Notes

¹ Robert L. Bradley, Jr. is president of the Institute for Energy Research in Houston, the author of the two-volume Oil, Gas, and Government: The U.S. Experience, and an adjunct scholar of the Cato Institute. Except for material on green pricing and the glossary, this study presents a modified version of a forthcoming paper published by the Cato Institute.

² Although a public-policy evaluation of these issues is beyond the scope of this paper, a "worst case" and "best case" can be assumed for externality adders (i.e., penalties assessed for assumed externalities) to compare different fuels on an economic and environmental basis. See the dicussion later in this paper.

³ Preferential taxation is not a government intervention into the marketplace or a net economic loss. While nonneutral taxation can be criticized for misallocating resources away from other alternatives to the area of tax preference, less taxation per se allows the private sector to retain earnings and increase activity. This reduction of government takings is differentiable from "corporate welfare." See, for example, the argument of Stephen Moore and Dean Stansel, "Ending Corporate Welfare as We Know It," Cato Policy Analysis, May 12, 1995, p. 10.

⁴ Department of Energy, Office of Chief Financial Officer, Appropriations History Table, FY 1978-FY 1995, File: Approp (jjg), Updated printout of 2/6/95. The nominal dollars in this DOE-supplied Excel spreadsheet were restated in 1995 dollars using the Consumer Price Index. (Hereafter referred to as DOE Budget Study.)

⁵ Richard Cowart, "Restructuring and the Public Good: Creating a National Benefits Trust," The Electricity Journal, April 1997, p. 57. Adding energy efficiency programs, low-income support, and research and development costs funded by government at all levels, the annual total is estimated to be between $4 billion and $8 billion annually (p. 55).

⁶ For a market-based evaluation of mainstream environmentalism, see Jonathan Adler, Environmentalism at the Crossroads (Washington, DC: Capital Research Center, 1995).

⁷ Combined-cycle technology, developed in the 1960s from jet engine research, captures waste heat created from primary generation to produce additional electricity. It is the most efficient technology for electric generation today. See Walter Vergara et al., Natural Gas: Its Role and Potential in Economic Development (Boulder: Westview Press, 1990), pp. 55-57.

⁸ Wind does have operating costs after capital costs become sunk. See the discussion below.

⁹ California Energy Commission, Wind Project Performance: 1994 Summary (Sacramento, CEC, August 1995), p. 1. Total operating capacity of 1,609 megawatts produced 3.2 gigawatt hours of power in 1994 (ibid., p. 25). (Hereafter cited as Wind Project Performance.) An average capacity factor is a broader measure than dependable on-peak capacity since off-peak performance is measured as well.

¹⁰ Energy Information Administration, Annual Energy Review 1995, July 1996, p. 261; Resource Data International, Energy Choices in a Competitive Era (Alexandria, Va..: The Center for Energy and Economic Development, 1995), p. 6 (hereafter CEED Study); and Enron Corp., The Natural Gas Advantage: Strategies for Electric Utilities in the 1990s (Houston, TX: Enron Corp., 1992), p. 11.

¹¹ Christopher Flavin and Nicholas Lenssen, Power Surge: Guide to the Coming Energy Revolution (New York: W.W. Norton & Company, 1994), p. 125.

¹² San Diego Gas & Electric, "Response to CEERT's Additional Testimony on Resource Case Analysis," ER92 Proceedings, California Energy Commission, August 28, 1992, p. 5.

¹³ California Energy Commission, 1994 Electricity Report, November 1995, pp. 94, 97.

¹⁴ Secretary of Energy Advisory Board, Task Force on Strategic Energy Research and Development (Washington, DC: Department of Energy, June 1995), Annexes 2-4, p. 184. (Hereafter DOE Task Force Study.) A DOE study similarly estimated that wind costs had fallen from 50 cents per kwh in 1980 to 5 to 7 cents by 1993. Julie Doherty, "U.S. Wind Energy Potential: The Effect of the Proximity of Wind Resources to Transmission Lines," Energy Information Administration, Monthly Energy Review, February 1995, p. viii. Also see "Statement of George Preston," Electric Power Research Institute, Hearing of U.S. Senate Committee on Energy and Natural Resources on the Department of Energy FY 1995 Budget, March 8, 1994, p. 3.

¹⁵ Conversation with Randall Swisher, executive director of the American Wind Energy Association, March 22, 1996.

¹⁶ Joseph Romm and Charles Curtis, "Mideast Oil Forever?" The Atlantic Monthly, April 1996, p. 64.

¹⁷ Total oil and gas tax incentives at the wellhead are estimated to be around $1 billion for 1996. Office of Management and Budget, Analytical Perspectives, Budget of the United States (Washington, DC: Government Printing Office, 1996), p. 62. With natural gas accounting for approximately 60 percent of total U.S. oil and gas production on a BTU basis, the tax allocation is $0.03 per Mcf [Thousand Cubic Feet] of 1995 production, under 2 percent of the 1995 wellhead price of $1.59 per MMBtu [Million Bitumous Thermal Units] Energy Information Administration, Monthly Energy Review, March 1996, p. 125.

¹⁸ See Independent Petroleum Association of America, The Oil & Gas Producing Industry in Your State (Washington, DC: IPAA, 1996), p. 103.

¹⁹ "Wind-driven electricity generating facilities must be located at specific sites to maximize the amount of wind energy captured and electricity generated. However, many good wind energy sites are on ridges or mountain passes, where siting and permitting difficulties, land restrictions, aesthetic objections, the potential for bird kills, and harsh weather conditions often constrain development." Julie Doherty, "U.S. Wind Energy Potential," p. x.

²⁰ CEED Study, p. 14. This generic estimate is applicable for a high voltage (230-KV) line from a wind farm in California, and with substation expenses it would be more. Conversation with Don Kondoleon, Supervisor, Transmission System Evaluation Unit, California Energy Commission, February 13, 1996. A lower estimate of $286,000 per mile, based on a study using information prior to 1993, is made in J.P. Doherty, "Wind," in Energy Information Administration, Renewable Energy Annual, 1995, December 1995, p. 88.

²¹ The half-cent estimate was stated as typical by Randall Swisher, and is an actual cost for the 35-MW West Texas wind project of the Lower Colorado River Authority. Conversation with Tom Foreman, Manager of Marketing and Energy Services, Lower Colorado River Authority, October 4, 1995.

²² "Wind resources cannot yet be predicted with precision for a specific hour 24 hours in advance." Comments submitted by the American Wind Energy Association to the Federal Energy Regulatory Commission, quoted in "Various Parties Protest California IOU's ISO and Power Exchange Proposals Filed in Response to CPUC Restructuring Order," Foster Electric Report, June 26, 1996, p. 5.

²³ At the California-Oregon border (COB) pricing point, the most actively traded point for spot electricity in the country where futures trading takes place, one hour firm (where the seller can cancel the power with an hour notice to the buyer) has a value of approximately a half-cent per kwh compared to interruptible, and full firm (without an interruption provision) has a one-cent value compared to interruptible. "Conversation with Patrick O'Neill," Energy Market Report, April 10, 1997.

²⁴ Julie Doherty, "U.S. Wind Energy Potential," pp. ix-x.

²⁵ The material requirements for wind turbines could be 50 times greater than for gas power plants, creating additional electricity consumption and air emissions. This rough estimate is made by comparing the materials used to construct the 1,875 megawatt Teesside gas project to the recently announced 112.5 megawatt Zond project in Iowa.

²⁶ For a comparison of externality estimates between natural gas and renewables, particularly wind and solar energy, and for an estimate of the social cost of renewable subsidies, see the later discussion in this paper.

²⁷ Artificially low estimates for wind power can also result from substituting a real for nominal price (where future prices are discounted to the present) and hidden benefits such as utility financing or free land usage.

²⁸ "Comments of San Diego Gas & Electric on Proposed Policies Governing Restructuring Electric Service Industry and Reforming Regulation," Submitted to the California Public Utilities Commission, June 8, 1994, p. 35.

²⁹ Conversation with Marino Monardi, Supervising Resource Planner, Sacramento Municipal Utility District, January 30, 1996.

³⁰ Northwest Energy System, "Toward a Competitive Electric Power Industry for the 21st Century," Portland, Oregon, December 12, 1996, p. 20. The new-capacity gas cost was 2.93 cents per kwh for 3,356 megawatts; the new-capacity wind cost was 4.1 cents per kwh for 117 megawatts and 4.94 cents per kwh for the next 116 megawatts. Conversation with Jeff King, Northwest Power Planning Council, March 6, 1997.

³¹ Paul Gipe, Wind Energy Comes of Age (New York: John Wiley & Sons, Inc., 1995), pp. 238-39.

³² FERC, "Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by Public Utilities, Recovery of Stranded Costs by Public Utilities and Transmitting Utilities; Proposed Rulemaking and Supplemental Notice of Proposed Rulemaking," 60 Federal Register 17662 at 17669-70 (April 7, 1995). Another recent estimate -- between $0.028 and $0.045 per kwh -- is made by Henry Lee and Negeen Darani, "Electric Restructuring and the Environment," Harvard University, Environment and Natural Resources Program Study 95-13, December 1995, p. 65.

³³ Conversation with Marino Monardi.

³⁴ The backwardation curve is a result of such market knowledge as major pipeline capacity additions from Canada, where surplus gas is selling at a significant discount to U.S. lower-48 gas, expected in late 1998. See DOE, Natural Gas Imports and Exports, Second Quarter Report, 1996, pp. iii-v.

³⁵ For example, ten-year fixed-priced gas in December 1996, when the front month was selling at $4.575 per MMBtu, was $2.635 per MMBtu. Ten-year, fixed-price gas in January 1997, when the front month price fell nearly 50 percent, was $2.555 per MMBtu, only a $0.08 per MMBtu difference. Translated into electric rates, this 3 percent increase in gas prices equates to less than one mill per kwh.

³⁶ Energy Information Administration, Natural Gas Monthly, March 1996, p. 11. These statistics have been restated in 1995 dollars using the Consumer Price Index. Higher wellhead prices that began in late 1995 and are continuing in early 1997 are expected to be reversed with new deliverability (increased oil flows) from the lower-48 and Canada, explaining the aforementioned backwardation curve.

³⁷ Wolfgang Gajewski, "Using Gas for Power Generation," in Fundamentals of the Natural Gas Industry (London: The Petroleum Economist and Gas World International, October 1995), p. 110. Coal plants have also improved, with a one-half decline in coal input prices and a one-third fall in installed capacity costs in the last ten to fifteen years. CEED Study, pp. 3-9 to 3-10.

³⁸ Energy Information Administration, Annual Energy Outlook, 1996 (Washington, DC: U.S. Department of Energy, January 1996), p. 32.

³⁹ Joseph Schuler, "Generation: Big or Small?," Public Utilities Fortnightly, September 15, 1996, p. 30.

⁴⁰ Surplus capacity means that all electricity-related air emissions associated with building the wind farm is incremental and must be subtracted from later air-emission displacement.

⁴¹ "California grew to dominate worldwide wind development during the early 1980's because the state has some of the most energetic winds in North America, and where these occur, low-cost land was abundant; at the time California had the most favorable purchase power rates and the most cooperative utilities in the nation; it had an abundance of wealth; it had a favorable investment climate; and California offered lucrative incentives to match those of the federal government." Paul Gipe, Wind Energy Comes of Age, p. 30.

⁴² "Our marginal generation cost for oil in the 1970s and early '80s was six cents per kwh. Today it is two cents per kwh using natural gas." Vikram Budhraja, "Generation as a Business -- Fact, Fumbles, Fictions and the Future," The Electricity Journal, July 1995, p. 37.

⁴³ See Southern California Edison Company, Application for Off-System Power Sales Incentive Mechanism, Application 93-08-006, August 2, 1993, p. 2.

⁴⁴ "[The California Energy Commission's Electricity Report 94] demonstrated that there is a sufficient reserve margin within the PG&E service territory [northern California] through 2003." Letter from PG&E to the California Energy Commission, Re: Docket 95-ER-96, January 9, 1996. "Edison agrees with conclusions reached by the CEC in ER 94 that no new resource additions are needed in the Edison system until 2005." Southern California Edison, "Testimony on Submittal of Supply-Side Data," CEC Docket No. 95-ER-96, May 15, 1996, p. 2.

⁴⁵ "Comments of the Institute for Energy Research to the California Energy Commission in the Matter of Preparation of the 1994 Energy Efficiency Report and 1994 Electricity Report," April 4, 1995, p. 13.

⁴⁶ A new wind power contract between Zond Corporation (Enron Corp.) and MidAmerican Energy, despite being the lowest bid, was forced on the unwilling utility by a 1983 set-aside law. Staff Report, "Iowa Utilities Finally Comply With Long-Dormant Renewables Law," March 26, 1997, p. 30. This suggests that either the power is surplus to the needs of the area (and thus backs out cheap surplus power) or was more expensive than conventional new capacity options.

⁴⁷ American Wind Energy Association, "Is a Residential Wind System for You?" May 1995, p. 1. The up-front costs of a home wind system range from $6,000 to $22,000, with an estimated payout from displaced utility electricity between six and fifteen years.

⁴⁸ Ibid.

⁴⁹ Energy Information Administration, Electric Power Annual, 1994, vol. 1, p. 46. California (9.8 cents) and Maine (9.7 cents) were near the 10 cent threshold.

⁵⁰ Ibid.

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