Decoupling and Utility Demand Side Management Place your chosen image here. The four corners must just cover the arrow tips. For covers, the three pictures should be the same size and in a straight line. Janet Gail Besser, Vice President, Regulatory Strategy and Policy Harvard Electricity Policy Group December 10, 2010 Tucson, AZ
Overview National Grid Expectations for the Utility of the Future Needs of the Utility of the Present Evolving Regulatory Framework Decoupling Advanced Decoupling Aligning Interests 2
National Grid US Second largest utility in US* Distributes electricity to 3.3 million customers Services 1.1 million customers of Long Island Power Authority (LIPA) Provides natural gas to 3.5 million customers Currently owns over 4,000 MW of generation, dedicated to LIPA Based on customer numbers; includes the servicing of LIPA s 1.1 million customers 3
The Utility of the Future Increasing customer, regulator & policymaker focus on Managing rising and volatile cost of energy Reducing greenhouse gas emissions and other environmental impacts of energy use Deploying advanced technologies Expectation that utilities will play a key role Delivering energy efficiency and demand side programs Facilitating renewable energy development Building the smart grid 4
The Utility of the Present Continuing obligation to provide safe, reliable and efficient service Increasing need for investment to replace and refurbish aging/deteriorating infrastructure Facing uncertain financial markets While stepping up to meet new expectations 5
Regulatory Environment Increasing recognition that traditional regulation not working for customers or utilities Disincentive to pursue energy efficiency, demand side resources, renewables, smart grid Inadequate to support increasing investment Negative financial impact on utilities Regulators and policymakers discussing need for change 6
Elements of New Regulatory Framework Decoupling Positive incentives for utility energy efficiency Capital adjustment mechanisms Productivity incentives Adequate (industry standard) return 7
Regulatory Support for Utility Demand Side Management Revenue decoupling breaks the link between sales and revenues Rates are adjusted periodically so utility is collecting (only) the amount of revenue allowed by regulators To remove disincentives to aggressive utility implementation of energy efficiency To facilitate other demand side resources, including distributed renewable energy Positive energy efficiency incentives to encourage excellent performance and focus management attention 8
Full Revenue Decoupling Full revenue decoupling (as opposed to partial) does not distinguish among reasons for changes in sales E.g., energy efficiency, weather, economic activity If actual revenues are greater than allowed, rates are adjusted downward If actual revenues are less than allowed, rates are adjusted upward 9
Fixing Revenues v. Rates Revenue decoupling and traditional rate setting both start with a cost-based determination of the allowed revenues Approaches differ in whether rates (P) or revenues (R) are fixed P (rate) x Q (sales) = R (revenues) Allowed Revenue Requirement Rates Fixed Total Revenues Vary with Use Total Revenues Fixed Rates Vary to Avoid Over- or Under-Recovery Traditional Ratemaking Ratemaking with Revenue Decoupling 10
Implications of Decoupling Under traditional ratemaking, utilities typically rely upon rising revenues from growing sales to recover increasing costs of operation and capital Decoupling eliminates this source of revenue to cover costs Current market environment exacerbates the challenges of covering costs 190 Price Indices for Distribution Plant and Consumer Goods 170 Price Index (January 2000 = 100) 150 130 110 Handy-Whitman Distribution Plant - North Atlantic Region CPI - U.S. City Average 90 70 50 Jan-00 Apr-00 Jul-00 Oct-00 Jan-01 Apr-01 Jul-01 Oct-01 Jan-02 Apr-02 Jul-02 Oct-02 Jan-03 Apr-03 Jul-03 Oct-03 Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Apr-05 Jul-05 Oct-05 Jan-06 Apr-06 Jul-06 Oct-06 Jan-07 Apr-07 Jul-07 Oct-07 Sources: Bureau of Labor Statistics, accessed April 30, 2009. The Handy-Whitman Index of Public utility Construction Costs, Cost Trends of Electric Utility Construction, updated January 2009. 11
Investment Needed Today and To Meet Future Expectations 110,000 100,000 Total Transmission & Distribution (T&D) Investment Total T&D Investment -- Real Dollars ($2008) 1400 90,000 Forecast Total T&D Investment -- BAU 1200 ($ Millions) 80,000 70,000 60,000 50,000 40,000 Forecast Total T&D Investment -- BAU & Modernization Handy-Whitman Total Distribution Plant Index 1000 800 600 Handy-Whitman Index Historical and Forecast Transmission and Distribution Investment 30,000 400 20,000 200 10,000 0 0 Source: EEI, NAS, EPRI, Analysis Group calculations. BAU investment for reliability projected at 4.5% (nominal) per year Modernization of grid could cost an additional $220 billion 12
Constraints of Traditional Regulatory Framework $200,000 $180,000 $160,000 $140,000 $120,000 $100,000 $80,000 $60,000 $40,000 Rate Base Revenue Requirement Revenue (with periodic rate cases) Cumulative Revenue Deficiency Revenue (driven by rising sales) grows at a slower rate than therevenue requirement needed to recover capital expenditures. The gap between revenue requirements and revenues billed reflects a structural deficiency given the regulatory framework and market conditions. Periodic rate cases bring revenues back in line with revenue requirements assuming rates are set using a future test year. Industry-wide Hypothetical Revenue Requirement and Revenues, Delivery Capital Investment, Future Test Year, 2011 to 2030 ($ Million) $20,000 The cumulative deficiency between actual revenues and the revenue requirement needed to cover capital expenditures grows over time. $0 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Source: Analysis Group calculations. Revenues not sufficient to recover costs of investment Frequent rate cases needed to keep revenues in line with costs 13
Supporting Needed Investment Revenue decoupling advances energy efficiency and demand side resources But it eliminates sales growth to fund needed investment between rate cases (however, even that sales growth is insufficient to match increasing investment need) To provide cost recovery for needed capital investment Future test years and multi-year rate plans Reconciling cost adjustment mechanisms for capital expenditures between rate cases 14
Addressing Increasing Costs Adjustments designed to track changes in costs Capital costs Adjust revenues given actual capital expenditures as approved by the commission Adjusts timing of revenue recovery but not the amounts approved for recovery Under traditional ratemaking, capital expenditures would roll into rate base in next rate case Operations and maintenance costs Adjust revenues to level of inflation and level of utility productivity (similar to PBR) 15
Advanced Decoupling: Capital Cost Adjustments General Rate Case Capital Investment Placed Into Service Billed Revenue to ATR Reconciliation Base Distribution Rates Class-Specific Uniform per + per kwh + kwh RDM = CapEx Factors Factor Distribution Rates Billed to Customers in the Following Year Unique to Mass. Electric s RDM Increases annually assuming CapEx exceeds depreciation expense allowance from last general rate case 16
Capital Cost Adjustment Mechanisms Future test years and multi-year rate plans Reconciling capital cost adjustment mechanisms Capital cost adjustment with a cap on expenditures Partial capital cost adjustment Capital cost adjustment with performance incentives Targeted infrastructure capital cost adjustment Features provide incentive for efficient investment 17
Capital Cost Adjustment Mechanism Example Without revenue growth from increased sales to cover increasing capital costs, another mechanism is needed between rate cases Capital Cost Adjustment Mechanism with a Cap on Expenditures Proportion of Benchmark capital Expenditures Proportion of Annual Capital Expenditures Considered in capital Adjustment Mechanism Example: 100 M Benchmark Actual Capital Expenditure Capital Expenditure Considered in Adjustment >145% 0% $150M $122.50M 130% to 145% 25% $140M $121.25M 115% to 130% 50% $125M $116.25M 100% to 115% 75% $110M $107.50M <100% 100% $95M $95.00M Example: When actual spending is $125 million, capital expenditures considered in the adjustment mechanism are: 100%*$100 M + 75%*$15 M + 50%*$10 M = $116.25 M 18
Advanced Decoupling: Incentives for Efficient Operation Incentives for efficient operations Indexing of operations and maintenance costs for inflation, less a productivity offset Reliability, service quality, customer satisfaction indices Reconciling adjustment for highly variable costs, costs beyond utilities control, and incremental programs subject to significant cost uncertainty Supports aggressive utility approach to system needs to the benefit of customers 19
Productivity Factor The Look Back portion of the process The Look Ahead portion of the process The annual RDR Plan adjustment A B C RDR Plan Revenue Reconciliation (for each Class) + RDR Plan Revenue Adjustment (for each Class) = RDR Plan Adjustment Factor (by Class) /kwh /kwh /kwh Class -Specific: Annual Target Revenue v. Actual Revenue = Sum of All Classes Revenue Gaps Divided by Total Company-wide kwh for upcoming year Class Revenue Gap Class -specific Revenue Requirement divided by class kwh for upcoming year Adjustment to each class revenue requirement in the upcoming year allocated using factors from rate case. Annual Target Revenues ( ATR ) = the sum of: (1) Allowed Revenue from Rate Case, plus (2) cumulative Net CapEx for years after the rate case, plus (3) cumulative Net Inflation. 1. Adjustment for Net Inflation: reflecting change in inflation over two previous years less 0.5% productivity offset, plus 2. Adjustment for Cumulative Net CapEx since the rate case 3. Adjustment for Current Year Net CapEx: set at 75% of average annual historical Net CapEx in two prior years * Note that the first RDR Plan filing occurs at the end of 2010, for an RDR Plan Revenue Adjustment Factor to go into effect on January 1, 2011. 20
Adequate Return on Investment Increasing investment to replace, refurbish and modernize the grid Uncertain financial markets Adequate returns on equity (ROE) essential to attract capital needed for investment Decoupling and mechanisms for timely recovery do not warrant lower returns Adjusting returns downward undermines the effectiveness of these mechanisms Need to assess ROE on case by case basis 21
Common Misconceptions about Decoupling Misconception #1: Revenue decoupling systematically shifts risks from the utility to customers Decoupling allows customers and utility to share risks associated with weather and other factors outside their control that change energy use Misconception #2: Revenue decoupling guarantees the utility s earnings Decoupling provides revenue stability but does not guarantee earnings since utility still must manage operational costs and cost-side risks Misconception #3: Revenue decoupling will lead to large swings in rates 22
Decoupling Adjustments Have Typically Been Small 25 Revenue Decoupling Adjustments as a Proportion of Total Customer Rates 23 Number of annual rate adjustments 20 15 10 5 0 Refund Surcharge 13 3 2 2 1 1 0 6 * 12 7 7 5 4 2 0 >3% 3% 2% 1% 1% 2% 3% >3% * Impact of Mass. Electric s first RDM reconciliation filing, excluding effects of Capex provision, is a decrease of ~0.2% to a 500 kwh per month residential bill Decoupling rate adjustment Gas Electric Source: Pamela Lesh, Rate Impacts and Key Design Elements of Gas and Electric Utility Decoupling: A Comprehensive Review, June 30, 2009, at http://www.raponline.org/pubs/lesh-compreviewdecouplinginfoelecandgas-30june09.pdf. 23
Distribution Rate Adjustments Offset by Commodity Reductions Commodity and Distribution Rates Under Proposed Alternative Ratemaking in RI RDM and Comprehensive RDR Plan (with Inflation and Capital Cost Adjustments) $14 $12 $10 Standard Offer Energy Commodity Rate Price (Cents/kWh) $8 $6 Distribution Rate Assuming the RDR Plan Had Been in Place for 2003 to 2008 $4 $2 Distribution Rate Assuming an RDM Had Been in Place for 2003 to 2008 $0 Standard Offer Price History Distribution Rate (RDR Plan) Distribution Rate (RDM Only) 24
Conclusion Achieving objectives for Utility of Future requires alignment of customer, policy and utility interests Regulatory framework must encourage demand side management and efficient investment in infrastructure To capture benefits and reduce costs for customers in the long run To address climate and environmental objectives To maintain safe, reliable and efficient energy services 25