Traditionally, utility shareholders and their utilities have a bias toward supply-side resources as opposed to demand-side reduction programs. The reason for this bias is obvious—supply-side resources, such as new production facilities, add to the utility’s rate base, generating additional earnings.
Conversely, decreased sales (from energy efficiency) reduce the need for supply-side assets, thereby diminishing the utility’s earnings opportunities and possibly leading to under-earnings between rate cases. Furthermore, reductions in demand may result in excess supply-side resources that are likely to be excluded from rate base because they do not meet the “used and useful” standard.
Consequently, energy utilities place a great deal of emphasis on sales or throughput. In short, increased sales increase the need for supply-side assets and more earnings.
However, there is a solution: Allow energy utilities to benefit from earnings rewards for demand-side reduction. From an earnings perspective, such a solution would place demand-side alternatives on par with supply-side projects.
The DOE recently recommended this solution in a March 2007 report.1 However, the department did not offer a methodology for calculating a supply-side earnings equivalent for a demand-side energy efficiency program. Such a methodology will help utilities develop effective conservation incentive programs.
Today, in response to growing demand for electricity and natural gas, many energy experts predict the United States will need hundreds of new electric generating plants and more emphasis on liquefied-natural-gas facilities (LNG) and new domestic sources of natural gas. Current projections anticipate an increase in U.S. energy demands by more than one-third by 2030, with electricity demand rising by more than 40 percent.2 Confronted with the growing demand for energy—as well as the environmental consequences of obtaining or producing that energy—some state regulators are entertaining new regulatory regimes to reward utilities for their energy efficiency activities.
In most cases, demand-side investments aren’t capital intensive and thus present few opportunities to generate shareholder earnings. In fact, most demand-side programs require a lot of cash, labor, and outsourcing that show up on the income statement as expenses. Furthermore, in the few instances when capital investments are necessary to accomplish a demand-side goal, that investment is short lived or becomes the property of the customer.
Even more frustrating for the utility are the risks associated with operating a demand-side program. For example, if savings goals are not met, regulators often impose penalties, negatively affecting earnings. When most of the readily available energy efficiency programs have been accomplished, meeting the utility’s energy efficiency goals becomes more difficult.3
A simple solution would give utilities a financial stake in saving energy. To accomplish this goal, regulators must adopt programs that compensate utilities for lost sales from energy efficiency and reward utilities for energy efficiency programs at the same level as earnings for supply-side rate-based investments and expenditures. The bottom line should make the utility indifferent between making a supply-side investment or spending money on energy-efficiency programs.
A number of rate-making approaches would compensate utility stockholders for managing and taking the risks associated with energy efficiency programs. For example:
• Include energy-efficiency expenditures in rate base;
• Award shareholders a fixed percentage of the energy-efficiency expenditures;
• Award shareholders a fixed percentage of the value of the energy savings;
• Increase the allowed return-on-equity rate when energy-savings targets are met or exceeded, and decrease the allowed return when targets are not met; and
• Capitalize the energy-efficiency expenditures and earn a return.
Each option above has its advantages and disadvantages, but a true supply-side equivalent would reward the utility for a successful energy-efficiency program based on the benefits or net energy savings—the savings on customers’ bills, minus the cost of the energy-efficiency program, which customers pay in utility rates.
Note the source of funds for the program is not at issue here. The funds are built into utility rates as part of expenses. The goal is to reward the utility for managing the energy-efficiency program and meeting or exceeding targets.
Such an approach can produce a win-win situation for both customers and shareholders. Customers enjoy the majority of the efficiency benefits, while shareholders earn cash rewards for encouraging and holding management accountable for developing and implementing cost-effective energy-efficiency related programs.
Shareholders, through the board of directors, will respond to earnings potential. If the utility loses money through energy-efficiency programs that, by definition, are intended to reduce sales, shareholders will tend to reward a management team that drags its feet in developing and managing energy-efficiency programs to their fullest extent. However, if shareholders see that equal and even greater earnings can result from a highly efficient and well-run energy efficiency program, the shareholders will pressure management to maximize the energy efficiency gains from every dollar spent on these programs. Within this economic incentive lies the beauty of having utilities manage energy-efficiency programs.
In utility rate-making, the benefit to the customer, if met by a supply-side asset, includes the return to the common shareholder as part of the price of the product—electricity and natural gas. Similarly, the benefit to the customer, if met by a demand-side program, should include a return to the common shareholder as part of the savings the customer enjoys by efficiently using that product.
This rationale supports the conclusion that total net benefits to energy consumers (the price of the energy times the quantity of energy saved, less the cost of the energy-efficiency program) should be shared with utility common shareholders at the same level shareholders would get from a supply-side, rate-based asset. If the utility can supply the benefit through demand-side efforts cheaper than that same benefit can be supplied through a supply-side alternative, so much the better.
Because regulators only authorize utilities to earn reasonable returns on supply-side investments contained in the ratebase, management focus on energy-efficiency solutions is more likely to achieve the regulator’s energy savings goals when the incentives to do so are equal to or greater than additional supply-side alternatives. Thus, the returns to shareholders on supply-side resources are a logical basis for determining the magnitude of incentives. Customers and society as a whole benefit from mechanisms that encourage utilities to achieve the greatest possible energy savings within approved budgets.
The earnings-equivalency model describes a tiered-rate, shared-savings mechanism. The earnings calculation would be based on the cumulative net energy savings benefits created by program installations from the first year through the year an incentive claim is made by the utility. The dollar value of earnings at any point would equal the product of the multi-tiered performance earnings rate (PER) and the performance earnings basis (PEB). Performance earnings begin after successful achievement of the minimum performance standard (MPS).
The threshold for eligibility to receive performance rewards should be set at a value between 0 and 100 percent of the assigned savings goals set by the regulator. The lower the minimum-performance standard, the higher the ultimate reward level will be. An MPS of 75 percent is suggested. Once a utility meets the pre-set level of its savings goal, the performance rate is calculated using the corresponding net benefits attained above this threshold.
An incentive mechanism will align utility incentives with customer interests, because utility shareholders will earn at least a portion of the earnings they would otherwise receive if the energy-efficiency expenditures were invested in utility plant. In return, customers will benefit from energy cost savings in excess of the energy efficiency expenditures.
The PEB is the net benefit to customers—that is, the net dollar amount customers will save on their energy bills through the energy-efficiency program. For example, if the customer saves 4 therms of gas because of the energy-efficiency program, and that gas is worth $2.50 per therm, the total savings is $10. If the program cost is $1 per therm, the PEB would equal $6.
Once the MPS is achieved, and until 100 percent of the goal is met, the reward earnings must be set at a pre-selected earnings rate, as a percentage of the PEB—in this case, 15 percent. To continue the previous example, if the customer saves 4 therms with a PEB of $6, for an achievement level below 100 percent, the reward to the utility would be 90 cents. Thus, the customer would see real dollar savings of $5.10.
Because most energy-efficiency programs last approximately 12 years, the earnings equivalency is calculated for a 12-year period (see Table 1, “Cost of Capital”). After considering the utility’s cost of capital, the ratebase for each of the 12 years must be calculated by considering both straight-line and accelerated depreciation. For the purposes of this analysis, the weighted state and federal tax rate is 40.746 percent, with a book life of 12 years and a tax life of 6 years.
With the ratebase known for each of the 12 years, simple math will provide the earnings associated with a $100 rate-based investment. Since the equivalent earnings are calculated for common equity only, the ratebase is multiplied by the weighted return on equity—5.24 percent. However, the utility must earn enough to pay the income taxes associated with the equity earnings to net 5.24 percent to the equity holder. Therefore, the before-tax weighted return on equity is used—8.85 percent.
The before-tax earnings results for the 12 years are then added to total $37. But these total returns must be discounted back to the present to calculate the total return amount anticipated from the $100 investment in current dollars. The discount rate used to move the dollars back through time is equal to the utility’s weighted average cost of capital—8.23 percent. This number is sometimes referred to as the discount rate. Its value is equal to the opportunity cost of money for the utility’s capital holders (see Table 3).
In this example, the utility’s common stockholders would expect to earn, in today’s dollars, $26 per $100 invested, or 26 percent of the amount invested. This result is the earnings equivalency and is comparable to the rate (PER) in the energy-efficiency incentive mechanism.
This percentage applies to the net benefits of the energy-efficiency programs, not to the costs of those programs. Therefore, the utility has the incentive to get the most efficiency it can from the program budget.
Some utilities rely on long-term power or natural gas contracts for all of their supply needs. When these contracts are present, a modified analysis might provide more desirable results. Specifically, the capital structure might change, because long-term energy contracts frequently are treated similarly to a long-term debt obligation when examining the financial risk of a utility. Generally accepted practices discount the amount of the energy contract to only a portion of its total value. A 20 to 30 percent discount is typical; for example, if the contract had a total value of $100, only $20 to $30 would be included in the capital structure (see Table 4).
The contract payment is assumed to be $100 per year for 12 years. This payment is like an annual debt payment because it is a fixed financial commitment for the duration of the contract. The NPV of the 12-year contract is $745. The discount rate, as stated earlier, is the utility’s weighted average cost of capital, or 8.23 percent. The NPV of the remaining contract payments is calculated for each year and summed together in place of taking the NPV of the whole stream of payments. This is necessary in case additional contracts are added during the 12-year period.
In this analysis, since no additional contracts are added, the result would be the same if one simply took the NPV of the whole stream of payments. The discount rate is equal to the cost of debt, or 5.75 percent, pursuant to the methodology from Standard & Poor’s. The cost of debt is used as the discount rate because the contract is treated like debt for purposes of calculating the risk factor.
As part of the rebalancing process, the equivalent amount of debt is removed in substitute for the contract. The rebalanced capital structure leads to an earnings equivalent value of 10.1 percent.
Most utilities rely on some, but not all, contracted energy to meet supply needs. The analysis must be modified to demonstrate the effect of partial reliance on supply contracts. Assuming the utility meets 50 percent of its energy requirements through its own resources and 50 percent through contracted energy, the 50:50 split is calculated by adding together one-half of the earnings resulting from the owned-supply option and one-half of the earnings result of the purchased-energy option. Therefore, to continue with the previous example, if the all-owned option results in a value of 26 percent and the all-contract option 15 percent, the 50:50 split is calculated as follows:
26%*0.5 + 12.6%*0.5 = 13% + 6.3% = 19%.
Other portions of owned resources and contracts can be substituted for the 0.5 multiplier above, to calculate the earnings equivalent percentage for different supply mixes.
In any case, adapting the earnings-equivalency model to fit the circumstances of a given utility can provide the incentives needed to place shareholders at an indifference point between a supply-side solution and an energy- efficiency solution. Ultimately, the benefits of these programs can be established on the same playing field, with fair and effective incentives for utility shareholders.
1. State and Regional Policies That Promote Energy Efficiency Programs Carried Out by Electric and Gas Utilities, A Report to the United States Congress Pursuant to Section 139 of The Energy Policy Act of 2005.
2. EIA, 2006.
3. Dalton, Matthew, “The Bottom Line – Utilities typically have had little incentive to reduce demand for their product. States are trying to change the math.” The Wall Street Journal, Feb. 12, 2007, p. R-4.