OLR Research Report

October 3, 2005




By: Kevin E. McCarthy, Principal Analyst

You asked how (1) PA 05-1 of the June Special Session addresses the decoupling of utility sales and revenues and (2) other states have dealt with decoupling.


Historically, utility regulators such as the Department of Public Utility Control (DPUC) have set electric and gas rates, and thus the utility's revenues, based on the utility's projected sales volume. This approach can discourage utilities from promoting conservation or the development of distributed generation (on-site generation of electricity by utility customers), because these initiatives decrease utility sales and thus utility revenues.

In Connecticut, the legislature authorized DPUC to take several steps to decouple utility sales and revenues in 1991. PA 05-1, June Special Session additionally provides electric utilities with several financial incentives to encourage them to promote conservation and distributed generation. These include: (1) financial awards when a utility educates its customers and promotes their investments in conservation programs and distributed generation; (2) an additional award of $25 per kilowatt-year to the utilities for specified new utility conservation programs approved by DPUC; and (3) requirements that the utilities meet part of their demand through conservation and distributed generation measures implemented by commercial and industrial customers and provisions specifying how the utilities recover the resulting costs.

At least five other states have taken steps to decouple utility sales and revenues. California was the first state to do so, adjusting electric and gas rate policies starting in 1981 to compensate utilities for revenues that were lost when they implemented conservation programs. New York established a similar policy for Consolidated Edison in the 1990s, but terminated the policy after it deregulated the electric industry.

Maine, Oregon, and Washington have taken a somewhat different approach, allowing utilities to earn a specified amount of revenue per customer, independent of the amount of energy they sell. Maine and Washington eliminated their programs when factors other than conservation programs (an extended recession and increased costs of purchased power, respectively) put upward pressure on rates.

A non-profit organization, the Regulatory Assistance Project, has prepared a paper that presents arguments for and against decoupling, which is available online at Additional information on the subject of decoupling is available at


Previous Legislation

Utility regulators have historically set rates at a level that allows the utility, based on its projected sales volume, to just recover its prudently incurred expenses and investments and earn a reasonable rate of return on these investments. This approach is designed to ensure the lowest possible utility rates consistent with the utility's continued financial health. But, this approach can discourage utilities from promoting conservation or the development of distributed generation, because these initiatives decrease utility sales and thus utility revenues.

In Connecticut, the legislature recognized this problem in 1991, with the adoption of CGS Sec. 16-19kk. The legislature found that utilities would have a disincentive to participate in conservation programs and other programs promoting state energy policy if participation harmed their earnings. The legislation required DPUC to consider, in setting a utility's rate of return on its investments, the reduced demand resulting from the utility's conservation programs, the utility's success in reducing dependence on oil and meeting other criteria with state energy policy. The legislation also allowed DPUC to establish other performance-based

incentives designed to promote state energy policy. DPUC subsequently allowed electric utilities to earn a bonus on their conservation program expenditures that varied with the effectiveness of the programs.

PA 05-01, June Special Session

PA 05-1, June Special Session, includes several additional financial incentives to encourage electric utilities to promote conservation and distributed generation. The act rewards an electric utility when it educates its customers and promotes their investments in conservation programs and distributed generation. The reward is paid when the resource becomes operational, under the following schedule, $200 per kilowatt (kw) for resources developed by January 1, 2008, $150 per kw for resources developed by January 1, 2009, $100 per kw for resources developed by January 1, 2010, and $50 per kw for resources developed thereafter. The company's revenues from its award do not count in DPUC's determination of whether the company's rates are just and reasonable (If they did, and DPUC determined that the company was exceeding its authorized return on its investments, the utility would normally be required to share part of the revenues with its customers.)

The act requires DPUC, by January 1, 2006, to establish a program to grant awards equal to $25 per kilowatt-year to the utilities for specified conservation programs approved by DPUC and developed in Connecticut on or after January 1, 2006. The programs are for load curtailment, demand reduction, and retrofit conservation that reduce costs arising from congestion on the transmission system. Revenues from the awards do not count in DPUC's determination of whether a company's rates are just and reasonable.

The act also imposes several requirements on the utilities. Among other things, it requires that they meet part of their needs by obtaining “class III” resources. These resources are energy savings achieved by commercial and industrial customers or energy produced by these customers using distributed generation. The act makes the utility eligible to earn a bonus rate of return on its costs in implementing the act.



The California PUC adopted an electric rate adjustment mechanism (ERAM) for the state' s three major utilities in the early 1980s. The mechanism sought to ensure that a utility could collect the amount of money needed to recover its fixed costs, notwithstanding the effect of conservation programs on revenues. Differences between a utility's PUC-authorized revenues and its actual revenues were tracked in the ERAM balancing account. The authorized revenues were adjusted annually to reflect changes in the utility's capital expenditures, its costs of capital and interest rates, and changes in operational costs such as wage rates. Under- or over-collection of revenues were recovered or refunded through subsequent changes in the utility's rates. The mechanism applied to all electricity sales for residential and small commercial customers (a similar mechanism applied to gas sales to these customers in the case of PG&E and San Diego Gas and Electric). A study by the federal Lawrence Berkeley Laboratory found that ERAM had a negligible effect on rate levels and reduced the risks of rate volatility for customers and profit losses for the utilities.

In 1990, the California PUC supplemented this mechanism with a system of performance-based financial incentives for utilities to promote additional cost-effective energy savings. In 1996, as part of its legislation restructuring the electric industry, the state required all customers to pay a charge to fund conservation and renewable energy programs.

The PUC suspended the ERAM and the financial incentives following adoption of the restructuring legislation. This was because these measures potentially conflicted with the rate freeze adopted as part of the legislation. In addition, the continued operation of the ERAM threatened the ability of the utilities to recover their stranded costs as provided for in the legislation. On the other hand, the PUC adopted a decoupling mechanism for Southern California Gas in 1998. The mechanism compensates the company for its costs on a per-customer basis with a set margin per customer, regardless of change in the total amount of gas that the company sells. This mechanism provides an incentive for the utility to increase the efficiency of its service delivery per customer.

In 2001, the legislature enacted Assembly Bill 29x, requiring the PUC to again break the link between the utilities' revenues and sales. The commission adopted decoupling mechanisms as part of each utility's subsequent rate case. For example, in 2002, the PUC adopted a mechanism for Southern California Edison as part of its performance-based ratemaking ruling. In this ruling, the amount of revenue that the utility may earn is periodically adjusted to reflect inflation, increases in productivity, and increases in the number of customers the utility serves.

In 2003, the PUC adopted the state's Energy Action Plan. Among other things, the plan requires electric utilities to follow a “loading order” in meeting the state's needs. They must first use conservation and demand response measures to minimize increases in electricity and natural gas demand. Next, they must invest in renewable resources and distributed generation. Finally, they can use conventional resources to meet remaining needs. The current system does not provide utilities with a financial incentive to invest in conservation or renewable resources, but the PUC is developing such incentives.


The Maine PUC implemented a decoupling experiment for Central Maine Power (CMP) that ran for three years in the early 1990s. The PUC adjusted the company's allowed revenues based on growth in the number of customers it served, rather than on the amount of sales.

After decoupling was put into place, CMP filed for increased rates, in large part because sales fell significantly due to an extended economic recession. CMP subsequently petitioned the PUC to withdraw the requested rate increase and the commission agreed. The effect of the withdrawal was that the decoupling mechanisms were used to defer a rate increase. The deferred balances became quite large, and the commission decided not to extend the experiment.

New York

Consolidated Edison had an ERAM-type mechanism in place from 1992 to 1997. This was also the peak period for the utility's energy efficiency investments, with average annual investments during this period of nearly $74 million. Rate impacts from this mechanism were minimal.

The decoupling mechanism was eliminated after the Public Service Commission restructured the electric industry. Among other things, the restructuring initiative gave the New York State Energy Research and Development Authority the primary responsibility for developing and implementing conservation programs, and funded these programs through a systems benefits charge. After the decoupling mechanism was eliminated, Consolidated Edison's average annual energy saving investments dropped by nearly half.

In 2003, the commission began a study of how the rate structure might create disincentives for the promotion of energy efficiency, renewable energy, and distributed generation. A 2004 staff report, available at, summarizes arguments for and against reestablishing a decoupling mechanism. The report recommended against reestablishing a decoupling mechanism, and the commission has not done so to date.


In 1992, the Oregon PUC concluded that the connection between profits and sales should be severed. In 1998, it approved an alternative form of regulation for Pacificorp, one of the state's large electric utilities, which established a cap on the utility's revenues in lieu of setting fixed rates. In the years following the decision, the utility's spending on conservation doubled. Rates only fluctuated by a few percentage points during this period.

Oregon has also implemented decoupling on a trial basis for NW Natural, a natural gas utility. The commission authorizes a target “rate of return” on NW Natural's capital investments. Each month, if the utility sells less energy than expected because of conservation (as distinct from an economic slowdown or warm weather), then rates increase slightly to reach the target level for revenues. If sales are higher than expected, because of a lack of conservation, then rates and profits diminish. Rates are also adjusted to reflect increases or decreases in consumption that are attributable to annual changes in commodity costs or changes in the company's general rates. The resulting additional company revenues or credits to customers are recovered in the company's purchased gas adjustment clause. The experiment is currently being evaluated to determine whether it should be continued.


In 1991, the Washington Utilities and Transportation Commission (WUTC) establishing a revenue per customer (RPC) mechanism to sever the link between Puget Sound Energy's revenues and its electric sales. Under this approach, the WUTC determined the company's revenue requirements (the amount of money it needed to cover its costs) in the traditional fashion. It then divided this number by the projected number of customers. The authorized RPC was then multiplied by the number of customers the utility actually served in the subsequent year to determine the total revenue the company was allowed to keep. If the company earned more than this amount, the excess was rolled over into the next year and rates were reduced. If the company did not meet its RPC, rates were increased in the subsequent year.

In 1993, the WUTC found that the mechanism had achieved its primary goal of removing disincentives to conservation investments and extended the mechanism for another three years. However, subsequent increases in the company's cost of purchased power led the commission to discontinue the mechanism.