Energy policy discussions of the twenty-first century have focused in part on the increased need for investments in demand response (DR) and energy efficiency (EE) as mechanisms for reducing emissions, conserving natural resources, and avoiding the need for capital expenditures. Electric utilities are in a unique position to catalyze wide-scale deployment of DR and EE because of their size and scale, financial resources, and existing relationships with customers.
However, regulatory policies must be properly structured to realize widespread utility investments in DR and EE. Legislators and utility regulators are well-positioned to create regulatory mechanisms to foster increased utility investment in cost-effective DR and EE technologies. This paper discusses the existing methodologies for regulatory treatment of DR and EE incentives in the United States.
Traditional utility regulation favors supply-side resources over DR and EE resources. First, utilities earn a rate of return on investments in generation, transmission and distribution infrastructure. The absence of a parallel incentive for DR and EE investments creates a bias against demand-side resources. This has been described in the economic literature as the "Averch-Johnson Effect." That is, where a firm's profits are linked to its capital investment, as is the case with utilities under traditional regulatory structures, there is an embedded incentive for the firm to increase its capital outlay in a manner that does not necessarily maximize producer and consumer surplus. Stated another way, traditional regulatory frameworks create a disincentive for utilities to meet resource needs using approaches that are less capital intensive. Thus, faced with otherwise equivalent alternatives of building a power plant that contributes to profitability or making investments in DR and EE that allow for cost-recovery only, a utility would generally prefer to build a power plant.
Second, traditionally, a utility's revenue has been directly tied to kilowatt-hour sales of electricity. That is, the more electricity a utility's customers use, the more revenue that utility earns. Under this paradigm, since DR and EE reduce customer consumption, DR and EE can reduce a utility's revenues, even in cases where the direct costs of DR and EE investments are recoverable by the utility. While revenue loss due to DR and EE investments may be small in comparison to a utility's gross revenue, the impact on total profits can be substantial given the high fixed costs that utilities face. To illustrate this point, a 5 percent decline in revenue for the average investor-owned utility in 2007 would have meant a 17 percent decline in operating income.
Like any business, investor-owned utilities have a fiduciary obligation to maximize shareholder value. Thus, when faced with two investment decisions – such as the choice between building a power plant or investing in DR and EE – a rational utility will chose the one that is most profitable. Acting in any other way can negatively impact its ability to conduct business and attract investor capital. Thus, despite the fact that utilities are well-positioned to deploy cost-effective DR and EE programs, financial factors have prevented widespread adoption of DR and EE as a core component of the utility business model.
Regulatory models for the treatment of DR and EE vary greatly from state-to-state, and even utility-to-utility within a state. Even when categorizing different regulatory approaches, there is tremendous variety within each category. A recent paper published by the Environmental Protection Agency in connection with the National Action Plan for Energy Efficiency presents a framework that describes three major categories of regulatory approaches to DR and EE investments: program cost recovery, performance incentives, and lost margin recovery.
What follows is a discussion of different cost recovery and performance incentive approaches. This discussion does not seek to address lost margin recovery mechanisms such as decoupling. While decoupling can address lost utility margins, the decoupling concept implicates a number of other broad policy considerations. A properly-designed performance incentive mechanism can indirectly address recovery of lost margin revenue (eliminating a disincentive) as well as create a balanced regulatory platform that will properly incent utilities to evaluate DR and EE investments as part of an overall energy strategy to ensure reliable electric service at reasonable costs to customers.
As its name suggests, under a cost-recovery mechanism, a utility can recover prudently-incurred costs of DR and EE investments on a dollar-for-dollar basis, typically through a rider or customer surcharge. Cost recovery is designed to make a utility whole on its DR and EE investments. However, there are challenges with this approach. First, cost recovery alone will not address the lost margin revenue the utility will face due to reduced energy sales from DR and EE programs. Second, cost recovery does not factor in opportunity costs: DR and EE investments displace supply-side investments for which the utility can earn a profit. Absent a statutory or regulatory mandate, program cost recovery alone will generally not attract utility interest in DR and EE programs. Even with a mandate, the utility is generally not motivated to apply substantial resources to pursue robust programs or foster innovation.
Governors, state legislatures, and utility commissions in some states have set specific targets for utilities around demand reduction or energy savings. A financial "carrot and stick" can be attached to the targets to provide increased incentive to invest in programs that will deliver the desired results. Typically, this approach will use bands to determine the incentives or penalties a utility will face. For example, utilities may face a financial penalty if they fail to achieve at least 70 percent of the target, receive a pro-rated percentage of the incentive for achieving 70 to 110 percent of the target, and an additional reward for achieving more than 110 percent of the target. Sometimes the incentive is tied to a percentage of the shared savings from avoided costs (discussed below), but the incentive may be structured and funded by a variety of means. While state commissions must ultimately approve the target level, the target may be in the form of a commission-determined regulatory mandate or a utility-suggested target. The most successful programs that achieve the desired goals and objectives are those that ensure utility cooperation with properly designed regulatory performance incentives. While commissions have the power to mandate utilities to implement DR and EE programs with or without incentives or penalties. A mandate without an incentive, perhaps with cost recovery only, will likely lead to utility's pursuing minimum participation. The utility will not be motivated to be innovative in exploring cost-effective strategies that will gain widespread customer participation.
Under this approach, the utility receives a percentage share of the energy savings from a DR or EE investment. The savings are generally calculated as the avoided costs of an additional supply-side resource minus the DR or EE investment. A shared savings approach will generally allow for incentives above a threshold level of DR and EE participation, and may include penalties for failing to achieve the desired DR or EE objective. Typically, a utility will receive an increasing percentage of shared savings as participation or savings levels increase. This structure creates an incentive for promoting cost-effective DR and EE, but also encourages careful cost management because excessive or inefficient spending reduces the incentives available.
In some jurisdictions, utilities can capitalize and earn a rate of return on their DR and EE investments. Under this approach, a utility will generally accumulate costs associated with investments in DR and EE as regulatory assets, and later recover those costs in the utility's next rate case. The primary advantage of this approach is that it puts DR and EE on an equal footing with supply-side investments. In these circumstances, utilities will have no embedded disincentives in pursuit of a least-cost, optimally-efficient approach to meeting customers' electric needs either through a demand- or supplyside solution. A few states have implemented, or are considering implementing, rate of return adders to investments in DR and EE. In these cases, DR and EE investments earn a higher rate of return than traditional supply-side investments. A rate of return mechanism allows the utility the opportunity to earn a profit on DR and EE investments in the same manner as other capital investments in a utility's rate base. This puts utilities in a position of pursuing optimal resource planning with both supply and demand resources, unencumbered by a negative impact to a utility's profitability from pursuing demand resource options.
An emerging model, put forth originally by Duke Energy, proposes that the utility be compensated for demonstrated DR and EE savings by receiving a percentage of the utility's avoided supply costs. Under the proposed Duke approach, know as Save-A-Watt, the utility would "recover the amortization of and a return on 90 percent of the costs avoided by producing save-a-watts." The Save-A-Watt proposal has not received final approval. As noted above, there is tremendous variation in the basic incentive mechanisms employed by state utility commissions to align utility incentives to promote an efficient level of cost-effective DR and EE investments. The right approach can vary by state, utility, even utility program, and should be considered in terms of what approach will motivate the utility to achieve positive program results. The utility should be motivated to deploy all cost-effective DR and EE strategies up to a level that is optimally efficient for the utility and its customers. Program cost recovery alone will not achieve that result, while incentives that are too generous will lead to overspending on DR and EE programs beyond a level that is cost-effective.
Funding for "Conservation & Load Management" (C&LM) programs in Connecticut comes from a systems benefit charge on customers' electric bills that is collected by the state Energy Conservation Management Board (ECMB). The State's distribution utilities (Connecticut Light & Power and United Illuminating) administer C&LM programs with ECMB funding and Department of Public Utility Control (DPUC) approval.
The Connecticut DPUC and ECMB encourage C&LM initiatives with financial incentives known as program "management fees." Each year, utilities propose their energy savings goals and other performance metrics eligible for performance incentive payments, which must be approved by the DPUC. If utilities then achieve at least 70 percent of their goal, they are eligible to earn pre-tax incentives of 1-8 percent of their C&LM expenditures, in addition to program cost recovery. Achieving 70 percent of a utility's goal translates into a 1 percent management fee; achieving 100 percent of the goal equates to a 5 percent management fee; and achieving 130 percent of the goal would mean an 8 percent management fee. The utilities can also earn a reasonable rate of return when they market and sell their C&LM programs as well as incentives for demand savings from load reduction programs. Penalties for failure to achieve energy savings goals are not considered in Connecticut, like they are in California.
Minnesota encourages investment in cost-effective DR and EE by allowing utilities to share in the net savings that their programs create for customers, provided they achieve a certain percentage of their target. Each utility in the state is required to show that their demandside expenditures (with minimum spending levels as a function of energy sales) result in net ratepayer benefits. Net ratepayer benefits are calculated as utility program costs netted against avoided supply-side costs, according to a standard avoided cost calculation. A portion of net customer benefits, with the exact amount dependent on savings achieved relative to targets, is then given to the utility as an incentive. If savings of 90 percent or less of the goal are achieved, the utility receives no incentive. The percentage of net benefits paid to the utility increases as savings levels increase. The utility's incentive is capped at 30 percent of its spending requirement and achieving the maximum requires hitting 150 percent of the savings goal.
This shared savings mechanism combines the target with incentive mechanism and is designed to ensure that a utility's program is cost-effective. If programs are not cost-effective, then there are no net benefits and no incentives are paid. No significant incentive is provided unless a utility meets or exceeds its savings target at the minimum spending requirements. As the cost-effectiveness increases, net benefits and incentives increase accordingly.
Las Vegas boomed in the 1990's and early 2000's. New businesses and residents came to Nevada in droves, dramatically pushing up electricity demand. Nevada experienced 4.5 percent average annual growth in electricity consumption from 1980 to 2005, the highest of any state in the nation and more than double the national average of 2.2 percent over that period.
In 2001, the Public Utilities Commission of Nevada reversed a 1997 decision that had effectively ended customer funded energy efficiency. Nevada utilities reestablished their energy efficiency programs, but statewide spending hovered at around $3 million through 2002 and $11 million to $14 million from 2003 to 2005. In 2004, Nevada became the first state to permit utilities to earn a bonus rate of return on DR and EE investments. In simple terms, utility DR and EE investments become regulatory assets that are eligible to earn a return of up to 5 percent more than traditional supply-side investments on the equity portion of the authorized return. With the ability to earn more money by investing in demand-side resources, coupled with the inclusion of energy efficiency in the state's Renewable Portfolio Standard in 2006, Nevada utilities have dramatically increased their spending on DR and EE. Nevada utility spending on DR and EE hit $38 million in 2007, a nearly three-fold increase from the $14 million that was spent in 2005.
In 2007, Duke Energy Carolinas received national attention by proposing a DR and EE rider in North Carolina and South Carolina that was counter to traditional regulatory mechanisms for DR and EE. Duke's proposal was referred to as Save-A-Watt (SAW). Rather than recommending a cost recovery mechanism that is a function of how much the utility spends on DR and EE investments, SAW is a function of the cost of the supply-side resources Duke avoids with successful implementation of DR and EE. Duke's proposal called for the utility to receive "90% of the return of and on the supply-side investment [Duke] would have made to provide the same capacity and energy over the same life as the measures and programs included within the portfolio of energy efficiency programs."
Duke contends that if it did not invest in DR or EE, then a certain amount of additional capacity and energy would be procured, the costs for which would be borne by ratepayers. By asking for 90% of the return that Duke would earn if it had invested in supply-side resource alternatives, Duke points out that there are benefits to customers and the utility. Customers will see lower bills than they otherwise would have faced, and Duke can truly consider "saved watts" the "fifth fuel" in its portfolio. Duke's SAW program has yet to receive regulatory approval in either North Carolina or South Carolina.
A challenge for state utility commissions is to adopt policies that a) achieve a least-cost model, b) counterbalance the Averch-Johnson Effect, and c) encourage the right level of investment in DR and EE resources as well as traditional utility infrastructure. State utility commissions have the authority to increase utility-sponsored DR and EE by creating a favorable regulatory environment for utility DR and EE investment so that utilities will pursue an optimally-efficient strategy to meet the needs of their customers. In general, state utility commissions today want the utilities in their jurisdiction to pursue DR and EE programs due to the environmental and economic benefits these programs offer customers. Commissions should therefore ensure that utilities receive regulatory signals consistent with these objectives.
In addition to program cost recovery, state utility commissions should consider a constructive level of utility performance incentive through a mechanism that is appropriate for the utilities in the state. A properly designed performance incentive mechanism can align a utility's corporate objectives with that of ensuring a cost effective level of DR and EE activity for the benefit of its customers.
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