Rising Utility Construction Costs:

Sources and Impacts

Prepared by:
Marc W. Chupka
Gregory Basheda

The Brattle Group

Prepared for:

SEPTEMBER 2007
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 Table of Contents

Introduction and Executive Summary.................................................................................................... 1

Projected Investment Needs and Recent Infrastructure Cost Increases ............................................. 5

Current and Projected U.S. Investment in Electricity Infrastructure ......................................................................5
Generation...............................................................................................................................................................5
High-Voltage Transmission ....................................................................................................................................6
Distribution .............................................................................................................................................................6
Construction Costs for Recently Completed Generation........................................................................................7
Rising Projected Construction Costs: Examples and Case Studies .....................................................................10
Coal-Based Power Plants ..............................................................................................................................10
Transmission Projects ...................................................................................................................................11
Distribution Equipment.................................................................................................................................12

Factors Spurring Rising Construction Costs ....................................................................................... 13

Material Input Costs..............................................................................................................................................13
Metals............................................................................................................................................................13
Cement, Concrete, Stone and Gravel ............................................................................................................17
Manufactured Products for Utility Infrastructure .........................................................................................18
Labor Costs ...................................................................................................................................................20
Shop and Fabrication Capacity .............................................................................................................................21
Engineering, Procurement and Construction (EPC) Market Conditions ..............................................................23
Summary Construction Cost Indices ....................................................................................................................24
Comparison with Energy Information Administration Power Plant Cost Estimates ............................................27

Conclusion ............................................................................................................................................... 31

iii
 Introduction and Executive Summary
In Why Are Electricity Prices Increasing? An Industry-Wide Perspective (June 2006), The Brattle Group
identified fuel and purchased-power cost increases as the primary driver of the electricity rate increases that
consumers currently are facing. That report also noted that utilities are once again entering an infrastructure
expansion phase, with significant investments in new baseload generating capacity, expansion of the bulk
transmission system, distribution system enhancements, and new environmental controls. The report
concluded that the industry could make the needed investments cost-effectively under a generally supportive
rate environment.

The rate increase pressures arising from elevated fuel and purchased power prices continue. However,
another major cost driver that was not explored in the previous work also will impact electric rates, namely,
the substantial increases in the costs of building utility infrastructure projects. Some of the factors
underlying these construction cost trends are straightforward—such as sharp increases in materials cost—
while others are complex, and sometimes less transparent in their impact. Moreover, the recent rise in many
utility construction cost components follows roughly a decade of relatively stable (or even declining) real
construction costs, adding to the “sticker shock” that utilities experience when obtaining cost estimates or
bids and that state public utility commissions experience during the process of reviewing applications for
approvals to proceed with construction. While the full rate impact associated with construction cost
increases will not be seen by customers until infrastructure projects are completed, the issue of rising
construction costs currently affects industry investment plans and presents new challenges to regulators.

The purpose of this study is to a) document recent increases in the construction cost of utility infrastructure
(generation, transmission, and distribution), b) identify the underlying causes of these increases, and c)
explain how these increased costs will translate into higher rates that consumers might face as a result of
required infrastructure investment. This report also provides a reference for utilities, regulators and the
public to understand the issues related to recent construction cost increases. In summary, we find the
following:
ƒ Dramatically increased raw materials prices (e.g., steel, cement) have increased construction cost
directly and indirectly through the higher cost of manufactured components common in utility
infrastructure projects. These cost increases have primarily been due to high global demand for
commodities and manufactured goods, higher production and transportation costs (in part owing to
high fuel prices), and a weakening U.S. dollar.
ƒ Increased labor costs are a smaller contributor to increased utility construction costs, although that
contribution may rise in the future as large construction projects across the country raise the demand
for specialized and skilled labor over current or projected supply. There also is a growing backlog of

1
Introduction and Executive Summary

project contracts at large engineering, procurement and construction (EPC) firms, and construction
management bids have begun to rise as a result. Although it is not possible to quantify the impact on
future project bids by EPC firms, it is reasonable to assume that bids will become less cost-competitive
as new construction projects are added to the queue.
ƒ The price increases experienced over the past several years have affected all electric sector investment
costs. In the generation sector, all technologies have experienced substantial cost increases in the past
three years, from coal plants to windpower projects. Large proposed transmission projects have
undergone cost revisions, and distribution system equipment costs have been rising rapidly. This is
seen in Figure ES-1, which shows recent price trends in generation, transmission and distribution
infrastructure costs based on the Handy-Whitman Index© data series, compared with the general price
level as measured by the gross domestic product (GDP) deflator over the same time period. 1 As
shown in Figure ES-1, infrastructure costs were relatively stable during the 1990s, but have
experienced substantial price increases in the past several years. Between January 2004 and January
2007, the costs of steam-generation plant, transmission projects and distribution equipment rose by 25
percent to 35 percent (compared to an 8 percent increase in the GDP deflator). For example, the cost
of gas turbines, which was fairly steady in the early part of the decade, increased by 17 percent during
the year 2006 alone. As a result of these cost increases, the levelized capital cost component of
baseload coal and nuclear plants has risen by $20/MWh or more—substantially narrowing coal’s
overall cost advantages over natural gas-fired combined-cycle plants—and thus limiting some of the
cost-reduction benefits expected from expanding the solid-fuel fleet.

Figure ES-1
National Average Utility Infrastructure Cost Indices
Total Plant-All Steam Generation Gas Turbogenerators GDP Deflator Transmission Distribution

190

180

170

160
Index (1991=100)

150

140

130

120

110

100

90
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Year
Sources: The Handy-Whitman© Bulletin, No. 165 and the U.S. Bureau of Economic Analysis.
Simple average of all regional construction and equipment cost indexes for the specified components.

1
The GDP deflator measures the cost of goods and services purchased by households, industry and government, and as such
is a broader price index than the Consumer Price Index (CPI) or Producer Price Index (PPI), which track the costs of
goods and services purchased by households and industry, respectively.

2
 Rising Utility Construction Costs: Sources and Impacts

ƒ The rapid increases experienced in utility construction costs have raised the price of recently
completed infrastructure projects, but the impact has been mitigated somewhat to the extent that
construction or materials acquisition preceded the most recent price increases. The impact of rising
costs has a more dramatic impact on the estimated cost of proposed utility infrastructure projects,
which fully incorporates recent price trends. This has raised significant concerns that the next wave
of utility investments may be imperiled by the high cost environment. These rising construction costs
have also motivated utilities and regulators to more actively pursue energy efficiency and demand
response initiatives in order to reduce the future rate impacts on consumers.
ƒ Despite the overwhelming evidence that construction costs have risen and will be elevated for some
time, these increased costs are largely absent from the capital costs specified in the Energy Information
Administration's (EIA's) 2007 Annual Energy Outlook (AEO). The AEO generation capital cost
assumptions since 2001 are shown in Figure ES-2. Since 2004, capital costs of all technologies are
assumed to grow at the general price level—a pattern that contradicts the market evidence presented in
this report. The growing divergence between the AEO data assumptions and recent cost escalation is
now so substantial that the AEO data need to be adjusted to reflect recent cost increases to provide
reliable indicators of current or future capital costs.

Figure ES-2
EIA Generation Construction Cost Estimates

Conventional Coal Conventional CC Conventional CT Wind Advanced Nuclear

IGCC Wind Advanced Nuclear Conventional CT GDP Deflator
135

130

125

120
Index (2001=100)

115 GDP
Deflator
110

105

100

95

90

85
2001 2002 2003 2004 2005 2006
Year
Sources: Data collected from the U.S. Energy Information Administration, Assumptions to the Annual Energy Outlook 2002 to
2007 and from the U.S. Bureau of Economic Analysis.

3
 Projected Investment Needs and Recent
Infrastructure Cost Increases
Current and Projected U.S. Investment in Electricity Infrastructure
The electric power industry is a very capital-intensive industry. The total value of generation, transmission
and distribution infrastructure for regulated electric utilities is roughly $440 billion (property in service, net
of accumulated depreciation and amortization), and capital expenditures are expected to exceed $70 billion
in 2007. 2 Although the industry as a whole is always investing in capital, the rate of capital expenditures
was relatively stable during the 1990s and began to rise near the turn of the century. As shown in Why Are
Electricity Prices Increasing? An Industry-Wide Perspective (June 2006), utilities anticipate substantial
increases in generation, transmission and distribution investment levels over the next two decades.
Moreover, the significant need for new electricity infrastructure is a world-wide phenomenon: According to
the World Energy Investment Outlook 2006, investments by power-sector companies throughout the world
will total about $11 trillion dollars by 2030. 3

Generation
As of December 31, 2005, there were 988 gigawatts (GW) of electric generating capacity in service in the
U.S., with the majority of this capacity owned by electric utilities. Close to 400 GW of this total, or 39
percent, consists of natural gas-fired capacity, with coal-based capacity comprising 32 percent, or slightly
more than 300 GW, of the U.S. electric generation fleet. Nuclear and hydroelectric plants comprise
approximately 10 percent of the electric generation fleet. Approximately 49 percent of energy production is
provided by coal plants, with 19 percent provided by nuclear plants. Natural gas-fired plants, which tend to
operate as intermediate or peaking plants, also provided about 19 percent of U.S. energy production in 2006.

The need for installed generating capacity is highly correlated with load growth and projected growth in peak
demand. According to EIA’s most recent projections, U.S. electricity sales are expected to grow at an annual
rate of about 1.4 percent through 2030. According to the North American Electric Reliability Corporation
(NERC), U.S. non-coincident peak demand is expected to grow by 19 percent (141 GW) from 2006 to 2015.
According to EIA, utilities will need to build 258 GW of new generating capacity by 2030 to meet the

2
Net property in service figure as of December 31, 2006, derived from Federal Energy Regulatory Commission (FERC)
Form 1 data compiled by the Edison Electric Institute (EEI). Gross property is roughly $730 billion, with about $290
billion already depreciated and/or amortized. Annual capital expenditure estimate is derived from a sample of 10K reports
surveyed by EEI.
3
Richard Stavros. “Power Plant Development: Raising the Stakes.” Public Utilities Fortnightly, May 2007, pp. 36-42.

5
Projected Investment Needs and Recent Infrastructure Cost Increases

projected growth in electricity demand and to replace old, inefficient plants that will be retired. EIA further
projects that coal-based capacity, that is more capital intensive than natural gas-fired capacity which
dominated new capacity additions over the last 15 years, will account for about 54 percent of total capacity
additions from 2006 to 2030. Natural gas-fired plants comprise 36 percent of the projected capacity
additions in AEO 2007. EIA projects that the remaining 10 percent of capacity additions will be provided by
renewable generators (6 percent) and nuclear power plants (4 percent). Renewable generators and nuclear
power plants, similar to coal-based plants, are capital-intensive technologies with relatively high construction
costs but low operating costs.

High-Voltage Transmission
The U.S. and Canadian electric transmission grid includes more than 200,000 miles of high voltage (230 kV
and higher) transmission lines that ultimately serve more than 300 million customers. This system was built
over the past 100 years, primarily by vertically integrated utilities that generated and transmitted electricity
locally for the benefit of their native load customers. Today, 134 control areas or balancing authorities
manage electricity operations for local areas and coordinate reliability through the eight regional reliability
councils of NERC.

After a long period of decline, transmission investment began a significant upward trend starting in the year
2000. Since the beginning of 2000, the industry has invested more than $37.8 billion in the nation’s
transmission system. In 2006 alone, investor-owned electric utilities and stand-alone transmission
companies invested an historic $6.9 billion in the nation’s grid, while the Edison Electric Institute (EEI)
estimates that utility transmission investments will increase to $8.0 billion during 2007. A recent EEI survey
shows that its members plan to invest $31.5 billion in the transmission system from 2006 to 2009, a nearly
60-percent increase over the amount invested from 2002 to 2005. These increased investments in
transmission are prompted in part by the larger scale of base load generation additions that will occur farther
from load centers, creating a need for larger and more costly transmission projects than those built over the
past 20 years. In addition, new government policies and industry structures will contribute to greater
transmission investment. In many parts of the country, transmission planning has been formally
regionalized, and power markets create greater price transparency that highlights the value of transmission
expansion in some instances.

NERC projects that 12,873 miles of new transmission will be added by 2015, an increase of 6.1 percent in
the total miles of installed extra high-voltage (EHV) transmission lines (230 kV and above) in North
America over the 2006 to 2015 period. NERC notes that this expansion lags demand growth and expansion
of generating resources in most areas. However, NERC’s figures do not include several major new
transmission projects proposed in the PJM Interconnection LLC, such as the major new lines proposed by
American Electric Power, Allegheny Power, and Pepco.

Distribution
While transmission systems move bulk power across wide areas, distribution systems deliver lower-voltage
power to retail customers. The distribution system includes poles, as well as metering, billing, and other
related infrastructure and software associated with retail sales and customer care functions. Continual

6
 Rising Utility Construction Costs: Sources and Impacts

investment in distribution facilities is needed, first and foremost, to keep pace with growth in customer
demand. In real terms, investment began to increase in the mid-1990s, preceding the corresponding boom in
generation. This steady climb in investment in distribution assets shows no sign of diminishing. The need to
replace an aging infrastructure, coupled with increased population growth and demand for power quality and
customer service, is continuing to motivate utilities to improve their ultimate delivery system to customers.

Continued customer load growth will require continued expansion in distribution system capacity. In 2006,
utilities invested about $17.3 billion in upgrading and expanding distribution systems, a 32-percent increase
over the investment levels incurred in 2004. EEI projects that distribution investment during 2007 will again
exceed $17.0 billion. While much of the recent increase in distribution investment reflects expanding
physical infrastructure, a substantial portion of the increased dollar investment reflects the increased input
costs of materials and labor to meet current distribution infrastructure needs.

Construction Costs for Recently Completed Generation

The majority of recently constructed plants have been either natural gas-fired or wind power plants. Both
have displayed increasing real costs for several years. Since the 1990s, most of the new generating capacity
built in the U.S. has been natural gas-fired capacity, either natural gas-fired combined-cycle units or natural
gas-fired combustion turbines. Combustion turbine prices recently rose sharply after years of real price
decreases, while significant increases in the cost of installed natural gas combined-cycle combustion capacity
have emerged during the past several years.

Using commercially available databases and other sources, such as financial reports, press releases and
government documents, The Brattle Group collected data on the installation cost of natural gas-fired
combined-cycle generating plants built in the U.S. during the last major construction cycle, defined as
generating plants brought into service between 2000 and 2006. We estimated that the average real
construction cost of all natural gas-fired combined-cycle units brought online between 2000 and 2006 was
approximately $550/kilowatt (kW) (in 2006 dollars), with a range of costs between $400/kW to
approximately $1,000/kW. Statistical analysis confirmed that real installation cost was influenced by plant
size, the turbine technology, the NERC region in which the plant was located, and the commercial online
date. Notably, we found a positive and statistically significant relationship between a plant’s construction
cost and its online date, meaning that, everything else equal, the later a plant was brought online, the higher
its real installation cost. 4 Figure 1 shows the average yearly installation cost, in nominal dollars, as predicted
by the regression analysis. 5 This figure shows that the average installation cost of combined-cycle units
increased gradually from 2000 to 2003, followed by a fairly significant increase in 2004 and a very
significant escalation—more than $300/kW—in 2006. This provides vivid evidence of the recent sharp
increase in plant construction costs.

4
To be precise, we used a “dummy” variable to represent each year in the analysis. The year-specific dummy variables
were statistically significant and uniformly positive; i.e., they had an upward impact on installation cost.
5
The nominal form regression results are discussed here to facilitate comparison with the GDP deflator measure used to
compare other price trends in other figures in this report.

7
Projected Investment Needs and Recent Infrastructure Cost Increases

Figure 1
Multi-Variable Regression Estimation:
Average Nominal Installation Costs Based on Online Year ($/kW)
1000

900

5
800

89
700

600
($/kW)

500

2
57

57
4

0
7
51

51
50
400
9
45

300

200

100

0
2000 2001 2002 2003 2004 2005 2006
Online Year
Sources and Notes:
* Data on summer capacity, total installation cost , turbine technology, commercial online date, and zip code for the period 2000-2006
were collected from commercially available databases and other sources such as company websites and 10k reports.

Figure 2 compares the trend in plant installation costs to the GDP deflator, using 2000 as the base year. Over
the period of 2000 to 2006, the cumulative increase in the general price level was 16 percent while the
cumulative increase in the installation cost of new combined-cycle units was almost 95 percent, with much
of this increase occurring in 2006.

Figure 2
Multi-Variable Regression Estimation:
Average Nominal Installation Costs Based on Online Year (Index Year 2000 = 100)
250
GDP Deflator
Average Installation Costs 5
19
200

150 5 5
12 12
Index

2 0 1
0 11 11 11
10
100
6
3

11
9

11
6

10
4
2

10
0

10
10
10

50

0
2000 2001 2002 2003 2004 2005 2006
Online Year
Sources and Notes:
* Data on summer capacity, total installation cost , turbine technology, commercial online date, and zip code for the period 2000-2006
were collected from commercially available databases and other sources such as company websites and 10k reports.
** GDP Deflator data were collected from the U.S. Bureau of Economic Analysis.

8
 Rising Utility Construction Costs: Sources and Impacts

Another major class of generation development during this decade has been wind generation, the costs of
which have also increased in recent years. The Northwest Power and Conservation Council (NPCC), a
regional planning council that prepares long-term electric resource plans for the Pacific Northwest, issued its
most recent review of the cost of wind power in July 2006. 6 The Council found that the cost of new wind
projects rose substantially in real terms in the last two years, and was much higher than that assumed in its
most recent resource plan. Specifically, the Council found that the levelized lifecycle cost of power for new
wind projects rose 50 to 70 percent, with higher construction costs being the principal contributor to this
increased cost. According to the Council, the construction cost of wind projects, in real dollars, has
increased from about $1150/kW to $1300-$1700/kW in the past few years, with an unweighted average
capital cost of wind projects in 2006 at $1,485/kW. Factors contributing to the increase in wind power costs
include a weakening dollar, escalation of commodity and energy costs, and increased demand for wind
power under renewable portfolio standards established by a growing number of states. The Council notes
that commodities used in the manufacture and installation of wind turbines and ancillary equipment,
including cement, copper, steel and resin have experienced significant cost increases in recent years. Figure
3 shows real construction costs of wind projects by actual or projected in-service date.

Figure 3
Wind Power Project Capital Costs
$2,000
2006$/kW

$1,500

$1,000

$500 Estimated overnight capital cost

Poly. (Estimated overnight capital cost)

$0
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Service Year

Source: The Northwest Power and Conservation Council, "Biennial Review of the Cost of Windpower" July 13, 2006.

These observations were confirmed recently in a May 2007 report by the U.S. Department of Energy (DOE),
which found that prices for wind turbines (the primary cost component of installed wind capacity) rose by
more than $400/kW between 2002 and 2006, a nearly 60-percent increase. 7 Figure 4 is reproduced from the
DOE report (Figure 21) and shows the significant upward trend in turbine prices since 2001.

6
The NPCC planning studies and analyses cover the following four states: Washington, Oregon, Idaho, and Montana. See
“Biennial Review of the Cost of Windpower” July 13, 2006, at
www.bpa.gov/Energy/N/projects/post2006conservation/doc/Windpower_Cost_Review.doc. This study provides many
reasons for windpower cost increases.
7
See U.S. Department of Energy, Annual Report on U.S. Wind Power Installation, Cost and Performance Trends: 2006
Figure 21, page 16.

9
Projected Investment Needs and Recent Infrastructure Cost Increases

Figure 4
Wind Turbine Prices 1997 - 2007

Rising Projected Construction Costs: Examples and Case Studies

Although recently completed gas-fired and wind-powered capacity has shown steady real cost increases in
recent years, the most dramatic cost escalation figures arise from proposed utility investments, which fully
reflect the recent, sharply rising prices of various components of construction and installation costs. The
most visible of these are generation proposals, although several transmission proposals also have undergone
substantial upward cost revisions. Distribution-level investments are smaller and less discrete (“lumpy”) and
thus are not subject to similar ongoing public scrutiny on a project-by-project basis.

Coal-Based Power Plants

Evidence of the significant increase in the construction cost of coal-based power plants can be found in
recent applications filed by utilities, such as Duke Energy and Otter Tail Power Company, seeking
regulatory approval to build such plants. Otter Tail Power Company leads a consortium of seven
Midwestern utilities that are seeking to build a 630-MW coal-based generating unit (Big Stone II) on the site
of the existing Big Stone Plant near Milbank, South Dakota. In addition, the developers of Big Stone II seek
to build a new high-voltage transmission line to deliver power from Big Stone II and from other sources,
including possibly wind and other renewable forms of energy. Initial cost estimates for the power plant were
about $1 billion, with an additional $200 million for the transmission line project. However, these cost
estimates increased dramatically, largely due to higher costs for construction materials and labor. 8 Based on
the most recent design refinements, the project, including transmission, is expected to cost $1.6 billion.

8
Other factors contributing to the cost increase include design changes made by project participants to increase output and
improve the unit’s efficiency. For example, the voltage of the proposed transmission line was increased from 230 kV to
345 kV to accommodate more generation.

10
 Rising Utility Construction Costs: Sources and Impacts

In June 2006, Duke submitted a filing with the North Carolina Utilities Commission (NCUC) seeking a
certificate of public convenience and necessity for the construction of two 800 MW coal-based generating
units at the site of the existing Cliffside Steam Station. In its initial application, Duke relied on a May 2005
preliminary cost estimate showing that the two units would cost approximately $2 billion to build. Five
months later, Duke submitted a second filing with a significantly revised cost estimate. In its second filing,
Duke estimated that the two units would cost approximately $3 billion to build, a 50 percent cost increase.
The North Carolina Utilities Commission approved the construction of one 800 MW unit at Cliffside but
disapproved the other unit, primarily on the basis that Duke had not made a showing that it needed the
capacity to serve projected native load demands. Duke’s latest projected cost for building one 800 MW unit
at Cliffside is approximately $1.8 billion, or about $2,250/kW. When financing costs, or allowance for funds
used during construction (AFUDC), are included, the total cost is estimated to be $2.4 billion (or about
$3,000/kW).

Rising construction costs have also led utilities to reconsider expansion plans prior to regulatory actions. In
December 2006, Westar Energy announced that it was deferring the consideration of a new 600 MW coal-
based generation facility due to significant increases in the estimated construction costs, which increased
from $1.0 billion to about $1.4 billion since the plant was first announced in May 2005.

Increased construction costs are also affecting proposed demonstration projects. For example, DOE
announced earlier this year that the projected cost for one of its most prominent clean coal demonstration
project, FutureGen, had nearly doubled. 9 FutureGen is a clean coal demonstration project being pursued by
a public-private partnership involving DOE and an alliance of industrial coal producers and electric utilities.
FutureGen is an experimental advanced Integrated Gasification Combined Cycle (IGCC) coal plant project
that will aim for near zero emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), mercury, particulates
and carbon dioxide (CO2). Its initial cost was estimated at $950 million. But after re-evaluating the price of
construction materials and labor and adjusting for inflation over time, DOE’s Office of Fossil Energy
announced that the project’s price had increased to $1.7 billion.

Transmission Projects
NSTAR, the electric distribution company that serves the Boston metropolitan area, recently built two 345
kV lines from a switching station in Stoughton, Massachusetts, to substations in the Hyde Park section of
Boston and to South Boston, respectively. In an August 2004 filing before ISO New England Inc. (ISO-NE),
NSTAR indicated that the project would cost $234.2 million. In March 2007, NSTAR informed ISO-NE
that estimated project costs had increased by $57.7 million, or almost 25 percent, for a revised total project
cost of $292 million. NSTAR stated that the increase is driven by increases in both construction and material
costs, with construction bids coming in 24 percent higher than initially estimated. NSTAR further explained
that there have been dramatic increases in material costs, with copper costs increasing by 160 percent, core
steel by 70 percent, flow-fill concrete by 45 percent, and dielectric fluid (used for cable cooling) by 66
percent.

9
U.S. Department of Energy, April 10, 2007, press release available at
http://www.fossil.energy.gov/news/techlines/2007/07019-DOE_Signs_FutureGen_Agreement.html
.

11
Projected Investment Needs and Recent Infrastructure Cost Increases

Another aspect of transmission projects is land requirements, and in many areas of the country land prices
have increased substantially in the past few years. In March 2007, the California Public Utilities
Commission (CPUC) approved construction of the Southern California Edison (SCE) Company’s proposed
25.6-mile, 500 kV transmission line between SCE’s existing Antelope and Pardee Substations. SCE initially
estimated a cost of $80.3 million for the Antelope-Pardee 500 kV line. However, the company subsequently
revised its estimate by updating the anticipated cost of acquiring a right-of-way, reflecting a rise in
California’s real estate prices. The increased land acquisition costs increased the total estimate for the
project to $92.5 million, increasing the estimated costs to more than $3.5 million per mile.

Distribution Equipment
Although most individual distribution projects are small relative to the more visible and public generation
and transmission projects, costs have been rising in this sector as well. This is most readily seen in Handy-
Whitman Index© price series relating to distribution equipment and components. Several important
categories of distribution equipment have experienced sharp price increases over the past three years. For
example, the prices of line transformers and pad transformers have increased by 68 percent and 79 percent,
respectively, between January 2004 and January 2007, with increases during 2006 alone of 28 percent and 23
percent. 10 The cost of overhead conductors and devices increased over the past three years by 34 percent,
and the cost of station equipment rose by 38 percent. These are in contrast to the overall price increases
(measured by the GDP deflator) of roughly 8 percent over the past three years.

10
Handy-Whitman© Bulletin No. 165, average increase of six U.S. regions. Used with permission.

12
 Factors Spurring Rising Construction
Costs
Broadly speaking, there are four primary sources of the increase in construction costs: (1) material input
costs, including the cost of raw physical inputs, such as steel and cement as well as increased costs of
components manufactured from these inputs (e.g., transformers, turbines, pumps); (2) shop and fabrication
capacity for manufactured components (relative to current demand); (3) the cost of construction field labor,
both unskilled and craft labor; and (4) the market for large construction project management, i.e., the queuing
and bidding for projects. This section will discuss each of these factors.

Material Input Costs

Utility construction projects involve large quantities of steel, aluminum and copper (and components
manufactured from these metals) as well as cement for foundations, footings and structures. All of these
commodities have experienced substantial recent price increases, due to increased domestic and global
demands as well as increased energy costs in mineral extraction, processing and transportation. In addition,
since many of these materials are traded globally, the recent performance of the U.S. dollar will impact the
domestic costs (see box on page 14).

Metals
After being relatively stable for many years (and even declining in real terms), the price of various metals,
including steel, copper and aluminum, has increased significantly in the last few years. These increases are
primarily the result of high global demand and increased production costs (including the impact of high
energy prices). A weakening U.S. dollar has also contributed to high domestic prices for imported metals
and various component products.

Figure 5 shows price indices for primary inputs into steel production (iron and steel scrap, and iron ore) since
1997. The price of both inputs fell in real terms during the late 1990s, but rose sharply after 2002.
Compared to the 20-percent increase in the general inflation rate (GDP deflator) between 1997 and 2006,
iron ore prices rose 75 percent and iron and steel scrap prices rose nearly 120 percent. The increase over the
last few years was especially sharp—between 2003 and 2006, prices for iron ore rose 60 percent and iron
and scrap steel rose 150 percent.

13
Factors Spurring Rising Construction Costs

Exchange Rates
Many of the raw materials involved in utility construction projects (e.g., steel, copper,
cement), as well as many major manufactured components of utility infrastructure
investments, are globally traded. This means that prices in the U.S. are also affected
by exchange rate fluctuations, which have been adverse to the dollar in recent years.
The chart below shows trade-weighted exchange rates from 1997. Although the dollar
appreciated against other currencies between 1997 and 2001, the graph also clearly
shows a substantial erosion of the dollar since the beginning of 2002, losing roughly 20
percent of its value against other major trading partners’ currencies. This has had a
substantial impact on U.S. material and manufactured component prices, as will be
reflected in many of the graphs that follow.

Nominal Broad Dollar Index

135

130

125
Index (1997=100)

120

115

110

105

100
7

97

99

01

03

05

7
99

00

00

00

00
99

99

00

00

00

00
19

19

20

20

20
-1

-1

-1

-2

-2

-2

-2

-2

-2

-2

-2
P-

P-

P-

P-

P-
Y

Y
N

N
SE

SE

SE

SE

SE
A

A
JA

JA

JA

JA

JA

JA
M

Source: U.S. Federal Reserve Board, Statistical Release, Broad Index Date
Foreign Exchange Value of the Dollar.

14
 Rising Utility Construction Costs: Sources and Impacts

Figure 5
Inputs to Iron and Steel Production Cost Indices
225

200

Iron and Steel Scrap

175
Index (1997=100)

150

Iron Ore
125
GDP Deflator

100

75

50
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Year
Sources: U.S. Geological Survey, Mineral Commodity Summaries, and the U.S. Bureau of Economic Analysis.

The increase in input prices has been reflected in steel mill product prices. Figure 6 compares the trend in
steel mill product prices to the general inflation rate (using the GDP deflator) over the past 10 years. Figure
6 shows that the price of steel has increased about 60 percent since 2003.

Figure 6
Steel Mill Products Price Index

160

150
Steel Mill Products

140
Index (1997=100)

130

120
GDP Deflator
110

100

90

80
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Year
Sources: U.S. Geological Survey, Mineral Commodity Summaries, and the U.S. Bureau of Economic Analysis.

15
Factors Spurring Rising Construction Costs

Various sources point to the rapid growth of steel production and demand in China as a primary cause of the
increases in both steel prices and the prices of steelmaking inputs. 11 China has become both the world’s
largest steelmaker and steel consumer. In addition, some analysts contend that steel companies have
achieved greater pricing power, partly due to ongoing consolidation of the industry, and note that recently
increased demand for steel has been driven largely by products used in energy and heavy industry, such as
plate and structural steels.

From the perspective of the steel industry, the substantial and at least semi-permanent rise in the price of
steel has been justified by the rapid rise in the price of many steelmaking inputs, such as steel scrap, iron ore,
coking coal, and natural gas. Today’s steel prices remain at historically elevated levels and, based on the
underlying causes for high prices described, it appears that iron and steel costs are likely to remain at these
high levels at least for the near future.

Other metals important for utility infrastructure display similar price patterns: declining real prices over the
first five years or so of the previous 10 years, followed by sharp increases in the last few years. Figure 7
shows that aluminum prices doubled between 2003 and 2006, while copper prices nearly quadrupled over the
same period.

Figure 7
Aluminum and Copper Price Indices
300

250

Copper
Index (1997=100)

200

Aluminum

150

GDP Deflator

100

50
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Year
Sources: U.S. Geological Survey, Mineral Commodity Summaries, and the U.S. Bureau of Economic Analysis.

11
See, for example, Steel: Price and Policy Issues, CRS Report to Congress, Congressional Research Service, August 31,
2006.

16
 Rising Utility Construction Costs: Sources and Impacts

These price increases were also evident in metals that contribute to important steel alloys used broadly in
electrical infrastructure, such as nickel and tungsten. The prices of these display similar patterns, as shown
in Figure 8.

Figure 8
Nickel and Tungsten Price Indices

350

300

250
Index (1997=100)

200
Nickel

150

GDP Deflator
100
Tungsten

50
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Year
Sources: U.S. Geological Survey, Mineral Commodity Summaries, and the U.S. Bureau of Economic Analysis.

Cement, Concrete, Stone and Gravel

Large infrastructure projects require huge amounts of cement as well as basic stone materials. The price of
cement has also risen substantially in the past few years, for the same reasons cited above for metals.
Cement is an energy-intensive commodity that is traded on international markets, and recent price patterns
resemble those displayed for metals. In utility construction, cement is often combined with stone and other
aggregates for concrete (often reinforced with steel), and there are other site uses for sand, gravel and stone.
These materials have also undergone significant price increases, primarily as a result of increased energy
costs in extraction and transportation. Figure 9 shows recent price increases for cement and crushed stone.
Prices for these materials have increased about 30 percent between 2004 and 2006.

17
Factors Spurring Rising Construction Costs

Figure 9
Cement and Crushed Stone Price Indices
150

140

130
Index (1997=100)

120
GDP Deflator

110

Cement
100

Crushed Stone

90
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Year
Sources: U.S. Geological Survey, Mineral Commodity Summaries, and the U.S. Bureau of Economic Analysis.

Manufactured Products for Utility Infrastructure

Although large utility construction projects consume substantial amounts of unassembled or semi-finished
metal products (e.g., reinforcing bars for concrete, structural steel), many of the components such as
conductors, transformers and other equipment are manufactured elsewhere and shipped to the construction
site. Available price indices for these components display similar patterns of recent sharp price increases.

Figure 10 shows the increased prices experienced in wire products compared to the inflation rate, according
to the U.S. Bureau of Labor Statistics (BLS), highlighting the impact of underlying metal price increases.

Manufactured components of generating facilities—large pressure vessels, condensers, pumps, valves—have

also increased sharply since 2004. Figure 11 shows the yearly increases experienced in key component
prices since 2003.

18
 Rising Utility Construction Costs: Sources and Impacts

Figure 10
Electric Wire and Cable Price Indices
240

220

200
Copper Wire
Index (1997=100)

180

160

140

Electric Wire and Cable

120
GDP Deflator
100

Nonferrous Wire
80
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Year
Sources: The U.S. Bureau of Labor Statistics and the U.S. Bureau of Economic Analysis.

Figure 11
Equipment Price Increases

2003 2004 2005 2006

0.8

0.7
8%
0.6 20%

0.5 9%
15% 15%
0.4 10%
30% 45%
25%
8%
0.3
25%
30%
25%
0.2 8% 16%
15%
0.1 20% 7% 12%
12% 7% 8% 9%
5%
0
l
ss els ipe ers gea
r
ive
rs
ive
rs tee ent
Ve eP ng ch Dr Dr lS ip m
ns, Lin cha Sw
it ura qu
Ex s& r& uct E
olu m mp s so St r her
C Pu pr e Ot
C om
Source: "Who, What, Where, How" presentation by John Siegel, Bechtel Power Corp. Delivered at the conference entitled Next
Generation of Generation (Dewey Ballantine LLP), May 4, 2006.

19
Factors Spurring Rising Construction Costs

Labor Costs
A significant component of utility construction costs is labor—both unskilled (common) labor as well as
craft labor such as pipefitters and electricians. Labor costs have also increased at rates higher than the
general inflation rate, although more steadily since 1997, and recent increases have been less dramatic than
for commodities. Figure 12 shows a composite national labor cost index based on simple averages of the
regional Handy-Whitman Index© for common and craft labor. Between January 2001 and January 2007, the
general inflation rate (measured by the GDP deflator) increased about 15 percent. During the same period,
the cost of craft labor and heavy construction labor increased about 26 percent, while common labor
increased 27 percent, or almost twice the rate of general inflation. 12 While less severe than commodity cost
increases, increased labor costs contributed to the overall construction cost increases because of their
substantial share in overall utility infrastructure construction costs.

Figure 12
National Average Labor Costs Index
Labor for Heavy Construction and Reinforced Concrete Common Labor Craft Labor GDP Deflator

180

170

160
Index (1991=100)

150

140

130

120

110

100
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Year
Sources: The Handy-Whitman© Bulletin, No. 165, and the U.S. Bureau of Economic Analysis.
Simple average of all regional labor cost indices for the specified types of labor.

Although labor costs have not risen dramatically in recent years, there is growing concern about an emerging
gap between demand and supply of skilled construction labor—especially if the anticipated boom in utility
construction materializes. In 2002, the Construction Users Roundtable (CURT), surveyed its members and
found that recruitment, education, and retention of craft workers continue to be critical issues for the
industry. 13 The average age of the current construction skilled workforce is rising rapidly, and high attrition
rates in construction are compounding the problem. The industry has always had high attrition at the entry-
level positions, but now many workers in the 35-40 year-old age group are leaving the industry for a variety
of reasons. The latest projections indicate that, because of attrition and anticipated growth, the construction

12
These figures represent a simple average of six regional indices, however, local and regional labor markets can vary
substantially from these national averages.
13
Confronting the Skilled Construction Workforce Shortage. The Construction Users Roundtable, WP-401, June 2004, p. 1.

20
 Rising Utility Construction Costs: Sources and Impacts

industry must recruit 200,000 to 250,000 new craft workers per year to meet future needs. However, both
demographics and a poor industry image are working against the construction industry as it tries to address
this need. 14

There also could be a growing gap between the demand and supply of electrical lineworkers who maintain
the electric grid and who perform much of the labor for transmission and distribution investments. These
workers erect poles and transmission towers and install or repair cables or wires used to carry electricity
from power plants to customers. According to a DOE report, demand for such workers is expected to
outpace supply over the next decade. 15 The DOE analysis indicates a significant forecasted shortage in the
availability of qualified candidates by as many as 10,000 lineworkers, or nearly 20 percent of the current
workforce. As of 2005, lineworkers earned a mean hourly wage of $25/hour, or $52,300 per year. The
forecast supply shortage will place upward pressure on the wages earned by lineworkers. 16

Shop and Fabrication Capacity

Many of the components of utility projects—including large components like turbines, condensers, and
transformers—are manufactured, often as special orders to coincide with particular construction projects.
Because many of these components are not held in large inventories, the overall capacity of their
manufacturers can influence the prices obtained and the length of time between order and delivery. The
price increases of major manufactured components were shown in Figure 11. While equipment and
component prices obviously reflect underlying material costs, some of the price increases of manufactured
components and the delivery lags are due to manufacturing capacity constraints that are not readily overcome
in the near term.

As shown in Figure 13 and Figure 14, recent orders have largely eliminated spare shop capacity, and
delivery times for major manufactured components have risen. These constraints are adding to price
increases and are difficult to overcome with imported components because of the lower value of the dollar in
recent years.

The increased delivery times can affect utility construction costs through completion delays that increase the
cost of financing a project. In general, utilities commit substantial funds during the construction phase of a
project that have to be financed either through debt or equity, called “allowance for fund used during
construction” (AFUDC). All else held equal, the longer the time from the initiation through completion of a
project, the higher is the financing costs of the investment and the ultimate costs passed through to
ratepayers.

14
Id., p. 1.
15
Workforce Trends in the Electric Utility Industry: A Report to the United States Congress Pursuant to Section 1101 of the
Energy Policy Act of 2005. U.S. Department of Energy, August 2006, p. xi.
16
Id., p. 5.

21
Factors Spurring Rising Construction Costs

Figure 13
Shop Capacity

2004 Shop Load Current Shop Load Anticipated 2006 Shop Load
1.4

1.2

0.8

0.6

0.4

0.2

ers tor
s
ger
s els mp
s es
ool ess al v
C Mo ch
an s/V Pu lV
Ai r Ex n tro
lu m C on
Co
Source: "Who, What, Where, How" presentation by John Siegel, Bechtel Power Corp. Delivered at the conference entitled Next
Generation of Generation (Dewey Ballantine LLP), May 4, 2006.

Figure 14
Delivery Schedules

2004 2005 2006

120

100

80
Weeks

60

40

20

ers P) ge r
s
mn
s els o rs rs NG
)
l ve
s
ool 0H an lu Ve
ss act sso Va
rC 50 ch Co Re re l. L ol
Ai s (> Ex mp xc
ntr
tor Co Co s (e
Mo mp
rge Pu
La
Source: "Who, What, Where, How" presentation by John Siegel, Bechtel Power Corp. Delivered at the conference entitled Next
Generation of Generation (Dewey Ballantine LLP), May 4, 2006.

22
 Rising Utility Construction Costs: Sources and Impacts

Engineering, Procurement and Construction (EPC) Market Conditions

Increased worldwide demand for new generating and other electric infrastructure projects, particularly in
China, has been cited as a significant reason for the recent escalation in the construction cost of new power
plants. This suggests that major Engineering, Procurement and Construction (EPC) firms should have a
growing backlog of utility infrastructure projects in the pipeline. While we were unable to obtain specific
information from the major EPC firms on their worldwide backlog of electric utility infrastructure projects
(i.e., the number of electric utility projects compared with other infrastructure projects such as roads, port
facilities and water infrastructure, in their respective pipelines), we examined their financial statements,
which specify the financial value associated with their backlog of infrastructure projects. Figure 15 shows
the cumulative annual financial value associated with the backlog of infrastructure projects at the following
four major EPC firms; Fluor Corporation, Bechtel Corporation, The Shaw Group Inc., and Tyco
International Ltd. Figure 15 shows that the annual backlog of infrastructure projects rose sharply between
2005 and 2006, from $4.1 billion to $5.6 billion, an increase of 37 percent. This significant increase in the
annual backlog of infrastructure projects at EPC firms is consistent with the data showing an increased
worldwide demand for infrastructure projects in general and also utility generation, transmission, and
distribution projects.

Figure 15
Annual Backlog at Major EPC Firms
65000

60000

55000
Amount (Millions of $)

50000

45000

40000

35000

30000

25000
2002 2003 2004 2005 2006
Year
Data are compiled from the Annual Reports of Fluor Corporation, Bechtel Corporation, The Shaw Group Inc., and Tyco
International Ltd. For Bechtel, the data represent new booked work, as backlog is not reported.

The growth in construction project backlogs likely will dampen the competitiveness of EPC bids for future
projects, at least until the EPC industry is able to expand capacity to manage and execute greater volumes of
projects. This observation does not imply that this market is generally uncompetitive—rather it reflects the
limited ability of EPC firms with near-term capacity constraints to service an upswing in new project
development associated with a boom period in infrastructure construction cycles. Such constraints,

23
Factors Spurring Rising Construction Costs

combined with a rapidly filling (or full) queue for project management services, limit incentives to bid
aggressively on new projects.

Although difficult to quantify, this lack of spare capacity in the EPC market will undoubtedly have an
upward price pressure on new bids for EPC services and contracts. A recent filing by Oklahoma Gas &
Electric Company (OG&E) seeking approval of the Red Rock plant (a 950 MW coal unit) provides a
demonstration of this effect. In January 2007, OG&E testimony indicated that their February 3, 2006, cost
estimate of nearly $1,700/kW had been revised to more than $1,900/kW by September 29, 2006, a 12-
percent increase in just nine months. More than half of the increase (6.6 percent) was ascribed to change in
market conditions which “reflect higher materials costs (steel and concrete), escalation in major equipment
costs, and a significant tightening of the market for EPC contractor services (as there are relatively few
qualified firms that serve the power plant development market).” 17 In the detailed cost table, OG&E
indicated that the estimate for EPC services had increased by more than 50 percent during the nine month
period (from $223/kW to $340/kW).

Summary Construction Cost Indices

Several sources publish summary construction cost indices that reflect composite costs for various
construction projects. Although changes in these indices depend on the actual cost weights assumed e.g.,
labor, materials, manufactured components, they provide useful summary measures for large infrastructure
project construction costs.

The RSMeans Construction Cost Index provides a general construction cost index, which reflects primarily
building construction (as opposed to utility projects). This index also reflects many of the same cost drivers
as large utility construction projects such as steel, cement and labor. Figure 16 shows the changes in the
RSMeans Construction Cost index since 1990 relative to the general inflation rate. While the index rose
slightly higher than the GDP deflator beginning in the mid 1990s, it shows a pronounced increase between
2003 and 2006 when it rose by 18 percent compared to the 9 percent increase in general inflation.

17
Testimony of Jesse B. Langston before the Corporation Commission of the State of Oklahoma, Cause No. PUD
200700012, January 17, 2007, page 27 and Exhibit JBL-9.

24
 Rising Utility Construction Costs: Sources and Impacts

Figure 16
RSMeans Historical Construction Cost Index

170

160

RSMeans Historical
150 Construction Cost Index
Index (1990 = 100)

140

130
GDP Deflator

120

110

100

90
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Year
Source: RSMeans, Heavy Construction Cost Data, 20th Annual Edition, 2006.

The Handy-Whitman Index© publishes detailed indices of utility construction costs for six regions, broken
down by detailed component costs in many cases. Figures 17 through 19 show the evolution of several of
the broad aggregate indices since 1991 compared with the general inflation index (GDP deflator). 18 The
index numbers displayed on the graphs are for January 1 of each year displayed.

Figure 17 displays two indices for generation costs: a weighted average of coal steam plant construction
costs (boilers, generators, piping, etc.) and a stand-alone cost index for gas combustion turbines.

As seen on Figure 17, steam generation construction costs tracked the general inflation rate fairly well
through the 1990s, began to rise modestly in 2001, and increased significantly since 2004. Between January
1, 2004, and January 1, 2007, the cost of constructing steam generating units increased by 25 percent—more
than triple the rate of inflation over the same time period. The cost of gas turbogenerators (combustion
turbines), on the other hand, actually fell between 2003 and 2005. However, during 2006, the cost of a new
combustion turbine increased by nearly 18 percent—roughly 10 times the rate of general inflation.

18
Used with permission. See Handy-Whitman© Bulletin, No. 165 for detailed data breakouts and regional values for six
regions: Pacific, Plateau, South Central, North Central, South Atlantic and North Atlantic. The Figures shown reflect
simple averages of the six regions.

25
Factors Spurring Rising Construction Costs

Figure 17
National Average Generation Cost Index
Total Plant-All Steam Generation Gas Turbogenerators GDP Deflator

180

170

160

150
Index (1991=100)

140

130

120

110

100

90
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Year
Sources: The Handy-Whitman© Bulletin, No. 165 and the U.S. Bureau of Economic Analysis.
Simple average of all regional construction and equipment cost indices for the specified components.

Figure 18 displays the increased cost of transmission investment, which reflects such items as towers, poles,
station equipment, conductors and conduit. The cost of transmission plant investments rose at about the rate
of inflation between 1991 and 2000, increased in 2001, and then showed an especially sharp increase
between 2004 and 2007, rising almost 30 percent or nearly four times the annual inflation rate over that
period.

Figure 18
National Average Transmission Cost Index
190

180

170

160
Index (1991=100)

Transmission Plant
150

140

130
GDP Deflator
120

110

100

90
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Year
Sources: The Handy-Whitman© Bulletin, No. 165, and the U.S. Bureau of Economic Analysis.
Simple average of all regional transmission cost indices.

26
 Rising Utility Construction Costs: Sources and Impacts

Figure 19 shows distribution plant costs, which include poles, conductors, conduit, transformers and meters.
Overall distribution plant costs tracked the general inflation rate very closely between 1991 and 2003.
However, it then increased 34 percent between January 2004 and January 2007, a rate that exceeded four
times the rate of general inflation.

Figure 19
National Average Distribution Cost Index
180

170

160
Distribution Plant
150
Index (1991=100)

140

130
GDP Deflator
120

110

100

90
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Year
Sources: The Handy-Whitman© Bulletin, No. 165, and the U.S. Bureau of Economic Analysis.
Simple average of all regional distribution cost indices.

Comparison with Energy Information Administration Power Plant Cost Estimates

Every year, EIA prepares a long-term forecast of energy prices, production, and consumption (for electricity
and the other major energy sectors), which is documented in the Annual Energy Outlook (AEO). A
companion publication, Assumptions to the Annual Energy Outlook, itemizes the assumptions (e.g., fuel
prices, economic growth, environmental regulation) underlying EIA’s annual long-term forecast. Included
in the latter document are estimates of the “overnight” capital cost of new generating units (i.e., the capital
cost exclusive of financing costs). These cost estimates influence the type of new generating capacity
projected to be built during the 25-year time horizon modeled in the AEO.

The EIA capital cost assumptions are generic estimates that do not take into account the site-specific
characteristics that can affect construction costs significantly. 19 While EIA’s estimates do not necessarily
provide an accurate estimate of the cost of building a power plant at a specific location, they should, in
theory, provide a good “ballpark” estimate of the relative construction cost of different generation

19
EIA does incorporate regional multipliers to reflect minor variations in construction costs based on labor conditions.

27
Factors Spurring Rising Construction Costs

technologies at any given time. In addition, since they are prepared annually, these estimates also should
provide insight into construction cost trends over time.

The EIA plant cost estimates are widely used by industry analysts, consultants, academics, and
policymakers. These numbers frequently are cited in regulatory proceedings, sometimes as a yardstick by
which to measure a utility’s projected or incurred capital costs for a generating plant. Given this, it is
important that EIA’s numbers provide a reasonable estimate of plant costs and incorporate both
technological and other market trends that significantly affect these costs.

We reviewed EIA’s estimate of overnight plant costs for the six-year period 2001 to 2006. Figure 20 shows
EIA’s estimates of the construction cost of six generation technologies—combined-cycle gas-fired plants,
combustion turbines (CTs), pulverized coal, nuclear, IGCC, and wind—over the period 2001 to 2006 and
compares these projections to the general inflation rate (GDP deflator). These six technologies, generally
speaking, have been the ones most commonly built or given serious consideration in utility resource plans
over the last few years. Thus, we can compare the data and case studies discussed above to EIA’s cost
estimates.

Figure 20
EIA Generation Construction Cost Estimates

Conventional Coal Conventional CC Conventional CT Wind Advanced Nuclear

IGCC Wind Advanced Nuclear Conventional CT GDP Deflator
135

130

125

120
Index (2001=100)

115 GDP
Deflator
110

105

100

95

90

85
2001 2002 2003 2004 2005 2006
Year
Sources: Data collected from the Energy Information Administration, Assumptions to the Annual Energy Outlook 2002 to 2007 and
from the U.S. Bureau of Economic Analysis.

The general pattern in Figure 20 shows a dramatic change in several technology costs between 2001 and
2004 followed by a stable period of growth until 2006. The two exceptions to this are conventional coal and
IGCC, which increase by a near constant rate each year close to the rate of inflation throughout the period.
The data show conventional CC and conventional CT experiencing a sharp increase between 2001 and 2002.
After this increase, conventional CC levels off and proceeds to increase at a pace near inflation, while
conventional CT actually drops significantly before 2004 when it too levels near the rate of inflation. The

28
 Rising Utility Construction Costs: Sources and Impacts

pattern seen with nuclear technology is near to the opposite. It falls dramatically until about 2003 and then
increases at the same rate as the GDP deflator. Lastly, wind moves close to inflation until 2004 when it
experiences a one-time jump and then flattens off through 2006.

These patterns of cost estimates over time contradict the data and findings of this report. Almost every other
generation construction cost element has shown price changes at or near the rate of inflation throughout the
early part of this decade with a dramatic change in only the last few years. EIA appears to have reconsidered
several technology cost estimates (or revised the benchmark technology type) in isolation between 2001 and
2004, without a systematic update of others. Meanwhile, during the period that overall construction costs
were rising well above the general inflation rate, EIA has not revised its estimated capital cost figures to
reflect this trend.

EIA’s estimates of plant costs do not adequately reflect the recent increase in plant construction costs that
has occurred in the last few years. Indeed, EIA itself acknowledges that its estimated construction costs do
not reflect short-term changes in the price of commodities such as steel, cement and concrete. 20 While one
would expect some lag in the EIA data, it is troubling that its most recent estimates continue to show the
construction cost of conventional power plants increasing only at the general rate of inflation. Empirical
evidence shows that the construction cost of generating plants—both fossil-fired and renewable—is
escalating at a rate well above the GDP deflator. Even the most recent EIA data fail to reflect important
market impacts that are driving plant construction costs, and thus do not provide a reliable measure of current
or expected construction costs.

20
Annual Energy Outlook 2007, U.S. Energy Information Administration, p. 36.

29
 Conclusion
Construction costs for electric utility investments have risen sharply over the past several years, due to
factors beyond the industry’s control. Increased prices for material and manufactured components, rising
wages, and a tighter market for construction project management services have contributed to an across-the-
board increase in the costs of investing in utility infrastructure. These higher costs show no immediate signs
of abating.

Despite these higher costs, utilities will continue to invest in baseload generation, environmental controls,
transmission projects and distribution system expansion. However, rising construction costs will put
additional upward pressure on retail rates over time, and may alter the pace and composition of investments
going forward. The overall impact on the industry and on customers, however, will be borne out in various
ways, depending on how utilities, markets and regulators respond to these cost increases. In the long run,
customers ultimately will pay for higher construction costs—either directly in rates for completed assets of
regulated companies, less directly in the form of higher energy prices needed to attract new generating
capacity in organized markets and in higher transmission tariffs, or indirectly when rising construction costs
defer investments and delay expected benefits such as enhanced reliability and lower, more stable long-term
electricity prices.

31