Utility Business Model
States that promote alternative business models for utilities through mechanisms such as decoupling attempt to disassociate a utility's revenues from sales, which makes the utility indifferent to maximizing sales. Although this does not necessarily make the utility more likely to promote efficiency programs, it removes the disincentive for them to do so. States can also offer shareholder incentives to utilities (and in some cases, non-utility organizations) for meeting specified program goals. These mechanisms have received a great deal of attention recently with a number of states enacting them in order to support increased energy efficiency initiatives and programs.Alabama Power Company and Alabama Gas Company recover their retail costs (including a reasonable return) through a formulary rate approach called Rate RSE (Rate Stabilization and Equalization). Operations under Rate RSE can produce either upward or downward revenue adjustments, depending on whether the return calculated thereunder falls below or above an authorized range.
In accordance with the Energy Independence and Security Act of 2007, the Alabama Public Service Commission (APSC) opened a docket to consider (among other things) proposed standards regarding: (i) the integration of energy efficiency measures into utility integrated resource planning (IRP); and (ii) rate design modifications to promote energy efficiency investments. (See Docket No. 31045). At the conclusion of that proceeding, the APSC found that Alabama Power and Alabama Gas already have established IRP programs that meet the goals of the former, and that they both offer APSC approved rates, programs, and initiatives that achieve the goals of the latter. Accordingly, the APCS found it unnecessary to adopt any additional policies.
Alabama Power and Alabama Gas Company may recover a reasonable rate of return on efficiency spending via a rate rider.
Last Updated: July 2017
There is currently no policy in place that decouples utility profits from sales.
There is currently no policy in place that rewards successful energy efficiency programs.
Last Updated: July 2017
On December 13, 2011, the ACC approved a full revenue decoupling mechanism for Southwest Gas as part of the utility's rate case (Docket No. G-01551A-10-0458).
On May 24, 2012, the ACC approved a lost revenue adjustment mechanism (LRAM) for the Arizona Public Service Company as part of the utility’s rate case (Docket No. E-01345A-11-0224). In June 2013, an LRAM was also approved for Tucson Electric Power Company (Docket No. E-01933A-12-0291). UniSource Energy Services also operates under an LRAM.
Arizona Public Service (APS) has a tiered shareholder performance incentive that is based on a percentage of the net benefits from energy savings and capped as a tiered percentage of program costs. The incentive is capped at $0.0125 per kWh saved (See ACC Decision 74406).
Tucson Electric Power (TEP) also has a performance incentive in place. The most recent incentive became effective July 2013 (See ACC Decision 73912). TEP receives a share (8%) of net benefits. The incentive is capped at $0.0125 per kWh saved.
Last reviewed: November 2024
In December 2010, the Arkansas PSC approved a joint electric and gas utility motion to allow the awarding of lost contributions to fixed costs that result from future utility energy efficiency programs. All investor-owned utilities were approved to recover lost revenues as part of the annual energy efficiency program tariff docket (See Order No. 14 Docket 08-137-U).
In 2007 rate cases, the Arkansas PSC approved a decoupling mechanism, a billing determinant adjustment (BDA) tariff that furthers its goal of promoting energy efficiency, for the three major natural gas distribution companies in the state. The purpose of the BDA tariff is to account for declines in non-gas revenues due to declining gas volumes caused by conservation and decreasing billing determinants. The tariff applies to the Residential and Small Commercial rate classes and was in effect for three evaluation periods (2008, 2009, and 2010). (See Docket No. 07-016-U for Arkansas Oklahoma Gas).
In December 2010 the PSC issued an order approving a general policy under which the Commission outlined steps to approve incentives to reward achievement in the delivery of essential energy conservation services by investor-owned utilities. (See Order No. 15 Docket 08-137-U). Incentives were approved for all three gas utilities in the state and the two largest electric utilities in 2012 and 2013.
Energy efficiency performance incentives are awarded annually for achievement ranging between 80% and 120% of the Commission-established performance goal. The performance incentive is 10% of portfolio total resource cost net benefits, limited to a percentage of program budgets ranging from 4% of program budgets to 8% of program budgets, based linearly on the degree of achievement.
Last Updated: July 2018
California initially implemented decoupling through the Supply Adjustment Mechanism (SAM) for gas utilities beginning in 1978 (Decision 88835). By 1982, similar mechanisms were in place for the three electric IOUs. As the gas industry restructured, gas utilities began to serve large customers under a straight fixed-variable rate design, which continues through today. The CPUC stopped the electric decoupling mechanisms in 1996 due to restructuring of the electric power industry.
In 2001, the Legislature passed Section 739.10, which required that the CPUC resume decoupling. Decoupling resumed for Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric beginning with the 2004 revenue requirement. Currently, the revenue decoupling program is combined with performance incentives for meeting or exceeding energy efficiency targets. Revenue requirements are adjusted for customer growth, productivity, weather, and inflation on an annual basis with rate cases every three or four years, varying by utility.
Decoupling mechanisms have been developed and applied in individual cases with the IOUs. All of the investor-owned electric and gas utilities have decoupling, which has been in place for many years and is an integral policy for California's "big, bold" energy efficiency initiative (CA 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).
The California Public Utilities Commission defined a new Energy Savings and Performance Incentive (ESPI) for investor-owned utilities in Rulemaking 12-01-005. Decision 13-09-023 (September 2013) allocates incentive earnings among four major categories: Energy Efficiency Resource Savings; Ex Ante Review Process Performance; Codes and Standards Advocacy Programs; and Non-Resource Program:
- Incentives for energy efficiency resource savings are capped at 9% of resource program expenditures.
- Incentives for successful implementation of ex ante "lock down" are based on performance scores and are paid as an award of up to 3% of resource program expenditures.
- Incentives are also provided for utility involvement in codes and standards programs in the form of a management fee equal to 12% of approved program expenditures.
- For non-resource programs, utilities may earn a management fee equal to 3% of non-resource program expenditures (exclusive of administrative costs).
D.13.09.023 directs Commission staff to identify deemed measures with sufficiently uncertain ex ante savings parameters such that the savings claim should be subject to ex post verification in order to be included in the incentive payment. For the purposes of the ESPI mechanism, "sufficiently uncertain" measures are defined as those measures for which the Commission believes the net lifetime savings of the current DEER or non-DEER savings estimate may be as much as 50% or more under- or over-estimated.
Last reviewed: November 2024
All investor-owned natural gas utilities in Colorado recover lost revenues through an Acknowledgement of Lost Revenues (ALR) mechanism. The gas DSM rules were proposed in Proceeding No. 07R-371G and adopted in Decision No. C08-0248, which was issued on March 7, 2008. The ALR is only calculated for first-year savings. Electric utilities do not recover lost revenues.
The 2009/10 Demand-Side Management (DSM) Plan was intended to remove disincentives to efficiency, offset revenue and earnings erosion, and reward utility performance, among other things, for the Public Service Company of Colorado. The PUC indicated that it is not appropriate and likely not feasible to define in a docket the lost margins resulting from DSM. Instead, it addressed the financial disincentives of DSM with a fixed payment of $2 million after taxes (approximately 3.2. million gross) for each year that 80% of the annual energy savings goal for an approved DSM plan is achieved, with the option that the offset could be adjusted downward in the case that the 80% target is not achieved. This amount is recovered over the 12-month period following the year in which the DSM plan is implemented. The PUC specifically notes that this “disincentive offset” should not be considered lost margin recovery but rather as an annual bonus for meeting approved DSM goals. Incentives are also included in the mechanism, and utilities achieving efficiency targets can earn a percentage of the net economic benefits generated by those savings. Combined total incentive payments are capped at 20% of PSCo’s annual DSM expenditures.
In 2018, the Commission ruled that, given the new 500 GWh energy savings goal, PSCo will begin to receive a performance incentive only when reaching 80% of the goal, or at 400 GWh (Decision No. C18-0417 Proceeding No. 17A-0462EG). There will be a disincentive offset of $3M that PSCo will earn in two installments; the first $1.5M will be given once PSCo reaches 400 GWh of savings (80% of goal), and the second $1.5M will be given when the company reaches 450 GWh of savings (90% of goal). The performance incentive for PSCo is 40% of incremental net benefits above 280 GWh up to 550 GWh upon achievement of at least 400 GWh. Total incentives are capped at $18M.
For natural gas utilities, the incentive bonus is capped at 25% of the expenditures or 20% of the net economic benefits of the DSM programs, whichever amount is lower.
Last reviewed: July 2019
Public Act 07-242, An Act Concerning Electricity and Energy Efficiency, required PURA to order the state’s electric and natural gas distribution companies to decouple distribution revenues from the volume of natural gas or electricity sales. In 2013, Public Act 13-298, An Act Concerning Implementation of Connecticut’s Comprehensive Energy Strategy and Various Revisions to the Energy Statutes, adopted the requirement (again) of decoupling for all electric distribution companies.
Currently, United Illuminating uses a full decoupling mechanism, adjusted annually (see Docket No. 08-07-04RE03 and 13-01-19). Public Act 13-298 approved lost-based revenue recovery via federally mandated congestion charges (FMCCs), absent decoupling for Eversource (f/k/a Connecticut Light & Power). In 2015, Eversource’s rate case was approved for full decoupling.
Connecticut’s natural gas companies also recover lost-based revenues. Connecticut Natural Gas has been decoupled since 2014, and in the next LDC rate case, Eversource (f/k/a Yankee Gas Services) will also file for decoupling. Southern Connecticut Gas currently recovers lost margins as a component of the Conservation Adjustment Mechanism (CAM) that is designed to recover distribution revenues lost due to energy efficiency program activities (avoided usage).
For managing Connecticut’s energy efficiency programs and budgets, the electric and natural gas distribution companies earn an annual performance management incentive (PMI) that is tied to program specific-oriented metrics, including but not limited to energy savings and net economic benefits. PMI earnings use a sliding scale-based on a percentage of utility spending (2 percent to 8 percent) corresponding with the level of performance (75 percent to 130 percent) dependent on if goals and/or targets are met or exceeded. For the 2022-2024 term, the Companies have a base target 5.0 percent PMI payout at 100% goal achievement for the 2022, 2023, and 2024 program years. Other changes to the 2022-2024 PMI model include incorporating benefits/net benefits from Residential and C&I Active Demand Response programs and including fossil benefits and net benefits (i.e., utilize the Modified Utility methodology versus the Utility Benefit methodology). In Connecticut, there are two types of metrics:
- Primary metrics. These are program specific-oriented metrics, including energy savings/benefits and net energy savings benefits (benefits minus costs). The benefits are achieved from program savings (lifetime energy savings) including electric (kWh), natural gas (ccf), and fossil fuel (gallons), as well as summer peak demand savings from both passive and active demand resources.
- Secondary metrics. These metrics are complementary metrics and target other areas such as increased energy savings from all fuel types (MMBtus), program participation, comprehensiveness, equity, and outreach to specific groups or types of customers, and program comprehensiveness. Secondary metrics can include: but are not limited to: (a) Number of single-family homes served that receive a specific add-on measure, and (b) Number of new construction C&I projects built a certain percentage above state building code.
Last reviewed: November 2024
The state evaluates the issue of decoupling on a utility-by-utility basis when it sets utility rates through rate case proceedings. In September 2009, the PSC entered Order 7641 (Docket No. 09-276T), examining a modified fixed variable rate design for Delmarva Power (electric and gas). The docket has been on hold since late 2011 because the conditions required to implement decoupling could not be met until Delmarva Power was able to implement energy efficiency programs that benefit its customers. In 2014, the state legislature passed SB 150, calling for the expansion of cost-effective electric and natural gas utility programs and allowing utilities to deliver these programs and recover costs through rates.
Delmarva Power and Light’s program plan filed with the PSC did not include provisions for a performance incentive. Delmarva proposed to recover the costs of the program, amortized over a five-year period, using the same rate of return as their supply-side capital investments.
Last reviewed: November 2024
In September 2009, Potomac Electric Power Company (PEPCO) received approval for its Bill Stabilization Adjustment (BSA) which would implement electric revenue decoupling. (Case No. 1053, Order No. 15556). Pepco's BSA was offered and approved by the Commission to further public policy goals of encouraging the development of energy efficiency. The BSA is intended to account for changes in usage due to variations in weather, customer response to generation price increases or energy efficiency programs. The BSA is applied on a monthly basis to the distribution charge of all customer classes except street lighting and telecommunications network customers. More info is available here.
In April 2016, Washington Gas filed a request for decoupling, but it was not accepted by the commission (Formal Case 1137, Order No. 19236).
The DC Council adopted the Clean and Affordable Energy Act (CAEA) of 2008 effective October 1, 2008 which authorizes the Energy Office to contract with a “Sustainable Energy Utility” (SEU) for the implementation of energy efficiency programs. Section 202 of the CAEA, codified at section 8-1774.02, specifies that the contract between the District Department of the Environment and the SEU “shall be performance based and shall provide financial incentives for the SEU to surpass the performance benchmarks set forth in the SEU contract. The SEU contract shall also provide financial penalties to be applied to the SEU if the SEU fails to meet the required performance benchmarks.” In April 2017, DCSEU moved to operating on a five-year contract, which allows for larger, longer projects, and higher savings targets over the five years.
In 2008, the District of Columbia enacted the Clean and Affordable Energy Act, which effectively eliminated the Reliable Energy Trust Fund and replaced it with a new fund, the Sustainable Energy Trust Fund. This fund is administered by the District Department of the Environment, and it funds DC's third-party "Sustainable Energy Utility" (DCSEU). Responsibility for the implementation of energy efficiency programs was transferred from PEPCO to DCSEU in 2011. In 2011, the District of Columbia awarded a performance-based contract to VEIC to operate the DCSEU under a one-year contract with additional option years. In 2016, the District solicited proposals to operate the DCSEU under a new five-year performance-based contract with an optional five-year extension. In 2017, the contract was awarded to VEIC, which designs and implements the DCSEU’s residential, commercial and institutional, and multifamily energy efficiency programs as well as some renewable energy programs. Under the contract awarded in 2017, the DCSEU’s energy savings goals are cumulative across the five-year contract period rather than on an annual basis. Benchmarks have minimum and maximum levels of achievement.
The FY2022-FY2026 contract period sets new performance incentives for reductions in energy consumption (on a total source MMBtu basis), increases in renewable energy generating capacity, improving EE and RE generating capacity of low-income housing and shelters, completing deep energy retrofits in commercial and multifamily residential buildings, and reducing greenhouse gas emissions.
Last reviewed: November 2024
Florida does not have decoupling or lost revenue adjustment mechanisms in place for electric or natural gas utilities. HB 7135 instructed the Public Service Commission to analyze utility revenue decoupling and provide a report and recommendations to the governor and the legislature in December 2008. In 2008, the FPSC decided that existing annual cost recovery clauses made it unnecessary to introduce decoupling, though gas utilities could still request decoupling in a rate case. In 2009 the FPSC concluded that utilities may request an increase in rates in order to maintain a reasonable rate of return when efficiency programs reduce revenues, but none have been authorized (See Final Order PSC-09-0855-FOF-EG).
Sections 366.82(8) and (9) of Florida Statute authorize the commission to provide financial rewards and penalties and to allow gas and electric investor-owned utility to earn an additional return on equity for exceeding energy efficiency and conservation goals. Specifically the FPSC may allow utilities to earn an additional return on equity of up to 50 basis points for exceeding 20% of their annual load-growth through energy efficiency measures. The FPSC may also assess penalties if utilities do not meet the goals. No utilities have yet requested the additional return.
Last reviewed: November 2024
Georgia Code (O.C.G.A. § 46-3A-9) authorizes electric utilities to recover costs and an “additional sum” for approved programs. In the 2013 IRP, the Commission approved an additional sum of 8.5% of actual net benefits of electricity savings for achieving 50% or more of kWh projected savings. If the additional sum exceeds program costs, the portion of the total that exceeds program cost is limited to 4% of actual net benefits.
Last reviewed: November 2024
In October 2008, an order was issued to investigate implementing a decoupling mechanism similar to the one used in California. In August 2010, the Hawaii PUC issued its final Decision and Order approving the implementation of the decoupling mechanism for the Hawaiian Electric Company (HECO). Utilities are required to report on their performance of commitments made in the energy agreement in their rate cases as the basis for review, modification, continuation, or possible termination of the decoupling mechanism (See HI Docket 2008-0274 Order dated Aug.31, 2010).
In July 2009 Hawaiian Electric Company (HECO) transferred administration of its energy efficiency programs to a third-party “Public Benefits Fee” administrator. The governor’s office claimed: “Moving energy efficiency programs to an independent third party will remove the perceived conflict between the electric utilities' desire to sell more electricity to increase profitability and the desire to implement energy efficiency programs that will decrease electricity sales.” The third-party contractor (Hawaii Energy) negotiated to run HECO's energy efficiency program is compensated by the Commission for satisfactory performance of its contract (See Hawaii Energy Executive Summary in Annual Report PY 2009).
The Gas Company (TGC) and Kauai Island Utility Cooperative (KIUC) are subject to the Renewable Portfolio Standard but are excluded from DSM utility incentives. TGC does not currently operate any DSM programs and KIUC has not requested incentives. The most recent bill establishing an Energy Efficiency Portfolio Standard (EEPS) allows the PUC to establish incentives and penalties based on performance in achieving the EEPS.
Last Updated: August 2018
Idaho Power's decoupling mechanism, called a Fixed-Cost Adjustment (FCA), was designed to provide symmetry (a surcharge or credit) when fixed cost recovery per customer varies above or below a commission-established base. The FCA was first implemented on a pilot basis for a three-year period beginning January 1, 2007 and running through December 31, 2009. The pilot was extended for two years after that and made permanent on January 31, 2013 (See Order No. 32731 in Case No. IPC-E-11-19). The FCA applies to all residential and small commercial customers. The FCA also incorporates a 3% cap on annual increases and carries over unrecovered deferred costs to subsequent years. Rate increases and credits resulting from the FCA are distributed to residential and small general service customer classes equally on an energy use basis. Avista requested and was granted a similar FCA mechanism for electric and natural gas beginning January 2016.
Idaho does not offer energy efficiency performance incentives to its investor-owned utilities.
Last reviewed: November 2024
In February 2008, North Shore Gas and Peoples Gas and Coke were both approved for four-year revenue-per-customer decoupling pilots. Monthly adjustments began in March 2008. To continue the program after four years, the utility was required to make a general rate filing in which the commission extends the program (cases 07-0241/07-0242 (consolidated) and 09-0166/09-0167 (consolidated)). In the 09-0166/09-0167 (consolidated) cases, the rider was approved on a permanent basis.
The Commission approved decoupling for Ameren for natural gas in December 2015 (Docket No. 15-0142).
The two largest electric utilities do not have an explicit decoupling rider for energy efficiency purposes. However, as part of the AMI installation process, these utilities are using formula rates that adjust every year based on actual costs and actual sales in the previous years. The formula rate is in effect until December 31, 2022 per 220 ILCS 5/16-108.5.
Illinois Public Act 99-0906 was passed in December 2016, including a mechanism for electric utility shareholder incentives for energy efficiency. The legislation provides either increased ROI or decreased ROI to electric utilities based on their performance relative to statutory goals. This goes into effect on January 1, 2018.
Last reviewed: November 2024
The Commission currently limits lost revenue recovery to: (1) four years or the life of the measure, whichever is less, or (2) until rates are implemented pursuant to a final order in the utility's next base rate case, whichever occurs earlier. They did this for Duke Energy Indiana (Cause No. 43955 DSM 3) Order March 9, 2016; SIGECO (Cause No 44645) Order March 23, 2016; NIPSCO Cause No. 44634 Final Order Dec. 30, 2015; Indiana Michigan Power Company Cause No. 43827 DSM 5 Order June 22, 2016; and Indianapolis Power and Light Co. Cause No. 44792 Dec. 28, 2016.
Performance incentives may be approved by the Commission in Indiana, but only one has been. According to the final order for IPL in Cause No. 44792, Dec. 28, 2016, page 26: "Ind. Code§ 8-1-8.5-90) states, in part, that the Commission may not, after December 31, 2014, require an electricity supplier to meet a goal or target established in the DSM order issued by the Commission on December 9, 2009. Utilities are now able to set their own, lower energy savings targets.... Beginning no later than calendar year 2017, utilities will be required to establish energy efficiency goals under Section 10. Section 10 authorizes a utility to recover reasonable financial incentives that encourage implementation of energy efficiency programs that are consistent with statutory resource planning requirements, or eliminate or offset regulatory or financial bias against either energy efficiency programs or in favor of supply-side resources. However, IPL has not submitted a plan under Section 10; therefore, it is not entitled to the reasonable financial incentives authorized by Section 10. Section 9(l) only states that, if the Commission determines the proposed energy efficiency programs are reasonable and cost effective, the electricity supplier may recover energy programs costs (which are defined by statute as program costs, lost revenues, and incentives approved by the Commission). In light of the reduced savings target, we see no reason to treat IPL's request differently from similar Section 9 proposals by Duke, I&M, and NIPSCO, in which the Commission denied requests for shared savings incentives. Accordingly, we do not approve any performance incentives for the 2017 plan year."
SIGECO has made a filing under IC 8-1-8.5-10 that was accepted by the Commission in Cause No. 44645 and approved performance incentives to be tied to both tiered levels of energy savings achieved and the net present value of the net benefits of the UCT test. See page 27 of Order dated March 23, 2016.
Last reviewed: November 2024
On December 18, 2006, the Iowa Utilities Board examined the possibility of decoupling profits from sales revenue for their natural gas utilities. The Board did not require utilities to decouple, but it concluded that individual utilities may apply for automatic adjustment mechanisms or other rate design changes on a case by case basis (Iowa Docket No. NOI-06-1).
There is currently no policy in place that rewards successful energy efficiency programs.
Last reviewed: November 2024
The Kansas Corporation Commission will consider proposals from electric and gas utilities that include decoupling on a case by case basis; however, no plans have been approved for any utilities (Docket 08-GIMX-441-GIV).
Kansas Statute 66-117 (e) allows a rate of return of 0.5% to 2% on top of the rate of return authorized for capital investments for energy efficiency investments. The Kansas Corporation Commission will consider proposals from electric and gas utilities that include shared savings performance incentives on a case by case basis (Docket 08-GIMX-441-GIV). On January 1, 2011, the KCC approved a lost-margin recovery (shared savings) mechanism for Westar Energy’s Simple Savings (Efficiency Kansas) program (Docket 10-WSEE-775-TAR).
Last reviewed: November 2024
Kentucky is generally supportive of lost revenue recovery. The state reiterated this in 2010 in House Bill 240, which reenacted preexisting legislation from 2008. Lost revenue recovery is determined on a case-by-case basis, but the largest investor-owned electric utilities in Kentucky have DSM proposals in place that include similar lost revenue recovery methods. For these utilities, lost revenues are calculated using the marginal rate, minus variable costs and multiplied by the estimated kWh savings from a DSM measure (KY Statute Ch. 278, Title 285; Dockets 2007-00477; 2008-00473).
Natural gas utilities use a similar system to the one described above.
Statute 278.285 allows utilities to recover the full costs of DSM programs via rates and allows incentives designed to provide financial rewards for utilities and encourage implementation of cost-effective DSM programs. Duke Energy, Kentucky Power (AEP), and Louisville Gas & Electric (LG&E) each have a shared savings mechanism in place. Duke and AEP can earn an incentive of up to 10% of net savings after program costs while LG&E can earn up to 15% of net resource savings.
Last Updated: December 2017
The Louisiana Public Service Commission authorized a Lost Contribution to Fixed Costs (LCFC) mechanism for efficiency programs in its “Quick Start” Energy Efficiency rules for electric and gas utilities (General Order Docket R-31106, September 20, 2013). The three investor-owned electric utilities (Cleco, Entergy Louisiana/Gulf States, and SWEPCO) began implementing energy efficiency programs, along with an LCFC mechanism, in November 2014. Gas utilities chose not to file efficiency programs.
In New Orleans, there is a rate rider that provides for recovery of lost contribution to fixed costs for the electric and gas utility, Entergy. The lost contribution estimate is the product of the adjusted gross margin per kWh and the total annual projected savings. There is currently no policy in place at the state level that decouples utility profits from sales.
Also in New Orleans, there is a rate rider that includes an incentive mechanism for the electric and gas utility, Entergy. To be eligible for an incentive the utility must achieve 75% or greater of its approved savings goal. The incentive is based on a sliding scale and is a percentage of the utilities approved return on equity. The incentive is capped at 125% of the annual projected savings goal.
The LPSC Quick Start Energy Efficiency rules do not authorize utility shareholder incentive mechanism for efficiency; however, it does list the topic for discussion during the Phase II Comprehensive program phase.
Last reviewed: November 2024
Efficiency programs across all utility territories in Maine are implemented by a single, third-party administrator called Efficiency Maine. Efficiency Maine is managed by a stakeholder board of trustees, with oversight from the MPUC. It is considered a quasi-state agency. There are statutory provisions allowing decoupling and incentives. 35-A MRSA section 3195, subsection 3195 (1) deals with rate-adjustment mechanisms and subsection 3195 (1) (A) authorizes the MPUC to adopt a decoupling mechanism. The state’s largest electric utility, serving roughly 80% of statewide load, proposed and was granted decoupling in its rate case in 2014 (Docket No. 2013-00168).
Last reviewed: November 2024
The Public Service Commission approved revenue-per-customer decoupling for the three investor-owned utilities in Maryland: PEPCO, Delmarva Power and Light, and Baltimore Gas & Electric. Delmarva and PEPCO file bill stabilization adjustments monthly. Natural gas decoupling has been in place for Washington Gas Light since 2005. (Sources: Delmarva Case Jacket 9093, Order 81518, July 2007; PEPCO Case Jacket 9092, Order 81517, July 2007; Washington Gas Light Case Jacket 8990, Order 80130, August 2005).
Section 7-211 of the Public Utilities Article of the Annotated Code of Maryland allows the Public Service Commission to approve financial incentive mechanisms for gas and electric companies, in appropriate circumstances, to promote energy efficiency and conservation programs. No incentives have been approved. Cost recovery through a monthly billing surcharge is amortized over multiple years and can include a return.
Last reviewed: November 2024
Massachusetts has implemented decoupling for all of its gas and electric utilities pursuant to DPU Docket 07-50-A (July 2008). Target revenues are determined on a utility-wide basis, and can be adjusted for inflation or capital spending requirements if necessary. The Massachusetts DPU has approved decoupling plans for all utilities. Each distribution company is required to update a decoupling mechanism with its next filed rate case.
Shareholder incentives are in place for electric and gas utilities. The shareholder incentive provides performance incentives for IOUs to earn a return (depending on PA performance against planned metrics) on the 3-year plan spending for meeting program goals. The incentive is based on a combination of elements including energy savings, benefit-cost analysis, and market transformation results. The shareholder incentive structure was amended by DPU Order 20-150-A to reflect that performance incentives should be in line with energy goals as they evolve with state law. The current performance incentive parameters may be found in the 2022-2024 term sheet.
The enabling statute calls for all cost-effective energy efficiency and demand reduction resources (ch. 25 section 21). DPU 21-120 to 21-129 adds an electrification component to the 2022-2024 EE performance incentive. It provides an additional incentive for utilities to electrify fossil fuel end uses in weatherized homes. In addition, the approved plans for 2022-2024 set performance incentives based on lifetime MMBTU savings which combines all end uses and, therefore, provides a stronger incentive to electrify than PI based on lifetime electric and gas savings individually. Because the statute requires demand reduction resources in the portfolio, they are implicitly incented in the standard PI for their benefits as calculated for the cost-effectiveness test.
Last reviewed: November 2024
With the passage of Act 342, electric utility providers serving less than 100,000 customers are now eligible to propose a decoupling mechanism for energy efficiency programs.
Previously, Act 295 had been the relevant decoupling legislation. Act 295 mandated that the Commission consider decoupling mechanisms proposed by the state's electric utilities. Consumers Energy and Detroit Edison had decoupling in place (U-15768 and U-15751), but Commission orders on electric utilities were overturned in court on basis of lack of statutory authority (See Michigan Court of Appeals Association of Businesses Advocating Tariff Equity v. Michigan Public Service Commission, April 10, 2012). In light of the Court’s determination, the Commission dismissed all pending cases involving electric revenue decoupling.
Act 295 also authorized natural gas decoupling, which has been implemented in a series of Commission orders. The Commission has approved natural gas decoupling for Michigan Consolidated Gas Company (Docket No. U-15985), Consumers Energy (Docket No. U-15986), and Michigan Gas Utilities (U-15990). Natural gas decoupling was not overturned in the 2012 court case above.
For the period 2017 through 2021, Act 342 allows for a provider to collect a financial performance incentive of up to 20% of program spending if that provider achieves 50% more than the mandated energy savings target. It is a sliding scale from 100% of target up to 150%, and the incentive level spreads from 15% to 20% of program spending.
The Commission approved performance incentives for DTE-Electric and DTE-Gas for program years 2009 through 2013 (U-16358, U-16359, U-16737, U-17282, U-17602, U-16289, U-16290, U-16751, U-17288, U-17608). The Commission has also approved performance incentives for Consumers Energy for program years 2009 through 2013 (U-16302, U-16303, U-16736, U-17281, U-17601). The Commission also approved a performance incentive for SEMCO Gas (U-17362) and Indiana Michigan Power Company (U-17353) for program years 2014 and 2015.
PA 295 (2008) contained two provisions whereby utilities could receive an economic incentive for implementing energy efficiency programs. First, they were allowed to request that energy efficiency program costs be capitalized and earn a normal rate of return. Second, they were allowed to request a performance incentive for shareholders if the utilities exceed the annual energy savings target. Performance incentives could not exceed 15% of the total cost of the energy efficiency programs nor 25% of net benefits. The Commission had approved performance incentives for DTE - Electric and Gas (U-17352, U-17358), and Consumers Energy (U-17351). The Commission also approved a performance incentive for SEMCO gas (U-17362). The Commission approved a performance incentive for Indiana Michigan Power Company (U-17353).
Last reviewed: November 2024
In 2007, the Minnesota legislature enacted Section 216B.2412, directing the Public Utilities Commission to allow one or more rate-regulated utilities to participate in a pilot program (of up to 3 years) to assess the merits of a rate-decoupling strategy. In June 2009, the PUC issued an Order adopting criteria and standards for pilot proposals for revenue decoupling (Docket No. E,G-999/CI-08-132, Issue date June 19, 2009). The Minnesota Commission has approved full revenue decoupling for three gas utilities, CenterPoint Energy, Minnesota Energy Resources Corp, and Great Plains Natural Gas (Docket Nos. Docket Nos. E008/GR-13-316; G007,G011/GR-10-977; and G004/GR-15-879). In addition, the Minnesota Commission approved full revenue decoupling for one electric utility, Xcel Energy (Docket No. E002/GR-13-868.)
Minnesota has had a shared benefit incentive in place since 1999. For gas and electric utilities, the percent of net benefits awarded increases as a utility achieves a higher level of energy savings measured as a percentage of retail sales. For gas utilities, the threshold is set at 0.7 percent of retail sales. For each energy savings increase of 0.1% of retail sales, net benefits awarded increase by 0.75% until reaching the net benefits cap of 10 percent at energy savings equal to 1.2 percent of retail sales. For electric utilities, the threshold is set at 1.0 percent of retail sales. For each energy savings increase of 0.1% of retail sales, net benefits awarded increase by 0.75% until reaching the net benefits cap of 10 percent at energy savings equal to 1.7 percent of retail sales. In addition, the incentive levels are capped at 30 percent of a utility’s Conservation Improvement Program (CIP) expenditures.
Gas utilities may exceed the 30% CIP Expenditures Cap, up to a maximum of 35%, if they meet or exceed energy savings equaling 1.2% of retail sales; electric utilities may exceed the 30% CIP Expenditures Cap, up to a maximum of 35%, if they meet or exceed energy savings equaling 2% of retail sales. (See Minn. Stat.§ 216B.241, subd. l(c) and Docket No. E,G-999/CI-08-133).
Last reviewed: November 2024
On November 22, 2019, the Mississippi Public Service Commission approved an Order to revise the then current Energy Efficiency Rule. Rule 29 has been revised to an Integrated Resource Planning and Reporting rule that incorporates Energy Efficiency. According to the new revised rule, lost contributions to fixed costs associated with energy efficiency programs are considered to be captured in a utility's annual formula rate plan. (See 2018-AD-064 Rule 29)
There is no policy to allow energy efficiency performance incentives (See 2018-AD-064 Rule 29).
Last reviewed: November 2024
Recovery of Lost Revenues: In 2011, the Missouri Public Service Commission promulgated rules that authorize utilities to file for recovery of lost revenues (See 4 CSR 240-3.163, 4 CSR 240-3.164, 4 CSR 240-20.093, and 4 CSR 240-20.094). In 2012, the Commission approved a demand-side investment mechanism that allows Ameren Missouri to collect $80 million in an annual revenue requirement (Case No. ER-2012-0166) for recovery of demand-side programs’ costs, recovery of fixed operating costs, and a future performance incentive award based on after-the-fact verified energy savings from the programs (See Case No. EO-2012-0142). KCP&L Greater Missouri Operations Company (GMO) has an investment mechanism that allows collection of an $18 million annual revenue requirement for recovery of demand-side programs’ costs, recovery of fixed operating costs, and a future performance incentive award based on verified energy savings. Lost revenues are recovered through a rider or tracker mechanism until the full amount, including carrying charges, is recovered.
The rule implementing SB 376 provides for more timely cost recovery of DSM program costs by allowing adjustments to the funds collected between rate cases. Prior to SB 376, implementation program costs were recovered over a 6-year period. The SB 376 rule allows a regulated electric utility to propose performance incentives that are based on net shared benefits from the DSM programs it implements. Any utility incentive component of a DSIM shall be based on the performance of demand-side programs approved by the commission in accordance with 4 CSR 240-20.094 and shall include a methodology for determining the utility’s portion of annual net shared benefits achieved and documented through EM&V reports for approved demand-side programs. Each utility incentive component of a DSIM shall define the relationship between the utility’s portion of annual net shared benefits achieved and documented through EM&V reports, annual energy savings achieved and documented through EM&V reports as a percentage of annual energy savings targets, and annual demand savings achieved and documented through EM&V reports as a percentage of annual demand savings targets. Utilities may also propose recovery of lost revenues as measured and verified through EM&V prior to recovery on a retrospective basis.
In early 2016, the Commission approved DSM programs and demand-side programs investment mechanisms (DSIM) for Ameren Missouri (Case No. EO-2015-0055), KCP&L (Case No. EO-2015-0240), and KCP&L Greater Missouri Operations Company (Case No. EO-2015-0241), which allow each utility to bill customers for estimated lost revenues due to the programs and to true-up the billed lost revenues as a result of energy savings determined through retrospective net-to-gross EM&V performed by each utility’s independent EM&V contractors and reviewed by the Commission’s EM&V auditor. Presently, there is no electric utility revenue decoupling in Missouri. Missouri Gas Energy has straight-fixed variable (SFV) rate design. Laclede Gas and Ameren Missouri Gas both have a weather-mitigated rate design that is similar to SFV in principle.
Performance Incentives: The approved DSM programs and DSIMs for Ameren Missouri (Case No. EO-2015-0055), KCP&L (Case No. EO-2015-0240), and KCP&L Greater Missouri Operations Company (Case No. EO-2015-0241) also allow each utility to receive an earning opportunity determined after the completion of the 3-year plan period and to recover any approved earnings opportunity over a two-year period. The earnings opportunity amount for each utility is based upon the achievement of each DSM program relative to established performance metrics for the DSM program, which metrics are most commonly 3-year cumulative annual energy targets and/or 3-year cumulative annual demand savings targets. Actual 3-year cumulative annual energy and/or demand savings for programs are determined through retrospective net-to-gross EM&V performed by each utility’s independent EM&V contractors and reviewed by the Commission’s EM&V auditor.
In October 2017, the Commission promulgated 4 CSR 240-20.092 Definitions for Demand-Side Programs and Demand-Side Programs Investment Mechanisms; revised 4 CSR 240-20.093 Demand-Side Programs Investment Mechanisms and 4 CSR 240-20.094 Demand-Side Programs; and rescinded 4 CSR 240-3.163 Electric Utility Demand-Side Programs Investment Mechanisms Filing and Submission Requirements (now incorporated in revised 4 CSR 240-20.093) and 4 CSR 240-3.164 Electric Utility Demand-Side Programs Filing and Submission Requirements (now incorporated in revised 4 CSR 240-20.094).
Last reviewed: November 2024
A lost revenue adjustment mechanism was previously used in Montana, however, the PSC denied recovery of lost revenues for NorthWestern Energy in Order No. 73571 in Docket No. D2014.6.53, effective December 1, 2015. MDU was denied recovery of lost revenues for its natural gas conservation program beginning in 2017 (Docket D2017.1.7). The PSC required NorthWestern to implement decoupling in 2010, however, the order was appealed in court and a settlement was reached in 2011. However, the decoupling approach proposed by NorthWestern was rejected by the PSC (see Docket No. 2009.9.129, Order No. 7046i).
A decoupling mechanism pilot, called a fixed-cost recovery mechanism ("FCRM"), was apporved for NorthWestern in its 2019 rate case, Docket D2018.2.12. The FCRM is set to begin July 1, 2020, however, NorthWestern has requested a delay, due to the Commission opening a docket to investigate any potential COVID-19 impacts on the FCRM pilot.
Montana statute allows the PSC to add 2% to the authorized rate of return for demand-side management investments (MT Code 69-3-712). This incentive has not yet been approved for any utility.
Last reviewed: November 2024
There is currently no policy in place that decouples utility profits from sales. (As utilities in the state of Nebraska are by statute 100% publicly owned, there are no profits from which to decouple the variable energy rate component.)
There is currently no policy in place that rewards successful energy efficiency programs.
Last reviewed: November 2024
In May 2011, the Public Utilities Commission of Nevada (PUCN) issued an order approving the first recovery of lost revenues from demand-side management (DSM) programs for NV Energy, parent company of Nevada Power and Sierra Pacific Power Companies. This was the first filing under new regulations that provide for the recovery of DSM expenses and lost revenues in an annual balancing account. The investigation into an alternative to the lost revenue mechanism was completed in 2015, and in Docket No. 14-10018, a new multiplier method was proposed by the electric utilities. Regulations approving the multiplier methodology have been drafted but have not yet been approved by the Commission.
In 2008, the Commission adopted temporary rules pursuant to a 2007 law allowing gas utilities to propose decoupling their profits from their sales in a general rate case filed within one year of the approval of their energy efficiency programs. The rules specify a revenue-per-customer system for determining utility revenues to recover fixed costs. The PUCN adjusts this revenue on a per-class basis (i.e., “residential”) (PUCN Docket No. 07-06046 and Nevada Admin. Code 704.953). Gas utilities in Nevada can choose to either implement decoupling or use a performance.
In 2009 the Nevada Legislature passed SB 358, which directed the Commission to remove the financial disincentives faced by the utilities, and in 2010, the PUCN approved a Lost Revenue Adjustment Mechanism for electric utilities. The partial decoupling mechanism allowed utilities to recover "lost revenues" based on estimated savings through a third party M&V contractor during annual DSM filings. In 2015, the PUCN completed an investigation into an alternative lost revenue mechanism, and in Docket No. 14-10018, a new multiplier method was proposed by the electric utilities. Regulations approving the multiplier method were adopted in 2016.
Last Updated: July 2018
Energy Efficiency Rates, Budgets, Goals: In August 2016, the New Hampshire Public Utilities Commission approved a settlement agreement establishing a statewide EERS (2018-2020) (ref DE 15-137, Order No 25,932). The EERS set a target of cumulative annual electric kWh savings by the end of the first triennium of 3.1% by 2020 (as a percentage of 2014 electric kWh sales); and 2.25% by 2020 (as a percentage of 2014 natural gas sales). For 2021, the utilities were approved on a preliminary basis to continue the same SBC rate and structure of the energy efficiency programs as 2020. HB549, approved February 2022, established the electric utility and gas utility system benefit charge (SBC) rate and local distribution adjustment clause (LDAC) rates to be used to establish the energy efficiency budgets starting in 2022, which in turn are used to establish the energy savings goals. With Order No. 26,621, in Docket DE 20-092, the NHPUC approved a plan with a savings goal of 1.62% from 2019 delivered electric sales (within annual savings of 0.84% and 0.78%) and 1.49% from 2019 delivered natural gas sales (within annual savings of 0.75%).
Performance Incentive (PI): The New Hampshire electric and natural gas utilities earn performance incentive (PI). The PI formula is the similar for electric and gas utilities comparing planned versus actual. The PI cap is set at 6.875%, with a target baseline of 5.5%. The metrics for the PI include an annual savings goal, lifetime savings goal, summer peak passive demand reduction, winter peak passive demand reduction, and net benefits goal for electric utilities, and an annual savings goal, lifetime savings goal, and net benefits goal for natural gas utilities.
Lost Base Revenue and Revenue Decoupling: The Commission approved the calculation and recovery of lost base revenue (LBR) staring in 2017, with the utilities to transition to a revenue decoupling mechanism in a future distribution rate case. The Commission has authorized revenue decoupling (in lieu of LBR) for all electric and gas utilities except for one, who is required to propose a decoupling mechanism in its next distribution rate case.
Last reviewed: November 2024
Under the next generation of EE programs launched in July 2021, utilities are able to earn incentives based on performance towards their utility-specific targets. The NJBPU as a state agency does not receive performance incentives for achieving energy savings targets. Performance incentives and penalties take the form of a return on equity (ROE) adjustment applied to EE and PDR program investment. An incentive is awarded if a utility achieves between 110% and 150% of its target. Achievement of between 90% and 110% of the target represents compliance. A penalty is assessed if performance of the target is between 50% and 90%, and a utility is deemed non-compliant if achieving 50% or less of its target.
The NJBPU currently permits utilities to collect lost revenues related to reduced sales resulting from energy efficiency programs. Beginning with the transition to the new EE framework adopted by the BPU in June 2020, as per the Clean Energy Act of 2018, each utility shall file to recover on a full and current basis through a surcharge all reasonable and prudent costs incurred as a result of EE and PDR programs, including but not limited to recovery of and on capital investment, and the revenue impact of sales losses resulting from implementation of the programs. Program costs associated with O&M are expensed and included in a utility's annual cost recovery petition, program investments are amortized over a 10-year period, there is no absolute cap on customer distribution rates or bills associated with EE and PDR investments, and carrying costs for program investments use the capital structure established in each utility's most recent base rate case. Utilities may either use a lost revenue adjustment mechanism (LRAM) or a Conservation Incentive Program (CIP), which are designed to be applicable to both gas and electric public utilities.
Last reviewed: June 2022
Currently no utility has a decoupling or lost revenue adjustment mechanism in New Mexico, however HB 291 (2019) specifically allows for adoption of a decoupling mechanism that ensures that the revenue per customer approved by the commission in a general rate case proceeding is recovered by the public utility without regard to the quantity of electricity actually sold by the public utility.
The Efficient Use of Energy Act and the Rule do allow a utility to propose a profit incentive mechanism that is based on satisfactory program performance and does not exceed the product of the approved annual program costs and its weighted average cost of capital. PNM, EPE, SPS, and NMGC all earn an incentive award.
Last reviewed: November 2024
Following an April 2007 order (Cases 03-E-0640 and 06-G-0746), electric and gas utilities must file proposals for true-up-based decoupling mechanisms in ongoing and new rate cases. All six major electric and all 10 major gas companies have revenue decoupling mechanisms in place.
In 2008, the Commission established incentives for electric utility energy efficiency programs under the Energy Efficiency Portfolio Standard (EEPS) proceeding. Over the 2009-2011 and the 2012-2015 incentive periods, a utility earned incentives for achievement of its energy savings targets, and also for the achievement of statewide goals in the latter period to encourage cooperation with NYSERDA.
In 2014, New York initiated a proceeding, Case 14-M-0101, "Reforming the Energy Vision," to examine the potential for major changes to the utility regulatory structure within the state. The 2014 REV proceeding, in Case 14-M-0101, which led to the filing of Energy Efficiency Transition Implementation Plans (ETIPs) beginning in 2016, did not include EEPS-like incentives. Rather, energy efficiency earning adjustment mechanisms (EAMs) are developed for each IOU separately during its rate case proceeding.
Beginning with Con Edison in 2016 (Case 16-E-0060), Earning adjustment mechanisms (EAMs) are being designed within a rate case to reward energy efficiency performance, environmentally beneficial electrification of buildings and transportation, and other policy objectives. These EAMs have been established on a company specific basis as they have been part of the negotiated outcomes of the rate case proceedings.
New York utilities are required to consider and incentivized to pursue Non-Wires Solutions and Non-Pipes Solutions, where utilities procure energy efficiency, distributed energy resources (DERs), and other non-traditional resources to defer or avoid conventional infrastructure investments. In New York, utilities have earned variations on a rate of return for total expenditures on Non-Wires and Non-Pipes Solutions as well "share-of-savings" incentive mechanisms for Non-Wires Solutions projects.
Last reviewed: May 2022
Rate-regulated utilities may seek to recover the costs for energy efficiency programs through a Demand-Side Management/Energy Efficiency rate rider. Statute also allows the Commission to approve incentives for public utilities adopting and implementing new programs.
Duke Energy Carolinas received approval of a cost recovery mechanism (Docket No. E-7, Sub 1032) in October 2013. The mechanism is a shared savings model providing recovery of program costs, lost revenues (up to 36 months), and a 11.5% portfolio performance incentive. Duke Energy Progress was granted a new recovery mechanism in January 2015 (Docket No. E-2, Sub 931 – Order dated January 20, 2015), also with a shared savings model for recovery of program costs, up to 36 months of net lost revenues, and a bonus incentive of 11.75% on a shared savings model. Dominion received approval of a revised cost recovery mechanism (May 7, 2015 in Docket No. E-22, Sub 464) that provides for program cost recovery, up to 36 months of net lost revenues, and a program performance incentive (8% for DSM programs and 13% for EE programs).
In the natural gas sector, Piedmont Natural Gas and Public Service Company of North Carolina both have revenue-per-customer decoupling with semi-annual adjustments. Public Service Company received approval for its program in October 2008. (See Piedmont Natural Gas: Docket Nos. G-9, Sub 499 (November 2005) and G-9, Sub 550 (November 2008); Public Service Company of North Carolina Docket No. G-5, Sub 495 (October 2008); Report of the North Carolina Utilities Commission to the Governor of North Carolina, Environmental Review Commission, and the Joint Legislative Utility Review Committee: Docket E-100, Sub 116 (September 2008)). Duke Energy Progress has an incentive mechanism in place. The Duke mechanism permits the utility to earn a percentage of avoided costs which are capped as a percentage of actual program costs. The cap ranges from 5-15%. The Duke mechanism allows the utility to earn 8-13% of the net present value of the net savings from DSM programs.
Last reviewed: November 2024
There is currently no policy in place that decouples utility profits from sales. Xcel Energy has a straight fixed variable approach in place.
Last reviewed: November 2024
Under HB 6 (2019), any cost recovery for compliance with the state's EERS is terminated upon utilities effectively reaching the 17.5% cumulative savings benchmark, a goal anticipated to be surpassed in 2020. Per HB 6, a February 2020 PUCO order calls for the winding down of programs starting in September 2020.
In the Public Utilities Commission of Ohio’s (PUCO) rules, the commission may provide for decoupling, and an electric distribution utility may submit an application for approval of a revenue decoupling mechanism to PUCO. Rather than true decoupling, the gas utilities have all been allowed to implement straight-fixed-variable rate designs. Rule: ORC §4928.143(B)(2)(h); Duke riders: Docket Nos. 06-0091-EL-UNC, 06-0092-EL-UNC, and 06-0093-GA-UNC.
In January 2015, Ohio Senate Bill 310 gave certain customers the ability to opt-out of energy efficiency programs entirely. HB 6 (2019) amended R.C. 4928.6610 expanding the opt-out to all mercantile customers as of January 1, 2020.
Last Updated: May 2020
Both Public Service Oklahoma (PSO) and Oklahoma Gas and Electric Company (OG&E) currently have lost revenue recovery mechanisms. Additional revenue recovery mechanisms will be determined on a case-by-case basis (Cause No. PUD 200700449, ID No. 3710105. April 8, 2008).
The Oklahoma gas utilities use a performance-based ratemaking (PBR) mechanism to review earnings annually. The PBR includes a bandwidth around allowed return, and revenues can be adjusted if return is outside of the bandwidth.
Both Public Service Oklahoma (PSO) and Oklahoma Gas and Electric Company (OG&E) have shared benefit incentive plans. The Demand Program rules for electric utilities base the incentive on the performance of utility programs. Utilities must achieve at least 80% of goals to gain an incentive; the incentive is adjusted based on performance to goal. Incentives are capped at 15% of total program costs.
Oklahoma Natural Gas and CenterPoint Oklahoma previously were allowed a shared benefit incentive plan for programs that pass the Total Resource Cost (TRC) Test. The companies could potentially collect 15% of the net benefits of such programs and 15% of the program costs for those programs that did not pass the TRC Test (See Cause No. PUD 201000143; Order 585366 and Cause No. PUD 201000148; Order 683869).
Last reviewed: September 2020
Since 2009, Portland General Electric has implemented revenue per customer decoupling (called Sales Normalization Adjustment) for residential, small business, and “other” customers. Lost revenue recovery is implemented for commercial and industrial consumers with loads less than 1 average megawatt. The program also has a 2% rate cap on the amount recoverable by PGE through fixed costs in usage-based rate adjustments (Portland General Electric (electric): Docket No. UE-197; Order Nos. 09-020, 09-176, 10-478 and 11-110).
Avista Natural Gas was approved for decoupling effective January 1, 2017. However, Energy Trust began running some programs in 2016 for transition purposes. Cascade Natural Gas was approved for margin-per-customer decoupling effective May 1, 2006. Northwest Natural Gas has been implementing use-per-customer decoupling since 2003. Both make a base rate decoupling adjustment to reflect changes in use per customer over the past year on a prospective basis in the following year’s rates.
Cascade Natural Gas Docket No. UG 167, Order No. 06-191, April 2006; Northwest Natural Gas Docket No. UG 163, Order No. 07-426 (extending through October 2012 the prior decoupling mechanism approved in Docket No. UG 152, Order No. 03-507); Portland General Electric; Docket No. UE-197; Order Nos. 09-020 and 09-176), Avista Natural Gas Docket No. UG 288,UM 1753, Order No. 01-109, March 2016
There is currently no policy in place that rewards successful energy efficiency programs as Energy Trust is an independent, non-profit, and overseen by the State.
Last reviewed: July 2019
There is currently no policy in place that rewards successful energy efficiency programs with performance incentives.
Please see the Alternative Ratemaking Final Policy Statement at Docket No. M-2015-2518883. It provides the opportunity for the PUC to consider EDC plan filings that would decouple profits from sales, and allow for alternative methods of cost-recovery including incentives based on program performance. No utilities have adopted revenue decoupling or other alternative ratemaking mechanisms under this rule.
Last reviewed: November 2024
Enacted in 2010, House Bill 8082 requires revenue decoupling for electric and natural gas utilities and requires utilities to submit proposals to implement these policies. In 2011, National Grid proposed a revenue decoupling mechanism that was approved by the Public Utilities Commission (Docket No. 4206).
Rhode Island has had a shareholder incentive for electric and gas since 2005 and 2007, respectively. The Narragansett Electric Company, d/b/a National Grid or NG, can earn incentives for both electric (kWh) and gas (MMBtu) savings. There is a target base incentive rate of 5% for both electric and gas in 2010 applied to the eligible spending budget for 2010. The threshold performance level for energy savings by sector is set at 75% of the annual energy and demand savings goal for the sector (Docket 4366). Further, in 2015, the Commission approved 30% of the target electric program incentive to be based on demand savings, while the remaining 70% will be based on energy savings (Docket 4527).
Last reviewed: July 2019
S.C. Code Ann. 58-37-20 authorizes the Public Service Commission to adopt procedures that encourage electrical utilities to invest in cost-effective energy efficient technologies and energy conservation programs. A mechanism allowing for the recovery of lost revenues was first authorized in 2008 for Duke Energy Progress. In 2010, South Carolina Electric & Gas Company (now Dominion Energy of South Carolina) proposed a lost revenue recovery mechanism that was approved (Docket No. 2009-261-E and Docket 200-251-E). The Commission has also approved a mechanism allowing Duke Energy Carolinas to adjust rates to recover lost revenue. Mechanisms for both Duke Energy Progress and SCE&G were reauthorized in 2013. Lost revenues are estimated prospectively and are trued-up annually based on actual penetration rates and energy savings data.
Duke Energy Progress, Duke Energy Carolinas, and Dominion Energy of South Carolina have shared savings incentives based on the net present value of each program using the Utility Cost Test (Docket No. 2009-261-E). Dominion Energy retains 9.9 percent of the savings its energy efficiency programs produce, while Duke Energy Carolinas and Duke Energy progress retain 11.5 percent and 11.75 percent, respectively, of the savings its EE programs generate.
The South Carolina General Assembly has not authorized revenue decoupling.
Duke Energy Progress and South Carolina Electric & Gas Company have shared savings incentives based on the net present value of each program using the Utility Cost Test (Docket No. 2009-261-E). The PSC approved Duke Energy’s Save-A-Watt program (See Dockets 2007-358-E and 2008-251-E).
Last Updated: November 2024
All investor-owned utilities in South Dakota recover lost revenues. In 2010, the South Dakota Public Utilities Commission authorized the first lost revenue adjustment mechanism for Montana-Dakota Utilities in docket NG09-001. Lost revenues are negotiated as a percentage of approved budget spend. Any over/under collection for the first year (including interest), plus forecasted DSM program costs and lost revenues for the second year, are added together to compute rates for the second year.
South Dakota has approved performance incentives through various mechanisms. In 2008, OtterTail Power received approval for its energy efficiency programs, with a flat-rate bonus if the utility met its efficiency goals. In 2009, the Commission approved a similar mechanism for MidAmerican Energy. In 2010, MidAmerican’s incentive was amended to a straight return based on a percentage of the program budget. Montana-Dakota Utilities, Northwestern Energy, Black Hills Power, Xcel Energy, and Otter Tail Power have similar mechanisms. The fixed percentage, as settled upon between the utility and the Commission, is intended to cover lost revenues due to EE programs.
Last Updated: November 2024
There is currently no policy in place that decouples electric utility profits from sales, but the Tennessee Valley Authority made a determination that efforts will be made to address the issue of lost contributions to fixed costs for distributors.
In 2010, the Tennessee Regulatory Authority (TRA) approved the Chattanooga Gas Co.'s request for an increased monthly charge for fixed costs to “more properly align the interest of ratepayers and utilities in better promoting energy efficiency.” The mechanism is referred to the Alignment and Usage Adjustment (AUA). The AUA applies to residential (R-1) and Small Commercial (C-1) classes. A revenue per customer was calculated for the aforementioned customer classes in docket 09-00183. Each year, the actual revenue per customer is compared to the benchmark revenue per customer. If the revenue per customer declines, then customers are surcharged to collect the difference during the subsequent year, and vice-versa. The AUA was approved on a three-year trial and was extended pending a full report on the mechanism. It remains in effect. There is, however, a 2% accrual on margin recoveries.
There is currently no policy in place that rewards successful energy efficiency programs. The Tennessee Valley Authority has made a determination that incentives are not appropriate for a public power company.
Last Updated: November 2024
Texas does not decouple utilities’ profits from their sales. In 2009, the state considered a bill on decoupling, but the legislation did not pass (SB 1972).
All investor-owned utilities have a shared benefit incentive in place. When a utility exceeds its demand reduction goal within the prescribed cost limit, it is awarded a performance bonus. The performance bonus is based on the utility’s energy efficiency achievements for programs implemented in the previous year (PUCT Substantive Rule §25.181).
A utility that exceeds 100% of its demand and energy reduction goals shall receive a bonus equal to 1% of the net benefits for every 2% that the demand reduction goal has been exceeded, with a maximum of 10% of the utility’s total net benefits.
Last Updated: July 2017
No decoupling mechanism is in place for electric utilities.
In 2003, the Utah Public Service Commission approved Rocky Mountain Power's Electric Service Schedule 193, Demand Side Management Cost Adjustment. In 2016, Utah passed Senate Bill 115 - Sustainable Transportation and Energy Plan Act (See: https://le.utah.gov/~2016/bills/static/SB0115.html). The bill requires the PSC to authorize a large-scale electric utility that is allowed to charge a customer for demand side management under Subsection (2)(a) to:
(i) if requested by the large-scale electric utility, capitalize the annual costs incurred for demand side management provided in Subsection (2)(a);
(ii) amortize the annual cost for demand side management over a period of 10 years;
(iii) apply a carrying charge to the unamortized balance that is equal to the large-scale electric utility's pretax weighted average cost of capital approved by the commission in the large-scale electric utility's most recent general rate proceeding; and
(iv) recover the amortization cost described in Subsection (2)(b)(ii) and the carrying charge described in Subsection (2)(b)(iii) in customer rates.
Schedule 193 is a balancing account mechanism where revenues to fund the above programs are collected outside of general rate case proceedings. RMP's Electric Service Schedule 194, Sustainable Transportation and Energy Plan (STEP) Cost Adjustment Pilot Program, is a balancing account mechanism where revenues to fund the programs are collected outside of a general rate case. Schedules 193 and 194 are the funding sources for cost effective energy efficiency/load management programs and STEP programs approved by the PSC and managed by PacifiCorp. Charges for these programs appear on customer bills as a line item labeled Customer Energy Services and Step.
On October 5, 2006, Questar Gas, now Dominion Energy Utah, was approved to implement a Conservation Enabling Tariff (CET) and Demand-Side Management (DSM) Pilot Program. The CET allows Distribution Non-Gas (DNG) revenues received by Dominion to be based on the number of customers rather than customers’ gas usage. This is considered to be a form of decoupling. On June 24, 2009, the Pilot Program was extended to operate until December 31, 2010 (PSC Docket No. 05-057-T01, October 2006). Dominion's CET decoupling mechanism was changed from a pilot program to ongoing in 2010 (See Order June 3, 2010, changing the status of the CET from a pilot to permanent).
2009 HJR 9 expresses support for regulatory mechanisms to help remove utility disincentives and create incentives to increase efficiency and conservation so long as these mechanisms are found to be in the public interest.
Last reviewed: June 2024
The majority of the state programs are operated by Vermont Energy Investment Corporation (VEIC). VEIC is eligible to receive a performance incentive for meeting or exceeding performance goals established for three-year performance cycles. Vermont statute (30 VSA Sec. 218c) directs all electric and natural gas utilities to prepare and implement least cost integrated plans—plans "for meeting the public's need for energy services, after safety concerns are addressed, at the lowest present value life cycle cost, including environmental and economic costs, through a strategy combining investments and expenditures on energy supply, transmission and distribution capacity, transmission and distribution efficiency, and comprehensive energy efficiency programs." In addition, Vermont has a well-established regulatory process to factor the Energy Efficiency Utility's energy savings into utility companies' load forecasts. Vermont law requires EEU budgets to be set at a level that would realize "all reasonably available, cost-effective energy efficiency."
The state's two IOUs (electric and natural gas) are decoupled through an Alternative Regulation Structure. Green Mountain Power is decoupled through a power cost adjustment and an earnings sharing mechanism. Vermont Gas is also decoupled through an earnings sharing mechanism.
Electric cooperatives and municipal utilities are not decoupled.
Last reviewed: November 2024
Virginia’s 2020 Clean Economy Act allows the Commission to award performance incentives for utilities that achieve energy savings goals under § 56-596.2. This incentive is equal to at least program operating expenses plus a general return on equity, with an additional 20 basis points for each incremental 0.1% annual savings achieved beyond established requirements, up to more than 10% of the utility’s total energy efficiency program spending.
Virginia does not have incentives in place for natural gas.
Virginia allows natural gas utilities, but not electric utilities, to decouple profits from their sales.
In December 2008, Virginia Gas received approval to implement a three-year conservation and ratemaking efficiency plan. The plan has two main components: an Energy Conservation Plan (ECP) to promote conservation and efficiency and a Revenue Normalization Adjustment, Rider D ("RNA Rider" or "Rider"), which is a natural gas decoupling mechanism that provides for a sales adjustment to customers’ monthly bills. The ECP and RNA Rider became effective on January 1, 2009 (Docket No. PUE-2008-00060; December 23, 2008).
Virginia Code Section 56-585.1 provides for the recovery of revenue reductions related to energy efficiency programs. Dominion Virginia Power applied for recovery of lost revenues in a regular rate case as part of its application to continue its DSM riders. The Commission denied Dominion’s lost revenue recovery request because it determined that the company did not meet its “burden to establish that its proposed revenue reductions ‘occur[red] due to measured and verified decreased consumption of electricity caused by energy efficiency programs approved by the Commission…’” (emphasis in order). The Commission held that Dominion failed to provide “sufficient evidence for the Commission to measure and to verify that a specific amount of decreased consumption of electricity was directly caused by the CFL program.”
Last Updated: February 2021
The proposed full decoupling mechanism in Avista's 2014 general rate case (Dockets UE-140188 and UG-140189) was approved by the Commission in November 2014. As part of decoupling, Avista committed to increasing acquisition of electric conservation savings by 5% above its Energy Independence Act (EIA) biennial conservation targets while the decoupling mechanism is in effect.
Similarly, Puget Sound Energy's full decoupling mechanism went into effect July 2014, accompanied with the commitment to increase the acquisition of electric conservation savings by 5% above its EIA biennial conservation target and increase the funding available for low-income conservation. Additionally, through its decoupling petition, PSE committed to pursuing natural gas market transformation, which led to the NEEA natural gas market transformation pilot.
Pacific Power and Light's decoupling mechanism went into effect September 2016 (Docket UE-152253). As part of decoupling, all electric investor owned utilities in Washington have now been committed to increasing acquisition of electric conservation savings by 5% above the Energy Independence Act (EIA) biennial conservation targets while the decoupling mechanism is in effect.
Consumer-owned utilities, which serve more than half the state's electric load, are not subject to state regulation of retail rates and may adjust rates as they deem necessary, including to adjust for the effect of energy efficiency programs on retail revenue. No specific decoupling mechanism is required to achieve this outcome.
Electric investor-owned utilities may propose “positive incentives for an investor-owned utility to exceed the [biennial conservation] targets,” as allowed by RCW 19.285.060(4). No incentive mechanism is currently in place or proposed, however. Utilities can also be penalized if they fail to meet energy savings goals (RCW 19.285.060).
Last reviewed: July 2019
In Case 14-0345 (2014), if Appalachian Power expends funds of their own on EE/DR activities, such funds shall be treated as an investment and deferred as a regulatory asset. Appalachian Power is allowed to earn a return on such investment at the weighted average cost of capital ("WACC") plus fifty (50) basis points. There is currently no method for utilities to earn a higher rate of return based on performance of EE/DR programs.
Last Updated: November 2024
Wisconsin Electric Power Company submitted a proposed Gas Cost Recovery Mechanism. Approval was granted June 2011 (Docket No. 6630-GF-112).
Utilities can propose incentives as part of their rate cases, but there have been no such proposals from other utilities recently. Wisconsin did have performance incentives in place in the early to mid-90s, but dropped them as the state began investigating restructuring and deregulation.
The 2023-2026 contract between the Statewide Energy Efficiency and Renewables Administration (SEERA) and Aptim Government Solutions, LLC, includes a performance bonus mechanism for achievement in customer satisfaction, rural incentive spending targets, increased applications received from income-qualified customers, spending equity across participating utilities, and energy savings goals.
In September 2021, the Commission ordered an initial stakeholder workshop to facilitate further understanding and engagement on performance-based regulation and specificed the workshop address regulatory options related to customer affordability. The Commission held several stakeholder workshops to investigate goals, outcomes, and metrics associated with performance-based regulation, with high attendance at sessions that explored affordability and energy efficiency. Commission staff are taking information from these workshops and other investigations into energy burden, demand response, and reliability and additional work on the investigation into performance-based regulation is ongoing.
Last reviewed: June 2024
A three-year pilot decoupling program was approved for Questar Gas Company in June 2009 for its General Service class of customers. The pilot began July 1, 2009, and remains in effect. It is adjusted annually (Docket No. 30010-94-GR-8, May 2009).
A load management tracking adjustment mechanism is in place for Montana-Dakota Utilities Company to track and recover lost revenues associated with implementation of load management programs (Docket No. 20004-65-ET-06. Filed on August 31, 2006).
There is currently no policy in place that rewards successful energy efficiency programs.
Last Updated: July 2016