. Cir. 1979).
Ms. Kimberly Bose
October 30, 2015
Page 9 of 10
the non-firm transmission service provided by each other, the total impact to the revenues
generated by non-firm transmission service under the Xcel Energy OATT would be de minimis.
As Ms. Eaton explains in her testimony, the non-firm transmission revenue credits resulting from
non-firm transmission service to BHCE and PRPA are less than $20,000 annually. Even if all of
the non-firm revenues PSCo receives from PRPA and BHCE were to disappear due to the JDA,
the resulting loss of revenue credits for PSCo’s firm transmission service customers would have
a de minimis impact on their rates.
IV.
PROPOSED EFFECTIVE DATE AND REQUEST FOR WAIVERS
XES requests that the proposed tariff revisions be accepted for filing effective January 1,
2016, and that the Commission waive its prior notice requirements to permit the filing of the
enclosed tariff revisions less than sixty days prior to the requested effective date. 15 Pursuant to
its regulations, the Commission will grant waiver of the prior notice requirements where good
cause is shown. 16 Good cause exists here to grant waiver in this case. The enclosed tariff
revisions have no effect on existing rates, as discussed above, justifying a waiver of the prior
notice requirements. 17 Moreover, in advance of the filing – on October 1, 2015 – PSCo posted a
copy of the filing for its transmission customers’ review.
XES also respectfully requests waiver of any other requirements of the Commission’s rules
and regulations, as well as any authorizations as may be necessary or required, to permit the revised
rates to be accepted by the Commission and made effective in the manner proposed herein.
V.
CONTENTS OF FILING
Pursuant to 18 C.F.R. § 35.12(a) and 18 C.F.R. § 35.28(f)(1), this filing consists of the
following documents:
VI.
•
This transmittal letter;
•
Revisions to the Xcel Energy OATT in eTariff format;
•
Attachment A: Testimony of Terri K. Eaton
SERVICE AND POSTING
An electronic copy or notice of this filing will be served on all transmission service
customers of PSCo taking service under the Xcel Energy OATT and the Public Utilities
Commission of Colorado.
15
18 C.F.R. § 35.3(a) (2015).
16
18 C.F.R. § 35.11 (2015).
17
Central Hudson Gas & Electric Corp. et al., 60 FERC ¶ 61,106, reh'g denied, 61 FERC ¶ 61,089 (1992).
Ms. Kimberly Bose
October 30, 2015
Page 10 of 10
In advance of this filing, on October 1, 2015, PSCo posted a copy of the attached testimony
and tariff sheets on its OASIS site, available to its transmission customers for their review.
Pursuant to 18 C.F.R. § 35.2(d), a copy of this filing will be available for public inspection
at the offices of Xcel Energy – Transmission Services at 414 Nicollet Mall – MP8, Minneapolis,
Minnesota 55401, and at the offices of PSCo at 1800 Larimer Street, Denver, CO 80202. A copy of
this filing will also be posted at PSCo’s OASIS site.
VII.
CONCLUSION
XES sincerely appreciates the Commission's prompt attention to this matter. Please direct
any questions regarding this filing to the undersigned. Thank you.
Sincerely,
/s/ William M. Dudley
William M. Dudley
Attachments
CERTIFICATE OF SERVICE
I, Tracee J. Holte, hereby certify that I have this day served a notice of the enclosed
document filing via electronic mail on each party designated on the attached Service List.
Dated at Minneapolis, Minnesota this 30th day of October, 2015.
/s/ Tracee J. Holte
Tracee J. Holte,
Senior Business Analyst
Xcel Energy Services Inc.
414 Nicollet Mall - MP08
Minneapolis, MN 55401
Tel: 612-330-6206
[email protected]
Attachment - Clean Tariff Records
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
TABLE OF CONTENTS Version: 0.5.0 Effective 1/1/2016
TABLE OF CONTENTS
I.
COMMON SERVICE PROVISIONS
1
Definitions
1.1
Affiliate
1.2
Ancillary Services
1.3
Annual Transmission Costs
1.4
Application
1.5
Commission
1.6
Completed Application
1.7
Control Area
1.8
Curtailment
1.9
Delivering Party
1.10 Designated Agent
1.11 Direct Assignment Facilities
1.12 Eligible Customer
1.13 Facilities Study
1.14 Firm Point-To-Point Transmission Service
1.15 Good Utility Practice
1.16 Interruption
1.17 Load Ratio Share
1.18 Load Shedding
1.19 Long-Term Firm Point-To-Point Transmission Service
1.20 Native Load Customers
1.21 NERC TLR Procedures
1.22 Network Customer
1.23 Network Integration Transmission Service
1.24 Network Load
1.25 Network Operating Agreement
1.26 Network Operating Committee
1.27 Network Resource
1.28 Network Upgrades
1.29 Non-Firm Point-To-Point Transmission Service
1.30 Non-Firm Sale
1.31 Non-Variable Energy Resource
1.32 Open Access Same-Time Information System (OASIS)
1.33 Part I
1.34 Part II
1.35 Part III
1.35A Part IV
1.36 Parties
1.37 Point(s) of Delivery
1.38 Point(s) of Receipt
1.39 Point-To-Point Transmission Service
1.40 Power Purchaser
1.41 Pre-Confirmed Application
1.42 Receiving Party
1.43 Regional Transmission Group (RTG)
1.44 Reserved Capacity
Page No. 1
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
2
3
4
5
6
7
8
9
10
11
12
Page No. 2
1.45 Service Agreement
1.46 Service Commencement Date
1.47 Short-Term Firm Point-To-Point Transmission Service
1.48 System Condition
1.49 System Impact Study
1.50 Third-Party Sale
1.51 Transmission Customer
1.52 Transmission Provider
1.53 Transmission Provider's Monthly Transmission System Peak
1.54 Transmission Service
1.55 Transmission System
1.56 Variable Energy Resource
Initial Allocation and Renewal Procedures
2.1
Initial Allocation of Available Transfer Capability
2.2
Reservation Priority For Existing Firm Service Customers
Ancillary Services
3.1
Scheduling, System Control and Dispatch Service
3.2
Reactive Supply and Voltage Control from Generation or Other Sources
Service
3.3
Regulation and Frequency Response Service
3.4
Energy Imbalance Service
3.5
Operating Reserve - Spinning Reserve Service
3.6
Operating Reserve - Supplemental Reserve Service
3.7
Flex Reserve Service
3.8
Generator Imbalance Service
Open Access Same-Time Information System (OASIS)
4.1
Terms and Conditions
4.2
NAESB WEQ Business Practice Standards
Local Furnishing Bonds
5.1
Transmission Providers That Own Facilities Financed by Local Furnishing
Bonds
5.2
Alternative Procedures for Requesting Transmission Service
Reciprocity
Billing and Payment
7.1
Billing Procedure
7.2
Interest on Unpaid Balances
7.3
Customer Default
Accounting for the Transmission Provider's Use of the Tariff
8.1
Transmission Revenues
8.2
Study Costs and Revenues
Regulatory Filings
Force Majeure and Indemnification
10.1 Force Majeure
10.2 Indemnification
Creditworthiness
Dispute Resolution Procedures
12.1 Internal Dispute Resolution Procedures
12.2 Mediation Procedures
12.3 External Arbitration Procedures
12.4 Arbitration Decisions
12.5 Costs
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
12.6
II.
Page No. 3
Rights Under The Federal Power Act
POINT-TO-POINT TRANSMISSION SERVICE
Preamble
13
Nature of Firm Point-To-Point Transmission Service
13.1 Term
13.2 Reservation Priority
13.3 Use of Firm Transmission Service by the Transmission Provider
13.4 Service Agreements
13.5 Transmission Customer Obligations for Facility Additions or Redispatch
Costs
13.6 Curtailment of Firm Transmission Service
13.7 Classification of Firm Transmission Service
13.8.1 Scheduling of Firm Point-To-Point Transmission Service on the PSCo
System
13.8.2 Scheduling of Firm Point-To-Point Transmission Service on the NSP and
SPS Systems
14
Nature of Non-Firm Point-To-Point Transmission Service
14.1 Term
14.2 Reservation Priority
14.3 Use of Non-Firm Point-To-Point Transmission Service by the
Transmission Provider
14.4 Service Agreements
14.5 Classification of Non-Firm Point-To-Point Transmission Service
14.6.1 Scheduling of Non-Firm Point-To-Point Transmission Service on the
PSCo System
14.6.2 Scheduling of Non-Firm Point-To-Point Transmission Service on the NSP
and SPS Systems
14.7 Curtailment or Interruption of Service
15
Service Availability
15.1 General Conditions
15.2 Determination of Available Transfer Capability
15.3 Initiating Service in the Absence of an Executed Service Agreement
15.4 Obligation to Provide Transmission Service that Requires Expansion or
Modification of the Transmission System, Redispatch or Conditional
Curtailment
15.5 Deferral of Service
15.6 Other Transmission Service Schedules
15.7 Real Power Losses
16
Transmission Customer Responsibilities
16.1 Conditions Required of Transmission Customers
16.2 Transmission Customer Responsibility for Third-Party Arrangements
17
Procedures for Arranging Firm Point-To-Point Transmission Service
17.1 Application
17.2 Completed Application
17.3 Deposit
17.4 Notice of Deficient Application
17.5 Response to a Completed Application
17.6 Execution of Service Agreement
17.7 Extensions for Commencement of Service
18
Procedures for Arranging Non-Firm Point-To-Point Transmission Service
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
19
20
21
22
23
24
25
26
27
III.
Page No. 4
18.1 Application
18.2 Completed Application
18.3.1 Reservation of Non-Firm Point-To-Point Transmission Service on the
PSCo System
18.3.2 Reservation of Non-Firm Point-To-Point Transmission Service on the
NSP and SPS Systems
18.4 Determination of Available Transfer Capability
Additional Study Procedures For Firm Point-To-Point Transmission Service
Requests
19.1 Notice of Need for System Impact Study
19.2 System Impact Study Agreement and Cost Reimbursement
19.3 System Impact Study Procedures
19.4.1 Facilities Study Procedures
19.4.2 Clustered Transmission Service Requests
19.5 Facilities Study Modifications
19.6 Due Diligence in Completing New Facilities
19.7 Partial Interim Service
19.8 Expedited Procedures for New Facilities
19.9 Penalties For Failure to Meet Study Deadlines
Procedures if The Transmission Provider is Unable to Complete New
Transmission Facilities for Firm Point-To-Point Transmission Service
20.1 Delays in Construction of New Facilities
20.2 Alternatives to the Original Facility Additions
20.3 Refund Obligation for Unfinished Facility Additions
Provisions Relating to Transmission Construction and Services on the
Systems of Other Utilities
21.1 Responsibility for Third-Party System Additions
21.2 Coordination of Third-Party System Additions
Changes in Service Specifications
22.1 Modifications On a Non-Firm Basis
22.2 Modification On a Firm Basis
Sale or Assignment of Transmission Service
23.1 Procedures for Assignment or Transfer of Service
23.2 Limitations on Assignment or Transfer of Service
23.3 Information on Assignment or Transfer of Service
Metering and Power Factor Correction at Receipt and Delivery Points(s)
24.1 Transmission Customer Obligations
24.2 Transmission Provider Access to Metering Data
24.3 Power Factor
Compensation for Transmission Service
Stranded Cost Recovery
Compensation for New Facilities and Redispatch Costs
NETWORK INTEGRATION TRANSMISSION SERVICE
Preamble
28
Nature of Network Integration Transmission Service
28.1 Scope of Service
28.2 Transmission Provider Responsibilities
28.3 Network Integration Transmission Service
28.4 Secondary Service
28.5 Real Power Losses
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
29
30
31
32
33
34
Page No. 5
28.6 Restrictions on Use of Service
Initiating Service
29.1 Condition Precedent for Receiving Service
29.2 Application Procedures:
29.3 Technical Arrangements to be Completed Prior to Commencement of
Service
29.4 Network Customer Facilities
29.5 Filing of Service Agreement
Network Resources
30.1 Designation of Network Resources
30.2 Designation of New Network Resources
30.3 Termination of Network Resources
30.4 Operation of Network Resources
30.5 Network Customer Redispatch Obligation
30.6 Transmission Arrangements for Network Resources Not
Physically Interconnected With The Transmission Provider
30.7 Limitation on Designation of Network Resources
30.8 Use of Interface Capacity by the Network Customer
30.9 Network Customer Owned Transmission Facilities
Designation of Network Load
31.1 Network Load
31.2 New Network Loads Connected With the Transmission Provider
31.3 Network Load Not Physically Interconnected with the Transmission
Provider
31.4 New Interconnection Points
31.5 Changes in Service Requests
31.6 Annual Load and Resource Information Updates
Additional Study Procedures For Network Integration Transmission Service
Requests
32.1 Notice of Need for System Impact Study
32.2 System Impact Study Agreement and Cost Reimbursement
32.3 System Impact Study Procedures
32.4.1 Facilities Study Procedures
32.4.2 Clustered Transmission Service Requests
32.5 Penalties For Failure to Meet Study Deadlines
Load Shedding and Curtailments
33.1.1 Procedures on the PSCo System
33.1.2 Procedures on the NSP and SPS Systems
33.2 Transmission Constraints
33.3 Cost Responsibility for Relieving Transmission Constraints
33.4 Curtailments of Scheduled Deliveries
33.5 Allocation of Curtailments
33.6 Load Shedding
33.7 System Reliability
Rates and Charges
34.1.1 Monthly Demand Charge on the SPS Transmission System
34.1.2 Monthly Demand Charge on the PSCo Transmission System
34.2 Determination of Network Customer's Monthly Network Load
34.3 Determination of Network Customer’s Average Network Load on
the SPS System
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
Page No. 6
Determination of Transmission Provider's Monthly Transmission System
Load on the SPS Transmission System
34.5 Reserved For Future Use
34.6 Determination of Transmission Provider’s Average Transmission System
Load on the SPS Transmission System
34.7 Redispatch Charge
34.8 Stranded Cost Recovery
34.9 SPS Meter Charge
Operating Arrangements
35.1 Operation under The Network Operating Agreement
35.2 Network Operating Agreement
35.3 Network Operating Committee
34.4
35
IV.
BALANCING AUTHORITY ANCILLARY SERVICES
Preamble
36
Definitions
36.1 Ancillary Service Customer (ASC)
36.2 Ancillary Service Load
36.3 Balancing Authority Area (BAA)
36.4 Balancing Authority (BA) Operator
36.5 Balancing Authority (BA) Services
36.6 Internal Transmission Owner (ITO
36.7 Load Serving Entity (LSE)
36.8 Reserved Capacity
36.9 RMRG
36.10 WECC
37
Nature of Balancing Authority Services
37.1 Requirement to Provide and Obtain BA Services
37.2 Source and Acquisition of BA Services
37.3 Sufficiency of Balancing Authority Services
37.4 Real Power Losses
37.5 Service Agreements
37.6 No Transmission Service Provided
38
Authority and Obligations
38.1 BA Operator Authority
38.2 ASC Obligations
39
Metering
39.1 ASC Obligations
39.2 Metering Data
39.3 Testing
39.4 Meter Failure
39.5 Billing Adjustments
39.6 Examination of Records
39.7 BA Operator Access to Metering Data
40
Billing
V.
JOINT DISPATCH TRANSMISSION SERVICE (Applicable to Public Service
Company of Colorado only)
Preamble
41
Definitions
41.1 Joint Dispatch Arrangement
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
Page No. 7
Joint Dispatch Agreement
Joint Dispatch Transmission Service
Service Agreement for Joint Dispatch Transmission Service (“Service
Agreement”)
41.5 Joint Dispatch Transmission Service Customer
Nature of Joint Dispatch Transmission Service
42.1 Limited Transmission Provider Responsibilities
42.2 Real Power Losses
42.3 Restrictions on Use of Service
42.4 Imbalance Service
Initiating Service
43.1 Condition Precedent for Receiving Service
43.2 Application Procedures
43.3 Joint Dispatch Transmission Customer Facilities
43.4 Filing of Service Agreement
41.2
41.3
41.4
42
43
SCHEDULE 1 SCHEDULE 2 SCHEDULE 3 SCHEDULE 3A -
Scheduling, System Control and Dispatch Service
Reactive Supply and Voltage Control from Generation Sources Service
Regulation and Frequency Response Service
Regulation and Frequency Response Service for Point-To-Point
Transmission Service for the PSCo Balancing Authority Area
SCHEDULE 4 Energy Imbalance Service
SCHEDULE 4A Reserve Sharing Energy Charges
SCHEDULE 4B Reserve Sharing Energy Charges
SCHEDULE 5 Operating Reserve - Spinning Reserve Service
SCHEDULE 6 Operating Reserve - Supplemental Reserve Service
SCHEDULE 7 Long-Term Firm and Short-Term Firm Point-To-Point Transmission
Service
SCHEDULE 8 Non-Firm Point-To-Point Transmission Service
SCHEDULE 9 Generator Imbalance Service
SCHEDULE 10 Tax Adjustment Rider for Service by Southwestern Public Service
Company
SCHEDULE 11 Reserved For Future Use
SCHEDULE 12 Midwest Independent Transmission System Operator, Inc. Charges
SCHEDULE 13 Network Integration Transmission Service on the PSCo Transmission
System
SCHEDULE 13A Network Integration Transmission Service across the Lamar Tie Line
SCHEDULE 14 Point-to-Point Transmission Losses on the PSCo Transmission
System
SCHEDULE 15 Joint Dispatch Transmission Service
SCHEDULE 16 Flex Reserve Service
ATTACHMENT A-1 - Form of Service Agreement For Short-Term Firm Point-To-Point
Transmission Service
ATTACHMENT A-2 - Form of Service Agreement For Long-Term Firm Point-To-Point
Transmission Service
ATTACHMENT A-3 - Form of Service Agreement For The Resale, Reassignment Or Transfer
Of Point-To-Point Transmission Service
ATTACHMENT B - Form of Service Agreement For Non-Firm Point-To-Point Transmission
Service
ATTACHMENT C - Methodology To Assess Available Transfer Capability
ATTACHMENT D - Methodology for Completing a System Impact Study
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
ATTACHMENT E ATTACHMENT F -
Page No. 8
Index of Point-To-Point Transmission Service Customers
Form of Service Agreement For Network Integration Transmission
Service
ATTACHMENT G - Form of Network Operating Agreement
ATTACHMENT H - Annual Transmission Revenue Requirement For Network Integration
Transmission Service
ATTACHMENT I Index of Network Integration Transmission Service Customers
ATTACHMENT J - Procedures for Addressing Parallel Flows
ATTACHMENT K - Form of System Impact Study Agreement
ATTACHMENT L - Form of Facilities Study Agreement
ATTACHMENT M - Methodology for Allocating Transmission Revenues Among Utility
Operating Companies
ATTACHMENT N - Standard Large Generator Interconnection Procedures (LGIP) Applicable to Generating Facilities that exceed 20 MWs
ATTACHMENT O - Public Service Company of Colorado Formulaic Rates
ATTACHMENT O – SPS - Southwestern Public Service Company Formulaic Rates
ATTACHMENT P - Standard Small Generator Interconnection Procedures (SGIP) Applicable to Generating Facilities less than 20 MWs
ATTACHMENT Q - Creditworthiness Procedures
ATTACHMENT R – PSCo - Transmission Planning Process
ATTACHMENT S - Reserved For Future Use
ATTACHMENT T - Form of Service Agreement For Balancing Authority Ancillary Services
Applicable to the Public Service Company of Colorado (PSCo) System
ATTACHMENT U - Form of Service Agreement For Transmission to Load Interconnection
Service
ATTACHMENT V - Form of Service Agreement For Joint Dispatch Transmission Service
ATTACHMENT AA – Service Agreements For Point-To-Point Transmission Service
ATTACHMENT BB – Service Agreements For Network Transmission Service
ATTACHMENT CC – Service Agreements For Generation Interconnection Service
ATTACHMENT DD – Service Agreements For Balancing Authority Ancillary Services
ATTACHMENT EE - Reserved For Future Use
ATTACHMENT FF – Service Agreements For Transmission to Load Interconnection Service
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
Page No. 9
Additional Volumes of
Xcel Energy Operating Companies
Transmission Service Tariffs
Volume No.
Contents
Joint Open Access Transmission Tariff
Original Volume 2
Reserved for Future Use
FERC Electric Transmission Tariff
Original Volume 3
Northern States Power Company transmission rate
schedules
Original Volume 4
Northern States Power Company (Wisconsin) transmission
rate schedules
Original Volume 5
Public Service Company of Colorado transmission rate
schedules
Original Volume 6
Southwestern Public Service Company) transmission rate
schedules
Original Volume 7
WestConnect Point-to-Point Regional Transmission Service
Experiment Tariff
Note: The noted tariff volumes contain transmission-related rate schedules filed by the
Transmission Services function of the Xcel Energy Operating Companies.
Rate schedules related to electric supply services may be found in the Electric Services Tariffs
separately maintained by the Xcel Energy Markets function.
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
Page No. 1
Part V Joint Dispatch Trans Svc Version: 0.0.0 Effective 1/1/2016
V.
JOINT DISPATCH TRANSMISSION SERVICE (Applicable to Public Service
Company of Colorado only)
Preamble
Service under Part V shall be applicable only to load serving entities in the PSCo Balancing
Authority Area that are signatories to a Joint Dispatch Agreement (JDA) under which: (1)
participating generating resources of the parties are dispatched as a pool on a least-cost basis
respecting transmission limitations; (2) the Joint Dispatch Transmission Service Customers’
respective transmission service providers have provided within their OATT a transmission
service schedule for energy dispatched pursuant to the JDA at a rate equal to zero dollars on a
non-firm, as-available basis with the lowest curtailment priority, pursuant to the provisions of
this Part V of the Tariff.
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
Page No. 1
41 Definitions Version: 0.0.0 Effective 1/1/2016
41
Definitions
In addition to the Definitions and Terms set forth in the Common Service Provisions
found in Part 1 of this Tariff, the following definitions shall apply to this Part V, the Joint
Dispatch Services set forth in Schedule 15 and Attachment V of this Tariff.
41.1
Joint Dispatch Arrangement: An operating arrangement whereby participating
generation resources owned, operated or controlled by load serving entities
within the PSCo Balancing Authority Area are dispatched as a pool on a leastcost basis respecting transmission limitations in order to economically optimize
dispatch on an aggregate real-time basis among all participants in the Joint
Dispatch Arrangement.
41.2
Joint Dispatch Agreement: An agreement detailing the rights and obligations
of participants in a Joint Dispatch Arrangement.
41.3
Joint Dispatch Transmission Service: Non-firm transmission service across
transmission facilities of the Transmission Provider that is used to transmit
energy dispatched pursuant to a Joint Dispatch Agreement and that is subject to
the provisions of this Part V of the Tariff. Joint Dispatch Transmission Service
will be made available from posted ATC after procurement and scheduling
deadlines have passed for the current operating hour, as specified in the
Transmission Provider’s Business Practices posted on OASIS.
41.4
Service Agreement for Joint Dispatch Transmission Service (“Service
Agreement”): An agreement between the Transmission Provider and a Joint
Dispatch Transmission Service Customer for Joint Dispatch Transmission
Service.
41.5
Joint Dispatch Transmission Service Customer: Any entity (or its Designated
Agent) that: (i) executes a Service Agreement; or (ii) requests in writing that the
Transmission Provider file with the Commission a proposed unexecuted Service
Agreement.
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
Page No. 1
42 Nat of Joint Dispatch Trans Svc Version: 0.0.0 Effective: 1/1/2016
42
Nature of Joint Dispatch Transmission Service
Joint Dispatch Transmission Service is an optional service available to any load serving
entity in the PSCo Balancing Authority Area that: (1) has entered into a Joint Dispatch
Agreement; and (2) makes Joint Dispatch Transmission Service on its transmission
system, if any, available to PSCo and all other parties to the Joint Dispatch Agreement
at the same rate, terms, and conditions as set out in this Part V of the Tariff and related
schedules and attachments. As further detailed herein, Joint Dispatch Transmission
Service may only be used to deliver energy dispatched under a Joint Dispatch
Agreement to the entity’s wholesale and retail native load customers. Joint Dispatch
Transmission Service is provided only on a non-firm, as available basis and has the
lowest curtailment priority.
42.1
Limited Transmission Provider Responsibilities. The Transmission Provider
shall have the obligation to operate its Transmission System in accordance with
Good Utility Practice. For purposes of Joint Dispatch Transmission Service, the
Transmission Provider shall have no obligation to plan, construct, or maintain its
Transmission System for the benefit of any Joint Dispatch Transmission Service
Customer.
42.2
Real Power Losses. Real Power Losses are associated with all transmission
service. The Joint Dispatch Transmission Service Customer shall be responsible
for all losses associated with Joint Dispatch Transmission Service, which
responsibility shall be manifested as the difference between the amount of
energy dispatched on behalf of the Joint Dispatch Transmission Service
Customer and the amount of energy actually delivered to such customer based
on the following loss factors.
PRPA
Seller
Buyer
PRPA
PSCo
BHCE
PRPA
PRPA+PSCo
PSCo
BHCE
PSCo
PSCo+BHCE
BHCE
PSCo
Where:
PRPA= Loss Factor set forth in PRPA’s OATT Section 15.7
PSCo=Loss Factor set forth in PSCo OATT Section 15.7
BHCE= Loss Factor set forth in BHCE OATT Section 15.7
42.3
Restrictions on Use of Service. The Joint Dispatch Transmission Service
Customer shall not use Joint Dispatch Transmission Service for (i) off-system
sales of capacity or energy or (ii) direct or indirect provision of transmission
service by the Joint Dispatch Transmission Service Customer to any third party.
Joint Dispatch Transmission Service may be used only for receipt or delivery of
energy dispatched within the PSCo Balancing Authority Area on a non-firm basis
to serve wholesale or retail native load of any participant in a Joint Dispatch
Agreement.
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
42.4
Page No. 2
Imbalance Service. The purpose of the Joint Dispatch Arrangement is to
balance loads and resources of the parties by optimizing dispatch of the parties’
resources. As a result, the Transmission Provider shall not assess energy
imbalance charges under Ancillary Service Schedule 4 or 9 to any Joint Dispatch
Transmission Service Customer.
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
Page No. 1
43 Initiating Scv Version:0.0.0 Effective: 1/1/2016
43
Initiating Service
43.1
Condition Precedent for Receiving Service. Subject to the terms and
conditions of this Part V of the Tariff, and related schedules and attachments, the
Transmission Provider will provide Joint Dispatch Transmission Service to any
eligible customer, provided that (i) the eligible customer has wholesale or retail
native load in the Transmission Provider’s Balancing Authority area; (ii) the
eligible customer has entered into a Joint Dispatch Agreement; (iii) the eligible
customer’s transmission provider has a transmission service tariff offering Joint
Dispatch Transmission Service on the same terms and conditions as offered
under this Part V of the Tariff, and related schedules and attachments; and (iv)
the eligible customer executes a Service Agreement pursuant to Attachment V
for service under this Part V of the Tariff or requests in writing that the
Transmission Provider file a proposed unexecuted Service Agreement with the
Commission.
43.2
Application Procedures. An Eligible Customer requesting service under Part V
of this Tariff must submit an application containing the information specified
below. No deposit or credit evaluation is necessary to obtain Joint Dispatch
Network Transmission Service. Further, no transmission studies shall be
required to obtain Joint Dispatch Transmission Service because such service is
provided only on a non-firm, as available basis. Applications should be
submitted to the Transmission Provider via e-mail to the person(s) listed on
OASIS. Application contents:
(i)
(ii)
(iii)
(iv)
(v)
(vi)
(vii)
(viii)
The identity, address, telephone number and facsimile number of the
party requesting service;
A statement that the party requesting service is, or will be upon
commencement of service, an Eligible Customer under the tariff;
A statement that the party requesting service has, or will have upon
commencement of service, wholesale or retail native load in the PSCo
Balancing Authority;
A statement that the party requesting service has, or will have upon
commencement of service, entered into a Joint Dispatch Agreement with
PSCo;
A statement that the party requesting service has, or will have upon
commencement of service, a tariff offering Joint Dispatch Transmission
Service at the same rates, terms, and conditions as this Part V of the
Tariff and associated schedules and attachments;
Service Commencement Date and the term of the requested Joint
Dispatch Transmission Service;
A statement signed by an authorized officer from or agent of the Joint
Dispatch Transmission Service Customer attesting that Joint Dispatch
Transmission Service will be used only for receipt or delivery of energy
dispatched under a Joint Dispatch Agreement for the benefit of the
customer’s wholesale and retail native load customers;
Service is conditioned on the Transmission Service Provider being in
receipt of an executed Joint Dispatch Agreement.
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
Page No. 2
Unless the Parties agree to a different timeframe, the Transmission Provider
must acknowledge the request within ten (15) days of receipt.
The
acknowledgement must include a date by which a response, including a Service
Agreement, will be sent to the Eligible Customer. If an application fails to meet
the requirements of this section, the Transmission Provider shall notify the
Eligible Customer requesting service within fifteen (15) days of receipt and
specify the reasons for such failure. Wherever reasonably possible, the
Transmission Provider will attempt to remedy deficiencies in the Application
through informal communications with the Eligible Customer. If efforts are
unsuccessful, the Transmission Provider shall return the Application, without
prejudice to the Eligible Customer filing a new or revised Application that fully
complies with the requirements of this section.
43.3
Joint Dispatch Transmission Customer Facilities: The Joint Dispatch
Transmission Service Customer’s transmission provider will retain its existing
obligations to plan, construct, operate and maintain its transmission system using
standard utility practices.
43.4
Filing of Service Agreement. The Transmission Provider will file Service
Agreements with the Commission in compliance with applicable Commission
regulations, if any.
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
Page No. 1
15 Joint Dispatch Trans Svc Version: 0.0.0 Effective: 1/1/2016
Schedule 15
Joint Dispatch Transmission Service
This is an optional service provided by PSCo, subject to the terms and conditions of Part
V of this Tariff. For Joint Dispatch Transmission Service Customers meeting the
conditions set forth in Part V of this Tariff, no charge shall be assessed for receipt or
delivery of energy dispatched pursuant to a Joint Dispatch Agreement with PSCo
provided the customer makes Joint Dispatch Transmission Service available to PSCo at
the same rates, terms, and conditions as set forth in Part V of this Tariff, this Schedule
15, and any other related schedules or attachments to this Tariff. Joint Dispatch
Transmission Service is provided in real-time on a non-firm, as available basis having
the lowest curtailment priority.
1) Monthly delivery: the rate or $0.00/kW-month of Reserved Capacity.
2) Weekly delivery: the rate $0.00/kW-week of Reserved Capacity.
3) Daily delivery: the rate $0.00/kW-day of Reserved Capacity.
4) Hourly delivery: On-Peak Hours: the on-peak rate $0.00/MWh of Reserved Capacity.
Off-Peak Hours: the off-peak rate $0.00/MWh of Reserved Capacity.
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
Page No. 1
V Form of Svc Agrmt for Joint Dispatch Trans Version: 0.0.0 Effective: 1/1/2016
ATTACHMENT V
Form of Service Agreement For Joint Dispatch Transmission Service Applicable to the
Public Service Company of Colorado (PSCo) System
1.0
This
Joint
Dispatch
Transmission
Service
Agreement,
dated
as
of
__________________________,
is
entered
into,
by and between __________________________ (“Transmission Provider”),
and __________________________ ("Joint Dispatch Transmission Customer"),
all of whom may be referred to individually as “Party” or jointly as “Parties”.
2.0
The Joint Dispatch Transmission Customer has been determined by the Transmission
Provider to have a signed a Joint Dispatch Agreement.
3.0
Service under this agreement shall commence on the later of (1) the requested service
commencement date, or (2) such other date as it is permitted to become effective by the
Commission. Service under this agreement shall terminate on such date as mutually
agreed upon by the parties.
4.0
Any notice or request made to or by either Party regarding this Service Agreement shall
be made to the representative of the other Party as indicated below.
Transmission Provider:
_____________________________________
_____________________________________
_____________________________________
Transmission Customer:
_____________________________________
_____________________________________
_____________________________________
5.0
The Tariff is incorporated herein and made a part hereof.
Xcel Energy Operating Companies
FERC Electric Tariff, Second Revised Volume No. 1
Page No. 2
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by
their respective authorized officials.
Transmission Provider:
By:
___________________ ___________________ ___________________
Name
Title
Date
Transmission Customer:
By:
___________________ ___________________ ___________________
Name
Title
Date
Attachment - Marked Tariff records
TABLE OF CONTENTS
I.
COMMON SERVICE PROVISIONS
1
Definitions
1.1
Affiliate
1.2
Ancillary Services
1.3
Annual Transmission Costs
1.4
Application
1.5
Commission
1.6
Completed Application
1.7
Control Area
1.8
Curtailment
1.9
Delivering Party
1.10 Designated Agent
1.11 Direct Assignment Facilities
1.12 Eligible Customer
1.13 Facilities Study
1.14 Firm Point-To-Point Transmission Service
1.15 Good Utility Practice
1.16 Interruption
1.17 Load Ratio Share
1.18 Load Shedding
1.19 Long-Term Firm Point-To-Point Transmission Service
1.20 Native Load Customers
1.21 NERC TLR Procedures
1.22 Network Customer
1.23 Network Integration Transmission Service
1.24 Network Load
1.25 Network Operating Agreement
1.26 Network Operating Committee
1.27 Network Resource
1.28 Network Upgrades
1.29 Non-Firm Point-To-Point Transmission Service
1.30 Non-Firm Sale
1.31 Non-Variable Energy Resource
1.32 Open Access Same-Time Information System (OASIS)
1.33 Part I
1.34 Part II
1.35 Part III
1.35A Part IV
1.36 Parties
1.37 Point(s) of Delivery
1.38 Point(s) of Receipt
1.39 Point-To-Point Transmission Service
1.40 Power Purchaser
1.41 Pre-Confirmed Application
1.42 Receiving Party
1.43 Regional Transmission Group (RTG)
1.44 Reserved Capacity
2
3
4
5
6
7
8
9
10
11
12
1.45 Service Agreement
1.46 Service Commencement Date
1.47 Short-Term Firm Point-To-Point Transmission Service
1.48 System Condition
1.49 System Impact Study
1.50 Third-Party Sale
1.51 Transmission Customer
1.52 Transmission Provider
1.53 Transmission Provider's Monthly Transmission System Peak
1.54 Transmission Service
1.55 Transmission System
1.56 Variable Energy Resource
Initial Allocation and Renewal Procedures
2.1
Initial Allocation of Available Transfer Capability
2.2
Reservation Priority For Existing Firm Service Customers
Ancillary Services
3.1
Scheduling, System Control and Dispatch Service
3.2
Reactive Supply and Voltage Control from Generation or Other Sources
Service
3.3
Regulation and Frequency Response Service
3.4
Energy Imbalance Service
3.5
Operating Reserve - Spinning Reserve Service
3.6
Operating Reserve - Supplemental Reserve Service
3.7
Flex Reserve Service
3.8
Generator Imbalance Service
Open Access Same-Time Information System (OASIS)
4.1
Terms and Conditions
4.2
NAESB WEQ Business Practice Standards
Local Furnishing Bonds
5.1
Transmission Providers That Own Facilities Financed by Local Furnishing
Bonds
5.2
Alternative Procedures for Requesting Transmission Service
Reciprocity
Billing and Payment
7.1
Billing Procedure
7.2
Interest on Unpaid Balances
7.3
Customer Default
Accounting for the Transmission Provider's Use of the Tariff
8.1
Transmission Revenues
8.2
Study Costs and Revenues
Regulatory Filings
Force Majeure and Indemnification
10.1 Force Majeure
10.2 Indemnification
Creditworthiness
Dispute Resolution Procedures
12.1 Internal Dispute Resolution Procedures
12.2 Mediation Procedures
12.3 External Arbitration Procedures
12.4 Arbitration Decisions
12.5 Costs
12.6
II.
Rights Under The Federal Power Act
POINT-TO-POINT TRANSMISSION SERVICE
Preamble
13
Nature of Firm Point-To-Point Transmission Service
13.1 Term
13.2 Reservation Priority
13.3 Use of Firm Transmission Service by the Transmission Provider
13.4 Service Agreements
13.5 Transmission Customer Obligations for Facility Additions or Redispatch
Costs
13.6 Curtailment of Firm Transmission Service
13.7 Classification of Firm Transmission Service
13.8.1 Scheduling of Firm Point-To-Point Transmission Service on the PSCo
System
13.8.2 Scheduling of Firm Point-To-Point Transmission Service on the NSP and
SPS Systems
14
Nature of Non-Firm Point-To-Point Transmission Service
14.1 Term
14.2 Reservation Priority
14.3 Use of Non-Firm Point-To-Point Transmission Service by the
Transmission Provider
14.4 Service Agreements
14.5 Classification of Non-Firm Point-To-Point Transmission Service
14.6.1 Scheduling of Non-Firm Point-To-Point Transmission Service on the
PSCo System
14.6.2 Scheduling of Non-Firm Point-To-Point Transmission Service on the NSP
and SPS Systems
14.7 Curtailment or Interruption of Service
15
Service Availability
15.1 General Conditions
15.2 Determination of Available Transfer Capability
15.3 Initiating Service in the Absence of an Executed Service Agreement
15.4 Obligation to Provide Transmission Service that Requires Expansion or
Modification of the Transmission System, Redispatch or Conditional
Curtailment
15.5 Deferral of Service
15.6 Other Transmission Service Schedules
15.7 Real Power Losses
16
Transmission Customer Responsibilities
16.1 Conditions Required of Transmission Customers
16.2 Transmission Customer Responsibility for Third-Party Arrangements
17
Procedures for Arranging Firm Point-To-Point Transmission Service
17.1 Application
17.2 Completed Application
17.3 Deposit
17.4 Notice of Deficient Application
17.5 Response to a Completed Application
17.6 Execution of Service Agreement
17.7 Extensions for Commencement of Service
18
Procedures for Arranging Non-Firm Point-To-Point Transmission Service
19
20
21
22
23
24
25
26
27
III.
18.1 Application
18.2 Completed Application
18.3.1 Reservation of Non-Firm Point-To-Point Transmission Service on the
PSCo System
18.3.2 Reservation of Non-Firm Point-To-Point Transmission Service on the
NSP and SPS Systems
18.4 Determination of Available Transfer Capability
Additional Study Procedures For Firm Point-To-Point Transmission Service
Requests
19.1 Notice of Need for System Impact Study
19.2 System Impact Study Agreement and Cost Reimbursement
19.3 System Impact Study Procedures
19.4.1 Facilities Study Procedures
19.4.2 Clustered Transmission Service Requests
19.5 Facilities Study Modifications
19.6 Due Diligence in Completing New Facilities
19.7 Partial Interim Service
19.8 Expedited Procedures for New Facilities
19.9 Penalties For Failure to Meet Study Deadlines
Procedures if The Transmission Provider is Unable to Complete New
Transmission Facilities for Firm Point-To-Point Transmission Service
20.1 Delays in Construction of New Facilities
20.2 Alternatives to the Original Facility Additions
20.3 Refund Obligation for Unfinished Facility Additions
Provisions Relating to Transmission Construction and Services on the
Systems of Other Utilities
21.1 Responsibility for Third-Party System Additions
21.2 Coordination of Third-Party System Additions
Changes in Service Specifications
22.1 Modifications On a Non-Firm Basis
22.2 Modification On a Firm Basis
Sale or Assignment of Transmission Service
23.1 Procedures for Assignment or Transfer of Service
23.2 Limitations on Assignment or Transfer of Service
23.3 Information on Assignment or Transfer of Service
Metering and Power Factor Correction at Receipt and Delivery Points(s)
24.1 Transmission Customer Obligations
24.2 Transmission Provider Access to Metering Data
24.3 Power Factor
Compensation for Transmission Service
Stranded Cost Recovery
Compensation for New Facilities and Redispatch Costs
NETWORK INTEGRATION TRANSMISSION SERVICE
Preamble
28
Nature of Network Integration Transmission Service
28.1 Scope of Service
28.2 Transmission Provider Responsibilities
28.3 Network Integration Transmission Service
28.4 Secondary Service
28.5 Real Power Losses
29
30
31
32
33
34
28.6 Restrictions on Use of Service
Initiating Service
29.1 Condition Precedent for Receiving Service
29.2 Application Procedures:
29.3 Technical Arrangements to be Completed Prior to Commencement of
Service
29.4 Network Customer Facilities
29.5 Filing of Service Agreement
Network Resources
30.1 Designation of Network Resources
30.2 Designation of New Network Resources
30.3 Termination of Network Resources
30.4 Operation of Network Resources
30.5 Network Customer Redispatch Obligation
30.6 Transmission Arrangements for Network Resources Not
Physically Interconnected With The Transmission Provider
30.7 Limitation on Designation of Network Resources
30.8 Use of Interface Capacity by the Network Customer
30.9 Network Customer Owned Transmission Facilities
Designation of Network Load
31.1 Network Load
31.2 New Network Loads Connected With the Transmission Provider
31.3 Network Load Not Physically Interconnected with the Transmission
Provider
31.4 New Interconnection Points
31.5 Changes in Service Requests
31.6 Annual Load and Resource Information Updates
Additional Study Procedures For Network Integration Transmission Service
Requests
32.1 Notice of Need for System Impact Study
32.2 System Impact Study Agreement and Cost Reimbursement
32.3 System Impact Study Procedures
32.4.1 Facilities Study Procedures
32.4.2 Clustered Transmission Service Requests
32.5 Penalties For Failure to Meet Study Deadlines
Load Shedding and Curtailments
33.1.1 Procedures on the PSCo System
33.1.2 Procedures on the NSP and SPS Systems
33.2 Transmission Constraints
33.3 Cost Responsibility for Relieving Transmission Constraints
33.4 Curtailments of Scheduled Deliveries
33.5 Allocation of Curtailments
33.6 Load Shedding
33.7 System Reliability
Rates and Charges
34.1.1 Monthly Demand Charge on the SPS Transmission System
34.1.2 Monthly Demand Charge on the PSCo Transmission System
34.2 Determination of Network Customer's Monthly Network Load
34.3 Determination of Network Customer’s Average Network Load on
the SPS System
34.4
35
Determination of Transmission Provider's Monthly Transmission System
Load on the SPS Transmission System
34.5 Reserved For Future Use
34.6 Determination of Transmission Provider’s Average Transmission System
Load on the SPS Transmission System
34.7 Redispatch Charge
34.8 Stranded Cost Recovery
34.9 SPS Meter Charge
Operating Arrangements
35.1 Operation under The Network Operating Agreement
35.2 Network Operating Agreement
35.3 Network Operating Committee
IV.
BALANCING AUTHORITY ANCILLARY SERVICES
Preamble
36
Definitions
36.1 Ancillary Service Customer (ASC)
36.2 Ancillary Service Load
36.3 Balancing Authority Area (BAA)
36.4 Balancing Authority (BA) Operator
36.5 Balancing Authority (BA) Services
36.6 Internal Transmission Owner (ITO
36.7 Load Serving Entity (LSE)
36.8 Reserved Capacity
36.9 RMRG
36.10 WECC
37
Nature of Balancing Authority Services
37.1 Requirement to Provide and Obtain BA Services
37.2 Source and Acquisition of BA Services
37.3 Sufficiency of Balancing Authority Services
37.4 Real Power Losses
37.5 Service Agreements
37.6 No Transmission Service Provided
38
Authority and Obligations
38.1 BA Operator Authority
38.2 ASC Obligations
39
Metering
39.1 ASC Obligations
39.2 Metering Data
39.3 Testing
39.4 Meter Failure
39.5 Billing Adjustments
39.6 Examination of Records
39.7 BA Operator Access to Metering Data
40
Billing
V.
JOINT DISPATCH TRANSMISSION SERVICE (Applicable to Public Service
Company of Colorado only)
Preamble
41
Definitions
41.1 Joint Dispatch Arrangement
41.2
41.3
41.4
42
43
Joint Dispatch Agreement
Joint Dispatch Transmission Service
Service Agreement for Joint Dispatch Transmission Service (“Service
Agreement”)
41.5 Joint Dispatch Transmission Service Customer
Nature of Joint Dispatch Transmission Service
42.1 Limited Transmission Provider Responsibilities
42.2 Real Power Losses
42.3 Restrictions on Use of Service
42.4 Imbalance Service
Initiating Service
43.1 Condition Precedent for Receiving Service
43.2 Application Procedures
43.3 Joint Dispatch Transmission Customer Facilities
43.4 Filing of Service Agreement
SCHEDULE 1 SCHEDULE 2 SCHEDULE 3 SCHEDULE 3A -
Scheduling, System Control and Dispatch Service
Reactive Supply and Voltage Control from Generation Sources Service
Regulation and Frequency Response Service
Regulation and Frequency Response Service for Point-To-Point
Transmission Service for the PSCo Balancing Authority Area
SCHEDULE 4 Energy Imbalance Service
SCHEDULE 4A Reserve Sharing Energy Charges
SCHEDULE 4B Reserve Sharing Energy Charges
SCHEDULE 5 Operating Reserve - Spinning Reserve Service
SCHEDULE 6 Operating Reserve - Supplemental Reserve Service
SCHEDULE 7 Long-Term Firm and Short-Term Firm Point-To-Point Transmission
Service
SCHEDULE 8 Non-Firm Point-To-Point Transmission Service
SCHEDULE 9 Generator Imbalance Service
SCHEDULE 10 Tax Adjustment Rider for Service by Southwestern Public Service
Company
SCHEDULE 11 Reserved For Future Use
SCHEDULE 12 Midwest Independent Transmission System Operator, Inc. Charges
SCHEDULE 13 Network Integration Transmission Service on the PSCo Transmission
System
SCHEDULE 13A Network Integration Transmission Service across the Lamar Tie Line
SCHEDULE 14 Point-to-Point Transmission Losses on the PSCo Transmission
System
SCHEDULE 15 Joint Dispatch Transmission Service
SCHEDULE 16Flex Reserve Service
ATTACHMENT A-1 - Form of Service Agreement For Short-Term Firm Point-To-Point
Transmission Service
ATTACHMENT A-2 - Form of Service Agreement For Long-Term Firm Point-To-Point
Transmission Service
ATTACHMENT A-3 - Form of Service Agreement For The Resale, Reassignment Or Transfer
Of Point-To-Point Transmission Service
ATTACHMENT B - Form of Service Agreement For Non-Firm Point-To-Point Transmission
Service
ATTACHMENT C - Methodology To Assess Available Transfer Capability
ATTACHMENT D ATTACHMENT E ATTACHMENT F -
Methodology for Completing a System Impact Study
Index of Point-To-Point Transmission Service Customers
Form of Service Agreement For Network Integration Transmission
Service
ATTACHMENT G - Form of Network Operating Agreement
ATTACHMENT H - Annual Transmission Revenue Requirement For Network Integration
Transmission Service
ATTACHMENT I Index of Network Integration Transmission Service Customers
ATTACHMENT J - Procedures for Addressing Parallel Flows
ATTACHMENT K - Form of System Impact Study Agreement
ATTACHMENT L - Form of Facilities Study Agreement
ATTACHMENT M - Methodology for Allocating Transmission Revenues Among Utility
Operating Companies
ATTACHMENT N - Standard Large Generator Interconnection Procedures (LGIP) Applicable to Generating Facilities that exceed 20 MWs
ATTACHMENT O - Public Service Company of Colorado Formulaic Rates
ATTACHMENT O – SPS - Southwestern Public Service Company Formulaic Rates
ATTACHMENT P - Standard Small Generator Interconnection Procedures (SGIP) Applicable to Generating Facilities less than 20 MWs
ATTACHMENT Q - Creditworthiness Procedures
ATTACHMENT R – PSCo - Transmission Planning Process
ATTACHMENT S - Reserved For Future Use
ATTACHMENT T - Form of Service Agreement For Balancing Authority Ancillary Services
Applicable to the Public Service Company of Colorado (PSCo) System
ATTACHMENT U - Form of Service Agreement For Transmission to Load Interconnection
Service
ATTACHMENT V - Form of Service Agreement For Joint Dispatch Transmission Service
ATTACHMENT AA – Service Agreements For Point-To-Point Transmission Service
ATTACHMENT BB – Service Agreements For Network Transmission Service
ATTACHMENT CC – Service Agreements For Generation Interconnection Service
ATTACHMENT DD – Service Agreements For Balancing Authority Ancillary Services
ATTACHMENT EE - Reserved For Future Use
ATTACHMENT FF – Service Agreements For Transmission to Load Interconnection Service
Additional Volumes of
Xcel Energy Operating Companies
Transmission Service Tariffs
Volume No.
Contents
Joint Open Access Transmission Tariff
Original Volume 2
Reserved for Future Use
FERC Electric Transmission Tariff
Original Volume 3
Northern States Power Company transmission rate
schedules
Original Volume 4
Northern States Power Company (Wisconsin) transmission
rate schedules
Original Volume 5
Public Service Company of Colorado transmission rate
schedules
Original Volume 6
Southwestern Public Service Company) transmission rate
schedules
Original Volume 7
WestConnect Point-to-Point Regional Transmission Service
Experiment Tariff
Note: The noted tariff volumes contain transmission-related rate schedules filed by the
Transmission Services function of the Xcel Energy Operating Companies.
Rate schedules related to electric supply services may be found in the Electric Services Tariffs
separately maintained by the Xcel Energy Markets function.
V.
JOINT DISPATCH TRANSMISSION SERVICE (Applicable to Public Service
Company of Colorado only)
Preamble
Service under Part V shall be applicable only to load serving entities in the PSCo
Balancing Authority Area that are signatories to a Joint Dispatch Agreement (JDA) under
which: (1) participating generating resources of the parties are dispatched as a pool on
a least-cost basis respecting transmission limitations; (2) the Joint Dispatch
Transmission Service Customers’ respective transmission service providers have
provided within their OATT a transmission service schedule for energy dispatched
pursuant to the JDA at a rate equal to zero dollars on a non-firm, as-available basis with
the lowest curtailment priority, consistent with the provisions of this Part V of the Tariff.
41
Definitions
In addition to the Definitions and Terms set forth in the Common Service Provisions
found in Part 1 of this Tariff, the following definitions shall apply to this Part V, the Joint
Dispatch Services set forth in Schedule 15 and Attachment V of this Tariff.
42
41.1
Joint Dispatch Arrangement: An operating arrangement whereby participating
generation resources owned, operated or controlled by load serving entities
within the PSCo Balancing Authority Area are dispatched as a pool on a leastcost basis respecting transmission limitations in order to economically optimize
dispatch on an aggregate real-time basis among all participants in the Joint
Dispatch Arrangement.
41.2
Joint Dispatch Agreement: An agreement detailing the rights and obligations
of participants in a Joint Dispatch Arrangement.
41.3
Joint Dispatch Transmission Service: Non-firm transmission service across
transmission facilities of the Transmission Provider that is used to transmit
energy dispatched pursuant to a Joint Dispatch Agreement and that is subject to
the provisions of this Part V of the Tariff. Joint Dispatch Transmission Service
will be made available from posted ATC after procurement and scheduling
deadlines have passed for the current operating hour, as specified in the
Transmission Provider’s Business Practices posted on OASIS.
41.4
Service Agreement for Joint Dispatch Transmission Service (“Service
Agreement”): An agreement between the Transmission Provider and a Joint
Dispatch Transmission Service Customer for Joint Dispatch Transmission
Service.
41.5
Joint Dispatch Transmission Service Customer: Any entity with load in the
PSCo BA (or its Designated Agent) that: (i) executes a Service Agreement; or (ii)
requests in writing that the Transmission Provider file with the Commission a
proposed unexecuted Service Agreement.
Nature of Joint Dispatch Transmission Service
Joint Dispatch Transmission Service is an optional service available to any load serving
entity in the PSCo Balancing Authority Area that: (1) has entered into a Joint Dispatch
Agreement; and (2) makes Joint Dispatch Transmission Service on its transmission
system, if any, available to PSCo and all other parties to the Joint Dispatch Agreement
at the same rate, terms, and conditions as set out in this Section V of the Tariff and
related schedules and attachments. As further detailed herein, Joint Dispatch
Transmission Service may only be used to deliver energy dispatched under a Joint
Dispatch Agreement to the entity’s wholesale and retail native load customers. Joint
Dispatch Transmission Service is provided only on a non-firm, as available basis and
has the lowest curtailment priority.
42.1
Limited Transmission Provider Responsibilities. The Transmission Provider
shall have the obligation to operate its Transmission System in accordance with
Good Utility Practice. For purposes of Joint Dispatch Transmission Service, the
Transmission Provider shall have no obligation to plan, construct, or maintain its
Transmission System for the benefit of any Joint Dispatch Transmission Service
Customer.
42.2
Real Power Losses. Real Power Losses are associated with all transmission
service. The Joint Dispatch Transmission Service Customer shall be responsible
for all losses associated with Joint Dispatch Transmission Service, which
responsibility shall be manifested as the difference between the amount of
energy dispatched on behalf of the Joint Dispatch Transmission Service
Customer and the amount of energy actually delivered to such customer based
on the following loss factors.
PRPA
Seller
Buyer
PRPA
PSCo
BHCE
PRPA
PRPA+PSCo
PSCo
BHCE
PSCo
PSCo+BHCE
BHCE
PSCo
Where:
PRPA= Loss Factor set forth in PRPA’s OATT Section 15.7
PSCo=Loss Factor set forth in PSCo OATT Section 15.7
BHCE= Loss Factor set forth in BHCE OATT Section 15.7
42.3
42.4
Restrictions on Use of Service. The Joint Dispatch Transmission Service
Customer shall not use Joint Dispatch Transmission Service for (i) off-system
sales of capacity or energy or (ii) direct or indirect provision of transmission
service by the Joint Dispatch Transmission Service Customer to any third party.
Joint Dispatch Transmission Service may be used only for receipt or delivery of
energy dispatched within the PSCo Balancing Authority Area on a non-firm basis
to serve wholesale or retail native load of any participant in a Joint Dispatch
Agreement.
Imbalance Service. The purpose of the Joint Dispatch Arrangement is to
balance loads and resources of the parties by optimizing dispatch of the parties’
resources. As a result, the Transmission Provider shall not assess energy
imbalance charges under Ancillary Service Schedule 4 or 9 to any Joint Dispatch
Transmission Service Customer.
43
Initiating Service
43.1
Conditions Precedent for Receiving Service. Subject to the terms and
conditions of this Part V of the Tariff, and related schedules and attachments, the
Transmission Provider will provide Joint Dispatch Transmission Service to any
eligible customer, provided that (i) the eligible customer has wholesale or retail
native load in the Transmission Provider’s Balancing Authority Area; (ii) the
eligible customer has entered into a Joint Dispatch Agreement; (iii) the eligible
customer’s transmission provider has a transmission service tariff offering Joint
Dispatch Transmission Service on the same terms and conditions as offered
under this Part V of the Tariff, and related schedules and attachments; and (iv)
the eligible customer executes a Service Agreement pursuant to Attachment FF
for service under this Part V of the Tariff or requests in writing that the
Transmission Provider file a proposed unexecuted Service Agreement with the
Commission.
43.2
Application Procedures. An Eligible Customer requesting service under Part V
of this Tariff must submit an application containing the information specified
below. No deposit or credit evaluation is necessary to obtain Joint Dispatch
Transmission Service. Further, no transmission studies shall be required to
obtain Joint Dispatch Transmission Service because such service is provided
only on a non-firm, as available basis. Applications should be submitted to the
Transmission Provider via e-mail to the person(s) listed on OASIS. Application
contents:
(i)
(ii)
(iii)
(iv)
(v)
(vi)
(vii)
The identity, address, telephone number and facsimile number of the
party requesting service;
A statement that the party requesting service is, or will be upon
commencement of service, an Eligible Customer under the tariff;
A statement that the party requesting service has, or will have upon
commencement of service, wholesale or retail native load in the PSCo
Balancing Authority Area;
A statement that the party requesting service has, or will have upon
commencement of service, entered into a Joint Dispatch Agreement with
PSCo;
A statement that the party requesting service has, or will have upon
commencement of service, a tariff offering Joint Dispatch Transmission
Service at the same rates, terms, and conditions as this Part V of the
Tariff and associated schedules and attachments;
Service Commencement Date and the term of the requested Joint
Dispatch Transmission Service.
A statement signed by an authorized officer from or agent of the Joint
Dispatch Transmission Service Customer attesting that Joint Dispatch
Transmission Service will be used only for receipt or delivery of energy
dispatched under a Joint Dispatch Agreement for the benefit of that
customer’s wholesale and retail native load customers.
(viii)
Service is conditioned on the Transmission Provider being in receipt of an
executed Joint Dispatch Agreement.
Unless the Parties agree to a different timeframe, the Transmission Provider
must acknowledge the request within ten (10) days of receipt. The
acknowledgement must include a date by which a response, including a Service
Agreement, will be sent to the Eligible Customer. If an application fails to meet
the requirements of this section, the Transmission Provider shall notify the
Eligible Customer requesting service within fifteen (15) days of receipt and
specify the reasons for such failure. Wherever reasonably possible, the
Transmission Provider will attempt to remedy deficiencies in the Application
through informal communications with the Eligible Customer. If efforts are
unsuccessful, the Transmission Provider shall return the Application, without
prejudice to the Eligible Customer filing a new or revised Application that fully
complies with the requirements of this section.
43.3
Joint Dispatch Transmission Customer Facilities: The Joint Dispatch
Transmission Service Customer’s transmission provider will retain its existing
obligations to plan, construct, operate and maintain its transmission system using
good utility practices.
43.4
Filing of Service Agreement. The Transmission Provider will file Service
Agreements with the Commission in compliance with applicable Commission
regulations, if any.
Schedule 15
Joint Dispatch Transmission Service
This is an optional service provided by PSCo, subject to the terms and conditions of Part
V of this Tariff. For Joint Dispatch Transmission Service Customers meeting the
conditions set forth in Part V of this Tariff, no charge shall be assessed for receipt or
delivery of energy dispatched pursuant to a Joint Dispatch Agreement with PSCo
provided the customer makes Joint Dispatch Transmission Service available to PSCo at
the same rates, terms, and conditions as set forth in Part V of this Tariff, this Schedule
15, and any other related schedules or attachments to this Tariff. Joint Dispatch
Transmission Service is provided in real-time on a non-firm, as available basis having
the lowest curtailment priority.
1) Monthly delivery: the rate or $0.00/kW-month of Reserved Capacity.
2) Weekly delivery: the rate $0.00/kW-week of Reserved Capacity.
3) Daily delivery: the rate $0.00/kW-day of Reserved Capacity.
4) Hourly delivery: On-Peak Hours: the on-peak rate $0.00/MWh of Reserved Capacity.
Off-Peak Hours: the off-peak rate $0.00/MWh of Reserved Capacity.
ATTACHMENT V
Form of Service Agreement For Joint Dispatch Transmission Service Applicable to the
Public Service Company of Colorado (PSCo) System
1.0
This
Joint
Dispatch
Transmission
Service
Agreement,
dated
as
of
__________________________,
is
entered
into,
by and between __________________________ (“Transmission Provider”),
and __________________________ ("Joint Dispatch Transmission Customer"),
all of whom may be referred to individually as “Party” or jointly as “Parties”.
2.0
The Joint Dispatch Transmission Customer has been determined by the Transmission
Provider to have a signed a Joint Dispatch Agreement.
3.0
Service under this agreement shall commence on the later of (1) the requested service
commencement date, or (2) such other date as it is permitted to become effective by the
Commission. Service under this agreement shall terminate on such date as mutually
agreed upon by the parties.
4.0
Any notice or request made to or by either Party regarding this Service Agreement shall
be made to the representative of the other Party as indicated below.
Transmission Provider:
_____________________________________
_____________________________________
_____________________________________
Transmission Customer:
_____________________________________
_____________________________________
_____________________________________
5.0
The Tariff is incorporated herein and made a part hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by
their respective authorized officials.
Transmission Provider:
By:
___________________ ___________________ ___________________
Name
Title
Date
Transmission Customer:
By:
___________________ ___________________ ___________________
Name
Title
Date
Exhibit PSC-1
Page 1 of 24
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Public Service Company of Colorado
)
Docket No. ER16-___-000
PREPARED TESTIMONY
OF
TERRI K. EATON
XCEL ENERGY SERVICES INC.
ON BEHALF OF
PUBLIC SERVICE COMPANY OF COLORADO
Exhibit PSC-1
Page 2 of 24
1
I
INTRODUCTION AND EXPERIENCE
2
Q.
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
3
A.
My name is Terri K Eaton. My office address is 1800 Larimer Street, 12th Floor, Denver,
4
Colorado, 80202.
5
Q.
BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?
6
A.
I am employed by Xcel Energy Services Inc. (“XES”). I am the Director, Federal
7
Regulatory Administration.
8
Q.
ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?
9
A.
I am testifying on behalf of Public Service Company of Colorado (“PSCo” or the
10
“Company”), a wholly owned subsidiary of Xcel Energy Inc. (“Xcel Energy”). PSCo is
11
an integrated electric and natural gas utility operating in Colorado, including in the
12
Denver metropolitan area, and is one of four utility operating company subsidiaries of
13
Xcel Energy.
14
Q.
PLEASE EXPLAIN YOUR DUTIES AND RESPONSIBILITIES.
15
A.
My department is responsible for regulatory filings, regulatory activity, and compliance
16
monitoring activities involving the Federal Energy Regulatory Commission (“FERC” or
17
“Commission”) for the four Xcel Energy utility operating companies, including PSCo.
18
The FERC compliance monitoring responsibilities include PSCo compliance with North
19
American Electric Reliability Corporation (“NERC”) and the Western Electricity
20
Coordinating Council (“WECC”) mandatory electric reliability standards.
Exhibit PSC-1
Page 3 of 24
1
Q.
2
3
WHAT IS YOUR EDUCATION AND YOUR EXPERIENCE IN THE ELECTRIC
UTILITY BUSINESS?
A.
In 1981, I received my B.S. degree from the University of Texas. In 1985, I received my
4
J.D. from the University of Texas School of Law. From 2000 to 2002, I worked as a staff
5
attorney for the Public Utility Commission of Texas (“PUCT”). In that role, I was
6
responsible for representing PUCT staff in rate case, transmission line, stranded cost, and
7
various other proceedings.
8
Manager of Governmental Affairs, representing the company’s interests as a competitive
9
retail electric provider before the PUCT, the Texas legislature, and the Electric Reliability
10
Council of Texas (“ERCOT”). I joined XES in 2005 as a Manager of Market Operations,
11
representing the interests of PSCo’s affiliate Southwestern Public Service Company
12
(“SPS”) in the efforts by Southwest Power Pool, Inc. (“SPP”) to create its Energy
13
Imbalance Service market. In 2006, I transferred into XES’s FERC regulatory group
14
where I managed electric market policy issues. In 2007, I assumed a newly created
15
position focused on monitoring and oversight of mandatory reliability standards
16
compliance efforts of the Xcel Energy Operating Companies. In 2009, I assumed my
17
current position.
18
Q.
19
20
In 2002, I joined Green Mountain Energy Company as
HAVE YOU PREVIOUSLY SUBMITTED TESTIMONY BEFORE ANY
REGULATORY COMMISSION?
A.
Yes, I have previously submitted pre-filed testimony before this Commission in Docket
21
Nos. ER12-1589, ER14-1969, and ER15-237. Additionally, I have submitted affidavits to
22
the Commission on various matters, including affidavits in support of tariff change filings
23
in Docket Nos. ER12-435-000, ER12-436-000, and ER12-455-000.
Exhibit PSC-1
Page 4 of 24
1
II
PURPOSE AND SUMMARY
2
Q.
WHAT IS THE PURPOSE OF YOUR TESTIMONY?
3
A.
The purpose of my testimony is to provide a brief description of Xcel Energy, XES and
4
PSCo, and to provide an overview of PSCo’s request for approval of revisions to its Open
5
Access Transmission Tariff (“Xcel Energy OATT”) to facilitate transactions under the
6
Joint Dispatch Agreement (“JDA”).
7
approval of the JDA, an agreement that will provide for the economic dispatch of
8
participating generation within the PSCo Balancing Authority Area (“BAA”), and the
9
other FERC jurisdictional party to the JDA is filing revisions to its Open Access
10
Concurrent with this filing, PSCo is filing for
Transmission Tariff corresponding to PSCo’s changes in this filing.
11
Q.
PLEASE SUMMARIZE THE PROPOSED TARIFF CHANGES.
12
A.
The proposed revisions to the Xcel Energy OATT include:
•
13
A new section titled Joint Dispatch Transmission Service that provides non-firm
14
transmission service at a zero rate applicable only to load serving entities that
15
have participating generation that they can contribute to the joint dispatch pool in
16
the PSCo BAA and are signatories to a Joint Dispatch Agreement;
17
•
A new Schedule 15, Joint Dispatch Transmission Service; and,
18
•
A Service Agreement for Joint Dispatch Transmission Service.
19
Q.
20
21
22
HAVE YOU INCLUDED ATTACHMENTS TO YOUR TESTIMONY SHOWING
THE CHANGES TO THE OATT?
A.
Yes. The attached Exhibit No. PSC-2 is a redlined version of the proposed tariff changes,
while Exhibit No. PSC-3 is a clean version of the tariff changes.
Exhibit PSC-1
Page 5 of 24
1
III
CORPORATE OVERVIEW
2
Q.
PLEASE PROVIDE A BRIEF DESCRIPTION OF XCEL ENERGY.
3
A.
Xcel Energy is a holding company that primarily engages in the production, transmission
4
and distribution of electricity and the distribution of natural gas through its four utility
5
subsidiaries: PSCo, SPS and Northern States Power Company, a Minnesota corporation
6
(“NSPM”) and Northern States Power Company, a Wisconsin corporation (“NSPW”)
7
(NSPM and NSPW jointly the “NSP Companies”). PSCo, NSPM and NSPW are each
8
combination electric and natural gas utilities.
9
Collectively, Xcel Energy’s utility operating company subsidiaries serve 3.4 million
10
electric and 1.9 million natural gas customers in Colorado, Michigan, Minnesota, New
11
Mexico, North Dakota, South Dakota, Texas and Wisconsin. In addition, SPS owns and
12
operates transmission facilities in Kansas and Oklahoma. I note that the changes to the
13
Xcel Energy OATT proposed in this filing do not affect the rates or terms of service on
14
the NSP Companies or SPS transmission systems.
SPS is an electric-only utility.
15
Q.
PLEASE DESCRIBE XES.
16
A.
XES is a service company that provides a variety of management and administrative
17
services to Xcel Energy’s four utility operating companies, including PSCo. Some of the
18
services provided by XES include executive management, human resources, accounting,
19
audit, legal, claims, regulatory and compliance, fuel and energy management,
20
engineering and customer services. As a service company, XES files an annual Form 60
21
service company report with the Commission each year detailing the revenues from its
22
charges to the individual utility operating companies.
23
Q.
PLEASE PROVIDE A BRIEF DESCRIPTION OF PSCO.
Exhibit PSC-1
Page 6 of 24
1
A.
PSCo generates, transmits and distributes electric power and energy throughout portions
2
of the State of Colorado. PSCo provides electric service to approximately 1.3 million
3
wholesale and retail customers in Colorado. The Company’s greatest concentration of
4
retail customers is in the Denver metropolitan area.
5
PSCo is located at the eastern edge of the Western Interconnection and is a
6
member of WECC.
Since there is no regional transmission organization (“RTO”)
7
serving Colorado, PSCo is the transmission provider for the PSCo transmission system.
8
PSCo provides Network Integration Transmission Service (“NITS”) and Point-to-Point
9
Transmission Services and derives rates for such services pursuant to Attachment O-
10
PSCo of the Xcel Energy OATT, on file with the Commission pursuant to Order Nos.
11
888 and 890.
12
IV
BACKGROUND
13
Q.
WHAT IS THE PURPOSE OF THE INSTANT FILING?
14
A.
The instant filing reflects changes to the Xcel Energy OATT designed to facilitate joint
15
dispatch of the resources of PSCo, Platte River Power Authority (“PRPA”) and Black
16
Hills Colorado Electric Utility Company, LP (“BHCE”) (collectively referred to as “the
17
Parties”) under the JDA. More specifically, the proposed tariff changes provide that non-
18
firm transmission service used to deliver energy dispatched under the JDA across the
19
PSCo transmission system will be provided at no additional cost, other than payment of
20
losses, to parties to the JDA. The proposed revisions to PSCO’s OATT are consistent
21
with the JDA’s terms and conditions that require each signatory to agree to provide the
22
necessary transmission service for JDA energy, at no additional cost, across the
23
transmission systems on which they take network service.
To that end, BHCE, a
Exhibit PSC-1
Page 7 of 24
1
jurisdictional public utility transmission provider, is also filing similar proposed changes
2
to its OATT in order to provide the necessary transmission service for JDA transactions.
3
PRPA is not a jurisdictional public utility and therefore is not making a similar filing;
4
however, PRPA will implement the necessary changes to its transmission tariff.
5
PSCo previously filed changes to the Xcel Energy OATT to facilitate the JDA on
6
November 14, 2014, in Docket No. ER15-237-000. However, that filing, as well as the
7
related filing by PSCo of the JDA itself in Docket No. ER15-326-000, was rejected by
8
the Commission on June 23, 2015. Public Serv. Co. of Colorado, 151 FERC ¶ 61,248
9
(2015) (“June Order”).
10
The Commission rejected the filings for two reasons. First, the Commission
11
found that PSCo did not show that its proposed payment structure for resources
12
dispatched under the JDA would result in rates that are just and reasonable.
13
Commission’s concerns on this issue were due to PSCo’s lack of market-based rate
14
authority in the PSCo BAA and the Commission’s conclusion that PSCo could exercise
15
market power through the pricing structure of the JDA, which the Commission found was
16
not cost-based. June 23 Order at P 99. Second, the Commission found that the JDA
17
would require JDA parties to grant PSCo’s merchant function access to non-public
18
information that, under the Standards of Conduct, should be restricted to PSCo’s
19
transmission function. Id. at P 100.
20
Q.
The
DID THE JUNE ORDER CONCLUDE THAT ANY OF THE REVISIONS
21
PROPOSED TO THE XCEL ENERGY OATT TO FACILITATE THE JDA MAY
22
BE UNJUST AND UNREASONABLE?
Exhibit PSC-1
Page 8 of 24
1
A.
No.
The Commission’s reasons for rejecting the filings were related only to the
2
provisions of the JDA, not the proposed revisions to the Xcel Energy OATT. Although
3
the Commission did not identify specific issues in the June Order related to transmission
4
under the Xcel Energy OATT, certain transmission-related issues were raised in the
5
pleadings of other parties during the proceedings and in a deficiency letter issued by
6
Commission staff.
7
Commission to the originally-proposed Xcel Energy OATT revisions, I provide
8
additional explanation and support for the revisions to respond to the transmission-related
9
issues.
Thus, while no required adjustments were identified by the
10
IV
OVERVIEW OF THE JDA
11
Q.
WHAT IS THE PURPOSE OF THE JDA?
12
A.
The parties to the JDA intend to capture efficiencies and cost savings through joint
13
dispatch of their committed resources to serve the native load obligation of the parties to
14
the JDA within the PSCo BAA.
15
Q.
HOW WILL THE JDA CAPTURE EFFICIENCIES?
16
A.
As discussed in more detail in the companion filing and the testimony of John Welch in
17
that filing, the parties to the JDA have agreed to allow PSCo to dispatch the committed
18
and participating resources of all the parties in real-time in a manner that maintains
19
reliability while minimizing overall production costs and respecting transmission
20
constraints and unit operating characteristics.
21
Q.
WHERE IS THE LOAD THAT WILL BE SERVED BY THE JDA LOCATED?
22
A.
Under the JDA, the load that can be served under the agreement is limited to that which is
23
located within the PSCo BAA.
Exhibit PSC-1
Page 9 of 24
1
V
POLICY
2
Q.
WHY SHOULD THE TARIFF REVISIONS BE APPROVED BY THE
3
4
COMMISSION, AND IS THE JDA IN THE PUBLIC INTEREST?
A.
The JDA will enable optimal dispatch of the combined participating resources of all the
5
participating parties, resulting in increased dispatch efficiency. The tariff revisions are in
6
the public interest because, among other things, the dispatch efficiency facilitated by the
7
JDA and tariff revisions will be reflected through reduced fuel costs for the customers of
8
all participating parties, including PSCo’s retail and wholesale customers.
9
The JDA and tariff revisions provide an alternative mechanism to effectively
10
manage the difference between scheduled and actual load, which is currently managed in
11
the PSCo BAA through Energy Imbalance services under Schedule 4 of the Xcel Energy
12
OATT.
13
transmission service to do so. PSCo balances the system after taking into account the
14
committed resources from each customer that were determined prior to the start of the
15
hour.
16
Transmission Service, participating generation resources will be dispatched in the most
17
economic order to achieve this balance.
PSCo, as the BA, provides energy imbalance services without purchasing
Under joint economic dispatch facilitated by the JDA and Joint Dispatch
18
VI
OATT REVISIONS
19
Q.
WHAT REVISIONS ARE BEING MADE TO PSCO’S OATT?
20
A.
PSCo is revising its OATT in order to offer Joint Dispatch Transmission Service. Joint
21
Dispatch Transmission Service is service that can only be used to receive and deliver
22
energy dispatched under the JDA to the Parties’ wholesale and retail native load
23
customers.
Exhibit PSC-1
Page 10 of 24
1
Q.
2
3
ARE THE TARIFF PROVISIONS PROVIDING FOR THE NEW SERVICE
OPTION OPEN TO ADDITIONAL PARTIES?
A.
Yes, the tariff provisions are not limited to the initial Parties of the JDA. Any load-
4
serving entity in the PSCo BAA who agrees to provide, or whose host transmission
5
provider agrees to provide, joint dispatch transmission service at rates and terms
6
comparable to those proposed in this filing, and has the ability to contribute generating
7
resources located within the PSCo BAA to the JDA pool, is eligible to participate in the
8
JDA. If the prospective JDA party is not a transmission service provider, its transmission
9
service provider must agree to make its transmission system in the PSCo BAA available
10
11
for JDA transactions on a non-firm, zero-price basis.
Q.
12
13
ARE THERE EXCEPTIONS TO THE REQUIREMENT THAT GENERATION
BE LOCATED INSIDE THE BAA?
A.
Yes. Generation could be located outside the PSCo BAA but pseudo-tied into the PSCo
14
BAA. A pseudo-tie essentially involves electrically sinking the output of a generator in
15
one BAA into another sink BAA.
16
Q.
WERE ANY ISSUES RAISED IN DOCKET NO. ER15-237-000 REGARDING
17
THE AVAILABILITY OF THE NEW SERVICE OPTION TO OTHER
18
CUSTOMERS?
19
A.
The Commission did not identify this as one of its concerns in the June Order. However,
20
during the proceedings in Docket No. ER15-237-000, Tri-State Generation &
21
Transmission Association (“Tri-State”) argued that the new service option could be
22
unduly discriminatory because “it does not provide for a circumstance that would arise if
23
an entity desires to participate in the JDA but cannot persuade its transmission provider to
Exhibit PSC-1
Page 11 of 24
1
provide free transmission service.” 1 This is not a valid concern. The only transmission
2
providers in the PSCo BAA are PSCo, PRPA, BHCE, and Tri-State. As noted earlier, the
3
initial JDA parties are PSCo, PRPA, and BHCE, and they have agreed to make their
4
transmission systems available for the service. Thus, the only entity that might create
5
obstacles to its customers using the new transmission service option in conjunction with
6
JDA participation is Tri-State itself.
7
Q.
8
9
ARE THE PROPOSED CHANGES CONSISTENT WITH, OR SUPERIOR TO,
THE COMMISSION’S PRO FORMA OATT?
A.
Yes. The new tariff provisions provide for a new type of service for Parties to the JDA
10
that is essentially a license plate rate available to those entities that have committed to
11
joint dispatch of their participating resources to serve load located in the PSCo BAA.
12
These new provisions do not depart from the Commission’s prior determination that
13
PSCo’s OATT conforms with, or is superior to, the pro forma OATT. In addition to
14
being non-discriminatory, the new service will not have an adverse impact on other
15
transmission users.
16
Q.
17
18
PLEASE EXPLAIN HOW THE JOINT DISPATCH TRANSMISSION SERVICE
WILL NOT ADVERSELY IMPACT OTHER TRANSMISSION USERS.
A.
Joint Dispatch Transmission Service is only available if there is posted non-firm
19
Available Transmission Capacity (“ATC”) after all other procurement and scheduling
20
deadlines have passed. PSCo will limit transfers under Joint Dispatch Transmission
21
Service to the amount of unused ATC that remains on the system after such procurement
22
and scheduling deadlines have passed. Although schedule-driven ATC updates may
1
Tri-State Protest at 13, Docket Nos. ER15-237-000, et al., (Nov. 20, 2014).
Exhibit PSC-1
Page 12 of 24
1
occur every quarter-hour, PSCo will update ATC limits for Joint Dispatch Transmission
2
Service every five minutes. By conducting these updates every five minutes, PSCo will
3
ensure that any immediate intra-hour schedule changes, such as those prompted by
4
outages, are captured and only the leftover ATC is made available for Joint Dispatch
5
Transmission Service. In this way, energy transfers are limited by ATC availability on
6
the system, and participating generation units will be adjusted to limit volumetric
7
transfers between Parties based on unused ATC that remains after the close of
8
transmission schedules. Thus, Joint Dispatch Transmission Service will only use ATC
9
that would otherwise go unused and promotes more complete usage of the existing
10
transmission system. Additionally, Joint Dispatch Transmission Service will have the
11
lowest priority, and any party seeking transmission service will be in a queue position
12
higher than Joint Dispatch Transmission Service.
13
Each Party’s transmission service provider will be required to post ATC that PSCo will
14
collect and use to determine appropriate transfer capabilities. Based on historic data,
15
PSCo estimates the transfer capabilities needed to execute the JDA should not exceed
16
300 MW between parties, with typical transfers expected to be less than 150 MW.
17
Q.
WILL JOINT DISPATCH TRANSMISSION SERVICE HAVE AN IMPACT ON
18
FIRM XCEL ENERGY OATT CUSTOMERS BY DISPLACING REVENUES
19
GENERATED BY NON-FIRM TRANSMISSION SERVICE UNDER THE XCEL
20
ENERGY OATT?
21
A.
PSCo does not expect the JDA to cause a significant change in typical non-firm
22
transmission service revenues and, therefore, has no reason to anticipate that any change
23
in future non-firm transmission service revenues – and the credits they provide to firm
Exhibit PSC-1
Page 13 of 24
1
transmission service customers’ rates – will result from implementation of the JDA.
2
Even if all of the non-firm revenues PSCo receives from PRPA and BHCE were to
3
disappear due to the JDA, the resulting loss of revenue credits for PSCo’s firm
4
transmission service customers would have a de minimis impact on their rates.
5
Parties to the JDA are required to have available sufficient resources to serve load
6
plus reserves for every hour under Section 3.1 of the JDA. In advance of the intra-hour
7
dispatch under the JDA, parties will not know whether their resources will be dispatched
8
up or down in real-time. Therefore, parties will continue to look for opportunities to
9
lower their dispatch costs through economic purchases. Parties will also look for
10
opportunities to lock in margins from economic sales. Transmission will have to be
11
procured for both economic purchases and sales—just as it is today.
12
While PSCo expects all JDA parties to continue to engage in economic purchases
13
and sales just as they do today, even if that were not the case and the JDA Parties no
14
longer utilized the non-firm transmission service provided by each other, the total impact
15
to the revenues generated by non-firm transmission service would be de minimis. Total
16
dollars received by PSCo for non-firm point-to-point transmission service to facilitate
17
energy transactions to the other JDA Parties for 2013 and 2014 are shown in Table 1 and
18
Table 2 below. This table shows the non-firm point-to-point (Schedule 8) revenues PSCo
19
received from BHCE and PRPA for 2013 and 2014.
2013
Total
Customer
20
2014
Total
BHCE
(67,294)
(178,975)
PRPA
-
(3,742)
Exhibit PSC-1
Page 14 of 24
1
Thus, the total revenues received by PSCo from PRPA and BHCE for non-firm
2
service is $250,011 for the two year period, or about $125,000 per year or 0.05% of
3
PSCo’s annual transmission revenue requirement, on average. Non-firm revenues are
4
credited to the annual transmission revenue requirement. Wholesale customers represent
5
21.81% of the total customers that would receive credits for non-firm revenues. Of the
6
21.81% amount, third-party transmission-only customers represent 60.47%. Thus, of the
7
$125,000 average impact, PSCo’s transmission-only customers would only see a
8
collective loss of less than $20,000 in revenue credits. (($125,000 × .2181) × .6047 =
9
$16,485).
10
The PSCo merchant function primarily utilizes network integration transmission
11
service to serve native load, not non-firm transmission service for purchases from PRPA
12
and BHCE, and thus there are no non-firm revenues displayed in the table associated with
13
the PSCo merchant function. If, for the sake of argument, one makes the improbable
14
assumption that the PSCo merchant function would cease to engage in any economic
15
sales with third parties using non-firm transmission on any path (i.e., not only those paths
16
associated with service to BHCE and PRPA) due to the JDA, then the loss of those
17
revenues would still have only a minimal impact. Adding the $195,770 associated with
18
the wholesale merchant function to the $250,011 associated with non-firm transmission
19
for PRPA and BHCE on the PSCo transmission system, as described in the deficiency
20
letter response filed in Docket Nos. ER15-237 et al., results in a sum of $445,781 for
21
2013 and 2014, and a total average amount of $222,890.50. Wholesale customers
22
represent 21.81% of the total customers that would receive credits for non-firm revenues.
23
Of this 21.81% amount, third-party transmission customers represent 60.47%. Thus, of
Exhibit PSC-1
Page 15 of 24
1
the hypothetical $222,890.50 average loss (if such were the case) in non-firm revenues,
2
there would be $29,396 less in total revenue credits to offset the revenue requirement of
3
all of PSCo’s transmission-only customers taking firm service.
4
expected amount of non-firm revenue credits expected for 2015 from all transmission
5
customers, which is $2,716,261, the loss in non-firm revenues under this hypothetical
6
worst-case scenario represents a reduction of less than 1% in the total anticipated credits.
Compared to the
7
VII
DESCRIPTION OF THE SERVICE
8
Q.
WHAT TYPE OF TRANSMISSION SERVICES WILL BE PROVIDED UNDER
9
10
THE NEW TARIFF PROVISIONS?
A.
Joint Dispatch Transmission Service is a non-firm, “as-available” transmission service
11
provided at a zero rate that is made available for the sole purpose of facilitating energy
12
transfers pursuant to the JDA.
13
Q.
WOULD A JDA BE FEASIBLE WITH TRANSMISSION CHARGES?
14
A.
No. Xcel Energy and BHCE explored a joint dispatch arrangement that incorporated
15
additional transmission charges a few years ago, but shelved the idea primarily because
16
the economic benefits would be severely diminished if both PSCo and BHCE secured
17
point-to-point transmission service to facilitate dynamic transfers or if BHCE became a
18
network customer under the Xcel Energy OATT. In this proposal, too, transmission
19
charges would likely eliminate the benefits that the Parties expect to achieve through the
20
JDA.
21
22
Q.
PLEASE
EXPLAIN
WHY
A
TRANSMISSION
CHARGE
WOULD
INCOMPATIBLE WITH JOINT DISPATCH TRANSMISSION SERVICE.
BE
Exhibit PSC-1
Page 16 of 24
1
A.
The reason PSCo is proposing to have zero-price transmission service is to maximize the
2
level of re-dispatch among the parties – to reduce the delivered energy cost to the
3
participants’ customers. Any charge for Joint Dispatch Transmission Service would add
4
a hurdle rate and as a result reduce the level of generation re-dispatch. If transmission
5
prices were added, the difference in dispatch costs would have to be higher for a
6
transaction to take place. In the table below, an example of this is presented:
7
8
9
10
11
12
13
14
15
Seller
PRPA
PSCo
BHCE
Buyer
PRPA
PSCo
BHCE
NA
3.75
8.83
5.08
NA
5.08
8.83
3.88
NA
16
This table shows that if the parties’ respective on-peak hourly transmission rates
17
were applied, differences in dispatch costs between $3.75/MWh and $8.83/MWh would
18
have to be achieved prior to a transaction taking place. By comparison, on a unitized
19
basis the per MWh savings associated with each JDA transaction would be roughly
20
$6.63/MWh assuming the net estimated overall savings of $4.5 million is achieved. A
21
comparison of the unitized savings to the cost of non-firm transmission shows that
22
assessing posted transmission charges against JDA transactions would erode a significant
23
portion of JDA benefits. In some cases, the transmission cost would exceed the unitized
24
savings.
25
Q.
HOW WILL THE BENEFITS OF THE JOINT DISPATCH TRANSMISSION
26
SERVICE ALIGN WITH THE CURRENT RATEPAYERS WHO PAY FOR THE
27
PSCO TRANSMISSION SYSTEM?
Exhibit PSC-1
Page 17 of 24
1
A.
The vast majority of PSCo’s transmission customers – almost 90% on a load basis– are
2
production customers as well. This group of customers will receive the reduced fuel cost
3
benefits of joint dispatch through the applicable fuel cost adjustments. As explained
4
above, PSCo does not expect the JDA to have any impact on rates paid by wholesale
5
transmission customers.
6
The smaller group of PSCo transmission-only customers will experience either
7
zero or de minimis additional costs. 2 Further, the transmission-only customers may
8
obtain benefits from reduced imbalance charges. This is because PSCo’s purchases of
9
cheaper surplus energy under the JDA may reduce PSCo’s system incremental cost,
10
which is the basis for imbalance energy rates under Schedules 4 and 9 of the Xcel Energy
11
OATT.
12
Q.
CAN JOINT DISPATCH TRANSMISSION SERVICE BE USED BY A PARTY
13
FOR TRANSACTIONS OTHER THAN TO SERVE NATIVE LOAD WITH JDA
14
ENERGY?
15
A.
No. Joint Dispatch Transmission Service will not be available for off-system sales of
16
capacity or energy or for providing direct or indirect transmission service to a third party
17
and is limited to the use described above. Joint Dispatch Transmission Service cannot be
18
used as a substitute for point-to-point or network service. For off-system purchases and
19
sales, Joint Dispatch Transmission Service Customers must ensure point-to-point
20
transmission service has been obtained, as needed, to import purchases from outside the
21
PSCo BAA, or to export off-system sales, in accordance with FERC regulations. Thus,
2
For example, in the Southwest Power Pool’s regional pooled dispatch (aka Energy Imbalance Service), scheduled
delivery using transmission service actually increased after dispatch operations began. If this occurs for PSCo, the
transmission system costs to the transmission-only customers would be reduced.
Exhibit PSC-1
Page 18 of 24
1
each Joint Dispatch Transmission Service customer will continue to be required to
2
maintain adequate firm network and point-to-point service for its wholesale and retail
3
native load and its contractual commitments.
4
VIII. TRANSMISSION CHARGES
5
Q.
WHAT IS THE CHARGE FOR JOINT DISPATCH TRANSMISSION SERVICE?
6
A.
PSCo proposes that Joint Dispatch Transmission Service be priced at $0 per MWh,
7
meaning that Joint Dispatch Transmission Service Customers will not pay any additional
8
transmission charges for receipt and delivery of energy dispatched under the JDA. Each
9
Joint Dispatch Transmission Service Customer has an obligation independent of the JDA
10
to maintain adequate firm network and firm point-to-point service on the transmission
11
systems where they are located, in order to serve its wholesale and retail native load.
12
With Joint Dispatch Transmission Service, no additional transmission service charge will
13
be imposed for energy deliveries under the JDA.
14
Q.
15
16
WHY IS THE ZERO RATE FOR JOINT DISPATCH TRANSMISSION SERVICE
REASONABLE?
A.
In essence, the $0 price for Joint Dispatch Transmission Service will operate as a zonal or
17
license plate transmission service with respect to the energy imbalance deliveries under
18
the JDA. The parties to the JDA must independently maintain network and point-to-point
19
service under applicable transmission tariffs to serve their respective loads, so they are
20
already bearing the fixed costs of the same transmission systems used to deliver energy
21
under the JDA, i.e., in the “zones” where they are located. Therefore, the $0 rate does
22
not affect the recovery of embedded costs in the transmission system or materially
23
displace the payment burden onto other transmission customers because those costs will
Exhibit PSC-1
Page 19 of 24
1
continue to be borne by parties to the JDA in the same manner and magnitude as today.
2
The $0 rate helps to mitigate rate pancaking issues so that the JDA parties are not paying
3
additional transmission charges for delivery of imbalance energy under the JDA
4
associated with the “source” transmission system. Each Party will continue to pay point-
5
to-point charges for sales to third parties.
6
The proposed $0 rate is consistent with the nature of this transmission service
7
because the Joint Dispatch Transmission Service would be the lowest priority
8
transmission service. Non-firm transmission service will have a higher priority than Joint
9
Dispatch Transmission Service. Joint Dispatch Transmission Service will only utilize
10
non-firm ATC within the operating hour that is otherwise unused—capability that is not
11
being used or paid for by transmission customers.
12
The fact that the rate for Joint Dispatch Transmission Service will be $0,
13
however, does not mean that the service is free.
14
participant must arrange to provide the necessary transmission service to effect the JDA
15
transactions on the transmission systems where it is located. This results in an exchange
16
of transmission service among the JDA parties, which the Commission has recognized
17
includes an exchange of consideration among contracting parties. Such an arrangement
18
is a legitimate form of compensation. 3 Under the definition of “electric service,” the
19
Commission’s own rules provide that charges for transmission service are “without
20
regard to the form of payment or compensation.” 4
3
As discussed earlier, Each JDA
See, e.g., Central Iowa Power Cooperative, Inc. v. FERC, 606 F.2d 1156, 1172 (D. C. Cir. 1979) (explaining that
including smaller systems in a power pool would not burden existing pool members “as long as they provide
compensation for the true value of transmission services, whether in kind or in money”).
4
18 C.F.R §35.2.
Exhibit PSC-1
Page 20 of 24
1
Absent such a transmission arrangement, there may not be the capability to
2
deliver joint dispatch energy to the prospective customer. In addition, there is a potential
3
for free ridership for prospective customers who may be served by PSCo, BHCE, or
4
PRPA and also have service with another transmission service provider who has not
5
made its transmission system available for joint dispatch transmission service. In that
6
case, the prospective customer would have free use of the systems of PSCo, BHCE, and
7
PRPA for joint dispatch transactions but not be supporting expansion of the JDA through
8
contribution of their own transmission capability.
9
Conversely, including an additional transmission fee for JDA service above the
10
in-kind compensation already contributed by JDA participants is not necessary and would
11
negatively affect the economics of the arrangement.
12
Q.
IS THERE PRECEDENT FOR THIS TYPE OF LICENSE PLATE SERVICE?
13
A.
Yes. In Docket No. ER14-1386-000, the Commission conditionally approved a proposal
14
by California Independent System Operator (“CAISO”) to facilitate the Energy
15
Imbalance Market (“EIM”) outside of the CAISO footprint. PacifiCorp is one of the first
16
participants and filed revisions to its OATT in Docket No. ER14-1578 to allow it to
17
participate in the EIM. In that case, FERC conditionally accepted PacifiCorp’s OATT
18
revisions, but specifically rejected PacifiCorp’s proposal to require participating
19
resources in the EIM in PacifiCorp’s BAA to pay for additional transmission service
20
charges beyond what they already pay as transmission customers on PaciCorp’s OATT.
21
In this respect, PacifiCorp’s proposal was in conflict with CAISO’s proposal to waive
22
wheeling access charges for EIM exports from CAISO to PacifiCorp.
23
Commission explained:
As the
Exhibit PSC-1
Page 21 of 24
1
2
3
4
5
6
7
8
9
10
11
PacifiCorp’s proposal to charge for transmission service in association with
participation in the EIM is in conflict with the proposal by CAISO to have
reciprocal transmission rates for the EIM, which we accept in the concurrently
issued order on CAISO’s EIM proposal. CAISO proposes to assess transmission
charges only in the BAA where the EIM energy sinks. In the CAISO BAA, load,
which will include EIM Transfers originating in PacifiCorp, will continue to pay
the CAISO transmission access charge; however, CAISO proposes to waive its
wheeling access charge, normally charged on exports from CAISO, on EIM
Transfers to PacifiCorp. If PacifiCorp requires EIM resources to purchase
transmission service to participate in the EIM then that cost of transmission will
be included in the energy bids of those resources. 5
12
The proposal of the JDA parties is similar to CAISO’s proposal in that there will be a $0
13
rate charged for transmission service of JDA energy from the source system and this
14
service will be provided reciprocally among the JDA participants, who are all located in
15
the PSCo BAA. JDA participants will still pay for the transmission system where their
16
loads are located. However, requiring the participants to pay additional transmission
17
costs for the transmission system where the energy is sourced would cause the overall
18
price of their JDA energy to increase and defeat the efficiencies and, ultimately, the
19
purpose of the JDA arrangement.
20
Q.
WILL
THE
PSCO
TRANSMISSION
FUNCTION
INCUR
COSTS
IN
21
PROVIDING JOINT DISPATCH TRANSMISSION SERVICE THAT ARE NOT
22
RECOVERABLE THROUGH A $0 RATE?
23
A.
No. The extent of PSCo’s transmission function activities associated with the JDA will
24
be limited to processing and administering the associated Joint Dispatch Transmission
25
Service Agreements. The number of these agreements is limited (with only three
26
signatories to the JDA to date, only three agreements must be processed) and it is
27
expected that all such service agreements will use the pro forma Joint Dispatch
5
PacifiCorp, 147 FERC ¶ 61,227 at P 146 (2014).
Exhibit PSC-1
Page 22 of 24
1
Transmission Service Agreement proposed by PSCo in this proceeding. Further, there is
2
no settlement, billing, or payment required under the JDA agreement by the transmission
3
function. Therefore, the costs to execute and administer the Joint Dispatch Transmission
4
Service Agreements are de minimis and do not need to be independently captured or
5
accounted for. PSCo has identified no other costs that its Transmission function would
6
incur to facilitate Joint Dispatch.
7
The only other activity performed by PSCo’s transmission function upon which
8
the JDA is dependent is the regular updating and posting of Available Transfer Capability
9
(“ATC”) on the PSCo OASIS. However, PSCo’s Transmission business unit already
10
updates and posts ATC in real time when a third party submits and confirms a
11
Transmission Service Request and no additional activity is required. Because the ATC
12
update is already a part of PSCo Transmission’s normal activities, it will not experience
13
any incremental increase in ATC management activity levels or costs in support of the
14
JDA.
15
Q.
16
17
ARE THERE OTHER COSTS ASSOCIATED WITH THE JDA THAT WILL BE
ALLOCATED TO TRANSMISSION CUSTOMERS?
A.
Some costs that are associated with IT and software could be allocated to the
18
transmission function through an existing salaries and wages allocator factor, resulting in
19
a pass-through of a portion of the costs to transmission customers through transmission
20
rates. In the separate, contemporaneous filing by PSCo of the revised JDA, Ms. Deborah
21
Blair identifies how PSCo proposes to identify the costs that might be allocated to
22
transmission through the allocator and to apply an offsetting credit such that there is no
23
impact to transmission customers as a result of the JDA.
Exhibit PSC-1
Page 23 of 24
1
Q.
2
3
HOW WILL LOSSES BE CHARGED UNDER THESE PROPOSED TARIFF
PROVISIONS?
A.
As provided in the proposed tariff language, all Joint Dispatch Transmission Service
4
Customers will be responsible for losses on each Party’s system used for delivery of JDA
5
energy. So, for example, if energy is delivered from PRPA to BHCE, which necessarily
6
involves a delivery across PSCo’s system, BHCE will be assessed losses by both PRPA
7
and PSCo.
8
Q.
9
10
WILL JOINT DISPATCH CUSTOMERS BE RESPONSIBLE FOR ANCILLARY
SERVICE CHARGES?
A.
Ancillary service charges will not apply to Joint Dispatch Transmission Service as a
11
separate transmission service. However, Joint Dispatch Transmission Service Customers
12
will continue to be responsible for ancillary service charges applicable to any service they
13
may take under Part II, III, or IV of the Xcel Energy OATT, including Scheduling,
14
System Control and Dispatch, Reactive Supply and Voltage Control, Reserve Sharing,
15
Operating Reserve – Spinning, and Operating Reserve -- Supplemental.
16
Notably, however, participation in the JDA will effectively eliminate imposition
17
of charges under Schedule 4 of the Xcel Energy OATT for those customers taking other
18
transmission service under the Xcel Energy OATT because, by definition, PSCo will be
19
responsible for balancing the load and resources of all parties to the JDA. More detail
20
about the services offered under the JDA and the charges associated with those services is
21
found in the companion JDA filing
22
23
Q.
IN THE JUNE ORDER, THE COMMISSION SUGGESTED THAT THE PSCO
TRANSMISSION FUNCTION COULD ADMINISTER THE JDA, IN ORDER TO
Exhibit PSC-1
Page 24 of 24
1
ELIMINATE STANDARDS OF CONDUCT CONCERNS. IS THIS FEASIBLE
2
FROM PSCO’S PERSPECTIVE?
3
A.
No.
While transmission function personnel are adept at managing the transmission
4
system, they do not have the personnel or skill sets to routinely dispatch resources on an
5
economic basis. Implementing that skill set within the transmission organization would
6
result in significant duplication of resources. Further, to the extent the Commission
7
believes a Standards of Conduct issue exists, it would seem that having transmission
8
function personnel administer the JDA would constitute a violation of the independent
9
functioning requirement because the PSCo transmission function would be engaging in
10
11
sales of energy among the JDA parties and arguably engaging in merchant activities.
Q.
12
13
HOW HAS PSCO ADDRESSED THE JUNE ORDER’S STANDARDS OF
CONDUCT CONCERNS IN THIS FILING?
A.
As explained in its request for rehearing submitted in Docket No. ER15-237-000, et al.,
14
PSCo does not believe that information exchanged under the JDA is transmission
15
function information that must be controlled by the PSCo transmission function or
16
subject to the Standards of Conduct at all. Nevertheless, the JDA parties have attempted
17
to address the Commission’s concern in this filing. The testimony of John Welch in the
18
accompanying JDA filing explains PSCo’s proposed approach to mitigate the
19
Commission’s concerns.
20
IX
CONCLUSION
21
Q.
DOES THIS CONCLUDE YOUR PREPARED PRE-FILED TESTIMONY?
22
A.
Yes.
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Public Service Company of Colorado
)
)
)
Docket No.
STATE OF COLORADO )
COUNTY OF DENVER
)
)
VERIFICATION
I, Terri K. Eaton, being duly sworn, depose and state that I am the witness identified in the
foregoing prepared testimony, and that the statements of fact set forth herein are tree and correct
to the best of my knowledge, information and belief.
Subscribed and sworn to before me this~ ~ day of
.J
My commission expires:~’Jd-~
Notary Public
State of Colorado
Notary IO 20144008609