Issues: Oil & Energy

Introduction and Overview

Electric-utility restructuring has threatened a loss of momentum in energy-efficiency and renewable energy development, with significant environmental and economic penalties. In the United States, electricity production accounts for one-fourth to two-thirds of emissions in the following categories: mercury, nitrogen oxides, particulates, sulfur dioxide, and carbon dioxide. Throughout the world, efficient electricity services are increasingly critical to quality of life and healthy economies.

Many states have been learning how to mobilize utilities to unleash efficiency improvements, whose average cost in some instances has been driven below that of displaced fuel at power plants. Progress within the electricity sector also has been encouraging, if less universal, for low-income services, renewable energy development, and long-term research. At the same time, a consensus is emerging that the integrated utilities themselves represent an obsolete industrial form. The resulting uncertainty has left the companies wary of all long-term investments, while reinvigorating longstanding tensions between managers who want, respectively, to maximize generation-asset utilization and end-use efficiency.

This article presents both short- and long-term responses to the restructuring challenge. An immediate action, appropriate regardless of regulators' ultimate destination, is to reclassify utility investments with strong environmental and equity dimensions as "universal system benefits charges", which cannot be bypassed by customers who remain connected to the electrical grid. Regulations issued in April of 1996 by the Federal Energy Regulatory Commission (FERC) have reinforced state authority to take such action and minimized prospects for evasion.

The next step will be voluntary separation of distribution and generation businesses, removing increasingly evident conflicts of interest and releasing both enterprises to follow very different paths and incentives. Generation companies will concentrate on minimizing commodity costs and improving production efficiencies in an open market without price regulation. Utilities' investments in end-use efficiency and other sources of environmental and equity benefits will shift to regulated distribution companies. These companies' revenues should be independent of electricity consumption and their profits should be tied in part to the performance of their energy-efficiency portfolios. These predictions all are crucial to reconciling economic and environmental goals, for an industry and society that cannot afford failure on either count.

Electricity Production and the Environment

The Environmental Protection Agency recently reassessed electric utilities' contributions to major categories of air pollution. The results reaffirm in the strongest terms that this remains an industry "affected with the public interest":

In 1993, power plants were responsible for 72 percent of all sulfur dioxide (SO2) emissions in the U.S. They also contributed 33 percent of all nitrogen oxides (NOx) emissions and 32 percent of all emissions of particulate matter (PM). Of the nation's emissions of mercury, a toxic heavy metal, 23 percent came from power generation in 1993 ... Moreover, power plants represent the source of 36 percent of all [human] 1993 emissions of carbon dioxide (CO2), a dominant greenhouse gas. ¹

EPA's stark recitation should eliminate any question whether electricity is "just another commodity;" as Secretary of Energy Hazel O'Leary likes to point out, that view is about as plausible as the proposition that "oxygen is just another gas." Electricity production remains the most important term -- for both good and ill -- in the principal environmental debates of our time. For example, the Northeast cannot solve its urban ozone problem without curbs on emissions from Midwest coal generators.² The world cannot stabilize its greenhouse gas emissions without repeating the initial successes of utilities' energy-efficiency investments in California, New England and New York.³ Anadromous fisheries and hydropower have reached a supreme moment of mutual crisis in the Pacific Northwest.

As these examples show, the electricity industry potentially is implicated in environmental solutions as well as problems. It is thanks principally to supportive utilities that wind generation is poised to compete successfully with fossil units. When Southern California Edison and Pacific Gas & Electric recently drove the cost of saved electricity below the price of the fuel it displaced, they struck a blow equally for regional and global economies.

Moreover, as in politics, some of the best stories are local: like Mission Energy's discovery of an economical way to make commercially useful steam from Brooklyn's municipal wastewater, potentially saving enough freshwater initially to serve 19,000 residents. Lawrence Berkeley Laboratory has invented an inexpensive, high-efficiency ultra-violet light application that disinfects rural water supplies: add batteries or village-scale renewable generation and you have a powerful and affordable antidote to some of the world's principal killers of children.⁴

Efficiently applied kilowatt-hours are increasingly crucial to a decent standard of living everywhere on earth. From both environmental and economic perspectives, enormous benefits potentially attend better ways of making and using electricity. This article asks whether utilities can continue to help the rest of us take advantage of such opportunities, both during and after the industry's imminent restructuring.

Electricity Solutions: Recent Lessons

From 1980-1995, literally hundreds of electric utilities proved that they could invest productively in end-use energy efficiency improvements. The success stories cut across the full spectrum of size and ownership structure; a common thread was a strongly committed senior management, driven by some combination of customer demand, resource need and financial incentives.

In their evaluations of utility performance from 1990-1994 alone, California and New York regulators found $3.6 billion in net life-cycle benefits to their systems.⁵ Realization rates -- the ratio of confirmed to predicted savings -- were up sharply.⁶ By 1994, the average cost of saved kilowatt-hours to California utilities had dropped below two cents per kilowatt-hour, and Southern California Edison was announcing an energy-efficiency portfolio that would be cost-effective even if credited solely with the value of unburned fuel.⁷ Annual savings equivalent to one percent of system consumption were being achieved by companies that had in no sense tested the limits of their capacity.⁸

The Pacific Northwest also is among the nation's efficiency leaders. By 1995, Montana, Idaho, Oregon and Washington had secured almost 900 average Megawatts of savings, acquired at an average cost to utilities of between 2 and 2.5 cents per kilowatt-hour. "Conserved energy totaled over 50,000 gigawatt-hours in 1995, with a retail value to consumers of $2 billion." ⁹

The rise of "market transformation" programs gave utilities new means for adding savings at reduced cost. Instead of promoting the most efficient equipment already on the market through rebates, utilities began rewarding manufacturers for getting better products into distribution channels. The first of these initiatives, the Super Efficient Refrigerator Program, created mass-produced appliances that outperformed the previous "state of the art" by 25% while eliminating ozone-depleting chlorofluorocarbons; just a few years earlier, such an achievement had been widely declared incompatible with the laws of physics.

Utilities' very ability to achieve these results attests one of the best documented features of energy markets: formidable market barriers continue to obstruct efficiency improvements that are highly cost-effective by almost any measure. As Section IV will explain, restructuring has been reinforcing some of those barriers by introducing uncertainty about future energy price structures. Independent energy-service companies have never been in greater need of support and assistance from friendly utilities -- nor have they ever been more vulnerable to hostile interference.

Two lessons from recent history bear particular emphasis in charting utilities' future involvement in energy-efficiency investment. The first is the need for less costly and administration-intensive mechanisms to certify and reward performance. This is a widely shared concern of both utility managers and regulators; it grows in part out of the relatively high start-up costs of the evaluation enterprise, reinforced by adversarial tensions associated with utilities' self-certification of the very empirical results that generate the companies' own rewards and penalties.

Enduring solutions here require independent certification boards, applying increasingly refined, uniform and inexpensive techniques. Major advances in the near future should include the establishment of the first such certification system in the Pacific Northwest,¹⁰ and the Department of Energy's imminent publication of industry-wide guidelines for energy-efficiency evaluation (prepared under the direction of Dr. Arthur Rosenfeld).

Also increasingly clear is the value of a utility role that focuses on expanding competitive opportunities for third-party providers, rather appropriating such opportunities for the utility's principal or exclusive benefit. There is no natural monopoly involved in the actual delivery of energy-efficiency improvements; the rationale for utility intervention involves the use of credible information and financial incentives to overcome market barriers that obstruct cost-effective technologies. If utility efforts go beyond removal of those barriers, unregulated competitors will have little difficulty in voicing or establishing a grievance. These principles appear to have achieved wide acceptance among all parties concerned; few if any serious disputes are pending.

The Challenge of Restructuring

Utility restructuring per se is in no sense hostile to improved energy efficiency. There can be no question, however, that the industry's overall commitment has flagged in the face of uncertainty about the schedule and outcome of the restructuring process.

Part of the problem is simply a reallocation of the most talented managers and planners to restructuring issues (reminiscent of a similar "brain drain" in the 1980s as utilities grappled with the threat of nuclear cost disallowances). Also important is management's determination not to incur any more strandable costs at a time when tens of billions are already at risk. To most industry leaders, energy efficiency looks like one more societal invitation to put capital at risk today only to run the risk of repudiation tomorrow; renewable energy and most research and development falls into the same suspect category.

Finally, energy-efficiency initiatives seem at cross purposes with utilities' efforts to prepare for cutthroat generation competition by cutting commodity costs. This imperative appears incompatible with the historic practice of recovering system-wide efficiency investments as part of the bundled electricity charge; too many "unbundled" commodity competitors are in the wings (if not already on the stage). Costs associated with utilities' low-income services also look like dead weight in such a market, and the rest of the environment/equity agenda does not fare much better. Systemwide investments raise utilities' prices, however minutely, compared to competitors without comparable responsibilities.

Restructuring threatens these prospects from another important direction as well, which is independent of developments within utilities. To the extent they actually emerge, retail commodity markets in electricity are likely to favor prices with higher fixed-to-variable cost ratios than is typical of current practice. In these emerging markets, utilities and suppliers alike will strive for more rapid and secure recovery of capital investment in generation, which is most readily obtained by making more of customers' bills independent of fluctuations in their electricity use. Options include take-or-pay contracts, higher fixed (and lower variable) charges, and combinations of both. To the extent that these strategies dominate, a result will be reductions in rewards for reducing consumption -- not necessarily because electric services are cheaper, but because the price structure has changed and more of the bill is now independent of kilowatt-hour usage.

Such price structures would be particularly devastating to energy service companies, which depend in significant part on "shared savings" contracts with customers. In a world of lower variable costs, less would be available to share. That is also an inhospitable setting for new renewable energy generation, which historically has depended on long-term contracts signed in anticipation of relatively high "avoided costs." Even if its sponsors can secure direct access to retail customers, renewable energy faces bleak immediate prospects in spot markets dominated by continental surpluses of fossil generation. At some point spot market prices will rise, but investors are impatient and renewable energy companies urgently need tangible opportunities to deliver value to customers.

Solutions

Utility investments that deliver systemwide economic, environmental and equity benefits can be sustained with a non-bypassable, usage-based "system benefits charge" on electric distribution services. The charge also can become a vehicle for delivering performance-based incentives associated with these investments, and for decoupling utilities' revenues from fluctuations in retail sales volumes. The result is a versatile cost-recovery and incentive system that is consistent with all plausible restructuring outcomes.

Washington's Utilities and Transportation Commission recognized as much in December 1994 when it approved Washington Water Power's proposal for a usage-based distribution charge to recover energy-efficiency investments; the Idaho Public Utilities Commission followed in March 1995.¹¹ The California PUC formally endorsed and broadened this mechanism in December 1995 in a rate case involving the Pacific Gas & Electric Company.¹² And the New York Public Service Commission's inquiry into restructuring produced a May 1996 decision that a "system benefits charge [will] be set at approximately the level of current utility expenditures" for energy efficiency, in order "to provide a funding source during the transition, and possibly over the long term, for public policy initiatives that are not expected to be adequately addressed by competitive markets." New York's system benefits charge also will cover research and development and low-income services.¹³

This "new" cost-recovery approach requires no change in current rates, rate structures or cost allocations among customer classes. Utilities today typically recover the equivalent of system-benefits charges from all retail customers based on electricity usage; they would continue to do so under this proposal. State commissions would simply be making explicit that those who use integrated power systems may not bypass their share of contributions to system benefits by designating a new supplier of kilowatt-hours over the integrated grid.

The focus on distribution charges avoids potential disputes over state jurisdiction. Ours is an era characterized by expanding federal involvement in electricity regulation under authority of the Federal Power Act. But states clearly retain the right to oversee and charge for the use of distribution services. The boundary between federally regulated transmission and state regulated distribution had long been blurred, but remarkable clarity came at last in an April 1996 decision of the Federal Energy Regulatory Commission.

The FERC adopted what might be termed a "functional" definition of state jurisdiction, as opposed to a physical definition framed in terms of wires or voltages. Physical definitions invite unproductive investment aimed solely at evading state regulation and shifting systemwide costs to other users. FERC chose instead an approach that highlights the distinction between the end-use services that account for retail electricity consumption and the commodity purchases-for-resale that are reserved for federal regulation:

First, . . . we believe that states have authority over the service of delivering electric energy to end users. Second, through their jurisdiction over retail delivery services, states have authority not only to assess stranded costs but also to assess charges for stranded benefits, such as low-income assistance and demand-side management.¹⁴

Such charges can be "based on usage (kWh), demand (KW), or any combination" that state regulators find appropriate,¹⁵ and no customer in a regulated utility's service territory can avoid them:

[E]ven where there are no identifiable local distribution facilities, states nevertheless have jurisdiction in all circumstances over the service of delivering energy to end users. Under this interpretation of state/federal jurisdiction, customers have no incentive to structure a purchase so as to avoid using identifiable local distribution facilities in order to bypass state jurisdiction and thus avoid being assessed charges for stranded costs and benefits.¹⁶

Exercising state authority to approve system-benefits charges is entirely consistent with the concept of energy efficiency as a cost-effective resource for utilities and their customers. Indeed, it is precisely the generalized economic and environmental benefits delivered by cost-effective conservation that help justify its inclusion in a system benefits charge. Moreover, utilities need not own all (or any) of the generation that serves their customers in order for utilities' conservation investments to reduce demand for fuel combustion and plant construction. Adopting a system benefits charge would change the characterization of cost recovery for conservation and other system-benefits investments, but would not repudiate the rationales underlying those investments.

Nor would the charge create any new incentive to bypass electrical systems. Complete physical bypass of an integrated grid is both rare and costly; shifting the basis of cost recovery for "stranded benefits" certainly will not make it any more attractive than it is now (it just reclassifies costs that already are being recovered). And most talk of "bypass" today involves the retail wheeling variety, which does not involve physical disconnection from the grid and would not prevent collection of usage-based distribution charges.

That is not to say that regulators should be indifferent to the size or elements of universal system-benefits charges. It is not my aim to identify here a promising new way to fund higher education or pad municipal payrolls. These universal charges should be reserved for investments that can be shown to represent potential "stranded benefits" for electrical systems. To the extent they come to be seen as pork barrel subsidies, they will attract growing and ultimately successful opposition from powerful customer constituencies. The charges will endure to the extent that electricity customers continue to see tangible value delivered back to their electricity systems. States can and should continue to build in strong performance-based incentives to deliver system value at least cost.

System-benefits charges should usher in a new era of full disclosure for all major elements of electric bills. Some analysts are concerned that political opposition will emerge immediately in the wake of line-item listings for low-income services, research and development, renewable energy additions and energy-efficiency investment. No such outcome is likely as long as other expenditures get comparable treatment. Consider a plausible California utility bill under the new regime:

The numbers would vary from place to place, but in every case the first five items collectively would yield much higher numbers and more skeptical scrutiny than the last four.

Through the use of universal system-benefits charges, it should be possible to achieve productive investments in efficiency, renewable energy and low-income services during a period of transition for the electric industry. Of still greater importance, however, is utilities' ultimate destination and its implications for environmental and equity goals.

Much of the restructuring ferment involves speculation about the breakup of vertically integrated utilities and the opening of transmission grids to a host of new competitors. The era of vertical integration clearly is ending, although the final result is likely to grow out of cooperation among all (or most) concerned, rather than coercive state action.¹⁷

The fundamental problem with the vertical structure is the increasingly obvious embedded conflicts of interest. The most obvious involves electrical generation. Today's utility-owned generation companies will want to maintain as much market share as possible among a customer base that prominently includes their current retail service territory; yet it is difficult anytime soon to imagine an industry structure that does not have distribution companies choosing or at least influencing the portfolios of generation that serve many if not all of their customers. The Texas PUC's widely praised initial restructuring proposal serves to underscore the point.¹⁸ If the distribution business is helping in any way to select the winners in an increasingly competitive generation marketplace, distribution's ownership of some of the competitors all but ensures continuing discord.¹⁹

From an environmental perspective, an equally obvious conflict may be even more important. Any company with substantial generation assets will build a corporate culture based in part on maximizing utilization of those assets. Such a culture is difficult to reconcile with a corporate imperative to exploit all cost-effective electricity saving opportunities. History shows that incentives to do both can be embedded within the same integrated entity. But objectives of both generation and end-use efficiencies might be served better in more focused, less schizophrenic institutions.

For all of these reasons, I expect many states soon to be welcoming independent electricity distribution, transmission and generation companies. Decisions about system operation will be independent of generation ownership; every power plant will have to compete continuously for access to the integrated grid. "Utilities" as we know them now will be giving way to a new set of institutions. History will credit the Niagara Mohawk Company with the first formal application -- on October 6, 1995 -- to separate its generation and distribution businesses.²⁰ Soon after, California and Massachusetts regulators strongly endorsed such voluntary separations.²¹

Will society continue to value and support utility-system investment in energy savings that cost less than displaced generation, transmission and distribution? The undiminished public interest in exploiting such savings has already been outlined. An obvious issue, however, is whether the resource-based justification for utilities' efficiency investments will be a casualty of restructuring. Will distribution companies be selecting a mix of generation and demand-side resources for their service territories, or will that function be contested competitively in a new marketplace? It is important to recognize that this issue is entirely independent of utilities' degree of vertical integration; orchestra conductors do not have to own any or all of the instruments for which they are responsible.

Some believe that such matters can be resolved through contracts between individual buyers and sellers, based on responses to energy-commodity prices. Others contend that, just as multiple decisionmakers cannot operate a transmission system reliably, they are not well equipped to orchestrate a diversified mix of resources for meeting a healthy economy's electrical service needs at the lowest possible life-cycle costs.

In other words, like grid control, resource-portfolio management may be a classic "natural monopoly" that cannot be broken up without imposing significant costs on customers and society generally. Quantitative analysis by the Northwest Power Planning Council indicates that valuable resource diversification can be achieved, and investment in reserves and duplicative generation can be minimized, under effective systemwide portfolio management.²² Critics respond that generation portfolios need not be uniform across each distribution company's service territories, and that competing portfolio managers should have access to some or all retail electric-service customers.²³

If regulators opt for multiple portfolio managers, they can still retain distribution companies as energy-efficiency investors by using the "universal system-benefits charges" described above. Efficiency investments then would be weighed not against the distribution company's own generation alternatives, but against those offered to retail customers by competing suppliers. Tests for cost-effectiveness could still be performed, based on the extensive price information (including futures markets) that proponents of increased generation competition promise to provide. Loss of the resource-acquisition rationale for distribution companies' efficiency investments would not remove the other justifications reviewed above, which reflect the public interest in securing inexpensive economic and environmental benefits.

Wherever electric power systems retain distribution companies either as portfolio managers generally or energy-efficiency investors specifically, their regulators should create financial incentives to minimize life-cycle costs. For example, the portfolio managers' or distribution companies' profits should not be linked to their customers' consumption of kilowatt-hours. For either entity, profitability should at least in part reflect net benefits delivered through verified efficiency improvements.

These principles have been a source of discord in the integrated-utility context; critics have contended that they detract from what should be a single-minded focus on minimizing electricity-commodity costs by maximizing asset use. Also controversial have been the regular, albeit modest, adjustments in commodity prices that "decoupling" systems imply.

Once distribution and generation are separate, however, the debate changes completely. Generation will compete in an increasingly deregulated commodity marketplace; generation revenues and profits will be linked to commodity sales and all competitors will have strong incentives to minimize rates. But distribution businesses no longer will have any involvement in commodity production; regulators will want them to concentrate on strategies that minimize customers' electric-service bills -- including but not limited to energy-efficiency improvements. Freeing distribution revenues from fluctuations in commodity sales will mean regular small adjustments in distribution prices, but commodity rates will be unaffected.

Conclusion

The electric service industry is moving toward the separation of integrated utilities into at least three independently owned and operated enterprises, encompassing generation, transmission and distribution functions. Generation will become a highly competitive business that ultimately will operate without traditional price regulation, while transmission and distribution remain natural monopolies with regulated prices. This article seeks to help manage the transition to de-integration, and to ensure that participants have incentives to minimize the life-cycle costs of the reliable electricity services that a healthy economy needs.

Notes

1. Comments of the U.S. Environmental Protection Agency to the Federal Energy Regulatory Commission, Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities, Aug. 7, 1995, at p. 7.

2. More specifically, as the Environmental Protection Agency noted in a recent letter to the Council on Environmental Quality:

Current NOx emissions in the eastern half of the United States from electric power plants are approximately three million tons during the summer ozone season. EPA believes that based on the best available scientific information, it will be necessary to reduce these NOx emissions to below one million tons during the ozone season, in order to prevent violations of the ozone health standard in downwind areas in the Northeast and Upper Midwest.

Letter from Carol M. Browner, EPA Administrator, to Kathleen A. McGinty, Chair of the Council on Environmental Quality, May 13, 1996, pp. 2-3.

3. For a recent review of the strengthening scientific consensus on the urgency of this objective, see W. Stevens, Human Role in Global Warming Confirmed, Experts Say, New York Times, September 10, 1995, at A1; and the follow-up lead editorial, Global Warming Heats Up, New York Times, September 18, 1995.

4. In a May 6, 1996 press release announcing LBL's selection as a finalist for its annual Award for Technological Innovation, Discover Magazine stated that the new technology "could save the over 400 children around the world who die each hour from drinking contaminated water." (Emphasis added.)

5. The California share of net benefits is $2.2 billion, based on PUC decisions and documents cited in P. Miller, Presentation Before CPUC Full Panel Hearing on Restructuring, R. 94-04-031 (Sept. 8, 1995). The New York estimate is taken from Public Service Commission records, which are reported in a September 1994 Energy Conservation Fact Sheet prepared by the Pace University Center for Environmental Legal Studies.

6. For example, the Oak Ridge National Laboratory's summary review of more than fifty recent ex post studies of program impacts found, on average, that measured savings in California were within 10 percent of predicted levels. M. Brown & P. Mihlmester, Summary of California DSM Impact Evaluation Studies, Oak Ridge National Laboratory, October 1994. Moreover, this summary is highly conservative in its reporting of overall averages, because the "realization rates" for individual programs were not weighted to reflect savings from each program:

If the realization rates were weighted by energy savings, the mean would be expected to be greater. This is because the [commercial, industrial and agricultural] programs have higher realization rates and tend to have higher savings than the residential programs, yet in the unweighted calculation all are counted equally. Thus, the overall mean of 1.12 (0.93 without the four highest outliers) could be viewed as a conservative calculation of the ratio of actual savings to anticipated savings. Id. at p. x.

7. Data on the average cost of electricity savings in California appear in E. Hirst, R. Cavanagh & P. Miller, The Future of DSM in a Restructured U.S. Electricity Industry (July 1995: publication forthcoming in Energy Policy). Edison's projection of conservation costs below fuel costs came in the company's 1994 General Rate Case, Application No. 93-12-025, Ex. 37-A, p. 7; Tr. at pp. 1198-99 (Gudger) (1994).

8. E. Hirst et al., note 7 above, p. 2.

9. The Energy Foundation, Sustainable Energy: Boosting America's Prosperity While Reducing the Threat of Global Warming, p. 18 (December 1995) (citing Northwest Power Planning Council data).

10. This initiative will be a joint project of the Northwest Power Planning Council, the Bonneville Power Administration, and numerous Northwest utilities. See U.S. Senate Committee on Appropriations, Senate Report, Energy and Water Appropriations Act of 1996 (June 27, 1995), p. 121 (endorsing "regional technical forum on conservation program evaluation and verification").

11. Washington Water Power (WWP) filed its distribution charge proposal with the Washington Utilities and Transportation Commission on October 25, 1994; Commission approval came in December (DSM Tariffs UE-941375 & UE-941377). The Idaho Commission endorsed a virtually identical WWP proposal in Order No. 25917, Case No. WWP-E-94-10 (March 6, 1995).

12. The Commission decided to include in the charge the costs of PG&E's energy efficiency investments, decoupling adjustments, low-income rate discounts, and some research and development expenses. See Decision 95-12-055, pp. 15-17 (December 20, 1995).

13. See New York Public Service Commission, Opinion No. 96-12, pp. 56-57 (May 20,1996).

14. Order No. 888, 18 C.F.R. Parts 35 and 36, pp. 436-37 (April 24, 1996).

15. Id. at p. 436.

16. Id. at pp. 436-37.

17. See, e.g., Massachusetts Department of Public Utilities, D.P.U. 96-100 (Aug. 16, 1995), pp. 26-27: "The Department continues to believe that mandatory divestiture of generation or any other category of assets is not desirable or necessary at this time") (emphasis in original).

18. Chairman Pat Wood's September 1995 "Proposal for Achieving Transmission Access and Full Wholesale Competition" vests the portfolio function squarely with electric distribution businesses.

19. Moreover, compared with incumbent generators, a much higher fraction of new entrants are unaffiliated with utilities (and utility affiliates increasingly focus their marketing outside the host service territory). National and state policymakers are likely to be particularly receptive to ensuring a fair competitive opportunity for generation base additions, which typically will be cleaner and more efficient than incumbents.

20. Niagara Mohawk Corporation, Public Service Commission Case No. 94-E-0098, 94-E-0099, Phase II Multi-Year Electric Restructuring and Retail Access Proposal, October 6, 1995.

21. See California PUC, Decision 96-01-009 (January 10, 1996), p. 100 (creating financial incentives for voluntary divestiture of generating assets); Massachusetts Department of Public Utilities, D.P.U. 96-100 (May 1, 1996), p. 27 ("[V]oluntary divestiture of generation over time provides the cleanest solution to the problem of inappropriate and anticompetitive affiliate transactions").

22. See Northwest Power Planning Council, 1991 Northwest Conservation and Electric Power Plan, Volume II, Part II, pp. 793-95 (1991) (identifying potential benefits of $2.5 billion from "improved coordination of resource development" over Northwest power system).

23. This view appears, for example, in the proposal that initiated the California Public Utilities Commission's inquiry on electric-utility restructuring. See Order Instituting Rulemaking and Order Instituting Investigation, R. 94-04-013, p. 52 (April 20, 1994).