Regulated gas utilities have become increasingly enthusiastic about rate-design “decoupling” in recent years, as soaring gas prices have threatened the companies’ delivery margins and, ultimately, their earnings. Advocates of energy efficiency, conservation, and renewable energy also are strong proponents of decoupling mechanisms.
Utilities see decoupling as a way to avoid disincentives to promote conservation and energy efficiency by removing the need to increase throughput to maintain or increase profitability. Many regulatory agencies and consumer groups, on the other hand, view decoupling proposals as attempts to further insulate gas utilities’ profit margins from the vagaries of the marketplace while placing consumers at added risk of increased gas bills.
New Jersey has found a way to achieve conservation objectives while maintaining the regulatory objective for utilities to operate efficiently, without placing additional risk on consumers. The ultimate result is to share the conservation benefits between the utility and the ratepayers.
First, we need to define the term “decoupling” as used for ratemaking purposes. Decoupling can be viewed as any mechanism that severs the relationship between changes in throughput and revenues. Aside from a customer charge, the rates for most gas utilities are set per unit of energy used.1 If consumption rises, the revenues that flow to the gas utility also increase. Lower consumption results in less revenue received by the gas utility.
The bulk of delivery costs incurred by gas utilities, in contrast, is considered fixed rather than variable. The delivery charges of most gas utilities are set based on an assumed level of throughput. Changes from the assumed level of throughput will be reflected directly in the net revenue received by the gas utility. If costs remain the same, changes in throughput will either raise or lower the gas utility’s profit margin.
Thus, under traditional rate-design structures, gas-utility revenues increase when throughput increases and decrease when throughput declines. The level of throughput is affected both by changes in use by existing customers and the addition of new customers.2
One example of a partial-decoupling mechanism is the weather-normalization clause. This type of clause, which many states have used, provides for rate adjustments when temperatures deviate from a previously defined normal level. When colder than normal weather occurs, rates are adjusted downward to reflect the net revenue that would have been obtained under normal weather conditions. When warmer than normal weather occurs, rates are adjusted upward. The clause acts to reduce the volatility in the gas utility’s net revenue. The logic behind the clause is twofold: first, weather variations can result in significant changes in net revenues; second, the weather is outside the control of the utility. Decoupling proponents would expand this concept by compensating for any change in throughput, regardless of the cause, through a per-unit surcharge or credit.
Another form of decoupling is a rate design in which all of the gas utility’s fixed costs are reflected in a fixed rate. The so-called straight fixed-variable rate design, which the Federal Energy Regulatory Commission (FERC) developed for interstate gas pipelines, is one example of this form of decoupling. The shift to this rate design was done in order to decouple the price of the gas commodity from the cost of transportation. The straight fixed-variable rate design put all of the pipeline’s fixed costs in the demand charge, with only variable charges included in the commodity charge.3 FERC’s intent was to provide a level playing field to suppliers and better transparency for buyers when it effectively banned bundled sales by the interstate pipelines. Similarly, Atlanta Gas Light Co.’s delivery rates were changed to a fixed rate calculated on the basis of peak-day deliveries when it opted not to compete for sales with third-party marketers but to provide a delivery only service.4
State utility commissions find themselves facing a dilemma. Most state commissions have tended to embrace what has become known as incentive regulation,5 moving away from more traditional regulatory structures in an attempt to promote economic efficiencies. Decoupling might be viewed as a step back to “make-whole” regulation. At the same time, many state commissions vigorously have encouraged energy efficiency and conservation programs. For these efforts to be fully successful, the active cooperation of the regulated utilities is required. Gas utilities may be less likely to pursue energy efficiency and conservation programs aggressively if these efforts result in lower sales and reduced profit margins.
Measures promoting energy efficiency and conservation have benefited from a groundswell of support in recent years. Conservation is no longer considered just a “personal virtue” but is becoming an important prong in the nation’s energy policy. State governments, rather than the federal government, have led the way in this renewed focus on energy efficiency and conservation. The states, typically through their public utility commissions, have attempted to partner with utilities to promote energy efficiency and conservation.
In some cases states have undertaken this effort without substantial help from the utilities, but it generally is preferable to take advantage of the utilities’ unique knowledge of their customers’ usage profiles and the housing stock in their territories. Conservation efforts to date have achieved some degree of success. However, gas utilities may not wholeheartedly pursue energy efficiency and conservation incentives as long as earnings are tied to delivery throughput; hence the interest in decoupling proposals.
Ten states6 so far have adopted decoupling mechanisms for gas utilities in their jurisdictions. Connecticut considered decoupling mechanisms in a generic proceeding and determined that they would not be appropriate. The Arizona and Nevada commissions rejected proposals for decoupling. A decoupling proposal was withdrawn in Minnesota after the state attorney general raised both policy and legal impediments. On the other side of the coin, proposals to incorporate decoupling provisions are pending in at least 11 other jurisdictions.
Earlier decoupling experiments had occurred at electric utility systems in New York, California, Washington, Maine, Montana, and Idaho. New York and Washington discontinued these programs with the advent of electric-utility restructuring. The experiments in Idaho, Montana, and Maine proved generally unsuccessful as unforeseen events, e.g., economic turndowns, had unintended and adverse results for customers. Most of the recent emphasis on decoupling has been on the gas utility side, reflecting the large run up in wholesale-gas costs.7
The decoupling mechanism in Oregon (on Northwest Natural’s system) has been in effect since 2002 and recently was extended (and expanded) through 2009. This program has been touted as a successful example of how such programs can work. It is interesting to note, however, that except for a small-scale existing conservation program, these conservation programs have been undertaken without any active involvement by the gas utility. Instead, the company has been required to transfer its energy conservation programs to a selected independent entity approved by the commission. The Oregon commission also required that the company submit annual integrated resource plans that address both demand-side and supply-side economic efficiencies.
Baltimore Gas & Electric (BG&E) is a utility where a form of decoupling has been in place for several years. The BG&E mechanism was intended primarily to offset the effects of attrition as opposed to a vehicle to promote conservation. Reports are that the program “works” in that it has helped to stabilize revenues between rate cases and has not been burdensome to customers. In that case, the utility initially was required to reduce its base rates to reflect a lower return on equity (50 basis points) in recognition of the lower risk to the utility.8 Decoupling mechanisms adopted in most of the other states are of more recent origin and no track record exists on the benefits or deficiencies of each program.
Ken Costello, senior institute economist at the National Regulatory Research Institute, in his report on decoupling developments,9 listed a total of 19 arguments that have been made in favor of rate-design decoupling in proceedings around the country. He also lists a total of 17 arguments that have been made against a decoupling mechanism. He pared these points down to 10 arguments in favor of decoupling and 8 against decoupling that he considered strong arguments.
The arguments posed in favor of decoupling generally are in the category of what it would enable the utility to do. There is the now-familiar argument that decoupling would remove the utilities’ disincentive to promote energy efficiency linked to the hope that, should the utility then promote energy conservation, the results would benefit customers. Another contention is that other alternatives to decoupling are administratively unwieldy (lost revenue mechanisms tied directly to conservation results) or politically unpalatable (shift all costs to the customer charge or take into account declines in use per customer in a base-rate case). Other arguments center around the fact that, for the most part, sales levels are outside the control of the utility and the effects of a given change in sales can have large effects on utilities’ earnings. These latter arguments historically have been used to promote the idea that a mechanism is required to offset earnings attrition.
The arguments in opposition to decoupling are familiar. One set of arguments centers around the concept that extraordinary conditions must be shown before a “true-up” mechanism should be approved. A corollary argument is that it is inappropriate to single out revenues for true-up adjustments. Another argument is that, with a decoupling mechanism, it is less likely that other rate design issues will be addressed. Opponents also stress that the benefits to the utility are much more apparent than the benefits to the customer. Decoupling opponents further argue that the mechanism is overly broad and that other incremental options should be considered. Legal issues also have been raised about retroactive ratemaking and, more broadly, the potential for setting precedents that may work to the detriment of customers.
Proponents and opponents of decoupling have raised the traditional arguments many times in past controversies dealing with other rate issues in the utility industry.10 What appears to be missing in the present controversy is the idea of using incentive regulation to bridge the gap between the opposing views. It is necessary to step back and realize that, at the present time, gas-utility delivery charges may represent no more than 30 percent of the typical residential customer’s bill.11 The gas utilities’ profit margins are included in the delivery portion of the bill. The other 70 percent of the bill consists of gas-supply-related charges that are typically passed through to customers, with no profit margins included. Also, the twin issues of load loss and the need to promote conservation arise largely because of the significant increases in gas-supply costs. The judicious use of incentive regulation could provide the gas utilities with revenue stability; remove the barriers to focused conservation efforts; and provide customers with demonstrable benefits in terms of reduced gas-utility charges.
During the process of deregulation and restructuring, gas utilities’ gas-supply costs and delivery costs were disaggregated. Gas-supply costs at the wellhead (and gas imports) no longer are regulated at any level; they are set in the competitive market place. FERC regulates the transportation charges of interstate pipelines that serve gas utilities. While FERC has rate jurisdiction over interstate facilities, it has begun to deregulate the storage charges for new or expanded storage facilities. The bundling of gas supply, transportation, and storage charges to the gas utility usually is included in the utility’s gas-supply charge. Those charges typically are set out separately from the utility’s delivery charge. In most cases, the gas-supply costs incurred by the gas utility are considered pass-through costs over which the utility has little or no control. While state regulatory agencies generally do have the power to disallow gas-supply costs, it is done relatively rarely and usually only when egregious behavior on the part of the utility has been shown.
FERC’s restructuring orders in the 1990s recognized the effect of its mandated changes and the changing patterns of demand that were emerging by requiring pipelines to include provisions in their tariffs for what it termed “capacity release.” Before restructuring, capacity contracted for by gas utilities but not used by them on any given day could be sold on an interruptible basis by the pipelines. The pipelines’ rates included a “credit” for such sales that either was embedded in the base rate or included as an adjustment to the stated rates. FERC’s restructuring orders provided for capacity release. This allowed the gas utility to release capacity it had contracted for but did not need every day of the year.12 The revenues obtained by the gas utility were, in effect, credited to its cost of pipeline capacity. While originally envisioned as a sale of capacity only, some gas utilities began bundling the capacity release with sales of the gas itself. These off-system sales could be used to reduce the cost of gas supply to the utility, because although capacity releases are capped at the pipeline’s maximum FERC-regulated rate, off-system sales that bundle the commodity with the capacity essentially are priced at market levels constituting what has been called a “grey market.”
FERC’s capacity release and off-system sales provisions were meant to improve economic efficiencies by encouraging the efficient use of the utility’s gas-supply assets and by, hopefully, lowering costs. FERC, however, had no authority to require that such savings be passed through to the ultimate consumer. Since the program was voluntary, it could not require gas utilities to participate. State utility commissions also were limited in their actual if not theoretical powers. Many regulatory agencies were promoting customer-choice programs that allowed customers to choose a third-party supplier instead of purchasing the gas commodity from the utility. In many states, policies were developed that encouraged gas utilities to vigorously pursue capacity release and off-system sale programs by allowing the gas utility to keep part of the revenues from such sales or releases. The remaining savings would be flowed through to customers usually as offsets to charges fully passed through to retail customers.
This type of incentive regulation typically has worked to the benefit of all parties. The customers’ rates are lower than they would be otherwise. Gas utilities have the opportunity to enhance their bottom lines, and economic efficiencies are encouraged. In New Jersey, incentive regulation for gas utilities has been expanded to include storage activities, hedging activities, and capacity turn-back activities. Each incentive program is designed to get the gas utility to devote resources to activities that will reduce gas-supply prices to the customer. In return, the gas utilities receive the opportunity (not the guarantee) to improve their net earnings. The need for such programs became more apparent when it became clear that the customer-choice programs were not reaching as much of the market as originally envisioned.13 For the foreseeable future, gas utilities in most states likely will be required to provide gas supplies to a significant portion of their delivery markets.
New Jersey is unique in deciding that incentive regulation also can be used to address the issue of decoupling. The two goals that needed to be reconciled are the utility’s need for protection against potential load losses from decreased customer usage and consumers’ desires for reductions (or at least no increases) in their gas bills. New Jersey has created an incentive program designed to meet these criteria.
Gas utilities have more control over their gas-supply costs than is commonly thought. While it is true that no single gas utility, or group of gas utilities for that matter, can dictate the price of natural-gas futures on NYMEX, or the benchmark spot price at Henry Hub, gas utilities do have flexibility in terms of how they use the capacity they have contracted for with interstate pipelines. They also have flexibility with respect to where they purchase supplies and how they use storage. Unless constrained by state regulatory agencies, gas utilities also have the ability to enter into hedging agreements and use price arbitrage to lower prices. Many gas utilities have non-jurisdictional affiliates that engage in sales, transportation, and trading activities.
Contracting for pipeline capacity is far more dynamic than it has been in years past. The potential for capacity swaps and exchanges has increased significantly. The incentive for gas utilities to devote resources to these activities is directly related to the likelihood of earnings enhancement. New Jersey’s incentive programs recognize this and attempt to strike a balance between achieving lower costs to consumers while providing appropriate incentives to the gas utilities.
The New Jersey Board of Public Utilities (BPU) approved a pilot program for two of the state’s gas utilities last fall.14 The Conservation Incentive Program (CIP) reflects the goals discussed above. New Jersey Natural Gas Co. (NJNG) and South Jersey Natural Gas Co. (SJG) separately had filed proposed programs that might be considered generic “plain vanilla” decoupling mechanisms. The companies did pledge to aggressively focus their efforts on promoting conservation and energy efficiency in return for incorporating a decoupling mechanism in their rates. The proposal was deemed unacceptable in its filed form by both the board’s staff and the rate counsel.15 After a series of discussions, an agreement was reached that incorporated the elements that would truly make the program incentive based, but without a guaranteed recovery of revenue lost because of lower sales.
New Jersey’s program is a carefully developed incentive program that addresses each of the issues raised by proponents and opponents of decoupling. It allows gas utilities to adjust their delivery rates to account for load loss and conservation efforts; however, the adjustment is capped at the amount of verifiable supply cost reductions achieved by the gas utility. Gas utilities’ gas-cost reductions, if vigorously pursued, should exceed any cost increases from load losses. Further, the load-loss adjustment should provide sufficient incentive for the gas utility to undertake a focused conservation effort. The gas utility has an added incentive to promote conservation since reductions in load because of conservation should lead to further gas-supply cost reductions.
Once the basic parameters are set by the regulatory authority, the administration and costs of this program are left in the hands of the utility. It is in the interests of the utilities to have a streamlined program given that it is shareholder monies at stake. The increased stability in earnings resulting from the program should help to stretch out the time between rate cases. The program has sufficient flexibility so that necessary revisions can be made when and where necessary. The key to New Jersey’s program is that it aligns the interest of the utilities and the consumers.
At the same time, consumers are protected from rate increases as a result of this program. There also is a requirement to consider other rate-design issues as a condition of program approval.16 A rate of return or return-on-equity rate cap was placed on the utilities so that any adjustment that would result in earning more than a predetermined rate would be denied or deferred. The experimental nature of the program required a time limit (three years) to gauge its success in terms of conservation and impact on customer rates.
While it would be preferable that the program commence at the conclusion of a rate case where issues related to representative volumes and appropriate margins have been fully aired by the parties and agreed upon (or adjudicated), circumstances dictated the approval of the program outside of the rate-case convention. The companies are required to submit a detailed cost and revenue study before the initial adjustment will be put into effect. These checks are particularly important when the gas utility has healthy customer growth that, in some cases, can offset any net revenue loss from lower customer usage.
The key elements in the CIP can be summarized as follows:
1. The CIP calls for focused conservation efforts to achieve a long-term reduction in gas use.
2. The conservation efforts will include incentives to upgrade to more efficient equipment and to utilize automatic-setback thermostats.
3. Each company has pledged to use its entire staff as advocates for energy conservation.
4. The companies will use shareholder, as opposed to ratepayer, monies to finance and administer the CIP.
5. The companies will be recompensed for reductions in (non-weather related) usage only to the extent that those costs are offset by gas supply cost reductions that are long-term in nature and are chiefly linked to reductions in capacity costs paid to pipeline suppliers.
6. The amount of recompense is further limited by a cap on earnings for each of the utilities; if the surcharge related to lower use results in earnings in excess of the specified return-on-equity cap, the amount of pass-through is limited by the cap.
7. The program requires each company to undertake studies with respect to innovative rate-design alternatives, e.g., inverted supply rates and the potential for advanced metering or control equipment to reduce gas use.
8. The companies are required to make a “mini rate filing” prior to the initial application of a CIP surcharge so the board can be assured that the underlying distribution rates of each utility meet the just-and-reasonable standard.
The centerpiece of the CIP is its requirement that the companies reduce gas-capacity costs to receive any recovery of revenue losses from non-weather-related reduced use.17 This means the sales customer’s rate will not increase as a result of the CIP mechanism and actually may decrease. To ensure a net saving to the sales customer over the course of the three-year pilot program, the companies were required to flow through agreed-upon gas-supply capacity cost savings before any CIP surcharge would be applicable. These initial reductions will not be offset by future CIP surcharges. In each case the reduction in capacity-related supply costs amounts to about 10 percent of the annual fixed pipeline charges to each company. Each company has pledged to continue the initial level of capacity cost reductions for the duration of the pilot program, regardless of the CIP surcharge.
Although the program is in its earliest stages, there are some promising signs. The companies appear to be taking very seriously their pledge to refocus their efforts, on a company-wide basis, to encourage conservation and energy efficiency. The response to the mailings by the companies to its customers also has been encouraging. The companies’ sales customers already have received the benefits of the first year’s reductions in gas-supply capacity costs.
The eventual success or failure of the program will depend on whether the companies’ customers respond in such a way that long-term reductions in use occur. This will enable the companies to reduce and reshape upstream transport and storage capacity, thereby increasing efficiency and reducing costs. At a broader level, if these types of programs are successfully incorporated nationwide, gas-supply costs should fall and the need for imported supplies such as LNG would become less necessary. All in all, a win-win scenario for gas customers. Stay tuned for further developments.
1. Some gas utilities still utilize the so-called declining block-rate structure, where the per-unit rate decreases as use reaches a certain threshold level. This type of rate structure has become less common in recent years.
2. The above description of the dynamics of ratemaking is an oversimplification and is somewhat misleading since, over time, the direct nexus between throughput level and profits dissipates.
3. FERC and its predecessor agency, the FPC, traditionally had used either the Atlantic Seaboard rate-design method, which included one half of the fixed costs in the commodity charge or, during the natural-gas shortage era, the United rate-design method, which included 75 percent of the fixed costs in the commodity charge.
4. See Georgia PSC order in Docket No. 8390-U in July 1998 pursuant to Atlanta Gas Light’s election to open territory to competition pursuant to the Natural Gas Competition and Deregulation Act of 1997.
5. Incentive regulation recognizes that effective regulation from wellhead to burner tip may need to include economic incentives for utilities to achieve greater economic efficiencies. These incentives usually take the form of some type of share-the-savings mechanisms whereby ratepayers and the gas utility share in cost savings put in place by the utility.
6. The states that have adopted some form of decoupling mechanism include California, Indiana, Maryland, Missouri, New Jersey, North Carolina, Ohio, Oregon, Utah, and Washington.
7. California is the only state that has adopted decoupling for both gas and electric utilities. Decoupling programs began there in the late 1970s and early 1980s.
8. The requirement to reduce the allowed ROE was dropped in subsequent proceedings.
9. See briefing paper entitled Revenue Decoupling for Natural Gas Utilities issued April 2006. http://www.nrri.ohio-state.edu/NaturalGas.
10. The need for a mechanism to offset earnings attrition was pressed by utilities in the late 1970s and early 1980s when inflation and interest rates were soaring, resulting in “pancaked” rate filings.
11. Gas-delivery charges to commercial and industrial customers represent an even smaller percentage of those customers’ total bills.
12. A gas utility typically needs the full capacity it has contracted for or has on site, e.g., LNG, propane air facilities, for only a few days during the year. However, contracts with its pipeline suppliers usually require payment based on 365 days use per year.
13. For example, the New York Public Service Commission had set a target date of 2002 for when virtually all gas customers in the state would purchase their gas supplies from third-party suppliers. This goal has not been met and is not likely to be met in the foreseeable future.
14. A copy of the order approving the program and the stipulation setting forth the details of the program is available on the NJBPU’s Web site, at http://www.state.nj.us/bpu/home/home.shtml.
15. The rate counsel is a separate state agency charged with representing the consumers’ interest before the board.
16. Each company is required to perform an analysis as to the feasibility of introducing inverted rates for the gas-supply component of its charges.
17. Both companies had existing weather-normalization clauses. Adjustments for weather would follow the same procedure as was used prior to the CIP.