Energy efficiency in the utility industry has grown substantially in the past decade, largely due to its benefits in addressing many of the industry’s most pressing concerns: system reliability, environmental regulations, and rising costs. Today the utility industry is rapidly evolving as it adapts to several new trends, including greater use of distributed energy resources, flattening energy sales, a need for emissions reductions, increasing penetration of plug-in electric vehicles, and growing attention to transmission and distribution constraints and grid resilience. In this new era of utility transformation, energy efficiency will play an important role as a low-cost utility resource that can help address these challenges by lowering costs, reducing emissions, and improving reliability.
At the same time, the traditional utility business model has continued to impede development of energy efficiency resources. For example, many utility stakeholders have viewed spending on energy efficiency programs as having a detrimental effect on utility revenues by reducing sales of the utility’s core product, electricity or natural gas. Their reasoning is straightforward: While a utility’s variable costs change in proportion to sales volume, short-term fixed costs associated with providing service do not. Therefore, a reduction in sales due to efficiency improvements leads to a reduction in revenue that is larger than the costs avoided. In addition, to the extent that energy efficiency displaces other capital investments, a utility’s associated earnings opportunities are reduced. Together these factors affect the utility’s balance sheet, reducing the financial benefits to its investors and providing a strong incentive for utilities not to invest in energy efficiency.
Comprehensive strategy to achieve high utility sector energy efficiency savings
- Establish specific energy efficiency savings targets
- Align utility ratemaking with energy efficiency by incorporating:
- Program cost recovery
- Full revenue decoupling
- Earnings opportunities tied to performance toward savings targets
ACEEE research shows that a comprehensive policy strategy―both setting specific energy efficiency targets and providing opportunities for utilities to earn a return on efficiency investments and collect authorized revenues―is most closely associated with achieving high savings. Such a strategy is essential to sustaining long-term utility interest in capturing cost-effective energy efficiency resources. While many states have adopted a robust set of policies, many others still have not. For energy efficiency to play a large and sustained role in the utility of the future, more states need to adopt and maintain an optimal mix of policies that align utility business models with energy efficiency.
This toolkit covers the second part of that comprehensive strategy: aligning utility ratemaking with energy efficiency (information on utility energy savings targets can be found here.)
Electric and gas utilities are regulated as natural monopolies. Regulatory bodies, through judicial processes, set rates to ensure utilities are able to recover the cost of providing service while earning a reasonable return on investments. Utility rates recover a variety of costs, including expenses associated with operation of the system, fuel, depreciation costs associated with assets (generation, transmission, or distribution), and taxes. Rates also recover debt costs associated with financing and a return on equity, the reasonable rate of return for shareholders. The total cost of service, including the return on equity and debt, produces an annual revenue requirement. The revenue requirement represents the total revenue a utility needs to recover from customers to provide service. The revenue requirement is allocated by customer class and then converted into rates using billing determinants (therms, kWh, kW, and customer charges).
Types of Regulatory Tools
ACEEE finds that there are three general categories of regulatory tools that better align energy efficiency as a utility resource with the traditional utility ratemaking principles described above (each of these and various subcategories are described in more detail below). The three categories are:
- Program cost recovery. Recovery of the direct costs of energy efficiency programs
- Removal of throughput incentive. Recovery of lost contributions to fixed costs and elimination of throughput incentive (profits linked to increased energy sales) via symmetrical revenue decoupling
- Performance incentives. Creation of performance-based earnings opportunities for energy efficiency investments
These tools, combined with specific energy efficiency targets, can help utilities consider the value of energy efficiency in a way similar to their evaluation of other supply-side investments.
Program Cost Recovery
Energy efficiency program costs typically include program administration, implementation, and evaluation. Timely program cost recovery is an essential requirement for utility program implementation. According to the Institute for Electric Innovation (IEI), program cost recovery is already in use in nearly every state. There are several options for achieving this, including recovery via base rates or through an additional charge, known as a rider, on a customer bill. We expand our discussion of the common approaches to program cost recovery below.
Public Service Surcharge
This method of recovering program costs relies on a customer bill surcharge, often known as a system benefits charge or public service surcharge. For example, states may require utilities to levy a specified charge (e.g., 3 mills or 0.3 cents per kWh) on all customer bills to fund energy efficiency programs.
In Connecticut, for example, costs for energy efficiency programs are recovered through a Combined Public Benefits (CPB) charge. The CPB charge includes a Renewable Energy Investment Charge, which supports renewable energy programs; a Systems Benefit Charge, which allows electric companies to recover costs from implementing a variety of public policies, such as programs for low-income customers; and a Conservation and Load Management (C&LM) Charge, which supports energy efficiency programs. The C&LM charge is set at 0.3 cents per kWh, but it can be increased by up to an additional 0.3 cents per kWh through an adjustment mechanism (See Conn. Gen. Stat. § 16-245l).
Recovery of Costs in Base Rates
The advantage of recovering costs through general rate cases is that doing so is consistent with existing regulatory rules and procedures. Utilities can therefore be reasonably assured of timely cost recovery, particularly if there is a frequent balancing mechanism in place between rate cases.
A less common approach to cost recovery involves treating efficiency program costs like an investment in physical capacity, adding the unamortized cost and an approved return on capital to the revenue requirement, which is then passed on to the customer as an increase in per-kWh or per-therm rates at the next rate case. Although capitalization has been used in the past by some states, it is no longer the preferred method of cost recovery. This is because capitalization spreads out cost recovery over an extended period, raises the total cost of efficiency programs, and allows a return on capitalized program costs that is not tied to program performance.
In practice, according to IEI, in many states recovery of efficiency program costs takes place through some combination of base rate adjustments, system benefits charges, and other surcharges.
Removal of Throughput Incentive and Lost Margin Recovery
Energy efficiency programs are designed to reduce the amount of electricity and gas that customers use, but this reduction in sales can impact revenue recovery. Lost margin recovery attempts to mitigate this impact and is one of the most widely debated areas of policy related to utility sector energy efficiency programs.
Symmetrical Revenue Decoupling
Of those states that have enacted or are planning to enact policy for lost margin recovery, symmetrical revenue decoupling is the most commonly used or proposed mechanism. Decoupling is a policy meant to sever the link between utility sales and revenues by ensuring full cost recovery of authorized revenue requirements, no matter the level of sales or reason for change. In practice, a periodic adjustment (also known as a true-up) adjusts revenue recovery up or down, based on the difference between projected and actual sales. The adjustment is symmetrical, meaning refunds for customers in the event of over-recovery or charges for customers in the event of under-recovery. As a result the utility is able to recover authorized revenues regardless of sales, removing the disincentive to invest in energy efficiency programs due to reduced sales.
Interest in decoupling has continued to grow. In 2007, 15 states had decoupling for gas utilities and 5 states had policies for electric utilities. In 2015, 23 states had decoupling for gas utilities and 14 had policies for electric utilities. These numbers indicate that at least one major utility in each state has implemented decoupling.
Proponents of decoupling argue that, because the throughput incentive drives a wedge between a utility’s responsibility to deliver investment returns to its shareholders and the promotion of energy efficiency among its customers, some mechanism of lost margin recovery is essential to the realization of robust energy efficiency gains. Other advantages of decoupling include shielding utility revenues from fluctuations in sales, to a certain extent, and reducing the need for frequent rate cases with a corresponding reduction in regulatory costs.
One major criticism of decoupling is that it removes the normal business risk faced by utilities by guaranteeing they will receive their authorized revenues, no matter the cause of any shortfall (whether from the efficiency program itself, weather, the economy, or something else). In response, some commissions have approved the use of formulas for calculating the true-up that attempt to account for factors other than the efficiency program. Some commissions have also considered reducing the authorized rate of return for utilities with decoupling. We do not recommend that approach, because it would be seen as a disincentive and contrary to the original intent of these business model adjustments. Furthermore, symmetrical decoupling effectively shields customers from the risk of over-recovery of costs. Pamela Morgan’s comprehensive study of decoupling adjustments found that about 63% of decoupling adjustments were surcharges and 37% were refunds.
A 2009 article by S. Kihm argues that decoupling is appropriate only in situations where regulators keep a utility’s allowed rate of return close to its cost of capital, and that utilities earning a return on capital investments greater than the cost of capital still face the Averch–Johnson (A-J) effect, which is the incentive to acquire additional capital. Any difference between the two encourages large-scale investments by the utility because doing so raises the stock price, to the benefit of investors. This situation holds whether or not a decoupling mechanism is in place. Therefore, while decoupling may make utilities indifferent to fluctuations in sales, it does not necessarily remove the incentive to make large supply-side investments that benefit shareholders.
Lost Revenue Adjustment Mechanisms
A second means of recovering lost marginal revenue is through a lost revenue adjustment mechanism (LRAM), sometimes referred to as lost contributions to fixed costs (LCFC). This mechanism allows a utility to recover authorized revenues that are reduced specifically as a result of energy efficiency programs. This removes disincentives to invest in efficiency.
Unlike decoupling, this mechanism does not attempt to completely sever the link between revenue and sales. As a result, utilities may still be motivated to increase sales because additional revenues from higher sales outside of the energy efficiency program context can still be retained by the utility. Some states, however, have mechanisms in place to help address concerns regarding the potential for over-collection of fixed costs (see 2015 ACEEE study by Gilleo et al.). For example, in Nevada, utilities are explicitly prevented from over-earning and in recent years have refunded excess revenues to customers.
Finally, LRAMs have other disadvantages compared with symmetrical revenue decoupling. They require a robust evaluation process to accurately estimate savings from the energy efficiency measures because considerable amounts of money can be at stake. The verification challenges can lead to contentious rate cases and an incentive for utilities to maximize savings claims to increase lost revenue recovery. Also, the timing of energy efficiency program development, LRAM determinations, and ratemaking decisions are not always aligned, which can become a challenge to implementation.
The Gilleo et al. study reviewed the 17 states with LRAM policies at the time and found that while LRAM is not a complete substitute for decoupling, it can help bring parties to the table and may be a temporary solution on the way to full revenue decoupling. However ACEEE strongly recommends full revenue decoupling as the preferable approach to address both lost margin recovery and the throughput incentive. While LRAM does address recovery of fixed costs, it does not remove the throughput incentive. Furthermore, while under-collection of authorized revenues is addressed by both LRAM and decoupling, only symmetrical decoupling requires over-collection of revenues to be refunded to customers.
While program cost recovery and lost margin recovery mechanisms serve to mitigate the utility disincentive to invest in energy efficiency due to a reduction in sales, these policies do not necessarily provide an incentive for such investment or for a certain level of performance. Even with a decoupling mechanism in place, investor-owned utilities often still have an incentive to make supply-side investments to provide greater returns to shareholders.
To incentivize utilities to provide energy efficiency programs for their customers, there should be a reasonable earnings opportunity for the successful implementation of energy efficiency programs. In general, the available incentive should be comparable to the return on investment in supply-side resources such as new generating capacity. Performance incentives are widely used by states that have adjusted utility business models beyond program cost recovery. A 2015 ACEEE study by Nowak et al. reviewed performance incentives in the United States and identified 25 states that had such a policy in place. That research characterized four general types of performance incentives:
- Shared net benefits incentives provide utilities the opportunity to earn an amount equivalent to some portion of the benefits of a successful energy efficiency program. The amount is usually a percentage of the positive difference between program spending and the dollar valuation of energy savings achieved. Most incentives in this category also have a savings-based element, a threshold level set as the achievement of a minimum percentage of the energy savings performance goal for the utility. We call it shared net benefits because the incentive amounts are driven by net benefits; the greater the net benefits, the higher the incentive payment amount.
- Energy savings–based incentives reward utilities for achieving, and sometimes for exceeding, preestablished energy savings goals, measured in kWh or therms. Often, these energy savings targets for utilities may be tied to or derived from statewide energy efficiency resource standard (EERS) policies. For example, if the utility energy efficiency programs save 100% of the target, they are eligible for some specified incentive payment. Five of the six states with savings-based incentives have EERSs. The amount of the financial incentive the utility earns is often calculated as a percentage of total program spending or budget in a tiered structure (e.g., achieve 100% of the savings target and receive an amount equivalent to 6% of program spending; achieve 110% and receive 8%; and so on), but it is driven by the program energy savings achieved.
- Multifactor incentives are those in which the calculation of performance incentive amounts include multiple metrics, not only energy savings or energy savings net benefits. This approach is found in a handful of states where the mechanism is used to forward the achievement of several regulatory and public policy goals at the same time. For example, financial incentives may be tied to energy savings, demand savings, success in reaching low-income customers, and/or measures of customer service quality.
- Rate-of-return incentives allow utilities to earn a rate of return based on efficiency spending. This creates a correspondence between demand-side (energy efficiency) spending and supply-side (generation and transmission) investments. For example, a utility may earn a rate of return for efficiency investments equivalent to or comparable to the rate it earns for new energy supply capacity investments. This approach is far less common.
The major advantage of incentives is that they put energy efficiency and supply-side resources on relatively equal financial footing, enabling shareholders to earn a comparable financial benefit on either investment. An important additional advantage with most of these mechanisms is that they are tied to a specific level of performance rather than spending.
Arguments against incentives include the cost and difficulty of implementing a robust evaluation mechanism to verify savings for performance-based incentives, as well as the view that ratepayers should not have to pay utilities for simply complying with regulatory mandates for energy efficiency. S. Kihm’s 2009 article also notes that the difference in scale of investments in energy efficiency programs versus supply-side resources encourages utilities to continue to favor the latter over the former, even when their respective rates of return are equal.