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entitled 'Economic and Other Implications of Switching from Coal to
Natural Gas at the Capitol Power Plant and at Electricity-Generating
Units Nationwide' which was released on May 1, 2008.
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GAO-08-601R:
May 1, 2008:
The Honorable Mary L. Landrieu:
Chair:
The Honorable Lamar Alexander:
Ranking Member:
Subcommittee on Legislative Branch:
Committee on Appropriations:
United States Senate:
The Honorable Debbie Wasserman Schultz:
Chair:
The Honorable Tom Latham:
Ranking Member:
Subcommittee on Legislative Branch:
Committee on Appropriations:
House of Representatives:
Subject: Economic and Other Implications of Switching from Coal to
Natural Gas at the Capitol Power Plant and at Electricity-Generating
Units Nationwide:
Elevated concentrations of greenhouse gases--carbon dioxide, methane,
nitrous oxide, and several synthetic chemicals--in the atmosphere
resulting from the combustion of fossil fuels and other sources have
the potential to cause significant changes in the earth's climate.
These potential impacts include shifts in sea level and weather
patterns and could pose threats to coastal and other infrastructure.
Concerns about the potential impacts of climate change have led the
Congress to consider legislation that would place binding, nationwide
limits on greenhouse gas emissions, and the House of Representatives'
leadership has initiated efforts to decrease emissions attributable to
its operations. Nearly all of the greenhouse gas emissions from House
operations consist of carbon dioxide and are associated with
electricity purchased from utilities and the combustion of fossil fuels
in the Capitol Power Plant (CPP), which provides steam and chilled
water for heating and cooling the Capitol building and 23 surrounding
facilities. The Architect of the Capitol (AOC) operates CPP.
In June 2007, the Chief Administrative Officer (CAO) of the House of
Representatives released the Green the Capitol initiative (the
initiative) at the direction of the Speaker and the Majority Leader.
[Footnote 1] Among other goals, the initiative calls for the House of
Representatives to operate in a carbon-neutral manner by the end of the
110th Congress (December 2008). Carbon-neutral, as defined in the
initiative, means that operations produce no net contribution to
greenhouse gas emissions. The initiative outlines several strategies to
achieve the goal of carbon neutrality, including operating CPP with
natural gas instead of coal to meet the needs of the House. (Natural
gas generates about half as much carbon dioxide as coal when burned but
costs about four times more for a comparable amount of energy
input.)[Footnote 2] Based on an AOC estimate, the House's share of the
cost of achieving the fuel-switching goal would total $2.75 million in
fiscal year 2008. The Omnibus Appropriations Act for that year
appropriated $85.3 million for CPP. The House Appropriations Committee
Explanatory Statement directs $3.27 million of this amount to the Green
the Capitol initiative.[Footnote 3]
CPP produces steam using a combination of seven boilers--two boilers
that primarily burn coal, but could also burn natural gas, and five
boilers that burn fuel oil or natural gas. These boilers burn fuel to
convert water to steam that, in turn, provides energy primarily for
space heating but they do not generate electricity.[Footnote 4] The
total capacity of these boilers is over 40 percent higher than the
maximum capacity required at any given time, and the plant has the
flexibility to switch among the three different fuels or burn a
combination of fuels. The percentage of energy input from each fuel has
varied from year to year, with an average fuel mix of 43 percent
natural gas, 47 percent coal, and 10 percent fuel oil between 2001 and
2007. The overall amount of steam required depends on numerous factors,
including weather, the adoption of voluntary and federally mandated
energy-efficiency and conservation measures, and the addition of new
buildings (such as the Capitol Visitor Center, scheduled to open in
late 2008).
In addition to the House's efforts to implement the Green the Capitol
initiative, the Congress is considering proposals that would create
nationwide limits on greenhouse gas emissions from electricity-
generating units and other sectors of the economy. Many of these
proposals would involve the use of mechanisms that create an economic
incentive for emitters to decrease their emissions by limiting the
overall allowable quantity of emissions or by placing a direct price on
each unit of emissions. Because the combustion of fossil fuels results
in greenhouse gas emissions, efforts to limit emissions could lead to
overall shifts in the prices and demand for different types of fuels.
For example, the Department of Energy has projected that limits on
greenhouse gases would shift the nation's demand for fossil fuels by
decreasing the demand for coal and increasing the demand for natural
gas. In 2006, production of electricity from coal totaled 49 percent of
the nation's net generation, followed by 20 percent from natural gas,
19 percent from nuclear power, and 7 percent from hydroelectric power,
with lesser quantities produced from other renewable sources,
petroleum, and other fuels. These percentages have remained relatively
stable in recent years with a slight increase in natural gas generation
and a slight decrease in generation from coal. In principle, all coal
units could be physically switched from coal to natural gas with
varying degrees of modification. It would also be possible to build new
gas-fired power plants to replace coal-fired power plants. These
modifications or replacements would require different amounts of
investment in the power plants themselves, as well as related
infrastructure. Legislative proposals that would impose limits on
greenhouse gas emissions from the electricity sector raise important
questions about the potential supply and demand for different fuels
under different scenarios, as well as about the ability of existing
generating units to switch from burning high-emitting fuels, such as
coal, to lower-emitting fuels, such as natural gas. Moreover, such
proposals prompt questions about the overall economic benefits and
costs that would accrue.
Within this context, the House Committee on Appropriations directed us
to determine, in consultation with the Department of Energy, (1) the
expected increase in natural gas use for House operations and the
associated costs at CPP that would result from the Green the Capitol
initiative, and (2) the ability of existing U.S. coal-burning,
electricity-generating units to switch to burning natural gas and the
associated economic implications.
To respond to the first objective, we first reviewed two studies
prepared for the House CAO. One study was an analysis prepared by AOC
that served as the basis for the fuel-switching funding estimate in the
Green the Capitol initiative presented by CAO to the House leadership.
The other study was a subsequent analysis prepared by the Department of
Energy's Lawrence Berkeley National Laboratory (LBNL). We then
determined the average annual quantity of each fuel (measured in
British thermal units or Btu) consumed by the plant between 2001 and
2007. Next, we calculated the proportion of the plant's steam output
consumed by buildings operated by the House of Representatives, which
we estimated was 29 percent based on the total square footage of
buildings served by the plant. We assumed that the fuel-switching
approach outlined in the initiative required that this proportion of
the plant's output be derived entirely from natural gas. The remaining
71 percent would continue to reflect the plant's historical average of
43 percent natural gas, 47 percent coal, and 10 percent fuel oil. We
did not assume a change in the quantity of fuel oil that would be
burned by the plant because of technical considerations at the plant
that require the use of fuel oil as a back-up fuel. We then calculated
the incremental cost of achieving an adjusted fuel mix. We made this
calculation assuming that, beginning in 2008, the demand for the
plant's output would decrease by 1 percent annually from the 2001
through 2007 baseline due to energy efficiency legislation and
additions to the Capitol complex. We then estimated future CPP cost per
unit of fuel for the period from 2008 through 2012 using historical
data on AOC's fuel expenditures and projections of fuel prices for the
industrial sector from the Annual Energy Outlook of the Energy
Information Administration (EIA) within the Department of Energy. We
adjusted EIA's projected fuel prices to account for historical
differences in the average prices paid by industrial users of these
fuels and the prices paid by AOC. All of our cost estimates are in
constant 2006 dollars. In preparing our estimates, we consulted with
AOC staff, officials representing the House CAO, and the Department of
Energy (including LBNL and EIA). We also reviewed relevant studies
prepared by these agencies.
To respond to the second objective, we analyzed available data from the
Department of Energy and other sources. We also obtained information
from key stakeholders identified in discussions with the department
that represent the electricity generation, natural gas, and coal
industries using written interview questions. Enclosure I provides a
more detailed description of our scope and methodology. We conducted
our audit work between October 2007 and April 2008 in accordance with
generally accepted government auditing standards. Those standards
require that we plan and perform the audit to obtain sufficient,
appropriate evidence to provide a reasonable basis for our findings and
conclusions based on our audit objectives. We believe that the evidence
obtained provides a reasonable basis for our findings and conclusions
based on our audit objectives.
Summary:
According to our analysis, implementing the Green the Capitol
initiative's fuel-switching directive to decrease carbon dioxide
emissions from the CPP should lead to a 38 percent increase in natural
gas use over the average annual quantity consumed between 2001 and
2007. We estimated that the fuel switching should cost about $1.4
million in fiscal year 2008 and could range from between $1.0 and $1.8
million depending on actual fuel costs, among other factors. Our cost
estimates are less than the $2.75 million AOC budgeted for this purpose
in fiscal year 2008, largely because we employed a different
methodology than AOC when it prepared its estimates and maintained
certain assumptions that AOC did not. Specifically, AOC based its
estimates on a scenario in which the plant would eliminate its use of
coal altogether and burn natural gas exclusively, for a total cost of
$7.78 million. Of this total cost, AOC estimated that $2.75 million
represented the portion that could be applied to the House, based on
the number of square feet of building space served by the plant. In its
estimate, AOC also did not account for the fact that the Ford House
Office Building obtains steam from the General Services Administration
rather than from CPP. As a result, AOC's plans to fulfill the Green the
Capitol initiative involve increasing natural gas use by 48 percent, an
increase that far exceeds the initiative's fuel-switching
recommendation. In contrast, our analysis focused on estimating the
incremental cost of adjusting the plant's fuel mix such that the
portion of its output that serves buildings operated by the House
(about 29 percent on a square footage basis) would consist entirely of
natural gas. This equates to increasing the level of natural gas from
43 percent to 60 percent of the historical fuel mix, a net difference
of 17 percentage points and a 38 percent increase in overall natural
gas consumption. Importantly, the plant's existing natural gas boilers
have the capacity to accommodate this increase in natural gas use and
CPP would not have to eliminate its use of coal altogether. Looking
ahead, we estimate that the incremental cost of maintaining the
adjusted fuel mix will range between $4.7 million and $8.3 million over
the 2008 through 2012 time period, depending on fuel prices, the
plant's output, and other factors. However, an important uncertainty
with our estimates stems from the fact that AOC does not have complete,
reliable information on the efficiency of its seven boilers in
converting fuel into steam or on the full costs associated with the use
of each fuel, taking into account factors such as fuel transportation
and handling, and fuel-specific pollution control devices. As a result,
AOC does not have all the information it needs to make fully informed
decisions about operating the plant as efficiently or cost-effectively
as possible. While the increased use of natural gas and decreased use
of coal will increase costs above a business-as-usual baseline
scenario, the initiative would likely generate other important
benefits. These benefits include decreased emissions of carbon dioxide
and pollutants that cause smog and acid rain, as well as potential
reductions in the plant's operating costs associated with the
transportation, storage, handling, and treatment of coal and related
waste streams.
With regard to the ability of U.S. coal-burning, electricity-generating
units to switch to natural gas, according to available data and key
stakeholders, the ability of these units to switch is limited by high
natural gas prices, supply constraints, and existing infrastructure. In
addition, increasing the nation's use of natural gas for electricity
generation could result in adverse economic consequences. Natural gas
currently costs about four times more than coal per British thermal
unit and has shown a relatively higher rate of price increases and
volatility over time relative to coal, according to EIA. In addition to
higher fuel costs, supply constraints limit the practicality of
replacing electricity generated from coal with natural gas. The United
States has limited capability to meet the growing demand for natural
gas with domestic production and would need to become increasingly
dependent on international supplies of natural gas if there was
widespread switching to natural gas from coal. Even taking imported
natural gas into account, key stakeholders doubted whether natural gas
supply could meet the demand if plant operators decided to pursue fuel
switching. Fuel switching to natural gas also poses challenges related
to existing infrastructure, including limited pipeline and storage
capacity and technical and regulatory barriers to the conversion of
existing coal plants. Large-scale fuel switching would require
substantial investments in pipeline and storage capacity and new
terminals to process imported natural gas--all of which would require
regulatory approval. With respect to the conversion of existing coal-
burning plants, stakeholders said that it would be more feasible and
cost-effective to construct new natural gas units or dispatch excess
capacity at existing natural gas units than to convert a coal plant
because of technical and economic factors, among other reasons. For
example, retrofitting an existing coal unit to burn natural gas would
require significant capital expenditures, while also potentially
decreasing the unit's overall efficiency in converting fuel input into
electricity. Because of these technical and other issues, large-scale
shifting demand for electricity production from coal to natural gas
would increase electricity prices, residential and commercial heating
costs, and fuel costs for certain industries that consume large
quantities of natural gas, including chemical and fertilizer
manufacturers. Because of these and other concerns, key stakeholders
said that switching coal plants to natural gas has occurred
infrequently in the past and is not likely to occur in the future.
We are recommending that, before adjusting the Capitol Power Plant's
fuel mix beyond the level directed by the Green the Capitol initiative,
the Acting Architect of the Capitol consult with AOC's oversight
committees in the Congress and evaluate the economic and environmental
tradeoffs associated with the use of each fuel at the plant, taking
into account the efficiency of the plant's boilers, related fuel supply
systems, and pollution control equipment.
We provided a draft copy of this report to the Acting Architect of the
Capitol for review and comment. AOC provided comments via electronic
mail. AOC officials said that they agreed with our cost estimate under
the high fuel price scenario but expressed concerns about the potential
level of resources that would be required to respond to our
recommendation. We subsequently met with AOC officials who said that
they were concerned that implementing our recommendation would require
them to collect exact information on the efficiency of its boilers and
fuel supply systems. Based on this discussion, we adjusted the wording
of the recommendation to clarify that this was not our intent. AOC also
provided a number of technical clarifications regarding the plant's
operation and their cost estimates for fuel switching, which we
incorporated into our report as appropriate.
Fuel Switching at the Capitol Power Plant Is Expected to Require a 38
Percent Increase in Natural Gas Use at a Cost of about $1.4 Million in
Fiscal Year 2008:
Based on available data and key assumptions about the plant's operation
and future fuel costs, we estimated that fulfilling the Green the
Capitol initiative's fuel-switching directive would require the plant
to increase its natural gas use by 38 percent relative to its baseline
level of fuel consumption between 2001 and 2007. As a portion of the
plant's total fuel mix, natural gas would increase from about 43
percent of overall energy input to about 60 percent of input. Using
information from the AOC on its fuel expenditures and fuel price
projections from EIA, we estimate that implementing the fuel-switching
directive could range in cost from $1.0 to $1.8 million in fiscal year
2008.
Because our calculations involve projections and assumptions about key
variables, the estimates are inherently uncertain and actual
expenditures may vary depending on changes to these variables. Key
variables and assumptions underlying our estimates include the
following:
* Baseline fuel consumption and steam production. We estimated the
quantity of additional natural gas required to fulfill the initiative's
fuel-switching goal for the year 2008. We assumed that the fuel-
switching approach outlined in the initiative required that 29 percent
of the plant's output be derived entirely from natural gas. The 29
percent figure is based on an estimate of the House's share of the
total square footage of buildings served by the plant. The remaining 71
percent would continue to reflect the average fuel mix over the 2001 to
2007 time period.[Footnote 5] Using an average, as opposed to a single
year's level of production, provides a more realistic picture of the
plant's historical operation. We held the amount of fuel oil constant
because of technical considerations at the plant that require using oil
as a backup fuel.
* Boiler efficiency. We assumed that each of the seven boilers at the
power plant converts fuel into steam with equal efficiency. We made
this assumption based on research conducted by an independent
consultant to GAO, a previous analysis conducted by Ross Associates (a
consultant to AOC), and discussions with AOC staff. Overall, we found
that AOC does not have complete, reliable information on the efficiency
of its seven boilers in converting fuel into steam or on the full costs
associated with the use of each fuel, taking into account factors such
as transportation, handling, and pollution control. As a result, AOC
does not have all the information it needs to make fully informed
decisions about operating the plant as efficiently or cost-effectively
as possible. While the available data suggests that our assumption is
reasonable, the lack of complete, reliable data on efficiency of each
of the boilers and related fuel supply equipment represents an
important uncertainty with our analysis.
* Fuel costs. To estimate the cost of each fuel in fiscal year 2008, we
used fuel price projections from EIA' s Annual Energy Outlook 2008,
which we then adjusted to account for historical differences in the
prices paid by AOC versus the average price paid by industrial
consumers.[Footnote 6]
Figure 1: Projected Change in CPP Fuel Use:
[See PFG for image]
This figure contains two pie-charts depicting the following
information:
Projected Change in CPP Fuel Use: Before fuel switch:
Coal: 47%;
Natural gas: 43%;
Fuel oil: 10%.
Projected Change in CPP Fuel Use: After fuel switch:
Coal: 31%;
Natural gas: 60%;
Fuel oil: 10%.
Note: Due to rounding, percentages do not add up to 100 percent in both
charts.
Source: EIA.
{End of figure]
Our Estimates Are Substantially Lower than Previous Estimates and the
Level of Funding AOC Budgeted for Fuel Switching at the Plant:
Our estimated costs of increasing natural gas use at CPP to meet the
initiative's fuel-switching directive fall well below a previous
estimate prepared by AOC. Specifically, AOC estimated that the cost in
fiscal year 2008 would total about $2.75 million. In fiscal year 2009,
AOC is requesting a much lower amount--1.22 million--to complete the
fuel switch. In its own analysis, LBNL estimated the total cost for
fiscal year 2008 at about $1.88 million.
The discrepancy between our estimates and those developed by AOC and
LBNL stems from variations in the methodologies each party employed.
Specifically, AOC's analysis involved a scenario in which the plant
would burn only natural gas and eliminate the use of coal and fuel oil
altogether. This analysis estimated that switching the entire plant to
natural gas would cost a total of about $7.8 million in fiscal year
2008. Based on this analysis, AOC then estimated that the cost of fuel
switching under the initiative would equal approximately 35 percent of
the total cost of switching the entire plant. The 35 percent figure was
based on the assumption that the House consumed that proportion of the
plant's total output, based on the number of square feet of building
space served by the plant. This yielded an estimate of $2.75 million to
switch fuels in fiscal year 2008. To fulfill the initiative's fuel
switching directive, AOC officials said that they planned to increase
natural gas use from 42 percent of fuel use to 62 percent. According to
our analysis, this would increase natural gas use beyond the
initiative's goals.
The analysis conducted by LBNL estimated the total cost at $1.88
million in 2008, a substantially lower figure than the previous
estimate developed by AOC. Key differences between our methodology and
the methodologies employed by AOC and LBNL follow:
* We based our cost estimates on EIA fuel price projections for fiscal
year 2008 and used AOC historical cost data from 2001 through 2007 to
estimate the actual cost of the fuel after delivery. In contrast, AOC's
analysis used an average of their natural gas costs from 2005 through
2007, which may have inflated the cost estimates, since there were some
very high natural gas price spikes during these years. LBNL used
natural gas prices from fiscal year 2007.
* We assumed that House buildings use approximately 29 percent of the
steam generated by the plant, based on data from AOC's 2006 Annual
Report to Congress. We excluded the Ford House Office building from our
analysis because it obtains steam from General Services Administration
rather than from the plant. In contrast, AOC and LBNL included the Ford
Building, which resulted in estimates of 31 percent and 35 percent,
respectively.
Estimated Annual Fuel-Switching Costs Are Expected to Range from $1.2
to $1.4 Million between 2008 and 2012:
In addition to estimating the costs for fiscal year 2008, we projected
the costs of maintaining the adjusted fuel mix over the 2008 through
2012 time period. Specifically, we estimated that CPP would spend
roughly $1.2 to $1.4 million per year over the next 5 years. This
amount could run as high as $1.8 million in fiscal year 2009 or as low
as $823,000 in 2012, depending on fuel prices. Table 1 summarizes the
potential future costs of maintaining an adjusted fuel mix at CPP and,
because of uncertainties about fuel price projections, includes low and
high fuel price scenarios.
Table 1: Projected Cost of Maintaining Adjusted Fuel Mix, 2008 through
2012:
Fiscal year: 2008;
Low fuel price scenario: $1,002,632;
Baseline scenario: $1,385,488;
High fuel price scenario: $1,768,343.
Fiscal year: 2009;
Low fuel price scenario: $1,045,606;
Baseline scenario: $1,435,660;
High fuel price scenario: $1,825,714.
Fiscal year: 2010;
Low fuel price scenario: $952,500;
Baseline scenario: $1,316,872;
High fuel price scenario: $1,681,244.
Fiscal year: 2011;
Low fuel price scenario: $868,061;
Baseline scenario: $1,210,391;
High fuel price scenario: $1,552,721.
Fiscal year: 2012;
Low fuel price scenario: $823,029;
Baseline scenario: $1,151,236;
High fuel price scenario: $1,479,443.
Fiscal year: Totals;
Low fuel price scenario: $4,691,828;
Baseline scenario: $6,499,647;
High fuel price scenario: $8,307,465.
[End of table]
Similar to our fiscal year 2008 estimate, these projections rely on a
number of assumptions which, if changed, would substantially affect the
overall cost. In addition to the assumptions cited above, the following
factors and assumptions could affect the accuracy of our estimates:
* Fuel demand. We estimated that the demand for the plant's steam would
decline by 1 percent annually relative to a baseline level of demand
equal to that we derived by averaging the annual demand for fiscal
years 2001 through 2007. We based the 1 percent annual decline in
demand on two important and partially offsetting considerations:
- Additions to the Capitol Complex, including the Capitol Visitor
Center, are expected to increase the plant's steam demand by 1 percent
each year through 2025.
- The Energy Policy Act of 2005 requires a 2 percent reduction in
energy use per year for federal buildings. Because over a quarter of
House energy use is for heating, the act's implementation may
significantly reduce steam demand over time.
* Fuel costs. We used fuel price projections for the U.S. industrial
sector from EIA for the years 2008 through 2012 and adjusted them to
reflect our estimate of the historical difference between these prices
and the AOC per-unit cost of each fuel. Because of the uncertainty of
fuel price projections, we constructed a low-price scenario and a high-
price scenario for the years 2008 through 2012 based on measures of
variability in the historical prices of these fuels.
Of these variables and assumptions, those associated with future fuel
prices pose the greatest uncertainty. As we have previously reported,
prices may depend on a variety of factors, such as supply, demand,
available infrastructure, market conditions, and severe weather
events.[Footnote 7] Since 1999, market conditions generally have
fostered an upward trend in natural gas prices that, according to EIA,
will continue until 2009. Starting in 2010, EIA expects natural gas
prices to decline until approximately 2016.
Other important considerations can affect demand for the plant's
services, including planned or future investments in energy efficiency,
weather, and changes in energy or environmental legislation. Because of
the uncertain and potentially offsetting effects of these factors on
demand for the plant's services, we did not address them in our
estimates.
Fuel Switching Would Reduce Carbon Dioxide Emissions at an Average Cost
of about $139 per Ton; Other Benefits May Also Accrue:
Based on our cost projections for fiscal year 2008, we estimate that
the fuel switch would yield carbon dioxide reductions of about 9,970
metric tons[Footnote 8] per year at an average cost of $139 per ton.
We developed this estimate using our $1.4 million cost estimate as a
base price and applying EIA's carbon dioxide conversion factors for
coal and natural gas. (The world's largest carbon market, the European
Union's Emissions Trading Scheme, currently prices a metric ton of
carbon at approximately $37.) Additional information on the cost-
effectiveness of the fuel-switching strategy relative to other carbon
dioxide abatement options would help inform future decision making on
fuel switching and related investments intended to decrease emissions.
In April 2007, we recommended that legislative branch agencies
establish a schedule for conducting energy audits and implement
selected projects as part of a plan to reduce emissions.[Footnote 9]
Such audits have the potential to identify projects that compare
favorably to fuel switching.
In addition to reducing carbon dioxide emissions, decreasing the
plant's reliance on coal may yield other environmental and health
benefits. While coal currently costs less than natural gas, coal's
combustion generally produces more carbon dioxide and air pollutants
compared to natural gas. These pollutants, in turn, pose a variety of
adverse health effects. For example, nitrogen oxides may exacerbate
existing conditions such as asthma, and particulate matter has been
linked to heart attacks and chronic bronchitis. Furthermore, acid rain
may occur when the sulfur dioxide produced in the combustion of coal at
the plant reacts with other chemicals in the atmosphere to form
sulfuric acid. Burning less coal may also help Washington, D.C., and
neighboring jurisdictions in their efforts to achieve compliance with
federal air quality standards. Currently, the city is noncompliant for
ground-level ozone and fine particulate matter. Finally, fuel switching
has the potential to reduce costs associated with the transportation,
storage, and handling of coal and related waste streams. In addition,
coal storage, handling, and related air pollution abatement require the
use of electricity, a major source of carbon dioxide, nitrogen oxide,
and mercury. As a result, increasing the plant's reliance on natural
gas may also yield reductions in such emissions from the power plant
and the electricity generating units that provide the plant with
electricity.
The Ability of U.S. Electricity-Generating Units to Switch from Coal to
Natural Gas Is Limited, and Fuel Switching Could Cause Adverse Economic
Consequences:
Relatively High Natural Gas Prices Limit the Potential for Fuel
Switching from Coal:
According to industry stakeholders, switching from coal to natural gas
for electricity generation is generally not economically feasible due
to the relatively high price of natural gas compared to coal, as
illustrated in figure 2.
Figure 2: Average Cost of Fuels for the Electric Power Industry, 1995
through 2006:
[See PDF for image]
This figure is a multiple line graph depicting the following data:
Average Cost of Fuels for the Electric Power Industry, 1995 through
2006:
Year: 1995;
Cents per million Btu, Coal: 132;
Cents per million Btu, Natural gas: 198;
Cents per million Btu, All fossil fuels: 145.
Year: 1996;
Cents per million Btu, Coal: 129;
Cents per million Btu, Natural gas: 264;
Cents per million Btu, All fossil fuels: 152.
Year: 1997;
Cents per million Btu, Coal: 127;
Cents per million Btu, Natural gas: 276;
Cents per million Btu, All fossil fuels: 152.
Year: 1998;
Cents per million Btu, Coal: 125;
Cents per million Btu, Natural gas: 238;
Cents per million Btu, All fossil fuels: 144.
Year: 1999;
Cents per million Btu, Coal: 122;
Cents per million Btu, Natural gas: 257;
Cents per million Btu, All fossil fuels: 144.
Year: 2000;
Cents per million Btu, Coal: 120;
Cents per million Btu, Natural gas: 430;
Cents per million Btu, All fossil fuels: 174.
Year: 2001;
Cents per million Btu, Coal: 123;
Cents per million Btu, Natural gas: 449;
Cents per million Btu, All fossil fuels: 173.
Year: 2002;
Cents per million Btu, Coal: 125;
Cents per million Btu, Natural gas: 356;
Cents per million Btu, All fossil fuels: 152.
Year: 2003;
Cents per million Btu, Coal: 128;
Cents per million Btu, Natural gas: 539;
Cents per million Btu, All fossil fuels: 228.
Year: 2004;
Cents per million Btu, Coal: 136;
Cents per million Btu, Natural gas: 596;
Cents per million Btu, All fossil fuels: 248.
Year: 2005;
Cents per million Btu, Coal: 154;
Cents per million Btu, Natural gas: 821;
Cents per million Btu, All fossil fuels: 325.
Year: 2006;
Cents per million Btu, Coal: 169;
Cents per million Btu, Natural gas: 694;
Cents per million Btu, All fossil fuels: 302.
Note: Average cost is not adjusted for inflation.
Source: GAO analysis of EIA's data.
[End of figure]
Currently, natural gas costs about four times more than coal per
British thermal unit. Due to its higher cost, substituting natural gas
for coal would increase operating costs for electricity-generating
units. Natural gas fuels about 20 percent of electricity production in
the United States and, according to one stakeholder, accounts for 55
percent of the electric utility industry's entire fuel expense ($50
billion out of $91 billion). In addition, natural gas has shown a
higher rate of price increases over time relative to coal, according to
EIA, and as illustrated in figure 3, natural gas prices have been
volatile in recent years. The market for natural gas has been
susceptible to extreme price swings when unexpected changes occur in
the market, such as weather-related spikes in demand or supply
constraints caused by hurricane damage.
Figure 3: Natural Gas and Coal Costs at U.S. Electric-Generating
Plants, 2001 through 2007:
[See PDF for image]
This figure is a multiple line graph depicting the following data:
Natural Gas and Coal Costs at U.S. Electric-Generating Plants, 2001
through 2007:
Date: January 2001;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.223;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 9.207.
Date: April 2001;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.239;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 5.637.
Date: July 2001;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.225;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 3.743.
Date: October 2001:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.21;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 2.715.
Date: January 2002:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.26;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 3.
Date: April 2002:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.25;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 3.64.
Date: July 2002:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.25;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 3.41.
Date: October 2002:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.25;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 4.04.
Date: January 2003:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.26;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 5.15.
Date: April 2003:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.29;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 5.22.
Date: July 2003:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.28;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 5.3.
Date: October 2003:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.28;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 4.81.
Date: January 2004;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.29;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 6.17.
Date: April 2004;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.34;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 5.57.
Date: July 2004;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.37;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 6.08.
Date: October 2004;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.41;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 5.84.
Date: January 2005;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.46;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 6.5.
Date: April 2005:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.54;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 7.11.
Date: July 2005:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.52;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 7.34.
Date: October 2005:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.58;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 11.55.
Date: January 2006;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.67;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 9.11.
Date: April 2006;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.71;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 7.13.
Date: July 2006;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.68;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 6.48.
Date: October 2006;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.7;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 5.51.
Date: January 2007;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.75;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 6.78.
Date: April 2007:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.78;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 7.54.
Date: July 2007:
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.77;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 6.85.
Date: October 2007;
Cost of coal receipts at electric-generating plants, Dollars per
million Btu: 1.78;
Cost of natural gas receipts at electric-generating plants, Dollars per
million Btu: 6.82.
Source: GAO analysis of EIA's data.
[End of figure]
Constrained Natural Gas Supply Limits Fuel Switching from Coal:
In addition to the relatively high price of natural gas, the ability of
coal-fired, electricity-generating units to switch fuels is constrained
by the available supply of natural gas. According to industry
stakeholders, the United States already faces serious supply problems
without a potential increase in demand due to fuel switching. According
to industry stakeholders and available EIA data, U.S. natural gas
production peaked in 1973, and the average productivity of natural gas
wells in the United States has declined for the past 35 years due to
diminishing output of older wells and lower yields and higher depletion
rates from more recent discoveries. EIA projects that natural gas
production will not increase in the lower 48 U.S. states over the next
20 years. According to industry stakeholders, the United States has
already found and used its easily recoverable natural gas and finding
new gas requires drilling deeper and in more inaccessible locations,
raising production costs. One stakeholder said that it is increasingly
difficult to keep output constant because about one-third of U.S.
natural gas production has to be replaced every year. Thus, the United
States has limited capability to meet growing demand for natural gas
with domestic production.
Consequently, widespread fuel switching at electricity-generating units
would increase demand for natural gas beyond the capabilities of
existing and projected supply. Stakeholders noted that the United
States would require nearly twice as much natural gas supply by 2030,
as currently projected by EIA, if the United States were to replace all
coal-fired plants with natural gas. According to one stakeholder,
replacing even one-half of coal-fired generation after 2015 with
natural gas would lead to an overwhelming demand. Industry stakeholders
said it is not possible to increase supplies by this magnitude,
especially in light of a trend toward increased global demand and
consumption.
Because of limited domestic supplies, meeting additional demand would
require imports from Canada, pipelines from Alaska, or liquefied
natural gas (LNG) from overseas suppliers.[Footnote 10] According to
one stakeholder, imports, primarily from Canada, have steadily grown to
comprise about 10 to 15 percent of U.S. supply. However, Canadian
exports are declining as a result of decreased drilling and increased
domestic demand. EIA identifies this as a significant problem facing
the U.S. natural gas market, according to one stakeholder. In addition,
prospects for an Alaskan pipeline and other pipelines are unclear,
creating further supply concerns for the U.S. market.
With widespread fuel switching, the United States would be more
dependent on imported LNG, according to industry stakeholders. The
EIA's Annual Energy Outlook 2007 projected major increases in LNG
imports into the United States. According to one stakeholder, all of
the natural gas required by large-scale fuel switching with LNG by 2015
would require more than 50 percent of the global supply. Another
stakeholder estimated that LNG supplies would be insufficient for the
United States to fully switch from coal to natural gas unless the
United States captured at least 90 percent of the world LNG market,
which seems highly unlikely because of the significant projected growth
in natural gas demand in the rest of the world.
Fuel Switching for Electricity-Generating Units Would Require
Investment in New and Existing Infrastructure:
Switching from coal to natural gas would require investment in new
infrastructure and changes to existing infrastructure, including
pipeline and storage capacity and generation technologies employed at
existing coal plants. In theory, all coal units can be physically
switched from coal to natural gas, but stakeholders said this practice
would not occur broadly due, in part, to inadequate existing
distribution networks and storage capacity, including pipelines.
According to stakeholders, burning natural gas at an existing coal
plant would require a pipeline with the ability to meet the plant's
fuel supply requirements. If not, a new gas pipeline would have to be
sited, permitted, designed, and constructed. Almost all coal-fired
boilers use some natural gas to ignite and regulate combustion, but
they require relatively small amounts of natural gas with
correspondingly small supply pipelines. Thus, existing coal-fired units
would have to enhance their supply pipelines to switch to natural gas.
As a result, according to stakeholders, a major fuel-switching program
would require a nationwide natural gas infrastructure construction
program. This would require expansion of interstate and intrastate
pipelines to transport increased volumes of natural gas. Furthermore,
existing plants and local natural gas distribution systems would have
to increase their storage capacity. Local storage can help buffer
variations in demand, and addressing local storage requirements could
pose challenges, according to stakeholders. Increased reliance on
natural gas would also require other new infrastructure, such as LNG
terminals.
Even with sufficient supply and storage capacity, stakeholders said
that it would be more feasible and cost-effective to construct new
natural gas units or dispatch excess capacity at existing natural gas
units instead of fuel switching. Converting a coal-burning plant to
natural gas would involve significant capital costs and result in a
less efficient plant with higher operating costs. At a minimum, an
existing boiler designed for coal would need a new combustion system
and a new heating surface to account for the differences between coal
and gas combustion, according to stakeholders. Because a gas-fired
steam generator is designed differently from a coal-fired boiler,
burning natural gas in a coal-fired boiler would result in a loss of
efficiency, which could decrease the amount of electricity produced by
the unit. According to one stakeholder, a decrease in capacity of 10 to
12 percent is a reasonable estimate. As a result, certain stakeholders
said that it would be more economically efficient in terms of capital
and fuel costs to tear down an existing coal unit and build a new
natural gas unit instead of retrofitting an existing coal unit to burn
natural gas. In addition, industry stakeholders said that some coal-
fired units cannot switch fuels because natural gas is not available,
existing technology cannot be modified, or the system reserve is so low
in the area that shutting down the coal plant for conversion to natural
gas would result in brownouts or blackouts. One stakeholder stated that
modifying a coal unit to burn natural gas would take the unit out of
service for 4 to 6 months.
In the few instances in which the industry has switched from coal to
gas, existing plants have not been retrofitted to burn gas; instead,
existing gas-fired units have displaced generation from marginally cost-
effective coal-fired units rather than retrofitting existing plants to
burn gas. Industry stakeholders said that many natural-gas- fired power
plants were constructed in the late 1990s and early 2000s, leading to a
large amount of underutilized capacity at plants constructed during
this boom. According to one stakeholder, it is likely that, instead of
fuel switching at coal plants, utilities would dispatch these
underutilized natural gas units and run coal units less aggressively.
EIA data describing the average capacity factors of different
generation options demonstrate that significant excess capacity exists
at natural-gas-fired plants. Capacity factor, in general terms,
measures how intensely and frequently a generating unit is
run.[Footnote 11] According to EIA, the average capacity factor for
natural gas units is much lower than capacity factors for other
generation options, such as nuclear and coal. As illustrated in figure
4, nuclear and coal-fired generation have the highest average capacity
factors for 2006 at 89.6 percent and 72.6 percent, respectively. As a
result, coal and nuclear capacity serve base load energy
requirements.[Footnote 12] In 2006, average capacity factors for
natural gas units ranged from 38.5 to 10.7 percent, depending upon the
specific type of natural gas unit. Accordingly, there is potential to
increase the utilization of existing natural gas units. Furthermore,
the fact that there is excess capacity at existing natural gas units
demonstrates the economic and other barriers to using natural gas for
electricity production.
Figure 4: Average Capacity Factor by Energy Source, 2006:
[See PDF for image]
This figure is a vertical bar graph depicting the following data:
Average Capacity Factor by Energy Source, 2006:
Source: Nuclear;
Percent: 89.6%.
Source: Coal;
Percent: 72.6%.
Source: Other renewables;
Percent: 45.6%.
Source: Hydroelectric;
Percent: 42.4%.
Source: Natural gas/combined cycle;
Percent: 38.3%.
Source: Petroleum;
Percent: 12.6%.
Source: Natural gas/all other types;
Percent: 10.7%.
Source: Energy Information Administration, Form EIA-806, "Annual
Electric Generator Report;" Form EIA-906, "Power Plant Report;" and
Form EIA-920, "Combined Heat and Power Plant Report."
[End of figure]
In the event that the owners or operators of a plant decided to switch
from coal to natural gas, changes to infrastructure, including
pipelines and individual electricity-generating units, would require
regulatory approval, which can be costly and time-consuming to obtain.
Certain stakeholders said that it may take years to complete all of the
mandatory permitting requirements before constructing pipelines. One
stakeholder had significant reservations about whether the industry
could obtain the required permits and rights-of-way for such an
undertaking. However, this stakeholder also said that the natural gas
industry may acquire rights-of-way by eminent domain rights, which
could help address pipeline-siting and construction challenges.
Stakeholders also identified air quality issues as a concern in
retrofitting a coal plant to burn natural gas. Modifying the equipment
at an existing coal plant could trigger permitting requirements and
necessitate the purchase of additional air pollution control
technologies. Several stakeholders said that modifying air permits
would not be difficult, but that it would take time for the regulatory
agencies to review the applications and issue revised permits.
Fuel Costs and Electricity Prices Could Increase As a Result of Fuel
Switching, among Other Adverse Economic Consequences:
Fuel switching and related pressure on available natural gas supplies
could increase the price of natural gas, increasing energy costs for
residential, commercial, and industrial consumers for both natural gas
and electricity. Because energy costs account for a relatively large
share of overall costs or because they are heavily dependent on natural
gas, for some residential and industrial consumers, any price increases
can present significant difficulties. According to industry
stakeholders, higher natural gas prices would affect millions of
residential consumers who cook and heat their homes and water with
natural gas. In 2006, we reported that the effect of higher wholesale
natural gas prices on consumers depends largely on the degree to which
the consumers or their suppliers may have purchased gas on the spot
market--which reflects current wholesale prices--or may have taken
steps to reduce their exposure to these prices.[Footnote 13] The effect
of higher prices also depends on the consumer's sensitivity to price
changes. Some consumers, such as low-income residents and certain high-
energy intensive industries, are more sensitive to price changes than
others and appear likely to experience the greatest impact.
As we reported in 2006, high natural gas prices adversely affected
industrial consumers. In particular, industries that rely on natural
gas, such as chemical and fertilizer manufacturers, could face
increased fuel costs. Other affected industries could include iron,
steel, automobile manufacturing, glass, aluminum, plastics, paper and
machinery, according to industry stakeholders. High fuel costs could
make these industries less competitive internationally, according to
stakeholders. Recent high natural gas prices forced some industrial
consumers to shut down production facilities, and further cutbacks
could occur if prices are high in the future.
According to industry stakeholders, increases in the price of natural
gas could also lead to electricity price increases. In the late 1990s
and early 2000s, the combination of low gas prices and the fact that
natural gas produces less air pollution than coal led to the
construction of many new natural gas plants. However, these plants are
currently underutilized because gas prices have risen substantially in
recent years. Requirements to utilize these plants instead of coal
plants could lead to higher electricity costs for consumers because
some producers would be able to pass on their increased operating costs
to consumers.
Potential Benefits of Fuel Switching Include Reductions in Emissions
and in Some Operation and Maintenance Costs, and Improvements in Local
Environmental Benefits:
Switching from coal to natural gas could decrease airborne emissions of
carbon dioxide and air pollutants that cause adverse health effects,
including nitrous oxide, sulfur dioxide, and particulates. Natural gas
is the cleanest fossil fuel to burn in terms of air quality and carbon
emissions, emitting up to 60 percent less carbon dioxide than coal when
burned, according to industry stakeholders. However, stakeholders said
that the magnitude of these benefits would depend on the source of the
natural gas and other factors, such as plant efficiency. For example,
one stakeholder said that increased reliance on LNG would result in
smaller carbon dioxide emission reductions relative to coal than those
through production and consumption of domestic natural gas because of
the carbon dioxide emissions associated with the processing and
transportation of imported LNG. In addition, utilities switching from
coal to natural gas could gain public relations benefits from emission
reductions, as well as a potential advantage associated with early
action toward compliance with any future emissions reductions policies.
Fuel switching from coal to natural gas could also decrease some
operations and maintenance costs, in addition to lessening the physical
impact on the surrounding environment. For example, fuel switching to
natural gas would decrease the costs of storing coal on site and
grinding it in preparation for combustion. In addition, according to
one stakeholder, natural gas infrastructure has less of an impact on
the surrounding environment because plants are modular and have smaller
footprints than coal-burning facilities. Also, natural gas is delivered
by pipelines, which are less visible than the infrastructure required
for transporting and storing coal, particularly in urban areas, because
they are often buried.
Conclusions:
Burning natural gas instead of coal at CPP and at electricity-
generating units nationwide as part of efforts to reduce greenhouse gas
emissions involves important tradeoffs related to economic,
environmental, infrastructure, and fuel supply considerations. While
CPP can adjust its fuel mix to burn more natural gas, doing so at
existing electricity-generating units nationwide poses substantial
challenges because of fuel supply constraints, infrastructure that
would require modification, and economic considerations.
With respect to fuel switching at CPP, AOC's plans to purchase more
natural gas than necessary under the Green the Capitol initiative
raises questions about the efficient use of appropriated funds.
Specifically, we estimated that fuel switching at the plant should cost
between $1.0 and $1.8 million in 2008, well below the $2.75 million
budgeted for this purpose. Key uncertainties with our estimates include
the future price of each fossil fuel burned at the plant and the lack
of complete, reliable information on the overall efficiency of the
plant or its seven boilers. Based on our estimates, substituting
natural gas for a portion of the coal used at the plant would achieve
reductions in carbon dioxide emissions at a cost of about $139 per ton
of emissions. We believe that any decisions to exceed the level of fuel
switching called for by the initiative should take into consideration
the sense of the Congress with respect to achieving greenhouse gas
reductions at the plant, as well as the economic and environmental
tradeoffs associated with the use of each fuel.
Recommendation for Executive Action:
We are recommending that, before adjusting the Capitol Power Plant's
fuel mix beyond the level directed by the Green the Capitol initiative,
the Acting Architect of the Capitol consult with AOC's oversight
committees in the Congress and evaluate the economic and environmental
trade-offs associated with the use of each fuel at the plant, taking
into account the efficiency of the plant's boilers, related fuel supply
systems, and pollution control equipment.
Agency Comments and Our Evaluation:
We provided a draft copy of this report to the Acting Architect of the
Capitol for review and comment. AOC provided comments via electronic
mail. AOC officials said that they agreed with our cost estimate under
the high fuel price scenario but that they were concerned about the
potential level of resources that would be required to respond to our
recommendation. We subsequently met with AOC officials who said that
they were concerned that implementing our recommendation would require
them to collect exact information on the efficiency of its boilers and
fuel supply systems. Based on this discussion, we adjusted the wording
of the recommendation to clarify that this was not our intent. AOC also
provided a number of technical clarifications regarding the plant's
operation and their cost estimates for fuel switching, which we
incorporated into our report as appropriate.
We are sending copies of this report to the appropriate congressional
committees. We are also sending this report to the Architect of the
Capitol and the Department of Energy. We will make copies available to
others upon request. In addition, this report will be available at no
cost on the GAO Web site at [hyperlink, http://www.gao.gov].
If you or your staffs have any questions about this report, please
contact Terrell Dorn at (202) 512-6923 or dornt@gao.gov or Frank Rusco
at (202) 512-3841 or ruscof@gao.gov. Contact points for our Offices of
Congressional Relations and Public Affairs may be found on the last
page of this report. GAO staff who made major contributions to this
report are listed in enclosure II.
Signed by:
Terrell Dorn, Director:
Physical Infrastructure Issues:
Signed by:
Frank Rusco, Director:
National Resources And Environment:
Enclosures:
[End of section]
Enclosure I: Scope and Methodology:
To respond to the first objective, we reviewed two analyses prepared
for the House of Representatives' Chief Administrative Officer (CAO),
including an analysis prepared by the Architect of the Capitol (AOC)
that served as the basis for the fuel-switching funding in the Capitol
Power Plant's (CPP) fiscal year 2008 appropriation, and a subsequent
analysis prepared by the Department of Energy's Lawrence Berkeley
National Laboratory (LBNL). We then developed our own analysis based on
data provided by AOC and U.S. Energy Information Administration (EIA).
Part of our analysis was consistent with LBNL's approach. The primary
differences are that we extended LBNL's analysis to future years based
on projections of fuel use and prices.
In conducting our analysis, we relied on fuel input data from AOC that
had been provided to LBNL via AOC's "Utilities Guru" database. In its
analysis, LBNL had converted the fuel quantities from physical units to
thermal units (expressed in millions of British thermal units). Next,
we estimated the portion of steam produced by CPP that is used to heat
House buildings. To do this, we divided the total square footage of
House buildings by the total square footage served by the plant, based
on data from the AOC's 2006 Report to Congress.[Footnote 14] We
excluded the Ford House Office Building from our analysis because its
steam is supplied by General Services Administration, not CPP. The
resulting calculation indicated that approximately 29 percent of the
plant's steam output is attributable to the House of Representatives.
Because the initiative recommends that CPP use natural gas to meet the
energy needs of the House, we assumed that the House's 29 percent of
steam would be provided by natural gas only. We added to this an amount
of natural gas equivalent to 71 percent of the total natural gas used
had the fuel switching not occurred. This last step ensures that the
amount of natural gas is "additional" to what would have occurred in a
business-as-usual scenario. We based our business-as-usual scenario on
the plant's historical average of 43 percent natural gas, 47 percent
coal, and 10 percent fuel oil over the period from 2001 through 2007.
We left the amount of fuel oil used unchanged because the plant's
operations require the use of fuel oil as a back-up fuel. These
calculations enabled us to approximate the level of natural gas
required to meet the initiative's directive in fiscal year 2008.
To calculate the incremental cost of the new fuel mix in fiscal year
2008, we estimated the total cost of fuel under the Green the Capital
scenario and subtracted our estimate of fuel cost under the business-
as-usual scenario. For both scenarios, we multiplied the quantities of
fuels needed by our estimates of the average cost of fuel per unit. We
based our estimates of the average cost per unit for each fuel on
fiscal year 2008 price projections from EIA. We escalated the EIA-
projected prices by percentage "premiums" based on estimated
relationships between average U.S. fuel prices in the industrial
sector, as reported by EIA, and AOC's annual average fuel costs per
unit over the period from 2001 through 2007.
We assumed that each boiler at the plant converts fuel into steam with
equal efficiency based on a review of available data from an
independent consultant to GAO and from Ross Associates, a consultant to
AOC. We also requested information from AOC on the efficiency of its
boilers on three occasions between November 2007 and January 2008. In
January 2008, AOC referred us to the Ross Associates analysis. In April
2008, AOC provided data on the combustion efficiency of its coal
boilers and two of the four boilers that can burn oil or natural gas,
which it collected during February 2008. Because AOC did not make us
aware of this analysis or provide any results until after we had
completed our work, time constraints precluded us from assessing its
reliability or including it in our analysis. A review of the data
suggests that it would not have made a material difference in our cost
estimates.
As part of our analysis, we projected the AOC's per unit costs of
natural gas, coal, and fuel oil for CPP for the period from 2008
through 2012. To estimate a baseline level of fuel consumption for the
years 2008 through 2012, we started with the average fuel consumption
by CPP during fiscal years 2001 through 2007. We then applied a 1
percent decline in demand each year, beginning in 2008. The 1 percent
estimate is based on two partially offsetting factors:
* Additions to the Capitol Complex, including the Capitol Visitor
Center, are expected to increase the plant's steam demand by 1 percent
each year through 2025. This estimate was obtained from a 2004 report
developed by an AOC consultant.
* The Energy Policy Act of 2005 requires a 2 percent reduction in
energy use per year for federal buildings. Because over one-quarter of
House energy use is for heating, the act's implementation may
significantly reduce steam demand over time.
Next, we estimated the incremental cost of the fuel mix under a Green
the Capitol scenario over what the cost would be without a policy
change, for each year between 2008 through 2012. To do so, we used EIA-
projected fuel prices for the industrial sector escalated with our
estimated AOC cost premiums. These calculations produced a baseline
cost scenario for each year, ranging from a high of $1.44 million in
fiscal year 2009 to a low of $1.15 million in fiscal year 2012.
We also conducted sensitivity analyses around our baseline estimates
using a low-price and a high-price scenario for fiscal years 2008 to
2012. EIA has not yet published new low-and high-price projections
because of their recent revision of the Annual Energy Outlook 2008. To
estimate low-and high-price projections, we adjusted the EIA
projections of fuel prices for the industrial sector using measures of
variability of these prices in the last few years. Specifically, we
calculated the coefficient of variation[Footnote 15] of monthly prices
of coal, natural gas, and distillate oil in the U.S. industrial sector
over the period of December 2003 through November 2007.[Footnote 16]
The coefficient of variation for the monthly prices for this period
were: 18.2 percent for the price of natural gas, 6.5 percent for coal,
and 17.2 percent for fuel oil. For the-low price scenario, we reduced
EIA's price projections for each of the three fuels by the
corresponding percentage, while for the high-price scenario, we
escalated the price projections by the same percentages.
All of our cost estimates are in constant 2006 dollar values. In
preparing our estimates, we consulted with AOC staff, officials
representing the House CAO, and the Department of Energy (including
LBNL and EIA). We also reviewed relevant studies prepared by these
agencies.
To respond to the second objective, we analyzed available data from the
Department of Energy and other sources. We also obtained information
from key stakeholders identified in discussions with the department
that represent the electricity generation, natural gas, and coal
industries using written interview questions. These key stakeholders
included the American Gas Association (AGA), Edison Electric Institute
(EEI), Electric Power Research Institute (EPRI), Interstate Natural Gas
Association of America (INGAA), National Coal Council (NCC), National
Mining Association (NMA), and Natural Gas Supply Association (NGSA). We
conducted our work between October 2007 and April 2008 in accordance
with generally accepted government auditing standards. Those standards
require that we plan and perform the audit to obtain sufficient,
appropriate evidence to provide a reasonable basis for our findings and
conclusions based on our audit objectives. We believe that the evidence
obtained provides a reasonable basis for our findings and conclusions
based on our audit objectives.
[End of enclosure]
Enclosure II: GAO Contacts and Staff Acknowledgments:
GAO Contacts:
Terrell Dorn, (202) 512-6923 or dornt@gao.gov:
Frank Rusco, (202) 512-3841 or ruscof@gao.gov:
Staff Acknowledgments:
In addition to the contacts named above, Elizabeth Beardsley, Janice
Ceperich, Tonnye Conner-White, Elizabeth R. Eisenstadt, Philip Farah,
Mark Gaffigan, Michael Hix, Hannah Laufe, Jessica Lemke, Jon Ludwigson,
Susan Michal-Smith, SaraAnn Moessbauer, Joseph Thompson, and Sara
Vermillion made key contributions to this report.
[End of enclosure]
Footnotes:
[1] Chief Administrative Officer of the House of Representatives, Final
Report, Green the Capitol Initiative (June 21, 2007). The Green the
Capitol initiative establishes the goal of carbon neutrality for the
House of Representatives only, whereas CPP also serves the Senate and
additional congressional buildings.
[2] According to the Department of Energy's Energy Information
Administration, the amount of carbon dioxide emitted from burning
pipeline natural gas is 117.08 pounds per million British thermal units
(Btu) of energy. The amount generated from burning coal ranges from
205.3 pounds to 227.4 pounds per million Btu and depends on the
specific type of coal burned.
[3] Consolidated Appropriations Act, 2008, Committee Print of the House
Committee on Appropriations on H.R. 2764/Public Law 110-161
(Legislative Text and Explanatory Statement), 153 Cong. Rec. H15479,
H15741 (Dec. 17, 2007). According to a House Appropriations Committee
summary of the initial House-passed legislative branch appropriations
bill, the Green the Capitol initiative funding in the earlier bill
included "...$2.7 million to shift from coal to cleaner burning natural
gas for heating needs, $520,000 to switch to 100 percent renewable wind
power for electrical needs, $500,000 for an ethanol gas station for
House automobiles, and $100,000 for energy efficient compact florescent
light bulbs." (See [hyperlink,
http://appropriations.house.gov/press_releases_2007.aspx], follow link
under "August.")
[4] In addition to space heating, these boilers provide energy for
other minor services, including humidification and food services. The
House of Representatives purchases electricity from an external
provider.
[5] The plant's coal boilers underwent a number of renovations and
repairs, including a grate replacement, in 2005 and 2006. This may have
decreased the amount of coal that the plant would have otherwise burned
in those years, leading to a lower average baseline level of coal use.
[6] The difference between AOC's per unit cost of a given fuel and the
corresponding average U.S. price of the same fuel in the industrial
sector can be due to various factors, including transportation costs.
[7] GAO, Natural Gas: Factors Affecting Prices and Potential Impacts on
Consumers, [hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO-06-420T]
(Washington, D.C.: Feb. 13, 2006).
[8] A metric ton is equal to 2,205 pounds, while a short ton, a
measurement used in the United States is equal to 2,000 pounds.
[9] GAO, Legislative Branch: Energy Audits Are Key to Strategy for
Reducing Greenhouse Gas Emissions, [hyperlink, http://www.gao.gov/cgi-
bin/getrpt?GAO-07-516] (Washington, D.C.: Apr. 25, 2007).
[10] EIA defines LNG as natural gas (primarily methane) that has been
liquefied by reducing its temperature to -260 degrees Fahrenheit at
atmospheric pressure. LNG and other liquefied petroleum gases are
liquefied through pressurization for convenience of transportation.
[11] The EIA definition of capacity factor is "the ratio of the
electrical energy produced by a generating unit for the period of time
considered to be the electrical energy that could have been produced at
continuous full power operation during the same period."
[12] EIA defines base load capacity as the generating equipment
normally operated to serve loads on an around-the-clock basis.
According to EIA, a base load plant usually houses high-efficiency,
steam-electric units, which are normally operated to take all or part
of the minimum load of a system, and which consequently produce
electricity at an essentially constant rate and run continuously. These
units are operated to maximize system mechanical and thermal efficiency
and minimize system operating costs.
[13] GAO, Natural Gas: Factors Affecting Prices and Potential Impacts
on Consumers, [hyperlink, http://www.gao.gov/cgi-bin/getrpt?GAO-06-
420T] (Washington, D.C.: Feb. 13, 2006).
[14] The buildings used by the House of Representatives that were
included in our analysis are: Cannon House Office Building, Longworth
House Office Building, Rayburn House Office Building, East and West
underground garages, and the House Page Dorm. Our analysis also
includes 50 percent of the U.S. Capitol building and CPP.
[15] The coefficient of variation is defined as the standard deviation
divided by the mean.
[16] At the time of writing, December 2007 was the last month for which
prices of these fuels were available from EIA.
[End of section]
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