Review of Proposed Adjustments
to
Salt River Project’s
Standard Electric Price Plans
Prepared by:
John Chamberlin
Timothy Lyons
December 12, 2014
Table of Contents
Executive Summary ......................................................................... 1
Background ................................................................................................1
Price Plan Proposals ..................................................................................1
Review ........................................................................................................3
Evaluation ...................................................................................................3
Conclusion ..................................................................................................7
1.0
Introduction............................................................................. 9
1.1
2.0
The Need for a General Price Increase................................ 11
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
3.0
Approach .........................................................................................9
Overview ........................................................................................11
FY2016 Financial Forecast ............................................................11
Sales and Revenue Forecast.........................................................13
Net Plant and Expenditure Forecast ..............................................15
Mitigating Efforts ............................................................................17
Proposed Increase Needed to Achieve Financial Goals ................17
Comparison to Other Electric Utilities ............................................21
Conclusion .....................................................................................23
Cost Allocation Study and Revenue Targets ...................... 24
3.1
3.2
3.3
3.4
Overview ........................................................................................24
Review of the SRP’s Cost of Service Study in 2013 ......................24
Results of the FY2016 Cost of Service Study ................................25
Changes in the Cost of Service Study ...........................................27
3.4.1 Change in Production Allocator ...........................................27
3.4.2 Change in Transmission Allocator .......................................29
3.4.3 Change in Distribution Cost Allocator ..................................30
3.4.4 Change in Customer Service Allocator................................31
3.4.5 Change in Load Data ..........................................................32
3.5
3.6
4.0
Target Class Returns .....................................................................32
Conclusion .....................................................................................33
Proposed Changes to Standard Price Plan Designs.......... 35
4.1
4.2
4.3
4.4
4.5
Overview ........................................................................................35
Approach .......................................................................................36
Recovery of Revenue Targets .......................................................36
Increase in Fixed Charge Revenues ..............................................37
Seasonal Differentials ....................................................................45
4.5.1 Marginal Costs ....................................................................45
SUSSEX ECONOMIC ADVISORS, LLC
PAGE i
4.5.2 Evaluation of Seasonal Differentials ....................................46
4.6
5.0
Conclusion .....................................................................................47
New Pricing Initiatives .......................................................... 48
5.1
Customer Generation for Residential Customers ..........................48
5.1.1 Overview of Cost Recovery .................................................48
5.1.2 Concerns with Current Approach: Net Energy Metering.....49
5.1.3 Two Areas for Potential Solutions .......................................51
5.1.4 A note on decoupling mechanisms as an alternative means to
address fixed cost underrecovery ..................................................56
5.1.5 Review of SRP’s Customer Generation Price Plan for
Residential Service Proposal .........................................................57
5.1.6 Evaluation of SRP’s Customer Generation Price Plan
Proposal.........................................................................................58
5.2
Standby Rider ................................................................................61
5.2.1 Review of the Standby Rider Proposal ................................61
5.2.2 Evaluation of the Standby Rider Proposal ...........................62
5.3
Electric Vehicle Rate ......................................................................63
5.3.1 Review of the Electric Vehicle Rate Proposal .....................63
5.3.2 Evaluation of the Electric Vehicle Rate Proposal ................64
6.0
Conclusions .......................................................................... 66
Appendix A: Review of Proposed Price Plans ............................. 67
A.1
Residential Service Price Plans .....................................................67
E-23 Residential Price Plan ...........................................................67
E-26 Residential Time-of-Use Price Plan.......................................68
E-24 Residential M-Power Price Plan for Pre-Pay Service ............69
E-28 Residential M-Power Time-of-Use Price Plan .......................70
E-27 Residential Customer Generation Price Plan ........................70
E-22 and E-25 Experimental Price Plans for Super Peak Time of-Use
Price Plan ......................................................................................71
E-29 Experimental Price Plan for Super-Off Peak Time of Use
Electric Vehicles (“EV TOU”) .........................................................71
A.2
General Service Price Plans ..........................................................72
E-36 General Service Time-of-Use Price Plan...............................72
E-32 General Service Price Plan ...................................................73
SUSSEX ECONOMIC ADVISORS, LLC
PAGE ii
E-34 M-Power Pre-Pay Price Plan .................................................74
E-33 Experimental Price Plan for Super Peak Time of Use ...........74
A.3
Pumping Price Plans......................................................................74
E-47 Standard Electric Price Plan for Agricultural Pumping...........74
E-48 Standard Electric Price Plan for Agricultural Pumping...........75
A.4
Lighting Service Price Plans ..........................................................75
E-54 Standard Electric Price Plan for Traffic Signal Lighting Services
............................................................................................75
E-56 Standard Electric Price Plan for Public Lighting Service .......76
E-57 Standard Electric Price Plan for Private Security Lighting
Service ...........................................................................................77
A.5
Large General Service Price Plans ................................................78
E-61 Standard Electric Price Plan for Secondary Large General
Service ...........................................................................................78
E-63 Standard Electric Price Plan for Primary Large General Service
............................................................................................78
E-65 Standard Electric Price Plan for Dedicated Large General
Service ...........................................................................................79
E-66 Standard Price Plan for Dedicated Large General Service with
Integrated Interruptible Load ..........................................................80
Critical Peak Experiment Price Plan, Supplemental to E-65 Price
Plan ............................................................................................80
A.6
Riders ............................................................................................81
Economy Discount Rider ...............................................................81
Medical Life Support Equipment Discount Rider............................81
Renewable Energy Credit Pilot Rider.............................................82
Buyback Service Rider...................................................................82
Solar Net Metering Pilot Rider .......................................................83
Time-of-Use Residential Community Solar Pilot Rider ..................84
Business Community Solar Pilot Rider ..........................................85
Renewable Energy Services Pilot Rider ........................................86
Time-Dependent Demand Rider Supplement to E-47 ...................86
Unmetered Credit Rider Supplemental to E-36..............................86
Lighting Equipment Rider Supplemental to E-56 and E-57 ............87
SUSSEX ECONOMIC ADVISORS, LLC
PAGE iii
Municipal and Non-Municipal Lighting Equipment Rider
Supplemental to E-56 ....................................................................87
Private Security Lighting Equipment Rider Supplemental to E-57 .88
Standby Electric Service Rider for Power Production Facilities .....88
Facilities Rider ...............................................................................89
Use Fee Interruptible Rider ............................................................89
Customized Interruptible Rider ......................................................90
Full Service Requirements Rider ...................................................90
Monthly Energy Index Rider...........................................................90
Fuel and Purchased Power Adjustment Mechanism .....................91
Systems Benefits Charge (“SBC”) .................................................91
Environmental Programs Cost Adjustment Factor (EPCAF) ..........92
SUSSEX ECONOMIC ADVISORS, LLC
PAGE iv
Executive Summary
Background
Sussex Economic Advisors, LLC (“Sussex”) was retained by the Board of Directors of the Salt
River Project Agricultural Improvement and Power District (the “Board”) to review and evaluate
Salt River Project Management’s (“SRP” or “Management”) Proposed Adjustments to its Standard
Electric Price Plans. SRP is proposing an overall increase of 3.9 percent in its Standard Electric
Price Plans to be effective in April 2015. The increase is expected to generate additional revenues
of $109.7 million. The proposed adjustments affect all price plans.
SRP believes that the increase is needed to maintain its financial ability to fulfill its mission of
serving low-cost, reliable water and power to its customers. Key cost drivers for the proposed
increase include:
•
Meeting regulatory/environmental requirements, including the Coronado Emissions
Control Project at the Coronado Generating Station.
•
Maintaining reliability, safety, and aging infrastructure, including cost associated with
SRP’s transmission and distribution (“T&D”) systems and corporate infrastructure.
•
Meeting growth requirements, including capital and operating expenditures to build and
maintain investments in generation, transmission, and distribution systems, such as the
purchase of one generating unit at the Mesquite Generating Station and transmission
system expenditures in the Southeast Valley and Price Road Corridor Projects.
The proposed increase is based on a financial forecast of revenues, expenses, and net plant for
Fiscal Year 2016 (“FY2016”). The plan includes growth of approximately 35,000 customers since
SRP’s most recent Price Process (which was based on a FY2014 financial forecast). The FY2016
forecast reflects a slight increase in use per customer, reversing a declining trend in use per
customer over the most recent price processes.
Price Plan Proposals
SRP has proposed several changes to its existing price plans, including:
•
An overall price increase of 3.9 percent.
•
Increases in several fixed price components of the standard price plans, including the
Monthly Service Charges (“MSC”), facility charges, and demand charges, to better
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 1
achieve recovery of fixed cost components. The increases include a $3.00 increase in the
residential MSC, from $17.00 per month to $20.00 per month.
•
New demand charges for Large General Service customers to better achieve recovery of
generation, transmission, and distribution costs.
•
Increases in the peak-to-winter seasonal variable price differentials to better reflect
seasonal differentials in the marginal cost of service.
•
Other proposed changes include: (a) transfer of facility costs from the Facilities Rider to
the respective E-61 and E-63 price plan to align prices with the functional costs; (b) an
increase in the Economy Discount Rider of $3.00 per month in the winter months, resulting
in a winter discount of $20.00 per month as compared to the summer discount of $21.00
per month; and (c) a freezing of the Medical Life Support Equipment Discount Rider from
new participation, instead meeting this need via a program that better protects eligible
customers.
In addition to changes in its existing price plans, SRP has proposed two new price plans and
modification of the Standby Rider: (1) Customer Generation for Residential Service (“E-27”); (2)
Experimental Time-of-Use with Super Off-Peak for Electric Vehicles (“E-29”); and (3) Standby
Electric Service Rider for Power Production Facilities. The proposals all have in common an
attempt to develop appropriate prices for customers that have unusual (i.e., different from
standard price plans) load characteristics:
•
The customer generation E-27 price plan is designed to better reflect the cost of service
for residential customers with small-scale distributed generation (“DG”) units, including
roof-top solar.
•
The Experimental Electric Vehicle (“EV”) E-29 price plan is designed to reflect the lower
cost of providing electric service during the nighttime, super off-peak period, while
providing an incentive for residential customers to charge their EV overnight.
•
The standby service rider is designed to recover the cost of service from industrial
customers with large-scale DG units.
The proposed price plan designs are based on an Unbundled Revenue Analysis (“URA” or “cost
of service study”) that allocates SRP’s total cost of service to individual price plans, and a Marginal
Cost of Service Study. Recently, Sussex conducted a comprehensive review and evaluation of
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 2
SRP’s cost of service study. 1 Sussex recommended several improvements to the study, which
have been incorporated into the current cost of service study. With these improvements, SRP’s
cost of service study produces results that are reasonable, accurate, consistent with industry
practices, and can be relied upon for setting prices.
Review
Sussex’s review and evaluation of SRP’s proposals consisted of the following:
•
Reviewed Management’s proposed price plans, along with supporting reports,
documents, workpapers, data, calculations, and analyses.
•
Held numerous discussions with SRP staff.
•
Prepared analysis and evaluation of the reasonableness of SRP’s proposals. We interpret
reasonableness as addressing the following questions:
o
Has SRP demonstrated a sufficient need for the overall price increase?
o
Are the proposed prices consistent with the Board’s pricing policies, including equity,
gradualism, cost relation, and sufficiency?
o
Do the proposed prices reflect the underlying cost drivers at least as well as the
existing set of prices?
•
Prepared written report.
Evaluation
The level of the overall price increase is reasonable. Our conclusion is based on analysis of the
cost drivers for the increase, a review of the report by the PFM Group, 2 and a comparison of
similar increases for other companies in the electric industry.
•
The proposed price increase is based on a FY2016 financial forecast that reflects capital
and operating cost increases largely driven by:
meeting regulatory/environmental
requirements; maintaining reliability and safety standards and an aging infrastructure; and
meeting growth requirements.
•
The capital cost increases are consistent with other companies in the electric industry. As
discussed in Section 2.0, there has been a five-fold increase in U.S. electricity
1
2
“Cost of Service Report,” prepared by John Chamberlin and Timothy Lyons of Sussex Economic
Advisors, LLC, December 16, 2013.
“Financial Market and Capital Structure Considerations in Public Power Pricing Decisions”, prepared
by Public Financial Management, Inc., December 2014.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 3
transmission investment from 1997 to 2012. The U.S. Energy Information Agency (“EIA”)
cites several reasons for the increase, including: improving reliability, connecting to
renewable energy sources, accommodating changes in electricity demand, and increasing
costs to build new facilities. 3
•
The proposed increase will strengthen SRP’s financials that otherwise would lead to a
decline in credit ratings and increase in borrowing costs. This conclusion is based on a
report from the PFM Group, which determined that the proposed price increase “should
preserve SRP’s credit strength” and in the absence of such a price increase, “PFM would
expect at least one of the rating agencies to respond with some form of negative action”. 4
•
The proposed price increase is comparable to other electric utilities. As discussed in
Section 2.0, SRP’s proposed price increase of 3.9 percent is comparable to rate increases
by other electric utilities over the past five years. The rate increases were supported by
similar cost drivers as SRP, including investments related to safety, reliability, and
environmental regulations.
SRP’s cost of service study produces results that are reasonable, accurate, consistent with
industry practices, and can be relied upon for setting prices. In addition, the established revenue
targets appropriately strike a balance between equity (i.e., treating all customers in an
economically fair manner) and gradualism (i.e., stabilizing price levels and smoothing the impacts
of cost movements).
•
The cost of service study incorporates improvements recommended by Sussex in its
recent review and evaluation of SRP’s cost of service study.
•
The price plan revenue targets were set based on a formulaic approach that is
transparent, reviewable, accurate, and appropriately balances competing pricing
principles.
SRP’s proposed price plans are appropriate, and should be approved.
•
The proposed price plans are expected to recover the revenue targets established in the
cost of service.
•
The proposed prices improve the reflection of cost causation in prices, including higher
fixed prices that better align with fixed cost of service. As discussed in Section 4.0, SRP’s
3
4
“Investment in electricity transmission infrastructure shows steady increase”, EIA, August 26, 2014,
http://www.eia.gov/todayinenergy/detail.cfm?id=17711.
“Financial Market and Capital Structure Considerations in Public Power Pricing Decisions”, prepared
by Public Financial Management, Inc., December 2014, at 9.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 4
proposal to recover more costs through a fixed monthly customer charge reflects a gradual
movement toward improving fixed cost recovery in manner that is consistent with industry
trends.
•
While MSC increases result in percent increases in monthly bills higher than the system
average for low use, E-23 customers (i.e., those that use 400 kWh or less per month), the
actual increase is approximately $3.50 per month, which is ameliorated for limited income
customers due to the proposed increase in the Economy Discount Rider by $3.00 per
month during the winter months. Low use customers represent approximately 6 percent
of E-23 customers. Even with the increases, the proposed MSC’s are still less than fixed
customer costs for most price plans.
•
The proposed prices produce a slight improvement in the seasonal variable price
differentials, consistent with the result of the Marginal Cost Study.
SRP’s proposed customer generation price plan addresses the unique load characteristics of
residential customers that operate distributed generation units in a manner that appears to better
align rates and cost recovery, and addresses the growing problem of under-recovery of costs
from DG customers.
•
The current residential price plans recover a substantial portion of fixed costs in usage
charges that are based upon the load characteristics of the entire price plan. To the extent
that actual usage for any group of customers is significantly different than estimated usage
for the class as a whole, as would be the case when customers install DG units, then the
utility rates no long recover the full cost of service for those customers.
•
Customers with DG units are compensated for their output through a method known as
Net Energy Metering (“NEM”), where the generation output is netted against on-site usage
and customers are effectively paid the retail rate as a bill credit. NEM is a common
approach in the industry, and has been viewed as an important incentive for emerging
renewable, DG technologies.
•
However, there are two concerns with this approach: (1) DG customers are implicitly paid
the full retail price for their output, since the DG output is netted against customer usage,
and (2) DG customer usage is reduced by the DG output, resulting in less revenue and
lower fixed cost recovery for the utility (since fixed cost recovery is based upon customer
usage). Fixed costs not recovered from DG customers are then recovered from non-DG
customers, resulting in cost shifting among customers that also raises equity concerns.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 5
•
SRP’s proposed solution is to implement a price plan that addresses these concerns while
continuing to provide an economic incentive (via continuation of NEM) for residential
customers who install a DG unit. The proposed E-27 price plan does this by establishing
a Time-of-Use (“TOU”) price plan designed exclusively for self-generation customers,
establishing fixed prices to align with fixed costs, and setting energy prices to match
marginal variable cost by differentiated costing period (i.e., by season, by time of day).
Under the proposed E-27 price plan, DG customers would retain the benefit of NEM;
however, the effective benefit would be lower than the current level because the variable
component of the prices are lower with the E-27 price plan than current price plans.
•
Certain aspects of the proposed approach are consistent with the approaches taken by
other electric utilities in the U.S., as discussed in Section 5.0 (although it has some
important differences). Specifically, other utilities have proposed and implemented higher
fixed charges, as well as started the process to move customers onto rates more aligned
with cost (such as TOU rates) to achieve better price signals for all customers, including
DG customers.
•
The E-27 price plan design is a reasonable approach, given the challenges of designing
a price plan for customers whose load characteristics are different from those of traditional
customers. SRP designed the price plan on the basis of current and planned load
characteristics that at this point appear to be reasonable.
•
SRP’s proposal recognizes the challenges of serving self-generation customers, in
general, and addressing NEM, in particular. The issue has been contested in many state
utility rate proceedings, including Arizona. SRP’s approach recognizes that current DG
customers have invested in DG units on the basis of economic parameters that are now
different under the E-27 price plan. In response, SRP proposes to ‘grandfather’ current
DG customers and apply the new E-27 price plan to new DG customers. While this
approach does not address cost shifting among current customers, the impact is
manageable with current levels of installed DG. More importantly, the proposed approach
puts in place a long-term solution that addresses a potentially significant impact and better
reflects prices that recover the underlying cost of service.
•
The proposed E-27 price plan has an important improvement over numerous recent
proposals by other utilities. It is not simply an increase in fixed charges to DG customers.
Inclusion of the demand charges allows DG customers to tailor rooftop solar designs in
ways to increase their savings, while simultaneously increasing the value of such systems
to SRP. DG customers can also reduce their levels of instantaneous demand (through, for
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 6
example, demand interlocks and/or storage), which can yield both significant additional
bill savings, and additional value to the utility.
•
It is important to note that monthly bills under the E-27 price plan are lower after installation
of a DG unit than monthly bills under the E-26 price plan prior to installation of a DG unit.
The proposed standby rider appropriately reflects the cost of serving standby customers. The
rider includes a daily demand and energy charge that reflects the cost of service during an outage.
The daily demand does not contain a “ratchet”, thus encouraging standby customers to return to
self-generation as soon as possible (and therefore allows the customer to avoid paying for
“traditional” service as soon as the outage is resolved). The price plan is consistent with standby
service at other electric utilities. 5
The proposed Experimental Electric Vehicle price plan appropriately reflects the cost of serving
the nighttime, super off-peak period, as well as provides an incentive for EV customers to charge
their EV during the nighttime, when generation costs are low.
Conclusion
Based on our review and evaluation of SRP’s proposals, we conclude the following:
•
SRP has demonstrated a need for a price increase. SRP has demonstrated the need
for a 3.9 percent revenue increase based on recent financial forecasts and performance
measures, consistent with a financial policy that permits continued access to capital
markets by a highly rated entity. The proposed price increase is expected to bring retail
margins to a level that management believes is sufficient to cover operating expenses and
provide adequate contribution to new investment, albeit below historic levels.
•
The cost allocation study methodology and results are reasonable, accurate,
consistent with industry practices, and can be relied upon for setting prices. In
addition, the cost study results can be used to establish revenue targets that improve the
equity of SRP’s price plans.
•
The proposed price plans recover the 3.9 percent revenue increase and continue to
improve fixed cost recovery. Further, the price plans generally continue to move prices
slightly closer to the underlying marginal cost of service.
5
Direct Testimony of John H. Chamberlin, Ph.D., on behalf of Entergy Gulf States, Inc. in Louisiana, in
Docket No. U-22137.
Also see “Standby Rate for Customer-Site Resources,” prepared by U.S. Environmental Protection
Agency, Office of Atmospheric Programs, December 2009.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 7
•
The proposed new price plans address non-traditional uses of SRP’s system in a
way that reflects the cost service, while shielding customers who have made
investments based upon the incentives contained in existing price plans.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 8
1.0 Introduction
Sussex Economic Advisors, LLC (“Sussex”) was retained by the Board of Directors of the Salt
River Project Agricultural Improvement and Power District (the “Board”) to review and evaluate
Salt River Project Management’s (“SRP” or “Management”) Proposed Adjustments to its Standard
Electric Price Plans. SRP is proposing an overall increase of 3.9 percent in its Standard Electric
Price Plans to be effective in April 2015. The increase is expected to generate additional revenues
of $109.7 million. The proposed adjustments affect all price plans.
SRP believes that the increase is needed to maintain its financial ability to fulfill its mission of
serving low-cost, reliable water and power to its customers. Key cost drivers for the proposed
increase include:
•
Meeting regulatory/environmental requirements, including the Coronado Emissions
Control Project at the Coronado Generating Station.
•
Maintaining reliability, safety, and aging infrastructure, including cost associated with
SRP’s transmission and distribution (“T&D”) systems and corporate infrastructure.
•
Meeting growth requirements, including capital and operating expenditures to build and
maintain investments in generation, transmission, and distribution systems, such as the
purchase of one generating unit at the Mesquite Generating Station and transmission
system expenditures in the Southeast Valley and Price Road Corridor Projects.
The proposed increase is based on a financial forecast of revenues, expenses and net plant for
Fiscal Year 2016 (“FY2016”).
1.1
Approach
Sussex’s review and evaluation addressed the following questions:
•
Has Management demonstrated a sufficient need for an overall price increase?
•
Are the proposed prices consistent with SRP’s pricing objectives of gradualism, cost
relation, equity, and sufficiency?
•
Do the proposed prices reflect the underlying cost drivers at least as well as the existing
set of prices?
Sussex’s review and evaluation of Management’s proposal included the following tasks:
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 9
•
Reviewed Proposed Adjustments to SRP’s Standard Electric Price Plans Effective with
the April 2015 Billing Cycle (“Blue Book”).
•
Reviewed Unbundled Revenue Analysis in Support of Proposed Adjustments to SRP’s
Standard Electric Price Plans Effective with the April 2015 Billing Cycle (“Green Book”).
•
Reviewed Unbundled Revenue Analysis (“URA”) for functionalized costs and revenue
analysis used to determine class revenue targets.
•
Reviewed SRP’s Marginal Cost Study.
•
Reviewed workpapers and supporting analysis regarding the need for a price increase
and the proposed changes in the price plans.
•
Prepared questions and reviewed responses by SRP staff to specific questions about the
proposed changes, and their impacts on customers.
•
Held numerous discussions with SRP staff on various aspects of the pricing proposal.
•
Conducted industry research.
•
Prepared various analyses of the pricing proposals.
The balance of this report discusses our review and evaluation of SRP’s price plan proposal in
the following sections:
Section 2.0
The Need for a General Price Increase: This section describes our review and
evaluation of SRP’s need for a general price increase, including cost drivers and
comparison to other companies in the industry.
Section 3.0
Cost Allocation Study and Revenue Targets: This section describes our review and
evaluation of SRP’s cost allocation study and revenue targets, including
methodology and data changes since the last price process.
Section 4.0
Price Plan Design: This section describes our review and evaluation of SRP’s
proposed price plans, including increased fixed charge recovery.
Section 5.0
New Pricing Initiatives: This section describes our review and evaluation of SRP’s
new pricing initiatives, including industry review and analysis.
Section 6.0
Conclusions.
Appendix A
Summary of review and evaluation for each price plan, and rider.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 10
2.0 The Need for a General Price Increase
This section describes Sussex’s review and evaluation of SRP’s need for a general price increase.
2.1
Overview
SRP proposes to increase its electric service prices by 3.9 percent effective with the April 2015
billing cycle, raising FY2016 revenues by $109.7 million. The revenue increase consists of the
following:
Figure 2.1: Components of the Net Increase in Revenues 6
Proposed Changes
Revenues
($Millions)
Increase in base prices for electric service
$124.6
Decrease in Environmental Programs Cost Adjustment
Factor ("EPCAF")
Decrease in Fuel and Purchased Power Adjustment
Mechanism (“FFPAM”)
Net increase in revenues
2.2
14.7
0.2
$109.7
FY2016 Financial Forecast
The proposed increase is supported by a FY2016 financial forecast that shows, at current price
levels, a forecasted rate of return substantially less than that approved in the most recent 2012
Price Process. While FY2016 retail revenues are expected to increase, operating costs are
expected to increase at a faster pace, resulting in a forecasted rate of return of 3.7 percent, which
is substantially less than the 5.3 percent return approved in the 2012 Price Process. SRP’s rate
of return is calculated as operating income, excluding EPCAF and FFPAM revenues, as a
percentage of net plant less Construction-Work-in-Progress (“CWIP”). The forecasted rate of
return is also less than the return needed to maintain SRP’s strong financial results.
Presently, SRP has a high credit rating, as demonstrated by its “AA/Aa1” bond ratings by Standard
and Poor’s and Moody’s Investment Services. Preserving SRP’s high credit rating requires an
adequate rate of return that is not expected at current price levels. In response, SRP proposes a
6
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 11
general price increase of 3.9 percent that will raise FY2016 revenues by $109.7 million and
produce a rate of return of 5.4 percent, which SRP believes is sufficient to maintain SRP’s strong
financial results.
In their report, PFM evaluated the impact of the price increase on SRP’s credit and determined
that the proposed increase should preserve SRP’s credit strength going forward. 7
A decline in credit strength can have a significant adverse effect on utilities and their customers.
Credit rating agencies observe and evaluate financial metrics that constitute credit strength, and
a decrease in such metrics can result in negative actions from those agencies, leading to
increased borrowing rates. As shown in Figure 2.2, Moody’s already considers SRP to be at the
low range of several metrics, which could be negatively affected in the absence of a rate increase.
Figure 2.2: SRP’s Scoring based on Moody’s Methodology 8
7
8
“Financial Market and Capital Structure Considerations in Public Power Pricing Decisions”, prepared
by Public Financial Management, Inc., October 2014, at 9.
Ibid., at 7.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 12
This is especially important considering SRP’s projected capital plans and its potential ability to
refinance over $2.0 billion in outstanding bonds in the near future (see Figure 2.3). According to
PFM, SRP’s borrowing rates could increase by roughly 0.25 percent if the price increase is not
implemented, increasing future debt service obligations and resulting in higher customer costs. In
the absence of a price increase, SRP would also require an additional $600 million of debt to
replace ratepayer equity funding. 9
Figure 2.3: Bond Series Potentially Eligible for Refinance 10
PFM’s report provides support for SRP’s proposed price increase, explaining that it “will provide
cash flow to cover debt service and contribute to SRP’s considerable capital improvement plan”
while sending “a message to the financial community that SRP is making the difficult decisions
that will balance the needs of current customers with the goal of maintaining its strong financial
condition.” 11
PFM also notes that “it appears to be necessary to prevent an eventual ratings downgrade”, and
that the absence of a price increase would have a very negative impact on the utility’s financial
metrics and, eventually, its customers. 12 This perspective is echoed by SRP, noting that “[a]bsent
a price adjustment, funds available, debt service coverage ratio and combined net revenues
would be at or below the 9 year lows for these key indicators of financial health.” 13
2.3
Sales and Revenue Forecast
The FY2016 financial forecast is based on a sales and revenue forecast that employs the same
general approach as used in past price processes. Specifically, the sales forecast of 29.3 million
megawatt-hours (MWh) is based on econometric models that forecasts by price plan the number
9
10
11
12
13
Ibid., at 3-4.
Ibid., at 4.
Ibid., at 9.
Ibid., at 4.
SRP Blue Book.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 13
of customers and use per customer.
The models include a combination of economic and
demographic variables, such as population, weather, and personal income. This is a common
approach in the industry, and, for SRP, this approach has produced forecasts that are generally
consistent with actual results.
Figure 2.4 compares the FY2016 customer forecast to the FY2014 customer forecast used in the
2012 price process.
Figure 2.4: Change in Forecast Customers (FY2014 to FY2016) 14
The Figure shows a 3.6 percent increase in the overall number of customers. The forecast of
residential customers is 3.7 percent higher, while the forecast of non-residential customers is 2.2
percent higher. The increase in residential customers includes a shift in customers from the E23 and E-26 Price Plans to the E-24 (pre-payment) and EZ-3 (Time-of-Use) Price Plans as a
result of SRP’s promoting the new price plans to customers seeking to lower their energy bills.
Figure 2.5 illustrates the forecast of residential use per customer. The Figure shows a slight
increase in residential use per customer over the next several years due to improving economic
conditions. The forecast reverses a decline in use per customer over the past several years.
Specifically, the Figure shows annual declines in residential use per customer over the past six
years ending FY2014, and a forecasted increase over the next several years. Residential use
14
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 14
per customer is not uniform across all price plans as E-24 use per customer of 12,246, one of
SRP’s fastest growing price plans, is substantially less than the overall residential use per
customer of 14,311.
Figure 2.5: Use per Customer (1988 – 2022) 15
The non-residential forecast shows a similar increase in use per customer.
2.4
Net Plant and Expenditure Forecast
The FY2016 financial forecast includes a significant increase in capital and operating
expenditures related to:
•
Meeting regulatory and environmental requirements.
Current U.S. Environmental
Protection Agency (“EPA”) regulations require significant capital expenditures related to
emission reductions on SRP’s coal-fired power plants. The expenditures include the
Coronado Emissions Control Project at the Coronado Generating Station.
•
Maintaining reliability and safety standards, and an aging infrastructure. SRP’s T&D
systems and corporate infrastructure are aging, requiring significant capital expenditures
to maintain them.
The expenditures include the wood pole and underground cable
replacement projects.
15
Figure provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 15
•
Meeting growth requirements. As discussed earlier, growth has started to return in SRP’s
service area, requiring significant capital expenditures in generation, transmission, and
distribution systems. These expenditures include the purchase of one generating unit at
the Mesquite Generating Station and transmission system expenditures in the Southeast
Valley Project and the Price Road Corridor Project.
•
Additional depreciation and taxes. The capital expenditures discussed above result in
higher depreciation and in lieu taxes.
The increase in capital and operating expenditures is consistent with other companies in the
industry. Figure 2.6 illustrates the five-fold increase in U.S. electricity transmission investment
from $2.7 billion in 1997 to $14.1 billion in 2012. 16
Figure 2.6: Investment in U.S. Electricity Transmission Infrastructure
The Figure provides a breakdown by type of transmission investment, including station
equipment, conduit, and supporting infrastructure. The U.S. Energy Information Administration
(“EIA”) cites several reasons for the increase, including:
16
•
Improving reliability;
•
Connecting to renewable energy sources;
“Investment in electricity transmission infrastructure shows steady increase”, EIA, August 26, 2014,
http://www.eia.gov/todayinenergy/detail.cfm?id=17711.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 16
•
Accommodating changes in electricity demand, particularly related to population shifts;
and
•
Increasing costs to build new facilities.
These items are consistent with SRP’s cost drivers, and include an increase in net plant
investment from the FY2014 financial forecast to the FY2016 financial forecast.
2.5
Mitigating Efforts
SRP has taken steps to control the cost increases, holding Operations and Maintenance (“O&M”)
cost increases to less than 1.0 percent between the FY2014 and FY2016 financial forecasts.
Some examples include:
•
Increased self-service options;
•
Added new PayCenters;
•
Renegotiated supplier contracts; and
•
Sold retired assets and recycled materials.
While these initiatives have reduced the overall amount needed for a price increase, they are not
sufficient to allow SRP to meet its financial goals without a price increase.
2.6
Proposed Increase Needed to Achieve Financial Goals
SRP proposes to increase its overall price levels by 3.9 percent. SRP believes that the proposed
increase is needed to adequately fund planned capital and operating expenditures, while
maintaining strong financial results and high credit ratings needed to access capital at lower
interest rates. Such high credit ratings have resulted in lower annual debt service and financing
costs that are passed on to customers in the form of lower prices.
SRP relies on two key measures to determine financial strength: debt service coverage, and debt
coverage.
Figure 2.7 shows SRP’s debt service coverage with and without the price increase. Specifically,
the Figure shows that the proposed price increase is needed for SRP to maintain its historic debt
service coverage ratios, which are close to the 2.5-3.0 times range.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 17
Figure 2.7: Debt Service Coverage Ratio 17
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
FY06
FY07
FY08
FY09
Actual
FY10
FY11
FY12
Without Increase
FY13
FY14
FY15
FY16
With Increase
Figures 2.8 and 2.9 show additional financial metrics with and without the price increase. The
Figures show that the proposed price increase is needed for SRP to support its financial metrics.
17
SRP Blue Book.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 18
Figure 2.8: Combined Net Revenues ($Millions) 18
500
400
300
200
100
0
-100
FY06
FY07
FY08
Actual
18
FY09
FY10
FY11
Without Increase
FY12
FY13
FY14
FY15
FY16
With Increase
Ibid.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 19
Figure 2.9: Operating Margin per Retail MWh ($/MWh) 19
16
14
12
10
8
6
4
2
0
FY06
FY07
FY08
Actual
19
FY09
FY10
FY11
Without Increase
FY12
FY13
FY14
FY15
FY16
With Increase
Ibid.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 20
2.7
Comparison to Other Electric Utilities
While every utility has unique cost and investment requirements, it is useful to see how SRP’s
proposed increase compares with those of other electric utilities. Figure 2.10 illustrates the range
of recent price increases at various southwestern electric utilities.
Figure 2.10: Sample of Recent Electric Base Rate Increases at Vertically-Integrated
Utilities20
20
SNL Financial. Includes electric rate increases that have been approved. Although Arizona Public
Service (APS) did not receive a rate increase in their most recent case, they did receive approval for a
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 21
As shown in Figure 2.10, there has been a wide range of approved base rate increases at
vertically-integrated utilities in the southwestern United States over the last five years. In general,
the rate increases were based on similar cost-drivers as those impacting SRP. For many, the rate
increases were based on increases in infrastructure investments (related to safety, reliability, and
environmental regulation) as well as declining use per customer and increasing O&M costs (such
as depreciation expense related to increased plant-in-service).
For example, Tucson Electric Power noted that increased costs were related to environmental
regulation and a significant increase in rate base due to “investments necessary to maintain high
levels of safety and service reliability.”
21
LADWP’s 2012-2014 proposed rate plan, which was approved by the City Council, cited its power
supply replacement, power reliability, and customer opportunities programs as the main cost
drivers necessitating the rate increase. These programs require significant investments in
rebuilding local power plants, renewable energy, coal transition, replacement of the aging T&D
system backbone, energy efficiency, and customer solar programs. 22
Southwestern Public Service Company’s recent rate increase resulted from capital investment in
rate base (production, transmission, and distribution), costs to comply with New Mexico
Renewable Portfolio Standard, depreciation and amortization expense (due to increased capital
in service), and the impact of changes to production and transmission allocators. 23
Nevada Power Company 24 and PacifiCorp (UT) 25 both cite capital investments as a major driver
of their requested rate increases, with PacifiCorp noting the impact of a lower retail sales forecast,
resulting in fewer kWh over which to spread fixed costs.
Additionally, Sacramento Municipal Utility District (“SMUD”) cited increased costs related to
meeting state mandates for renewable energy, and also noted the need to align costs and
revenues through transition to time-based rates for all residential customers in 2018. 26
21
22
23
24
25
26
Lost Fixed Cost Recovery Mechanism and a fixed surcharge on customers benefiting from the state’s
renewable energy rules. In addition, the Arizona Corporation Commission is currently determining how
to adjust rates to reflect APS’s Four Corners acquisition.
Docket D-E-01933A-12-0291, Direct Testimony of Kevin P. Larson, at 3-5.
“Proposed Rates 2012-2014”, Los Angeles Department of Water & Power, June 2012.
Docket C-12-00350-UT, Direct Testimony of Alice K. Jackson, at 12-15.
Docket D-11-06006, Application to Change Electricity Utility Annual Revenue Requirement, at 2-3.
Docket D-13-035-184, Application for General Rate Increase, at 5-6.
“Preparing for the future: 2013 Rate Proposal”, Sacramento Municipal Utility District.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 22
2.8
Conclusion
Our conclusion regarding the proposed general price increase was based on a reasonableness
standard that concluded:
•
The customer and sales forecast is based on analysis of econometric data, which has
produced reasonable results in the past.
•
The revenue forecast is based on a set of assumptions consistent with the sales forecast.
•
The forecast of capital projects is likely to occur, and projects are similar to those executed
by other companies in the industry.
•
The forecast of operating expenditures appears likely to occur.
•
The growth-related capital projects are developed from the same set of customer and
sales growth assumptions as the revenue forecast.
Based on these determinations, the overall conclusion is that the proposed price increase meets
the reasonableness standard, and therefore is needed to meet SRP’s financial criteria based on
its FY2016 financial forecast of revenue and capital and operating costs.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 23
3.0 Cost Allocation Study and Revenue Targets
This section describes Sussex’s review and evaluation of SRP’s cost allocation study and
revenue targets.
3.1
Overview
One of the SRP’s pricing principles is equity; i.e., the treatment of customers of all types in an
economically fair manner. SRP’s primary method to measure equity is through a rate of return
calculation. SRP’s rate of return is calculated as operating income, excluding EPCAF and FFPAM
revenues, as a percentage of net plant less CWIP. The rate of return for each price plan is
determined in SRP’s Unbundled Revenue Analysis (“URA”).
Prices are considered ‘equitable’ when the rate of return for a given price plan is the same as the
return across all of the price plans (“system average”). To the extent that returns for an individual
price plan are not the same as the system average, SRP establishes revenue targets to move the
price plan closer to the system average. For price plans with rates of return below the system
average, the revenue targets are set to increase prices at a level higher than the average price
increase. For price plans with rates of return above the system average, the revenue targets are
set to increase prices at a level less than the average price increase. In this manner, the price
plans over time move toward a more equitable price structure, while balancing the customer bill
impact of such movement.
3.2
Review of the SRP’s Cost of Service Study in 2013
Recently, Sussex conducted a comprehensive review and evaluation of SRP’s Unbundled
Revenue Analysis. The overall conclusion was that SRP’s cost of service study produces results
that are reasonable, accurate, and consistent with industry practice. The report included several
recommendations to improve the cost of service study.
In one instance, Sussex concluded that one of the demand allocators was inappropriate, and
recommended a specific change:
using higher, uninterrupted E-65 loads in preparing the
production cost allocator to eliminate double-counting of the interruptible benefit since interruptible
customers already received a direct benefit for their interrupted load through a credit on their bill.
In other instances, Sussex recommended SRP evaluate alternative methods for consideration in
future cost of service studies, and suggested that changes may be appropriate. These included:
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 24
•
Examining alternative methods to allocate distribution facility costs, since the results of the
then-current method were not consistent with the changes in customer demand over time;
•
Performing a study to classify distribution facilities into customer-related and demandrelated components;
•
Utilizing smart meter data to develop the demand allocators, following a technical process
to validate the data;
•
Improving the special study used to allocate customer service, billing and collections, and
meter reading expense; and
•
Acquiring the ability to use relative Loss of Load Probability (“LOLP”) rather than
Probability of Peak (“POP”) to allocate generation marginal costs to time periods.
As discussed below, we believe that the recommended changes, which SRP has addressed in
the current cost of service study, have resulted in an improved cost of service analysis since it
better reflects the costs to design, construct, and operate and maintain the facilities needed to
deliver reliable power to consumers, and is more consistent with generally accepted ratemaking
methods.
3.3
Results of the FY2016 Cost of Service Study
The results of the FY2016 cost of service study (which represents the FY2016 financial forecast
allocated to each price plan) are shown in Figure 3.1. The Figure shows that customers in some
price plans are currently paying less than their cost of service (i.e., price plan rate of return is less
than the system average) while customers on other price plans are paying more (i.e., price plan
rate of return greater than the system average). SRP has proposed revenue targets that move
each price plan closer to the system average.
The Figure shows current indexed returns (i.e., price plan rate of returns as a percentage of the
system average rate of return) moving closer to the system average. Indexed returns higher than
100 percent represent price plans that have a return higher than the system average. Index
returns less than 100 percent represent price plans that have returns less than the system
average. For example, the E-23 price plan has indexed returns above 100 percent and thus have
returns higher than the system average.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 25
Figure 3.1: Comparison of FY2016 Returns Utilizing Current and Proposed Prices 27
Figure 3.2 compares the results of the FY2016 study at current prices to the results of the FY2014
study also at current price. The change in indexed returns is due to a combination of factors,
including several recent higher-than-system-average price increases for residential price plans,
changes in customer loads, use of the more accurate smart meter data as the basis for allocation
factors, and improvements to the cost of service analysis.
27
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 26
Figure 3.2: Comparison of FY2014 and FY2016 Returns Utilizing Current Prices28
3.4
Changes in the Cost of Service Study
There are several changes in the production, transmission, distribution, and customer service
allocators in the current cost of service study, which collectively, allocate a significant portion of
the overall cost of service. Below is a discussion of each allocator.
3.4.1
Change in Production Allocator
Figure 3.3 shows the change in production allocators from the FY2014 to the FY2016 cost of
service studies.
28
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 27
Figure 3.3: Change in Production Allocators (FY2014 – FY2016) 29
The Figure shows the impact of a methodology change and in the underlying data since the last
cost of service study. SRP now utilizes higher, uninterrupted demands in developing the allocator
for the E-65 Price Plan, consistent with our recommendation. 30 The higher demands result in a
higher allocation of production-related costs to the E-65 Price Plan. Previously, SRP utilized
lower, interrupted demands.
The change to using the higher, uninterrupted demands is
appropriate since under the prior approach: (1) interruptible customers received two benefits: a
lower allocation of costs in the cost of service study, and a credit off their E-65 price; (2) noninterruptible, E-65 customers also received a benefit despite having no interruptible requirements;
and (3) SRP has not called an interruption in several years and at this point does not anticipate
an interruption in the near future. The prior methodology that adjusted actual coincident loads to
reflect potential interruptions understated E-65 customers’ use of production facilities. This
change also has the effect of slightly decreasing the production allocator for other customer
classes. In addition to the change in methodology, the Figure also reflects changes in the
underlying data, including: (1) a change in the forecasted number of customers in each price plan;
and (2) a change in coincidental peak demands per customer as a result of using the Meter Data
Management System (“MDMS”) data from the Smart Meters.
29
30
Sussex analysis of data provided by SRP.
“Cost of Service Report,” prepared by John Chamberlin and Timothy Lyons of Sussex Economic
Advisors, LLC, December 16, 2013.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 28
3.4.2
Change in Transmission Allocator
Figure 3.4 shows the change in transmission allocators from the FY2014 to the FY2016 cost of
service studies.
Figure 3.4: Change in Transmission Allocators (FY2014 – FY2016) 31
The Figure shows the impact of changes in the underlying data since the last cost of service
study, including: (a) a lower allocation of costs to wholesale customers; (b) a change in forecasted
number of customers in each price plan; and (c) a change in coincidental peak demands per
customer as a result of using the MDMS data from the Smart Meters. According to SRP, the
lower allocation of costs to wholesale customers is a result of fewer firm paths for wholesale
contracts as compared to retail. Figure 3.5 compares the current allocation to those in prior price
processes.
31
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 29
Figure 3.5: Allocation of Costs to Wholesale Customers (2005 – 2016) 32
Price Process
3.4.3
Percentage
2016
20.55%
2014
30.28%
2011
28.47%
2009
22.55%
2005
11.51%
Change in Distribution Cost Allocator
Figure 3.6 shows the change in distribution cost allocators from the FY2014 to the FY2016 cost
of service studies.
Figure 3.6: Change in Distribution Cost Allocator 33
The Figure shows the impact of a change in methodology and in the underlying data since the
last cost of service study.
SRP now utilizes a more common approach to developing its
distribution allocator, assigning facility costs related to class peak demand, such as distribution
substations and primary distribution lines, on the basis of class peak demands, and facility costs
32
33
Data provided by SRP.
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 30
to serve individual customer loads, such as secondary feeders and transformers, on the basis of
individual peak demands.
The change in methodology results in a lower allocation of costs to the residential classes.
Previously, SRP utilized a special study to allocate distribution costs. The change is appropriate
since the allocation method is more consistent with how costs are incurred, and is more consistent
with industry practice.
The change in underlying data includes: (a) the forecasted number of customer in each price plan;
and (b) coincidental peak demands per customer using the MDMS data from the Smart Meters.
3.4.4
Change in Customer Service Allocator
Figure 3.7 shows the change in customer service allocators from the FY2014 to the FY2016 cost
of service studies.
Figure 3.7: Change in Customer Service Allocator 34
The Figure shows the impact of changes in the underlying data from the last cost of service study,
including: (a) higher allocation of meter and Competitive Customer Service (CCS) costs to
residential customers; and (b) a change in the forecasted number of customers in each price plan.
SRP states that the higher allocation of meter costs to the residential classes results from the full
implementation of the Smart Meter program. Specifically, there is now less relative cost difference
between residential and non-residential meters.
34
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 31
The allocator also reflects a higher allocation of CCS costs to the residential classes. SRP states
that the higher allocation of CCS costs relates to a revised process to functionalize and allocate
CCS costs to the price plans. These results do not appear unreasonable as the residential class
represents approximately 90 percent of all customers.
3.4.5
Change in Load Data
Figure 3.8 shows the changes in the coincidental demand data used in development of the
demand allocator from the FY2014 to the FY2016 cost of service studies.
Figure 3.8: Change in Demands (kW) 35
The Figure shows changes in the underlying load data from the last price process, including: (a)
collected interval demand data utilizing Smart Meters; and (b) measured demands based on June
through September 2013 coincidental peak demands, updated from 2011 peak demands. This
is the first price process that relies on an URA with allocators derived from Smart Meter data.
Previously, SRP utilized data from a small but statistically representative sample per price plan of
customers with interval data recorder meters. Following a validation process, SRP utilized the
Smart Meter data on approximately 75 percent of customer meters to calculate coincidental peak
demands. As a result of the substantial increase in sample size (collectively, from approximately
2,000 meters to 750,000 meters), the current demands result in much narrower confidence
intervals, and improved certainty in the results.
3.5
Target Class Returns
In developing the target rates of return for each price plan, SRP balances two pricing principles:
equity (i.e., moving class returns closer to the system average) and gradualism (i.e., avoiding rate
shocks by limiting the size of the rate increase). Specifically, SRP sets the target rate of return
for an individual price plan at between 90 percent and 110 percent of the system average (or 4.9
35
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 32
to 5.9 percent in the current Price Process), while limiting the rate increases to an individual price
plan to between 75 percent and 150 percent of the system average (or 2.9 to 5.9 percent in the
current Price Process). SRP’s goal was to set the target or proposed rate of return to be within
those thresholds.
We reviewed the proposed revenue targets for each price plan to confirm that SRP’s guidelines
described above were applied accurately to achieve an overall rate of return of 5.4 percent, and
a general price increase of 3.9 percent. The results of our review are shown in Figure 3.9.
Figure 3.9: Summary of Revenue Targets 36
The Figure shows that those price plans with proposed returns above the thresholds, such as the
E-24 (M-Power) price plan, receive the minimum increase, while those price plans with proposed
returns below the threshold, such as E-47/E-48, receive the maximum increase. The only rate
design that is a slight departure from the stated guideline is E-26, in which the proposed rate of
return is below the threshold but the proposed increase is not at the maximum level.
Management’s logic, with which we agree, was to balance the proposed increase with that of the
residential class as a whole. We note that the rate design process generally introduces some level
of judgment, as is typical during a rate setting process.
3.6
Conclusion
SRP’s cost of service study is reasonable, accurate, and consistent with industry standards. The
proposed revenue targets (that yield the proposed returns) are reviewable, accurate and strike a
36
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 33
reasonable balance between equity and gradualism, two important principles of the pricing
philosophy established by the Board.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 34
4.0
Proposed Changes to Standard Price
Plan Designs
The purpose of this section is to discuss our review and evaluation of SRP’s proposed changes
to standard price plan designs.
4.1
Overview
Our review and evaluation of SRP’s price plan proposals examined the extent to which the
proposed price plans reflect the Board’s pricing policies of:
Gradualism – to enhance sound, economic decision-making by customers of all
types through stabilizing price levels and smoothing the impact of cost movements
that may be caused by temporary factors;
Cost Relation – to establish prices in relation to costs and SRP’s stewardship to
its water constituents, and thus not to pursue the maximization of “profit”;
Choice – to constantly improve customer satisfaction through the creative design
of pricing structures that reflect customers’ different desires or abilities to manage
the consumption, assume more price control, or demand differentiated products
and services, among others;
Equity – to treat customers of all types in an economically fair manner; and
Sufficiency – to recover the cost of, and to invest and reinvest in, a system of
assets to perform its policy obligations, including its obligation to store and deliver
water to the owners of land within the boundaries of the Salt River Reservoir
District, to maintain SRP’s financial well-being, and to follow the foregoing
principles.
In addition, we examined the extent to which the proposed prices address the long-term
implications of several strategic issues, including: (1) the potential rapid growth in distributed
generation; and (2) uncertain, but likely future carbon reduction targets.
SRP utilized three primary tools to design the proposed price plans: (1) SRP’s URA, which is used
to set revenue targets for each price plan as well as specific cost components (e.g., distribution,
transmission, energy, etc.); (2) the marginal cost study, which examines the incremental cost of
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 35
adding new load, enabling SRP to design prices that reflect the incremental cost of service; and
(3) the bill impact analysis, which evaluates gradualism considerations by examining the impact
in two ways: (a) across a frequency range of impacts, identifying the number and types of
customers whose increase is different than the system average; and (b) across stratum,
identifying the impact by size of customer.
All of these tools are useful and appropriate in establishing new prices.
4.2
Approach
Our approach to review and evaluate SRP’s proposed price plans focused on three areas:
•
Do the price plans recover the revenue targets established in the Unbundled Revenue
Analysis?
•
Do the price plans result in closer alignment between prices and costs; and if so, what are
the consequences?
•
Do the price plans better promote important price signals derived from the results of the
marginal cost study?
Our focus was a review of the changes to the standard price plans. In general, the primary
changes proposed by Management consisted of increases in monthly fixed charges, a slight
improvement in the seasonal price differentials, and the institution of new demand charges for the
large general service price plans. Each of these changes necessitated other changes to the
elements of the price plans (because the proposed changes increase revenues, which must then
be offset by changes to other components of the prices to offset those increases). Below is a
summary of our overall review and analysis of SRP’s price plan design change. Appendix A
provides a more detailed, plan-by-plan analysis.
4.3
Recovery of Revenue Targets
An important objective of the price plan design is to recover the proposed revenue targets
established in the cost of service study. We reviewed the development of each of the price plan,
including billing determinants (i.e., number of bills, energy units (kWh), demand units (kW)), to
confirm that the proposed price plan is designed to recover the proposed revenue targets. The
review included an evaluation of the data used to develop the customer, demand, and energy
charges for each season (summer peak, summer and winter) and for each time period (on-peak
and off-peak). The proposed designs are consistent with the current designs, with the exception
of the large general service plans (E-61, E-63 and E-65) which now include a demand charge. In
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 36
addition, SRP has proposed two new price plans, and a change to the standby rider, which are
discussed in Section 5.0.
Based on our review, we conclude that the proposed price plan designs recover the proposed
revenue targets based on the assumed billing determinants.
4.4
Increase in Fixed Charge Revenues
A second objective of the price plan design is cost relation (i.e., the relationship between how
costs are incurred and revenues are recovered). Figure 4.1 illustrates SRP’s analysis of the
relationship between how costs are incurred and revenue are recovered.
Figure 4.1: SRP Costs Incurred vs. Cost Recovery 37
While many utilities have implemented decoupling mechanisms 38 to address this problem in a
similar manner, SRP has decided instead to collect more of its fixed costs through fixed customer
charges to better reflect the cost associated with providing service. 39
37
38
39
SRP Blue Book.
A decoupling mechanism is a revenue adjustment mechanism that automatically flows any deviation
from anticipated revenues into a rider, which periodically adjusts to ensure that revenue collected
equals the authorized level of revenue. Overcollections flows back to customers; undercollections result
in increases in the rider to true up revenues to the authorized level.
SRP Blue Book.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 37
Figure 4.2 summarizes the proposed changes in the price plan customer charges. The Figure
shows a proposed $3.00 increase in residential price plans, from $17.00 to $20.00, or
approximately 18 percent. The Figure also shows a proposed increase in E-32 and E-36 price
plans. The percentage changes in the E-61, E-63 and E-65 customer charges of 11 percent, 0
percent, and -35 percent, respectively, are substantially less but offset by the introduction of a
new demand charge.
Figure 4.2: Proposed Change in Monthly Service Charges 40
Even with the proposed increases, the Monthly Service Charges (“MSC”) charges are well below
those costs classified as customer-related, including billing, meter reading, customer service, and
the customer-related portion of distribution costs.
Figure 4.3 compares the proposed MSC charges to SRP’s estimates of customer-related costs
for the residential price plans.
SRP prepared such estimates in response to one of the
recommendations in the Sussex review of the cost of service study. Customer-related costs are
generally calculated from two sources: (1) customer costs such as meters, billing and service
drops; and (2) a portion of distribution system costs that vary with the number of customers, but
not with the level of usage. In prior URAs, SRP did not separate distribution demand costs into
customer-, and demand-related components. It was therefore difficult to determine how a
proposed customer charge compared to the total fixed customer costs for each price plan. We
therefore recommended that SRP conduct a study to classify distribution-related costs into
customer-, and demand-related categories.
Because there is no single, unambiguously correct approach to classify distribution costs into
demand-related, and customer-related, SRP based their analysis on the results of three
alternative, commonly-accepted methods to calculate customer-related distribution costs: (1)
facilities method; (2) minimum distribution method; and (3) zero intercept method. The methods
result in slight variances in estimated cost, but the overall results show that the proposed customer
charges are well below the customer-related costs. Figure 4.3 reflects the average of the three
40
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 38
methods and shows that the proposed customer charges are well below SRP’s estimate of
customer-related costs.
Figure 4.3: Customer-Related Distribution Costs (Residential Price Plans) 41
Figure 4.4 compares current and proposed MSC revenues for each price plan as a percentage of
total revenues without fuel. For the standard residential plan (E-23), the Figure shows that fixed
cost recovery (i.e., MSC revenues as a percentage of non-fuel revenues) improves slightly from
17.3 percent to 19.5 percent under the proposed design.
41
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 39
Figure 4.4: MSC Revenues as Percentage of Non-Fuel Revenues 42
The Figure shows that the portion of fixed costs recovered in fixed charges improves for all price
plans, except E-65. This ensures there is a greater likelihood that fixed costs will be recovered if
usage differs from that anticipated when prices are developed.
It is important to note, however, that as fixed costs are moved from the volumetric portion of the
rate to a monthly charge, all users within the class are not impacted equally. Specifically, small
users are generally impacted disproportionately with higher increases as compared to large users.
This is illustrated for the E-23 class in Figure 4.5.
42
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 40
Figure 4.5: E-23 Bill Impact Analysis 43
The Figure shows the impact of the customer charge increase on low use customers, specifically
those whose average monthly use is 400 kWh or less. While MSC increases result in percent
increases in monthly bills higher than the system average for low use, E-23 customers (i.e., 400
kWh or less per month), the actual increase is approximately $3.50 per month, which for limited
income customers is ameliorated by the proposed increase in the Economy Discount Rider by
$3.00 per month during the winter months.
It is important to note that a low use customer is not necessarily a limited income customer. Figure
4.6 shows a breakdown of E-23, low use customers by limited income (“Economy Price Plan”, or
“EPP”) and non-limited income (“Non-EPP”) customers. The Figure shows that EPP customers
in Stratum 1 (i.e., the low use Stratum) as a percentage of total EPP customers is less than NonEPP customers. The Figure shows a higher percentage of EPP customers in Strata 2-4, and
lower percentage of EPP customers in Strata 5-6.
43
SRP Blue Book.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 41
Figure 4.6: Distribution of E-23, EPP and Non-EPP customers 44
Figure 4.7 provides a further breakdown of the bill impacts for EPP and Non-EPP customers. The
Figure shows that with the $3.00 per winter month increase in the Economy Discount Rider, EPP
customers would experience a lower increase on their bill than a Non-EPP customer across most
strata, both in absolute and on a percentage basis.
Figure 4.7: Bill Impacts of E-23, EPP and Non-EPP customers 45
44
45
Sussex analysis of data provided by SRP.
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 42
SRP’s proposed MSC of $20.00 is comparable to other utilities, as shown on Figure 4.8. In
Wyoming, for example, Montana Dakota Utilities has a $25.00 fixed monthly charge on residential
customers. 46 Rocky Mountain Power has a $20.00 monthly residential customer charge, and has
proposed to increase the charge by $2.00 to $22.00 per month. According to Rocky Mountain
Power, the proposed customer charge “continues to be well below the cost of service of
approximately $31.00 per month if all fixed costs were included in the basic charge”. 47
Figure 4.8: Fixed Monthly Charges – Examples 48
The approach of increasing fixed customer charges is consistent with recent industry trends.
Regulatory commissions across the United States, including those in the southwestern US, have
approved increasing levels of fixed customer charges in order to better align utility costs and
revenues.
As part of their Power Supply Improvement Plan, Hawaiian Electric presented a hypothetical case
outlining the need for, and impact of, DG-PV Reform. As part of this reform, “the current [Net
Energy Metering (“NEM”)] would be replaced with a tariff structure for DG systems that more fairly
allocates fixed grid costs to DG customers and compensates customers for the value of their
excess energy.” 49 Using O’ahu customers as an example, the Company projects that the Monthly
46
47
48
49
Docket No. 20004-81-ER-09, Direct Testimony of Tamie A. Aberle, at 12-13.
Docket No. 20000-405-ER-11, Application for General Rate Increase, at 10.
Sussex analysis of company tariffs and recent rate cases.
Hawaiian Electric Power Supply Improvement Plan, August 2014, at 6-3 – 6-4.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 43
Fixed Charge for all residential customers will equal $55.00, the charge for DG customers will be
an additional $16.00, and the Feed-in-Tariff Purchase Price for DG customers will be $0.16. 50
In Wisconsin, the Public Service Commission (“PSC”) recently approved a higher fixed charge for
Wisconsin Public Service Corporation, raising it from approximately $9.00 to $16.00. Although
this increase is still below the Company’s requested fixed charge of $25.00, it represents a
significant increase over the previous monthly rate. A similar increase was also approved by the
PSC for Wisconsin Electric Power. 51
In Oklahoma, American Electric Power (“AEP”) recently requested an increase in their base
service charge from $16.16 to $20.00 “to account for fixed customer, meter, meter reading, and
billing costs plus a portion of distribution function costs that are fixed in nature.” 52 As a result of
shifting these costs to fixed charges, AEP proposes to decrease customer energy charges. 53
Figure 4.9 compares the current fixed charge of utilities across the SRP region with their most
recent charge to illustrate the relative magnitude of fixed charge increases across the region. The
fixed charge increases include Sierra Pacific’s increase of $6.00 per month and Tucson Electric’s
increase of $3.00 per month.
Figure 4.9: Fixed Monthly Charges – Southwestern United States 54
50
51
52
53
54
Hawaiian Electric Power Supply Improvement Plan, August 2014, at 6-3 – 6-4.
“Wisconsin PSC votes rate changes for Wisconsin Electric Power”, SNL Regulatory Research
Associates, November 17, 2014.
Cause No. PUD 201300217, Direct Testimony of Jennifer L. Jackson, at 14-15.
Ibid.
Sussex analysis of company tariffs and recent rate cases.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 44
4.5
Seasonal Differentials
We reviewed the price plan designs for seasonal differentials, the extent to which prices provide
consumers the correct price signals to respond to an economically changing environment. Our
approach to the review compared the proposed and current seasonal price differential to the
marginal cost. This issue is important because growth in the summer peak generally drives large
investment decisions. In addition, the EPA’s proposed regulations on existing power plants to
reduce carbon emissions may result in early retirement of some generation units and new
investment in others. Price plan designs that reflect the cost of those new facilities would
generally encourage customers to reduce or curtail summer peak use to the point of possibly
avoiding or postponing the need for some new facilities.
For each price plan, our review included a comparison of the proposed and current prices, and
marginal costs for each of the following differentials:
•
Peak/winter prices;
•
Summer/winter prices; and
•
Peak/summer prices.
4.5.1
Marginal Costs
In examining the marginal cost, there are two potential approaches that can be used: short-run
and long-run marginal costs.
Short-run marginal costs are based on the incremental cost
assuming the current plant-in-service, while long-run marginal costs consider the incremental cost
assuming additions to plant-in-service.
According to Bonbright, the argument in favor of using short-run marginal cost for rate design is
that rates should reflect the costs that actually prevail at the time the rates are established. 55 If
there is excess capacity, then the marginal cost will be relatively low and thus encourages
consumers to make full use of the excess capacity. If, on the other hand, there is a shortage of
capacity, then the marginal cost will be relatively high and encourage consumers to ration the
current capacity until new capacity is built. In this manner, short-run marginal costs tend to be
volatile.
55
Bonbright, James, Danielsen, Albert, and Kamerschen, David. “Principles of Public Utility Rates.” Public
Utilities Reports, Inc. 1988. Second edition, at 463-469.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 45
The argument in favor of using long-run marginal cost for rate design is to promote more stable
rates, along with rate levels that compensate utilities for new investment required to meet
increasing demand.
SRP’s marginal cost study includes calculation of short-run and long-run marginal costs. The
short-run marginal cost consists of the variable cost components of the marginal cost study, such
as fuel and purchased power expense; while the long-run marginal cost consists of the total cost,
including facility investments. This approach of using the marginal cost study to guide price plan
designs enables the costs associated with meeting future requirements, such as new EPA
requirements that may require significant changes to SRP’s portfolio of generation resources, to
be reflected in current prices.
4.5.2
Evaluation of Seasonal Differentials
We compared the proposed and current total price and variable price differentials for each season
to the ratio or differential in marginal costs between the seasons to examine whether the proposed
price differentials have moved closer to the marginal cost differentials. In general, the proposed
price differentials are closer to the marginal cost differentials on both a total price/cost and variable
price/cost basis. The movement in the total price differentials as shown on Figure 4.10 is relatively
less than the variable price differentials as shown on Figure 4.11 due to the increase in the
Monthly Service Charge, which has the impact of raising total prices in the winter period.
Figure 4.10: Seasonal Differentials – Total Costs 56
56
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 46
Figure 4.11: Seasonal Differentials – Variable Costs 57
Other price plan proposals include:
•
New demand charges for the Large General Service customer to better achieve recovery
of generation, transmission, and distribution costs.
•
Other proposed changes include: (a) a transfer of facility costs from the Facilities Rider
to the respective E-61 and E-63 price plan to align prices with the functional costs; (b) an
increase in the Economy Discount Rider of $3.00 per month in the winter months, resulting
in a winter discount of $20.00 per month as compared to the summer discount of $21.00
per month; and (c) a freeze of the Medical Life Support Equipment Discount Rider from
new participation, and instead meet this need via a program that better protects eligible
customers.
The other price plan changes are consistent with the Board’s pricing policies, namely the
proposals better reflect the underlying cost of service (as in the case of the E-61 and E-63 change)
and gradualism, smoothing the impacts of cost movements (as in the case of the Economy
Discount Rider and Medical Life Support Rider changes).
4.6
Conclusion
SRP’s price plan design is reasonable, accurate, and consistent with industry standards. The
proposed revenue targets (that yield the proposed returns) strike a reasonable balance between
equity and gradualism, two important principles of the pricing philosophy established by the
Board.
57
Sussex analysis of data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 47
5.0 New Pricing Initiatives
This section describes Sussex’s review and evaluation of SRP’s proposal for two new price plans,
and modification of the Standby Rider: (1) Customer Generation for Residential Service (“E-27”);
(2) Experimental Residential Time-of-Use for Super Off-Peak for Electric Vehicle (“E-29”); and (3)
Standby Electric Service Rider for Power Production Facilities. The proposals all have in common
an attempt to develop appropriate prices for customers that have unusual (i.e., different from
standard price plans) load characteristics.
Usage by customers who have generation equipment, such as rooftop solar and fuel cell units,
will generally be significantly lower than other customers of the respective price plans. As a result,
applying standard plans to customer generation and standby customers leads to under recovery
of fixed costs when such costs are recovered in usage charges.
Experimental Electric Vehicle (“EV”) customers may bring about new loads and thus, a special
price plan tailored to these customers can encourage usage at times when SRP’s costs are at a
minimum.
5.1
Customer Generation for Residential Customers
5.1.1
Overview of Cost Recovery
SRP has proposed a new Customer Generation price plan designed for residential customers
that have DG units, including rooftop solar units. The new price plan is designed to better align
rates and cost recovery for all customers and, at the same time, ensure that residential customers
that have DG units (“DG customers”) pay their cost of service and not shift costs to non-DG
customers, without having an untoward negative impact on DG development. 58
As background, electric utilities incur three types of costs in providing electric service to
customers:
•
Fixed costs, such as metering, billing, and a portion of distribution costs, that generally
vary by number of customers;
58
We note that residential customer DG rate changes have attracted significant attention among various
stakeholders in regulatory proceedings across the country. For example, in Arizona Public Service’s
recent case (Docket No. E-01345A-13-0248) related to finding a “Net Metering Cost Shift Solution”, the
Commission acknowledged the significant attention to the case, including “numerous filings”, “an
unusually high number of public comments”, and “significant media coverage” (Decision No. 74202, at
26).
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 48
•
Demand-related costs, such as a portion of generation, transmission, and distribution
costs, that generally vary by demand; and
•
Energy-related costs, such as fuel and variable O&M expenses, that generally vary by
energy consumed.
Utility rates are designed to recover all of these costs. However, for residential customers on
“standard” utility rates, most costs are recovered on the basis of usage (or per kWh) charges,
based on estimated usage at the time rates are established. Thus, to the extent that actual usage
is significantly lower, the “standard” utility rates no longer recover the full costs of service. This is
an emerging issue in the industry, largely as a result of the growth in solar units as shown in
Figure 5.1. As DG installations increase and customers make long-term decisions based on
existing price plans, this issue becomes increasingly more significant.
Figure 5.1: U.S. Solar Electric Installations (MW) 59
5.1.2
Concerns with Current Approach: Net Energy Metering
Presently, DG customers are compensated for their output through NEM, where the generation
output is netted against the on-site usage and customers are effectively paid the retail rate as a
bill credit. NEM is a common approach in the industry, and has been viewed as an important
incentive for emerging renewable, DG technologies. 60 However, as has been raised in numerous
59
60
Solar Energy Industries Association (“SEIA”); Solar Energy Facts: Q2 2014.
California Public Utilities Commission states, “NEM is an important element of the policy framework
supporting direct customer investment in grid-tied distributed renewable energy generation, including
customer-sited solar photovoltaic (PV) systems.”
http://www.cpuc.ca.gov/PUC/energy/DistGen/netmetering.htm
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 49
regulatory proceedings, there are two concerns with this approach: (1) Because DG output is
netted against customer usage, DG customers are implicitly paid the full retail price for their
output, which may be different from the value of the DG output; and (2) DG customer usage is
reduced by the DG output, resulting in less revenue and lower fixed cost recovery for the utility
(since fixed cost recovery is based upon non-DG customer usage levels). 61
The second issue (i.e., under recovery of fixed costs) is a concern in the industry, in large part
due to its impact on other customers as fixed costs are shifted from DG to non-DG customers
(particularly for a non-investor utility such as SRP). The issue has been raised in studies and
regulatory proceedings in several states. 62
The Arizona Public Service Company (“APS”), as an example, in testimony in July 2013 before
the Arizona Corporation Commission (“ACC”) estimated the annual costs shifted to other
customers between $800 and $1,000 per customer with installed rooftop solar units. 63
Note that this is not simply a “revenue recovery” issue, but also one of fairness. A typical DG
customer, as a result of NEM, pays for a significantly reduced level of kwh. However, they
continue to rely upon the utility T&D system, both to transmit power to their home, and to move
power from the DG unit throughout the system. A fundamental principle of utility rate design
requires that rates be set so as to recover costs from all such customers.
As DG installations continue, the shift in fixed cost recovery to non-DG customers will grow.
According to the Edison Electric Institute, the threat of disruptive forces, including DG, has
“serious long-term implications for the traditional electric utility business model” and the industry
“must begin to seriously address these challenges in order to mitigate the potential impact of
disruptive forces, given the prospects for significant DER (“Distributed Energy Resource”)
participation in the future.” 64
Often, the goal is to seek solutions that address the under recovery of fixed costs without limiting
the growth in distributed generation. Even if the under recovery and resulting cost-shift is not
61
62
63
64
“Rethinking Standby & Fixed Charges: Regulatory & Rate Design Pathways to Deeper Solar PV Cost
Reductions”, prepared by the NC Clean Energy Technology Center, August 2014, at 38-41.
Studies involving Arizona, California, Colorado, New Jersey, New York, Pennsylvania, and Texas have
evaluated the benefits and costs of solar PV within those states, according to the Rocky Mountain
Institute. “A Review of Solar PV Benefit & Cost Studies”, eLab for the Rocky Mountain Institute,
September 2013.
“Residential Rooftop Solar Net Metering Proposals”, Arizona Public Service, July 2013.
“Disruptive Challenges: Financial Implications and Strategic Responses to a Changing Retail Electric
Business”, prepared by Energy Infrastructure Advocates for Edison Electric Institute, January 2013, at
17.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 50
seen presently as urgent, any attempt to address the problem though rate changes will have an
impact on existing DG customers. That may be seen as unfair to them, and, as a result, the rate
changes may be applied to only new DG customers (i.e., existing DG customers would be
grandfathered, either permanently or temporarily). In that case, the cost shift impact for current
DG customers would remain in place for the duration of the grandfathered period, underscoring
the importance of addressing the issue before large numbers of additional DG customers are
added.
5.1.3
Two Areas for Potential Solutions
There are two areas of concern regarding the current NEM structure: (1) the implicit price paid to
DG customers for their output is unlikely to be equal to the value of the output; and (2) the
“standard” rate structure differs from the actual structure of costs (because, for example,
significant portions of fixed costs are recovered through variable charges).
Attempts to develop a solution tend to address either, or both, of these areas: (1) “fix” the price
paid to DG customers so that it more accurately reflects the estimated value attributable to the
DG output; and/or (2) “fix” the rate structure so that changes in customer usage better track
changes in utility costs. Utilities and other interested parties have proposed a variety of
alternatives for each of these areas.
5.1.3(a)
Address the price paid for DG output
There are several ways to “fix” the price paid to DG customers. One common approach is to
develop a “Feed-in-Tariff” (“FIT”). Under a FIT, a customer is billed under the standard rate for all
of their usage. The full output of the DG unit is then sold by the customer to the utility at a specified
FIT price. Several FITs in existence today are based upon the utility’s attempt to determine the
specific value of the unit’s output. For rooftop solar, for example, the value would be based upon
the value of the energy, the shaped value of the capacity (recognizing the time dimension of solar
operation), T&D savings (or costs) believed to result from the distributed generation, and any
additional benefits and/or costs thought to result from the DG output. According to the EIA, as of
May 2013, FITs or “similar programs” (both mandatory and voluntary) exist in 20 states as either
state or utility policy. 65
65
“Feed-In Tariffs and similar programs”, U.S. Energy Information Administration, June 4, 2013,
http://www.eia.gov/electricity/policies/provider_programs.cfm.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 51
A FIT approach provides greater price transparency by separating the retail price of the electric
service paid by the customer to the utility from the resource purchase price paid by the utility to
the DG customer.
This approach is an alternative to paying the full retail price for the power, including a full allocation
of T&D costs, and instead develops a price that reflects any T&D savings (or costs) from a
distributed, local source of generation, plus any other benefits (or costs) that might exist. This
approach recognizes that there might be costs associated with introduction of DG, including
equipment to manage loads flowing backwards on the distribution system.
Austin Energy implemented such a program in 2012, calculating a Value of Solar rate (i.e., the
price at which DG customers are compensated) of $0.128/kWh. 66 This rate was updated to
$0.107/kWh in 2014. 67
A drawback of this approach is that the calculation of the FIT price is complex since it is based on
the relative value of the resource, which changes throughout the day and throughout the year.
Also, some components of the relative value may not be easily monetized, such as the value
resulting from reduced emissions. Furthermore, the relative value of avoided transmission and
distribution costs may tend to vary with the location of installations. As a result, a “fully-valued”
FIT would not be a single value, but a set of values that can vary by time period, season, and
even location.
Finally, it is worth noting that a FIT could also remedy the under recovery of fixed costs issue.
Under the FIT approach, all of the customer’s electricity usage would be billed at the standard
retail tariff, and all of the output of the DG unit would be sold to the utility at the established FIT
price. Accordingly, DG customers’ retail usage would remain at “pre-DG” levels; any fixed costs
recovered in usage charges would be recovered from them just as if they had not installed the
DG unit.
5.1.3(b)
Address the Price Structure
Another approach is to address the retail price structure for DG customers. Most attempts to
address the price structure have focused on better alignment of prices and costs. There are three
general approaches to accomplish this: (1) an increase in fixed monthly charges, which can
include (a) a higher monthly customer charge, and/or (b) a monthly charge that is intended to
66
67
“Designing Austin Energy’s Solar Tariff Using a Distributed PV Value Calculator”, prepared by Clean
Power Research, at 5
“2014 Value of Solar at Austin Energy”, prepared by Clean Power Research, October 21, 2013, at 41.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 52
reduce or eliminate the under recovery of fixed costs (based on the size of the DG unit) as usage
levels decrease; (2) a closer alignment between temporal costs and prices (which might include,
for example, mandatory Time-of-Use (“TOU”) rates); and (3) a rate structure designed specifically
for DG customers (with improved alignment of fixed charges and fixed costs, and billing
determinants that specifically reflect DG customer usage).
1. Fix the Price Structure: Increase fixed charges
There are several ways that higher fixed monthly charges can address the DG issue.
One approach is to increase the customer charges for DG customers, such as the additional
$5.00 per month customer charge assessed to DG customers of Idaho Power. 68 Under this
approach, fixed charges are increased for DG customers only. While this improves fixed cost
recovery, it may have adverse customer bill impacts, particularly for low usage customers. Also,
some fixed costs may be avoidable, especially in the long run.
Another approach is to assess a fixed charge based on the under recovery of fixed costs that may
be tied to the size of the DG unit, such as APS which has a $0.70 per kW of installed DG capacity
per month. Initially, the ACC Staff proposed a monthly charge of $4.00 per kW based on the size
of the DG unit (or, approximately $32 per month for an 8 kW system) that recovered the net
unrecovered fixed costs associated with that unit. The Commission, however, reduced the charge
to $0.70 per kW pending a full review in APS’ next rate case. 69
2. Fix the Price Structure: Better align the rate structure for all customers
A second way to fix the pricing structure would be a closer alignment between temporal costs and
prices, which might include, for example, a mandatory or default TOU rate. Under a TOU rate,
the price paid by customers varies depending on the time of day and season of year when the
electricity is used (more expensive during peak hours, peak season). Sacramento Municipal
Utility District has announced plans to move to such a pricing structure. 70
Ideally, the pricing structure would reflect the underlying cost structure, so that changes in
revenues due to changes in customer load characteristics (such as a reduction in usage due to
installation of a DG unit) is matched by changes in the underlying cost of service. This would offer
68
69
70
“Most of Idaho Power net metering proposals denied”, Idaho Public Utilities Commission, July 3, 2013,
http://www.puc.idaho.gov/press/130703_IPCnetmeterfinal.pdf.
“Arizona Corporation Commission sets new direction for net metering policy”, Press Release, Arizona
Public Service, November 13, 2013.
“Preparing for the future: 2013 Rate Proposal”, Sacramento Municipal Utility District, April 2013.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 53
customers better price signals by aligning prices with the cost of providing service, while giving
consumers more control over their usage and incentivizing energy conservation when it is needed
most. To the extent that a perfect alignment of prices and costs were in place today, the “cost
shift” problem described above (in which fixed cost responsibility is shifted from DG to non-DG
customers) would not exist. Some regulators and solar advocates, including the California Office
of Ratepayer Advocates, have promoted the benefits of mandatory time-based pricing
structures. 71
It should be noted, however, that TOU rates alone will not “cure” the lost fixed cost recovery
problem if they are based solely on usage (i.e., the rate consists of prices per kWh that vary by
time period). Such rates would still recover fixed costs through usage charges, leading to
continued underrecovery of fixed costs if usage is less than expected when the prices were
developed.
Utilities can transition residential customers to TOU rates through either voluntary (opt-in or optout) or mandatory enrollment. Voluntary enrollment would either keep customers on their current
rate plans and give them the option to transition to TOU rates (opt-in), or default to those TOU
rates and allow the customers to return to their previous rate plans (opt-out).
A voluntary enrollment approach is customer-friendly, and those enrolling tend to be customers
whose load characteristics would provide them with the largest bill savings. To the extent that is
true, an expected result would be loss in revenue for the utility. This problem is often referred to
as the “selection bias” issue. In addition, those who did not enroll would lead to a continuation of
the issues related to the existing price structure.
By requiring all customers to transition to TOU rates through mandatory enrollment, utilities
eliminate the aforementioned selection bias. However, this method is not as customer-friendly,
as customers may feel like they are being forced into a new rate class. Also, based on a Sussex
review of implemented programs, this approach is fairly uncommon for residential customers in
the United States.
Yet, mandatory enrollment in TOU rates for residential customers is gaining momentum in
California, where SMUD plans to transition all residential customers to mandatory TOU rates in
2017 or 2018. The utility believes that the current blocked price structure does not match cost
71
“California
Residential
Electric
Rate
Redesign”,
http://www.dra.ca.gov/general.aspx?id=2444.
SUSSEX ECONOMIC ADVISORS, LLC
Office
of
Ratepayer
Advocates,
PAGE 54
structure. The orderly transition to a “default” TOU rate is also supported by California’s Office of
Ratepayer Advocates. 72
The primary concern of this approach from a DG perspective is that billing determinants would be
set by all customers in the class, so DG customers would continue to have very low usage relative
to the "typical" or average customer use of the class. In addition, any fixed costs in usage based
charges would still be unrecovered as usage levels decrease due to installed DG units.
A possible solution is to move all fixed costs out of usage charges, which would likely have
significant customer bill impacts on many customers, not just DG customers. To address that
issue, the choices would be to: (a) move the rate only slightly toward cost alignment in order to
minimize bill impacts (leaving the original issue of unrecovered fixed costs unaddressed), or (b)
move the rate significantly, which addresses fixed cost recovery, but leads to widespread, large
bill impacts.
3. Fix the Price Structure: Create a Unique Rate Class
A third approach to fix the pricing structure is to create a new rate class that is designed for DG
customers. This has the primary benefit of ensuring that the billing determinants of the class
reflect the anticipated use of DG customers, as opposed to a mix of DG and non-DG customers.
It would also not impose bill impacts upon non-DG customers. 73
In addition, the rates for a DG-specific class would be set based on DG customer-specific load
characteristics. The rates would be unbundled sufficiently to allow fixed costs to be recovered in
fixed charges and variable costs to be recovered in variable charges, such that the fixed cost
recovery problem can be resolved. The downside to this approach is that the incentive for DG
may be reduced, perhaps significantly (at least in the short term), and that there may be a potential
adverse reaction from customers that do not like being forced into a new rate class.
Note that, in this case, there would continue to be two sources of revenue erosion in existence:
(1) any customer response rate components that were not perfectly aligned with cost could lead
to revenue erosion; and (2) there could still be the potential for selection bias if the rate were open
to non-DG customer who might benefit from the rate without adopting DG (or, with minimal DG
installations).
72
73
Ibid.
For an example of creating new rate classes, see Lyons, Timothy and Martin, John.
Reclassification: Who Buys What and When,” Public Utilities Fortnightly. October 15, 1991.
SUSSEX ECONOMIC ADVISORS, LLC
“Rate
PAGE 55
The option to create a unique, DG class of customers has been approved in Oklahoma, where
Senate Bill 1456 was recently signed into law, allowing utilities to create a new DG class and
implement a monthly surcharge on those customers.
Other possible solutions may arise from ongoing discussion to address issues related to NEM. In
California, for example, the Public Utility Commission recently launched a proceeding to establish
a Net Energy Metering successor tariff or contract in response to recent legislation. 74 Multiple
parties are presently engaged in such discussion and are evaluating various options intended to
provide a long term solution.
5.1.4 A note on decoupling mechanisms as an alternative means to address fixed cost
underrecovery
Some have suggested decoupling mechanisms as a means to address the rate structure issue
surrounding DG. 75 We believe that decoupling mechanisms do not address this issue, but merely
hide the underlying problem.
Decoupling mechanisms are regulatory accounting vehicles designed to ensure that authorized
levels of revenue are recovered as actual usage differs from usage levels built into rate designs.
They generally consist of a balancing account (to keep track of authorized levels of revenues vs.
actual), and a rider, which is set at whatever level is needed to true up actual revenues to
authorized levels. Decoupling mechanisms have become fairly common among regulated,
investor owned utilities in two circumstances:
1. Gas utilities frequently utilize decoupling mechanisms in the face of declining use per
customer.
2. Some electric (and a few gas) utilities have used decoupling mechanisms to ensure fixed
cost recovery in combination with large scale energy efficiency programs.
What decoupling mechanisms do is to provide a vehicle to spread unrecovered fixed costs among
all customers. They do not address the rate problem itself that gives rise to the unrecovered fixed
cost issue. They may be appropriate in the circumstances in which they’ve been employed, since
all (or many) customers share in responsibility for the declining use.
74
75
“Establishing a Successor Tariff or Contract Pursuant to AB 327 (Perea, 2013)”, California Public
Utilities Commission, http://www.cpuc.ca.gov/PUC/energy/DistGen/NEMWorkShop04232014.htm.
“Rethinking Standby & Fixed Charges: Regulatory & Rate Design Pathways to Deeper Solar PV Cost
Reductions”, prepared by the NC Clean Energy Technology Center, August 2014.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 56
However, the DG problem is different – a relatively small number of customers install a technology
that significantly reduces their usage (and thus payment for the facilities used) – while shifting
cost responsibility to other customers. Thus, decoupling mechanisms are not a “fix” to the rate
structure problem, but simply a means to recover unrecovered revenue for investor owned
utilities. The issue for SRP is one of shifting cost responsibility, as well as providing appropriate
price signals to customers who choose to install their own generation.
5.1.5
Review of SRP’s Customer Generation Price Plan for Residential Service Proposal
Our approach to review and evaluate SRP’s proposal focused on three specific questions:
•
Does the price plan improve recovery of the underlying cost of service?
•
Does the price plan address the issue of the under recovery of fixed costs from DG
customers?
•
Does the price plan have an untoward negative impact on DG installations?
SRP’s overall approach for establishing the E-27 price plan was based on a set of principles. The
development of the principles was informed by comments received from the Stakeholder
Initiatives Advisory Panel. The principles were also shared with Stakeholder Forum participants
as part of SRP’s recent Integrated Resource Planning process. The principles included:
•
Pursue investments, alternatives, and policies that embrace the opportunity for customers
to choose customer generation resources.
•
Develop prices for customers that reflect underlying economics and promote good
decision making.
•
Incentives associated with customer generation should be transparent and phase out with
the maturity of a given technology.
•
Insulate those who currently have customer generation from pricing and policy changes
for a reasonable period.
SRP’s revenue targets for the E-27 price plan proposal were based on Strata 4 through 6 in the
E-26 price plan. According to SRP, this profile of customer is the most likely to install small-scale
DG. Specifically, the rate design was based on 101,995 Strata 4-6 E-26 customers with 2,148
million kWh per year or 21,065 kWh per customer, which is 7 percent higher than the average E26 customer.
The rates were designed to be revenue neutral on a pre-solar basis for the 101,995 Strata 4-6 E26 customers.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 57
The E-27 rate design consists of four components: (1) Monthly Service Charge (“MSC”); (2)
distribution or Service Entrance Section (SES) charge; (3) energy charge; and (4) grid or demand
charge.
The MSC is assessed on a per-customer basis, and recovers customer service costs, along with
a portion of customer-related distribution costs. The MSC is consistent with the amount proposed
for the other residential price plans.
The distribution (SES) charge is assessed on a per-customer basis, similar to the Monthly Service
Charge, and recovers the fixed, customer-related distribution costs not recovered in the customer
charge. The SES charge varies based on the amperage (“amp”) service size. For example, the
proposed monthly charge for customers with 200 amp service or less (representing 95 percent of
customers in the proposed rate design) is $12.44, while the charge for higher than 200 amp
service is $25.44. The rationale for such difference is that the fixed monthly cost of service is
higher with higher amp service (i.e., larger homes) than lower amp service.
The energy charge is assessed on net energy usage (total customer usage less DG output), and
is set at the marginal energy cost ($ per kWh) for the E-26 price plan as calculated in the marginal
cost study.
The grid (demand) charge is assessed on net demand (total building demand less DG output),
and recovers the remaining revenue requirements associated with distribution costs, transmission
costs, ancillary services (1-2), energy, as well as System Benefit and EPCAF-related costs. The
demand charge consists of three price tiers, 0-3 kW, 3-10 kW, and over 10 kW.
5.1.6
Evaluation of SRP’s Customer Generation Price Plan Proposal
SRP’s approach to address the current issues with NEM is to adjust the underlying retail price
structure so that customers who decide to install DG units will continue to pay their fair share of
fixed costs. Based on our review, we believe this approach is appropriate for the following
reasons:
•
Better aligns prices with the cost of service. The price plan components are designed to
track the underlying cost components, so that, generally, fixed costs are recovered in fixed
charges and variable costs are recovered in variable charges. SRP proposes to fix the
price structure through a new customer generation price plan that recognizes DG
customers represent a new class of customers whose load characteristics will have more
clarity over time.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 58
•
Is supported by recent studies. Some argue that more granular, cost aligned rates would
encourage DG in a way that makes more sense. 76 Specifically, the manner in which
rooftop systems are designed and installed are, at least in part, a function of the retail rate
design. For example, east- and south-facing systems produce more energy (which is more
valuable to the customers with those systems installed with current bundled, usage-based
electric rates and NEM), whereas west facing systems produce more energy (and capacity
value) at times of system peaks (which is when marginal costs are higher, and the energy
and capacity is worth more to utilities). This is illustrated in Figure 5.2, in which westfacing systems tend to produce less energy than south-facing systems, and would
therefore, be worth less to customers with current systems, and existing retail pricing.
Figure 5.2: Impact on System Peak based on Orientation77
•
In using the large, E-26 strata as a basis for the revenue requirements, is reasonable and
consistent with recent SRP experience of large customers installing DG units.
•
Fixes the problem of cost shifting. As sales decrease due to installation of a DG unit, fixed
cost recovery is improved due to introduction of the SES and demand charges.
76
77
“Rate Design for the Distribution Edge”, prepared by Electricity Innovation Lab of the Rocky Mountain
Institute, August 2014, at 6.
“A Review of Solar PV Benefit & Cost Studies”, eLab for the Rocky Mountain Institute, September 2013,
at 30.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 59
•
Does not have an untoward negative impact on DG installations. This approach still
provides an economic incentive, depending on the changes in the level of demand. Figure
5.3 illustrates the ability of an E-27 customer to mitigate bill impacts by managing their
levels of demand. As the Figure shows, a customer installing a typical rooftop solar unit,
without additional measures to manage demand levels, would see an increase in monthly
bills of about $47. The monthly increase falls significantly as demand level are reduced,
reaching zero at a 60 percent reduction.
Figure 5.3: Bill Impact of Demand Reductions 78
•
It is important to note that monthly bills under the E-27 price plan are lower after installation
of a DG unit than monthly bills under the E-26 price plan prior to installation of a DG unit.
•
If paying a higher incentive were desired, an explicit subsidy could be paid, and the cost
recovered through the EPCAF, where it would be shared by all customers. It is worth
emphasizing that the inclusions of demand charges provides DG customers with
significantly more opportunity to control their bill than does the more common utility
proposals to simply increase fixed charges in the rate structure. Fixed charges cannot be
avoided. The proposed E-27 price plan allows DG customers to both increase the value
of their systems, as well as reduce their bill by controlling their levels of instantaneous
demand. These demand charge savings much more closely align the rate structure with
the kinds of avoided cost savings that may result from DG installations.
78
Sussex analysis of spreadsheet and data provided by SRP.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 60
•
Has been recommended by others. More “granular”, unbundled rates that allow prices to
more closely track costs are receiving more attention within the industry as of late. For
example, the Rocky Mountain Institute has recently encouraged such pricing as, among
other things, the solution to the DG fixed cost recovery problem. In a recent paper, RMI
argues that rate structures that vary by TOU, and that unbundle energy and demand
components, and perhaps vary by location as well, should replace current rate structures
as a means to provide proper price signals to DG customers. Additionally, the Institute
notes that “successful TOU programs to date suggest that it is plausible that many areas
of the country could move to TOU pricing, with unbundled demand and energy
components, as a default rate option within a matter of years”, similar to the transition
currently occurring in California that has been supported by utilities and ratepayer
advocates alike. 79
5.2
Standby Rider
5.2.1
Review of the Standby Rider Proposal
In addition to Customer Generation price plan for residential customers, SRP has also proposed
revisions to the Standby Rider for large-scale, industrial DG.
The rate design problem with Standby service is similar to that of DG. Specifically, a standby
customer typically installs a generation unit, and runs it in approximately baseload fashion. Such
a customer may continue to purchase peaking requirements from the utility, as well as full
requirements service whenever the on-site generator is down (either as a result of a temporary
outage or for periodic maintenance). To the extent that the rate the standby customer would
otherwise take service on recovers fixed costs in usage based charges, a portion of those fixed
costs will no longer be recovered, or must be shifted onto other customers.
The challenge with standby customers is to design a rate that ensures that appropriated fixed
costs are recovered, and that the rate appropriately charges the customer (and doesn’t
overcharge) whenever the on-site unit is down. In addition, since the utility must “stand ready” to
deliver power whenever the unit is down, there is an additional cost associated with whatever
reserve capacity is required for such service.
79
“Rate Design for the Distribution Edge”, prepared by Electricity Innovation Lab of the Rocky Mountain
Institute, August 2014, at 26.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 61
SRP’s standby rider is based on the respective E-61, E-63, and E-65 rate designs, since
customers in those price plans are most likely to take standby service.
The standby rate design consists of three components: (1) customer charge; (2) demand charge;
and (3) energy charge.
•
The customer charge is assessed on a per-customer basis, and recovers customer
service costs. The monthly charge is the same as the respective E-60 price plan. The
charge, which includes one meter charge, recovers the customer-related costs of serving
Standby customers.
•
The implementation of a daily on-peak maximum demand charge, in lieu of the Monthly
On-Peak Max kW Charge assessed under each Large General Service price plan. This
charge is intended to provide customers with appropriate costs and savings to keep their
units generating as reliably as possible. The daily on-peak maximum demand charge will
be applied when power is delivered to the customer (i.e., supplemental power) and will be
computed based on the conversion, from monthly to daily, of each Large General Service
price plan’s Monthly On-Peak Max kW Charge and all per kWh Energy (Generation)
components of each respective Large General Service price plan.
•
All per-kWh components under each Large General Service price plan will be applied to
power delivered to the customer, with the exception of the Energy (Generation)
component.
•
The output of the production facility will be metered and all per-kWh components of each
Large General Service price plan, with the exception of Energy (Generation), Fuel and
Purchased Power, and Ancillary Services 3-6, will be applied to the power production
facilities’ output.
5.2.2
Evaluation of the Standby Rider Proposal
The proposed standby rider appropriately reflects the cost of serving standby customers. The
price plan includes a daily demand and energy charge that reflects the cost of service during an
outage. The daily demand does not contain a “ratchet”, thus encouraging standby customers to
return to self-generation as soon as possible, and therefore allows the customer to avoid paying
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 62
for “traditional” service as soon as the outage is resolved. The price plan is consistent with
standby service at other electric utilities. 80
5.3
Electric Vehicle Rate
5.3.1
Review of the Electric Vehicle Rate Proposal
SRP has proposed an EV rate as part of a pilot program to encourage the development of electric
vehicles and send better price signals to these customers. The EV rate offers lower prices during
the nighttime, when residents commonly charge the vehicles and the marginal costs of service is
low.
SRP’s EV service is based on the E-26 residential time-of-use rate design, since the EV rate
varies based on the time of day, as shown in Figure 5.4. Customers must have a qualified Battery
Electric Vehicle (BEV) or Plug-in Hybrid Electric Vehicle (PHEV), as determined in SRP’s sole
discretion. No more than 10,000 may concurrently participate on this experimental price plan.
In addition to the on-peak and off-peak periods employed through SRP’s traditional time-of-use
rates, SRP has also included a “super off-peak” period from 11 PM until 5 AM that reflects the
lower cost of power during that period. The lower costs associated with this new super off-peak
period are illustrated in Figure 5.4.
The super off-peak rate reflects the same margin as the current E-26 rate, but reflects the lower
cost of generation during the nighttime.
80
Direct Testimony of John H. Chamberlin, Ph.D., on behalf of Entergy Gulf States, Inc. in Louisiana, in
Docket No. U-22137.
Also see “Standby Rate for Customer-Site Resources,” prepared by U.S. Environmental Protection
Agency, Office of Atmospheric Programs, December 2009.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 63
Figure 5.4: Proposed EV Rates (Summer) 81
On-Peak
Super Off-
Off-Peak
Peak
Off-Peak
Super
Off-Peak
The EV rate is consistent with similar programs in place at other utilities. Figure 5.5 compares
SRP’s rate to that of other utilities.
Figure 5.5: Electric Vehicle Summer Rates and Discounts to On-Peak 82
5.3.2
Evaluation of the Electric Vehicle Rate Proposal
The proposed Experimental EV E-29 price plan appropriately reflects the cost of serving the
nighttime, super off-peak period. The price plan provides an incentive for EV customers to charge
their EV during the nighttime, when generation costs are low. As with the customer generation
price plan, SRP has in place the tracking and reporting systems to monitor the impact of the price
81
82
Sussex analysis of data provided by SRP.
Company tariffs, corporate websites.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 64
plan design and make modifications as necessary. Further, the E-29 price plan is similar to EV
rates at other companies.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 65
6.0
Conclusions
Based on our review and evaluation of SRP’s proposals, we conclude the following:
•
SRP has demonstrated a need for a price increase. SRP has demonstrated the need
for a 3.9 percent price increase based on recent financial forecasts and performance
measures, consistent with a financial policy that permits continued access to capital
markets by a highly rated entity. The proposed price increase would be expected to bring
retail margins to a level that management believes is sufficient to cover operating
expenses and provide an adequate contribution to new investment, although below
historic levels.
•
The cost allocation study methodology and results appear to be calculated
accurately and consistently with industry practice. In addition, the cost study results
have been used to establish revenue targets that improve the equity of SRP’s price plans.
•
The proposed price plans recover the 3.9 percent revenue increase and continue to
improve fixed cost recovery. Further, the price plans generally continue to move prices
slightly closer to marginal costs.
•
The proposed new price plans appropriately seek to ensure that all customers pay
their fair share of system costs, as well as provide appropriate price signals.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 66
Appendix A: Review of Proposed Price Plans
Below is a summary of our review, findings, and recommendations on specific price plan
proposals. Highlights of the proposed changes include:
•
An increase to the fixed price components, including the Monthly Service Charge, facilities
charges and demand charges.
•
Implement a new price plan for residential customer generation that better reflects costs
as they are incurred by SRP.
•
The addition of an on-peak demand charge to Large General Service customers to better
reflect cost for generation, transmission, and distribution services.
•
Move the costs in the Facilities Rider to the respective rates.
•
Increase the Economy Discount Rider’s discount by $3.00 in the winter to provide a
discount of $20.00 per month in the winter to accompany the current $21.00 discount
already provided in the summer.
•
Introduce an experimental electric vehicle, TOU price plan with a super off-peak period for
residential customers, which in comparison to the standard E-26 TOU price plan, provides
a stronger price signal to encourage customers to charge overnight.
A.1
Residential Service Price Plans
E-23 Residential Price Plan
Proposals:
•
Proposed annual increase of 3.6 percent.
•
Increase in Monthly Service Charge by $3.00 to $20.00.
•
Increase in peak/winter and summer/winter variable cost pricing, consistent with the
results of the marginal cost study.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 67
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations, as
discussed in Sections 3.0 and 4.0, after considering the proposed change in Economy
Discount Rider.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0.
E-26 Residential Time-of-Use Price Plan
Proposals:
•
Proposed annual increase of 4.9 percent.
•
Increase in Monthly Service Charge by $3.00 to $20.00.
•
Increase in peak/winter and summer/winter variable cost pricing, consistent with the
results of the marginal cost study.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations, as
discussed in Sections 3.0 and 4.0, after considering the proposed change in Economy
Discount Rider.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0.
E-21 Residential Super Peak Time-of-Use Price Plan
Proposals:
•
Proposed annual increase of 4.1 percent.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 68
•
Increase in Monthly Service Charge by $3.00 to $20.00.
•
Increase in peak/winter and summer/winter variable cost pricing, consistent with the
results of the marginal cost study.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations, as
discussed in Sections 3.0 and 4.0, after considering the proposed change in Economy
Discount Rider.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0.
E-24 Residential M-Power Price Plan for Pre-Pay Service
Proposals:
•
Proposed annual increase of 2.9 percent.
•
Increase in Monthly Service Charge by $3.00 to $20.00.
•
Increase in peak/winter and summer/winter variable cost pricing.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
•
Is consistent with the cost of service.
•
Moves price plan rate of return closer to system average rate of return.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 69
•
Results in customer bill impacts that appropriately balance equity and gradualism
considerations, as discussed in Sections 3.0 and 4.0, after considering the proposed
change in Economy Discount Rider.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0.
E-28 Residential M-Power Time-of-Use Price Plan
Proposals:
•
Changes are consistent with changes to the E-26 Price Plan.
•
As of April 2014, no residential customers take service under this price plan.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed changes are consistent with changes to the E-26 Price Plan,
which is the basis for this price plan.
E-27 Residential Customer Generation Price Plan
Proposals:
•
Proposed new price plan, designed for customers that install on-site generating units after
December 8, 2014, and thus do not purchase all of their energy requirements from SRP.
•
Designed based on E-26 TOU price plan.
•
Designed to better reflect costs as SRP incurs them, and thus it better collects grid costs
that have to date been collected through per-kWh charges.
•
Designed to be revenue neutral for a typical solar customer before the installation of any
distributed generation.
•
Monthly Service Charge is set at $20.00, consistent with other residential price plans, and
also includes a distribution charge based on the amp service. Homes with 200 amp
service or less pay a distribution charge of $12.44, while homes with service greater than
200 amps have a charge of $25.44. This charge represents the customer-related portion
of SRP’s grid cost.
•
Demand charge consists of a 3-tiered structure of increasing rates.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 70
•
Energy charges consist of the same seasonal and time-of-day definitions as the current
E-26 TOU price plan. The energy charges for each season and time of day, however, are
set based on the marginal cost of service.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Better aligns prices with the cost of service. The price plan components are designed to
track the underlying cost components, so that, generally, fixed costs are recovered in fixed
charges and variable costs are recovered in variable charges.
•
Fixes the problem of cost shifting.
•
Does not have an untoward negative impact on DG installations. This approach still
provides an economic incentive.
•
Approach has been recommended by others. More “granular”, unbundled rates that allow
prices to more closely track costs are receiving a great deal more attention lately.
E-22 and E-25 Experimental Price Plans for Super Peak Time of-Use Price Plan
Proposals:
Changes consistent with changes to the E-21 Price Plan.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed changes are consistent with changes to the E-21 Price Plan,
which is the basis for this price plan.
E-29 Experimental Price Plan for Super-Off Peak Time of Use Electric Vehicles (“EV
TOU”)
Proposals:
•
Proposed new price plan is similar to E-26; however, the EV TOU splits the off-peak period
into off-peak and super off-peak periods. The new super off-peak period is daily from 11
p.m. to 5 a.m.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 71
•
Management designed the rate to examine whether this offering can help manage SRP’s
system load by encouraging customers with EVs to charge their vehicles in the super offpeak period.
During the experimental phase, SRP will limit participation to 10,000
customers.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed EV TOU price plan appropriately reflect the lower cost of serving
the nighttime, super off-peak period, while providing an incentive for EV customers to charge their
EV during the nighttime, when generation costs are low.
A.2
General Service Price Plans
E-36 General Service Time-of-Use Price Plan
Proposals:
•
Proposed annual increase of 3.9 percent.
•
Increase in combined Monthly Service and Meter Charge of $4.79.
•
The Demand Charge has been seasonally differentiated. The fixed cost changes are
mitigated by a 2 percent decrease in the kWh charge.
•
Results in customer bill impacts that for low use and low load factor customers are higherthan-average due to the changes in the MSC and the demand charges, respectively. See
figure below.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 72
•
Increase in peak/winter and summer/winter variable cost pricing, consistent with marginal
cost.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0.
E-32 General Service Price Plan
Proposals:
•
Proposed annual increase of 3.9 percent.
•
Increase in combined Monthly Service and Meter Charge of $6.58.
•
The combined on-peak/shoulder-peak charge is changed to an on-peak charge, making
it easier for E-32 customers to shift usage and to avoid the higher on-peak demand charge,
and the off-peak charge is changed to a combined off-peak/shoulder-peak demand
charge.
•
The on-peak demand charge is seasonally differentiated.
•
Increase in peak/winter and summer/winter variable cost pricing, consistent with marginal
cost.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 73
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0.
E-34 M-Power Pre-Pay Price Plan
Proposals:
Changes are consistent with changes to the E-24 Price Plan, varying only by the Fuel &
Purchased Power component.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed changes are consistent with changes to the E-24 Price Plan,
which is the basis for this price plan.
E-33 Experimental Price Plan for Super Peak Time of Use
Proposals:
•
There are currently 533 customers on this price plan.
•
Changes are consistent with changes to the Commercial class.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed changes are consistent with changes to the Commercial class,
which is the basis for this price plan.
A.3
Pumping Price Plans
E-47 Standard Electric Price Plan for Agricultural Pumping
Proposals:
•
Proposed annual increase of 5.9 percent.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 74
•
Rate design focused on minimizing the variation in customer impacts.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0.
E-48 Standard Electric Price Plan for Agricultural Pumping
Proposals:
•
Proposed annual increase of 5.9 percent.
•
Rate design changes are very similar to those proposed for E-47; however, since an E-48
customer pays the winter demand charge year-round, changes to the winter demand
charge impact E-48 customer accounts to a greater degree. However, E-48 customers
still pay an overall lower average price because of their reduced demand charges.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved for reasons similar to those stated in the E-47 price plan.
A.4
Lighting Service Price Plans
E-54 Standard Electric Price Plan for Traffic Signal Lighting Services
Proposals:
•
Proposed annual increase of 5.9 percent.
•
Proposed language that allows for assessing the fixed charges on a daily basis.
Conclusions:
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 75
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0.
E-56 Standard Electric Price Plan for Public Lighting Service
Proposals:
•
Proposed annual increase of 5.9 percent.
•
Proposed change in the distribution components of the price plan to improve fixed cost
recovery.
•
Distribution-related costs are recovered through the Facilities Charge (a fixed per
luminaire or per controller rated kVa charge), the Distribution Delivery Charge (a per
kilowatt-hour charge), and the lighting equipment costs (poles, mast arms, luminaires,
etc.) are recovered through the riders. To better reflect the underlying cost structure for
providing lighting facilities, the associated rider charges have been increased 6.8 percent.
•
Management also proposes adding language to the price plan that allows for assessing
the fixed charges on a daily basis.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 76
•
Reflects the Board’s pricing policies, as discussed in Section 4.0.
.
E-57 Standard Electric Price Plan for Private Security Lighting Service
Proposals:
•
Proposed annual increase of 5.9 percent.
•
Proposed change in the distribution components of the price plan to improve fixed cost
recovery.
•
Distribution-related costs are recovered through the Facilities Charge (a fixed per
luminaire or per controller rated kVa charge), the Distribution Delivery Charge (a per
kilowatt-hour charge), and the lighting equipment costs (poles, mast arms, luminaires,
etc.) are recovered through the riders. To better reflect the underlying cost structure for
providing lighting facilities, the associated rider charges have been increased 6.8 percent.
•
Management also proposes adding language to the price plan that allows for assessing
the fixed charges on a daily basis.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 77
A.5
Large General Service Price Plans
E-61 Standard Electric Price Plan for Secondary Large General Service
Proposals:
•
Proposed annual increase of 3.9 percent, which is an average of the E-61/E-63 Price Plan
increase.
•
The implementation of a monthly on-peak demand charge that is designed to better reflect
SRP’s underlying cost structure.
•
Moving the Facilities Charge from the Facilities Rider to the price plan for better visibility.
•
Update qualification criteria to be based on gross usage rather than billing usage to keep
customers with distributed generation on the proper price plan.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0
E-63 Standard Electric Price Plan for Primary Large General Service
Proposals:
•
Proposed annual increase of 3.9 percent, which is an average of the E-61/E-63 Price Plan
increase.
•
The implementation of a monthly on-peak demand charge that is designed to better reflect
SRP’s underlying cost structure.
•
Moving the Facilities Charge from the Facilities Rider to the price plan for better visibility.
•
Update qualification criteria to be based on gross usage rather than billing usage to keep
customers with distributed generation on the proper price plan.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 78
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0.
E-65 Standard Electric Price Plan for Dedicated Large General Service
Proposals:
•
Proposed annual increase of 3.9 percent.
•
The implementation of a monthly on-peak demand charge.
•
Removal of the minimum 1,000 kilowatt (kW) qualification criterion to clarify that E-65 is
intended for all customers served by a dedicated or customer-owned substation
transformer.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed plan:
•
Recovers a portion of the overall price increase, which is necessary based on our review
and evaluation in Section 2.0.
•
Is consistent with cost of service and marginal cost studies, based on our review and
evaluation of the cost studies in Sections 3.0 and 4.0.
•
Moves price plan rate of return closer to system average rate of return.
•
Results in customer bill impacts that balance equity and gradualism considerations.
•
Reflects the Board’s pricing policies, as discussed in Section 4.0.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 79
E-66 Standard Price Plan for Dedicated Large General Service with Integrated
Interruptible Load
Proposals:
Changes are consistent with changes to the E-65 Price Plan.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed changes are consistent with changes to the E-65 Price Plan,
which is the basis for this price plan.
Critical Peak Experiment Price Plan, Supplemental to E-65 Price Plan
Proposals:
Changes are consistent with changes to the E-65 Price Plan.
Conclusions:
Based on our review and evaluation, we conclude that the proposed price plan should be
approved because the proposed changes are consistent with changes to the E-65 Price Plan,
which is the basis for this price plan.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 80
A.6
Riders
Economy Discount Rider
Proposals:
•
Management proposes to increase the winter discount associated with this rider from its
current level of $17 to $ 20 per winter billing cycle. Management proposes no changes to
the current $21 per month summer and summer peak billing cycle discount.
•
The current program requires that the customer have a household income at or below 150
percent of federal poverty guidelines. In addition to these guidelines, management
proposes automatic enrollment of customers into the Economy Discount Rider when
qualifying for the Low-Income Home Energy Assistance Program FLIHEAP") or SRP Bill
Assistance. This change is estimated to add approximately 3,300 additional customers to
the rider.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies.
Medical Life Support Equipment Discount Rider
Proposals:
Management proposes freezing the Medical Life Support Rider but continuing to meet the needs
of customers with life support equipment through a similar program entitled the Medical
Preparedness Program. While freezing the current rider from new participation, the following
change is proposed:
•
Changing recertification from an annual to biennial process. Approximately 94 percent of
the current medical life support participants are considered to have a terminal condition
that is not likely to change within a 12-month period. Moving to a biennial re-certification
process will save customers money and time by reducing the need for an annual recertification appointment.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 81
Renewable Energy Credit Pilot Rider
Proposals:
Management proposes no change to this rider other than extending it to the new E-27 price plan.
Conclusions:
We conclude that the proposed rider should be approved as it reflects the Board’s policies.
Buyback Service Rider
Proposals:
•
The Buyback Service Rider establishes the price at which SRP purchases power from
retail electric customers operating cogeneration or small power production equipment.
The rider allows Buyback customers to sell power to SRP using a market-indexed price,
less a transaction fee.
Buyback Credit =∑ [(Hourly Buyback Energy) X
(Hourly Indexed Energy Price - $0.00017/kWh)]
•
Management proposes removing the residential price plans from this rider, as all
residential customers with cogeneration will take service under the E-27 price plan, which
includes terms for net metering. All non-residential accounts with cogeneration installed
after December 8, 2014 would receive service under this rider when it becomes effective,
as the Renewable Net Metering Rider will be frozen from further participation.
Conclusions:
•
We conclude that the proposed changes should be approved as they reflect the Board’s
policies.
Renewable Net Metering Rider
Proposals:
•
The Renewable Net Metering Rider provides an opportunity for customers who have
qualifying energy generating systems and who generate excess energy above their
monthly usage to have that energy credited back to them and carried over to the following
month. Each April billing cycle, the customer will be credited for any remaining excess
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 82
energy at an average annual market price. No credits are carried forward to the May billing
cycle.
•
Management proposes:
o
That customers participating on the rider as of December 8, 2014 may continue on
this rider, unless and until the customer takes service under the E-27 price plan,
which includes terms for net metering.
o
That customers with contracts for distributed generation submitted to SRP by
December 8, 2014 may participate on this rider, unless and until the customer
takes service under the E-27 price plan, which includes terms for net metering.
o
That this rider will be frozen for all other customers.
o
Striking the condition that freezes this rider once SRP ceases to pay monetary
incentives for the installation of photovoltaic systems.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies.
Solar Net Metering Pilot Rider
Proposals:
•
Management proposes eliminating this rider.
•
There are no customers on this rider.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies.
Energy for Education Pilot Rider
Proposals:
Management proposes no changes to this rider.
The rider is currently open to qualifying
customers through October 2015.
Conclusions:
We conclude that the proposed rider should be approved as it reflects the Board’s policies.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 83
Residential Community Solar Pilot Rider
Proposals:
Management proposes sunsetting the Residential Community Solar Pilot Rider given the creation
of the Time-of-Use Residential Community Solar Pilot Rider – no further customers will be added
to this program.
The Residential Community Solar Pilot Rider is an optional program by which SRP can provide
residential customers with an alternative to traditional rooftop solar. Customers pay a fixed
monthly charge per kWh for the solar energy they receive under the program; while SRP prices
may change over time, the price paid for this solar energy is fixed for five years. SRP retains all
of the “Environmental Attributes” (RECs) associated with the renewable energy produced under
the program.
Conclusions:
We conclude that the proposed rider should be approved as it reflects the Board’s policies.
Time-of-Use Residential Community Solar Pilot Rider
Proposals:
•
Management proposes the development of a new Residential Community Solar Rider. In
conjunction with the development of the Customer Generation Price Plan, SRP will be
entering into a purchase power agreement for a 45 MW solar facility. Given economies
of scale, SRP can purchase this solar energy at a far lower price than rooftop solar. This
rider will allow customers to purchase this solar power at the same price that SRP pays
for it. Consistent with the TOU hours of the Customer Generation Price Plan, this rider
will be limited to E-26 customers only.
Initial participation will be limited to 10,000
customers given available capacity.
•
This new rider is an optional program by which SRP can provide residential customers
with an alternative to traditional rooftop solar. While SRP prices may change over time,
the price paid for this solar energy is fixed for five years.
SRP retains all of the
“Environmental Attributes” (or RECs) associated with the renewable energy produced by
the solar facility.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 84
•
Participating customers will purchase an allocated share of Community Solar energy at
the price published on SRP’s website. Participating customers will purchase all power
and energy consumed by the customer under the E-26 Price Plan, and all charges under
that plan, including the Monthly Service Charge, remain in effect The customer’s bill will
be reduced by an amount equal to the product of (i) the customer’s share of the
Community Solar energy, multiplied by (ii) the combined prices for Energy (Generation)
and Fuel and Purchased Power under the E-26 Price Plan in effect for the applicable billing
period, adjusted for 4.8 percent losses. Based on the proposed E-26 price plan, the
following price credits would apply:
Prices for Community Solar E-26 Bill Reduction
E-26 Price Plan
Summer Peak
Summer
Winter
•
On
Off
$0.0871
$0.0804
$0.0526
$0.0496
$0.0494
$0.0469
Any Community Solar energy attributable to a customer under this program in excess of
the customer’s consumption during a given billing period will be repurchased by SRP at
the same price the customer pays for the Community Solar energy. This will insure that
customers do not purchase too much solar energy.
Conclusions:
We conclude that the proposed rider should be approved as it reflects the Board’s policies.
Business Community Solar Pilot Rider
Proposals:
Management proposes sunsetting this rider due to limited recent new participation – no further
customers will be added to this program.
Conclusions:
We conclude that the proposed rider should be approved as it reflects the Board’s policies.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 85
Community Solar for Schools Pilot Rider
Proposals:
Management proposes sunsetting this rider due to limited recent new participation – no further
customers will be added to this program.
Conclusions:
We conclude that the proposed rider should be approved as it reflects the Board’s policies.
Renewable Energy Services Pilot Rider
Proposals:
Management proposes no changes to this rider other than extending it to the new E-27 price plan.
Conclusions:
We conclude that the proposed rider should be approved as it reflects the Board’s policies.
Time-Dependent Demand Rider Supplement to E-47
Proposals:
Management proposes to increase the Monthly Service Charge from $35.39 to $40.39, effective
with the April 2015 billing cycle. This charge will apply in lieu of the Monthly Service Charge
stated in the E-47 Price Plan.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies.
Unmetered Credit Rider Supplemental to E-36
Proposals:
Management proposes to update the meter reading and meter equipment credit to match the
proposed changes to the E-36 Price Plan, effective with the April 2015 billing cycle.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 86
Lighting Equipment Rider Supplemental to E-56 and E-57
Proposals:
Management proposes to increase the prices listed in the Lighting Equipment Rider consistent
with the proposed increases to the Lighting Price Plans, to increase the upfront charge from $200
to $500 per luminaire given the cost of providing this service, and to further increase the upfront
cost by $100 per luminaire per year each May billing cycle starting in 2016 until the upfront charge
reaches a total of $1,000 per luminaire. Management also proposes to add language that allows
for assessing the monthly charges on a daily basis. Management proposes extending these
riders to the E-32, E-34, and E-36 price plans to allow for metering of SRP-owned lighting facilities.
Further, management proposes freezing this rider from any further participation by E-57
customers given the significant cost of providing SRP-owned lighting equipment.
Finally,
management proposes that at any time after the contract expiration or termination date, SRP may
transfer ownership of the lighting facilities to the customer or, in its discretion, remove the lighting
facilities, and discontinue service under this rider. Ownership of lighting facilities may also transfer
during the contract period upon mutual agreement between SRP and the customer.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies.
Municipal and Non-Municipal Lighting Equipment Rider Supplemental to E-56
Proposals:
Management proposes to increase the prices listed in the Municipal Public Lighting Equipment Rider
and to the Non-Municipal Public Lighting Equipment Rider consistent with the proposed increases to
the Lighting Price Plans to implement an upfront charge of $500 per luminaire given the cost of
providing this service, and to further increase the upfront cost by $100 per luminaire per year each
May billing cycle starting in 2016 until the upfront charge reaches a total of $1,000 per luminaire.
Management also proposes to add language that allows for assessing the monthly charges on a
daily basis. Further, management proposes to extend these riders to the E-32, E-34, and E-36 price
plans to allow for metering of SRP-owned lighting facilities. Finally, management proposes that at
any time after the contract expiration or termination date, SRP may transfer ownership of the lighting
facilities to the customer or, in its discretion, remove the lighting facilities, and discontinue service
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 87
under this rider. Ownership of lighting facilities may also transfer during the contract period upon
mutual agreement between SRP and the customer.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies.
Private Security Lighting Equipment Rider Supplemental to E-57
Proposals:
Management proposes to increase the charges listed in the Private Security Lighting Equipment
Rider consistent with the proposed increases to the Lighting Price Plans, to implement an upfront
charge of $500 per luminaire given the cost of providing this service, and to further increase the
upfront cost by $100 per luminaire per year each May billing cycle starting in 2016 until the upfront
charge reaches a total of $1,000 per luminaire. Management also proposes to add language that
allows for assessing the monthly charges on a daily basis. Further, management proposes to extend
these riders to the E-32, E-34, and E-36 price plans to allow for metering of SRP-owned lighting
facilities. Finally, management proposes that at any time after the contract expiration or termination
date, SRP may transfer ownership of the lighting facilities to the customer or, in its discretion, remove
the lighting facilities, and discontinue service under this rider. Ownership of lighting facilities may
also transfer during the contract period upon mutual agreement between SRP and the customer.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies.
Standby Electric Service Rider for Power Production Facilities
Proposals:
The proposed Standby Rider is comprised of the following charges:
•
The implementation of a daily on-peak maximum demand charge, in lieu of the Monthly
On-Peak Max kW Charge assessed under each Large General Service price plan. This
charge is intended to provide customers with appropriate costs and savings to keep their
units generating as reliably as possible. The daily on-peak maximum demand charge will
be applied when power is delivered to the customer (i.e., supplemental power) and will be
computed based on the conversion, from monthly to daily, of each Large General Service
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 88
price plan’s Monthly On-Peak Max kW Charge and all per kWh Energy (Generation)
components of each respective Large General Service price plan;
•
All per-kWh components under each Large General Service price plan will be applied to
power delivered to the customer, with the exception of the Energy (Generation)
component;
•
The output of the production facility will be metered and all per-kWh components of each
Large General Service price plan, with the exception of Energy (Generation), Fuel and
Purchased Power, and Ancillary Services 3-6, will be applied to the power production
facilities’ output; and
•
The Reservation Capacity Charge will be eliminated.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies
and appropriately reflect the cost of serving standby customers.
Facilities Rider
Proposals:
Management proposes to move the portion of the Facilities Rider that pertains to charges related
to general distribution to the E-61 and E-63 Price Plans for better visibility. See the sections for
those price plans earlier in this document for the proposed changes. The Facilities Rider will
continue to apply to customers requesting enhanced reliability, additional facilities, or system
capacity.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies.
Use Fee Interruptible Rider
Proposals:
Management proposes no changes to this rider.
Conclusions:
We conclude that the proposed rider should be approved as it reflects the Board’s policies.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 89
Customized Interruptible Rider
Proposals:
Management proposes no material changes to this rider.
Conclusions:
We conclude that the proposed rider should be approved as it reflects the Board’s policies.
Full Service Requirements Rider
Proposals:
Management proposes no changes to this rider except to clarify the economic-development
related purpose of the rider, clarify which components are eligible for a discount, and remove
residential, pumping, and lighting price plans from the rider as it is actually intended for larger
commercial and industrial loads. The rider applies only to customers with loads (individual or in
aggregate) of at least 1 MW.
Conclusions:
We conclude that the proposed changes should be approved as they reflect the Board’s policies.
Monthly Energy Index Rider
Proposals:
Management proposes no material changes to this rider except to extend applicability to the new
E-27 Price Plan.
Conclusions:
We conclude that the proposed rider should be approved as it reflects the Board’s policies.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 90
Fuel and Purchased Power Adjustment Mechanism
Proposals:
•
Management proposes to rebalance summer and winter fuel and purchased power prices
with decreases to summer prices and increases to winter prices. This results in a slight
decrease in the overall annual average Fuel and Purchased Power Adjustment
Mechanism (“FPPAM“) price to $0.0262 per kWh from the current price of $0.0263 per
kWh. Actual FPPAM prices vary by price plan and by season. This price was arrived at
by considering the estimated Fiscal Year 2015 collection balance as of April 30, 2015.
•
The proposed price targets an FPPAM balance by April 30, 2015 of approximately $3.0
million over-collected, which is within the dead band. As is the current practice, future fuel
and purchased power pricing actions will be taken in response to actual FPPAM revenues,
expenses and projections, and will be adjusted in accordance with the process approved
by the Board. FPPAM adjustments based on changes to average costs may occur twice
per year (May and November) with Board approval. However, if the collection balance
exceeds a dead band of $20 million (positive or negative), management may propose
additional adjustments, up to a maximum of one (1) per quarter.
Conclusions:
The proposed mechanism should be approved as it reflects the Board’s policies.
Systems Benefits Charge (“SBC”)
Proposals:
Management proposes to decrease the System Benefits Charge to $0.0007 per kWh from the
current price of $0.0010 per KWh, based on the projected Fiscal Year 2016 test year SBC budget.
This proposed decrease is due in part to a reduction in nuclear fuel disposal costs.
Conclusions:
The proposed charge should be approved as it reflects the Board’s policies.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 91
Environmental Programs Cost Adjustment Factor (EPCAF)
Proposals:
•
Management proposes that the EPCAF definition be clarified such that the EPCAF will be
used to track revenues and recover expenses relating to: 1) energy efficiency and demand
reduction programs adopted by SRP; 2) renewable energy resources obtained or
developed by SRP; and 3) improvements and initiatives that are not otherwise recovered
through base prices that specifically relate to carbon dioxide emissions reductions as
directed by the SRP Board, including, but not limited to, those undertaken as a result of
legislation or by regulation.
•
Management also proposes to decrease the overall annual average EPCAF price to
$0.0055 per kWh from the current price of $0.0060 effective with the April billing cycle.
The proposed decrease is intended to reduce the estimated $9.8 million over-collection
that will exist at the end of Fiscal Year 2015. Management estimates that the EPCAF
balance will decline over the subsequent 13 months.
•
Management proposes that the Board continue to review and approve the EPCAF
annually as part of the budget approval, with implementation of approved changes to the
factor occurring with the May billing cycle. However, management proposes that a semiannual review also occur for consideration of changes effective with the November billing
cycle. This is similar to the existing review process for the FPPAM.
•
Management does not propose any changes to the $20 million dead band referenced
above. Management may propose such additional adjustments, up to a maximum of one
per quarter.
Conclusions:
The proposed charge should be approved as it reflects the Board’s policies.
SUSSEX ECONOMIC ADVISORS, LLC
PAGE 92