|
|||||||||||||
To shed light on this issue we start by reviewing the mechanisms by which decoupling influences rates. We conclude that decoupling does shift some risk onto customers during a weak economy, but that the policy has become a scapegoat for other ills, and that many opponents' objections are misplaced. A simplified model of a decoupling mechanism demonstrates that an economic downturn is likely to be accompanied by a moderate increase of electricity rates, though it's also noted that much of that may occur whether or not a decoupling mechanism is in place. An examination of monthly average electricity prices of 378 utilities over the past four years indicates that the expected rate increase from decoupling is on the same scale as the month-to-month fluctuations experienced by the average utility as a result of rate cases, fuel cost adjustments, seasonal adjustments, and other factors. Looking to a real-world electric experience, Maine abandoned its decoupling mechanism amidst an economic downturn in the early 1990s and provides a good reality check for the modeled results. Ultimately, factors beyond the mechanism itself led to the suspension of decoupling in Maine.
The Anatomy of a Policy
Revenue decoupling is a regulatory framework that removes the link between a utility's energy sales and its revenues. Decoupling mechanisms accomplish this by guaranteeing that a utility will receive exactly the annual revenue required to cover its fixed-cost obligations, including a fair return on invested capital. The basic idea is simple: If a utility sells less energy than expected this year, rates will increase next year to put revenues back on track (conversely, rates go down if the utility sells more energy than anticipated).
The most heated opposition to decoupling has traditionally come from consumer advocates. They rightly point out that in keeping revenues constant as energy sales decline, it is necessary for energy prices to increase. Rather than focusing on the utility bill savings achieved by customers using energy more efficiently, they argue that customers failing to do this will be harmed should rates increase.
Energy sales -- and therefore under decoupling, rates -- are dependent on a number of factors including population growth, weather, efficiency programs, building codes, consumption patterns, and broader economic conditions.
How Decoupling Does (and Does Not) Influence Rates
To put the conclusions of this paper into perspective, it's worth taking a moment to discuss the extent to which decoupling does -- and, more importantly, does not -- place an extra burden on ratepayers.
Regulated utilities are entitled to earn a fair return on prudently invested capital (the so-called rate base). The rate base and rate of return help determine electricity prices alongside variable fuel and other costs. Absent decoupling, most utilities can request an adjustment to rates when revenues are falling short of the revenue requirement and they do not foresee that situation reversing. In this way, external factors like weather and the economy can result in downward or upward rate adjustments. Several examples of the current economic downturn affecting electricity prices were cited in a January 29, 2009, article from the Wall Street Journal which noted that "weaker revenues are pushing some power companies to ask regulators to raise electricity rates." The article mentioned Florida Power & Light and Avista as seeking rate increases due to revenue shortfalls.
Ordinarily the process of filing and resolving a rate case takes well over a year and any shortfalls that occur during that period are absorbed by utility shareholders. Where decoupling can shift some burden onto ratepayers is during that interim period that it takes a utility to recognize a revenue shortfall, plan, and conclude a rate case. Essentially, decoupling puts into place a process for guaranteeing that the utility will always receive exactly the amount that the regulators have determined it is entitled.
Decoupling may also have an indirect effect on rates by influencing the rate of return on prudent investments, although whether this happens is more a result of regulatory interpretation than of anything inherent to decoupling. Broadly, if decoupling reduces the utility's financial risk by providing a stable revenue stream, then regulators may authorize a lower rate of return. This would decrease electric rates. In its report, "Aligning Utility Incentives with Investment in Energy Efficiency," the National Action Plan for Energy Efficiency Leadership Group notes that more research is needed to better understand the effect of decoupling on utilities' cost of capital.
Boiling it down, a utility will request a rate increase when it perceives this to be in its best interest. The debate about the rate effect of decoupling is largely a matter of timing and who will get to keep whatever money is up for grabs during the interim.
Modeled Rate Impacts
To simulate the effect that a decline in electric retail sales would have on rates under decoupling, we used the Energy Efficiency Benefits Calculator created by the National Action Plan for Energy Efficiency. The model indicates that an economic downturn resulting in three years of static sales would result in average rates that are 1.5 percent higher than they would have been had sales grown at an annual rate of 1.6 percent (the model's default setting). Naturally, a 5 percent decline in sales was more dramatic, resulting in rates 6.9 percent higher after three years (Table 1). The model's default settings were used for the most part, but the energy-efficiency factor was excluded.
Energy Efficiency Benefits Calculator developed by the National Action Plan for Energy Efficiency was used to model the effect of decoupling on rates under two different scenarios of retail electricity sales that could occur during a recession. Specifically, we looked at rates when year-over year sales were static as well as when they declined by five percent.
Table 1: Modeled rate changes under decoupling
| Percentage Growth in Electricity Sales | Percentage Change in Rates over Base Case After 3 Years |
| 0 | 1.5 |
| -5 | 6.9 |
To gain perspective on the repercussions of slow electricity sales resulting in 6.9 percent higher rates over three years, we looked at the EIA Form 826 monthly filings of 378 utilities from January 2004 through November 2008. We examined average residential rates, inclusive of fuel adjustments, seasonal adjustments, purchased power, and other variable charges applied to end-use customers.
We found that at some point during this period, 56 percent of utilities experienced an electric price increase greater than 10 percent over the previous year. Monthly electricity price fluctuations were even larger, with more than half of utilities experiencing a month-to-month price increase greater than 15 percent at some point over those four years (more than half also saw a decrease larger than 10 percent). This monthly volatility probably resulted largely from seasonal price adjustments, purchased power, and fuel adjustment clauses that pass those costs directly to customers.
At 6.9 percent, the estimated increase in electric prices likely to accompany an economic decline under decoupling turned out to be smaller than the 10 to 15 percent price increases actually experienced by a majority of utilities over the previous four years. Most customers are familiar with the level of electricity price volatility that would be likely to coincide with decoupling.
Why Was Decoupling in Maine Unsustainable?
A decoupling pilot for Central Maine Power (CMP) started in May 1991 was abandoned before its short, three-year duration had expired. Ultimately, decoupling was politically untenable and rising electric prices were at the core of the problem. Although this is a vivid example of decoupling coinciding with price increases, a closer examination suggests that the regulatory regime was more scapegoat than culprit. The account -- if not necessarily the conclusions -- of Maine's decoupling experience revisited here was first published in an October 1995 article in The Electricity Journal by Leslie Hudson, Stephanie Seguino, and Ralph Townsend.
The pilot began at an inauspicious time as New England had been experiencing a recession since late 1989, and 1991 happened to be the first year that CMP's energy sales had decreased -- if only slightly -- since 1949. The economic slump continued and sales in 1992 increased by only eight-tenths of a percent, which was still lower than public utility commission forecasts had anticipated. Per the decoupling plan, the resulting revenue shortfall was passed along to customers through higher rates. It is important to note that practically any other regulatory approach would also have led to higher rates amidst these economic conditions. Indeed, in a rate case completed in early 1991, CMP had requested a rate increase as a result of the economic downturn. In this regard, the mistake appears to have been mostly political.
By the end of 1991, CMP filed for another rate increase because an annual 1 percent cap on decoupling-caused rate increases combined with declining revenue had quickly resulted in an accrual of revenue owed to the utility that was expected to continue growing over several years. Rather than raise rates during a recession, the regulators and CMP agreed that the utility would withdraw the rate case and the foregone revenues would be allowed to accrue. Essentially, a political decision was made to allow the decoupling mechanism to act as a credit card, postponing a needed rate case until a more opportune time. As unpopular as a rate increase would have been, the accruals resulting from this bargain became just as untenable.
Ultimately, several factors collided to increase rates. The economic downturn and a mild winter decreased sales, while an unexpected decision by the Securities and Exchange Commission mandated that large accruals be recovered within two years. The result was a rate increase on the order of 6 to 8 percent within two years. At the same time, three other factors unrelated to decoupling combined to raise rates up to 50 to 60 percent for some residential customers: Fuel and seasonal rate adjustments, as well as a rate design change, apportioned more responsibility for recovering the utility's fixed costs from industrial customers onto residential customers.
Keep It Simple
The decoupling mechanisms described here do shift some weather- and economy-related risk onto consumers. It's possible to control for both of these influences in order to reassign risk to the utility. Incorporating economic- and weather-impact models into the decoupling formula (such as Idaho currently does for weather) may redistribute risk back to the utility. Whether this gain is worth the complexity added to the already complex process of utility ratemaking probably differs from jurisdiction to jurisdiction.
How important are these things to address? Fuel adjustments and seasonal rate changes contribute greater rate volatility than is expected of decoupling mechanisms yet they are widespread and uncontroversial. Another aspect, often overlooked by opponents of decoupling, is that this regulatory mechanism ensures that customers will see lower rates on the upside of an economic boom. Absent decoupling, there are few reasons to think that this will happen.
Resources
Short Term Energy Outlook (PDF), Energy Information Administration (2009)
Maine's Electric Revenue Adjustment Mechanism: Why It Fizzled, The Electricity Journal (1995)
Aligning Utility Incentives with Investment in Energy Efficiency (PDF), National Action Plan for Energy Efficiency (2007)
Aligning Utility Interests with Energy Efficiency Objectives: A Review of Recent Efforts at Decoupling and Performance Initiatives, American Council for an Energy Efficient Economy (2006)
Utilities Scramble as Electricity Bills Fall, Wall Street Journal (2009)
Surprise Drop in Power Use Delivers Jolt to Utilities, Wall Street Journal (2008)
