Editor’s note: This is Part I of a three-part series, in which the authors examine the drivers behind restructuring and its current state; jurisdictional issues that often result in divergence of state and federal frameworks; and federal wholesale pricing policies that in many instances do not send appropriate signals to investors.
At the heart of the current deregulation debate is the tension that exists between relying on competitive forces to guide investment in the industry and the desire to embrace cost-based rates whenever market prices appear to be “high.” Some would argue that there must be a consistent and fair set of wholesale power pricing policies that send appropriate signals to investors ensuring that market-driven outcomes will be accepted and not second-guessed by regulators.
When the Federal Energy Regulatory Commission issued its landmark Orders 888 and 889 in 1996, the primary expectation was that benefits would emerge from the formation of more transparent, efficient wholesale markets, producing price signals that would guide both the operation of existing generating plants as well as unregulated capital investment in new plants. Other expected benefits included reductions in costs of operating electricity generation facilities and elimination of persistent price differentials between various U.S. regions. Expected cost savings from wholesale restructuring ranged widely, from $3.8 billion per year to as much as $100 billion per year.
There have been some notable successes in this policy effort, but electricity industry restructuring has also witnessed remarkable policy failures, such as the 2000/2001 “meltdown” in California. Whether or not they were caused by attempts to move to a more market-driven system, events such as those in California have certainly given regulators and policy-makers pause in the push for reform. A number of states have stopped and even reversed their restructurings, and others have backed away from even beginning to implement market-driven strategies (see Figure 1).
At the federal level, full-steam-ahead enthusiasm has turned to foot-dragging as doubts creep in as to whether benefits once so confidently predicted can be achieved, and whether competition’s benefits will outweigh the costs. The resulting state and federal regulatory regimes are mixtures of traditional and restructured regulatory systems that may represent policy stasis for at least the medium term. These mixed systems present policy challenges of their own.
the motivating vision
In the early 1990s, federal and many state policymakers began restructuring the electricity sector with the expectation that competitive markets for power generation would reduce costs and ensure reliable supplies, and that introducing competition at the retail level would promote the pass-through of efficiencies achieved upstream to consumers downstream. Once the transition from regulation to competition was complete, it was believed, electricity resource allocation would be performed by competitive markets reacting to price signals, and regulators would be able to substantially abandon the public utility-style regulation apparatus traditionally used to ensure reliability and protect against the market power of franchised monopolies.
With multiple marketers using open access to reach multiple generators, the generation and sale of power would need little or none of regulation’s heavy hand; only the remaining elements of natural monopoly in transmission and distribution lines would warrant the attention of the public utility commissions.
At its core, “restructuring” has meant the use of markets to determine power pricing and allocation at the wholesale level. The archetype is the short-term market operated by an independent system operator (ISO) that clears the market for energy with bidding and efficient dispatch. Today, there are five fully functioning ISOs, all of which have software and protocols that support the trading of various power products while allowing reliable operations second by second. The ISOs promote transparency in the marketplace by publishing market data in vast quantities, allowing market participants to assess market operations at numerous levels of detail. Most importantly, the markets operated by the ISOs promote efficiency and competition through their provision of bidding and dispatch services.
Prior to restructuring, the primary participants in the wholesale markets were investor-owned utilities (IOUs). Commonly organized in regional power pools, these IOUs generally faced requirements of generation self-sufficiency vis-Ã -vis their native loads and handled imbalances with bilateral purchases and sales of claims on generation capacity. Over time, the IOUs’ capacity was increasingly supplemented by non-utility generators (NUGs). These NUGs typically either consumed the power they generated and/or sold power to utilities at “avoided cost” prices established by state commissions pursuant to the Public Utility Regulatory Policies Act.
In the restructured wholesale market, hundreds of generator and marketer “merchant” entities have applied for and received federal authorization to transact. These markets are no longer dominated by IOUs.
Despite various efforts to introduce exchange-traded electricity futures contracts, most trading for longer-term power needs is done bilaterally on a forward contract basis using the Edison Electric Institute Master Agreement. Bilateral trading of forward contracts is a critical element of successful restructuring. Forward markets provide the long-term contracting that can efficiently allocate risk, permit efficient planning for reliability and serve as the basis for investment dollars and decisions. However, when the crisis in California rippled across the West in 2000/2001 and Enron imploded in late 2001, a spate of regulatory and private plaintiff investigations of power trading practices threw cold water on forward markets. By 2002, many of the companies that had reported the largest power trading volumes were scaling back their forward trading. Restructuring’s promises were scaled back in the process.
One of the clear successes of electricity industry restructuring has been the growth of investment in new generating facilities by unregulated merchant firms. Between 1998 and 2003, approximately 190,000 MW of new capacity entered service in the United States, with an estimated investment cost of around $115 billion. This represents approximately 20 percent of the total installed capacity in 2003. Of particular note, between 70 percent and 80 percent of this new investment was made by companies classified as “unregulated.”
New generation capacity put in service during 2001 and 2002 is shown in Figure 1. The unregulated investment has been concentrated in the same states where high retail prices led policy-makers to introduce retail competition, suggesting that investors were attracted both by expected price levels and access to customers.
Of course, in the process of re-sponding to market incentives and opportunities, supply has been directed to where it is most needed. The new plants have caused significant competitive pressure in wholesale electricity markets and have put wholesale electricity prices under downward pressure. For example, the PJM interconnect and ISO New England, where capacity investment has been strong, report that wholesale electricity prices have dropped during the past two years, even while gas prices have increased. In addition to lowering prices, the new capacity has also substantially elevated reserve (reliability) margins in many regions.
The combination of substantial system capacity expansions, the resulting downward competitive pressure on prices and macroeconomic slowdown in the early 2000s has put many prominent merchant energy companies into financial distress and even bankruptcy. The capacity they have created, however, remains to serve buyers.
Will current financial distress make it impossible to raise capital for competitive investments in the future? This seems extremely unlikely as long as re-regulation does not prevent investors from the opportunity to prosper in strong markets. What is certain is that investors will have learned much from experience and in the future will more assiduously seek to hedge and minimize their risks.
the transmission conundrum
It has long been recognized that it would be difficult, if not impossible, to turn over wholesale electricity transmission entirely to the market due to elements of natural and essential monopoly. Nevertheless, FERC has envisioned that regulatory reform-particularly in the form of regional transmission organizations (RTOs) not dominated by generators-would provide for efficient transmission capacity use, while transmission congestion pricing would improve signals and incentives for transmission investment and optimal location of new generation units. Indeed, price differentials between regions are easy to observe today, and a number of interregional locations have been identified as good prospects for efficient transmission investment.
But realization of the full benefits of a national grid and complete interregional price arbitrage (with attendant allocations of power to where it is in most demand) has been impeded. Transmission congestion pricing has proved procedurally and politically troublesome. And, fulfillment of the vision of market-driven transmission investment is complicated by the states’ jurisdictional authority over siting and construction of new transmission capacity.
Electricity is a necessity. This means that both its price and reliability are the focus of citizen and, hence, policymaker attention. Sound regulatory frameworks are necessary to ensure that future capital investments are forthcoming when and where they are in greatest demand. Historically, capital investments were made under the aegis of the “regulatory compact” in which franchise protection was accompanied by obligations to serve and cost-of-service pricing limits. “Restructuring” means turning to the forces of the marketplace to determine prices, accompanying inducements to investment and derivative system reliability.
This sanguine view of market forces under restructuring as the protectors of system reliability has been given its greatest challenge by the widespread Aug. 14, 2003, blackout. The recent federal task force on the blackout’s causes endorses no direct connection between restructuring and reliability (the cause of the blackout has largely been explained by inadequate operational procedures and unenforceable reliability standards). The task force, however, does recommend the commissioning of an independent study of the relationships among industry restructuring, competition, and reliability, as well as withholding FERC approval of new RTOs and ISOs until they have met minimum functional requirements. The 2003 blackout does not sound an alarm that restructuring and the all-important maintenance of reliability are inherently incompatible.
Joseph Cavicchi is a vice president at Lexecon, an FTI Company. He provides wholesale and retail electricity market regulatory economic analyses related to the restructuring of the U.S. electricity industry.
Charles Augustine is a managing consultant with Lexecon, an FTI Company. He specializes in the analysis of regulated markets, particularly natural gas and electricity.
Joseph Kalt is a senior economist with Lexecon, an FTI Company. Dr. Kalt is also the Ford Foundation Professor of International Political Economy at the John F. Kennedy School of Government at Harvard University.