Minnesotans For Sustainability©
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.
Biomass: The Air-Emission Renewable
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  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." 
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. 
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.  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. 
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. 
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  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. 
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. 
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." 
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.  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.  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.  Surplus gas-fired generation in California, New Mexico, and Utah also has removed the need for new geothermal capacity.  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. 
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."  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."  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.  Those problems and the location problem have caused some environmental groups to withhold support for geothermal since the late 1980s. 
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."  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. 
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."  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.  Nationally, capacity savings of approximately 11,000 MW is expected between 1995 and 1999. 
"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.  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. 
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.  Those massive subsidies, which have been reevaluated as too much, too soon,  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. 
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.  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,  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.  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.  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). 
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),  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.  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. 
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).  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. 
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." 
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.  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. 
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
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)  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
utilities to resist incurring new uneconomic costs with renewables and
conservation that could be "stranded" rather than passed through to the consumer
as before. 
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
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. 
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.  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."  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."  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. 
The opening salvo in the electricity restructuring debate was the Blue Book proposal of CPUC, released in April 1994.  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.
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. 
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.  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,  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. 
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. 
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." 
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. 
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.  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." 
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. 
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,  and the CEC is allocating a new round of subsidies to at-risk renewable projects. 
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.  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. 
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.  Energy subsidies alone, in other words, cannot account for the dramatic differences in price between renewable and nonrenewable fuels.  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. 
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. 
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.  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.  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]. 
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.
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.  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. 
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.  Canadian exports to the United States have almost tripled in the last decade and now account for approximately 13 percent of U.S. consumption.  Although uneconomic at present, natural gas reserves from the Alaskan North Slope ―estimated at 26 trillion cubic feet,  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. 
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.  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. 
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. 
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."  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. 
Enron Corp. testified that available long-term, fixed-priced gas contracts, futures hedging, and storage could mitigate or entirely remove price risk.  Thus analogies between natural gas and "crack cocaine,"  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.  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. 
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. 
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." 
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. 
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.  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).
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.  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. 
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).  The emission reductions of gas combined-cycle plants are compared with those of coal and fuel oil under present technology in Table 3.
Sources: ICF Kaiser Study for Enron Corp.,
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. 
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. 
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. 
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."  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,  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.  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. 
In contrast to Worldwatch, Greenpeace has urged the phaseout of gas-fired generation.  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. 
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.
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,  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
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.  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.  An externality assignment for a gas plant located in better air-quality areas would be half as much.  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,  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. 
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.  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.  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.  Tax incentives used to reduce SO2 emissions at coal plants can be employed to repower coal plants with natural gas.  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.
. Ibid., p. 63.
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