Let’s Remember Why We Are Here: “Re-Regulation” Will Not Provide Consumer Benefits

Appeals to the “good old days” of cost-plus utility regulation ignore the inherent shortcomings of traditional regulation that led to restructuring in the first place. Although re-regulation in the current climate might provide short-term price stability when compared to competitive markets, the long-term costs of a return to regulation would be significant -- stripping consumers of the efficiency gains and additional supply choices realized under competition, reducing significantly the incentives for innovation among industry participants, rolling back the environmental gains associated with efficiency and innovation, and transferring much of the risk associated with bad investment or business decisions by utilities back to consumers.

I. High electricity prices are not the product of restructured electricity markets

Recent increases in energy costs are affecting all electricity providers, including regulated utilities. Fuel costs are the main driver of electricity prices and the largest component in variable electricity production and short-run marginal costs. Fuel costs trended downward from regulated period 1993-1997 but then trended upward from deregulated period 1998-2003, particularly for natural gas and petroleum.¹

Indeed, the price of natural gas -- a key fuel for electricity generation -- has trended steadily upward since 1999 because demand has expanded faster than supply. Large increases in the use of natural gas for electricity generation over the past few years have exacerbated the tight natural gas supply. From January 1999 through July 2005, average wholesale prices for natural gas more than tripled at the Henry Hub (a key marketing hub in Louisiana), from about $2 to $6.75 per MMBtu. Coupled with the devastation to drilling platforms and the delivery infrastructure arising from Hurricanes Katrina and Rita, wholesale natural gas prices have been even more volatile; in the last half of 2005, prices rose to over $15 per MMBtu at the Henry Hub. Wholesale natural gas prices at that location recently have dropped to about $7 per MMBtu.² As to the short-term future price of natural gas, we can expect more of the same: it is estimated that Henry Hub prices will average $8.11 per MMBtu in 2006 and $8.74 per MMBtu in 2007.³

Due to increased fuel and purchased power costs, electricity prices have followed an upward trend as well. Retail electricity prices have increased, or are projected to increase, in all states that are transitioning to retail choice and also are facing, in many situations, the end of rate freezes or rate stabilization plans.

No part of the country, however, including regulated states, is escaping the impact of high fuel costs: the Tennessee Valley Authority recently approved fuel- related rate increases of approximately 18% for its customers; Georgia Power and Savannah Power (subsidiaries of the Southern Company) received increases of approximately 10% and 14%, respectively; Nevada Power is seeking an increase of more than 10%; Progress Energy Florida received an increase of 12%; Xcel Energy Colorado is seeking an increase of approximately 20%; and Entergy Mississippi received increases of approximately 24% over the past few months. In view of these facts, it is flatly wrong to say that the current high prices are caused by restructured electricity markets. The cost of generation fuel has increased in all states, those that restructured and those that did not.

In fact, between 1996-2004 “real residential prices fell more in states that implemented retail competition programs than in those that did not.”⁴ The average real price for residential customers in states without retail competition fell by about 8%, whereas the average real price for residential customers in states with retail competition generally fell about 10% to 30%.⁵

II. Under “re-regulation,” the risk of bad business or investment decisions largely shifts back to consumers

As one prominent economist put it, “the revisionist history about ‘the good old days of regulation’ has conveniently ignored the $5000/Mw nuclear power plants, the 12 cent/kWh PURPA contracts, the wide variations across utilities in the construction costs and performance of their fossil plants, and the cross-subsidies buried in regulated tariffs that characterized the regulatory regimes in many states.”⁶ As in the “good old days,” moreover, there is no reason to expect that after-the-fact, unwieldy prudence reviews would provide an effective check on bad business or investment decisions.

Those who call for re-regulation in the face of the expiration of price freezes should recognize the basic economic fact that, under the cost-plus regime, “[f]ull recovery of costs via retail rates necessarily implies that retail customers ultimately bear nearly all of the financial risks....”⁷ Assured cost recovery significantly mutes the incentive to respond appropriately to price signals and to protect against financial contingencies in making investment decisions. Once an asset has been placed into rate base, moreover, the regulated utility is protected against errors in operational judgment and has little incentive to improve operational efficiencies.

As the California PUC put it in a 1993 report, investments under traditional cost-plus regulation were rewarded on the basis of “tonnage of money invested” without any attention to the appropriate balance of risk between investors and rate- payers.⁸ Moreover, as recently noted by the Texas PUC, “In reality, a regulatory commission and the parties who participate in these proceedings face significant difficulties in challenging the utility on its choice of technology or its management of the construction process . . . . Because cost recovery is set for the life of the asset, customers are generally locked into paying for the investment, even if subsequent technologies or changes in fuel or energy markets make the investment uneconomic.”⁹

In effect, cost-plus regulation operates as “a kind of insurance for utilities, since it guarantees to a utility that its costs accepted as prudent and accepted into its rate base are eventually recovered in full from retail rates on an amortized basis that includes the cost of capital. . . . But inevitably, insurance dilutes incentives, since a utility does not bear the costs that result from its investment decisions and operating practices.”¹⁰ In contrast, under competition, a variety of risks with respect to generation – development, construction, fuel, operating and maintenance, financing, and marketing–are allocated largely to the developers of power projects, rather than to customers.¹¹

Also, a return to cost-plus regulation would greatly dampen the effect of price signals in guiding investment choices and imposing cost discipline on utilities. Likewise, the efficiency gains that attend competitive markets would be greatly diminished. Because regulators simply do not have the tools to recognize and reward efficiency gains, utilities operating under a cost-plus regime face no real penalty for failing to be as efficient as possible and no real reward for being exceptionally efficient. Efficiency becomes little more than an option left to the discretion of management, which is precisely the reason why differences in efficiency between utilities grew over time under cost-plus regulation, resulting in substantial disparities in rates.¹²

As with operating efficiencies, moreover, cost-plus regulation fails to reward technological innovation. Under the cost-plus regime, if a utility improves its overall return on equity through innovations and cost cutting, regulators will respond by cutting the utility’s rates, wiping out incentives to push for productivity innovations. This is reflected in the industry’s poor record of productivity growth, as evidenced by the fact that the average thermal efficiency (heat rate) of the utility generating fleet showed no change for the 35 year period between 1963 and 1998.¹³

Without the incentives for innovation and efficiency that accompany competitive markets, a return to cost-plus regulation will also eliminate tailored products and services and any significant expansion of customer choice. In addition, in the absence of market forces, price signals will not flow through to influence the business decisions of utilities, further undermining the already poor incentives to improve efficiency and innovate under cost-plus regulation. As a result, overall environmental performance likely will suffer. We simply cannot afford a return to the “good old days” of cost-plus regulation.

III. Conclusion

Competitive markets are the foundation of the U.S. economy and have proven, time and again, to be the most effective way to address economic shocks and periods of uncertainty. Policymakers should not ignore the lessons learned from the failed cost-plus regulatory regime of the past. It was those costly experiences that led to the realization that competition works best for customers. Competition is an ever- evolving enterprise. We should not be surprised by the growing pains we are seeing in certain regions of the country. Recent studies provide solid evidence of the benefits of competitive, well-structured electricity markets. In the world’s new energy marketplace, the United States competes for precious energy resources with China, India, and Europe. Energy prices currently are high, but this is a reality that cannot be avoided -- under cost-plus regulation or in a competitive market environment.

Policymakers should allow competition to work; neither re-regulation nor other precipitous, short-sighted actions are in the public interest. As market participants learn from experience, adapt to new circumstances, and further refine supporting institutions, competitive electricity markets will continue to evolve and become even more robust over time, producing even greater long-term benefits for consumers.

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¹ Cambridge Energy Research Associates (CERA) “Beyond the Crossroads, The Future Direction of Power Industry Restructuring” (CERA Special Report), at I-9, Figure I-9 (October 2005).

² GAO Report, “Natural Gas, Factors Affecting Prices and Potential Impacts on Consumers,” at 2, 7 (February 13, 2006).

³ Energy Information Administration, Short-Term Energy Outlook, at 1 (March 2006).

⁴ Paul L. Joskow, “Markets for Power in the United States: An Interim Assessment,” AEI-Brookings Joint Center for Regulatory Studies, Working Paper 05-20 at 27 (September 2005).

⁵ Id. at 48, Figure 6.

⁶ Id. at 32.

⁷ Hung-po Chao, Shmuel Oren, and Robert Wilson, “Restructured Electricity Markets: Reevaluation of Vertical Integration and Unbundling” (Restructured Electricity Markets), at 10 (July 1, 2005).

⁸ California Public Utilities Commission, “California’s Electric Services Industry: Perspectives on the Past, Strategies for the Future, Staff Report to the Commission by the Division of Strategic Planning” at 101 (February 1993).

⁹ Public Utility Commission of Texas, “Electricity Pricing in Competitive Retail Markets in Texas,” at 6 (February 2, 2006).

¹⁰ Chao et al., “Restructured Electricity Markets,” at 72.

¹¹ Boston Pacific Company, Inc., “Assessing the ‘Good Old Days’ of Cost-Plus Regulation” at 22 (2001).

¹² Charles M. Studness, “How Soon They Forget,” Public Utilities Fortnightly (July 1, 2001).

¹³ Id. at 3 (noting that the heat rate of the fleet of utility generating plants was 10,438 Btu/kWh in 1963 and 10,360 Btu/kWh in 1998.)

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