# STATE ELECTRIC EFFICIENCY REGULATORY FRAMEWORKS

**IEI Report December 2014** 

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## STATE ELECTRIC EFFICIENCY REGULATORY FRAMEWORKS This annual update summarizes ongoing and recent policy developments that support utility investments in electric efficiency programs, including program direct cost recovery, fixed cost recovery, and perfor

mance incentives for electric utilities on a state-by-state basis. It is widely recognized that supportive regulatory frameworks are key to expanding the electric power industry’s already large commitment to energy efficiency even further. Through them, the power in

dustry can fully and seamlessly integrate electric efficiency programs into their long-term financial and system planning. And, through these state regulatory frameworks, the nation’s homes and businesses are able to continue to benefit from electric efficiency today and into the future. Since the last IEI update (July 2013), several states have updated their existing regulatory frameworks for energy efficiency. One state – Mississippi – has significantly expanded the business environment to support investments in efficiency programs by electric utilities.

• In total, 32 states have approved fixed cost recovery mechanisms – 14 with revenue decoupling and 19 with lost revenue adjustment mechanisms. This includes two states – Connecticut and Ohio – with both revenue decoupling and lost revenue adjustment mechanisms.

• Nineteen states have lost revenue adjustment mechanisms, including Mississippi, which re

ceived approval recently.

• Fourteen states have electric decoupling mechanisms, including Wisconsin and Connecticut, which recently updated their existing decoupling mechanisms. One additional state – Dela

ware – is evaluating revenue decoupling, but currently has no specific mechanism proposed for regulatory approval.

• In total, 29 states currently have performance incentives in place. This is up from 28 states in 2013. Mississippi recently approved performance incentives, and California, Colorado, Georgia, New Hampshire, and New Mexico have all updated their existing mechanisms. An additional two states – Montana and West Virginia – are evaluating performance incentives.

• Georgia’s lost revenue status has been dropped and Virginia’s pending lost revenue status has been dropped.

Table 1. Summary of State Regulatory Frameworks: December 2014*



### Summary of State Regulatory Frameworks: December 2014*
Energy Efficiency Incentive Mechanism Number of States Pending
Fixed-Cost Recovery Mechanisms Lost Revenue Recovery 19 0 Revenue Decoupling 14 1 Performance Incentives 29 2

* To avoid double-counting, Connecticut and Ohio are included as approved decoupling states.

### 2 Figure 1. U.S. Electric Efficiency Budgets (2007-2013) and 2025 Forecast

Source: IEI, Summary of Electric Utility Customer-Funded Electric Efficiency Savings, Expenditures, and Budgets, March 2014.


### Spending and budgets for customer-funded, utility electric efficiency programs continue to grow, due in part to state policies that allow utilities to pursue efficiency as a sustainable business as well as state mandates for energy efficiency. In fact, according to a recent IEI report, utility company electric efficiency budgets in 2013 totaled $7 billion, a 30 percent increase above 2010 levels. By 2025, IEI predicts that electric efficiency budgets will exceed $14 billion. The remainder of this report provides detailed state-by-state information on regulatory decisions that support electric efficiency, current as of December 2014. 

### Aligning Utility Incentives with Investments in Energy Efficiency
It is well understood that aligning incentives for utilities to treat electric efficiency programs as equivalent to supply-side investments from a financial perspective, three regulatory mechanisms are critical: direct cost recovery, fixed cost recovery, and performance incentives.

• Direct Cost Recovery refers to regulator-approved mechanisms for the recovery of costs related to the administration of the efficiency program by the administrator, implementation costs such as marketing, and the actual cost of product rebates and mid-stream product buy-downs. Such costs are recovered through rate cases, system benefits charges, and tariff rider/surcharges.

• Fixed Cost Recovery refers to decoupling and lost revenue adjustment mechanisms that assist the utility in recovering the marginal revenue associated with fixed operating costs. Rate making practices tie the recovery of fixed costs to volumetric consumption charges with rates set based on an assumed level of energy sales. The purpose of electric efficiency programs is to reduce the consumption of electricity; decoupling and lost revenue adjustment mechanisms allow for timely recovery of fixed costs.

• Performance Incentives are mechanisms that reward utilities for reaching certain electric efficiency program goals, and impose a penalty for performance below the agreed-upon goals. Performance incentives allow utilities to earn a return on their investment in electric efficiency, typically similar to the return on supply-side investments.

### 3 State Direct Cost Recovery Fixed Cost Recovery Performance Incentives Rate Case System Benefits Charge Tariff Rider/ Surcharge Decoupling Lost Revenue Adjustment Mechanism
Alabama Yes Yes Yes Yes Alaska Arizona Yes Yes Yes Yes Arkansas Yes Yes Yes California Yes Yes Yes Yes Yes Colorado Yes Yes Yes Yes Connecticut Yes Yes Yes Yes Delaware Yes Yes Pending District of Columbia Yes Yes Yes Yes

Florida Yes Georgia Yes Yes Yes Hawaii Yes Yes Yes Yes Idaho Yes Yes Illinois Yes Indiana Yes Yes Yes
Iowa Yes
Kansas Yes Yes Kentucky Yes Yes Yes Louisiana Yes Yes Yes Maine Yes Maryland Yes Yes Massachusetts Yes Yes Yes Michigan Yes Yes Minnesota Yes Yes Yes Mississippi Yes Yes Yes Yes Missouri Yes Yes Yes
Montana Yes Yes Yes Pending
Nebraska Nevada Yes Yes New Hampshire Yes Yes Yes New Jersey Yes Yes Yes 

# State Regulatory Framework Summary Table

### 4 State Direct Cost Recovery Fixed Cost Recovery Performance Incentives Rate Case System Benefits Charge Tariff Rider/ Surcharge Decoupling Lost Revenue Adjustment Mechanism New Mexico Yes Yes Yes New York Yes Yes Yes North Carolina Yes Yes Yes North Dakota Ohio Yes Yes Yes Yes Oklahoma Yes Yes Yes Oregon Yes Yes Pennsylvania Yes Yes Rhode Island Yes Yes Yes South Carolina Yes Yes Yes South Dakota Yes Yes Yes
Tennessee
Texas Yes Yes Yes Utah Yes Yes
Vermont Yes Yes Yes Virginia Yes Washington Yes Yes Yes West Virginia Pending Wisconsin Yes Yes Yes Yes Wyoming Yes Yes

Please note that although information in this document was compiled from primary sources, readers are encouraged to verify the most recent developments by contacting the appropriate commission or regulatory agency

. For inquiries, please contact Adam Cooper at acooper@edisonfoundation.net. For further information, please visitwww. edisonfoundation.net

. 

### Summary of State Regulatory Frameworks: December 2014*
Energy Efficiency Incentive Mechanism Number of States Pending
Fixed-Cost Recovery Mechanisms Lost Revenue Recovery 19 0 Revenue Decoupling 14 1 Performance Incentives 29 2 * To avoid double-counting, Connecticut and Ohio are included as approved decoupling states.

### 5 State Lost Revenue and Decoupling Description Status Codes, Orders & Resources **Alabama (LR)** Lost revenue due to efficiency programs can be recovered through a rate rider. Rates can also be set annually to allow for recovery of energy efficiency, through a Rate RSE. Approved Docket 31045

**Arizona (LR)** In May 2012, a lost-fixed-cost recovery (LFCR) was approved, as part of a rate case filed by APS. Lost revenues can be recovered starting July 1, 2012. Utilities can recover a portion of transmission and distribution costs related to sales reduced by efficiency or distributed generation. Recovered revenue can be adjusted annually. The LFCR can be modified by the Commission up to the next APS rate case in 2015. There is a residential opt-out clause to the LFCR, if residents choose the optional Basic Service Charge (BSC) instead. Approved (2012) Dockets E01345A-11-0224; E01345A-12-0232; Decision #73183 

# Lost Revenue Adjustment & Revenue Decoupling Mechanisms for Electric Utilities by State

### 6 State Lost Revenue and Decoupling Description Status Codes, Orders & Resources **Arkanasas (LR)** In 2008 the Arkanasas Public Service Commission opened a docket “for the purpose of exploring and considering possible innovative approaches to traditional ratebase rate of return regulation”. This docket includes examination of decoupling/ lost revenues that result from decreases in power usage based on successful energy efficiency and demand response efforts.
In December 2010, the Arkanasas Public Service Commission issued Order #14 in Docket 08-137-U approving a proposal by utilities, alllowing them to submit applications within the annual EE tariff filing process to collect “lost contributions to fixed costs” (LCFC) contemporaneously with program implementation. LCFC is based on the best available data, which may include deemed savings, to be followed by an annual EM&V true-up calculation. The LCFC is eligible to be collected upon starting in 2011. Approved (2010) Docket 08-137-U, Order No. 14

**California** California has had some form of decoupling since 1982. The current “decoupling plus” program is a revenue decoupling program combined with performance incentives for meeting or exceeding energy efficiency targets (performance-based rates). Revenue requirements are adjusted for customer growth, productivity, weather, and inflation on an annual basis with rate cases every three or four years (varies by utility). The incentive structure caps penalties/earnings for energy efficiency programs at $450M. Approved (Decoupling “Plus” approved in 2007) Code Sec. 9 Section 739(3) and Sec. 10 Section 739.10 as amended by A.B. XI 29; Decisions 98-03-063 & 07- 09-043

**Colorado (LR)** In May 2014, the Colorado Public Utilities Commission issued a decision order on Public Service Company of Colorado’s DSM plan, providing a “disincentive offset” pre-tax bonus of $5 million if Public Service meets or exceeds 100% of its electric energy savigs goals. No bonus will be rewarded at lesser achievement levels. The current $30 million cap on the combined bonus and performance incentive is retained to ensure ratepayers are protected from rate increases. Xcel propose to implement a revenue decoupling mechanism, under which the company would charge or credit customers based on changes to the weather-normalized use per customer of customers on the residetial (“R”) and Commercial service schedules. The company proposes to collect the revenue decoupling adjustment through the General Rate Schedule Adjustment (“GRSA”). Approved Proceeding Number 13A0686EG, Decision Number C14-0731

### 7 State Lost Revenue and Decoupling Description Status Codes, Orders & Resources
**Connecticut** Pursuant to Conn. Gen. Stat. 16-245m, as amended in July 2013 by Connecticut Public Act 13-298, every three years electric distribution companies in Connecticut must submit a comprehensive conservation & load management (C&LM) plan to the Energy Conservation Management Board of the CT Department of Energy and Environmental Protection (DEEP). In October 2013, DEEP approved a final C&LM plan for the 2013-2015 program cycle. Since 1998, electric C&LM programs have been primarily funded by a retail charge on electric ratepayers of three mills per kWh. Additionally, Act 13-298 provides for the Public Utilities Regulatory Authority to ensure that additional revenues required to fund the approved C&LM budgets are “provided through a fully reconciling conservation adjustment mechanism for each electric company” of not more than three mills per kWh. United Illuminating’s existing decoupling mechanism recovers revenues from lost sales. CT law requires Connecticut Light & Power (CL&P) to submit a similar decoupling mechanism in its next general rate case. Until then, CL&P will seek recovery of lost revenues through its Non Bypassable Federally Mandated Congestion Charge. Approved (2013) Public Act No. 13-298; Docket No. 12-08-11; Docket No. 13-03-02; CT DEEP 2013-2015 Conservation & Load Management Plan, Final Decision, October 2013

**Delaware** Under Delaware SB 150, signed August 2014, “The Commission shall approve cost recovery for cost-effective energy savings resulting from cost-effective programs and portfolios of Commission-regulated affected energy providers.” SB 150 also states that “the Commission shall utilize a process that achieves the efficient and timely recovery on an annual basis... of appropriate costs and associated rates of return related to implementing [energy efficiency] activities and programs.” As part of their last general rate case in 2012 (Docket 11-528), Delmarva Power requested an alternative regulatory model which included a revenue decoupling mechanism, however the proposed decoupling mechanism was abandoned as part of a settlement with interveners and was not adopted in the final order. Pending Docket No. 11-528; Docket No. 09-276T; SB 150

**District of Columbia**  The DC Public Service Commission approved PEPCO’s Bill Stabilization Adjustment (BSA) in October 2009. Like the BSA approved for Maryland, an RPC mechanism is employed which adjusts quarterly. Approved (2009) PSC Order 1053-E-549

**Hawaii** The Hawaii PUC approved decoupling as a policy in February 2010, but a final order is pending. The utilities have submitted a proposed mechanism which allows for decoupling of revenues from sales, rate base adjustments for O&M costs and planned capital additions, and a mechanism for sharing earnings with rate payers should a company exceed their allowed ROE. True-ups occur annually. Approved - Pending Final Order Docket 2008-0274

### 8 State Lost Revenue and Decoupling Description Status Codes, Orders & Resources
**Idaho** After a five year pilot the Commission approved Idaho Power Company’s request to convert Schedule 54, a fixed-cost adjustment (FCA) mechanism from a pilot to an ongoing, permanent schedule. The FCA uses a fixed cost per customer approach. Sales are adjusted for weather and the FCA rate increases are capped at 3% over the previous year. The mechanism is only applied to residential and small general service customers. Approved (Pilot 2007- 2009, extended 2010- 2011) Case No. IPC-E-04-15, Order No. 30267; Case No. IPC-E-09-28, Order No. 31063; Case No. IPC-E-11-19, Order No. 32505, Order No. 32731

**Indiana (LR)** The Utility Regulatory Commission approved Duke Energy Indiana and Indiana Michigan Power Company’s request to recover lost revenues due to the implementation of a DSM program. Northern Indiana Power & Light, and Indianapolis Power & Light have lost margin recovery mechanisms proposals pending before the Commission. Approved Cause No. 43827; Cause No. 43955; Cause No. 43912; Cause No. 43960

**Kansas (LR)** Kansas Corporate Commission allows lost revenue adjustment in certain cases. In Docket No: 10-WSEE-775-TAR, Westar was granted a shared savings mechanism, which is similar to lost revenue recovery. The Commission does not favor lost revenue recovery, but will consider it if it achieves established energy efficiency goals. Approved Docket No: 10-WSEE775-TAR; Docket No: 12-GIMX-337-GIV

**Kentucky (LR)** Lost revenue recovery mechanisms are determined on a case-by-case basis, but all electric utilities in Kentucky have DSM proposals in place that include similar lost revenue (LR) recovery due to DSM programs. For these utilities, LR is calculated using the marginal rate, net of variable costs, times the estimated kWh savings from a DSM measure over a three-year period. Approved (2006) Statute Ch. 278, Title 285; Docket 2007-00477; 2008- 00473; 2009-00444; 2010- 00445; 2011-00448

**Louisiana (LR)** In December 2012, the Louisiana Public Service Commission (PSC) approved a plan to give utilities a year to develop energy efficiency programs for their ratepayers. The Commission reversed its decision in February 2013, but again agreed to revisit the initiative in May 2013 after several consumer and environmental groups filed suit. In June 2013, the PSC voted to reinstate the initiative.

In its September 2013 order, the Louisiana Public Service Commission (LPSC) lifted the stay on the Commission’s Energy Efficiency Rules which sets a timeline and guidance on the implementation and recovery of costs associated with quick start energy efficiency programs by LPSC jurisdictional electric utilities. The formula for recovery of Lost Contributions to Fixed Costs (LCFC) is still being finalized. The amount of proposed recovery may be considered a regulatory asset by the utility and may be reconciled in a base rate or forumula rate proceeding, whichever comes first. Alternatively, utilities may use the EE Rate Rider to recover contemporaneously the amount of proposed recovery from participating customers subject to annual true-up. Approved (2013) Docket R-31106

**Maryland** A plan to employ revenue decoupling for Maryland utilities under an RPC mechanism was approved in 2007, which adjusts quarterly. The mechanism is similar to the BSA approved for Washington, DC. Approved (2007) PSC Case No. 9093; Order 81518; Case No. 9154

### 9 State Lost Revenue and Decoupling Description Status Codes, Orders & Resources

**Massachusetts** Gas and electric utilities in Massachusetts must include a decoupling proposal in their next rate case. Target revenues are determined on a utility-wide basis (full decoupling) and can be adjusted for inflation or capital spending requirements if necessary. The Massachusetts DPU expects that all utilities will have fully operational decoupling plans by 2012. In May 2009, National Grid was the first utility to submit a revenue decoupling ratemaking plan (RDR), which proposes an RPC mechanism that adjusts annually. Approved (2008), full implementa

tion by 2012 Docket 07-50; Docket 09-39

**Mississippi (LR)** In July 2013, the Mississippi Public Service Commission issued a final order in Docket No. 2010-AD-2, adding Rule 29, related to the Conservation and Energy Efficiency Programs. Section 106 in Rule 29 defines energy efficiency program costs as the incremental program costs that are not already included in the then-current utiity rates and the lost contribution to fixed costs associated with approved energy efficiency programs. Cost recovery shall include full and timely recovery of incremental program costs and the lost contribution to fixed cost.

A utility can recover energy efficiency program costs through a rider, the Energy Efficiency Cost Rate (EECR). In support of this re-determined rate, the utility shall file a schedule of actual program costs for the reporting period, actual amounts collected under the rider for the reporting period, actual and projected lost contributions to fixed costs and approved program budgets for the current calendar year. The EECR shall be adjusted to reflect a reconciliation of any over- or under-recovery for the prior year and the approved budget for the current program year. Approved Docket No. 2010-AD-2

**Missouri (LR)** In 2011, the Missouri Energy Efficiency Investment Act authorized utilities to file plans to recover a portion of the net benefits of demand-side energy efficiency programs. Ameren Missouri and KCP&L GMO LR rate cases were approved in late 2012. Two other cases - Kansas City Power & Light Company and The Empire District Electric Company - were withdrawn in 2012, and is likely they will refile by 2014. Approved (2012) SB376; Case No. EO 2012-0142; Case No. EO 2012-0166; Case No. EO-2012-0009; Case No. EO-2012-0175

### 10 State Lost Revenue and Decoupling Description Status Codes, Orders & Resources **Montana (LR)** In December 2005, the MT PSC approved Northwestern Energy’s petition for a lost transmission and distribution revenue recovery mechanism.
Under the mechanism, lost revenues due to DSM acquisition efforts are factored into rates monthly as part of Northwestern’s default supply cost tracker. The estimated lost T&D revenue amount is then trued-up annually based on actual program activity following a comprehensive program evaluation and independent verification of actual savings, which must be filed with the Commission. NWE must consult with its advisory committee on the selection of an independent contractor to evaluate DSM programs and the scope of work. In December 2010, the Commission granted NorthWestern Corp. a decoupling mechanism as part of its electric rate case. NorthWestern filed a motion for reconsideration, leaving the docket open and the implementation of decoupling pending further action. Approved (LR, 2005) Dockets D2004.6.90 and D2010.5.50

Docket D2009.9.129

**Nevada (LR)** In June 2010, the Nevada PUC approved NV Energy’s proposal for a lost revenue recovery mechanism. Approved to implement the legislative directives of S.B. 358 (section 11.3), the mechanism calls for monthly lost revenue trackers with an annual true-up subject to measurement and verification of effects on utility revenue caused or created by energy efficiency and conservation programs.

The Nevada Public Utilities Commission has opened an investigative docket to collect information, analysis, and recommendation consistent with Nevada Revised Statutes 704.785 on alternatives to the lost revenue recovery mechanisms, including, but not limited to, an equity adder methodology and a general decoupling methodology. NV Energy has filed for consideration an annual cost recoverywith a multiplier methodology that would be a very simpleto-administer replacement for the current LRAM process, using a calculation similar to the previous equity adder, wherein the multiplier of 10 percent would be applied to the total energy efficiency and conservation expenditures made each year. Other parties have filed a modified revenue-cap decoupling approach, revenue per customer decoupling, and full decoupling. The docket remains open. Approved (2010) PUC Docket 12-12030

### 11 State Lost Revenue and Decoupling Description Status Codes, Orders & Resources
**New Mexico** In 2008, HB 305 was signed into law requiring that all utilities include cost-effective energy efficiency and load management programs and to remove regulatory disincentives for these programs. As a result, in 2010, the New Mexico Public Regulation Commission instituted an adder for all utilities. The adder comprised of a lost revenue adjustment and a performance premium, combined into a single payment. In July 2011, the New Mexico Supreme Court vacated the adder, stating that it must be cost-based and that each utility must file individually. In November, 2011, the NM Public Regulatory Commission determined that adders for PNM and El Paso Electric were utility-specific, cost-based, evidence-based, and properly balance the interests of the utility, its customers, and the public. In July, 2013, HB 267 ammended HB 305 and included a provision for a fixed cost tariff rider of 3% of revenues to fund efficiency programs. Other substantive changes include using the Utility Cost test in place of the Total Resource Cost test to determine program cost-effectiveness, and reducing the requirement for energy savings by from 10% to 8% of 2005 retail sales. In December, 2013, El Paso Electric reached a stipulated agreement and establlished an annual incentive for calendar years 2014-2016 that is equal to 7% of program expenditures. In November, 2013, PNM Ireceived an approved incentive of approximately 7.6% of program expenditures. In January 2014, Southwesten Public Service Company entered into an uncontested stipulation wherein its requests for recovery of financial incentives for 2013, 2014, 2015 were approved. Approved Case No. 13-00286-UT; Case No. 13-00176-UT; Case No. 12-00317-UT

**New York** Following an April 2007 order, electric and gas utilities must file proposals for true-up based decoupling mechanisms in ongoing and new rate cases. Proposals have been approved for Consolidated Edison and Orange & Rockland utilities, both for revenue-per-class mechanisms. True-ups occur annually. Approved (2007) Cases 03-E-0640, 07-E0949, & 07-E-0523

**North Carolina (LR)**  The Commission approved a proposed lost revenue adjustment mechanism for Progress Energy Carolinas as part of their cost recovery mechanism. Net lost revenues for each annual period are recovered over 3 years and determined by multiplying lost sales by a net lost revenue rate, which is the difference between the average retail rate applicable to the customer class impacted by the measure and (1) the related customer charge component of that rate, (2) the fuel component of the rate, and (3) the incremental variable O&M rate. True-ups occur annually. The Commission also approved a similar mechanism for Duke Energy Carolinas in December 2009 for energy efficiency measures only, coinciding with the approval of the utility’s virtual power plant mechanism. Approved (2009) Docket E-2, Sub 931; Docket E-7, Sub 831

### 12 State Lost Revenue and Decoupling Description Status Codes, Orders & Resources **Ohio (D, LR)** Lost revenue recovery mechanisms are determined on a case-by-case basis. Duke Energy Ohio recovers lost revenues resulting from their portfolio of EE programs through the DSM rider. LR is calculated as the amount of kWh sales lost due to the DSM programs times the energy charge for the applicable rate schedule, less variable costs, divided by the expected kilowatt-hour sales for the upcoming 12 month period. They are collected over a 36 month period. The Commission ordered AEP Ohio to develop a 3 year decoupling pilot program for 2012-2014. In this pilot there shall be no cap of annual rate decreases to customers; however, annual increases attributable to the pilot shall be capped at 3 percent of the total annual distribution revenues for a customer class. Duke Energy Ohio has a distribution revenue adjustment mechanism for large non-residential customers anddistribution revenue decoupling for residential and small nonresidential customers. Approved (2007) ORC §4928.143(B)(2)(h); 06-0091-EL-UNC; Case No. 11-3549-EL-SSO Case No. 11-0351-EL-AIR

**Oklahoma (LR)** OG&E has direct lost revenue adjustment (“Class Lost Revenue Factor”) built in to the approved demand program rider (DPR) structure, which includes a shared savings mechanism (see p. 15). As the name implies, LR amounts are examined by customer class. Approved (2009) Cause No. PUD 200800059, Order 556179

**Oregon** Portland General Electric was approved for a two year pilot employing an RPC decoupling mechanism. True-ups will occur annually. Approved - Pilot (2009) Order 09-020

**Rhode Island** May 2010, the Rhode Island passed the Decoupling Act (R.I.G.L. §39-1-27.7.1), mandating that Narragansett Electric Co., a subsidiary of National Grid Group Plc., decouple its revenues from sales. In October 2010, National Grid filed a request with the Rhode Island Public Utilities Commission to implement revenue decoupling mechansims for its electric and gas operations. In May 2012, order 20745 was issued approving National Grid’s RDM proposal. It is retroactive to April 2011 and an adjustment factor is to be annually. Approved (2012) (R.I.G.L. §39-1-27.7.1) Docket No. 4206, Order 20745

**South Carolina (LR)**  The Commission approved a proposed lost revenue adjustment mechanism for Progress Energy Carolinas as part of their cost recovery mechanism. Net lost revenues for each annual period are recovered over 3 years and determined by multiplying lost sales by a net lost revenue rate, which is the difference between the average retail rate applicable to the customer class impacted by the measure and (1) the related customer charge component of that rate, (2) the fuel component of the rate, and (3) the incremental variable O&M rate. True-ups occur annually. Approved (2009) Docket 200-251-E

### 13 State Lost Revenue and Decoupling Description Status Codes, Orders & Resources
**South Dakota (LR)**  Beginning in 2010, the SD utilities switched from receiving performance incentives to receiving a fixed percentage of lost revenues. MidAmerican and OtterTail Power converted in 2010 and 2011, respectively. Black Hills and Xcel Energy began recovering in 2011 as well. NorthWestern Energy is expected to file a lost revenue mechanism in the near future. All programs are still in the pilot phase and have not been incorporated into the base rate cases yet. They all allow for riders with annual true-ups for the recovery of lost revenues. Approved (2010) Dockets EL11-012; GE10- 001; EL11-002; EL11-013; GE12-001

**Vermont** An RPC decoupling program was approved for Green Mountain Power under the Alternative Regulation Plan. Rates can be adjusted up to four times per year with an annual reconciliation on allowed earnings. Changes in base rates cannot exceed ~2% per year. CVPS was also approved for decoupling in 2008. Approved (2007) Dockets 7175, 7176 & 7336

**Washington** The Washington Utilities and Transportation Commission (WUTC) approved decoupling mechanisms for PSE on June 25, 2013. The commission will allow PSE to increase rates by 3.34% this year, and over the next 3-4 years, a maximum of 3% of its revenue with any excess amounts above the 3% recovered in the following year. Approved (2013) Docket UE-121373

**Wisconsin** A 4-year decoupling pilot by Wisconsin Public Service Corporation (WPS) was initially approved in December 2008. In a rate case completed in December 2012, the pilot was extended with a modified Revenue Stabilization Mechanism (RSM). The new RSM is based on a Total Rate Case Margin instead of a Total Rate Case Margin per Customer, intending to remove the sensitivity related to sales per customer. Using a future test year to determine the revenue requirement, the utility compares the total target revenue with actual revenue and defers the difference, subject to carrying costs based on approved short-term debt rate. The margin equals the total revenue for each tariff, less the costs associated with the annual per-kWh value established for monitored fuel costs, and excluding any surcharges, credits, taxes, or similar charges. The formula for calculating an over-or-under collection is: actual margin minus ratecase forecasted margin established in the most recent rate proceeding. The new RPS will be in effect on a pilot basis until WPS’ next general rate order, expected for the 2014 and/or 2015 test years. Approved Docket No. 6690-UR-121

**Wyoming (LR)** A tracking adjustment mechanism that includes direct lost revenue recovery was approved for a small service territory covered by Montana Dakota Utilities. The adjustment applies to all MDU customers to recover costs and lost revenues for load management programs only. Approved (2007) Docket No. 20004-65-ET06

### 14 

# EE Performance Incentives for Electric Efficiency Providers by State

State Performance Incentive Description Status Relevant Statute, Code or Order

**Alabama** Alabama Power is able to recover a “reasonable rate of return” on efficiency program spending through a rate rider. Approved Docket 31045

**Arizona** Arizona Public Service (APS), Tucson Electric Power (TEP), and UniSource all have have performance incentives in place under a shared savings mechanism, set at a percentage of DSM program net economic benefits and capped at a percentage of total DSM expenditures. The percentages are dependent on achievemnt relative to energy efficiency goals. Each incentive is independently determined based on the utility’s rate case. Approved (2005) Decision 67744, Docket E-01345A-05-0816, et al

**Arkansas** In 2010, the Commission issued Order No. 15, approving performance incentives through a shared savings of net benefits approach. 10% of net benefits will be awared to a utility for achievement above 80% of the savings goal. Total incentive rewards are capped at 5% of proposed budget for achievement between 80% and 100% of goal; 7% of budget for achievement between 100% and 110% of goal. Net benefits shall be based on a TRC test. EE program portfolio goals as a percentage of 2010 energy sales are: 2011: 0.25%, 2012: 0.50%, 2013: 0.75% Approved (2010) Docket 08-137-U, Order No. 15

### 15 State Performance Incentive Description Status Relevant Statute, Code or Order

**California** California utilities are eligible to earn the Efficiency Savings and Performance Incentives (ESPI) mechanism on programs funded and implemented for the 2013-2014 program cycle and subsequent programs cycles, superseding the Risk/Reward Incentive Mechanism (RRIM). Potential EPSI earnings available over the 2013-2014 cycle is capped at $178 million. Performance incentive opportunities are divided as follows: A. Energy Efficiency Resource Savings paid as a combination of ex ante “locked down” and ex post verified units of savings results, according to the level of uncertainty of the measure for which savings are being claimed. Resource savings are measured based on net lifecycle savings. Incentives for EE resource savings are capped at 9% of resource program budgets, minus funding dedicated to administrative activities, codes and standards programs, EM&V, and community choice aggregator and regional energy networks programs. B. A performance award is available for implementing the lock down of ex ante parameters based on performance metrics scoring with the award capped at 3% of resource program expenditures. C. A management fee of 12% of approved codes and standard program expenditures. D. A management fee of 3% for implementing non-resource programs, which support savings based programs but in which there are no direct savings. EPSI award claims for the firstprogram year will be made in the first following year for nonresource program management fee, codes and standards program management fee, ex ante performance award, preliminary ex ante locked down deemed measure savings award. Subsequently, in the second following year of the first program year, claims covering custom projects, ex post verified deemend measure savings, and true up of preliminary ex ante lockdown award based on verified counts shall be made. Approved R.12-01-005; Decison 13.09.023

**Colorado** In May 2014, the Colorado Public Utilities Commission issued a decision order on Public Service Company of Colorado’s DSM plan, providing a financial incentives of 5% of net dollar savings when energy savings are 100% or greater of goal. The cap on the percentage of net dollar savings earned has been removed as the approved incentive no longer contains an incremental adder for energy savings over 100% of goal. The current $30 million cap on the combined bonus and performance incentive is retained to ensure ratepayers are protected from rate increases. Approved Proceeding Number 13A-0686EG, Decision Number C14-0731

**Connecticut** The CT PUC requires annual hearings for utilities, where the past year’s results for energy savings are reviewed and a performance incentive is determined, which ranges from 1% to 8% of program costs. The minimum threshold of 70% of goals earns the minimum (1%) incentive. Reaching 100% of goals earns 5%, and for reaching 130% of goals earns 8%. Approved (first in 1988, mechanism changes over time) Dockets 07-10-03; 08- 10-03; 09-10-03

### 16 State Performance Incentive Description Status Relevant Statute, Code or Order

**District of Columbia**  Section 202 of the DC Clean and Affordable Energy Acot of 2008 authorizes the District’s Department of the Environment to award “performanced based” and “financial” incentives to the operator of DC’s Sustainable Energy Utility, VEIC, for meeting or exceeding specific performance benchmarks established in its contract. The contract with the Department of the Environment also includes financial penalties should the utility fail to meet the performance benchmarks Approved (2008) Section 202 of the DC Clean and Affordable Energy Act of 2008

**Georgia** As agreed to under the 2013 Integrated Resource Plan stipulation resolution, Georgia Power will receive an Additional Sum of 8.5% of the NPV of the actual net benefits of verified net kWh savings as determined by the Program Administrator test from the certified DSM programs, with no cap, provided that following the annual determination of verified net kWh savings. If the annual incremental kWh savings is less than 50% of that initially projected, the Additional Sum shall be 0.5% for demand response measures and 3% for energy efficiency measures. If the Additional Sum exceeds program costs, the portion of Additional Sum that exceeds the program cost shall be calculated based on 4% of actual net benefits of verified net kWh savings as determined by the Program Administrator test from certified DSM programs. Georgia Power will update all data relating to actual program participation, as well as the actual energy savings and actual programs costs when calculating the Additional Sum for 2014 and future years. Approved Docket & Order 36499

**Hawaii** As part of the state’s transition plan to establish a third-party administrator for efficiency programs, the HECO companies are responsible for administering their own DSM programs until the transition date. HECO may earn a shared percentage of savings of 1%-5% with an incentive cap of $2M. Approved (2008) Docket & Order 23258, Docket 2007-0323

**Indiana** The state statute allows for either shared savings or adjusted/bonus ROE mechanisms as DSM incentives. To meet mandatory energy efficiency goals, Indiana utilities have developed “Core Plus” DSM programs. Duke Energy, Indianapolis Power & Light and Southern Indiana Gas & Electric Company received approval for a tiered structure shareholder performance incentives, and Indiana Michigan Power Company received approval for a shared benefits approach. Other cases currently pending before the Commission related to energy efficiency programs and performance incentives include No. 43938 (Vectren Energy Indiana), No. 43912 (Northern Indiana Public Service Company ), and No. 43960 (Indianapolis Power and Light). Approved (2010) Administrative Code, Title 170, Art. 4; Cause No. 43374; Cause No. 43427; Cause No. 43618; Cause 43623; Cause No.43827; Cause No. 43938; Cause No. 43912; Cause No. 43960; Cause No. 43955

**Kentucky** Performance incentives can be collected for three types of energy efficiency programs: programs for those who have difficulty participating in energy efficiency due to financial circumstances, programs aimed at residential housing, programs with long-run potential reduction in energy use." Approved (2007) Rev. Stat. 278.285(1) (c); Docket 2008-00473; 2007-00477

### 17 State Performance Incentive Description Status Relevant Statute, Code or Order

**Louisiana** In December 2012, the Louisiana Public Service Commission (PSC) approved a plan to give utilities a year to develop energy efficiency programs for their ratepayers. The Commission reversed its decision in February 2013, but again agreed to revisit the initiative in May 2013 after several consumer and environmental groups filed suit. In June 2013, the PSC voted to reinstate the initiative. The type of performance incentive mechanism has yet to be determined. Approved (2013) Docket R-31106

**Massachusetts** The incentive allows utilities to earn about 5% of program costs for energy efficiency programs that meet established program goals. The incentive structure is determined on a program-by-program basis but generally utilizes a three-tiered structure. The first “design performance” level is defined as performance that a Program Administrator expects to achieve in implementing its energy efficiency programs. The second “threshold performance” level is 75% of the design level. The third “exemplary performance” level is 125% of the design level. Incentives are awarded only if a program achieves the threshold level or above. Approved (2000) Docket 04-11; Order 98-100

**Michigan** The Commission approved DTE’s energy optimization plan in 2009, which includes an incentive mechanism that allows the utility to earn up to 15% of program spending (a cap mandated by PA 295) if they reach 125% of their savings goals. An incentive payment is applied only if DTE exceeds its savings goal.
PA 295 contains two provisions authorizing utilities to receive an economic incentive for energy efficiency programs. To be eligible, utilities must request that appropriate energy efficiency program costs be capitalized and earn a normal rate of return. Utilities can request a performance incentive mechanism to provide additional earnings to shareholders if they exceed the annual energy savings target. Incentives are capped at 15% of the total program cost. Approved (2009) PA 295 (2008); U-15806

**Minnesota** The PUC revised the performance incentive originally approved in 1999. Under the new agreement, utilities retain a portion of net benefits based on the level of achievement, measured as a percent of retail sales. The award scale for this modified shared savings mechanism is calibrated to award $0.09/kWh at 1.5% of sales (e.g. if a utility achieves savings equal to 1.5% of sales, it will receive $0.09 for every kWh saved. The order was approved in January 2010. Approved (1999); Revised mechanism (2010) Docket CI-08-133, Stat

ute 216B.241

### 18 State Performance Incentive Description Status Relevant Statute, Code or Order **Mississippi** In July 2013, the Mississippi Public Service Commission issued a final order in Docket No. 2010-AD-2, adding Rule 29, related to the Conservation and Energy Efficiency Programs. Section 106 in Rule 29 states that the utility may propose an approach to earn a return on energy efficiency investments through a shared savings or other performance based incentive mechanism to make these investments more like other investments on which utilities earn a return.

If the utility seeks Commission approval to earn a return on energy efficiency investments, it may file a return on investment caclulation through the Energy Efficiency Cost Rate (EECR) based on the its performance to meet or exceed specific reporting year energy savings targets expressed as percentages of energy sales. Approved Docket No. 2010-AD-3

**Missouri** The Missouri PSC approved Ameren Missouri and KCP&L GMO's requests for performance incentives using a shared net benefits approach. The Ameren agreement allows $80 million in annual revenue requirement in Ameren Missouri’s recent general rate case (Case No. ER-2012-0166) for recovery of demand-side programs’ costs and recovery of fixed operating costs. The KCP&L GMO agreement allows $18 million in annual revenue requirement in GMO’s recent general rate case (Case No. ER-2012-0175) for recovery of demand-side programs’ costs and recovery of fixed operating costs (to overcome the through-put disincentive) and which will allow the Company to earn a future performance incentive award based on after-the-fact verified 3-year program energy savings and demand savings. Approved (2012) Case No. EO-2012-0166; Case No. ER2012-0175

**Montana** MT statute allows for the Public Service Commission to add 2% to the authorized rate of return for DSM investments. It has not yet been approved for a specific utility. Pending. Passed into law, but not implemented by utility Code 69-3-712

### 19 State Performance Incentive Description Status Relevant Statute, Code or Order

**New Hampshire**  The PUC is currently re-evaluating its performance incentive In September 2013, the New Hampshire Commission approved a new performance incentive mechanism for the state’s Core utilities, which took effect beginning with the 2014 program year. For Core electric utilities, the new mechanism applies “a new ratio of electric lifetime savings to total lifetime energy savings as they relate to the total portfolio of Core electric programs. Upon applying this ratio, if it is determined that electric lifetime savings are greater than or equal to 55% of total lifetime energy savings, a higher performance incentive would apply. If the electric lifetime savings fall below 55% of total lifetime energy savings, a lower incentive would apply.” The new mechanism preserves the same basic structure as the prior mechanism, “except that the baseline is lowered from 8% to 7.5% at the 55% and up level, and to 6% at the under 55% level.” Additionally, “the overall maximum performance incentive that can be achieved is lowered from 12% to 10% at the 55% and up level and to 8% at the under 55% level.” Under the new mechanism, the individual components used to calculate the performance incentive (the kWh savings and benefit-cost components) will be capped, with each component representing no more than half of the maximum incentive (i.e., the kWh component would be capped at 5% and the benefit-cost component would be capped at 5% at the 55% and up level), rather than capping the overall performance incentive amount for each sector (residential and commercial/industrial sectors). The minimum thresholds of 65% of planned kWh savings and 1.0 for benefit-cost remain unchanged. Approved (2013) Docket DE 12-262; Order No. 25,569

### 20 State Performance Incentive Description Status Relevant Statute, Code or Order

**New Mexico** In 2008, HB 305 was signed into law requiring that all utilities include cost-effective energy efficiency and load management programs and to remove regulatory disincentives for these programs. As a result, in 2010, the New Mexico Public Regulation Commission instituted an adder for all utilities. The adder comprised of a lost revenue adjustment and a performance premium, combined into a single payment. In July 2011, the New Mexico Supreme Court vacated the adder, stating that it must be cost-based and that each utility must file individually. In November, 2011, the NM Public Regulatory Commission determined that adders for PNM and El Paso Electric were utility-specific, cost-based, evidence-based, and properly balance the interests of the utility, its customers, and the public. In July, 2013, HB 267 ammended HB 305 and included a provision for a fixed cost tariff rider of 3% of revenues to fund efficiency programs. Other substantive changes include using the Utility Cost test in place of the Total Resource Cost test to determine program cost-effectiveness, and reducing the requirement for energy savings by from 10% to 8% of 2005 retail sales. In December, 2013, El Paso Electric reached a stipulated agreement and establlished an annual incentive for calendar years 2014- 2016 that is equal to 7% of program expenditures. In November, 2013, PNM Ireceived an approved incentive of approximately 7.6% of program expenditures. In January 2014, Southwesten Public Service Company entered into an uncontested stipulation wherein its requests for recovery of financial incentives for 2013, 2014, 2015 were approved. Approved Case No. 13-00286-UT; Case No. 13-00176-UT; Case No. 12-00317-UT

**New York** The first phase of performance incentives were eligible to be collected for the 2011 year. The order caps the aggregateincentives at $40M per year statewide and target megawatthours will be set for each year at the time of review for the EE plans. Utilities could be rewarded or penalized for energy efficiency performance. As of June 2012, these incentives were being accounted for and will be paid out to the utilities upon completion. Phase 2 of the performance incentives will span 2012-2015. Incentives will total $36 million statewide over the three years - 2/3 of the amount can be earned by each utility independently, 1/3 of the amount will be distributed if the utilities reach a statewide goal. Utilities can only be positively rewarded in Phase 2. The proposal is still awaiting finalization. Approved (2011) Case 07-M-0548; Commission Opinion No. 89-29

### 21 State Performance Incentive Description Status Relevant Statute, Code or Order

**North Carolina**  North Carolina state law states that a utility may propose incentives for demand side management or energy efficiency programs to the Commission for consideration. The commission approved Progress Energy Carolina’s incentive mechanism that allows for an incentive of 8% of NPV of benefits from DSM programs and 13% of NPV from EE programs. The Commission is considering an avoided cost recovery mechanism submitted by Duke Energy. The Commission issued a notice of decision approving Duke Energy Carolinas’ Save-a-Watt program in December 2009 with a full decision to follow in January 2010. The program is similar to that in Ohio, where Duke will receive 50% of the net present value (NPV) of the avoided costs for conservation and 75% of the NPV for demand response. Approved - Progress Energy Carolinas (2009), Duke Energy (2009) Docket E-2, sub 931; Docket E-7, Sub 831

**Ohio** Duke Energy received approval in December of 2008 for its proposed “Save-a-Watt” program, where the utility will receive 50% of the NPV of the avoided costs for energy conservation and 75% of the NPV of the avoided costs for demand response. Demand response programs are viewed by the parties as having a useful life of 1 year, while energy conservation programs have useful lives of up to 15 years. This mechanism was approved through December 31, 2011. Duke Energy Ohio has filed for a new recovery mechanism of Shared Savings. This is at a tiered level dependent upon impacts achieved. Duke Energy Ohio has also filed a decoupling mechanism to account for LR. Approved (2008) Docket 08-920-EL-SSODocket 11-4393-ELRDR

**Oklahoma** A shared savings program has been approved for Public Service Oklahoma (AEP) which allows for two different returns: an incentive of 25% of net savings for programs for which savings can be estimated and 15% of the costs for other programs (e.g. education and marketing programs). OG&E also has an incentive mechanism where they receive shared benefits for achieving savings goals, calculated on a measure-by-measure basis. Approved - PSO (2008), OG&E (2009) Cause No. PUD 200700449, Order 555302; Cause No. PUD 200800059, Order 556179

**Rhode Island** The shareholder incentive mechanism includes two components: performance-based metrics for specific program achievements, and kWh savings targets by sector. The program performance metrics are established for each individual program, such as achieving specific savings or a certain market share for the targeted energy-efficient technology. If Narragansett (d/b/a National Grid) achieves the savings goal, it receives 4.4% of the eligible budget. The threshold performance level is 60% of the savings goal. Once the threshold level has been reached, the utility has the ability to earn an additional incentive per kWh saved up to 125% of target savings. Incentive rates change by customer class. Approved (2005) Docket 3635, Order 18152

### 22 State Performance Incentive Description Status Relevant Statute, Code or Order

**South Carolina**  South Carolina law stipulates that the PSC “may adoptprocedures that encourage electrical utilities [...] to invest in costeffective energy efficient technologies and energy conservation programs.” The Commission approved Progress Energy Carolina’s incentive mechanism that allows for an incentive of 8% of NPV of benefits from DSM programs and 13% of NPV from EE programs. The Commission issued a notice of decision approving Duke Energy Carolina’s Save-A-Watt program in December 2009 with full decision to follow in January 2010. The program calls for Duke to receive 55% of the net present value (NPV) of the avoided costs for conservation and 75% of the NPV for demand
response. Approved for Progress Energy Carolinas (2009); Approved for Duke Energy (2010) Title 58. Public Utilities, Services And Carriers, Chapter 37. Energy Sup

ply And Efficiency; Dockets 2008-251-E (Progress Energy), 2007-358-E, & 2008- 251-E (Duke Energy)

**South Dakota** The South Dakota Commission approved performance incentives for OtterTail in 2008, and MidAmerican in 2010. OtterTail has a flat-rate bonus incentive, while MidAmerican has a straight return on the program’s budget. Montana-Dakota Utilities and Northwestern Energy also have performance incentives. Approved (2008) Docket Nos. EL-07-015, GE10-001, NG09-001, and GE09-001

**Texas** Texas state code specifies that a utility may be awarded a performance bonus (a share of the net benefits) for exceeding established demand reduction goals that do not exceed specified cost limits. Net benefits are the total avoided cost of the eligible programs administered by the utility minus program costs. The performance bonus is based on the utility’s energy efficiency achievements for the previous calendar year. If a utility exceeds 100% of its demand reduction goal, the bonus is equal to 1% of the net benefits for every 2% that the demand reduction goal has been exceeded, up to a maximum of 20% of the utility’s program costs. A utility that meets at least 120% of its demand reduction goal with at least 10% of its savings achieved through Hard-to-Reach programs receives an additional bonus of 10% of the bonus calculated. Approved (2008) PUC of Texas Substan

tial Rule §25.181(h); CenterPoint Energy Houston Electric 2008 Energy Plan & Report, Project No. 35440

**Vermont** The operator of Efficiency Vermont, VEIC, is eligible to receive a performance incentive for meeting or exceeding specific goals established in its contracts. There is also a holdback in the compensation received by VEIC, pending confirmation that contractual goals for savings and other performance indicators have been achieved. The initial contract (2000-2002) allowed incentives of up to 2% of the overall energy efficiency budget over the three-year contract period. Incentives increased to 3.5% of the EE budget for the 2006-2008 period. Approved (2000) Contract 0337956, Attachment C

**West Virginia** On April 1, 2013, AEP filed a proposal to the Public Service Commission seeking performance incentives for its energy efficiency programs. AEP’s proposal includes an incentive of 5% of the pre-tax net benefits of their programs, up to 12% of overall program costs. The PSC is still reviewing AEP’s case (13-0462). Pending Case No. 13-0462

### 23 State Performance Incentive Description Status Relevant Statute, Code or Order

**Wisconsin** As of 2008, Wisconsin Power & Light (Alliant Energy) may earn the same rate-of-return on its investments in energy efficiency made through its “shared savings” program for commercial and industrial customers as it earns on other capital investments.
Utilities may propose incentives as part of their rate cases, but there have been no proposals from other utilities under the most recent version of performance incentives. [Note: Wisconsin dropped performance incentives in the 1990s.] Approved (2008) Docket 6680-UR-114



### Note: Information on fixed-cost recovery mechanisms and electric efficiency performance incentives for electric utili

ties was compiled using the latest public data available as of December 2014. Readers are encouraged to verify the most recent developments by contacting the appropriate commission or regulatory agency. Other resources used in the prepara

tion of this report were ACEEE’s State Energy Efficiency Program Database, documents from EPA’s National Action Plan on Energy Efficiency, and resources from the Regulatory Assistance Project.

For inquiries, please contact Adam Cooper atacooper@edisonfoundation.net

. For further information, please visithttp://www.edisonfoundation.net

.

## About the Institute for Electric Innovation The Edison Foundation Institute for Electric Innovation (IEI) focuses on advancing the adoption and application of new technologies that will strengthen and transform the power grid. IEI’s members are the investor-owned electric utilities that represent about 70 percent of the U.S. electric power industry. The membership is committed to an affordable, reliable, secure, and clean energy future. IEI promotes the sharing of information, ideas, and experiences among regulators, policymakers, technology companies, thought leaders, and the electric power industry. IEI also identifies policies that support the business case for the adoption of cost-effective technologies. IEI is governed by a Management Committee of electric industry Chief Executive Officers. In addition, IEI has a Strategy Committee made up of senior electric industry executives and more than 30 smart grid technology company partners.

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tion, the Foundation works to encourage a greater understanding of the production, delivery, and use of electric power to foster economic progress; to ensure a safe and clean environment; and to improve the quality of life for all people. The Edison Foundation provides knowl

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## For more information contact: Adam Cooper Senior Manager, Research Institute for Electric Innovation 701 Pennsylvania Avenue, N.W. Washington, D.C. 20004-2696
202.508.5551 acooper@edisonfoundation.net