Review of Proposed Adjustments. Salt River Project s. Standard Electric Price Plans

Transcription

1 Review of Proposed Adjustments to Salt River Project s Standard Electric Price Plans Prepared by: John Chamberlin Timothy Lyons December 12, 2014

2 Table of Contents Executive Summary... 1 Background...1 Price Plan Proposals...1 Review...3 Evaluation...3 Conclusion Introduction Approach The Need for a General Price Increase Overview FY2016 Financial Forecast Sales and Revenue Forecast Net Plant and Expenditure Forecast Mitigating Efforts Proposed Increase Needed to Achieve Financial Goals Comparison to Other Electric Utilities Conclusion Cost Allocation Study and Revenue Targets Overview Review of the SRP s Cost of Service Study in Results of the FY2016 Cost of Service Study Changes in the Cost of Service Study Change in Production Allocator Change in Transmission Allocator Change in Distribution Cost Allocator Change in Customer Service Allocator Change in Load Data Target Class Returns Conclusion Proposed Changes to Standard Price Plan Designs Overview Approach Recovery of Revenue Targets Increase in Fixed Charge Revenues Seasonal Differentials Marginal Costs SUSSEX ECONOMIC ADVISORS, LLC PAGE i

3 4.5.2 Evaluation of Seasonal Differentials Conclusion New Pricing Initiatives Customer Generation for Residential Customers Overview of Cost Recovery Concerns with Current Approach: Net Energy Metering Two Areas for Potential Solutions A note on decoupling mechanisms as an alternative means to address fixed cost underrecovery Review of SRP s Customer Generation Price Plan for Residential Service Proposal Evaluation of SRP s Customer Generation Price Plan Proposal Standby Rider Review of the Standby Rider Proposal Evaluation of the Standby Rider Proposal Electric Vehicle Rate Review of the Electric Vehicle Rate Proposal Evaluation of the Electric Vehicle Rate Proposal Conclusions Appendix A: Review of Proposed Price Plans A.1 Residential Service Price Plans E-23 Residential Price Plan E-26 Residential Time-of-Use Price Plan E-24 Residential M-Power Price Plan for Pre-Pay Service E-28 Residential M-Power Time-of-Use Price Plan E-27 Residential Customer Generation Price Plan E-22 and E-25 Experimental Price Plans for Super Peak Time of-use Price Plan E-29 Experimental Price Plan for Super-Off Peak Time of Use Electric Vehicles ( EV TOU ) A.2 General Service Price Plans E-36 General Service Time-of-Use Price Plan E-32 General Service Price Plan SUSSEX ECONOMIC ADVISORS, LLC PAGE ii

4 E-34 M-Power Pre-Pay Price Plan E-33 Experimental Price Plan for Super Peak Time of Use A.3 Pumping Price Plans E-47 Standard Electric Price Plan for Agricultural Pumping E-48 Standard Electric Price Plan for Agricultural Pumping A.4 Lighting Service Price Plans E-54 Standard Electric Price Plan for Traffic Signal Lighting Services E-56 Standard Electric Price Plan for Public Lighting Service E-57 Standard Electric Price Plan for Private Security Lighting Service A.5 Large General Service Price Plans E-61 Standard Electric Price Plan for Secondary Large General Service E-63 Standard Electric Price Plan for Primary Large General Service E-65 Standard Electric Price Plan for Dedicated Large General Service E-66 Standard Price Plan for Dedicated Large General Service with Integrated Interruptible Load Critical Peak Experiment Price Plan, Supplemental to E-65 Price Plan A.6 Riders Economy Discount Rider Medical Life Support Equipment Discount Rider Renewable Energy Credit Pilot Rider Buyback Service Rider Solar Net Metering Pilot Rider Time-of-Use Residential Community Solar Pilot Rider Business Community Solar Pilot Rider Renewable Energy Services Pilot Rider Time-Dependent Demand Rider Supplement to E Unmetered Credit Rider Supplemental to E Lighting Equipment Rider Supplemental to E-56 and E SUSSEX ECONOMIC ADVISORS, LLC PAGE iii

5 Municipal and Non-Municipal Lighting Equipment Rider Supplemental to E Private Security Lighting Equipment Rider Supplemental to E Standby Electric Service Rider for Power Production Facilities Facilities Rider Use Fee Interruptible Rider Customized Interruptible Rider Full Service Requirements Rider Monthly Energy Index Rider Fuel and Purchased Power Adjustment Mechanism Systems Benefits Charge ( SBC ) Environmental Programs Cost Adjustment Factor (EPCAF) SUSSEX ECONOMIC ADVISORS, LLC PAGE iv

6 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 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

7 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

8 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 Cost of Service Report, prepared by John Chamberlin and Timothy Lyons of Sussex Economic Advisors, LLC, December 16, Financial Market and Capital Structure Considerations in Public Power Pricing Decisions, prepared by Public Financial Management, Inc., December SUSSEX ECONOMIC ADVISORS, LLC PAGE 3

9 transmission investment from 1997 to 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 Investment in electricity transmission infrastructure shows steady increase, EIA, August 26, 2014, 4 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

10 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

11 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

12 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 Also see Standby Rate for Customer-Site Resources, prepared by U.S. Environmental Protection Agency, Office of Atmospheric Programs, December SUSSEX ECONOMIC ADVISORS, LLC PAGE 7

13 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

14 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 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

15 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 Section 3.0 Section 4.0 Section 5.0 Section 6.0 Appendix A 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. 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. Price Plan Design: This section describes our review and evaluation of SRP s proposed price plans, including increased fixed charge recovery. New Pricing Initiatives: This section describes our review and evaluation of SRP s new pricing initiatives, including industry review and analysis. Conclusions. Summary of review and evaluation for each price plan, and rider. SUSSEX ECONOMIC ADVISORS, LLC PAGE 10

16 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 14.7 Factor ("EPCAF") Decrease in Fuel and Purchased Power Adjustment 0.2 Mechanism ( FFPAM ) Net increase in revenues $ 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

17 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 Financial Market and Capital Structure Considerations in Public Power Pricing Decisions, prepared by Public Financial Management, Inc., October 2014, at 9. 8 Ibid., at 7. SUSSEX ECONOMIC ADVISORS, LLC PAGE 12

18 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 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 Ibid., at Ibid., at Ibid., at Ibid., at SRP Blue Book. SUSSEX ECONOMIC ADVISORS, LLC PAGE 13

19 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 E- 23 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

20 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 ( ) 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

21 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 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: Improving reliability; Connecting to renewable energy sources; 16 Investment in electricity transmission infrastructure shows steady increase, EIA, August 26, 2014, SUSSEX ECONOMIC ADVISORS, LLC PAGE 16

22 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 times range. SUSSEX ECONOMIC ADVISORS, LLC PAGE 17

23 Figure 2.7: Debt Service Coverage Ratio FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15 FY16 Actual Without Increase 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

24 Figure 2.8: Combined Net Revenues ($Millions) FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15 FY16 Actual Without Increase With Increase 18 Ibid. SUSSEX ECONOMIC ADVISORS, LLC PAGE 19

25 Figure 2.9: Operating Margin per Retail MWh ($/MWh) FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15 FY16 Actual Without Increase With Increase 19 Ibid. SUSSEX ECONOMIC ADVISORS, LLC PAGE 20

26 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 Utilities 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

27 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 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 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. 21 Docket D-E-01933A , Direct Testimony of Kevin P. Larson, at Proposed Rates , Los Angeles Department of Water & Power, June Docket C UT, Direct Testimony of Alice K. Jackson, at Docket D , Application to Change Electricity Utility Annual Revenue Requirement, at Docket D , Application for General Rate Increase, at Preparing for the future: 2013 Rate Proposal, Sacramento Municipal Utility District. SUSSEX ECONOMIC ADVISORS, LLC PAGE 22

28 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

29 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

30 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

31 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

32 Figure 3.2: Comparison of FY2014 and FY2016 Returns Utilizing Current Prices 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 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

33 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 Sussex analysis of data provided by SRP. 30 Cost of Service Report, prepared by John Chamberlin and Timothy Lyons of Sussex Economic Advisors, LLC, December 16, SUSSEX ECONOMIC ADVISORS, LLC PAGE 28

34 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

35 Figure 3.5: Allocation of Costs to Wholesale Customers ( ) 32 Price Process Percentage % % % % % 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 Data provided by SRP. 33 Sussex analysis of data provided by SRP. SUSSEX ECONOMIC ADVISORS, LLC PAGE 30

36 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 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

37 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 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 Sussex analysis of data provided by SRP. SUSSEX ECONOMIC ADVISORS, LLC PAGE 32

38 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

39 reasonable balance between equity and gradualism, two important principles of the pricing philosophy established by the Board. SUSSEX ECONOMIC ADVISORS, LLC PAGE 34

40 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

41 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

42 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 SRP Blue Book. 38 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. 39 SRP Blue Book. SUSSEX ECONOMIC ADVISORS, LLC PAGE 37

43 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

44 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

45 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 Sussex analysis of data provided by SRP. SUSSEX ECONOMIC ADVISORS, LLC PAGE 40

46 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 Non- EPP customers. The Figure shows a higher percentage of EPP customers in Strata 2-4, and lower percentage of EPP customers in Strata SRP Blue Book. SUSSEX ECONOMIC ADVISORS, LLC PAGE 41

47 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 Sussex analysis of data provided by SRP. 45 Sussex analysis of data provided by SRP. SUSSEX ECONOMIC ADVISORS, LLC PAGE 42

48 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 Docket No ER-09, Direct Testimony of Tamie A. Aberle, at Docket No ER-11, Application for General Rate Increase, at Sussex analysis of company tariffs and recent rate cases. 49 Hawaiian Electric Power Supply Improvement Plan, August 2014, at SUSSEX ECONOMIC ADVISORS, LLC PAGE 43

49 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 $ 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 $ 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 Hawaiian Electric Power Supply Improvement Plan, August 2014, at Wisconsin PSC votes rate changes for Wisconsin Electric Power, SNL Regulatory Research Associates, November 17, Cause No. PUD , Direct Testimony of Jennifer L. Jackson, at Ibid. 54 Sussex analysis of company tariffs and recent rate cases. SUSSEX ECONOMIC ADVISORS, LLC PAGE 44

50 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 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 Second edition, at SUSSEX ECONOMIC ADVISORS, LLC PAGE 45

51 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 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 Sussex analysis of data provided by SRP. SUSSEX ECONOMIC ADVISORS, LLC PAGE 46

52 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

53 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 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 ) 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 , at 26). SUSSEX ECONOMIC ADVISORS, LLC PAGE 48

54 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) 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 Solar Energy Industries Association ( SEIA ); Solar Energy Facts: Q 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. SUSSEX ECONOMIC ADVISORS, LLC PAGE 49

55 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 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 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 Residential Rooftop Solar Net Metering Proposals, Arizona Public Service, July 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

56 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 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 (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 Feed-In Tariffs and similar programs, U.S. Energy Information Administration, June 4, 2013, SUSSEX ECONOMIC ADVISORS, LLC PAGE 51

57 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 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 (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 Designing Austin Energy s Solar Tariff Using a Distributed PV Value Calculator, prepared by Clean Power Research, at Value of Solar at Austin Energy, prepared by Clean Power Research, October 21, 2013, at 41. SUSSEX ECONOMIC ADVISORS, LLC PAGE 52

58 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 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 Most of Idaho Power net metering proposals denied, Idaho Public Utilities Commission, July 3, 2013, 69 Arizona Corporation Commission sets new direction for net metering policy, Press Release, Arizona Public Service, November 13, Preparing for the future: 2013 Rate Proposal, Sacramento Municipal Utility District, April SUSSEX ECONOMIC ADVISORS, LLC PAGE 53

59 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 The utility believes that the current blocked price structure does not match cost 71 California Residential Electric Rate Redesign, Office of Ratepayer Advocates, SUSSEX ECONOMIC ADVISORS, LLC PAGE 54

60 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 Ibid. 73 For an example of creating new rate classes, see Lyons, Timothy and Martin, John. Rate Reclassification: Who Buys What and When, Public Utilities Fortnightly. October 15, SUSSEX ECONOMIC ADVISORS, LLC PAGE 55

61 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 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 Establishing a Successor Tariff or Contract Pursuant to AB 327 (Perea, 2013), California Public Utilities Commission, 75 Rethinking Standby & Fixed Charges: Regulatory & Rate Design Pathways to Deeper Solar PV Cost Reductions, prepared by the NC Clean Energy Technology Center, August SUSSEX ECONOMIC ADVISORS, LLC PAGE 56

62 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 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 E- 26 customer. The rates were designed to be revenue neutral on a pre-solar basis for the 101,995 Strata 4-6 E- 26 customers. SUSSEX ECONOMIC ADVISORS, LLC PAGE 57

63 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 $ 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 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

64 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 Orientation 77 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 Rate Design for the Distribution Edge, prepared by Electricity Innovation Lab of the Rocky Mountain Institute, August 2014, at A Review of Solar PV Benefit & Cost Studies, elab for the Rocky Mountain Institute, September 2013, at 30. SUSSEX ECONOMIC ADVISORS, LLC PAGE 59

65 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

66 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 Standby Rider 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

67 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 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

68 for traditional service as soon as the outage is resolved. The price plan is consistent with standby service at other electric utilities Electric Vehicle Rate 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 Also see Standby Rate for Customer-Site Resources, prepared by U.S. Environmental Protection Agency, Office of Atmospheric Programs, December SUSSEX ECONOMIC ADVISORS, LLC PAGE 63

69 Figure 5.4: Proposed EV Rates (Summer) 81 On-Peak Super Off- Peak Off-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 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 Sussex analysis of data provided by SRP. 82 Company tariffs, corporate websites. SUSSEX ECONOMIC ADVISORS, LLC PAGE 64