Issues: Energy

On one point at least, observers of the West's energy disorders agree: some very basic portfolio management skills have been conspicuously lacking. In particular, critics ask repeatedly, how could a major state have come to rely on a day-ahead spot market to procure most of its electricity supply? The answers are instructive and point toward enduring solutions. For most customers, there is a crucial portfolio management function associated with electricity resources, which has many features of a classic natural monopoly. Regulators cannot leave this function exclusively to unregulated participants in wholesale markets. Without designated portfolio managers operating under incentives to promote long-term public interests, deregulation of wholesale electric markets is unlikely to succeed.

The Crisis Begins

California launched its spot market in electricity commodities on March 31, 1998. After more than two years of reassuringly low prices and seemingly robust competition, calamity struck:

• Wholesale electricity prices that previously had ranged between two and three cents per kilowatt-hour soared to at least fifteen cents, on average, from June through August of 2000. That average price then doubled again in December 2000 and January 2001, even though demand levels were far below their summer peaks, and at one point the price reached $1.50 per kilowatt-hour.¹
  
  
• Natural gas prices, typically at $2 to $3 per million BTUs, climbed in January 2001 to nearly $10 per million BTUs nationally, with prices spiking above $50 in Southern California. As of April 2001, natural gas options contracts on the New York Mercantile Exchange were selling at levels above $5 for every month through March of the following year.²

Based on the gap between runaway wholesale electricity costs and state-frozen retail electricity rates, the West's two biggest electricity distribution companies -- PG&E and Southern California Edison -- claimed losses in excess of $12 billion from May 2000 to January 2001 on unreimbursed wholesale electricity purchases. Consumer advocates countered that these losses had been offset in part by gains on power sales from generators still owned or controlled by the utilities. By any measure, however, the distribution companies were on the brink of insolvency by early 2001.

At the same time, notices of supply emergencies became routine throughout the state, as operating reserves dropped below 5% for weeks on end. A host of public officials have been wondering loudly how matters could have reached such a pass.

Some have blamed alleged runaway growth in California's electricity consumption, along with environmental regulations that supposedly blocked power plant construction and operation. I respond briefly below to these largely discredited contentions, but my emphasis in what follows is the neglected portfolio management functions that could have averted the crisis and are now essential to overcoming it.

California's Electricity Use and Environmental Regulations

Reports of a dramatic surge in California electricity use are simply inaccurate. The estimated statewide annual increase for 2000 was about four percent, and the annual rate of growth from 1990-1998 was under one percent.³ California accounted for only about 15 percent of the increase in Western peak power use from 1995-1999, although the state represents about 40 percent of the total system.⁴ In other words, electricity consumption for the other ten western states has been growing more than twice as fast as California's, on average. In the nation as a whole, electricity use was up 22% from 1990-1999, about double California's figure for the same period.⁵

Some contend that environmental constraints on electric generation somehow caused rising electricity costs in California. But as the Los Angeles Times noted on January 25, 2001: "California regulations have not short-circuited the amounts of electricity produced, according to power company representatives." The only exception that the Times could find was one small and obsolete plant accounting for less than one-fifth of 1 percent of the state's demand, which had chosen "not to participate in a smog market that gives companies more flexibility in meeting pollution limits."⁶ Ample opportunities remain to reduce pollution at relatively low costs by cleaning up this and other older fossil generators, which could both increase their production and cut their emissions after modifications.⁷

Most complaints about the state's siting rules are just as unfounded. The California Energy Commission (CEC) works aggressively to site new power plants, generally in a year or less, and the agency can override local opposition where broader public interests dictate. For much of the 1990s, investors throughout California and the West generally had no interest in financing new power plants because of low prices and widespread electricity surpluses, not environmental rules. Even so, the CEC licensed eleven power plants in the early 1990s, and eight are producing almost 1,000 megawatts of power today (the equivalent of about 1 million California households).⁸ From 1991-1995, environmental groups strongly supported efforts by the CEC and other state agencies to add another 1,400 megawatts of renewable energy and highly efficient gas-fired plants, but a shortsighted Federal Energy Regulatory Commission blocked the power purchase contracts that were prerequisites to construction.⁹ In the two years following April 1999, almost 10,500 megawatts of new large-scale plants (equivalent to one-fifth of California's peak needs) have received CEC siting approval, and more than 5,500 megawatts are poised to follow.¹⁰

What Really Happened

No single factor explains recent and closely linked price increases in two essential energy commodities. The upswing in natural-gas prices most prominently reflects a prolonged contraction in exploration and storage due to low commodity prices, coupled (in the Southwest) with reduced pipeline capacity as a result of a summer 2000 explosion. And much costlier natural gas has in turn helped to drive up the operating cost of electric generation. High electricity prices also reflect Northwest hydropower production due to low rainfall and the generally overstressed state of the western power grid, which has suffered from a decade of reduced investment in energy efficiency, generating capacity and transmission upgrades.¹¹ As if all that were not enough, investigations continue of alleged anti-competitive practices by many market participants.¹²

But none of these factors, even in self-reinforcing combination, could have instigated a statewide financial crisis in 2000-2001 if most of California's electricity load had not been consigned to the spot market. This, in turn, reflected a fundamentally flawed if well intentioned policy judgment some five years earlier.

Portfolio Management Lost

Between April 1994 and January 1996, the California PUC devised a plan for restructuring the electric utilities subject to its jurisdiction. A prominent feature was eliminating utilities' longstanding responsibility for electricity resource investments.

The Commission acknowledged that, even after opening retail electricity markets to competition, many if not most customers would continue to procure their power from their hometown distribution companies. But the Commission insisted that these utilities would have to procure all the power that they sold directly from the short-term wholesale spot market. For those concerned about potential volatility in the spot market, the Commission had a ready response:

Many customers may be disinterested in the choice of generation but desire price stability and predictability over a defined period of time. Such customers are free to elect hedging contracts which may be concluded with any individual or entity willing to take the counter-part risk...

In our view parties [who] agree to accept the risk in a hedging contract may have generation facilities or contracted rights to generation but we see no need to restrict their qualification or in any manner make hedging contracts, termed "contracts for differences" in much of the literature, the object of Commission concern. Both entry into and exit from such a business, as well as the terms of such contracts are left to the genius of the marketplace and the will of market participants.¹³ [Emphasis added.]

Would this suffice for the average customer with little sophistication or understanding of electricity commodity markets? The Commission thought so:

At least initially, most observers anticipate that a significant majority of residential and small load commercial and agricultural users will either prefer, or lack competitive alternatives to, reliance upon the local utility to procure electric energy as well as provide distribution and related services. These average ratepayers may be referred to as "full service customers." During the transition period, we have concluded that our greatest contribution to those who initially elect or find no alternative to the status of full service customers is to ensure that they gain access to the competitive price for generation in a manner that is free of cost and confusion . . . A customer who, for any reason, desires a price structure which differs from the day by day, hour by hour, revelation in the Exchange will be afforded the opportunity to purchase a financial hedge . . . from any counterpart party who may or may not own or have contractual rights to any specific generation.¹⁴

In sum, utilities would cease their portfolio management functions and become mere passive conveyors of "day by day, hour by hour" spot market prices, which customers could either accept or hedge by seeking portfolio management services in the open market. In reaching these conclusions, the Commission disregarded strenuous objections from the Natural Resources Defense Council and others.¹⁵ And although the California legislature later made numerous changes in the PUC's proposal, the Commission's experiment with market-driven portfolio management went forward. Its catastrophic failure forced the legislature to take emergency action in January 2001, by directing an agency of the State of California to assume responsibility for power acquisition and begin assembling long-term contracts from multiple suppliers.¹⁶ Unfortunately, of course, it would be difficult to have picked a less opportune time to begin hedging commodity risks in electricity markets. A broader vision of the portfolio function will be required to restore affordable and reliable electricity service.

Portfolio Management Regained

California has now thoroughly tested the proposition that multiple competitive decision makers can orchestrate a diversified and affordable mix of resources for meeting a healthy economy's electrical services needs. The verdict is in with a vengeance. Yet the state was not alone in this dangerous venture; although other jurisdictions were less explicit in their choices, sharply reduced investment in all aspects of electricity infrastructure -- from end-use efficiency to transmission -- was the order of the day throughout much of the 1990s.¹⁷

Before the California PUC intervened so catastrophically in the mid-1990s, the state's electricity distribution companies and 3000-odd counterparts across North America had been responsible for choosing the mix of generating resources, purchased power and demand-side efficiency improvements that would minimize the costs and price volatility of reliable energy services.¹⁸ Both Congress and state legislatures had addressed these portfolio obligations extensively; California law provided as follows:

1. the Legislature finds and declares that, in addition to other ratepayer protection objectives, a principal goal of electric and natural gas utilities' resource planning and investment shall be to minimize the cost to society of the reliable energy services that are provided by natural gas and electricity, and to improve the environment and encourage the diversity of energy sources through improvements in energy efficiency and development of renewable energy resources, such as wind, solar, biomass, and geothermal energy.
   
   
2. the Legislature further finds and declares that, in addition to any appropriate investments in energy production, electrical and natural gas utilities should seek to exploit all practicable and cost-effective conservation and improvements in the efficiency of energy use and distribution that offer equivalent or better system reliability, and which are not being exploited by any other entity.¹⁹

California now needs to restore these principles to their earlier prominence, with special emphasis on a theme borrowed from earlier Northwest legislation: energy efficiency investments are compelling candidates for inclusion in any successful electricity-resource portfolio.²⁰ While there was much dissatisfaction with utilities' performance historically as portfolio managers, all now have special cause to appreciate the social importance of the diversification and aggregation functions at issue. Portfolio management looks increasingly like a classic "natural monopoly" that offers significant potential benefits to customers and society generally. That does not mean, of course, that it is physically impossible to have multiple entities making decisions about acquiring resources for an electricity distribution system, any more than it is physically impossible to run multiple power distribution lines into a building. But in either case abandoning central direction means higher costs for customers and society.²¹ Distribution companies typically have discharged the portfolio responsibility, although certainly they are not the sole candidates, and nothing in the fundamentals of the function itself requires ownership of the resources that contribute to the portfolio.²² Here as in other contexts, appropriate regulatory oversight is needed to ensure that the monopoly works in the public interest.

This does not mean that all customers in a service territory must be assigned initially to the same manager, or that competitive alternatives must be suppressed, or that management franchises should be permanent. Individual customers should be allowed to opt out of regulated portfolio management, as long as any right of return is conditioned to protect the regulated service and its other customers from financial harm. What California shows, paradoxically, is that those who want to offer competitive portfolio services have a particular stake in ensuring that good regulated service is available to all; the competitive providers were among those swamped in the tidal wave of price volatility from a largely unhedged spot market.

As regulators begin considering how best to reestablish portfolio management functions in California and elsewhere, several considerations should be paramount.

Thanks in part to legislation signed by Governor Davis last September, California has many immediate opportunities to accelerate its energy-efficiency and renewable-energy investments, which already have contributed more than 15,000 megawatts to a Western power grid that never needed them more.²³ For example, in January 2001, the California Energy Commission issued emergency upgrades for efficiency standards governing all new buildings and equipment, which should save about 1,000 megawatts over the next five years.²⁴ The legislature also has created a new ten-year investment fund for sustainable energy technologies that exceeds $5.5 billion.²⁵

In 2001, the state moved to do still more of what it already did best. In April, Governor Davis signed two bipartisan bills (SB 1X-5 and AB 1X-29) that provided more than $700 million in supplementary funding from the state's budget surplus for energy efficiency, renewable energy and low-income energy services. Environmental groups will also support additions of highly efficient natural-gas generation. But for those angered by rising fuel prices, the best revenge is still needing and using less. Congress could help immediately by enacting S. 207, a bipartisan bill that provides new financial incentives to improve significantly the energy-efficiency of new buildings and equipment. These incentives would also prod other western states to revive flagging energy-efficiency momentum. All of these initiatives are designed to reduce costly near-term public investments in additional fossil generation to meet urgent reliability needs. Westerners outside California should be asking hard questions about what if any comparable efforts their utilities, regulators and legislators are making.

Whether or not energy distribution companies retain portfolio management responsibilities, regulators must act to eliminate conflicts of interest that arise whenever distribution revenues are tied to throughput over the wires. No conceivable public interest is served by rewarding distribution system managers for diminished progress in energy efficiency, or for increased use of a commodity that others are now responsible for producing. The solution is to introduce modest annual adjustments in regulated electricity rates that automatically correct for unexpected fluctuations in electricity use. In other words, if traffic over the wires exceeds or falls short of estimates made at the time that regulators last established rates for electric distribution service, rates for the next year should be adjusted to compensate. The recovery of distribution costs is then independent of the total volume of electricity passing over the wires, although customers continue to be charged on the basis of kilowatt-hour consumption.²⁶

This is the model that the Public Utility Commission of Oregon and Pacificorp embraced in 1998, at the request of a diverse coalition of parties.²⁷ Portland General Electric agreed in September 2000 to file "ratemaking alternatives for distribution services under which the revenues and net income of PGE are not tied to or derived from kilowatt hour sales."²⁸ The San Diego Gas & Electric Company became a convert to this approach in January 2001, citing "the need for a strong and renewed focus on energy efficiency" in its decision to file for rate reforms to ensure that "SDG&E's earnings would not be proportional to the amount of energy that consumers use."²⁹ And by large bipartisan majorities, legislators subsequently wrote this policy into California law.³⁰

Across California, developers of new generation are racing to site and build plants (both renewable and fossil-fueled) that are dramatically cleaner than the incumbents. By the end of 2001, the state expects to add 2,353 MW of combined cycle gas generation and 800 MW of renewable generation.³¹ The 16,000-odd megawatts of gas and renewable capacity additions anticipated by 2003 are both clean and large enough to begin improving California's air quality by displacing dirtier competitors during at least some hours of the year. A particularly striking near-term benefit is minimizing the operation of emergency diesel generators, whose emissions per kilowatt-hour of nitrogen oxides and particulate matter exceed those of new gas-fired plants by 50-100 fold.³² In 1998, the California Air Resources Board listed diesel exhaust as a toxic air contaminant, and later concluded that it is responsible for more than 70 percent of the statewide cancer risk from air pollution.³³

Given the West's wholesale electricity prices, not even the most adept portfolio manager could rule out near-term increases in residential rates, and retail gas prices surged throughout the nation during the winter of 2000-2001. California and neighboring states traditionally have tried to ensure that low-income households receive targeted energy efficiency assistance and rate discounts; in California, these programs are administered by the state's utilities and funded through a modest surcharge on bills. Additional resources must be added now, to ensure that no one loses access to essential services. In April 2001, the California legislature approved emergency legislation (SB5X) that provides $240 million of supplementary funding. The federal government could help by expanding the Low-Income Home Energy Assistance Program (LIHEAP) and complementary energy efficiency investments.³⁴

Conclusion

No one wants to resume California's experiment with entrusting retail customers' electricity portfolios solely to "the genius of the marketplace." But other states unwittingly are doing precisely that, by allowing energy distribution companies to defer most investment in new resources, and in particular to neglect the diversification opportunities associated with energy efficiency and renewable resources. Adroit portfolio management, and incentives to achieve it, must become paramount objectives of both state utility regulators and those entrusted with this vital public function.

Notes

1. See R. Smith, "Probe of California Power Prices Begins, But New Plants Aren't Seen as Solutions," Wall Street Journal, September 11, 2000 ("[t]he average cost of power, per megawatt hour, was $185 in August, $117 in July and $167 in June"). A price of $1.50 per kWh cleared the California Power Exchange's day ahead market for deliveries at 6 am on December 13, 2000, according to the PX website (www.calpx.com). The weighted average cost of system power purchased through the Power Exchange from November 20 through December 20, 2000 was 28 cents per kWh; for the period December 20 through January 22, 2001, it rose to 29.4 cents per kWh. These weighted averages are reported by Green Mountain Energy, in the form of retail electicity bills received by the author for those months.

2. This reflects the Henry Hub natural gas options contract prices listed on nymex.com through March 2002, as of April 5, , 2001.

3. These data appear at http://www.energy.ca.gov/electricity/consumption_by_sector.html.

4. See Northwest Power Planning Council, Study of Western Power Market Prices: Summer 2000 (October 11, 2000), p. 15. The report notes that "by far, the most rapid growth" occurred in Arizona, New Mexico and southern Nevada: "[a]lthough this area only accounted for 12 percent of WSCC summer peak loads in 1995, it accounted for 47 percent of their growth from 1995 to 1999." Id. at p. 14.

5. See U.S. Department of Energy, Monthly Energy Review (December 2000), p. 99 (data reflect electricity end use); California consumption grew by 11% from 1990-1999, according to the California Energy Commission (see note 3 above).

6. M. Cone and G. Polakovic, "Bush's Idea of Easing Smog Rules Won't Help, Experts Say," Los Angeles Times, January 25, 2001.

7. See Paul Joskow and Edward Kahn, A Quantitative Analysis of Pricing Behavior In California's Wholesale Electricity Market During Summer 2000 (November 21, 2000), pp. 9-13 (reviewing abundant opportunities for Nox reductions at California generators, and noting that the five most polluting gas turbines in the Los Angeles air basin could cut emission rates by 65% "for costs of less than $1 million per unit").

8. See California Energy Commission, http://www.energy.ca.gov/sitingcases/backgrounder.html.

9. The FERC decision expressed "grave concern about the need for this capacity" and concluded that California utilities could not lawfully be required to execute the purchase contracts. Federal Energy Regulatory Commission, Order on Petitions for Enforcement Action Pursuant to Section 210(h) of PURPA, Docket No. EL95-16-00 (February 23, 1995), pp. 26-27.

10. For a continuously updated report on the status of siting proceedings at the California Energy Commission, see http://www.energy.ca.gov/sitingcases/backgrounder.html.

11. In the region drained by the Columbia River and its tributaries, precipitation for the four months starting in November 2000 was 49%, 57%, 40% and 53% of average, respectively; February 2001 streamflows at the Dalles on the Columbia River were 49% of the 60-year average; federal hydropower generation for February 2001 was at least 4000 MW below 1995-2000 averages; and the National Weather Service predicted that the year ending in July 2001 would bring "the second lowest volume runoff on record" at the Dalles (trailing only 1977). Bonneville Power Administration, Power System Data for the Week Ending March 2, 2001. The issue of reduced resource investment is addressed below in note 17.

12. For a provocative treatment, see R. McCullough, "Price Spike Tsunami: How Market Power Soaked California," Public Utilities Fortnightly (January 1, 2001). The California Independent System Operator renewed formal claims of anticompetitive actions by generators on March 1, 2001. See also T. Davis, Cal-ISO to FERC: Power Sales Reek of Market Power, The Energy Daily, March 2, 2001, p. 1 (ISO contends that "as much as $247 million or 21 percent of the real-time energy costs during December 2000 and $315 million or 63 percent of the real-time energy costs for January 2001 represent charges that may exceed just and reasonable levels").

13. Decision 95-12-063 (December 20, 1995) as modified by Decision 96-01-009 (January 10, 1996), at p. 8.

14. Id., pp. 56-57.

15. A full review of the portfolio management issues appears in NRDC's initial response to the Commission's proposal, and in a report issued shortly before the Commission's proposal was published. See Opening Comments of the Natural Resources Defense Council and Comments on Balancing Public Policy Objectives in a Competitive Environment (June 7, 1994), pp. 2-3 and 7-10; R. Cavanagh, "The Great Retail Wheeling Illusion" (NRDC: March 1994), pp. 3-8. For an analogous and equally timely critique of the PUC's proposal, see V. John White, "On a Cruel Sea," Coalition Energy News (CEERT, Spring 1994), p. 2.

16. See AB1X (Keeley), available in full at http://www.assembly.ca.gov/acs/acsframeset2text.htm.

17. See Northwest Power Planning Council, Study of Western Power Market Prices: Summer 2000 (October 11, 2000), pp. 13-14 (concluding that, while western peak loads increased by 12,000 megawatts from 1995-1999, generating capacity increased by only 4,600 megawatts and energy efficiency investment dropped substantially throughout the utility sector).

18. The California PUC had plenty of encouragement, much of it -- ironically and tragically -- from politically potent industrial interests who have been particularly hard hit by recent increases in electricity rates.

19. Public Utilities Code section 701.1. As NRDC noted at the time, note 14 above at p. 3, the initial PUC proposal conspicuously omitted any reference to this statute. The first legislation to address portfolio functions in detail was the Pacific Northwest Electric Power Planning and Conservation Act of 1980, 16 U.S. Code section 839 et seq.

20. See 16 U.S. Code section 839b and 839d.

21. In a prophetic 1991 analysis, the Northwest Power Planning Council demonstrated as much when it quantified literally billions of dollars of potential benefits from centralized resource procurement, compared with disaggregated development across a regional utility system. See Northwest Power Planning Council, 1991 Northwest Conservation and Electric Power Plan, Volume II, Part II, pp. 793-95 (1991).

22. In 1999, Montana opened the way for a portfolio-services competition; the statute established the possibility that a new statewide cooperative or some alternative provider might replace the incumbent distribution company as the entity responsible for executing procurement contracts on behalf of customers who did not choose a different supplier. See Montana Code Annotated, Title 35, Chapter 19, section 101; and Title 69, Chapter 8, sections 416 & 417.

23. See California Energy Commission, The Energy Efficiency Public Goods Charge Report (December 1999), p. 12 (savings estimates cover 1975-1998).

24. See http://www.energy.ca.gov/releases/2001_releases/2001-01-03_new_standards.html.

25. This legislation, enacted as SB 1194 and AB 995, is codified at section 399 of the Public Utilities Code.

26. For thoughtful treatment of these and related issues, see the website of the Regulatory Assistance Project at rapmaine.org.

27. Public Utility Commission of Oregon, Order No. 98-191 (May 5, 1998) (approving "alternative form of regulation" based on proposal by PacifiCorp, the Oregon Department of Energy, the Citizens Utility Board, the Natural Resources Defense Council, and the Northwest Energy Coalition).

28. This commitment appears in a stipulation that the Oregon Public Utilities Commission acknowledged as "in the public interest" in its order approving Sierra Pacific's acquisition of Portland General Electric. Order No. 00-702 (October 30, 2000), Appendix C, p. 4. PGE also agreed not to propose fixed charges "as a means of achieving the separation from kilowatt-hour sales," ensuring that customers' incentives to improve efficiency would not be reduced as a consequence of the pricing reforms. Id.

29. Letter from Pamela J. Fair, Vice President, Consumer Services, SDG&E, to Ralph Cavanagh, Natural Resources Defense Council (January 31, 2001).

30. See Public Utilities Code section 739.10, which directs the Public Utilities Commission to ensure that "errors in estimates of demand elasticity or sales do not result in material over or undercollections" of utility revenues.

31. The gas-fired generation additions are described in California Energy Commission, note 10 above; the renewable additions were reported to me in a March 5, 2001 communication from Marwan Masri, Manager of Renewable Energy Programs for the California Energy Commission, and reflect the cumulative impact of renewable energy investments orchestrated by the Commission since 1998.

32. California Air Resources Board, Air Pollution Emissions from Electricity Generation (September 2000) (typical diesel engines emit 25-30 pounds of N Ox and 1-3 pounds of PM per mWh, compared with .05 pounds of N Ox and .03-.07 pounds of PM for a new combined cycle gas-fired plant in California.

33. See California Air Resources Board, Identification of Diesel Exhaust as a Toxic Air Contaminant, (August 1998); Risk Reduction Plan to Reduce Particulate Matter Emissions from Diesel-Fueled Engines and Vehicles (July 13, 2000), p. 15.

34. For specific recommendations by the broad-based Campaign to Keep America Warm, see www.save-liheap.org.