Fossil Fuel Politics
How the New Congress Might Change the Mix
The 108th Congress will very likely resurrect the comprehensive energy and environmental legislation introduced in the 107th Congress, again raising questions about the effectiveness of market intervention in the area of electric generation.
The comprehensive energy proposals that passed the House (H.R. 4) and Senate (S. 517) in the 107th Congress-both of which contained proposals to extend the alternative fuels production tax credit;1 reauthorize the Price-Anderson Act; expand the renewable energy production tax credit to additional fuels;2 and create new tax credits for deploying clean coal technologies,3 combined heat and power systems,4 and fuel cells5-will serve as starting points in the new Congress, but with Republican majorities in both chambers, the new energy legislation will likely lean toward the House-passed bill from the last Congress.
The House energy bill focused more extensively on the exploration and production of fossil fuels, especially oil and natural gas, than did its Senate counterpart. Of the $35.4 billion of tax incentives proposed over 10 years in the House bill, $17 billion were estimated to benefit fossil fuels.6
The Senate energy bill-which emerged from a Democrat-controlled chamber, making it unlikely to be picked up by the new Congress-would have authorized energy tax incentives of $15.2 billion over the next 10 years.7 The bill also contained unique provisions establishing a federal renewable portfolio standard, granting loan guarantees for an Alaskan natural gas pipeline and addressing global climate change.
Other Federal Initiatives
Other federal legislative and administrative initiatives could affect fuel choices for electric generators in the coming years, including global climate-change policy, multi-pollutant legislation, and the Federal Energy Regulatory Commission's (FERC's) standard market design (SMD) proposal.
Among these, global climate change is the "elephant in the room." While the Bush administration has rejected the Kyoto Protocol, it would be unrealistic to believe that electric generation will not eventually be affected by a greenhouse gas emissions initiative, likely modeled on the SO2 trading program under the acid rain provisions of the Clean Air Act.
The multi-pollutant bills introduced in the 107th Congress set the stage and defined the parameters of what is likely to be a more active debate in the 108th Congress. The Clean Air Planning Act of 2002,8 introduced by Sen. Thomas Carper, D-Del., and the Clean Power Act of 2001,9 introduced by Sen. James Jeffords, I-Vt., proposed four pollutant schemes that would have regulated CO2 emissions and required additional NOX, SO2, and mercury emissions reductions beyond those required by current law. The Jeffords bill was more stringent than the Carper bill, as it would have required earlier compliance and greater levels of emissions reductions.
The Bush administration's alternative, the Clear Skies initiative, was unveiled in early 2002 and later introduced as legislation.10 The initiative sought additional reductions in NOX, SO2, and mercury emissions by 2010 and 2018, and also sought to amend the New Source Review program under the Clean Air Act. The initiative did not propose limiting CO2 emissions, which distinguished it from the competing Democratic legislation.
The Republican Senate majority in the 108th Congress greatly reduces the likelihood that a four-pollutant bill will be the starting point for consideration of multi-pollutant legislation in the new Congress. Instead, Clear Skies or a similar three-pollutant bill, will likely be the starting place for the legislative debate in the 108th Congress.
In 2001, members of Congress requested a series of Energy Information Administration (EIA) analyses concerning how new multi-pollutant limits could affect the electric generation fuel mix and electricity pricing. The responses to these inquiries provide a starting point for contrasting how a three-pollutant bill versus a four-pollutant bill might affect fuel choice and the cost of electricity.
In a four-pollutant scenario roughly equivalent to the Jeffords bill, EIA forecasted dramatic shifts in gas-fired and coal-fired generation, and not insignificant increases in the price of electricity. Under the assumption that CO2 emissions limits were implemented by 2007 and held to 1990 levels, EIA forecasted that the price of electricity would increase from 6.1 cents per kilowatt-hour to 8.0 cents per kilowatt-hour by 2010.11 EIA also forecasted that, compared to its baseline assumption, natural gas-fired generation would increase by almost 70 percent, from 826 billion kilowatt-hours to 1,395 billion kilowatt-hours, and that coal-fired generation would decrease by more than 40 percent, from 2,238 billion kilowatt-hours to 1,276 billion kilowatt-hours.12
One of the congressional inquiries requested that EIA examine the effect that a renewable portfolio standard (RPS) might have on electricity prices and the electric generation fuel mix under a four-pollutant scenario. In response, EIA forecasted that a mandatory RPS reaching 20 percent by 2020 would increase the overall cost of compliance with CO2 caps by $21 million. Electricity prices would be 0.1 cents per kilowatt-hour higher in 2010 due to the additional cost of constructing renewable energy facilities instead of gas-fired facilities. Electricity prices in 2020, however, would be 0.6 cents per kilowatt-hour lower with an RPS, because increased reliance on renewable energy would decrease demand for natural gas and carbon allowances, thereby offsetting the price impact of high-cost renewable energy.13 When compared to the four-pollutant scenario capping CO2 emissions at 1990 levels without an RPS, the introduction of an RPS eliminates an additional 356 billion kilowatt-hours of coal-fired generation and eliminates 395 billion kilowatt-hours of the increase in gas-fired generation that would have occurred otherwise.14
In response to another request, EIA looked at the differences between three-pollutant and four-pollutant scenarios. In particular, EIA was asked to examine alternative three-pollutant scenarios, where NOX, SO2, and mercury emissions were reduced by 50, 65, and 75 percent by 2012.15 EIA also was asked to examine the additive effect of requiring electric generators to acquire offsets for any increase in CO2 emissions that occur beyond the level expected in 2008.
In the three-pollutant scenarios, coal-fired generation declined slightly, while gas-fired generation increased roughly in lockstep with the decline in coal-fired generation16 . In contrast to its analysis of the price effects of a four-pollutant scenario with CO2 emissions capped at 1990 levels, EIA did not forecast any significant change in electricity prices over the next 20 years attributable to the new emissions limits.17 While NOX, SO2, and mercury were reduced by 75 percent, there was a 0.1 cent per kilowatt hour increase in electricity prices.18 By 2020, the increase was 0.4 cents per kilowatt-hour at the same reduction percentage.19
With CO2 emissions capped at 2008 levels, coal-fired generation declined by 408 billion kilowatt-hours, where three-pollutant missions were reduced by 50 percent (327 billion kilowatt hours greater than under the three pollutant scenario), 460 billion kilowatt-hours where three-pollutant emissions were reduced by 65 percent (293 billion kilowatt hours greater than under the three-pollutant scenario), and 508 billion kilowatt-hours where three-pollutant emissions were reduced by 75 percent (289 billion kilowatt hours greater than under the three-pollutant scenario).20 When combined with three-pollutant emissions reductions under the three scenarios, EIA forecasted that CO2 emissions capped at 2008 levels would cause electricity prices to increase by between 0.9 cents and 1.0 cent per kilowatt-hour by 2020.21
EIA's responses to the congressional inquiries confirm what one would suspect: three-pollutant regulation will have less of an impact on fuel choice for electric generation and electricity prices due to the absence of requirements directly regulating carbon emissions. The carbon emission limits that would be added by four-pollutant legislation would significantly affect the fuel mix and electricity pricing, because coal-fired electricity generation accounts for such a significant part of the U.S. generation portfolio22 and also contributes greatly to overall carbon emissions compared with other generating technologies.
Policies affecting access to federal lands for the exploration and production of natural gas could significantly affect the supply and price of future natural gas supplies. According to EIA, increased access to federal lands could increase the exploitable resource base in the Rocky Mountains by 29 trillion cubic feet (tcf) and reduce the cost and development time for exploiting an additional 59 tcf of natural gas resources. Similarly, increased access would increase exploitable resources on the Outer Continental Shelf by 58 tcf. This would translate into increased production and decreased price. EIA projects that under a high-demand scenario, such as one including CO2 emissions reduction mandates, increased access to public lands could result in an additional 1.1 tcf of domestic production in 2020, while also contributing to a 15-cent per thousand cubic feet reduction in price compared to the base case.23
While it is quite possible that multi-pollutant legislation will not be ripe for passage in the 108th Congress, a federal initiative affecting fuel choice that could be implemented in the near future is FERC's SMD rulemaking.24 SMD proposes a common set of rules for all jurisdictional public utilities (i.e., investor-owned utilities) that own, operate, or control transmission facilities. Among its specific proposals, the SMD rulemaking proposes a resource adequacy requirement that requires load-serving entities to arrange for sufficient resources to meet their peak demand, plus at least a 12 percent reserve margin. Such long-term planning can potentially affect fuel and generating technology choices, as it may make generators more inclined to invest in projects involving greater capital costs and longer lead times in lieu of quickly deployed measures, such as gas-fired turbines.
At present, FERC is collecting public comment on the SMD NOPR. The resource adequacy proposal has been controversial due to concerns expressed by state regulators and elected officials that the proposal federalizes a function that historically has been performed by the states. Still, even if it is amended or is dropped from the final rule, the proposed resource adequacy requirement highlights the point that new approaches may be required to address resource planning in the context of restructured wholesale power markets that are regional in scope.
It also highlights the question of whether fuel and generating technology choice will be left completely to the market or whether regulators and policy-makers should intervene to influence such choices.
In the absence of federal policies, individual states are now acting on a host of issues affecting fuel and technology choices for electric generation. Massachusetts and New Hampshire have legislated controls on greenhouse gases emitted from utilities. Several states, including Texas, have established renewable portfolio standards that require a certain percentage of total electricity generation produced from renewable energy sources.25 North Carolina recently enacted the Clean Smokestacks Act, requiring utilities to achieve additional emissions reductions in return for a rate moratorium.26 This could be the start of a trend leading to a disjointed set of state requirements affecting fuel and generating technology choices for the electric power industry and perhaps creating a greater imperative for federal action.
Federal policies affecting fuel choice for electric generation can include tax incentives, direct transfers, research and development, economic and environmental regulations, and transportation policy. Direct incentives in the form of tax expenditures and direct transfers are modest compared to both the overall size of energy markets and direct incentives for other segments of the economy. Still, targeted incentives can have a significant effect on the subject fuels and technologies.
While fuel-neutral on their face, economic and environmental regulations can have a significant effect on fuel choice. The Clean Air Act Amendments of 1990 resulted in fuel switching for existing coal-fired generators and added to the impetus for natural gas as the fuel of choice for new generators. Electric restructuring lowered barriers to market entry and placed an emphasis on cost recovery at market-clearing prices. This favored low-capital cost, short lead time technologies for new generation.
Comprehensive energy legislation is likely to be resurrected in the 108th Congress. Compared to the legislation considered in the 107th Congress, it is likely to include a greater emphasis on the increased production of energy from conventional fuel sources. Future environmental legislation has a much greater potential to affect profoundly the choice of fuel and technology for electric generation. This is especially true if such legislation includes a four-pollutant strategy (e.g., CO2 is included among the targeted pollutants).
More immediately, fuel and technology choice for electric generation could be affected by electric industry restructuring policies and by environmental initiatives in individual states. In sum, while direct government intervention in fuel markets has waned, federal energy and environmental policies will continue to affect fuel and technology choice for electric generation.
- The House and Senate bills proposed extending the alternative fuels production tax credit and expanding the qualifying fuels. The Senate bill extended the credit by three years for new facilities and two years for older facilities that produce certain fuels from lignite. The House bill extended the credit by four years for new facilities and three years for older facilities. The Senate bill included as qualifying fuels refined coal that meets emissions reduction targets, heavy oil, and gas from a coal mine that will be mined for coal.
- The Senate bill would have expanded the list of qualifying facilities to include coal co-fired with closed-loop biomass, open-loop biomass, swine and bovine waste, geothermal, solar energy, small irrigation power facilities, municipal biosolids, and recycled sludge. The bill also would have extended the placed-in-service deadline from 2003 to 2006. The House bill would have expanded the list of qualifying renewables to open-loop biomass and landfill gas and extended the placed-in-service deadline to 2006. It is speculated that under the House bill, by 2020, the tax credit could result in an additional 4 GW of wind capacity, an additional 2 GW of dedicated biomass capacity, and an additional 1 GW of landfill gas capacity. at 14. The overall share of renewable generation capacity could increase from 2.2 percent to 3.4 percent. Id.
- The legislation would have created two clean coal technology (CCT) tax credits. In the House version, the first credit would have been a 10 percent investment tax credit for investments in selected types of advanced CCT. The Senate bill would have based the investment credit on a variable rate. The second credit would have been a production credit for electricity generated from either advanced CCTs, or existing retrofitted coal-fired steam generators. The House bill also would have authorized an annual appropriation of $200 million through 2011 toward the Clean Coal Power Initiative to advance efficiency, environmental compliance, and cost competitiveness.
- The House version would have treated 50 kilowatt systems as business energy projects, qualifying them for a 10 percent investment tax credit. The recovery period for such investments would be increased from 15 years to 22 years. The Senate bill mirrored the House version, but also allowed property using back-pressure steam turbines to qualify.
- The House bill would have created a 10 percent tax credit for investments in stationary fuel cells, subject to a maximum credit of $1,000/kW of capacity. The Senate version provided a tax credit for business use of fuel cells and for stationary microturbine power plants. The credit for fuel cells would have been either 30 percent of costs or $1,000/kW of capacity, whichever is less. For microturbine power plants, the credit amounts to 10 percent of costs, up to $200/kW of capacity.
- Mark Holt and Carol Glover, Congressional Research Service, Omnibus Energy Legislation: H.R. 4 Side-by-side Comparison, Order Code RC3142 at 3-4 (2002) [hereinafter CRS].
- The Clean Air Planning Act of 2002, S. 3135, 107th Cong. (2002).
- The Clean Power Act of 2001, S. 556, 107th Cong. (2001).
- The Clear Skies Act of 2002, H.R. 5266, 107th Cong. (2001); see also The Clear Skies Act of 2002, S. 2815, 107th Cong. (2002).
- Id. at 41.
- Id. at 40, table 3.
- Under this request submitted by Sens. Smith, Voinovich and Brownback, the varying levels of assumed SO2 emissions were below the level required by full implementation of CAAA90, assumed NOX emissions were below 1997 levels, and assumed mercury emissions were below 1999 levels. Id. at 43.
- Compared to the reference case of 2,238 billion kilowatt-hours of coal-fired generation in 2010, coal-fired generation declined by between 76 billion kilowatt-hours under the 50 percent reduction scenario and 170 billion kilowatt-hours under the 75 percent reduction scenario. Compared to the reference case of 2,302 billion kilowatt-hours of coal-fired generation in 2020, coal-fired generation declined by between 81 billion kilowatt-hours under the 50 percent reduction scenario and 219 billion kilowatt-hours under the 75 percent reduction scenario. Id. at 44, table 4.
- No change occurred where pollution levels for NOX, SO2, and mercury were reduced by 50 percent and only a 0.1 cent increase per kilowatt-hour where three-pollutants were decreased by 65 and 75 percent. By 2020, the price difference under the 75 percent scenario was just 0.4 cents per kilowatt-hour.
- at 44, table 4.
- at 45, table 5.
- Coal accounts for slightly over 50 percent of U.S. electric generation today and, under EIA's baseline assumptions, will still account for 46 percent of U.S. generation in 2020. at 75.
- at 22; see also Office of Integrated Analysis and Forecasting, Energy Information Administration, Department of Energy, U.S. Natural Gas Markets: Mid-Term Prospects for Natural Gas Supply, No. SR/OIAF/2001-06 at ix (2001).
- at 80. State renewable portfolio standards will contribute to 7,035 MW of additional renewable generating capacity through 2020. Texas projects an increase of 2,279 MW of renewable generation resulting from renewable portfolio standards and renewable fuel mandates. California, Nevada, and New Jersey also project large increases in renewable generation totaling 1,930, 1,148, and 904 MW, respectively.
- The Clean Smokestacks Act, S.B. 1078, 2002 Gen. Assem. (N.C. 2002).
Federal Fuel Incentives for Electric Generators: Past and Present
Whether federal intervention in fuel and generating technology markets is good policy depends largely on one's ideological inclination-a debate beyond the scope of this article. Still, it is useful to discuss briefly the successes and failures of such interventions in terms of the results achieved.
By most accounts, the Powerplant and Industrial Fuel Use Act of 1978 (FUA)1 exemplifies a federal intervention that produced undesirable results. The FUA prohibited using natural gas and petroleum as energy sources in new electric and existing power plants and prohibited constructing any new electric power plant without the capability to use coal or any alternate fuel (i.e., most fuels other than natural gas or petroleum) as a primary energy source.2 Ultimately, the FUA was amended to allow for more fuel choices.3 Specifically, the amendments repealed the prohibitions against using natural gas and petroleum as a primary energy source in new and existing electric power plants, while requiring any plant constructed as a base load supplier also to have coal or other alternate fuel capabilities.
In contrast, the alternative fuels production tax credit (i.e., the Section 29 credit) exemplifies a highly effective, targeted intervention into the fuel markets. This credit has contributed mightily to the supply of natural gas from coalbed methane. From 1989 to 2000, coalbed methane recovery increased by a factor of more than 10, from 91 billion cubic feet to 1.4 trillion cubic feet.4 By 2000, coalbed methane accounted for 7.2 percent of domestic natural gas production.5
Overall, federal intervention in the fuels market, when measured in terms of tax expenditures and direct transfers, is relatively insignificant. Federal incentives/subsidies to the energy markets in 1999 accounted for just 1 percent of the total 1995 retail expenditures on energy.6 Another measure of the relative lack of federal intervention in fuels markets is to compare federal tax expenditures for fuels with tax expenditures directed to other sectors of the economy. According to the Energy Information Administration (EIA), incentives/subsidies in the form of tax expenditures directed to the energy market account for just 0.3 percent of all government tax expenditures.7
Given the increasingly significant role of natural gas as a fuel for electric generation, electric generators are affected indirectly by the various federal policies that affect the marginal economics of producing natural gas. Federal tax law that permits the expensing of exploration and development costs creates incentives for petroleum and natural gas exploration and production.8 The alternative fuels production tax credit likewise provides a tax credit to qualified fuels drilled from certain wells.9
Another current federal incentive affecting electric generation is the renewable energy production tax credit (i.e., the Section 45 credit) provided to generators that produce electricity using wind or closed-loop biomass processes.10 The nuclear generating sector also benefits from federal support in the form of the Price-Anderson Act, which limits the liability of nuclear plant operators in the event of an accident involving commercial nuclear power plants. For the 110 nuclear units operating in 1991, the total subsidy would have been $3.6 billion in 1999 dollars.11
Most federal incentives are targeted at particular fuels and technologies. Therefore, such incentives, while relatively small when their dollar value is compared with the overall size of the fuels market, still can have a significant effect on the economic viability of the targeted fuel or technology. For instance, the Section 29 tax credit provides a benefit upward of $1 billion annually to natural gas producers who produce eligible fuels, such as coalbed methane.12 Another example of a targeted incentive is the $0.7 billion that ethanol producers receive annually in the form of an excise tax exemption.13
Of course, federal interventions affecting fuel choice for electric generation are not limited to tax expenditures. The Clean Air Act Amendments of 1990 (CAAA90) have greatly affected fuel choices for electric generation. CAAA90 added to the advantages of natural gas as the fuel for new generation because, compared to coal-fired generators, gas-fired generators emit SO2 and NOX at far lower levels.14 CAAA90 also provided an impetus for low-sulfur coal, because many coal-fired generators found it more economical to comply by fuel-switching instead of installing emissions control technology.
Between 1990 and 1995, 52 percent of the generating units mandated to lower sulfur dioxide emissions under Phase I of the CAAA90 switched to low-sulfur coal.
Not coincidentally, during the overlapping period between 1986 and 1997, Western coal mine productivity (where one can find the highest concentrations of low-sulfur coal deposits) rose by 89.6 percent.16 Low-sulfur coal production is expected to continue increasing by 2.5 percent annually for the next 20 years.17
Electric restructuring initiatives (e.g., FERC Order No. 888), while fuel-neutral, also affect fuel choices for new electric generation. Such initiatives have removed significant barriers to market entry and have increased reliance on competitive markets for cost recovery. These market conditions have favored the comparatively low capital cost and short lead time for installation offered by natural gas turbines.
- Powerplant and Industrial Fuel Use Act of 1978, Pub. L. No. 95-620, 92 Stat. 3289 (codified as amended at 42 U.S.C. § 8301-8484 and in scattered sections of 15, 19, 42, and 49 U.S.C.).
- 42 U.S.C. § 8302(6) (2001).
- Act of May 21, 1987, Pub. L. No. 100-42, 101 Stat. 310.
- Office of Energy Markets and End Use, Energy Information Administration, Department of Energy, , No. DOE/EIA-0206(00) at 79 (2002).
- Office of Integrated Analysis and Forecasting, Energy Information Administration, Department of Energy, Federal Financial Interventions and Subsidies in Energy Markets 1999: Primary Energy, No. SR/OIAF/99-03 at 5 (1999) [hereinafter ].
- Id. at 13.
- Specifically, the law allows integrated oil companies to expense 70 percent of their intangible drilling costs for successful domestic wells, while amortizing the remaining 30 percent over the next 5 years. Independent oil producers can expense 100 percent of their intangible drilling costs for all domestic wells. at 64.
- Most of the Section 29 credits have been paid to coalbed methane producers. In 1992, 78 percent of all gas wells drilled for exploitation of gas were drilled in coal seams, tight sands, and shale oil. at 20.
- The credit is projected to amount to approximately $20 million to $30 million annually to qualified renewable energy facilities. at 75.
- at 42.
- at 11.
- at 11.
- Energy Information Administration, Department of Energy, Annual Energy Outlook 2002, No. DOE/EIA-0383 (2001) [hereinafter ].
- Id. at 12 (omitting footnote).
- Richard Bonskowski, Energy Information Administration, at 11-12 (1999).
- at 92.
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