Re-starting the Big Build calls for revisiting cost-recovery mechanisms.
Sherman Elliott is an independent consultant and formerly was a commissioner on the Illinois Commerce Commission. Ralph Zarumba is a director in Navigant’s energy practice.
Many years ago when utilities were small and local control areas themselves, electric supply-side investing was relatively risk free. Growth was steady and predictable, as was regulatory recovery of investment to meet supply-side expansion. However, the recessions of the late 1970s and early 1980s, combined with inaccurate long-run load forecasts, led to overbuilding. In addition, changes in nuclear plant design mandated by the government after the Three Mile Island accident led to schedule delays and cost overruns. The regulatory response resulted in protracted prudence reviews and various approaches to mitigate rate shocks in rate proceedings.
Today, supply-side investing in the face of uncertainty is incredibly daunting. The investment drivers are no longer the same as replacement of aging infrastructure and compliance with environmental or public policy reforms have replaced growth and increasing demand. Furthermore, while the development of wholesale markets over the past 20 years has improved overall economic efficiency for the industry, it has also made investment choices increasingly complex. Government intervention in the marketplace via state-mandated renewable portfolio standards, ratepayer-subsidized clean coal plants, and, in certain cases, mandated wholesale bidding practices (i.e., bidding new capacity at zero cost), can have a dramatic effect on valuation of existing and potential new merchant supply-side investment. In addition, new supply-side capacity is significantly more expensive than the existing portfolio, even when adjusted for inflation (see Figure 1). Therefore, the replacement of existing supply will not only significantly affect the investment profile of the utility, but also will trigger significant rate impacts to consumers.
While the cost of new generation technologies has outpaced inflation, very few new mechanisms have been introduced to mitigate rate shock as these more costly investments have entered service. A survey performed by Navigant on behalf of the Ontario Energy Board in 2011 indicates that most mechanisms used to mitigate the rate shock from the introduction of large generating units existed, or were introduced or emphasized, during the last generation cycle of the 1980s.
Alternative ratemaking proposals—such as pre-investment funding—mitigate both the rate impact and financial implications for the utility.
Traditional Regulation vs. Pre-funding
In traditional vertically integrated states, regulatory treatments for capital-intensive investments that can trigger significant financial implications for both utility and ratepayer have been addressed using recovery methods such as construction work in progress (CWIP) or allowance for funds used during construction (AFUDC). In today’s uncertain risk environment, these traditional methods might not provide the financial certainty needed to see projects move forward. For example, the Federal Energy Regulatory Commission (FERC) recently added incentives for qualifying transmission projects—such as 1) increased rate of return; 100 percent recovery of CWIP; and recovery of all prudently incurred development and construction costs if any of the projects are abandoned or cancelled, in whole or in part, for reasons beyond the utility’s control. While the provision of these incentives hasn’t been without controversy, it’s clear that the risk landscape has changed and become more uncertain for multi-year, capital intensive projects, and the FERC felt the need to provide these incentives to drive investment in this sector. Pre-funding is one approach that can mitigate risk for both the utility and ratepayer.
The traditional definition of a utility revenue requirement provides for a return on and of investment plus operation and maintenance expenses. Since rate base is depreciated over time, the revenue requirement also decreases over time. Therefore, a significant rate increase is triggered when an asset is replaced. Rate base is included in the revenue requirement equation when construction is complete, or in the case of CWIP, gradually throughout the construction cycle.
In contrast, pre-funding allows the utility to begin collecting the revenue requirement in advance of the construction of the asset. Collection of the revenue requirement would occur after the need is identified—generally several years before the introduction of the asset to service—as opposed to when the construction of the asset is completed. Unlike CWIP, pre-funding would occur before the utility expends any funding for a specific asset.
Pre-Funding Pros and Cons
Pre-funding of utility capital programs provides several key advantages, and also some challenges.
Most notably, recovery of the revenue requirement addition before the asset enters service allows for a more gradual rate impact. The impact is more gradual for two reasons. First, collection of the revenue requirement addition begins before the asset enters service—or perhaps even before a decision on a specific technology occurs—when the existing revenue requirement is still very low due to the depreciated value of current assets. Second, the time period over which the asset may be recovered is potentially extended.
Also, pre-funding better reflects the value of the generation portfolio, via the level of tariffs charged to customers. The revenue requirement equation generally recovers more capital costs at the beginning of an asset’s life than at the end of it. The paradox of the revenue requirement approach to collecting costs is that the value of a generating asset is typically greater at the end of the asset’s life. This is simply the result of the revenue requirement approach to cost recovery—a book value accounting treatment that reflects the depreciated asset, while the value of a generating unit’s replacement or extension-of-life costs are based upon the market value of replacement at the end of the unit’s life. Therefore, the traditional approach compares the book value of a fully depreciated unit, based on 30- to 40-year-old costs, to a new unit at today’s inflated prices. By contrast, the pre-funding approach provides for a better matching of costs with the values those assets provide to consumers.
Additionally, by virtue of pre-funding, utilities can obtain greater certainty of cost recovery, which provides risk assurance to the investment community. Specifically, reducing rate impacts by spreading costs over a longer timeline can significantly reduce upfront ratepayer backlash toward the needed investment, and therefore diminish regulatory uncertainty. This approach will decrease the cost of capital to both utilities and the customers they serve.
Finally, pre-funding allows utilities to defer decisions on specific investments until the time is right. Once the resource need is established and acknowledged, pre-funding mechanisms can be introduced before committing to a specific technology, for example. This allows for greater flexibility in meeting the need, and reduces project abandonment risk due to changes in public policy, demand or technologies.
Amid these benefits, however, utilities will encounter some challenges when seeking pre-funding treatment for capital projects. One issue involves concern about inter-generational transfers. Opposition should be expected from consumers that feel that inter-generational transfers are occurring—e.g., they are paying for a generation unit which will not serve their needs, but instead the needs of future consumers. It could be argued, however, that pre-funding balances the inter-generational transfer issues that already exist through the use of traditional ratemaking techniques.
Another significant question regards the allocation of costs between various customer classes for the pre-funding portion of the revenue requirement. Namely, which customer classes are driving the need for an investment? This is further complicated if the investment is intended to replace existing assets or to meet environmental or public policy requirements. The cost allocation issue only exists, however, if an allocated, or embedded cost-of-service approach is applied. Approaches relying upon a marginal cost revenue study won’t experience any changes in cost allocation from the addition of the pre-funding revenues.
An argument also could be made that pre-funding would capture a negative return—i.e., offset to rate base. An escrow arrangement or regulatory asset can be established whereby the money collected from the pre-funding is set aside in an isolated accounting environment. Any return on these funds would increase the level of funds available to reduce any future rate increase.
Another challenge involves forecasting demand. As noted in the opening paragraph, inaccurate long-run load forecasts led to overbuilding in the late ’70s and ’80s. Those concerns are still valid today, and are further amplified by the hodgepodge of deregulated retail and wholesale markets juxtaposed against traditional vertically integrated utility jurisdictions. Other factors include the potential impact of smart grid technologies, gains in energy efficiency, climate change, and the respective effects of all these factors on overall electric demand.
Utilities also might face questions about finance and accounting details and contingencies. For example, if a utility becomes insolvent in the time period between collection of the funds and construction of the asset, customers could be at risk of losing the funds without receiving the benefit of the useful asset. The incidence of utility bankruptcy is the United States, however, is very rare, and regulators do have the ability to restrict pre-funding mechanisms to credit-worthy utilities.
Tax liabilities present further questions. Generally the Internal Revenue Service requires that income taxes be paid at the time revenue is received by the utility. In the case of pre-funding, the tax liability associated with the asset will begin with the pre-funding as opposed to when the asset is introduced to service. Therefore, the benefit of the pre-funding is somewhat reduced acceleration of the tax liability.
Finally, capital cost differentials can raise questions among some customer groups. Generally, the customer’s cost of capital differs from that of the utility. Low-income residential customers will often have a cost of capital significantly higher than a regulated utility. The argument can be made that these customers will experience a reduced benefit to the pre-funding because their higher cost of capital will reduce the benefit they will receive from the pre-funding mechanism. However, this same argument can be made for virtually any investment made by a utility.
Preparing for the Inevitable
Given the possibility that the United States might need to replace 72.5 GW of generation capacity in the coming years, pre-funding could significantly mitigate the rate increases faced by many utilities. However, the implementation can also trigger a number of legitimate questions and concerns that must be adequately addressed by the utility, customers, and regulators. Failing to prepare for the inevitable will lead to more significant implementation problems. Well-prepared utilities should start exploring options sooner rather than later as pre-funding might be one of the better options available.
1. Approaches to Mitigation for Electricity Transmitters and Distributors, Navigant Consulting, Ltd., 2011.
2. See for example, Desert Southwest Power LLC, Docket No. EL10-54-000, wherein the FERC order grants combined ROE adders of 150 basis points, 100 percent CWIP in rate base, abandoned plant cost recovery, and a hypothetical capital structure of 50 percent equity and 50 percent debt.
3. U.S. Department of Energy—Energy Information Administration, Annual Energy Outlook 2012.