The future of utility customer-funded energy efficiency programs in the USA: projected spending and savings to 2025

Total spending on electric and gas energy efficiency programs is expected to increase in all scenarios across the study period. By 2025, we project that total electric and gas efficiency program spending, in nominal dollars, will rise from $4.8 billion in 2010 to $6.5 billion in the low case, $9.5 billion in the medium case, and $15.6 billion in the high case (see Fig. 1). These projections correspond to compound growth rates of approximately 2 % per year (low case), 5 % per year (medium case), and 8 % per year (high case). Although the projected increase in spending in both the medium and high cases is sizable in absolute dollar terms, the associated growth rates in all cases are substantially lower than that witnessed over the past half decade, when total electric and gas efficiency program rapidly accelerated at an average rate of 26 % per year from 2006 to 2010 (Eldridge et al. 2008, CEE 2012). In the decade preceding this recent and rapid expansion of energy efficiency program activity, however, electric program spending grew by less than 5 % per year from 1997 to 2006, which is on par with the projected growth in spending under the medium case.

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As discussed further in the following sections, projected growth rates for electric efficiency program spending are somewhat higher than for gas program spending in both the low and medium cases, with projected electric program spending growth of 2.3 and 4.9 % per year in the low and medium cases, versus less than 1.1 and 3.8 % per year for gas programs. In the high case, however, gas efficiency spending grows faster than electric spending (9.7 vs. 7.8 %). These differing trends reflect, in large part, the broader base of underlying policy support for, and historical experience with, electric efficiency programs, leading to stronger growth in the low and medium cases for electric programs, while leaving a large upside potential for growth in gas program spending under the high-case conditions.

Importantly, the projected growth in electric program spending across all cases does not occur smoothly over the forecast period, but rather is “front-loaded,” with much faster growth projected through 2015 (Table 5). In the medium case, for example, spending grows by 11 % per year through 2015 but by only 2 % per year from 2020 to 2025. This dynamic is partly due to the fact that, in many states, recent multi-year DSM plans entail significant spending increases over the next several years, but no longer-term targets or resource planning process currently exists to guide program activity beyond the time horizon of the DSM plan. The front-loaded spending projections also reflect the trajectory of EERS schedules, which typically reach their terminal targets by 2020 or sooner. From 2020 onward, we assume that spending growth in many states tapers off and grows roughly in proportion with projected revenues, reflecting both a lack of strong policy drivers for continued spending growth after 2020, as well as the assumption that savings potential within the 2020–2025 period will be diminished due to the success of programs implemented over the prior decade and tightening federal efficiency standards.

Not surprisingly, total U.S. electric program spending across all scenarios are driven, in large measure, by EERS policies, energy efficiency eligibility under RPS policies, and legislative mandates requiring utilities to acquire all cost-effective energy efficiency. In the medium case, for example, the 15 states with an electric EERS, plus the additional five states with legislative “all cost-effective energy efficiency” mandates (and no associated EERS) and the two states that qualify energy efficiency as an eligible resource under a renewable portfolio standard (again, without an associated EERS) together account for 72 % of the total projected electric efficiency program spending in the USA in 2025 (see Fig. 2). The remaining spending is associated primarily with the additional 18 states that rely primarily on DSM planning and/or IRP (without an associated EERS or “all cost-effective energy efficiency” mandate) to establish their electric efficiency budgets and targets, together comprising 28 % of total projected spending on electric efficiency programs.

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Projected trends in total U.S. spending are, to some extent, an overlay of distinct quasi-regional trends (see Fig. 3). In the medium scenario, overall growth of national efficiency program spending is driven chiefly by projected growth in the Midwest and South, which together represent 70 % of projected total U.S. electric program spending growth over the 2010–2025 period. In the Midwest, spending growth is associated with a contingent of populous states (IL, IN, MI, and OH) that are currently ramping up to meet statutory EERS targets, while in the South, increases in efficiency program spending are associated with a collection of relatively modest EERS policies and nascent IRP/DSM planning processes in states with a large base of energy consumption (TX, FL, NC, MD, and KY). The same underlying policy drivers propel spending growth in these two regions in the low and high scenarios as well, though to differing degrees.

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In the West and Northeast—the traditional bastions of energy efficiency activity—electric program spending is also projected to increase in the medium case, though by lesser amounts than the other two regions, reflecting the more mature state of those markets. In the Northeast, efficiency program spending is projected to increase under all three scenarios, where differences in spending levels between the medium and high cases are largely driven by assumptions about how utility program administrators and state regulators translate statutes requiring acquisition of all cost-effective efficiency into multi-year savings goals. For the West, the regional trends are dominated by California, where electric program spending in both the medium and low cases is projected to decline over the long term, as saturation within key end-use markets occurs and as the state leans more heavily on other energy efficiency policies (Navigant Consulting Inc. 2012). In the medium case, those declines are offset by spending growth in other western states, leading to net spending growth for the region as a whole, while in the low case, total electric program spending in the West is projected to decline slightly.

The differing regional trends imply a continued shifting of the energy efficiency map over the coming decade and beyond (see Fig. 4). While states in the West and Northeast accounted for more than 70 % of efficiency program spending in 2010, that percentage declines to just over 50 % by 2025 in the medium case, with the South and Midwest splitting the remaining spending about evenly. Notwithstanding the greater regional balance in absolute dollar spending on electric efficiency programs, the South is still projected to lag well behind other regions in terms of relative spending levels as a percentage of electric utility revenues. As shown in Fig. 5, spending as a percentage of revenues in the medium case is projected to rise from 1.8 to 2.8 % in the Northeast over the 2010 to 2025 timeframe, and decline slightly from 2.4 to 2.1 % in the West. In the Midwest, efficiency spending is expected to increase quite dramatically (from 0.7 to 2.2 % of revenues). However, in the South, while spending as a percentage of total electric utility revenues rises from 0.4 % of revenues in 2010 to 0.9 % in 2025, this is one third to one half the spending levels projected in the other three regions.

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In 2010, electric energy efficiency programs in the USA achieved incremental energy savings of 18.4 TWh, equivalent to 0.49 % of electric utility retail sales nationally (Foster et al. 2012).¹⁷ In comparison, leading states, where program administrators typically have a decade or more of experience in delivering energy efficiency programs, have achieved annual savings of more than 1.0 % of retail sales (e.g., CA, CT, MA, OR, VT, NV, HI, RI, and MN), and a sizeable contingent of other states has consistently achieved savings in excess of 0.50 % of retail sales.

As explained previously in the “Analytical approach” section (and in greater detail in Appendix 1), the electric efficiency program spending projections are linked to a corresponding set of savings projections (see Table 6 and Fig. 6), where in some cases savings estimates are derived from spending, and in other cases vice versa.¹⁸ In the medium case, incremental annual energy savings from electric efficiency programs are projected to increase to 28.8 TWh and 0.76 % of retail sales in 2025. This represents roughly a 50 % increase over the impact of electric efficiency programs in 2010. As was the case for the spending projection, much of the projected increase in annual incremental savings is concentrated in the initial years of the forecast period, as the projection follows the trajectory of the most recent batch of utility energy efficiency plans (which typically terminate in the 2012–2014 period) and EERS targets (which typically reach their final percentage targets by 2020 or sooner).¹⁹ In the low case, incremental annual savings rise moderately by 2015 before largely flattening out over the remainder of the forecast period, reaching 20.6 TWh or 0.53 % of retail sales by 2025. In the high case, annual incremental savings rise to 41.6 TWh by 2025, more than double the level achieved in 2010, equivalent to 1.13 % of total electric utility retail sales. Thus, in effect, the high case represents a scenario in which the national average savings rise to the level currently being attained by the top tier of states. In both the medium case and the high case, savings levels nationally are within the bounds of most studies of “achievable” energy efficiency potential. This suggests, among other things, that the level of savings projected in these two cases could potentially be reached through accelerated deployment of current technologies, without significant reliance on new efficiency technologies.

Table 6

Projected incremental annual electricity savings from utility customer-funded programs (TWh)

Scenario	2010	2015	2020	2025
Low	18.4	20.4	21.1	20.6
Medium	18.4	26.6	28.6	28.8
High	18.4	33.1	39.8	41.6

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To place these savings projections in perspective, the Energy Information Administration (EIA)’s most recent reference case forecast (EIA 2012) projects that total U.S. retail electricity sales will grow at a compound annual growth rate (CAGR) of 0.58 % over the 2010 to 2025 period, which is substantially lower than the average U.S. load growth of 1.6 % per year over the past two decades. The EIA’s modeling framework does not explicitly account for the impacts of future utility customer-supported efficiency programs; however, the model implicitly operates under the assumption that historical trends in utility customer-funded efficiency programs will continue over the forecast period. For the period 2000 to 2010, we estimate that utility customer-funded energy efficiency programs nationally achieved incremental savings of roughly 0.18 % per year, on average.²⁰ Thus, if one were to assume that the EIA reference case forecast implicitly assumes that savings from customer-funded electric efficiency programs continue to accrue at this historic rate, then a hypothetical reference case forecast with no future customer-funded energy efficiency activity would correspond to a CAGR of 0.76 % (i.e., 0.58 % plus 0.18 %).

Our medium case projection corresponds to average annual incremental savings of 0.72 % of retail sales per year between 2010 and 2025. This, in turn, implies that if electric utility customer-funded efficiency programs achieve savings at the level projected under our medium case, they would reduce growth in U.S. retail electricity sales to just 0.04 % per year through 2025 (i.e., 0.76 % annual growth with no future efficiency program activity minus projected annual incremental savings of 0.72 % of retail sales per year under the median case), offsetting almost all projected load growth under EIA’s 2012 reference case forecast.²¹ Following the same logic, our low case and high case savings projections would offset roughly 70 and 120 % of load growth, respectively, yielding average annual growth rates for retail electricity sales of 0.21 and −0.18 % from 2010 to 2025. To be sure, these benchmarks should be considered no more than a “back-of-the-envelope” estimate of the impact of projected customer-funded efficiency program savings on load growth in the USA. Nevertheless, they suggest that rising savings levels, in combination with modest underlying drivers for load growth, can potentially lead to flat, or even negative, load growth over the next 10 to 15 years.

The preceding set of projections suggest a wide range of potential trajectories for utility customer-funded energy efficiency program spending and savings in the USA—even without considering the possibility of fundamentally new policy developments. In this section, we identify some of the significant issues and uncertainties that may influence the spending course and impact of these programs over the next 10 to 15 years and which we attempted to account for—either directly or indirectly—within the projections. These interrelated issues and uncertainties include both external factors, such as the broader policy and market context within which utility customer-funded programs operate, and internal factors related to the implementation and regulatory oversight of these programs.

Utility customer-funded energy efficiency programs and their enabling policies function within a broader context, influenced by a variety of market forces and conditions, as well as by interactions with other policies. We briefly highlight four key elements of this broader market and policy context that may be particularly critical to the future trajectory of customer-funded efficiency programs: the state of the economy, natural gas prices, federal minimum efficiency standards, and environmental regulations affecting the electric power sector.²²

The timing and extent of the economic recovery may complicate and restrain efforts to scale-up energy efficiency spending and savings over the near to medium term, for several reasons. First, utility customer-funded energy efficiency programs typically require customers to pay a portion of the capital outlay for energy efficiency measures; as households and businesses struggle to manage their day-to-day expenses, and as declining home values reduce the equity available for financing efficiency improvements, many customers may be reluctant make new investments, even those with short payback periods. As a result, program participation may be suppressed, or program costs may rise if program administrators are required to increase financial incentives or expend greater sums on marketing efforts. Second, a stagnant economy is likely to reduce the rate of stock turnover and new housing starts, thereby reducing the amount of energy savings that could be captured through utility customer-funded programs targeting these market opportunities. Third, a slow economy may indirectly constrain energy efficiency program efforts in at least three ways: heightened sensitivity to potential near-term rate impacts associated with efficiency program spending,²³ increased risk that policymakers will re-direct dedicated funding for energy efficiency to shore-up state budgets²⁴ or other non-efficiency purposes, and slowed load growth, thereby reducing the avoided capacity costs and cost-effectiveness of energy efficiency programs.

As of April 2012, natural gas was trading at wellhead prices of less than $2 per million British thermal units, the lowest level in 10 years and nearing a record low. Although natural gas prices are projected to rise over the next 20 years (EIA 2012), they are nevertheless expected to remain lower, in real terms, than the prices that characterized most of the past decade, when most state energy savings targets were set.²⁵ For electric and gas energy efficiency programs, lower gas prices translate into reduced program benefits, which in turn constrains total efficiency spending and flexibility in program design as benefit–cost ratios decrease. More aggressive efficiency portfolios and comprehensive, multi-measure programs may be especially at risk because costlier measures will result in longer payback periods for customers and will not be as cost-effective from a total resource cost perspective. The effects of moderate gas prices will be especially pronounced for natural gas efficiency programs because lower gas commodity costs mean lower avoided energy costs to gas utilities, which affects program cost-effectiveness. Lower gas prices also mean that customers will have incentive to increase consumption or convert to gas heating from other fuels and will have less direct financial incentive to invest in energy efficiency.

In recent years, state adoptions of building energy codes have increased, and federal minimum efficiency standards for appliances and end-use equipment have been tightened. These policies affect utility customer-funded programs by essentially raising the baseline against which savings are measured, thereby influencing both the size of the remaining potential that can be harvested through those programs and the mix of technologies targeted. Two specific federal efficiency standards that are planned to go into effect over the near term—for lighting in 2012 to 2014, then again in 2020, and for non-weatherized natural gas furnaces in 2013—may have potentially significant impacts on customer-funded efficiency programs. The impact of the federal lighting standards is somewhat less certain because program administrators have other lighting technologies that are likely to remain cost-effective after the standards come into effect. Gas program administrators, however, may have fewer options. Starting in 2013, the new furnace standards would raise the minimum heat-to-fuel efficiency of furnaces from 78 to 90 % AFUE²⁶ in northern states (generally the states with the nation’s most substantial spending and savings targets). Programs can continue to provide incentives for higher efficiency gas furnaces, but with a technological efficiency limit of about 98 % AFUE, the incremental savings will be lower, and residential gas furnace programs are therefore less likely to continue as the mainstay of gas efficiency program portfolios.

Proposed or final air emissions regulations that are being considered or adopted by state and federal environmental agencies²⁷—in combination with low-priced, abundant gas—have become important drivers for utility customer-funded energy efficiency programs, as part of utilities’ multi-faceted strategies for managing the retirement of older coal-fired generators.²⁸ For example, many utility resource plans have discussed the potential role of demand-side resources as part of a strategy for complying with emissions requirements (e.g., Tennessee Valley Authority), as a prerequisite for utility customer funding of low carbon replacement generation (American Electric Power in West Virginia, Florida Power & Light in Florida), or as a means of deferring retirement and replacement decisions (Duke Energy Carolinas). The ultimate import of these regulations for future energy efficiency program budgets, however, depends on several factors. These factors include: the timing and stringency of the final rules, the price of natural gas (as gas-fired generation is expected to offset the majority of the retired coal-fired generation), the capital cost profile of clean energy generation alternatives (e.g., renewable energy, nuclear power, coal with carbon capture and sequestration), the regulatory and business models in place that govern the balance and relative attractiveness of supply- and demand-side investments, and the degree to which utilities and utility regulators integrate state and tribal Clean Air Act implementation plans with utility resource plans.

There are also a variety of other critical issues and uncertainties specific to the regulatory and administrative institutions within which utility customer-funded efficiency programs operate and that may strongly influence the spending and savings trajectories of those programs. Here, we highlight several: general aversion to rate impacts, challenges associated with developing innovative program designs to reach deeper and broader savings, and the limited ability in some states to extend gas efficiency programs to transportation gas customers.

In most states, utilities typically expense program costs for energy efficiency as they are incurred. As a result, energy efficiency program cost recovery is relatively front-loaded compared to cost recovery for most utility supply-side resource alternatives. As a result, the rate impacts from energy efficiency tend to occur sooner (even if the rate impacts are less over the long term, and even if average utility bills are reduced compared to supply-side alternatives). The short-term rate impacts associated with attaining very aggressive levels of savings (or even relatively modest levels of savings in states that are higher than has historically occurred) could pose a political challenge for state regulators, particularly in states that have seen significant rate hikes in recent years or whose rates are well above national averages. Across all states, these challenges are further heightened during periods of economic hardship. Concerns about rate impacts from energy efficiency programs have been institutionalized in a number of states, either through explicit caps on spending or rate impacts, or by the application of the ratepayer impact measure (RIM) test.²⁹ Meeting aggressive EERS targets in some states will likely require exceeding these caps or otherwise justifying rate increases, which may be feasible only in a robust, growing economy.

A number of states have established aggressive energy efficiency savings goals for future years that are well beyond current experience and practice in most leading states (e.g., annual incremental electric savings on the order of 1.5 to 2 % or more of retail sales). The challenge for these program administrators will be to design and implement programs that can achieve both deeper savings, on average, at customer facilities and have a broader reach in terms of market penetration over a sustained period of time. Service providers will have to achieve savings levels of 25–40 % of existing usage at customer facilities compared to current practice in utility customer-funded programs, which is typically in the 5–20 % range. Achieving higher market penetration rates will require programs to target and reach traditionally underserved markets (e.g., small commercial, multi-family, rental housing, moderate income households, non-owner occupied commercial facilities) in far greater numbers than current practice (MEEAC 2009). We are also likely to see increased attention to integrated delivery of electric and gas efficiency programs as well as coordinated delivery of energy efficiency, on-site renewable and combined heat and power, in order to reduce transaction costs and provide customers with tailored, customized service offerings.

In a significant number of states, energy savings in the large commercial and industrial markets are, in effect, beyond the reach of program administrators. This is especially true for gas efficiency programs as large commercial and industrial customers often purchase natural gas on the competitive market through alternative retailers, and may not pay into or be able to participate in gas utility customer-funded energy efficiency programs.³⁰ This “transportation gas” accounts for 46 % of total U.S. gas sales and 79 % of all commercial and industrial sales. The ability for many states to significantly increase gas efficiency program savings and spending may therefore hinge, to a large degree, on whether mechanisms can be developed (e.g., non-bypassable charges for program funding) to bring these customers and savings opportunities into the program fold.