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Sustainable Society:  A society that balances the environment, other life forms, and human interactions over an indefinite time period.







(Part 2 of 3)


Renewable Energy: Not Cheap, Not “Green”*

Robert L. Bradley Jr.
August 1997


Biomass: The Air-Emission Renewable
Geothermal: The Nonrenewable Renewable
Negawatts: Our Dirtiest Resource
Eco-Energy Planning in a Competitive Electricity Industry
    The Downside of Lower Rates for Eco-Energy Planning
    The California Crisis and Restructuring Proposal
    Restructured PURPA: Closing the Renewable Window?
Has Natural Gas Made Renewable Energy Subsidies Obsolete?
    The Open-Endedness of Natural Gas Supply
Is Fuel Diversity Obsolete?
The Increasing Environmentalism of Natural Gas
"Greening" Electricity Prices: Renewables Again Fall Short


Biomass: The Air-Emission Renewable 

Biomass is shorthand for electricity created from a variety of sources of energy such as wood, wood waste, peat wood, wood sludge, liquors, railroad ties, pitch, municipal solid waste, straw, tires, landfill gases, fish oils, and other waste products. Wood accounts for over 60 percent of those inputs. Biomass generated 59 million kWh in 1995, 1.7 percent of national electric power output and 15 percent of national renewable production (see Appendix, Table A.3).

Biomass is not economic today, and even the projected research and development goal of 4 to 5 cents per kWh [194] is still above the cost of new gas-fired capacity and roughly double the spot price of surplus electricity. In the Worldwatch Institute's Power Surge, the authors report that a government-sponsored design competition for a 25-30 MW biomass-fueled gas turbine could cut costs from 8 cents to 5 cents per kWh, "making biomass-fired electricity competitive with conventional coal-fired power plants." [195]

After a decade of liberal subsidies from the federal and state governments, the prospect that biomass will become competitive with coal is not encouraging. Gas-fired combined-cycle capacity is presently 1/2 as expensive to build as a coal plant and has a double-digit percentage levelized cost advantage under a variety of assumptions compared with state-of-the-art coal plants. [196]

Biomass is not environmentally benign from the energy environmentalists' own perspective, as carbon dioxide is released upon combustion ―even more than from coal plants in some applications. [197] Nitrogen oxide and particulates are also emitted. Other environmental problems were stated by Christopher Flavin and Nicholas Lenssen of the Worldwatch Institute:

Although biomass is a renewable resource, much of it is currently used in ways that are neither renewable nor sustainable. In many parts of the world, firewood is in increasingly short supply as growing populations convert forests to agricultural lands and the remaining trees are burned as fuel. . . . As a result of poor agricultural practices, soils in the U.S. Corn Belt . . . are being eroded 18 times faster than they are being formed. If the contribution of biomass to the world energy economy is to grow, technological innovations will be needed, so that biomass can be converted to usable energy in ways that are more efficient, less polluting, and at least as economical as today's practices. [198]

Although biomass is more akin to fossil fuels than to renewables, mainstream environmentalists have kept biomass on the favored energy renewables list. With hydropower banished, biomass is the only sizable option in the eco-energy planners' portfolio. New capacity will not come cheap, however. The Yergin task force estimates that $930 million in future DOE subsidies will be necessary to enable biomass to approach commercialization. [199]

Geothermal: The Nonrenewable Renewable

Geothermal ―steam energy that is generated by the Earth's heated core― is currently produced at 19 sites in four western states (California, Hawaii, Nevada, and Oregon) and accounts for just under 1/2 of 1 percent of national power production and national generation capacity (see Appendix, Tables A.2 and A.3). Production has fallen far short of projections made in the 1980s [200] and is currently in decline because of erratic output from a number of California properties. Nationally, geothermal output in 1995 was 14 percent below 1994, a drop of 2.4 million kWh. [201]

The experience of the world's largest geothermal facility ―the 1,672 MW facility known as the Geysers― is emblematic. As Pacific Gas and Electric reported,

Because of declining geothermal steam supplies, the Company's geothermal units at The Geysers Power Plant are forecast to operate at reduced capacities. The consolidated Geysers capacity factor is forecast to be approximately 33 percent in 1995, which includes forced outages, scheduled overhaul and projected steam shortage curtailments, as compared to the actual Geysers capacity factor of 56 percent in 1994. The Company expects steam supplies at the Geysers to continue to decline. [202]

After reporting a 37 percent performance for 1995 (versus the 33 percent forecast), Pacific Gas and Electric predicted a lower percentage for 1996 due to "economic curtailments, forced outages, scheduled overhauls, and projected steam shortage curtailments." [203]

A number of drawbacks are inhibiting geothermal growth. Geothermal is site specific and may not match customer demand centers. Geothermal sites often are located in protected wilderness areas that environmentalists do not want disturbed. [204] Unique reservoir characteristics and limited historical experience increase investor risk. Depletion occurs where more steam is withdrawn than is naturally recharged or injected, and "inexhaustible" reservoirs can become noncommercial. [205] Alternative water uses or low availability have reduced recharging capacity at the Geysers, for example. Corrosive acids have also destroyed equipment at the facility, and toxic emissions can occur. Promising sites can turn into dry holes upon completion of drilling. [206] Surplus gas-fired generation in California, New Mexico, and Utah also has removed the need for new geothermal capacity. [207] Concluded one journalist conversant with the western U.S. renewable industry,

By all accounts, the utility-grade geothermal power development business has reached a plateau within the United States. The few dozen viable sites identified and developed in California and Nevada during the 1980s are now entering a mature operational phase. New exploration opportunities ―mainly in Oregon and northern California― are sparse due to high cost and perceived "overcapacity" of resources held by utilities. Even expansion of existing plants is limited because of the low avoided-cost energy prices currently available from utilities and the current restrictions on nonutility purchasers. [208]

Is geothermal a renewable resource? One study included the statement that "geothermal is one of the few renewable energy sources that can be a reliable supplier of baseload electricity," yet the same study also noted that "geothermal resources are not strictly renewable on a human time scale, but the source is so vast it seems limitless." [209] Flavin and Lenssen told us five years later, "Although geothermal reserves can be depleted if managed incorrectly (and in come cases have been), worldwide resources are sufficiently large for this energy resource to be treated as renewable." [210] Yet the coal supply of the United States combined with the natural gas supply in North America is arguably "so vast it seems limitless" as well. Geothermal cannot be considered a renewable resource, at least in the United States.

Geothermal is not only a scarce, depleting resource, it has negative environmental consequences despite the absence of combustion. In some applications, there can be CO2 emissions, heavy requirements for cooling water (as much as 100,000 gal. per MW per day), hydrogen sulfide emissions, and waste disposal issues with dissolved solids, and even toxic waste. [211] Those problems and the location problem have caused some environmental groups to withhold support for geothermal since the late 1980s. [212]


Negawatts: Our Dirtiest Resource

If the foregoing renewable fuel sources are dismissed, energy efficiency is left as the "renewable" energy resource of consequence. Conservation as a "supply" of energy has been popularized by many writers, including Daniel Yergin, who in the late 1970s spoke of "conservation energy" as "no less an energy alternative than oil, gas, or nuclear." [213] Yergin then argued that a "serious commitment" to conservation in the United States could result in a 30 to 40 percent reduction in energy use with "the same or a higher standard of living" as a result. [214]

Pacific Gas and Electric, one of the largest electricity utilities in the country, in 1990 called energy conservation the "largest, least-costly untapped resource option." [215] The CEC in 1995 estimated that their state alone could displace more than 6,800 MW of capacity by the year 2005 through energy efficiency. [216] Nationally, capacity savings of approximately 11,000 MW is expected between 1995 and 1999. [217]

"Negawatts" (a termed coined by energy conservation guru Amory Lovins to describe the potential of conservation as a resource) in place of megawatts has become a multi-billion-dollar taxpayer- and ratepayer-subsidized industry. Between 1989 and 1995, the nation's utilities spent $15.1 billion on ratepayer-subsidized electricity conservation programs (known in the industry as "demand-side management," or DSM). Adding pre-1989 expenditures (DSM programs began as early as the mid-1970s), the total is above $17 billion. [218] The DOE has spent as much as $8 billion to $9 billion of its total conservation expenditures of $13.3 billion on state and federal electricity usage reduction programs since inception. [219]

California has led the nation with a $3 billion to $4 billion DSM commitment. Pacific Gas and Electric alone has accounted for over $1.5 billion. [220] Those massive subsidies, which have been reevaluated as too much, too soon, [221] have contributed to the state's abnormally high electricity rates and virtually ensure a nonsustainable level of energy conservation investment in the future. The historic Blue Book proposal of CPUC, in fact, substituted a new public policy goal ―reducing high rates― for the previous one of lowering total bills through conservation. [222]

Like wind and solar farms, utility demand-side management programs are susceptible to environmental review on a total fuel cycle basis. One electricity planner at a major California electricity provider has called DSM "our dirtiest energy source" because gasoline-powered vehicles traverse the countryside to service the thousands of residential and commercial program participants. [223] Motor gasoline, in effect, is being substituted for natural-gas-fired electricity generation in the provider's service territory.

Energy also is expended to manufacture the new energy-saving appliances marketed by DSM programs, and the disposal of traded-out energy assets (such as refrigerators) is an environmental liability that should be accounted for in the DSM environmental equation from the proponents' own viewpoint.

Environmental tradeoffs aside, economic problems threaten the future of utility-provided, ratepayer-subsidized DSM. The law of diminishing returns suggests that the supply of negawatts is a depletable resource. Declining benefit/cost ratios of utility DSM programs are a fact of life in California, [224] not to mention other states. The debate is really about how great the cost savings overestimates have been, not about how much cost-effective energy conservation really remains.

Of note are two particularly rigorous studies by the Illinois Commerce Commission and the DOE's Energy Information Administration. [225] The former examined the full costs of state natural gas DSM-type programs from their inception in 1985 through 1994. The commission found that no program showed benefits greater than costs. [226] In fact, most programs demonstrated benefits that were a mere 25 percent of costs.

The second study examined the total costs and benefits of DSM programs nationwide. The Energy Information Administration concluded that, from 1991 to 1995, approximately $12 billion (nominal) was spent on DSM programs that yielded 215.6 billion kWh of energy savings. Yet the cost of DSM programs over that period averaged 5.58 cents per kWh. Over that same period, however, fossil fuels produced electricity at 2.35 cents per kWh. Thus, subsidized energy conservation was twice as expensive as generated power, much of which came from facilities with unused available capacity (such as in California). [227]

If there were ever an economic honeymoon period for ratepayer-subsidized energy efficiency (and most academic and many professional economists doubt that there was ever an efficient phase of DSM based on empirical investigation and the pure logic of consumer choice), [228] those days have passed.

The impending industry restructuring, which will deliver to the market excess generating capacity and cause rates to drop significantly absent a new round of reregulation, will likely make the "production" of negawatts as unnecessary as the construction of new wind, solar, biomass, and geothermal energy capacity. In fact, increased electricity consumption to better use underperforming (often gas-fired) power plants will be a key strategy to bring average costs down toward the marginal costs of generation in states like California that are trying to be competitive with other jurisdictions.

The new era of constrained electricity conservation has already begun. Soon after CPUC's Blue Book proposal, two of the nation's and California's largest demand-side management utilities announced $206 million in DSM cutbacks for the following year (1995). Consumer groups in the state that were signatories to accelerating DSM investments in 1990 testified against further ratepayer cross-subsidies. The coalition put environmental groups in the awkward position of arguing that DSM spending was good for consumers whether their self-styled consumer representatives knew it or not. [229] In an article in Environmental Action, David Lapp also noticed

the emerging conflict between environmentalists and ratepayer advocates, particularly those representing low-income consumers. Although advocates for low-income ratepayers support energy conservation programs, many are raising questions about who benefits from the programs, how much they cost, and how those costs are distributed. [230]

The ongoing restructuring of the electricity industry removes the traditional rationales for ratepayer-subsidized conservation. First, the utility's incentive to invest in electricity generation so long as the allowed rate of return is greater than its cost of capital will be removed. In a restructured industry, future generation will compete in an open, competitive market and not be artificially encouraged by automatic cost recovery (or "stranded cost" compensation after the fact). [231] Second, flat rates capped at embedded cost, which in peak periods have failed to regulate consumption, will give way to market pricing in a restructured electricity industry. Real-time pricing and other "peaking rate" innovations will spontaneously prevent unnecessary consumption and the generation capacity needed to serve it. With the introduction of real-time pricing, interactive computer technologies controlling "smart appliances" and for-profit energy service companies promise to institutionalize market conservation as an alternative to political conservation in a restructured industry where for-profit opportunities really exist. [232]

In summary, the market is poised to replace both demand- and supply-side planning. As a Sierra Club representative concluded, "DSM as we have known it cannot function in a reasonably competitive marketplace because DSM is a fix to a flawed regulatory system, which competition is intended to replace." [233]


Eco-Energy Planning in a Competitive Electricity Industry

The electricity utility industry is one of America's last bastions of monopoly privilege. Heeding Samuel Insull's call for politicized electricity near the turn of the century, industry leaders successfully lobbied state legislatures to establish commissions to implement cost-plus rate regulation and franchise protection. [234] The predictable result of decades of the "regulatory covenant" is a high-cost, conservative, standardized industry ripe for restructuring. The investor-owned utilities estimate their collective uneconomic generation costs at between $50 billion and $300 billion versus a net worth of $175 billion ―a colossally bad economic investment. [235]


The Downside of Lower Rates for Eco-Energy Planning

Following the "open-access" natural-gas model ―which contributed to a 40 percent real decline in end-user rates in the 1985-95 period― states (and even some foreign countries) are now debating whether to allow end users to shop around for the cheapest power and turn to the utility for transmission and related services only. That economic model is called direct access, or mandatory retail wheeling. Driving the campaign for mandatory retail wheeling is the sizable gap between the (lower) marginal cost of generation and the (higher) average cost that consumers and marketers wish to force out of the system.

The consumers' gain would be eco-energy planning's loss in a retail wheeling world. Lower prices (and estimates are that deregulation could deliver electricity prices between 30 and 40 percent lower than those of today) [236] would

·        increase electricity consumption and accordingly increase the utilization rate of idle fossil-fuel capacity;

·        arrest DSM conservation programs by lengthening the payout period for energy-saving investments;

·        lower generation costs to make renewable generation technologies less competitive and even cause near-term retirements of uneconomic renewable capacity with high operating costs; and

·        incite utilities to resist incurring new uneconomic costs with renewables and conservation that could be "stranded" rather than passed through to the consumer as before. [237]

The restructuring would also likely

·        unbundle rates to itemize surcharges such as those for DSM to facilitate consumer scrutiny and challenge;

·        incite greater integration of geographically dispersed generation and transmission systems and thus remove the need for new electricity-generation capacity (including favored renewables) for some time;

·        replace average-cost pricing by utility providers (where higher cost renewable generation is averaged down by lower cost generation) with stand-alone economic evaluation for each generation source; and

·        introduce time-of-day pricing to value wind power and solar power as intermittent resources at (lower) off-peak rates to the extent that their power generation is noncoincident with demand peaks. [238]

Not surprisingly, sophisticated eco-energy planners did all they could to block interest in mandatory retail wheeling and the lower rates and economic efficiencies that would come with it. Ralph Cavanagh of the Natural Resources Defense Council led a national crusade with a Joint Declaration on the Electric Utility Industry, signed by some 50 groups, to dissuade state officials from even investigating mandatory retail wheeling. [239] Customer choice was described as "a great illusion," a paper shell game reallocating costs from more favored, larger end users to smaller, less favored end users with no overall economic gain. Cavanagh urged states to "go on saying no to retail wheeling in order to be able to create something better: regulatory reforms that align utility and societal interests in pursuing a least-cost energy future." [240] The quasi-reforms urged by Cavanagh were competition in the bulk power market (wholesale wheeling) and performance-based ratemaking for utilities. Monopoly utility service to end users would remain to allow the status quo of renewable and efficiency subsidies via integrated resource planning to continue. The alliance between high-cost utilities and pro-high-rate environmentalists was in clear evidence.

Electricity restructuring is no longer "if" but "when" and "in what form." [241] At the close of 1996, 10 states had either enacted legislation or issued commission orders setting timetables for universal retail wheeling: Arizona, California, Maine, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, and Vermont. Debate also is under way in virtually all of the other lower 48 states. [242]


The California Crisis and Restructuring Proposal

The opening salvo in the electricity restructuring debate was the Blue Book proposal of CPUC, released in April 1994. [243] The ironic but predictable result of the commission's dramatic about-face was that the rate crisis occurred in the very state proclaiming to be the world's leader in renewable energy and subsidized energy efficiency. Table 1 gives an overview of California's commitment to high-cost renewables (as of 1996) and conservation (as of 1994) compared with that of the nation as a whole.

With electricity prices at 150 percent of the national average and nearly double those of neighboring states, rates and total bills rising faster than the national average, and prospective stranded costs potentially greater than the net worth of the state's investor-owned utilities, California's energy diversity and energy-efficiency programs can be called a failure. [244]

Table 1
California's Renewable Capacity versus That of the United States as a Whole (megawatts as of 1995-96)



United States


















Demand-side managementb




Source: California Energy Commission, Department of Energy.
a. Estimated in light of the new California figure.
b. As of 1994.


A Restructured PURPA: Closing the Renewable Window?

PURPA required utilities to purchase power from independent "qualifying facilities" at the utilities' "avoided cost" of self-generation or self-procurement. So-called QF contracts have given small energy projects a long subsidy run and literally spawned the nonhydropower renewables industry.

While achieving its purposes of promoting independent power and renewable generation, PURPA significantly contributed to overcapacity in the electricity-generation market and higher electricity rates overall. [245] Utilities, while concerned about increasing rates, acquiesced so long as state commissions allowed them to pass through qualifying facility costs to consumers and so long as their customers could not bypass the system. With electricity utility restructuring raising the specter of "stranded costs" that might not be recoverable, utility concern turned into legal challenge.

In California, PURPA capital of the nation with nearly 10,000 MW of operational capacity subscribed between 1982 and 1986, [246] two of the state's three largest utilities ―Southern California Edison and San Diego Gas & Electric― petitioned FERC to void a 1993 California PURPA auction. The companies claimed that the capacity of the winning bids they had to accept was not needed, priced above their true avoided cost, and subject to recovery risk as stranded costs. Indeed, CPUC had forced the utilities to accept several hundred megawatts of renewable energy (geothermal and wind) priced at above 6 cents per kWh, compared with available new gas-fired capacity at less than 4 cents per kWh ―a 35 to 40 percent premium. [247]

In a landmark decision issued in February 1995, FERC agreed with the utilities that, given the emerging competitive landscape, avoided cost determinations had to be open to all sellers to accurately measure the utility's avoided cost. FERC summarized:

It is incumbent upon regulators, federal and state, to avoid the creation of transition costs where possible. California's decision to consider a major restructuring of its retail electricity market significantly heightens our concern with stranded costs arising from above avoided-cost rates. We believe it is inconsistent with our obligation under PURPA to ensure just and reasonable rates, and our goals to encourage development of competitive bulk power markets, to permit the use of PURPA to create new contracts that do not reflect market conditions for new bulk power supplies. [248]

In its rehearing order upholding its previous decision, FERC added that "in promoting greater fuel diversity . . . Congress was not asking utilities and utility ratepayers to pay more than they otherwise would have paid for power." [249]

Rejecting the charge that their decision would ruin the renewables industry, the commission reminded CPUC and eco-energy planners that renewable energy goals could be met outside of PURPA through tax incentives and capacity mandates. Still, the high-cost power industry, led by renewable interests, was stunned. Complained Randall Swisher of the American Wind Energy Association,

FERC has turned PURPA on its head. Legislation that was intended to encourage renewables has instead been used to throttle the domestic market for wind and other renewables. . . . This decision effectively closes the door to domestic markets for renewable energy. [250]

The early returns of the marketplace reflected the concerns of renewable interests. PURPA auctions are on hold, and a DOE forecast of electricity generation by fuel source to the year 2015 eliminated 927 MW of new wind-generating capacity, citing FERC's PURPA decision. [251] The economic consulting firm National Economic Research Associates similarly concluded, "A growing realization that expensive 'alternative energy' schemes cannot survive in a competitive environment suggests that electricity generation using renewable energy will increase slowly during the next 10 years." [252]

Joining FERC's reality check on state commissions has been congressional interest in repealing PURPA. Even if the law is not repealed, it faces a de facto demise due to a restructured industry where electricity generation from all sources, utility and independent, will be deregulated to compete on a variable-cost basis. An emerging forward market in "black-box" capacity commitments was another indication that, absent a new round of government intervention, a generation-blind electricity market would make PURPA and renewable quotas obsolete. [253]

Table 2
California's QF Renewable Energy Portfolio (in megawatts)

At-Risk Capacity

Total Capacity at Risk

Percentage Exp. Date


















Total    2,042




Source: California Energy Commission.


With PURPA's future in limbo, existing PURPA contracts are running their course toward expiration. Table 2 compares California's at-risk QF renewable capacity with total renewable capacity. As the clock ticks, renegotiations and contract buyouts of uneconomic qualifying facilities' contracts are occurring, [254] and the CEC is allocating a new round of subsidies to at-risk renewable projects. [255]


Has Natural Gas Made Renewable Energy Subsidies Obsolete?

Economic and technological advances in the natural gas industry (the fuel of choice for new power plants across the country) have direct implications for the debate over fuel use and the environment. Natural gas, in fact, has emerged as a fierce competitor, if not the victor (in both an economic and an environmental sense, as will be discussed) over both subsidized renewable generation and subsidized electricity conservation under present technologies. This is in spite of heavy government support of natural gas's competitors. Renewables' tax credits, as mentioned, swamp wellhead tax deductions. [256] And cumulative DOE subsidies for natural gas of $787 million through FY95 are swamped by over $10 billion given to nonhydropower renewables in the same period. [257]

Renewable energy remains stubbornly uneconomic, not because of past or current federal subsides for rival fuels, but because of the relative scarcity of resources necessary to deliver renewable energy to consumers at a competitive price. The DOE's Energy Information Administration reports that federal energy subsidies in 1990 totaling between $5 billion and $10 billion amounted to only about 1 to 2 percent of the total value of energy production. [258] Energy subsidies alone, in other words, cannot account for the dramatic differences in price between renewable and nonrenewable fuels. [259] Indeed, even the pro-renewable energy Alliance to Save Energy concedes that energy subsidies are responsible for no more than half a cent of every dollar spent on natural gas. [260]

It cannot be said that natural gas has been more heavily advantaged by past subsidies than have renewable fuels. According to Management Information Services, Inc. (an economic consulting firm in Washington, D.C.), total subsidies to renewable energy sources over the past four decades totaled $75 billion, while natural gas was subsidized with $58 billion over that same period of time. Because Management Information Services accepted many of the dubious definitions of subsidy marshaled by the Alliance to Save Energy, the $58 billion is heavily inflated. For example, $51 billion of the total four-decade subsidy credited to natural gas stems from special exemptions, allowances, deductions, and credits occasionally found in the tax code that partially offset double (and sometimes even triple) taxation of capital and capital returns. [261]

In fact, natural gas on net has been victimized by government intervention, not subsidized by it. Long-standing federal wellhead price regulation of natural gas, exacerbated by public utility regulation of interstate gas pipelines and local distribution companies, caused shortages and service moratoriums in interstate markets during the 1970s. [262] Eco-energy planners, like the political establishment, put the blame on nature and not bad public policy. It was believed that rapidly depleting natural gas supplies were insensitive to price and therefore consumption should be phased out of "low-priority" boiler and power plant uses and redirected to "high-priority" residential and commercial uses. [263] The result was the Powerplant and Industrial Fuel Use Act of 1978 and other legislation that further subsidized coal, nuclear, conservation, and renewables at the expense of natural gas.

The Energy Information Administration has concluded that regulatory interventions such as those discussed above are far more likely to unbalance the energy playing field than are direct subsidies.

It is regulation and not subsidization that has the greatest impact on energy markets. . . . The economic impact of just those energy regulatory programs considered in this [pre-1992 Energy Policy Act] report total at least 5 times that amount [of direct fiscal subsidy]. [264]

A decade of deregulation and restructuring later, natural gas has emerged as economically and environmentally a different fuel and a preferred choice for new capacity additions in the United States and, increasingly, abroad. Major developments in the past decade (1985-95) under open-access competition include significant price reductions from the wellhead to the burner tip, system reliability under even abnormal peak-demand conditions, dramatically improved energy-efficiency factors, major emission reductions, and new risk-management practices. As we head toward the new millennium, those developments directly challenge the case for renewable and energy-conservation subsidies.


The Open-Endedness of Natural Gas Supply

Over the last decade, wellhead natural gas prices, after adjusting for inflation, have fallen by one-half, while end-user prices have fallen by 40 percent. The price of natural gas delivered to powerplants fell nearly 60 percent in the same period. [265] In response, gas consumption has increased by 26 percent since the mid-1980s.

Continual reserve replacement and falling gas prices from the wellhead to the burner tip suggest that natural gas is not a nonrenewable resource in a policy-operative sense.

As one industry executive explained,

Domestic supply has increased as fast as it has been consumed ―and at a lower cost. Approximately 185 [trillion cubic feet] of gas was consumed in the United States between 1985 and 1994, yet proven reserves in the lower 48 states remain virtually the same today as they were a decade ago. Natural gas may be a finite, depletable resource under wellhead price regulation, but under market incentives, supply is proving to be open-ended. [266]

The natural gas supply situation in Canada, centered in Alberta, is even more dramatic than in the lower 48 states. Reserves have increased over 5 percent since 1982 despite record production and consumption in the same period. [267] Canadian exports to the United States have almost tripled in the last decade and now account for approximately 13 percent of U.S. consumption. [268] Although uneconomic at present, natural gas reserves from the Alaskan North Slope ―estimated at 26 trillion cubic feet, [269] more than a one-year supply for the entire United States at present consumption rates― await a price economical enough to justify pipeline construction through Canada to the lower 48.

Concerns over the size of the U.S. and North American gas resource base were addressed by a major 1992 study by a National Petroleum Council task force. In addition to near-term inventory (proven reserves) of 160 trillion cubic feet (TCF) as of January 1, 1991 ―a 10-year supply at prevailing consumption rates― conventional supply was estimated at 616 TCF and nonconventional supply at 519 TCF. Together, the nearly 1,295 TCF lower-48 resource estimate represented more than a 60-year supply for the United States. [270]

In addition to the abundant resource base, there is the question of whether at least some methane deposits are classically depletable. The DOE-appointed Yergin task force speculates that some oil and gas deposits are steady-state rather than depletable because of evidence of upward migration from fossil fuels from deeper sources. [271] This view, however, is secondary to the more important one: improving technology literally creates commercial supply where there was none before, and this process is open-ended. [272]

Not only gas supply but pipeline capacity to reach end-use markets is abundant. Ironically, the market with the most surplus natural gas capacity is California, the renewable energy capital of the nation. Between 1.5 billion cubic feet and 2 billion cubic feet per day of surplus natural gas capacity exists in the state, a 25 percent average-day surplus. Whereas regulatory delays in the construction of new pipeline capacity led to natural gas curtailments and oil burning in the state in the 1980s, the long-awaited arrival of three pipeline expansions and one new pipeline in 1992-93 portends surplus capacity well into the next century. [273]


Is Fuel Diversity Obsolete?

In 1992 the CEC held a policy debate on fuel diversity. Supporters of renewable energy lobbied for a fuel diversity penalty on natural gas in the integrated resource planning process to make planned gas-fired capacity additions more expensive relative to renewables. Their rationale was that natural gas had a price risk that renewables, without an energy input cost, did not. In response, the American Gas Association argued that "[energy] cost is only one form of risk, and fuel is only one of the three primary cost components." [274] The association explained,

The argument for fuel diversity is based on concerns with respect to volatility in fuel prices and supplies. But risk to the ratepayer depends on many other variables ―environmental and permitting risk, financial risk, the risk of new versus proven technologies and the risk of operating reliability. All of these risk categories will be translated into ratepayer risk, and gas-fired combined-cycle plants measure up extremely well on each of these measures― as proven by the fact that project developers have moved so strongly toward this technology. [275]

Enron Corp. testified that available long-term, fixed-priced gas contracts, futures hedging, and storage could mitigate or entirely remove price risk. [276] Thus analogies between natural gas and "crack cocaine," [277] insinuating that today's "low" gas prices are fostering unhealthy dependencies should prices spike, are irrelevant. A variety of financial products offers end users the ability to lock in their financial "high" for as long as 20 years. [278] Shorter term hedging can be done on the 18-month futures market. Market institutions have literally made yesterday's fuel diversity concerns obsolete for the sophisticated buyer. [279]

In nonhedged situations, price risk in the short run and the long run is symmetrical. There is no theoretical or empirical reason why the future price of natural gas (like that of other "depletable" resources) must be higher than the present price adjusted for inflation. In the shorter run, market processes continually work to arbitrage intertemporal and geographical prices through drilling, storage, and transmission investments, although surprises always have the market playing catch-up.

Concerns still linger about fuel diversity despite the aforementioned theoretical arguments and new market institutions. FERC commissioner William Massey, in his PURPA decision dissent (June 1995), raised the concern that

If the only costs cognizable under PURPA are quantifiable costs actually incurred by the utility, how would the PURPA process reflect the value of fuel diversity? If a utility today owns only gas-fired generation and places a high value on diversifying its fuel mix by making its next capacity addition something other than gas-fired, does today's order require the avoided cost determination nonetheless to include gas-fired generation? If so, would PURPA prohibit even cost adders to the gas bids to reflect the lower relative value to the utility of gas-fired generation? . . . The majority's order moves perilously close to a rule that PURPA requires selection of the cheapest power regardless of the value of fuel diversity. [280]

The CEC, in a report released in November 1995, cited the "substantial success" of California's having "one of the most diverse electricity systems in the world" and warned that "there is a legitimate concern that if nothing but gas-fired plants are constructed then someday the state may face a situation like the oil embargoes of the 1970s, or another unforeseeable crisis that will send electricity prices skyrocketing." [281]

Such concerns should not be a public policy issue, particularly in a restructured industry where market participants have a variety of risk-mitigating choices and must either make the right choices or be penalized. Without government price and allocation regulation, over a century of experience suggests that a buyers' market will be the rule and a sellers' market the exception for fossil fuels. [282]


The Increasing Environmentalism of Natural Gas

Natural gas has increasingly displaced fuel oil in dual-fuel electricity plants. Whereas electricity generated from natural gas accounted for less than half the dual-fuel power plant market as recently as 1976, it now has more than 80 percent of this market relative to fuel oil. [283] Fuel oil consumption in power plants in 1995 was 82 percent below 1973 (a 458 million barrel drop) and 62 percent below 1989 (a 162 million barrel reduction). [284] Coal, nuclear, and hydropower generation, accounting for approximately 80 percent of electricity generation, is typically baseloaded rather than dispatched because of lower variable costs. Consequently, renewable energy and conservation, traditionally justified as displacing coal and fuel oil emissions from power plants, must now justify displacing a much cleaner burning fuel, natural gas.

Decreased air pollution from existing and new natural-gas-powered plants is as significant a development as the fall in delivered gas prices and the improvement of combined-cycle turbine technology. While carbon dioxide emissions from all fossil-fuel power plants increased 15 percent between 1985 and 1993, CO2 emissions from gas plants decreased 16 percent. While nitrogen oxide (NOx) emissions fell 20 percent for the general power plant population, gas plants registered a 36 percent decrease in the same period. [285] Serving the Los Angeles region, Southern California Edison Company reported a 61 percent reduction in average NOx emissions and a 96 percent reduction in average SO2 emissions in its oil/gas plants between 1990 and 1995. [286]

New power-plant technologies can reduce NOx emissions, the major pollutant from natural gas combustion, by more than 90 percent from the uncontrolled-burn levels of the 1970s (from more than one pound per million Btu to under .1 pound per million Btu). [287] The emission reductions of gas combined-cycle plants are compared with those of coal and fuel oil under present technology in Table 3.

Table 3
Natural Gas Emissions versus Those of Clean Coal and
Residual Fuel Oil in New Power Plants (% reduction using gas)


Natural Gas versus Oila

Natural Gas versus Clean Coal

Sulfur dioxide



Nitrogen oxides



Carbon dioxide






Solid waste



Sources: ICF Kaiser Study for Enron Corp., September 1995;
Applied Automated Engineering Study for Enron Corp., September 1995.
a. 2.7 percent sulfur.


Other studies have found similar advantages for gas. A 1994 estimate by the Worldwatch Institute, for example, was that gas-fired combined-cycle plants emitted 92 percent less NOx, 100 percent less SO2, and 61 percent less CO2 than a pulverized-coal-fired steam plant with scrubbers. [288]

Existing gas power plants have been required to reduce NOx emissions under Clean Air Act requirements, and this situation will continue as new emission reduction targets take effect. New facilities in southern California must either acquire emissions offsets or obtain trading permits. The same California utilities that have led the nation (and the world) in wind and solar development and DSM expenditures have proclaimed that their gas power plants have internalized environmental externalities. As Pacific Gas and Electric testified before the CEC in 1994,

Before addressing how to internalize externalities from powerplants, it is first worth examining whether to internalize them. In the late 1980s, when internalization requirements were added to the Public Resources Code and Public Utilities Code, utility powerplants accounted for 3-5 percent of statewide NOx emissions. Many plants did not have advanced NOx control equipment, such as Selective Catalytic Reduction (SCR). Since then, air quality regulators have imposed "Best Available Retrofit Control Technology" requirements and other regulations that will drastically reduce NOx emissions. In effect, NOx emissions from utility powerplants are being internalized, at a cost of hundreds of millions of dollars. Given these changes, it is not clear whether an additional layer of regulation to internalize externalities from utility powerplants would produce a net benefit to society. [289]

Increased efficiency factors of natural gas, where the same unit of gas combustion produces more electricity, also have resulted in effective reductions in gas power plant emissions. The energy-efficiency factor for gas, as stated earlier, has increased 40 percent since the early 1980s. [290]

Improving gas-fired electricity generation, FERC concluded, "has been made possible by the development of more efficient gas turbines, shorter construction lead times, lower capital costs, increased reliability, and relatively minimal environmental impacts." [291] Given that natural gas is abundant, reliable, contractually price certain, and relatively clean, the question must be asked: why should the economic failure and environmental drawbacks of renewables be overlooked?

Eco-energy planners, while welcoming gas as the most environmentally benign of the three fossil fuels, [292] have been slow to redefine the opportunity cost of conservation and renewable energy not in terms of fuel oil or coal but of natural gas. [293] Testimony by the Natural Resources Defense Council in the California electricity restructuring proceedings warned against increased coal and fuel oil burning, for example, never once mentioning that relatively clean-burning natural gas was now the dominant fuel for California's electricity market. [294]

In contrast to Worldwatch, Greenpeace has urged the phaseout of gas-fired generation. [295] Instead of envisioning natural gas as the bridge fuel to renewables, Greenpeace sees gas as displacing renewables. Stated Jason Salzman,

There will be a new generation of gas-fired powerplants emitting pollutants for another 20 to 40 years that will be built in lieu of, rather than as a bridge to, renewables. We think that gas is undercutting the market for renewables, that the renewable market will hardly grow worldwide, and that our children will face a world in climate crisis. [296]

A Greenpeace world would have little energy generation or production, and what little was produced ―from solar and wind, primarily― would occur during only parts of the day. A modern society would have difficulty functioning under this scenario, to say the least.


“Greening” Electricity Prices: Renewables Again Fall Short

If current environmental standards governing power plant emissions are considered appropriate, or the entire exercise of defining externalities is considered too unscientific a basis for public policy, or both, [297] the externalities of fossil-fuel generation can be considered internalized. State and federal subsidies for favored renewables (and energy efficiency) are unnecessary, and existing tax credits, in fact, can be challenged as overcompensating qualifying renewables.

Yet assuming that fossil plants must be more stringently regulated to address such problems as ozone formation and global climate change, renewable subsidies may still be a poor use of the environmental dollar. The reasons are that

· subsidies are very expensive for renewable technologies that are a very small part of the electricity- generation market;

· natural gas, not coal or fuel oil, is the "opportunity cost" of renewables with existing and new capacity in California and other regions of the country; and

· more effective alternatives exist for air-emission abatement with the same expenditure.

In a September 1996 report, the Natural Resources Defense Council estimated that carbon dioxide emission costs for a coal plant were approximately 2 cents per kWh ($20 per ton) and 1 cent per kWh for a gas-fired facility. Carbon costs at new gas facilities were estimated to be lower still because of more efficient conversion rates. [298] This not only identifies coal plants as the most important target for the environmental dollar, it gives natural gas an environmental value that the renewables premium cannot exceed.

For the sake of argument, an "externality adder" for natural gas can be assigned to see if renewables are justified from an eco-energy perspective. The CEC calculated a "damage function" adder of 1.39 cents per kWh for gas plants located in the Los Angeles basin, the ozone capital of the nation. [299] An externality assignment for a gas plant located in better air-quality areas would be half as much. [300] Yet even the high side of this estimate appears to have been "internalized" already by the existing federal tax credit for qualifying renewables versus gas (now 1.7 cents per kWh), accelerated depreciation, [301] and the aforementioned negative externalities of renewables. Therefore, from a traditional environmentalist perspective, the substantial economic advantage of natural gas over renewables appears to be little disturbed even when externalities are internalized. Concluded the CEC after its painstaking externality exercise,

In the last several [Electricity Reports], our assessments have consistently found that gas-fired plants were the least-cost resource choice. . . . Even in the social cost case, which valued damages from residual emissions, new geothermal and wind plants did not become cost-effective until around 2010, past the end of the twelve-year forecast period. Baseload coal, solar thermal and pumped storage never entered the mix of cost-effective choices, even during a twenty-year assessment. [302]

The externality internalization exercise not only falls short of justifying government mandates, it turns into a double-edged sword for qualifying renewable energy resources, particularly wind and solar energy. Adding DOE subsidies as a "social cost" to the private cost of wind and solar, the externality penalty assigned to natural gas is not only negated but reversed. [303] Dividing the cumulative DOE subsidy to wind power by total U.S. wind output since 1977, roughly estimated to be 30 billion kWh, yields a "social cost" of over 2 cents per kWh ―the price of today's spot electricity. The same calculation with solar output, estimated at 10 billion kWh, yields an astronomical "social cost" of several dollars per kWh. Geothermal, in contrast, with cumulative production since 1977 of 192 billion kWh, almost five times the combined output of wind and solar, has a DOE "social cost" of under 1 cent per kWh. [304] Given the retirement of older wind and solar facilities and the need for further subsidy for new generations of technology, the social costs are not likely to be recouped or even significantly lowered with future production.

Should a carbon tax or carbon trading system be implemented to "correctly" value the social cost of fossil fuels, renewable energy subsidies would become obsolete, and the unfavorable economics or pure environmental costs, or both, of renewables would be controlling. But if the preponderance of evidence today suggests that an imputed externality or social cost for natural gas still leaves such alternatives as wind and solar energy uneconomic, the same verdict should be rendered, and the environmental dollar should be spent elsewhere (if at all). Natural gas should be free to expand its market share against both its more polluting fossil-fuel rivals and its less air-emitting rivals as incentives dictate.

Cofiring or repowering coal plants with natural gas, or substituting cleaner burning subbituminous coal for bituminous coal, are alternatives for the renewable-subsidy dollar. [305] Tax incentives used to reduce SO2 emissions at coal plants can be employed to repower coal plants with natural gas. [306] Environmental initiatives in the transportation sector are another "opportunity cost" of renewable subsidies. The failure of eco-energy planners to consider the opportunity cost of renewable subsidies, instead favoring a "get all the reduction you can get wherever you can get it" mentality, is an intellectual failing and policy convenience that should no longer be accepted.


[194]. Ibid., p. 63.
[195]. Flavin and Lenssen, Power Surge, p. 180.
[196]. ICF Kaiser Study. For coal-fired plants to be competitive, very high gas prices and very low gas-fired generation capacity factors must be assumed. See, for example, Energy Venture Analysis, "Fuel Choice for New Electric Generating Capacity: Coal or Natural Gas?" Study for Center for Energy and Economic Development, Washington, 1994.
[197]. Christopher Flavin, Slowing Global Warming: A Worldwide Strategy (Washington: Worldwatch Institute, October 1989), p. 41.
[198]. Flavin and Lenssen, Power Surge, pp. 176-77.
[199]. DOE Task Force Study, Annex 1, p. 63.
[200]. In 1989 Flavin predicted that year-2000 geothermal capacity would be between 4,200 MW and 18,700 MW. Flavin, Slowing Global Warming, p. 39. Capacity today is around 3,000 MW with little growth anticipated.
[201]. Energy Information Administration, Electric Power Annual, 1995, vol. 2, Table 1.
[202]. Pacific Gas and Electric, Securities and Exchange Commission Form 10-K for the Year Ended December 31, 1994, p. 21.
[203]. Pacific Gas and Electric, Securities and Exchange Commission Form 10-K for the Year Ended December 31, 1995, p. 28.
[204]. "Many of the most promising geothermal resources are located in or near protected areas such as national parks, national monuments, and wilderness, recreation, and scenic areas." Energy Information Administration, Renewable Energy Annual, 1995, p. 79.
[205]. "The steam-powered Coldwater Creek Geothermal Plant, hailed as a source of 'inexhaustible' clean energy at its opening eight years ago, may soon be shut down." Kimberly May, "SMUD Plans to Shut Down Steam Plant," Sacramento Bee, June 21, 1996, p. 1B.
[206]. "In a 'stunning blow' to supporters of geothermal energy, California Energy Company has 'mothballed' drilling operations at the Newberry National Volcanic Monument in Oregon, because it did not find enough superheated water at shallow depths." Mike Freeman, "Failure to Find Geothermal Hot Spot Puts 'Green' Energy Project at Risk," Seattle Daily Journal of Commerce Online, October 22, 1996.
[207]. These points are taken from DOE Task Force Study, Annex 1, p. 70. See also Energy Information Administration, "Geothermal Energy in the Western U.S. and Hawaii: Resources and Projected Generation Supplies," September 1991; Silverman and Worthman, "The Future of Renewable Energy Industries," pp. 17-20.
[208]. Arthur O'Donnell, "A Geyser of Ill Will, Part II," California Energy Markets, November 3, 1995, p. 8.
[209]. Christopher Flavin and Rick Piltz, Sustainable Energy (New York: Renew America, 1989), p. 30.
[210]. Flavin and Lenssen, Power Surge, p. 191.
[211]. "Carbon dioxide is released in direct steam and flash systems at a typical rate of 55.5 metric tons per gigawatt hour, or at approximately 11 percent of the rate for gas-fired steam electric plants." Energy Information Administration, Renewable Energy Annual, 1995, p. 78.
[212]. Complained Sen. Conrad Burns (R-Mont.) to a representative of the Natural Resources Defense Council in congressional hearings in 1989, "Now we have environmental concerns about geothermal energy. In other words, just about the time we want to use them, somebody comes along and says well, do not change the pattern of everything under the ground. And so we have to leave that alone." Arctic Coastal Plain Competitive Oil and Gas Leasing Act, p. 140.
[213]. Daniel Yergin, "Conservation: The Key Energy Resource," in Energy Future: Report of the Energy Project at the Harvard Business School, ed. Robert Stobaugh and Daniel Yergin (New York: Random House, 1979), p. 136.
[214]. Ibid. The father of modern energy conservation is Amory Lovins, whose article "Energy Strategy: The Road Not Taken," Foreign Affairs 55, no. 1 (October 1976): 65-96, popularized "soft energy" (conservation) as an alternative to "hard energy" (new megawatt capacity).
[215]. Quoted in Ralph Cavanagh, The Great "Retail Wheeling" Illusion―And More Productive Energy Futures (Boulder, Colo.: E Source, 1994), p. 8.
[216]. California Energy Commission, 1994 Electricity Report, p. 40.
[217]. Energy Information Administration, Electric Power Annual, 1994, vol. 2, p. 82.
[218]. Energy Information Administration, Electric Power Annual, 1993 (Washington: Government Printing Office, 1994), p. 108; Energy Information Administration, Electric Power Annual, 1995, vol. 2, p. 77. DSM expenditures for 1995 are conservatively estimated at one-half of 1994 levels, or $1.36 billion. Pre-1989 data for the United States are not available, but California's 1980-88 expenditure of $1.5 billion is included in this estimate. All estimates are restated in 1995 dollars.
[219]. DOE Budget Study. See also Appendix, Table A.1.
[220]. Pacific Gas and Electric, Form 10-K for the Fiscal Year Ending December 31, 1994, p. 14.
[221]. Two principals of the consulting firm Barakat & Chamberlin, who were instrumental in creating the analytical framework used to implement California's record DSM commitment, recently stated, "It is now clear that the industry led itself astray regarding the value and appropriateness of DSM activities; the erroneous views that developed regarding the source of the value of DSM came about at least in part because of the way in which the standard tests were applied." John Chamberlin and Patricia Herman, "The Energy Efficiency Challenge: Save the Baby, Throw Out the Bathwater," Electricity Journal, December 1995, p. 39. While those authors estimate the loss from understated costs and overstated benefits in the "millions of dollars"(p. 45), Herman elsewhere has estimated the national cost in the "hundreds of millions of dollars." Patricia Herman, "Reforming Demand-Side Management for the Competitive Power Era," Paper delivered at the conference on New Horizons in Electric Power Deregulation, Cato Institute, March 2, 1995.
[222]. For a discussion of the CPUC reversal of April 1994, see Robert Bradley Jr., "The Electric Restructuring Debate in California," in Restructuring California's Electric Industry: Lessons for the Other Forty-Nine States, ed. Robert Michaels (Houston: Institute for Energy Research, 1996), pp. 11-15.
[223]. The source of this inside joke wished to remain anonymous.
[224]. Seymour Goldstein, "California Utility DSM at the Crossroads," California Energy Commission, January 1995, p. 3.
[225]. Ruth K. Kretschmer, commissioner, Illinois Commerce Commission, Personal communication with Paul Ballonoff, 1996; Energy Information Administration, Electric Power Annual, 1994, vol. 2, Tables 50, 48, 13. Both studies were brought to the author's attention by the manuscript of Paul Ballonoff, Energy: Ending the Never-Ending Energy Crisis (Washington: Cato Institute, forthcoming).
[226]. Personal communication between Illinois Commerce Commissioner Ruth Kretschmer and Paul Ballonoff, 1995. Cited in ibid.
[227]. See Energy Information Administration, Electric Power Annual, 1995, vol. 2, Table 43, p. 77, for DSM program costs and savings and Table 13, p. 35, for the relative costs of the fuel use presumably avoided.
[228]. For various criticisms of DSM from academic and professional economists, see Alfred Kahn, "An Economically Rational Approach to Least-Cost Planning," Electricity Journal, June 1991, pp. 11-20; Paul Joskow and Donald Marron, "What Does a Negawatt Really Cost? Evidence from Utility Conservation Programs," Energy Journal 13, no. 4 (1992): 47-74; Albert Nichols, "How Much Energy Do DSM Programs Save? Engineering Estimates and Free Riders," National Economic Research Associates, Cambridge, Mass., 1993; Albert Nichols, "Estimating the Net Benefits of Demand-Side Management Programs Based on Limited Information," National Economic Research Associates, Cambridge, Mass., 1993; Albert Nichols, "How Well Do Market Failures Support the Need for Demand Side Management?" National Economic Research Associates, Cambridge, Mass., 1992; Ronald Sutherland, "Market Barriers to Energy Efficiency Investments, Energy Journal 12, no. 3 (1991): 15-33; Ronald Sutherland, "Income Distribution Effects of Electric Utility DSM Programs," Energy Journal 15, no. 4 (1994): 1-15; Ronald Sutherland, "Economic Efficiency, IRPs, and Long Term Contracts," Presented to the Western Economics Association, June 12, 1993; Larry Ruff, "Equity vs. Efficiency: Getting DSM Pricing Right," Electricity Journal, November 1992, pp. 24-35; Douglas Houston, Demand-Side Management: Ratepayers Beware (Houston: Institute for Energy Research, 1993); Bernard Black and Richard Pierce Jr., "The Choice between Markets and Central Planning in Regulating the U.S. Electricity Industry," Columbia Law Review 93 (October 1993): 1339-44; Andrew Rudin, "DSM: An Exorbitant Free Ride into an Unsustainable Future," Presented to the Great Lakes Conference of Public Utility Commissioners, July 13, 1992.
[229]. On these points, see Robert L. Bradley Jr., "California DSM: A Pyrrhic Victory for Energy Efficiency?" Public Utilities Fortnightly, October 1, 1995, p. 44.
[230]. David Lapp, "The Demanding Side of Utility Conservation Programs," Environmental Action, Summer 1994, p. 27.
[231]. "The regulated monopoly structure [of] . . . utilities . . . has more often than not led to an exacerbation rather than diminution of environmental problems. Investors need to be free to succeed or fail in the marketplace without recourse to the safety net of cost recovery if we are to efficiently match energy investments with demand." Environmental Defense Fund, Statement before the House Subcommittee on Energy and Power Resources Concerning Electric Regulation: A Vision for the Future, May 15, 1996, p. 1.
[232]. For a discussion of some of these issues, see Lee and Darani, pp. II, 12-15, 24-25.
[233]. Ned Ford, "What Role for DSM Now?" Electricity Journal, March 1996, p. 87.
[234]. For a brief review of the early industry's drive to trade franchise protection for rate regulation, see Marvin Olasky, Corporate Public Relations: A New Historical Perspective (Hillsdale, N.J.: Lawrence Erlbaum Associates, 1987), pp. 33-43. For a longer review, see Robert L. Bradley Jr., "The Origins of Political Electricity: Market Failure or Political Opportunism?" Energy Law Journal 17, no. 1 (1996): 59-102.
[235]. James Rhodes, Statement on behalf of Edison Electric Institute before the House Subcommittee on Energy and Power Resources Concerning Electricity Regulation: A Vision for the Future, May 15, 1996.
[236]. Michael Maloney and Robert McCormick, Customer Choice, Consumer Value: An Analysis of Retail Competition in America's Electric Industry (Washington: Citizens for a Sound Economy, 1996); Robert Crandall and Jerry Ellig, Economic Deregulation and Customer Choice: Lessons for the Electric Industry (Fairfax, Va.: Center for Market Processes, 1997).
[237]. This led directly to the political pressure to suspend PURPA auctions described in the later subsection, A Restructured PURPA.
[238]. Wind, for example, often peaks in the early evening, whereas the demand peak occurs in midafternoon. See Cavallo et al., p. 151.
[239]. The declaration and signatories are reprinted in Ralph Cavanagh, The Great "Retail Wheeling" Illusion, pp. 25-28.
[240]. Ibid., p. 3. See also Ralph Cavanagh, "Electricity Shopping Can Be a Bad Deal," New York Times, June 12, 1994, p. 11. A study by the Worldwatch Institute similarly complained that the "mirage" of retail wheeling "would severely undermine the long-term planning that has been so vital to the evolution of an efficient, environmentally sound electricity market." Christopher Flavin and Nicholas Lenssen, "Powering the Future: Blueprint for a Sustainable Electricity Industry," Worldwatch Paper no. 199, Worldwatch, Washington, June 1994, p. 46.
[241]. One report states that environmentalists have conceded as much, finding solace in the fact that competitive restructuring could hasten the phaseout of the nuclear industry and accelerate "green pricing" to help renewables compete. James Ridgeway, "The Green Movement's Shock Treatment," Village Voice, May 28, 1996, p. 22.
[242]. Rhodes, p. 10.
[243]. For a summary of the first year of the Blue Book debate, see Restructuring California's Electric Industry.
[244]. See generally, Bradley, "The Electric Restructuring Debate in California," and Bradley, "California DSM," pp. 41-47. A sign of the times is that a leading architect of California's central planning failure with electricity, Ralph Cavanagh of the NRDC, received the 1996 Heinz Award in Public Policy as "the most influential figure in Western energy policy." "Cavanagh Wins Congratulations and Cash for Bringing People Together," California Energy Markets, December 13, 1996, p. 2.
[245]. The Edison Electric Institute has estimated above-market PURPA-related costs of "at least" $38 billion. Edison Electric Institute, Statement, p. 11.
[246]. California Energy Commission, "QF-Self Generation LTBA Database," no date, copy in author's files.
[247]. Federal Energy Regulatory Commission, "Order on Petitions for Enforcement Action Pursuant to Secton 210(h) of PURPA," 70 FERC 61666 at 61667, 61672 (1995).
[248]. Ibid. at 61676.
[249]. Federal Energy Regulatory Commission, "Order on Requests for Reconsideration," 71 FERC 62074 at 62079.
[250]. Quoted in Craig Cano, "IPPs Stunned, State Miffed―Just Another Day on the PURPA Front," Inside F.E.R.C., February 27, 1995, p. 14.
[251]. Energy Information Administration, Annual Energy Outlook, 1996, p. 36. DOE also mentioned the "further uncertainty" of Congress's proposed elimination of the 1.5 cent per kWh tax credit. Ibid.
[252]. "NERA Energy Outlook," December 21, 1995, p. 1.
[253]. See, for example, Dennis Wamsted, "TVA Charts New Course, Takes Option on Enron Power," Energy Daily, January 2, 1996, pp. 1, 3.
[254]. See, for example, Arthur O'Donnell, "Edison Files QF Buyout Pact, Seeks Confidentiality of Provisions," California Energy Markets, September 1, 1995, p. 11.
[255]. See later subsection, Deregulate, Do Not Reregulate.
[256]. See earlier subsection, Unfavorable Economics. The depletion allowance was eliminated for integrated oil companies in the Tax Reduction Act of 1975 and significantly reduced for nonintegrated oil and gas production companies in the Tax Reform Act of 1976. The intangible drilling cost deduction was significantly scaled back in the same 1976 law and the Tax Equity and Fiscal Responsibility Act of 1982. See Robert L. Bradley Jr., Oil, Gas, and Government: The U.S. Experience (Lanham, Md.: Rowman & Littlefield, 1996), pp. 337-42.
[257]. See Appendix, Table A.1.
[258]. Energy Information Administration, "Federal Energy Subsidies: Direct and Indirect Interventions in Energy Markets," November 1992, p. x.
[259]. The Alliance to Save Energy calculates that energy subsidies in 1989 totaled $36 billion (about four times larger than the figure calculated by the DOE's EIA), but even this number is relatively inconsequential, in comparison with the total size of the U.S. energy industry (about 6 percent). Still, there are several serious problems with ASE's calculations. First, $11.6 billion of subsidies (almost a third of the total) stems from two programs―accelerated depreciation of capital stock and the generation investment tax credit―that have been repealed. Another $12 billion of the subsidies is not energy subsidies but tax provisions generally available to capital investments. Although ASE argues that those provisions artificially advantage capital investments over less capital-intensive alternatives (such as energy efficiency investments), a truly neutral tax code would not tax capital investments at all, since capital returns are invariably taxed a second time at the point of consumption whereas noncapital consumption is taxed only once. Thus, the "subsidies" castigated by ASE simply help offset the unfair treatment of capital via the corporate income tax and the capital gains tax. Finally, other ASE categories are a stretch, such as the Strategic Petroleum Reserve, considered to be a $2.1 billion annual subsidy to the oil industry. With SPR injections suspended and withdrawals becoming more regular, the subsidy has turned negative. Douglas Koplow, "Federal Energy Subsidies: Energy, Environmental, and Fiscal Impacts," Alliance to Save Energy, April 1993.
[260]. Ibid., p. 20.
[261]. "Federal Government Subsidies and Incentives for U.S. Energy Industries," Management Information Services, Inc., Washington, May 1993.
[262]. See Robert L. Bradley Jr. "The Distortions and Dynamics of Gas Regulation," in New Horizons in Natural Gas Deregulation, ed. Jerry Ellig and Joseph Kalt (Westport, Conn.: Praeger, 1996), pp. 12-14.
[263]. "Th[e] imbalance between [oil and gas] reserves and consumption should be corrected by shifting industrial and utility consumption from oil and gas to coal and other abundant energy sources. . . . By 1990 [under this plan], virtually no utilities would be permitted to burn natural gas." Executive Office of the President, The National Energy Plan (Washington: Government Printing Office, 1977), pp. xii, xix.
[264]. "Federal Energy Subsidies: Direct and Indirect Interventions in Energy Markets," p. x.
[265]. See also the later subsection, The Increasing Environmentalism of Natural Gas.
[266]. Kenneth Lay, "Electric Restructuring: A New Opportunity for Natural Gas," American Oil & Gas Reporter, December 1995, p. 43. For an explanation of the "resource pyramid concept" in place of the "finite volume model" to introduce the dynamic driver of improving technology, see The 1995 Enron Outlook (Houston, Tex.: Enron Corp., 1995), p. 8.
[267]. International Energy Statistics Sourcebook (Tulsa, Okla.: PennWell, 1994), p. 202.
[268]. Energy Information Administration, Natural Gas Annual, 1993, p. 211; Energy Information Administration, Natural Gas Monthly, December 1995, p. 10.
[269]. American Gas Association, 1993 Gas Facts (Arlington, Va.: AGA, 1993), p. 6.
[270]. National Petroleum Council, The Potential for Natural Gas in the United States (Washington: NPC, December 1992), Executive Summary, pp. 5-6.
[271]. DOE Task Force Study, p. 45. Also see Malcolm Browne, "Geochemist Says Oil Fields May Be Refilled Naturally," New York Times, September 26, 1995, p. B5.
[272]. See Ballonoff.
[273]. Robert L. Bradley Jr., "Deregulatory Dynamics: Bypass and Reckoning in the California Natural Gas Market," Presented to the DOE-NARUC Conference, New Orleans, April 27, 1993.
[274]. American Gas Association, "Comments in the Matter of: Preparation of the 1992 Electricity Report (ER92)," Docket no. 90-ER-92, January 24, 1992, p. 6.
[275]. Ibid., p. 3.
[276]. "Natural gas dependence does not create special risks for the prudent buyer over the long term. Widespread decisions to depend on natural gas should not be considered a 'market failure' but a vindication of the economic and environmental advantages of this fuel over its rivals." Trans-western Pipeline Company (Enron Corp.), "Natural Gas and a Potential Fuel Diversity Penalty," Testimony on fuel diversity before the California Energy Commission, Re: Docket 90-ER-92, January 24, 1992, p. 3.
[277]. "Natural gas [is] such a cheap high that it's referred to these days as the crack cocaine of the industry." Linn, "Whirly Birds," p. 12. See also Gipe, p. 478.
[278]. Enron Corp., The Natural Gas Advantage, p. 16.
[279]. For a description of the four stages in the evolution of the natural gas commodity business as of 1992, see Catherine Good Abbott, "The Expanding Domain of the Nonjurisdictional Gas Industry," in New Horizons in Natural Gas Deregulation, pp. 190-92.
[280]. 71 FERC 62074 at 62081.
[281]. California Energy Commission, 1994 Electricity Report, pp. 44, 47. The CEC went on to say that diversity does not appear to be a problem "at this time . . . [to] allow us to see how the market will respond" (p. 47). The report also moves away from renewables-as-diversity (p. 48).
[282]. For a historical review of shortages during regulated periods and "overproduction" during free-market periods in the U.S. oil and gas experience, see Robert L. Bradley Jr., The Mirage of Oil Protection (Lanham, Md.: University Press of America, 1989), pp. 129-39.
[283]. Energy Information Administration, Monthly Energy Review, March 1996, p. 95.
[284]. Ibid., p. 99.
[285]. Energy Information Administration, Annual Energy Review, 1994 (Washington: Government Printing Office, 1995), p. 341.
[286]. Communication from Southern California Edison Company to author, July 15, 1996. Part of the reduction came from eliminating fuel oil burning in favor of natural gas for economic and environmental reasons.
[287]. Natural Gas Council, "New Directions: Natural Gas, Energy and the Environment," May 1993, p. 10; Conversation with Paul Wilkinson, vice-president, American Gas Association, January 24, 1996.
[288]. Flavin and Lenssen, Power Surge, p. 101.
[289]. Mark Meldgim and Curtis Hatton, Pacific Gas and Electric, Testimony before the California Energy Commission on "Internalizing Externalities," Preparation of the 1994 Electricity Report (Docket 93-ER-94), October 20, 1994, p. 1. The 3-5 percent estimate for California compares to a national NOx contribution from gas power in 1994 of 2.5 percent. Environmental Protection Agency, National Air Pollutant Emission Trends, 1900-1994 (Washington: EPA, October 1995), pp. ES-8, A-6.
[290]. Gajewski, p. 110. Coal plants have also been improved, with a one-half decline in coal input prices and a one-third fall in installed capacity costs in the last 10 to 15 years. CEED Study, pp. 3-9 to 3-10. See also "Comments of the American Gas Association," CPUC Blue Book Hearings, July 21, 1994, pp. 12-13.
[291]. 60 Federal Register, 17669.
[292]. Flavin and Lenssen, Power Surge, call natural gas the "prince of hydrocarbons" (p. 91) and add "growing signs suggest that the world is already in the early stages of a natural gas boom that could profoundly shape our energy future. . . . This relatively clean and versatile hydrocarbon could replace large amounts of oil and coal" (p. 92). For a collaborative modeling study between the natural gas industry and eco-energy planners where natural gas displaces fuel oil and coal in electric generation to help achieve aggressive emission reduction goals, see Alliance to Save Energy, American Gas Association, and Solar Energy Industries Association.
[293]. Gipe (pp. 242, 324, 351, 394-95, 426, and 459) is also guilty of this, although he does properly focus on natural gas at the end of his book (pp. 476-79).
[294]. See Bradley, "California DSM," p. 45.
[295]. "We are calling for a moratorium on construction of all fossil-fired power plants, including those that burn gas, oil, and coal, and for a phaseout of all existing power plants burning fossil fuels." Jason Salzman, "The Role of Environmental Externalities in Utility Regulation: Comment," in Opportunities and Challenges for Natural Gas (Washington: Department of Energy/NARUC, 1996), p. 866.
[296]. Ibid., p. 867. Greenpeace criticizes environmental groups such as Worldwatch for participating in "the natural gas greenwash." See Carol Alexander, "Natural Gas: Bridging Fuel or Roadblock to Clean Energy?" Greenpeace, January 1993, pp. iv, 42.
[297]. "At the present time, it is not possible to either develop accurate damage values using the [Air Quality Valuation Model] or assess the accuracy of the damage values derived from the AQVM. This is due to the use of inadequate air quality models and the lack of complete data for health impacts from long-term exposure to air pollutants." California Air Resources Board, In the Matter of: Preparation of the 1994 Electricity Report, August 12, 1994, p. 1.
[298]. Natural Resources Defense Council, "Risky Business: Hidden Environmental Liabilities of Power Plant Ownership," September 1996, p. 6.
[299]. The ER-94 externality adders total 1.39 cents per kWh as follows: NOx (.30 cents), PM (.59 cents), CO2 (.47 cents), SOx (.03 cents), and ROG (.002 cents). California Energy Commission, 1994 Electricity Report, appendix A, part II, section A, pp. 104-5. Another addition can be made for methane leakage, estimated to be 1.4 percent of total gas production. Staff Report, "Gas Is green, EPA, GRI, Industry Study Finds," Gas Daily, November 18, 1996, p. 2. However, such a complete penalty for gas would require a total fuel cycle analysis for renewable energy projects, which would reduce if not reverse the gas adder on a net basis.
[300]. Conversation with Tom Tanton, California Energy Commission, March 4, 1997.
[301]. See earlier subsection, Ratepayer and Taxpayer Subsidies.
[302]. California Energy Commission, 1994 Electricity Report, p. 117. Added former CEC commissioner Richard Bilas, "When we did our integrated resource plans, it didn't matter whether we used cost of control or damage functions [to determine externalities]. And for all practical purposes, it didn't matter what the cost of control was. If it was out of sight, it didn't matter, because the only resources that ever won were gas-fired combined cycles. They won all the time." Richard Bilas, "The Role of Environmental Externalities in Utility Regulation: Comment," in Opportunities and Challenges for Natural Gas: Record of Proceedings of the Fourth Annual DOE-NARUC Natural Gas Conference, p. 864.
[303]. DOE subsidies to both wind and solar are more than $1 million per installed megawatt, which on a levelized basis is close to 8 cents per kWh using a calculation relied upon by Paul Gipe. See Gipe, pp. 238-39. DOE subsidies to gas, on the other hand, are virtually negligible, particularly given that gas-fired electricity output in 1995 was more than 125 times greater than the combined output of wind and solar generation. See Appendix, Table A.1.
[304]. For the cumulative renewable output for the United States per source and by year, see Energy Information Administration, Annual Energy Review, 1995, vol. 1, Table 10.9. Financial figures for DOE subsidies are given in Appendix, Table A.1.
[305]. The $5.8 billion spent by the Department of Energy on wind and solar subsidies over the last 20 years is the financial equivalent of replacing between 5,000 and 10,000 MW of the nation's dirtiest coal capacity with gas-fired combined-cycle units, which would have reduced carbon dioxide emissions between one-third and two-thirds. In contrast, the 2,100 MW of U.S. wind and solar capacity present today, which equates to around 700 MW on a dependable capacity basis, has displaced far less CO2 emissions. Simple mathematics shows that a one-third reduction in CO2 emissions for 5,000 to 10,000 MW is from three to four times greater than even a hypothetical 100 percent reduction in CO2 emissions for 700 MW.
[306]. See, for example, Erin Van Bronkhorst, "Coal Plant in Plan to Clean the Air," Journal of Commerce, December 5, 1996, p. B5.

Courtesy of the Cato Institute.
See original at <
http://www.cato.org/pubs/pas/pa-280.html >.
Cato Policy Analysis No. 280
August 27, 1997
Robert L. Bradley Jr. is president of the Institute for Energy Research in Houston, Texas.
The author of the two-volume Oil, Gas, and Government: The U.S. Experience,
and an adjunct scholar of the Cato Institute.

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