Among a host of arguments for and against RD is the question of upside for consumers.
Ken Costello is senior institute economist at the National Regulatory Research Institute at The Ohio State University. Contact him at email@example.com. The views and opinions of the author do not necessarily express or reflect the views, opinions or policies of the NRRI, NARUC, or NARUC member commissions. This paper is a shortened version of Ken Costello, Revenue Decoupling for Natural Gas Utilities, The National Regulatory Research Institute, Briefing Paper (06-06), April 2006.
Under standard rate-making, gas utilities have a strong incentive to promote gas sales between rate cases. Owing to regulatory lag, whenever sales grow, earnings increase because of the prevailing rate structure that includes most of a utility’s fixed costs in its volumetric charge. Conversely, when a utility sells less gas it recovers a smaller portion of its fixed costs. State commissions have endorsed this rate design over several decades, primarily on grounds of equity. Over the past few years, at the requests of gas utilities in rate filings, volumetric charges have included less fixed costs to reduce the utility’s risk from sales fluctuations. Still, with few exceptions, utility shareholders shoulder financial harm whenever sales decline between rate cases.
In response to the sales repression triggered by market forces and the regulatory goal in several states for utilities to promote and fund energy efficiency initiatives, several gas utilities recently have proposed to their state commissions a “tracker” mechanism that severs the link between their earnings and sales. Both gas utilities and conservationists aggressively have fostered this ratemaking mechanism, generically labeled in this article as revenue decoupling (RD).1 While retaining adequate earnings is the driving motive of gas utilities, conservationists view revenue decoupling as necessary for the removal of utility resistance to energy efficiency.2
At the time of this writing, sixteen gas utilities in nine states have RD mechanisms. Just since the middle of last year, commissions approved RD mechanisms for Vectren Energy Delivery in Indiana, Cascade Natural Gas and Avista Utilities (both in Washington), Questar Gas in Utah, New Jersey Natural Gas, and South Jersey Gas. Other gas utilities with RD include Baltimore Gas and Electric,3 Washington Gas Light in Maryland, the three major California gas utilities and Southwest Gas in California, Northwest Natural in Oregon,4 Cascade Natural Gas in Oregon, Vectren Energy Delivery in Ohio, and Piedmont Natural Gas in North Carolina. RD proposals by gas utilities are pending in Arizona, Arkansas, Colorado, Delaware, the District of Columbia, Kentucky, Minnesota, New Mexico, New York, and Virginia.
The rejection or withdrawal of RD proposals has occurred in a few states, including Arizona, Minnesota, and Nevada.5 For example, in early 2006 the Arizona Corporation Commission rejected a proposal by Southwest Gas (called a Conservation Margin Tracker or CMT).6 The commission reasoned, “There is conflicting evidence in the record as to whether the recent level of declining per-customer usage will continue into the foreseeable future, and whether conservation efforts are the direct cause of Southwest Gas’ inability to earn its authorized return from such customers.” The commission added, “The company is requesting that customers provide a guaranteed method of recovering authorized revenues, thereby virtually eliminating the company’s attendant risk. Neither the law nor public policy requires such a result nor do we decline to adopt the company’s CMT in this case.” The commission opined that the issue of declining usage per customer “should be fully explored as part of a broader investigation of usage volatility and margin recovery.”7
The Impetus for Revenue Decoupling
Two factors explain the heightened interest in RD for gas utilities. Both relate to ongoing energy conservation resulting from the combination of high natural-gas prices and utility-funded energy efficiency initiatives. According to an AGA study, natural-gas usage per household (normalized for weather) has declined by more than 20 percent since 1980. Major reasons for this include progressive increases in energy-efficient gas appliances and home construction. The study predicts this decline will continue during the next several years, although at a lower rate than since 1980.
Many, if not most, U.S. gas utilities have encountered declining usage per household over the past several years. Some gas utilities have experienced particularly sharp declines. For example, Questar Gas in Utah estimated that, adjusting for weather, its typical residential customer currently uses about 35 percent less natural gas than in 1980. Another reason for utilities’ interest in RD is the growing intent of state commissions and other groups to have gas utilities promote energy efficiency.
Table 1 provides the fundamental arguments in support of revenue decoupling presented by gas utilities and conservationists before state commissions. As a primary argument, RD can help to promote energy efficiency by eliminating the incentive of a utility to increase sales between rate cases. One contention is that if a state commission wants a utility to “sell” energy efficiency, rate-making practices should not discourage a utility from selling less gas. It is both unfair and counterproductive to require a utility to promote energy efficiency when detrimental to its shareholders.
Another argument in favor of RD is that small changes in gas sales significantly affect a utility’s earnings. Gas sales also are largely outside the control of a utility, in addition to being highly volatile from year to year, with weather as the major factor. Since almost all of a utility’s short-run, non-gas costs are invariant to changes in sales, a mechanism such as RD that adjusts for sales fluctuations has apparent merit.
An Overview of Major Arguments
Several arguments lie on both sides of the RD debate. The discussion below summarizes my observations of the major issues surrounding RD.
• Consumer groups disfavor the risk-shifting aspect of RD and the possibility that rates will rise higher than otherwise in the short term. Some industrial groups question whether utilities should be involved at all in promoting energy efficiency; they also generally prefer new rate designs that allocate more of the fixed costs to the customer charge. Consumer groups might support RD if it becomes part of a settlement agreement where a utility agrees to specific concessions. These concessions can include a commitment by the utility to spend a fixed amount of money on promoting energy efficiency, a transfer of monies to an independent entity to administer conservation programs, and agreement by the utility to lower its authorized earnings because of reduced risk.8
• As a tracker, RD meets the minimum criteria applied in the past by state commissions in other areas of a utility’s operation with approved trackers. Historically, “trackers” such as RD are justified in accordance with a three-prong threshold test: (1) the designated activity largely lies outside the control of a utility; (2) variations in the outcome of the activity have a non-trivial effect on a utility’s earnings; and (3) the actual outcome inevitably deviates from the baseline projections (i.e., projections are always wrong). When applying this test to the activity “sales,” it seems defensible to apply a tracker on sales. Indisputably, sales are largely external to a utility’s control and inescapable sales fluctuations significantly can affect a utility’s earnings.
For some state commissions, the legality of RD as well as its compatibility with policy precedent may be an issue. In Minnesota, the state’s Department of Commerce argued that the RD proposal by Xcel violates state statutes, which in its opinion do not provide a statutory exception for a true-up mechanism that adjusts rates based on the level of gas use per customer. In North Carolina, two commissioners dissented from a commission order approving an RD mechanism for Piedmont Natural Gas by arguing, among other things, that the mechanism violates North Carolina law by reflecting retroactive rate-making.9 The dissenters also argued that as a matter of policy, state commissions have approved true-up mechanisms only under “extraordinary circumstances,” which they contend did not apply in the case of declining gas use per customer. In first considering an RD proposal, a state commission should review its legal authority in addition to policy precedent in allowing for an earnings “true-up” between rate cases based on actual sales departing from “baseline” sales.
• Applying generally applied standards for rate-making (for example, Bonbright’s eight criteria10 for setting rates), RD has four salient features: (1) increased opportunity for a utility to earn its authorized rate of return (but no guarantee since costs can inflate beyond test-year levels);11 (2) more revenue stability; (3) removal of disincentives for a utility to promote socially desirable energy efficiency initiatives; and (4) elimination of a major contentious aspect of a general rate case.
On the other side, RD potentially has some negative attributes: (1) creation of a public-acceptability problem (for example, consumers complaining that a utility can increase rates simply because its sales have fallen); (2) the occurrence of more volatile and unpredictable rates;12 (3) less incentive for a utility to offer innovative service options and rates and, generally, to promote gas sales when economical; (4) introduction of another tracker mechanism to rate-making that can shift risks to consumers; and (5) the reduction of economic efficiency.13
• The limited ex-post evidence on RD for gas utilities points to positive results. From the perspective of a senior staff member of the Maryland Public Service Commission, the Baltimore Gas and Electric RD mechanism (Rider 8) has achieved the intended goals since its inception around eight years ago. Specifically, it has: (1) produced more stable and predictable revenues for the utility between rate cases by accounting for revenue “attrition” from declining gas use per customer; (2) reduced the volatility of gas bills, especially under cold weather conditions; and (3) allowed for the continuation of current rate designs that provide an incentive for consumers to conserve and that are non-discriminatory to low-usage customers. The staff person also added that the RD mechanism is easy for the utility to administer and the commission to monitor. Overall, the staff member concluded that the mechanism has “[fulfilled] more regulatory objectives with fewer shortcomings than other alternatives.”14
A 2005 study conducted for Northwest Natural concluded that: (1) by reducing revenue fluctuations, the Distribution Margin Normalization (DMN) mechanism has reduced the utility’s business and financial risks; (2) DMN margin adjustments largely can be attributed to the effect of price changes, with economic activity and the utility’s funded energy efficiency efforts having a statistically insignificant effect on use per customer; (3) the utility’s focus has shifted from marketing to promoting energy efficiency; (4) service quality did not decline; and (5) most of the risk reductions experienced by the utility were eliminated rather than shifted to customers. Making several recommendations for improving Northwest Natural’s DMN mechanism (for example, full decoupling), the study concluded, “The positive effects of DMN outweigh the negative effects.” To date, this study represents the most comprehensive and analytical ex post investigation of a RD mechanism for gas utilities.15
• Alternatives to RD in achieving the same objectives (e.g., revenue stability, promotion of energy efficiency) might be preferable, as RD is a more blunt approach than most alternatives. These alternatives include: (1) removal of fixed costs from the volumetric charge; (2) weather-normalization adjustments; (3) declining-block rate design; (4) a multi-year forecast horizon in setting new rates; and (5) a targeted incentive plan allowing a utility to profit from carrying out socially desirable energy efficiency initiatives. A state commission might want to assess the desirability of these alternatives to RD, recognizing their shortcomings.16
If a state commission is concerned that a utility will not have a reasonable opportunity to earn its authorized rate of return, short of filing a rate case, it might want to consider an earnings-sharing approach. This mechanism has the attractive feature of treating symmetrically costs and revenue deviations. Under RD, it is conceivable for a utility to have concurrently both: (1) its base rate adjusted upward between rate cases in response to a decline in sales per customer; and (2) its actual rate of return exceeding the authorized level because of actual expenses reduced below the test year estimates. A shortcoming of an earnings-sharing mechanism is that the utility’s shareholders still could suffer from lower sales to the extent they absorb a portion of the realized earnings losses.17 Thus, the utility would have a disincentive, as under standard rate-making, to foster energy efficiency.
• In considering RD, a state commission might want to first consider whether a gas utility should be in the business of selling natural gas and delivery service or, more broadly, of selling energy services, which include energy conservation. If the latter is preferred, then RD becomes a more tenable rate-making tool.18 If not, then a commission should assess RD solely in the basis of the “declining gas use per customer” phenomenon.
Regulators should not expect a utility to support energy-efficiency initiatives when shareholder interests deteriorate. A collision course leading to unintended consequences is inevitable under standard rate-making from requiring a utility, whose earnings directly relate to the level of sales, to initiate sales-reducing actions.
• A state commission needs to address several issues in implementing RD. These include: (1) scope of the mechanism in terms of factors (for example, weather and price elasticity)19 to be included in determining sales adjustments; (2) rate classes affected; (3) frequency of rate adjustments; (4) the need for a rate-adjustment cap (for example, limit annual rate adjustment to 5 percent of the base charge); (5) treatment of revenues from new customers; (6) treatment of any cost-of-capital effect; (7) pilot or permanent status;20 (8) accounting for overall utility earnings by considering cost changes over time; (9) proper forum for consideration (rate-case filing, special docket); (10) accounting for quality-of-service effects; and (11) adjustment to specific rate components (for example, the volumetric charge or the customer charge).
State commissions and consumer groups rightly have raised concerns about some of the negative features of RD. One generally expressed misgiving with RD is that, while necessarily beneficial to the utility in reducing its risk, it might be inimical to consumers. RD certainly helps to preserve the financial integrity of utilities and motivate them to be less opposed to promoting energy efficiency. Whether RD benefits consumers is less certain. It is partially for this reason that the debate over RD mechanisms at the state level, to date, has centered on conceptual and theoretical issues, specifically on whether RD offers consumers any advantages over standard ratemaking and is compatible with prevailing regulatory objectives.
Many skeptics view RD as akin to taxing consumers for the benefit of protecting utilities from financial harm when revenues fall short of some predetermined level. Although this perception arguably is a misrepresentation, it may be the heart of the equivocation by state commissions and consumer groups to RD. At the least, the concern with RD may require a utility to appease the doubters by committing to energy efficiency or by agreeing to a downward adjustment of its authorized rate of return as compensation.
Overall, the jury is still out on how state commissions will rule on RD proposals in the future. If commissions view gas utilities as purveyors of energy efficiency services, they will be more receptive to a mechanism that would protect utility shareholders from lost sales in addition to removing any disincentive for a utility to support those presumably socially desirable services. After all, if RD at worst results only in slightly higher rates (which seems likely), but achieves large benefits—or at least the perception of large benefits to consumers from utility-funded energy efficiency activities—the public will look more favorably upon the commission and utility in their endorsement of this emerging ratemaking mechanism.
1. Gas utilities have assigned different names to their RD proposals: Conservation Margin Tracker, Conservation-Enabling Tariff, Conservation Tariff, Conservation Rider, Conservation and Usage Adjustment Tariff, Conservation Tracker Allowance, Margin per Customer Balancing Provision, Delivery Margin Normalization, Usage per Customer Tracker, Customer Utilization Tracker.
2. The financial community also has looked favorably upon revenue decoupling in reducing a utility’s risk and improving its financial stability.
3. The Baltimore Electric and Gas mechanism (Rider 8) measures test-year base-rate revenues after adjusting for any change in the number of customers from the test-year level. The mechanism adjusts test-year revenues by accounting for the net number of customers added since the test year. The difference between actual revenues collected and the recalibrated test-year revenues determines the rate adjustment. In effect, the mechanism is a “true-up” that accounts for customer growth as this element could offset lower per-customer gas usage that the mechanism is intended to capture.
4. In August 2005, the Oregon Public Utility Commission extended Northwest Natural’s RD mechanism to four years and modified the mechanism by allowing for 100 percent decoupling (previously it was 90 percent), excluding weather effects.
5. In Minnesota, the state’s Department of Commerce and Office of Attorney General challenged an RD mechanisms proposal by Xcel. The utility subsequently withdrew the proposal as part of a rate-case settlement. In 2005, the Nevada Public Utilities Commission rejected an RD proposal by Southwest Gas, arguing in part that the proposal would constitute a major change from current ratemaking practices and before it can be justified “more recognized alternatives” (such as changes in rate design and more frequent rate filings) should be applied to the perceived problem (i.e., reduced earnings from less-than-expected gas sales) (Nevada Public Utilities Commission, Opinion, Docket No. 04-3011).
6. Southwest Gas proposed a “Conservation Margin Tracker” in anticipation of a continuation of the past trend of declining gas use per customer.
7. Arizona Corporation Commission, Opinion and Order (Decision No. 68487), Feb. 23, 2006.
8. In Oregon, the upgrading of Northwest Natural’s Standard & Poor bond rating occurred shortly after the commission approval of an RD mechanism.
9. The majority, however, argued that the RD proposal does not violate state statute against retroactive ratemaking since it represents an approved formula as part of a utility’s rate structure used to true-up an estimated rate. (See North Carolina Utilities Commission, Order Approving Partial Rate Increase and Requiring Conservation Initiative, Docket Nos. G-9, Sub 499, G-21, Sub 461 and G-44, Sub 15, Nov. 3, 2005, at 21.)
10. The eight criteria for a desirable rate design are: (1) simplicity, understandability, public acceptability, and feasibility of implementation; (2) uncontroversial as to proper interpretation; (3) effectiveness in providing the utility with adequate revenues to recover costs; (4) year-to-year revenue stability; (5) rate stability; (6) fairness among customer classes; (7) avoidance of undue price discrimination; and (8) economically efficient in giving customers proper price signals, for example, in not over-consuming a utility’s service. These criteria can conflict, with no rules of ranking offered. It is often difficult, if not impossible, to satisfy all of these criteria (for example, public acceptability and efficient pricing); almost all real-world ratemaking outcomes reflect compromises among the different regulatory objectives. Bonbright also identified the four primary functions of public utility rates as capital attraction, efficiency, demand rationing, and income distribution. (See James C. Bonbright et al., Principles of Public Utility Rates, 2nd Edition, Public Utilities Reports, Inc., 1988; the first edition, authored solely by Bonbright, was published in 1961.)
11. On the other hand, RD also would reduce the opportunity of a utility to over-earn, which may explain why some gas utilities do not support RD.
12. The monthly or yearly rate adjustments subject to RD likely would be small relative to the total delivered price of natural gas and to other factors affecting price (such as fluctuations in purchased gas costs).
13. One source of economic inefficiency stems from the expectation that RD would cause a utility to shift farther away from the minimum point of its short-run average cost curve, assuming that the mechanism will result in lower sales than otherwise. Since gas distribution is essentially a fixed-cost operation, higher average cost would result from reduced sales, since by definition average cost equals total cost divided by sales.
RD also makes the utility indifferent to increasing sales even when economical. For example, if the base rate is 50 cents per therm and the short-run marginal cost for gas distribution service is zero, under an RD mechanism the utility would have no incentive to increase sales even though it clearly would be economical to do so. This outcome is contrary to the universal corporate objective of spreading fixed costs over additional sales to produce greater operational efficiencies.
Another conceivable source of economic inefficiency derives from the presumption that a utility with an RD would have little or no incentive to modify its rate design by removing more of its fixed costs from the volumetric charge, which if nothing else would remove what some analysts consider a major source of prevailing price inefficiency in the utility sector. With RD protecting a utility’s financial condition from sales volatility, there would be little payoff to the utility from initiating any subsequent change in rate design that removes fixed costs from the volumetric charge.
14. See Calvin Timmerman, “Monthly Rate or Revenue Adjustments: Regulatory Perspective,” presentation at the Platts Rate Case and Pricing Symposium, Oct. 25, 2004, and Calvin Timmerman, “LDC/EDC Revenue Decoupling,” presentation to the 2006 MACRUC Commissioner Only Strategic Planning Session, April 3, 2006.
15. See Christensen Associates, A Review of Distribution Margin Normalization as Approved by the Oregon Public Utility Commission for Northwest Natural, March 31, 2005.
16. For example, higher customer charges could (1) lead to customer complaints about “minimum” bills during the low-use months, and (2) disproportionately impact low-income/low-usage customers. A straight fixed-variable rate design for gas distribution service is rare in the United States. At the time of this writing, Xcel in North Dakota and Atlanta Gas Light are the only gas utilities currently having this rate design. In the case of Xcel, the company originally proposed a partial decoupling rider but was withdrawn as the parties to a settlement agreement concurred in shifting the fixed-distribution costs to a monthly basic service charge. (See North Dakota Public Service Commission, Northern States Power Co. Natural Gas Rate Increase Application, Order Adopting Settlement, Case No. PU-04-578, June 1, 2005.)
17. As an illustration, if the sharing arrangement is 50-50 (with no “dead band”) and assuming a decline in sales of one percent attributable to the response of consumers to higher prices, a resulting reduction in the rate of return on equity of 100 basis points would be split evenly between consumers and utility shareholders. Thus, the utility absorbs a loss of 50 basis points. Earnings-sharing mechanisms, labeled alternatively as “revenue (or return) stabilization mechanisms,” are currently in place for some gas utilities in the United States, including utilities located in Alabama, Louisiana, Mississippi, and South Carolina.
18. In theory, utility involvement in energy conservation requires the existence of market or regulatory failures. Specifically, (1) the incorrect pricing of natural gas and its delivery exists because of regulation or market-power conditions, (2) the failure of natural gas prices to reflect environmental damages and other external costs, or (3) the availability of inadequate information to consumers reducing their demand for energy efficiency. Proponents of utility funded energy efficiency initiatives argue that some or all of these conditions hold.
19. With the dramatic increase in natural-gas prices over the last few years, and even with only a small price-elasticity response by consumers, the effect on a utility’s earnings can be non-trivial.
20. A pilot has the benefit of allowing for refinements of the mechanism periodically and of terminating a mechanism that exhibits undesirable outcomes.