State and Local Policy Database

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) though 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. Since the formula rate approach provides for an annual calculation (and potential adjustment) that captures ongoing changes in both costs and revenues, the formula rate operates as a decoupling and lost revenue adjustment mechanism.

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, and 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).

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 Updated: July 2017

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 are 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 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 2017

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 IOU utilities. All of the investor-owned electric and gas utilities have decoupling.  It has been in place for many years in California 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 paid as an award of up to 3% of resource program expenditures. Utilities are also incentivized for their involvement in codes and standards programs, and may earn 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 oprder to be included in the incentive payment.  For the purposes of the Energy Savings and Performance Incentive (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 Updated: June 2017

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. 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 is an annual bonus for meeting approved DSM goals. The $2 million disincentive offset can be adjusted downward in future years if the 80% target is not met although it was reported that the 80% target is so easily achieved as to make the payment almost automatic upon DSM program implementation. 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 2011, the Colorado Public Utilities Commission issued Decision No. C11-0442 into Docket No. 10A-554EG to change some aspects of the incentives package for PSCo. The Commission agreed to increase the pre-tax disincentive offset from $3.2 million to $5 million if the utility meets or exceeds 100% of its electric energy savings goals. PSCo will continue to receive a pre-tax disincentive offset of $3.2 million for performance relative to its electric energy savings goals in the range from 80-99%.

The 2009/10 Demand Side Management (DSM) Plan, approved in 2008, included a three-part incentive package that included a $2 million “disincentive offset” for each year that Public Service Colorado implement an approved DSM plan, a performance incentive and cost recovery via a rider on a prospective basis. A similar three-part package was approved for Black Hills. In each case the performance incentives are available for achieving efficiency targets. The incentive (including the disincentive offset) was capped at 20% of PSCo’s annual DSM expenditures. In 2011, the performance incentive was modified, with utilities recieving a percentage of net economic benefits on a sliding scale based on achievement of savings goals. In 2014, these PSCo incentives were again modified. Under current rules, PSCo recieves a flat 5% of net economic benefits once 100% of savings goals are achieved (See Proceeding No. 13A-0686EG Decision C14-0731).

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 Updated: July 2017

Connecticut's 2007 Electricity and Energy Efficiency Act (CT Public Act No. 07-242) requires the Department of Public Utility Control 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  was adopted again requiring 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). In 2014, legislation (13-298) approved Lost Based Revenue recovery via Federally Mandated Congestion Charges (FMCC's), absent decoupling for Connecticut Light & Power. In 2015 CL&P'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. In the next LDC rate case, Yankee Gas Services will also file for full decoupling. The Southern Connecticut Gas Company (SCG) currently recovers lost margin as a component of a Conservation Adjustment Mechanism (CAM) that is designed to recover distribution revenues lost due to conservation program activities (avoided usage). 

Both electric and natural gas utilities are also able to earn performance incentives for energy efficiency offerings. During annual hearings, the Energy Efficiency Board (EEB) reviews the past year’s results relative to the established goals and determines a performance incentive for the distribution utilities for achieving or exceeding the goals. The incentive, referred to as a “management fee,” can be from 2-8% of the program costs before taxes. The threshold for earning the minimum incentive (2%) is 77.5% in 2016-17, rising to 75% in 2018. Program costs are recovered through rates.

Anticipated incentives are built into the annual budgets.  Over the course of several dockets, the Public Utilities Regulatory Authority has affirmed the value of the incentive. The expenditures used to calculate the incentive may include administrative and overhead costs, but not EEB costs and incentive costs.

Currently, United Illuminating uses a full decoupling mechanism, adjusted annually (See Docket Nos. 08-07-04 and 13-01-19).  Connecticut Natural Gas utilizes annual decoupling excluding billed revenues collected through the Transportation Service Charge (TSC), Distribution Integrity Management Program (DIMP) and the System Expansion Rate (SER) rate mechanisms (See Docket No. 13-06-08). The Southern Connecticut Gas Company (SCG) currently recovers lost margin as a component of a Conservation Adjustment Mechanism (CAM) that is designed to recover distribution revenues lost due to conservation program activities (avoided usage). SCG establishes a baseline sales forecast in its respective rate case proceedings. The lost sales component of the CAM allows SCG to recover the value of the distribution revenues associated with conserved sales units that result from conservation installations starting from the implementation date of new rates (the beginning of the rate year).  This cumulative calculation keeps SCG whole until a new baseline forecast is established in its next rate case proceeding.

In 2014, CT Legislation (13-298) had approved Lost Based Revenue recovery via Federally Mandated Congestion Charges (FMCC's), absent decoupling for CL&P. In 2015 CL&P's Rate Case was approved for full decoupling. YGS had already been receiving Lost Based Revenue Recovery via a CAM since 1995. However, in the next LDC rate case, YGS will file for full decoupling.

Last Updated: June 2017

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 (electric and gas). The docket has been on hold since late 2011 because the conditions required to implemented decoupling had not been met, and could not be met until Delmarva was able to implement efficiency programs that benefit its customers.

In 2014, the state legislature passed SB 150 with an amendment calling for expansion of cost-effective electric and natural gas utility programs, and allowing utilities to deliver these programs and recover costs through rates.

Performance incentives for utilities are currently under consideration by the Delaware Energy Efficiency Advisory Council.

Last Updated: July 2017

In September 2009, Potomac Electric Power Company (PEPCO) received approval for its Bill Stabilization Adjustment which would implement electric revenue decoupling. (Case No. 1053, Order No. 15556).

In April 2016, Washington Gas filed a request for decoupling in Formal Case 1137, and the proceeding is ongoing.

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.”

Last Updated: June 2017

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 percent 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 Updated: July 2017

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.

In the 2010 IRP, the Commission approved seven energy efficiency programs including five residential and two commercial programs. Georgia Power currently has 12 certified energy efficiency programs. 

Last Updated: July 2017

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) companies. 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) contracted 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: July 2017

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 of 2016.

Idaho does not offer energy efficiency performance incentives to its investor owned utilities.

Last Updated: July 2017

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 EE 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 Updated: July 2017

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, 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 Commission 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 Updated: July 2017

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 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 Updated: July 2017

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 Updated: July 2017

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: June 2016

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 Updated: September 2016

Efficiency programs in Maine are implemented by an independent trust - 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 Updated: July 2016


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 Updated: July 2017

Massachusetts is currently implementing 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 National Grid Electric Company (DPU 09-39), National Grid Gas Company (DPU 10-55), Bay State Gas Company (DPU 09-30) and Western Massachusetts Electric Company (DPU 10-70). Each distribution company is required to institute 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 most recently amended by DPU Order 11-120-A.

Last Updated: June 2016

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.

The Commission has 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 progam years 2014 and 2015.                                                                                                                                                                                                        

PA 295 (2008) contains two provisions whereby utilities can receive an economic incentive for implementing energy efficiency programs. First, they are allowed to request that energy efficiency program costs be capitalized and earn a normal rate of return. Second, they are allowed to request a performance incentive for shareholders if the utilities exceed the annual energy savings target. Performance incentives cannot exceed 15% of the total cost of the energy efficiency programs, or 25% of net benefits.The Commission has approved new 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 Updated: July 2016

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-decouplingstrategy. Two utilities, CenterPoint Energy and Minnesota Energy Resources Corp, have decoupling for natural gas customers (Docket No. G-008/GR-08-1075, G007,G011/GR-10-977).  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). 

Minnesota has had a shared benefit incentive in place since 1999. The incentive increases as the percentage of savings of retail sales increases. There is a cap of 20% of net benefits on the amount of incentive that may be earned. The incentive is set such that at savings of 1.5% of retail sales, electric utilities will earn an incentive of $0.07 per kWh saved and gas utilities will earn and incentive of $9.00 per thousand cubic feet saved. The percentage of net benefits to be awarded to each utility at different energy savings levels will be set at the beginning of each year. (See Minn. Stat.§ 216B.241, subd. l(c) and Docket No. E,G-999/CI-08-133).

The PUC adopted an updated DSM benefit incentive mechanism for 2017-2019 with the following provisions: For electric utilities, the threshold is set for one 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 at energy savings achievements equal to 1.7 %. At savings of 1.7% and higher, the incentive provided equals the net benefit cap times the net benefits.

For gas, the threshold is set at 0.7% of retail sales. For each energy savings increase of 0.1 percent of retail sales, net benefits awarded increase 0.75% until reaching the established cap at energy savings achievements equal to 1.2%. At 1.2% savings and higher, incentives provided are equal to the net benfit cap times the net benefits.

Net benefit caps are set at 13.5% for 2017, 12.0% in 2018, and 10.0% in 2019.

Last Updated: July 2016

In July 2013, the Mississippi Public Service Commission issued an order that defines energy efficiency program costs as the incremental program costs that are not already included in the then-current utility rates and the lost contribution to fixed costs associated with approved energy efficiency programs (See Docket No. 2010-AD-2). Mississippi currently allows utilities to recover lost contribution to fixed costs in their energy efficiency cost recovery riders along with direct program costs. Cost recovery mechanisms were adopted in September 2014. 

There is currently no policy in place that rewards successful energy efficiency programs, however a collaborative process has led to a draft of “guiding principles” for an efficiency rule which call for efficiency incentives. In July 2013, the Mississippi Public Service Commission issued an order allowing utilities 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 (See 2010-AD-2 Rule 29).

Last Updated: July 2017

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 which 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. Currently costs are recovered over a 6 or 10 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 Demand- Side Programs 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 restrospective 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.

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.

Last Updated: July 2016

In the past, NorthWestern Energy was granted approval to recover lost revenue in 2004 and in 2008 by the PSC.  However, more recently on October 15, 2015, the Montana PSC issued Order No. 7375a in Docket No. D2014.6.53 that denies NorthWestern Energy from recovering any lost revenues (LRAM) through electric and gas supply rates, effective December 1, 2015.

A 2010 Commission Order required NorthWestern to implement decoupling. The Order was appealed in court and a settlement was reached in 2011, however the decoupling approach proposed by NorthWestern was rejected by the Commission. (Docket No. D2009.9.129 Order No. 7046i)

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 Updated: September 2016

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 Updated: July 2017

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 methodology were accepted by the Commission on a temporary basis, giving the new mechanism an implementation date of October 2015.

Last Updated: September 2016

The New Hampshire PUC issued an order in January 2009 allowing electric and natural gas utilities to propose rate design mechanisms to promote energy efficiency in future rate cases on a case-by-case basis. The Commission listed three primary options: (1) performance incentives, (2) rate design (decoupling), and (3) reconciling rate adjustment mechanisms (either partial or full).

As part of an August 2016 Settlement Agreement, it was recommended the Commission implement a lost revenue adjustment mechanism (LRAM) to take effect January 1, 2017. The LRAM will be calculated by dividing the projected cumulative lost distribution revenue associated with energy efficiency savings for a given period by the projected billed consumption for the period in which they would be recovered. In each calendar year, for each utility, the savings for which lost revenue may be recovered will be capped at 110% of planned savings. Settling Parties agreed that the LRAM for each utility will cease when a new decoupling mechanism, or other mechanism as an alternative to the LRAM, is implemented.

The Settlement Agreement also recommended, and the Commission approved, performance incentive levels going forward will be identical for electric and gas utilities. The maximum was reduced from 10% to 6.875%, with a target of 5.5% upon implementation of the LRAM in 2017. The cap and target shall remain at 6.875% and 5.5%, respectively through at least the first triennium of the EERS.

Last Updated: July 2017

On October 12, 2006, the New Jersey Board of Public Utilities (BPU) approved requests by New Jersey Natural Gas Co. and South Jersey Gas Co. to replace their existing weather normalization clauses (WNC) with a conservation incentive program (CIP) that would capture gross margin variations related to both weather and customer usage. (Weather normalization clauses mitigate the financial effects of weather on utilities and their customers.) The three-year pilot programs, were extended through 2016 in a later Order (See BPU Docket Nos. GR05121019 and GR05121020). The Board does not permit utilities to collect lost revenues.

In New Jersey, traditionally, there were third party “Market Managers” selected by the NJ Office of Clean Energy (OCE) to run the energy efficiency programs in New Jersey. These Market Managers were eligible to receive a performance incentive. However in 2011 the OCE requested that the Market Manager significantly reduce their budgets and eliminate their performance incentive (Docket Nos. Eo07030203 and Eo10110865). The Board is currently developing new performance incentives.

Last Updated: August 2016

Currently no utility has a decoupling  or lost revenue adjustment mechanism in New Mexico.  In Case No. 15-00261-UT (for higher retail electric rates), PNM proposed a decoupling mechanism, which the Hearing Examiner recommended rejecting in the Recommended Decision issued in August 2016.  The Commission has not issued a final order.

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, and SPS all earn an incentive award.  NM Gas proposed an incentive award in its Plan Year 2017 program for the first time.

El Paso Electric's 2016 profit incentive was decided in a stipulated agreement in Case No. 13-00176-UT and was set at 7.0% of a 2016 budget of approximately $5.8 million.  Southwestern Public Service's 2016 profit incentive was decided in Case No. 15-00119-UIt earns a base level incentive of 6.80% on a budget of approximately $11.5 million, based on a minimum cumulative savings threshold.  This amount can be adjusted downward if there is a shortfall in low income program spending in program year 2016.  Each GWh of additional savings above 31.805 net customer GWh earns an additional 0.1% in profit incentive, up to a maximum of 7.11%.  Finally, Public Service Company of New Mexico's 2016 profit incentive was also decided in a stipulated agreement in Case No. 14-00310-UT and is based on a linear progression of cumulative savings towards the 2020 goal.  The 2016 profit incentive is conditional on achieving energy savings of six percent of 2005 retail sales and is approximately 7.10% of program costs.

Plan Year 2017 energy efficiency cases before the Commission are:

  • PNM, Case No. 16-00096-UT
  • SPS, Case No. 16-00110-UT
  • EPE, Case No. 16-00185-UT
  • New Mexico Gas, Case No. 16-00100-UT
  • Zia Natural Gas, Case No. 16-00021-UT
  • Raton Natural Gas, Case No. 15-00247-UT (the original application for Plan Year 2016 was rejected by the Commission in July 2016, so RNG is in the process of proposing a new EE plan that will cover the remainder of 2016 and PY 2017).

Last Updated: August 2016

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 EEPS proceeding. Energy savings targets for initial program years 2009 through 2011 were combined to create a single target as of December 31, 2011; Beginning in 2012, savings targets will be annual. For the 2009 through 2011 incentive period, a utility earns incentives or incurs negative adjustments for its electric or gas EEPS portfolio based upon the extent to which it achieved its energy savings targets during the years 2009 through 2011. Maximum potential incentives/negative adjustments for each utility are calculated by multiplying $38.85/MWh for electric savings and $3.00/Dth for gas savings times the utility’s cumulative electric and gas energy savings targets for each portfolio. If a utility achieves over 80% of a portfolio’s energy savings target, it earns an incentive scaled linearly from zero percent of the available incentive at an 80% achievement level up to 100% at a 100% achievement level. Portfolio performance of 70-80% neither earns an incentive nor incurs a negative adjustment. Negative adjustments are calculated in a symmetrical manner to the incentives calculation with the full negative adjustment imposed at the 50% achievement level and decreasing linearly to zero percent at the 70% level.

In the 2012 through 2015 incentive period, the Commission established incentive pools totaling $36 million for electric utilities and $14 million for gas utilities, totaled over a four-year incentive period. The incentive program provides a two tier incentive. Utilities will be eligible for incentives not only for achievement of their own targets, but also for the achievement of statewide goals. This is intended to encourage utilities to act in cooperation with NYSERDA, which administers programs in all utility territories to enhance achievement of its targets as well. The amount for which each utility is eligible will be based on its proportional share of the utilities’ aggregate targets by the end of 2015.

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.

Last Updated: July 2016

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 new cost recovery mechanism (Docket No. E-7, Sub 1032) in October 2013.  The new 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 recieved 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 Progress mechanism allows the utility to earn 8-13% of the net present value of the net savings from DSM programs.

Last Updated: July 2017

There is currently no policy in place that decouples utility profits from sales. Xcel Energy has a straight fixed variable approach in place. 

Last Updated: July 2017 

With the exception of Duke, all of Ohio's electric utilities recover program costs and lost revenues resulting from its portfolio of energy efficiency programs through the DSM rider. Dayton Power & Light had their electric security plan approved by PUCO, which extends their existing generation rate plan through Dec. 31, 2012. Duke operates the Save-A-Watt program through which it recovers lost revenues. (Docket 08-920-EL-SSO)

In November 2011, both Duke Ohio and AEP Ohio agreed provisionally to forgo collection of lost revenues and develop a decoupling mechanism for total rate recovery for residential and small commercial customers. PUCO must approve and finalize the agreements. AEP: Docket 11-0351-EL-AIR; Duke: Docket 11-3549-EL-SSO.

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 the 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.

Incentives may be approved on a case-by-case basis. First Energy and AEP have had performance incentives approved. The recovery mechanism is an annually reconciled rider which includes conditioned adjustments for shared savings with a maximum 10% shareholder incentive if at least 65% of targeted savings are achieved. Duke Energy has a program called Save-A-Watt which limits the incentive to 15% of program costs (Docket 08-920-EL-SSO). Columbia Gas also filed for a shared savings mechanism in September 2011, which was subsequently approved in December 2011(Docket 11-5028-GA-UNC). 

Beginning in January 2015, Ohio Senate Bill 310 gives certain customers the ability to opt-out of energy efficiency programs entirely. Large customers may opt out of a utility’s energy efficiency provisions if they meet one of the following criteria:

  1. Receive service above the primary voltage level (e.g., GSU and GT Rate Schedules)
  2. Commercial or Industrial customer with more than 45,000,000 kWh usage through a meter or through more than one meter at a single location for the preceding calendar year with a written request for registration as a self-assessing purchaser pursuant to section 5727.81 of the Revised Code


Last Updated: September 2016

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 Commission declined to adopt decoupling (termed a formula-based rate) proposed by Public Service Co. The Commission found, however, that the mechanism has merit and said it will re-examine the issue in the future if other parties wish to file proposals (See Cause 200600285, Order 545168, October 2007). The gas companies use performance-based rates (PBR) and true up annually, which is considered to be decoupling.

Both Public Service Oklahoma (PSO) and Oklahoma Gas and Electric Company (OG&E) have shared benefit incentive plans. The current Demand Program rules for electric utilities base the incentive on the performance of utility programs. Utilities must achieve at least 85% of goals to gain an incentive; the incentive is adjusted based on performance to goal. Incentives are also capped at 15% of total program costs.  These new incentive rules for programs apply to natural gas utilities beginning in 2017.

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 Updated: July 2017

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 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 with performance incentives. 

Last Updated: July 2017

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 which 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 (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 Updated: July 2016

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 proposed a lost revenue recovery mechanism which 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 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: July 2016

All investor-owned utilities in South Dakota recover lost revenues. In 2010 the South Dakota Public Utilities Commission authorized a 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 UtilitiesNorthwestern 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: July 2017

There is currently no policy in place that decouples electric utility profits from sales, however 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: July 2016

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 Electric Service Schedule 193, Demand Side Management Cost Adjustment. Charges appear on customer bills as “Customer Efficiency Services,” the funding source for cost effective energy efficiency and load management programs approved by the Commission and managed by PacifiCorp. Schedule 193 is a balancing account mechanism where revenues to fund the above programs are collected outside of general rate case proceedings.

On October 5, 2006, Questar Gas 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 Questar 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). Questar'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.  

Under the Questar Gas ThermWise Business Custom Rebates program, self-directed rebates are available for the installation of energy efficiency measures. Incentives are the lesser of (a) and (b): (a) $10.00/decatherm per first year annual decatherm savings as determined solely by the Company; (b) 50% of the eligible project cost as determined by the Company.  Customers can choose to engage in self-direct and more traditional CRM programs simultaneously, provided the different programs are used to deploy different projects.

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 Updated: July 2017

Efficiency Vermont (EVT) serves the majority of the state and is 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. For the period January 1, 2015 to December 31, 2017, VEIC can earn up to $4,442,682 for meeting electric energy savings goals and other performance goals including peak savings, market transformation, and total resource benefits.

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 Updated: July 2016

Virginia allows natural gas utilities, but not electric utilities, to decouple their 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 CFLprogram.”

Revenue recovery is limited by any offsetting sales and subject to industry standard measurement and verification. (Case No. PUE-2010-00084)

The 2007 legislation amending the state's earlier restructuring law called for the Virginia State Corporation Commission (SCC) to open a proceeding to initiate the development and implementation of efficiency programs with incentives and alternative means of compliance to achieve such goals. The legislation also states that an electric utility may recover projected and actual costs of energy efficiency programs, including a margin recoverable on operating expenses, which is equal to the general rate of return on common equity.  The SCC can only approve such recovery if it finds that the program is in the public interest (See Virginia Code Section 56-585.1). 

Virginia does not have incentives in place for natural gas.

Last Updated: July 2016

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 percent 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 five percent 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 percent above the Energy Independence Act (EIA) biennial conservation targets while the decoupling mechanism is in effect. Note that Pacific's is only required to acquire 2.5 percent additional electric savings during the 2016-2017 biennium. 

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 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

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 2015-2018 contract between SEERA and CB&I has a performance bonus mechanism for customer satisfaction and energy savings goal achievement.

Last Updated: July 2017

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).

load management tracking adjustment mechanism is in place for Montana-Dakota Utilities Company to track and recovery 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