The Role of Tax Incentives in Energy Policy
Testimony prepared for presentation to
Committee on Finance
United States Senate
September 12, 2001
by Howard Gruenspecht, Resident Scholar
Resources for the Future
1616 P Street, NW • Washington, DC 20036 • www.rff.org • 202-328-5000
The Role of Tax Incentives in Energy Policy
Testimony prepared for presentation to
Committee on Finance
United States Senate
September 12, 2001
by Howard Gruenspecht, Resident Scholar, Resources for the Future*
Thank you Chairman Baucus, ranking member Grassley, and members of the committee for the
opportunity to testify on tax issues affecting the electricity sector. I am Howard Gruenspecht, a
Resident Scholar specializing in energy issues at Resources for the Future (RFF), a nonprofit,
non-advocacy research and educational organization specializing in problems of natural
resources and the environment since 1952. Before joining RFF, I worked at the Department of
Energy from 1991 until 2000, most recently as Director of Economic, Electricity and Natural
Gas Analysis. The views I express today are my own, not those of RFF.
These are exciting times (sometimes too exciting) in electricity markets. Wholesale electricity
markets are being restructured pursuant to provisions of the 1992 National Energy Policy Act.
Restructuring of retail electric markets is occurring in some states, although others have recently
placed planned retail restructuring efforts on hold pending an evaluation of recent events in the
West. Large amounts of generation capacity are being added, and it is entirely possible that there
will be a generation surplus in some areas over the next few years. However, transmission
capacity additions are lagging behind peak load growth, and there is significant uncertainty
regarding the rules and institutions that will govern the operation of the bulk power transmission
system.
I know that the committee will receive detailed testimony from industry participants outlining
the case for particular changes that would reduce their tax liability. Therefore, I will focus my
testimony on several lessons from my own research and policy analysis work, as well as the
*
Resources for the Future, 1616 P Street, NW, Washington DC 20036 (email: gruenspecht@rff.org).
Testimony by Howard Gruenspecht, Resources for the Future
September 12, 2001
broader economics literature, which may help the committee in prioritizing these proposals. I
will try to illustrate each of these points by drawing on some of the specific electricity-related tax
proposals that are the subject of this hearing.
Restructuring causes a need for some tax changes, but they are sometimes packaged with
unrelated provisions that should be judged on their own merits.
It is clear that certain assumptions about electricity markets that are reflected in our existing tax
laws no longer apply in a restructured industry. For example, while restructuring has created a
market for the sale of existing nuclear power plants to operators who will use them to supply
competitive wholesale power markets, the laws governing contributions to qualified
decommissioning funds for these plants presume that they operate under cost-of-service
regulation. Another well-known example relates to public power utilities with generation and
transmission assets that have been financed with tax-exempt debt. Under existing law, providing
open access to transmission facilities or selling power in competitive markets could subject
existing bonds to the loss of tax exemption or other costly penalties. Because this risk creates
strong disincentives for public power utilities to offer open access or compete in wholesale
power markets, the current tax regime can significantly reduce the consumer and marketefficiency benefits promised by restructuring.
While restructuring definitely creates a need to revisit certain existing tax provisions, many of
the proposals before the committee combine fixes needed in response to restructuring with
additional tax changes that are largely unrelated to restructuring. In such cases, I believe it is
appropriate to carefully consider the merits of the individual elements.
The tax treatment of qualified nuclear power plant decommissioning funds is one area where
proposals before the committee go substantially beyond restructuring-related fixes. In addition
to removing the requirement that deductible contributions to these tax-advantaged funds be
capped at the level allowed under cost-of-service regulation, S.389, S.972, and the recently
passed House legislation (H.R. 4) would repeal the present limitation that a qualified fund only
accumulate an amount sufficient to cover the share of a nuclear power plant’s decommissioning
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Testimony by Howard Gruenspecht, Resources for the Future
September 12, 2001
costs incurred during the period in which the qualified fund is in existence (generally post-1984
decommissioning costs). Nuclear plant owners would be allowed to make additional
contributions to cover the portion of decommissioning costs that were previously ineligible for
coverage for qualified funds. A buyer or seller of a nuclear plant would also be allowed to make
additional contributions to qualified funds as required pursuant to the terms of the transfer
agreement.
Proposals to allow substantially increased and accelerated contributions to qualified funds must
be considered in the context of recent developments in the nuclear power sector. Just a few years
ago, forecasts suggesting that many existing nuclear power plants would be unable to compete in
restructured markets and would be retired prematurely were widely disseminated. The actual
experience has been far different. Nuclear generation costs have been tightly managed and
capacity utilization rates for the nuclear fleet have increased dramatically. The market value of
existing nuclear plants has been rising steadily and many operators are seeking to renew the
initial 40-year licenses granted by the Nuclear Regulatory Commission (NRC) for an additional
20-year period. Six reactors have been relicensed over the past 18 months. Fourteen relicensing
applications are now pending before NRC, and 24 additional plants have already indicated their
intention to file applications by 2005. It is widely expected that many more plants will seek
relicensing.
Given that a new longer lifetime appears likely for most nuclear units, qualified funds
accumulated under the existing law may already be well ahead of a level funding profile for total
decommissioning costs, including those associated with pre-1984 operation. Life extension for
existing nuclear power plants affects the economics of decommissioning funds in two significant
ways. First, the start of decommissioning activities is delayed, allowing for continued growth in
the real value of qualified fund balances. With earnings of qualified funds taxed at a 20% rate
rather than standard corporate tax rates, even modest nominal returns can compound rapidly. For
example, an additional 20 years of compounded investment returns at a 4% after-tax real rate of
return would more than double the real value of the investments in a qualified fund even if no
additional contributions were made to the fund during the extended operating period. Second,
the longer useful life may provide an opportunity to collect a portion of the resources that will be
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Testimony by Howard Gruenspecht, Resources for the Future
September 12, 2001
needed for decommissioning during the extended operating period, consistent with the level
funding approach specified in current law.
In sum, the extended useful lifetime now expected for many existing nuclear plants is
significantly increasing the amount of real resources that will be available in qualified
decommissioning funds under existing law when decommissioning activities actually begin.
Changes in law that allow for additional contributions to qualified funds would provide
significant financial benefits to companies responsible for decommissioning costs, but they are
unlikely to have any impact on the way existing nuclear plants are used or decommissioned.
Efficient resource allocation is generally advanced when policies are neutral toward the
selection of competing technologies or service providers.
Restructuring itself helps to create a more neutral policy environment by opening the door to
competition between different electric service providers. In principle, restructuring also allows
for distributed power technologies located at an industrial plant or a commercial or residential
building to compete with traditional central-station generation plants much more effectively than
is possible when electricity is provided by a traditional regulated monopoly operating under costof-service regulation. However, the benefits of competition between central-station and
distributed power technologies will not be fully realized under existing tax policies, which
incorporate a bias against distributed power technologies.
Under current depreciation rules, electric-utility generating units are assigned a 15- or 20-year
recovery period and are eligible for accelerated depreciation methods. Distributed power
equipment often receives much less favorable treatment. For example, distributed power
property used to produce electricity and/or heat for use in a commercial or residential building is
likely to be classified as a building structural component. Within this category, it is depreciated
using the straight-line method over a 39-year period, even though the actual service lifetime for
such property typically is 10 years or less, compared to 40 years or more for many utility
generating units. The current asset classification system, which predates the emergence of
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Testimony by Howard Gruenspecht, Resources for the Future
September 12, 2001
distributed power technologies and electricity restructuring, is not neutral toward the choice
between central station- and distributed power technologies.
Changes in the tax treatment of distributed power property, as proposed in S. 596 and S.389, can
help to level the competitive playing field.
Some electricity generation technologies emit greenhouse gases and conventional
pollutants, which have external impacts that are not reflected in private market
transactions. The presence of important externalities creates an exception to the usual
presumption favoring neutral tax treatment of competing technologies.
Economists generally believe that taxes on pollution or pollution trading programs are the best
way to get producers and consumers to pay for the costs they impose on others when their
activities generate pollution and other adverse externalities. An alternative way to tilt the
competitive playing field against polluting technologies is to subsidize cleaner alternatives.
However, this approach is not as good as penalizing polluting technologies. While policies that
tax or regulate pollution usually raise prices and reduce overall demand, subsidies tend to have
the opposite effect. Nonetheless, because of the difficulty in imposing new taxes or regulatory
programs, subsidies to cleaner technologies may be seen as a “second-best” option to encourage
the development and selection of non-polluting or less-polluting technologies.
Production Tax Credits for Certain Renewable Energy Sources
Externalities are directly relevant to consideration of the possible extension of the existing
production tax credit (PTC) for wind and closed-loop biomass, now set to expire at the end of
this year, and its possible expansion to other renewable or waste resources. Renewable energy
technologies now eligible for the PTC emit no net greenhouse gases.1 Currently, the PTC is 1.7
cents per kilowatt-hour and is adjusted annually for inflation.2 Estimates from a study conducted
several years ago by RFF researchers estimated the monetary value of environmental damages
1
2
Wind energy also emits no conventional pollutants.
The PTC is roughly 40% to 50% of the average wholesale price of power in most regions of the country.
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Testimony by Howard Gruenspecht, Resources for the Future
September 12, 2001
throughout the entire fuel cycle, from resource extraction to final use.3 Comparing coal with
biomass, these researchers found that coal imposed greater external costs, reckoning the
difference at 0.8 cents per kilowatt-hour. More than 90% of the differential reflected the
imputed value of the impact of increased global warming from fossil fuel use, estimated at
roughly $18 per ton of carbon emitted to the atmosphere, well within the range of plausible
values derived from existing assessments of global warming risks.
Of course, all such estimates are subject to considerable uncertainty in the estimation of
relationships linking emissions to damages and procedures for valuing damages, so there is a
very wide range of reasonable externality values. For example, the recent National Academy of
Sciences Panel on Corporate Average Fuel Economy Standards used a $50-per-ton externality
value of carbon emitted to the atmosphere in developing its analysis, which significantly
increases the estimated gap in external costs between generation using coal and renewables.
However, an even higher value would need to be placed on avoided carbon-dioxide emissions to
fully justify the current PTC solely in terms of pollution externalities.
Other factors that could help to justify higher levels of support for renewables from a practical
policy perspective are less well-rooted in traditional economic analysis. Wind and biomass
resources are concentrated in rural areas that now rely heavily on a variety of federally funded
income-support programs. Rural benefits from renewable resource development include
increased economic development, job creation, higher local property-tax revenues, enhanced
agricultural production (for biomass), and increased land values. Successful development of
renewable energy could help to reduce the level of expenditures in other programs that currently
support rural economies and incomes.
While the PTC can play an important near-term role in advancing renewable energy
development, continued progress in reducing costs for renewable technologies and developing
policies to limit emissions of greenhouse gases will be critical to the long-run viability of
renewable generation technologies. A recent review by RFF researchers of the nation’s
3
Krupnick, Alan and Dallas Burtraw, The Social Costs of Electricity: Do the Numbers Add Up? Resource and
Energy Economics, 18 (1996) 423-466.
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Testimony by Howard Gruenspecht, Resources for the Future
September 12, 2001
experience with renewable technologies over the past 25 years4 provides some reason for
optimism regarding prospects for cost reduction. While market penetration of renewable
technologies generally has not met projections made during the 1970s and 1980s, the cost of
renewable technologies has also been lower than projected, even taking into account the
seemingly optimistic forecasts of renewable energy advocates. If cost reductions continue to
meet or exceed the milestones set by the Department of Energy’s renewable programs and the
renewable energy industry, it should be possible to sustain the significant momentum in
renewable capacity expansion experienced over the past several years under an extension of the
PTC that includes a provision to gradually lower the real value of the credit over time.
Proposed Investment and Production Tax Credits for Clean Coal Technologies
While differentially favorable tax treatment for renewable technologies can be justified in part as
a “second-best” policy approach to addressing environmental externalities, the same argument
cannot easily be made in support of the proposed investment and production tax credits for clean
coal technologies included in S.596, S.389, and H.R. 4. These programs would provide
incentives to deploy fixed amounts of specific clean coal technologies. The investment credits
would be available for plants with emissions and efficiency performance similar to new
conventional coal technologies. Eligibility for production credits would be linked to
improvements in thermal efficiency of 4% to 20% relative to the projected performance of a new
conventional plant in 2010 assumed in the Energy Information Administration’s latest Annual
Energy Outlook.
As noted earlier, greenhouse gas emissions are a dominant factor in comparisons of external
environmental costs across competing technologies. While improvements in thermal efficiency
provide proportional reductions in greenhouse gas emissions, even those units meeting the
proposed eligibility threshold for the highest production credit level would still emit roughly
twice the amount of greenhouse gas emissions per kilowatt-hour as the efficient gas-fired
generation units that are expected to provide the vast majority of capacity additions over the next
4
McVeigh, J.D., D. Burtraw, J. Darmstadter, and K. Palmer. Winner, Loser, or Innocent Victim: Has Renewable
Energy Performed as Expected? Research Report No.7, March 1999. Washington, DC: Renewable Energy
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Testimony by Howard Gruenspecht, Resources for the Future
September 12, 2001
decade. Any significant displacement of new gas-fired capacity by clean-coal technologies
meeting the performance criteria specified in this program would result in a net increase in total
greenhouse gas emissions from electricity generation. There would also be some increase in
emissions of conventional pollutants, although for some pollutants such increases would be
partially or fully offset with reductions at other facilities under existing environmental
regulations.
A final comment on the proposed coal tax credits concerns the allocation of resources across the
different technologies. In a world where greenhouse emissions matter, coal’s long-term viability
as a fuel source will require the use of systems to capture and sequester coal’s carbon content—
efficiency improvements alone will not suffice. Research and development in the area of carbon
capture and sequestration is therefore a high priority. While this work goes on, any tax credit
program to promote clean-coal technology deployment should emphasize those technologies that
can be most easily and cost-effectively integrated with future capture and sequestration systems.
S. 596, which allocates the lion’s share of the proposed tax credit program for integrated
gasification technologies, may be more productive in this regard than S.389 and H.R. 4, which
primarily support pulverized-coal and fluidized-bed technologies.
Ongoing changes in electricity markets make it very hard to estimate the impact on tax
revenues resulting from changes in electricity tax policies.
Revenue estimates are always uncertain. However, in addition to the usual uncertainties, the
revenue impacts of the electricity tax proposals now before the committee are likely to be highly
dependent on pending regulatory and legislative decisions regarding electricity and
environmental matters, as well as volatility in fuel markets and the pace of technology
development.
The Federal Energy Regulatory Commission’s (FERC) evolving policy towards Regional
Transmission Organizations (RTOs) is the critical energy regulatory matter affecting the
prospects for divestiture of transmission assets and resultant tax implications. At present, FERC
Project.
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Testimony by Howard Gruenspecht, Resources for the Future
September 12, 2001
has not leaned toward a particular business model for RTOs. Legislation that would redefine
FERC’s transmission jurisdiction; address impediments to siting new transmission lines; and/or
set policy on such issues as the interconnection of distributed generation or the design of
transmission tariffs for intermittent renewables would also have a significant impact on the
evolution of transmission markets. State regulatory and legislative decisions will also play a
role in this area.
Market developments as well as regulatory actions and legislation will also drive competition.
The price of natural gas will be particularly important to competition among generating
technologies. Each $1 change in the price of natural gas translates into roughly 0.75 cents per
kilowatt-hour in the cost of generating electricity in an efficient gas-fired plant. Until recently,
real wellhead gas prices had hovered in the neighborhood of $2 per million Btu for over a
decade. After a wild ride over the last 18 months, during which wellhead prices hit a peak of
$10 per million Btu in December 2000, prices today are back near the $2 per million Btu level.
Other key factors that will drive markets include technology cost reductions, the level of
consumer demand for so-called green power, and the increased use of real-time pricing systems
to better match demand and supply.
Major environmental regulatory issues affecting the choice among generating technologies
include regulatory actions to limit mercury emissions, future strategies to implement and attain
the 1997 ambient air quality standards for ozone and particulate matter, and the possible shift
toward output-based allocations of emissions rights. Environmental legislation that would have
a major impact on the choice of generation technology includes new multipollutant caps for
utility emissions or any requirement for limitations in domestic greenhouse gas emissions.
Environmental policies at the state level will also be important.
Finally, mandates for renewable energy, including the adoption of any renewable portfolio
standards at the state or federal level, would directly affect tax expenditures under production tax
credits.
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Testimony by Howard Gruenspecht, Resources for the Future
September 12, 2001
Conclusion
Mr. Chairman, the committee faces a significant challenge in addressing the many proposals for
tax relief for the electricity industry and other parts of the energy sector. Undoubtedly, your
ability to respond to these requests will be severely limited by budgetary constraints.
Insofar as electricity-related tax proposals are concerned, I think a reasonable strategy would be
to place the highest priority on tax provisions that are truly necessitated by restructuring and then
to try to redress current tax impediments to competitive neutrality. Where important externalities
exist, favorable tax treatment of particular technologies is warranted, but the size of the tax
benefit should not be disproportionate to the value of the externality being addressed. Finally,
recognize that there is unusually high uncertainty in estimates of the revenue implications of
particular proposals because of the large potential impact of pending environmental and energy
policy decisions. Therefore, there is a strong case for close coordination between tax and nontax policy decisions and for the frequent review of tax policies.
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