20080403DeFelice Direct.pdf

1!¡t:D.4..._ .DAVID J. MEYER
VICE PRESIDENT, GENERAL COUNSEL,
GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
REGULATORY &"ntl''!'Ut, ~ f'D')u 1'1 i\ _ ')v Pf1 /: 116
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AN CHARGES FOR ELECTRIC AN
NATURA GAS SERVICE TO ELECTRIC
AND NATURL GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-08-01
CASE NO. AVU-G-08-01
DIRECT TESTIMONY
OF
DAVE B. DEFELICE
FOR AVISTA CORPORATION
(ELECTRIC AND NATUR GAS)
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I. INTRODUCTION
Q.Please state your name, employer and business
3 address.
4 A.My name is Dave B. DeFelice.I am employed by
5 Avista Corporation as a Senior Business Analyst.My
6 business address is 1411 East Mission, Spokane, washington.
7 Q.Please briefly describe your education backgroun
8 and professional experience.
9 A.I graduated from Eastern Washington University in
10 June of 1983 with a Bachelor of Arts Degree in Business
11 Administration majoring in Accounting.I have served in
12 various positions within the Company, including Analyst
13 positions in the Finance Department (Rates section and
14 Plant Accounting) and in Marketing/Operations Departments,
15 as well.In 1999, I accepted the Senior Business Analyst
16 posi tion that focuses on economic analysis of various
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project proposals as well as evaluations and
recommendations pertaining to' business policies and
19 practices.
20 Q.As a Senior Business Anlyst, what are your
21 responsibilities?
22 A.As a Senior Business Analyst I am involved in
23 activities ranging from financial analysis of numerous
24 proj ects with various departments such as Engineering,
25 Operations, Marketing/Sales and Finance.Also, a portion
DeFelice, Di 1
Avista Corporation
1 of my job tasks involve advisory and informal training of
2 employees pertaining to regulatory finance and ratemaking
3 concepts.
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Q.What is the scope of your testimony?
A.My testimony and exhibits in this proceeding will
6 cover the Company's proposed regulatory treatment of
7 capital investments in utility plant through 2008.
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Q.Are you sponsoring any exhibits?
A.Yes.I am sponsoring Exhibit No. 11, Schedule 1
10 ("Rising Utility Construction Costs: Sources and Impacts"
11 study from The Brattle Group),Schedule 2 (Capital
12 Expenditures) , and Schedule 3 (2008 Capital Additions
13 Detail), which were prepared under my direction.
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II. CAPITAL INVSTMNT RECOVERY
Q.What does the Company's request for rate relief
17 include regarding new investment in utility plant to serve
18 customers?
19 A.In this filing, we are proposing to include in
20 retail rates the costs associated with utility plant that
21 is in-service, and will be used to provide energy service
22 to our customers during the 2009 pro forma rate year. This
23 is consistent with prior ratemaking practice in the State
24 of Idaho.
DeFelice, Di 2
Avista Corporation
1 The utility plant investment that we have included in
2 this filing represents utility plant that will be "used and
3 useful" in providing service to customers during the
4 approximate period that new retail rates from this filing
5 will be in effect.The costs associated with the
6 investment will be "known and measurable," and finally,
7 including the costs associated with this investment in
8 retail rates provides a proper "matching" of revenues from
9 customers, with the costs associated with providing service
10 to customers (including the cost of utility plant to serve
11 cus tomers) .
12 In the IPUC's Order No. 29602, in Case Nos. AVU-E-04-1
13 and AVU-G-04-1, dated October 8, 2004, the Commission
14 stated, at page 10, that:
15 "Once a test year is selected, adjustments are16 made to test year accounts and rate base to
17 reflect known and measurable changes so that test18 year totals accurately reflect anticipated19 amounts for the future period when rates will be
20 in effect. The Idaho Supreme Court has described21 "rate base" as "the utility's capital investment22 amount." Industrial Customers of Idaho Power v.
23 Idaho PUC 134 Idaho 285, 291, 1 P. 3d 786, 79224 (2000) . Adjustments to test year accounts25 generally fall into three categories: 1)
26 normalizing adjustments made for unusual27 occurrences, like one-time events or extreme28 weather conditions, so they do not unduly affect
29 the test year i 2) annualizing adjustments made30 for events that occurred at some point in the31 test year to average their effect as if they had32 been in existence during the entire year ¡and 3)
33 known and measurable adjustments made to include34 events that occur outside the test year but will35 continue in the future to affect Company income36 and expenses."
DeFelice, Di 3
Avista Corporation
1 If utility plant investment that is being used to
2 serve customers is not reflected in retail rates then the
3 retail rates will not be "just,reasonable,and
4 sufficient," i.e., it would not be just or reasonable for
5 customers to receive the benefit provided by the utility
6 investment without paying for it, and the retail rates
7 would not provide revenues "sufficient" to provide recovery
8 of the costs associated with providing service to
9 customers.
10 Q.Is the Company' s application of these ratemking
11 principles in this filing consistent with prior general
12 rate cases?
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A.Yes.In prior cases, the obj ecti ve has been the
same to include in retail rates the investment, or rate
15 base, that is providing service to customers, and ensure
16 that there is a proper matching of revenues and expenses
17 during the period that rates are in effect.
18 Q.How does new investment in utility plant change
19 rate base over time for ratemking purposes?
20 A.Historically, the annual dollars spent by the
21 Company on new utility plant has generally been relatively
22 close to the level of depreciation expense, with the
23 exception of years where the Company has invested in major
DeFel ice, Di 4
Avista Corporation
1 new utility . iproJects.I will use an example to
2 illustrate, in general terms, how new investment in utility
3 plant changes rate base over time.Let's assume that the
4 Company's rate base (adjusted net plant in service used to
5 serve customers) at the beginning of Year 1 is $1.5
6 billion.Also assume that depreciation expense in Year 1
7 is $80 million, and the Company's new investment in utility
8 plant in Year 1 is also $80 million.During Year 1, rate
9 base increased by $80 million (new investment), and
10 decreased by $80 million (depreciation), and ended up at
11 the same level of $1.5 billion at the end of the year. In
12 this simplified example, the Company i s rate base is $1.5
13 billion, both at the beginning of Year 1, and at the end of
14 Year 1. For ratemaking purposes, the $1.5 billion of rate
15 base is representative of the level of plant investment
16 used to serve customers, both at the beginning of the year
17 and at the end 0 f the year.Over time, if depreciation
18 expense continues to be approximately equal to new plant
19 investment, rate base would continue at a relatively
20 constant $1.5 billion. Under these circumstances, the use
21 of the $1.5 billion rate base amount from a prior year,
22 i. e., a historical test year, would be adequate for setting
23 rates for the upcoming year (pro forma rate year), because
i Recognzing that a porton of the costs associated with capita additions are offet by additional
revenues.
DeFelice, Di 5
Avista Corporation
1 there is little change in the net plant investment used to
2 serve customers.
3 In a similar manner, in prior general rate cases we
4 have used a rate base amount from a historical test year as
5 the starting point for the pro forma rate year.If there
6 were no major plant additions between the historical test
7 year and the upcoming pro forma rate year, the historical
8 test year rate base amount would be used for the pro forma
9 rate year as being representative of the net plant used to
10 serve customers. If there were known major plant additions
11 that would be in service for the pro forma rate year, such
12 as the recent addition of Coyote Springs II for Avista, the
13 major transmission upgrades,and the hydroelectric
14 upgrades, then rate base for the pro forma rate year is
15 adjusted for these major investments, so that rate base for
16 the pro forma rate year is representative of the level of
17 investment used to serve customers.
18 Q.Is Avista' s new investment in utility plant
19 exceeding its annual depreciation expense, causing an
20 increase in rate base?
21 A.Yes.Avista's investment in plant in 2007 and
22 2008, is well above the annual depreciation expense, and
23 will result in an increase in net plant in service (rate
24 base) that will be used to serve customers in the 2009 pro
25 forma rate year. Much of this new investment in plant for
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Avista Corporation
1 2007 and 2008 is spread among many different utility plant
2 categories, as opposed to a few major plant additions.
3 Therefore, the Company's pro forma adjustment for new
4 investment in plant in this filing involves a more detailed
5 analysis of the net change in rate base from the historical
6 test period to the pro forma rate year.The end resul t ,
7 however, is the same in this case as in prior cases - to
8 reflect in retail rates the level of net plant investment
9 that is used to serve customers during the pro forma rate
10 year, and to have a proper matching of revenues and
11 expens es .
12 Q.How was rate base for the pro form rate year
13 developed for this filing?
14 A.As in prior rate cases, Avista started with rate
15 base for the historical test year, which for this case is
16 the calendar year 2007.Adjustments were made to reflect
17 new additions and accumulated depreciation through December
18 2008, such that the proposed rate base reflects the net
19 plant in service that will be used to serve customers
20 during the 2009 pro forma rate year. Later in my testimony
21 i will provide the details of the adjustments to rate base.
22 Although there is a strong case to be made that the
23 new capital investment in 2009 will be used to serve
24 customers during the 2009 rate year, and should be
DeFelice, Di 7
Avista Corporation
1 reflected in this case, the Company has only included new
2 investment through Decemer 2008.
3 The capital additions through 2008 will be in-service
4 at the approximate time new rates become effective from
5 this rate filing, and customers will be receiving benefits
6 from this investment. The following chart illustrates the
7 2007 historical test period and the April 2008 filing of
8 this case.The chart also illustrates that the capital
9 additions for 2007 and 2008 will be completed and in
10 service prior to January 1, 2009.During 2009 customers
11 will receive the benefit from the full investment in 2007
12 and 2008, and it is appropriate for this investment to be
13 reflected in the retail rates for 2009.
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15 Illustration 1
16 Capital Additions 2007 - 2009Avista Utilties
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12/3112009~.- .-._.-. .._.. ._._.-.-. .I I. .I I. .I I. .I I
. _. l1'~Q!._._. _. _'_' _. _ .-!
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I.--- .-._._.--_._-_._._. ~
I
2007
Historical Test Year
2008 2009
Filing Date:
Apr.20oa
DeFelice, Di 8
Avista Corporation
1 As illustrated by the chart, if the proposed rates in
2 this case go into effect near the end of 2008, the 2007
3 plant additions will be entering their third year of
4 service during calendar year 2009, . and the 2008 capital
5 additions will be in their second year of service in 2009.
6 Clearly the 2007 and 2008 investment will be providing
7 service to customers, and would reflect the true cost of
8 funding assets that are necessary, and used and useful, to
9 provide service to customers during the year that new rates
10 will be in effect.It would result in a mismatch of
11 revenues and expense during 2009 if the costs associated
12 with these investments are not reflected in new retail
13 rates.
14 Q.You stated earlier that new utility investment in
15 2007 and 2008 will be substantially higher than the annual
16 depreciation expense.What is driving the significant
17 investment in new utility plant?
18 A.The Company is currently being required to add
19 significant new transmission and distribution facilities,
20 including strengthening the "back bone" of our system, due
21 in part to customer growth in our service area, reliability
requirements, and capacity upgrades.Other issues driving22
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the need for capital investment include an aging
infrastructure,physical degradation,and municipal
25 compliance issues (i.e., street/highway relocations), etc.
DeFelice, Di 9
Avista Corporation
1 While the overall economy is slowing on a national basis,
2 Kootenai County is still growing.In 2007, employment
3 growth in Kootenai County ranked in the top 5% of all
4 metropoli tan areas.
5 In addition, the cost of raw materials, including
6 concrete, steel, copper, aluminum and other materials, have
7 sky-rocketed in recent years, causing the cost of these new
8 facilities to be significantly higher than in the past.
9 Because the cost of adding new facilities is significantly
10 higher than the existing facilities, the investment in new
11 facilities will be significantly higher than the annual
12 depreciation expense on the existing facilities.
13 Q.What is causing the substantial increase in raw
14 materials for Avista, and the utility industry in general?
15 A.In September 2007,The Edison Foundation
16 commissioned a study from The Brattle Group titled, "Rising
17 Utility Construction Costs: Sources and Impacts," which
18 identified cost trends specifically related to the utility
19 industry pertaining to critical materials and equipment, as
20 well as labor support services used for building capital
21 infrastructure. This study is attached as Exhibit No. 11,
22 Schedule 1.The study identifies the reasons for drastic
23 cost increases in critical raw materials, such as global
24 competition and an aging domestic utility infrastructure as
DeFelice, Di 10
Avista Corporation
1 well as the need for additional infrastructure to
2 accommodate growth in the near future.
3 Q.What are some of the key cost drivers that are
4 ci ted in the study?
5 A.The study, at page 16, cites four major cost
6 drivers," (1) material input costs, including the cost of
7 raw physical inputs, such as steel and cement as well as
8 increased costs of components manufactured from these
9 inputs (e.g., transformers, turbines, pumps) i (2) shop and
10 fabrication capacity for manufactured components (relative
11 to current demand) i (3) the cost of construction field
12 labor, both unskilled and craft labor ¡and (4) the market
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for large construction project management,i.e. ,the
queuing and bidding for projects."The study goes on to
15 compare cost trends for various raw materials, critical
16 equipment and labor services relative to the general
17 inflation rate (GDP deflator).In addition, a cost trend
18 is sumarized by three key utility functional plant
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categories,including generation,transmission,and
distribution plant.The study concludes that these
21 inflation impacts have been outside the utility industry's
22 control and there are no immediate indications of cost
23 relief in the near future.
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25
Illustration 2 below depicts what has occurred to
infrastructure costs nationally.From the chart, it is
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Avista Corporation
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1 apparent that starting in 2003, costs of distribution,
2 transmission and generation infrastructure increased at a
3 far more significant rate than the overall economy, as
measured by the GDP deflator.
Illustration 2
Natonal Aleraie Utilit Infasucture Cost Ind
-Tól Pl.AllSt Geiar
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-- DeI-o~"'Ti$I -Di*iblar
180 - -- - - -- -- -- - - - -- -- - -- - - --- - ----.-- -- - -- -_.-.-- ~- -------
uo
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.!:: l.ie
¡13O
iS
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90
191 lØ 193 19 199 U9 191 19 im 20 201 200 ~ 2Ø 20 2G 207
Yar
s...: Th. H..cI.Wb\l..O BiilOl No. 165 ID tbe u.s. Bue.. of EcOlomc Ål,si..Si1e a..... of OIL reoi COIItOl ad
eqiJlcos ia.. ror the sped .-eaL .ll.. U1ilil) Co.ir1iOl C_: s... ..d I'to Prd b, Tho Bta. c:.. rorThell.OI Fouacl.. Septber 20
Q.Is there specific evidence that Avista is
21 experiencing cost escalations s~ilar to that indicated in
22 the study?
23 A.Yes. A sample was compiled of some materials and
24 equipment that Avista routinely uses in order to support
25 various infrastructure construction efforts that are part
DeFelice, Di 12
Avista Corporation
1 of the Company's annual capital requirements of purchases
2 made from 2003 through 2008.The sample of materials was
3 grouped into categories for typical electric and gas
4 distribution capital projects as well as major electric
5 substation proj ects. The cost sumary indicated that the
6 cost of the materials reviewed has risen sharply in most
7 categories from 2003 to 2008.For the distribution group
8 of materials, the average annual escalation impact from
9 2003 through 2007 is approximately 37%, which is equal to a
10 cumulative increase over the four-year period of 178%. The
11 escalation for the substation group of materials and
12 equipment has been approximately 12% per year for the
13 purchases Avista has made from 2003 to 2008, or a
14 cumulative increase of 55%.
15 Q.What is the historical and projected level of
16 annual capital spending for Avista?
17 A.Avista's capital requirements have steadily
18 increased from approximately $100 million to $200 million
19 over the last several years.Exhibit No. 11, Schedule 2
20 reflects this trend that Avista has experienced and what is
21 planned for in the near future.This clearly shows that
22 the amount of capital proj ects is well in excess of
23 revenue-supported capital expenditures to connect new
24 customers, and beyond the level of revenues that is being
25 collected from customers related to existing plant.The
DeFelice, Di 13
Avista Corporation
1 difference between the total capital requirements, less the
2 new revenue related capital, and allowed revenues represent
3 a significant discrepancy that is negatively impacting the
4 Company.
5 Q.What is the likelihood that Avista's capital
6 investment will continue at this level?
7 A.There are many factors that will influence
8 capital expenditures going forward. One factor is the cost
9 of raw materials is expected to continue to inflate over
10 time and the fact that there is more demand for capital
11 proj ects for such things as compliance work with municipal
12 highway and road proj ects, sewer proj ects, etc.Also, as
13 critical systems age, there will be more utility plant that
14 will be reaching the end of physical life and, in some
15 cases, plant may be replaced prior to the end of its
16 physical life based on power efficiency improvements that
17 can be recognized.
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III. DESCRIPTION OF CAPITAL PROJECTS
Q.For the 2008 capital projects pro for.ed in this
21 filing, please provide a description of the projects.
22 A.Exhibit No. 11, Schedule 3 details the capital
23 projects that will be transferred to plant in service in
24 2008 and included in this filing.A short description of
25 these proj ects follows:
DeFelice, Di 14
Avista Corporation
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Generation:
Thermal - Colstrip Capital Additions - $3,424,000
There will be a planned outage on Unit #4 so the
Company can install NOX (pollution control equipment)
to be in compliance with state and federal mandates.
Further, there will be a replacement of a cooling
tower.
Thermal - Kettle Falls Capital Projects - $1,131,000
The primary project at the Kettle Falls Generating
Station is the re-roofing of the power house. Other
smaller proj ects include: replacement of wood screw
conveyors which feeds wood into the hopper,
replacement of electronic recip. controllers, and
replacement of the 4160 protective relays.
Thermal - Other Small Proj ects - $130,000
Please refer to the workpapers of Mr. DeFelice for
detailed listing of projects.
Hydro Cabinet Gorge Bypass Tunnel Proj ect
$5,353,000
Feasibility study pertaining to the Company's FERC
mandated license obligation regarding gas super-
saturation issues within the Clark Fork River License
Agreement for the Cabinet Gorge Dam. This study will
be completed in August 2008. Company witness Mr.
Vermillion discusses this study further in histestimony.
Hydro Clark Fork Implement PME Agreement
$2,243,000
Over twenty projects are planned for 2008 as part of
the protection, mitigation and enhancement (PME) plan.
These proj ects were agreed to as part of the
settlement agreement and FERC license received in
2001.
Hydro - Noxon Capital Projects - $1,628,000Proj ects include finishing the replacement of the
stator frame, stator core, and stator windings on unit#5. Further, after spring runoff, the #1 turbine will
be upgraded, including a complete mechanical overhaul,
upgraded high efficiency turbine, stator core ands ta tor winding.
DeFelice, Di 15
Avista Corporation
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Hydro - Other Small Proj ects - $1,461,000The primary other small project involves the
replacement of the duct bank that runs from the Post
Street Substation to the Upper Falls Generating
Facili ty. Further, the 80 year old cables which have
had two recent failures will be replaced. Please
refer to the workpapers of Mr. DeFelice for detailed
listing of proj ects.
Coyote Springs 2 (CS2) Joint Share Projects
$2,200,000
The primary Joint Share proj ect is the hot gas path
overhaul. This includes the replacement of the 1ststage rotating and stationary blades and 1st stage
nozzles. This work is part of the long term service
agreement with General Electric.
Coyote Springs 2 (CS2) Capital Proj ects -
The primary proj ect is the replacement of
on the heat recovery steam generator,
result in more generation output from the
$1,400,000
duct burnerswhich willturbine.
Other Small Proj ects - $807,000
The control system at the Northeast Combustion Turbine
will be upgraded for standby reserve. Further, the
failed Mark 5 controller and low voltage bus duct
between the step transformer and the generator breaker
will be replaced, as they failed in 2007.
Electric Transmission:
West Plains Transmission Reinforcement Project
$1,993,000
This item includes constructing 4.7 miles of 115 kV
transmission lines from the Airway Heights substation
to the existing South Fairchild tap west of Spokane.
The line is required to reduce thermal loading on area
transmission lines and is the first phase of a multi-
phase proj ect .
Power Transformer - Transmission - $1,595,000
The primary project in this category is the purchase
and installation of a new 230/115 kV auto-transformer
at the Benewah Substation. The existing auto-
transformer has reached its end of life.
DeFelice, Di 16
Avista Corporation
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Spokane/Coeur d i Alene 115 kW Line Relay upgrades
$1,247,000
Improvements to the Spokane-Coeur d' Alene area 115 kV
line protection schemes are required in order to
improve system reliability. This proj ect includes the
installation of high speed communications between area
substations and the replacement of protective relays
for improved fault clearing.
Nez Perce 115 kV Sub-Inst Capacitor Bank - $751,000
This project involves the installation of a 15 MVAR
capacitor bank at the Nez Perce substation and the
installation of a 15 MVAR capacitor bank at the
Grangeville substation. These capacitor banks are
needed to provide area voltage support during peak
load conditions.
Beacon 230 Bus Convert to DB-DB - $750,000
This project will add a sectionalizing breaker at the
Beacon 230 kV substation to meet national reliability
compliance standards. Currently there is a 230 kV bus
tie breaker, which could be a single point of failure
for the entire substation.
Lolo 230 - Rebuild 230 kV Yard - $737,000
As a result of the 5- Year Transmission Upgrade
Project, fault duties at the Lolo substation have
increased. The substation is being rebuilt to meet
Company operating standards.
Transmission Air Switch Ground Mat - $697,000
This safety project involves the installation of above
ground switch platforms to all 115 kV line air
swi tches . The platforms will allow company personnel
to operate switches safely.
Other Small Proj ects - $4,316,000
Please refer to the workpapers of Mr. DeFelice for
detailed listing of projects.
Electric Distribution:
Electric Distribution Minor Blanket Proj ects
$5,800,000
Replace crossarms and poles on distribution lines as
required, due to storm damage, fires, or obsolescence.
DeFel ice, Di 17
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Wood Pole Mgmt Capital - $4,923,000
The distribution wood-pole management program is the
strength evaluation of a certain percentage of the
pole population each year. Depending on the test
results for a given pole, that pole is either
considered satisfactory, reinforced with a steel stub,
or replaced.
Electric Underground Replacement - $3,000,000Replace high and low vol tage underground cable asrequired.
T&D Line Replacement - $2,250,000
Relocation of transmission and distribution lines asrequired.
Power Transformer - Distribution - $1,755,000
Installation of distribution power transformers asrequired.
Failed Electric Plant - $1,750,000
Installation of distribution plant for failed plant asrequired.
Distribution Reliability and Energy Efficiency Program
(DREEP) - $1,500,000
This new process at Avista analyzes many aspects of
the distribution system, including distribution feederlengths, optimum amperage levels, phase balancing,
conservation voltage reduction, etc. , in order to
evaluate how the system can be made more efficient.
Plumer - Increase Capacity/Rebuild - $1,425,000
This proj ect is required to replace the existing
deteriorated wood substation, and increase transformer
capacity to meet system demand during all operatingconditions.
C & W Kendall Project - $3,050,000
This project involves the relocation and replacement
of transmission and distribution facilities for the
Kendall Yards project in Downtown Spokane from the
Post Street substation to the College and Walnutsubstation.
DeFelice, Di 18
Avista Corporation
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Indian Trail 115-13kV Sub-Construct New Sub
$2,275,000
This project involves the construction of a new 115-13
kV substation in the Indian Trail area to meet
capacity demands in northwestern Spokane. This will
be a 20 MVA, 2 feeder (13 kV) substation.
Critchfield 115 Sub-Construct - $1,614,000
This project involves the construction of a new South
Clarkston 115-13 kV substation (20 MVA transformer and
2 feeders) to reduce loading on other area
transformers, which are reaching full capacity.
Spokane Electric Network Incr Capacity - $1,445,000
These proj ects are associated with the DowntownSpokane electric network. The proj ects involve the
installation of vaults, cables, network transformers
and protectors as required to serve new networkcustomers, and to maintain service to existingcustomers by replacing overloaded and deteriorated
equipment.
WSDOT Highway Franchise Consolidation - $800,000
In order to operate our electric system within State
highway rights of way, the Company needs to establish
new Franchises. Existing franchises have expired and
Avista must seek new agreements with the State or riskpenal ties or non -approval by the State.
Other Small Projects - $4,737,000
Please refer to the workpapers of Mr. DeFelice for
detailed listing of projects.
General:
Computer/Network Hardware/Software - $9,225,000
Proj ects for replacement of obsolete technology
according to Avista' s refresh cycles that are
generally driven by hardware/software manufacturer and
industry trends. Further investment includes hardware
and software investments that address capacity and
performance constraints due to technology consumption
and growth. Finally, the Company will have technologyinvestments that support business ini tiati ves
generally relating to back-office automation,
reliability/safety/compliance for electric and gas
infrastructure, and systems that service the Customer.
DeFelice, Di 19
Avista Corporation
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HVAC Renovation Project - $4,990,000
The heating, ventilating, and air conditioning systemsthroughout the Spokane Central Operating Facilities
are approximately fifty years old and are in need ofreplacement. The project involves replacing central
air handling units and distribution systems in three
buildings - the Spokane Service Center, the general
office building, and the cafeteria audi torium
building. The building envelope of the general office
building will also be renovated with high efficiency
glass and insulation. New controls will also be
installed which will enable energy conservation.
Backup Control Center - $1,911,000
This project involves creating a redundant controlcenter to meet NERC reliability standard for
transmission and operations groups.
Tools Lab and Shop Equipment - $1,200,000
This request is for general replacement and additionsrequired for capi tal proj ects .
Structures and Improvements - $1,174,000
This is a group of capital maintenance projects that
Facilities Management coordinates at the Spokane
Central Operating Facilities and Avista branch
facilities - offices and service centers. For 2008,
some of the projects includei paving employee parking
at Coeur d' Alene, constructing a vehicle storage
building at Pullman Service Center, remodel the
Spokane Meter Shop, new carpet on General Office 4th
floor, remodel of the Cafeteria/ Audi torium building,
and multiple small capital maintenance projects acrossAvista's service territory.
Other Small Proj ects - $4,205,000
These proj ects include communication and security
initiatives, radio equipment, SCADA controls,
telephone systems, office and other general facilityupgrades.
Transportation:
Transportation Equipment - $5,985,000
Capi tal additions in transportation
purchase of new fleet vehicles and heavy
on-road and off-road applications.
include theequipment for
DeFelice, Di 20
Avista Corporation
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Gas Distribution:
Gas Non-Revenue Blanket - $2,297,000
This annual proj ect will replace sections of existing
gas piping that require replacement to improve theoperation of the gas system but are not directly
linked to new revenue. The proj ect includes relocation
of main related to overbuilds, improvement in
equipment and/or technology to improve system
operation and/or maintenance, replacement of obsolete
facili ties, replacement of main to improve cathodic
performance, and projects to improve public safety
and/or improve system reliability.
Gas Replacement Street and Highways - $2,060,000
This annual project will replace sections of existing
gas piping that require replacement due to relocation
or improvement of streets or highways in areas where
gas piping is installed. Avista installs many of its
facilities in public right-of-way under established
franchise agreements. Avista is required under the
franchise agreements, in most cases, to relocate its
facilities when they are in conflict with road orhighway improvements.
Replace Deteriorated pipe - $1,339,000
This annual proj ect will replace sections of existing
gas piping that is suspect for failure or hasdeteriorated within the gas system. This project will
address the replacement of sections of gas main thatno longer operate with reliability and/or safety.
Sections of the gas system require replacement due tomany factors including material failures,
environmental impact, increase leak frequency, orcoating problems. This proj ect will identify and
replace sections of main to improve public safety and
system reliability.
Reinforce Gate Station Post Falls, ID - $1,500,000
This proj ect will build a larger Gate Station at the
existing Post Fall, ID Tap. New metering, regulation,
and a line heater will be installed. Due to system
growth, demand for gas in the Post Falls area has
exceeded the capacity of the current Gate Station.
The existing facilities are inadequate during high
system demand. Rebuilding the gate station will
insure continued reliable operation of the gatestation facilities.
DeFelice, Di 21
Avista Corporation
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East Medford /Roseburg /Sutherlin HP Reinforcement
Projects - $10,020,000
These Oregon gas distribution projects are not
included in this filng.
Kettle Falls Relocation/Gate - $1,300,000
This multi-'phased project will install a new gate
station on the west side of Spokane to serve the
existing HP distribution and future replacement pipe
that is part of the Kettle Falls HP main. The
existing Kettle Falls Gate Station and high pressure
(HP) Kettle Falls main has experienced significant
encroachment due to growth in the north Spokane area.
Sections of the main will be relocated to ensure
continued safe reliable operation of the pipe system.
The new gate station will improve the safety and
reliability of operating the high pressure main and
improve the gate station delivery capacity into the
Kettle Falls HP system. Future phases of this project
will re-route sections of the existing HP Kettle Falls
main to improve system capacity and public safety.
Qualchan Reinforcement - $1,200,000
This project will reinforce the southeast Spokane area
west of Hwy 195 by looping the existing distributionsystem. The southeast Spokane distribution system
experiences low pressures during high system demand in
the winter. The area fails the gas planning model for
a design day. Growth in the area has reduced Avista' sabili ty to reliably serve gas from its existing
distribution system during a design day. This project
will improve delivery pressure and position the system
for future growth.
Other Small Proj ects - $4,981,000
Please refer to the workpapers of Mr. DeFelice for
detailed listing of proj ects.
Jackson Prairie Storage:
Jackson Prairie Storage Proj ect - $18,056,000
Avista and its partners started an expansion project
at Jackson Prairie for deliverability that will be in
service in the Fall of 2008. Mr. Vermillion describes
this project in his testimony in this case.
DeFelice, Di 22Avis ta Corporation
1
2
iV. ADJUSTMNT METHODOLOGY
Q.What was the general approach to computing the
3 pro form adjustments for investment in capital projects?
4 A.The Company chose to track the 2007 and 2008
5 capital investments separately to simplify the computation
6 and to make it easier to follow. For each vintage, capital
7 additions, depreciation and DFIT were computed to derive
8 rate base at December 31, 2007 and December 31, 2008 and to
9 compute operating expenses in the pro forma rate year.
10 Q.What reports or data were used in the
11 computation?
12 A.The Company maintains results of operations
13 reports that are prepared for each service and jurisdiction
14 on an average of monthly averages (AM) basis and on an end
15 of period (EOP) basis that were used in this computation.
16 Actual 2007 plant additions were used from the plant
17 accounting system to determine the month of addition and
18 the amount of additions that were for revenue producing
19 projects.Capital additions for 2008 (described above)
20 were based on specific capital requirements for 2008.
21 Capital additions for 2008 that were for revenue producing
22 projects were separated out and excluded. The Company did
23 not include any 2009 capital additions in this filing..
24 Q.Are the computations for all services and
25 jurisdictions the same?
DeFelice, Di 23
Avista Corporation
1 A.Yes, they are.Because of this, only the Idaho
2 electric data will be used below to describe the
3 methodology for computing the adjustments. The adjustments
4 for Idaho gas were computed in a similar manner.
5 Q.Please exlain in detail the computation of the
6 adjustment as it relates to rate base.
7 A.There are three steps to determine the rate base
8 adjustment at December 31, 2007 and December 31, 2008, as
9 follows:
10 Step 1 - Adjust AH 2007 to EOP Decemer 31, 2007
11 (Pro For. Capital Additions 2007 Adjustment)
12 The first step was to determine an adjusted Decemer
13 31, 2007 EOP net plant balance that includes only the AM
14 revenue producing capital. The Company's Decemer 31, 2007
15 EOP results of operations reports was the starting point.
16 The gross plant at Decemer 31, 2007 at EOP includes
17 all revenue producing capital added in 2007.It is
18 necessary to remove only the average of monthly averages of
19 those addi tions ,since 2007 test year includes AM
20 customers and revenue (this is explained further below).
21 To accomplish this, all revenue producing capital additions
22 were deducted from the EOP balance and then the AM
23 additions were added back. The EOP gross plant at December
24 31, 2007 was computed as follows:
25
DeFelice, Di 24
Avista Corporation
EOP Gross Plant at 12/31/07 per Results of Operations
Less: EOP 2007 Revenue Producing Capital Additions
($OOO's)
$912,978
($9,637)
Add: AMA 2007 Revenue Producing Capital Additions $4.138
EOP Adjusted Gross Plant at 12/31/07 $907.479
1
2 The pro forma capital additions 2007 adjustment in
3 Company witness Ms. Andrews' testimony at Exhibit No. 13,
4 Schedule 1, page 8, for gross plant of $27,983,000 was
5 computed by subtracting the AM gross plant balance used in
6 the filing of $879,496,000 from the calculated EOP adjusted
7 gross plant balance of $907,479,000.Additional details
8 regarding these adjustments are provided in Ms. Andrews'
9 workpapers .
10 This same process was used for both accumulated
11 depreciation and deferred income taxes,. to arrive at EOP
12 adjusted amount at Decemer 31, 2007 for the 2007 vintage
13 plant assets. The pro forma capital additions adjustment
14 for accumulated depreciation of $8,449,000 was computed by
15 subtracting the AM accumulated depreciation balance used
16 in the filing of $300,320,000 from the calculated EOP
17 adjusted accumulated depreciation balance of $308,769,000.
18 The pro forma capital additions adjustment for DFIT of
19 ($1,758,000) was computed by subtracting the AM DFIT
DeFelice, Di 25
Avista Corporation
1 balance used in the filing of ($80,527,000) from the
2 calculated EOP adjusted DFIT balance of ($82,285,000).
3
4 Step 2 - Adjust 2007 vintage Plant to EOP Decemer 31, 2008
5 (Pro Form Capital Additions 2008 Adjustment - Part A)
6 The second step was to determine rate base at Decemer
7 31, 2008 for the 2007 vintage plant assets.Only
8 accumulated depreciation and deferred taxes are impacted.
9 Depreciation expense of $24,241,000 was computed on gross
10 plant at December 31, 2007, adjusted for projected 2008
11 retirements, using the average effective depreciation rates
12 by functional plant group.Depreciation expense of
13 $269,000 on the 2007 revenue producing capital additions
14 was removed, for a net increase to accumulated depreciation
15 of $23,972,000.The deferred tax impact on the 2007
16 vintage plant assets i adjusted for the revenue producing
17 capital additions, was ($3,726,000). These changes to rate
18 base at December 31, 2008 are added to the 2008 vintage
19 plant additions (discussed below) to derive the pro formal
20 capital additions adjustment for 2008, detailed in Ms.
21 Andrews' testimony at Exhibit No. 13, Schedule 1, page 8.
22 Addi tional details regarding these adjustments are provided
23 in Ms. Andrews' workpapers.
24 Step 3 - Add 2008 vintage Plant to EOP Decemer 31, 200825 (Pro Form Capital Additions 2008 Adjustment - Part B)
26 The capital additions for 2008 were sumarized by
27 functional plant categories and either directly assigned or
DeFelice, Di 26
Avista Corporation
1 allocated to the services and jurisdictions based on
2 standard Company practices.The amount of revenue
3 producing capital additions in 2008 by service and
4 jurisdiction was excluded.The additions were further
5 sumarized by the month they are expected to be transferred
6
7
to plant in service.using the average effecti ve
depreciation rates by functional plant group,AM
8 depreciation expense was computed in order to include the
9 partial year convention of depreciation that will actually
10 be recorded in 2008.
11 For the Idaho electric service, plant additions were
12 $29,475,000, depreciation expense was $542,000 and DFIT was
13 ($519,000). These 2008 costs are added to the 2007 vintage
14 plant 2008 costs (discussed above) to derive the pro forma
15 capital additions adjustment to rate base for 2008.
16 A sumary of the pro forma capital additions 2008
17 adjustment follows:
($OOO's)Part A Part B Total
2007 Vintage 2008 Vintage Adjustment to
Plant Plant Rate Base
Plant in Service $0 $29,475 $29,475
Accumulated Depreciation $23,972 $542 $24,514
DFIT ($3,726)($519)($4,245)
18
19
20 Q.What other impact does the 2007 and 2008 capital
21 additions have on this case in addition to the rate base
22 impact?
DeFelice, Di 27
Avista Corporation
1 A.Depreciation expense and property taxes have been
2 computed for the 2007 and 2008 plant vintages for the pro
3 forma rate year.
4 The pro forma capital additions 2007 pre-tax
5 depreciation adjustment of $185,000 is computed as follows:
6
($OOO's)
Estimated full-year of depreciation expense in 2009 on the 2007 vintage plantbalance at December 31, 2008 $24,082
Less: Depreciation expense on 2007 revenue producing capital additions ($268)
Total Depreciation Expense $23,814
2007 test year depreciation expense, adjusted for the depreciation true-upadjustment. $23,627State Taxes ii
Pro forma Capital Additions 2007 Adjustment - Depreciation Expense $185
7
8 The pro forma capital additions 2008 pre-tax
9 depreciation and property tax adjustment of $1,563,000 is
10 computed as follows:
11
($OOO's)
Estimated full-year of depreciation expense in 2009 on the 2008 vintage plant
balance at December 31, 2008, net of revenue producing capital additions $1,144
Estimated full-year of propert taxes in 2009 on the 2008 vintage plant balance
at December 31, 2008, net of revenue producing capital additions $435State Taxes i1
Pro Forma Capital Additions 2008 Adjustment - Depreciation and Propert Tax ~
Expense
12
13
DeFelice, Di 28
Avista Corporation
1
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V. OTHER CONSIDERATIONS
Q.Did the Company consider the impact of 2009
3 capital additions?
4 A.Yes, it did.A similar process was used by the
5 Company to compute the adjustment that would be necessary
6 to include the AM capital additions for 2009, and to
7 adjust both the 2007 and 2008 vintage plant to June 30,
8 2009 (which represents an AM 2009 net rate base balance
9 for all plant through 2009.)Al though there is a case to
10 be made that the AM 2009 level of net rate base will be
11 used and useful and providing service to customers (i. e.
12 customers will be receiving benefit from the investment)
13 and therefore should be reflected in this case, the Company
14 has opted to only include the net effect of adjusting net
15 rate base to a pro forma December 31, 2008 level.
16 Q.What is the rationale behind the removal of
17 capital expenditures for connecting new customers?
18 A.The pro forma capital expenditures for 2008 that
19 the Company included in this filing excludes distribution
20 related capital expenditures made that are associated with
21 connecting new customers to the Company's system.The
22 Company recognizes the fact that new customers provide
23 incremental revenue that helps offset the revenue
24 requirements of the distribution related capital additions
25 that the Company incurs to provide service to those
DeFel ice, Di 29
Avista Corporation
1 customers. These adjustments completely eliminated the AM
2 2007 and EOP 2008 capital activity related to new customer
3 connections in order to avoid an unintended mismatch of
4 revenues exceeding the cost to serve customers.
5 Q.In addition to excluding new customer related
6 capital additions, does the Company address the 2009/2007
7 revenue difference in other ways?
8
9
A.Yes.The production property adjustment
(discussed in Company witness Ms.Knox's testimony)
10 addresses the production and transmission related retail
11 revenue that would be produced by the change in retail load
12 expected in 2009 compared to the 2007 normalized test year.
13 All production and transmission rate base and operating
14 expenses, including those from these capital additions
15 adjustments, are reduced in order to reflect the amount
16 needed to be recovered from 2007 sales volumes.
17
18
19
20
VI. CONCLUSION
Q.What is the impact of the pro form adjustment?
A.The proposed adjustment will result in a closer
21 matching of revenues to cost of service to customers at the
22 time new rates go into effect at the conclusion of this
23 general rate proceeding. Without the proposed adjustment,
24 the Company would not have the opportunity to earn its
25 allowed rate of return on investment during the rate year.
DeFelice, Di 30
Avista Corporation
1 Q.
2 testimony?
3 A.
Does this
Yes, it does.
conclude your pre-filed direct
DeFelice, Di 31
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT, GENERA COUNSEL,
GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P .0. BOX 3727
1411 EAST MISSION AVENU
SPOKAE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
REG~R&-3 PI'l 1:06
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-08-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-08-01
AUTORITY TO INCREASE ITS RATES )
AN CHAGES FOR ELECTRI C AN )
NATU GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 11
AN NATU GAS CUSTOMERS IN THE )STATE OF IDAHO ) DAVE B. DEFELICE
)
FOR AVISTA CORPORATION
(ELECTRIC AN NATU GAS)
Rising Utility Construction Costs:
Sources and Impacts
Prepared by:
Marc W. Chupka
Gregory Basheda
The Brattle Group
Prepared for:
ti'~-- ~" The
~ FO;~!~?or:
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page i of 33
SEPTEMBER 2007
The Edison Foundation is a nonprofit organization dedicated to
bringing the benefits of electricity to families, businesses, and
industries worldwide.
Furthering Thomas Alva Edison's spirit of invention, the
Foundation works to encourage a greater understanding of
the production, delivery, and use of electric power to foster
economic progress; to ensure a safe and clean environment;
and to improve the quality of life for all people.
The Edison Foundation provides knowledge, insight and
leadership to achieve its goals through research, conferences,
grants, and other outreach activities.
The Bratte Group
The Bratte Group provides consulting services and expert
testimony in economics, finance, and regulation to corporations,
law firms, and public agencies worldwide. Our principals
are internationally recognized experts, and we have strong
partnerships with leading academics and highly credentialed
industry specialists around the world.
The Bratte Group has offces in Cambridge, Massachusetts;
San Francisco; Washington, D.C.; Brussels; and London.
Detailed information about The Brattle Group is available at
ww.brattle.com.Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 2 of 33
(Ç 2007 by The Edison Foundation.
All Rights Reserved under U.S. and foreign law, treaties and conventions. This Work canot be reproduced, downloaded,
disseminated, published, or transferred in any form or by any means without the prior written permission of the copyrght
owner or pursuant to the License below. .
License - The Edison Foundation grants users a revocable, non-exclusive, limited license to use this copyrghted material for
educational and/or non-commercial puroses conditioned upon the Edison Foundation being given appropriate attribution for
each use by placing the following language in a conspicuous place, "Reprinted with the permission of The Edison
Foundation." This limited license does not include any resale or commercial use.
Published by:
The Edison Foundation
701 Pennsylvania Avenue, NoW.
Washington, D.C. 20004-2696
Phone: [phone]
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 3 of 33
Table of Contents
Introduction and Executive Summary .................................................................................................... i
Projected Investment Needs and Recent Infrastructure Cost Increases............................................. 5
Curent and Projected U.S. Investment in Electricity Infrastructue ......................................................................5
Generation...................................................................... ................................................................................. ........5
High-Voltage Transmission ...... ... ........ ....... ...... ........ ..... ................... ......... ........... ........... ................ .... ...................6
Distrbution .............................................................................................................................................................6
Constrction Costs for Recently Completed Generation .................... ....................... ........................ .......... ...........7
Rising Projected Constrction Costs: Examples and Case Studies .....................................................................10
Coal-Based Power Plants .................... ..........................................................................................................1 0
Transmission Projects ...................................................................................................................................11
Distrbution Equipment.................................................................................................................................12
Factors Spurring Rising Construction Costs ....................................................................................... 13
Material Input Costs..............................................................................................................................................13
Metals............................................................................................................................................................13
Cement, Concrete, Stone and Gravel... ..... ....... ..... ..... ...... ....... ............ ....... ............. .... ................................. .17
Manufactued Products for Utility Infrastrctue ....... ..... .............. ........... ........ ......... ...... ..... .... ... .......... .......18
Labor Costs.......................... ....................................................... ................................................................. .20
Shop and Fabrication Capacity .............................................................................................................................21
Engineerig, Procurement and Construction (EPC) Market Conditions ......... ............. ..... ..................... ..............23
Sumar Constrction Cost Indices. ............ ...... ....... ..... ................... ....... ...... ... ..... ..... ..... .... ......... ... ........ ........ ...24
Comparison with Energy Information Admstration Power Plant Cost Estimates ..... ....... ............... .................27
Conclusion ................................................................................................................................................31
Exhibit No. 11
Case Nos AVU-E-OB-Ol & AVU-G-OB-Ol
D. DeFelice, Avista
Schedule 1
Page 4 of 33
iii~
.. Introduction and Executive Summary
In Why Are Electricity Prices Increasing? An Industr-Wide Perspective (June 2006), The Brattle Group
identified fuel and purchased-power cost increases as the primar drver of the electrcity rate increases that
consumers curently are facing. That report also noted that utilties are once again enterig an infrastrctu
expansion phase, with signficant investments in new baseload generating capacity, expansion of the bulk
transmission system, distrbution system enhancements, and new environmental controls. The report
concluded that the industr 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 drver that was not explored in the previous work also will impact electrc rates, naely,
the substantial increases in the costs of buildig utility inastrctue projects. Some of the factors
underlying these constrction cost trends are straightforward-such as shar increases in materials cost-
while others are complex, and sometimes less transparent in their impact. Moreover, the recent rise in many
utility constrction cost components follows roughly a decade of relatively stable (or even declinng) real
constrction costs, adding to the "sticker shock" that utilities experience when obtainng cost estimates or
bids and that state public utility commssions experience durng the process of reviewing applications for
approvals to proceed with constrction. While the full rate impact associated with constrction cost
increases wil not be seen by customers until infrastrctue projects are completed, the issue of rising
constrction costs curently affects industr investment plans and presents new challenges to regulators.
The purose of this study is to a) document recent increases in the constrction cost ofutility infrastrctue
(generation, transmission, and distribution), b) identify the underlying causes of these increases, and c)
explain how these increased costs wil translate into higher rates that consumers might face as a result of
required infrastrctue investment. This report also provides a reference for utilties, regulators and the
public to understand the issues related to recent constrction cost increases. In sumar, we find the
following:
· Dramatically increased raw materials prices (e.g., steel, cement) have increased constrction cost
directly and indirectly though the higher cost of manufactued components common in utility
infastrctue projects. These cost increases have priarly been due to high global demand for
commodities and manufactued goods, higher production and transportation costs (in par owing to
high fuel prices), and a weakenig U.S. dollar.
· Increased labor costs are a smaller contributor to increased utility constrction costs, although that
contrbution may rise in the futue as large constrction projects across the countr raise the demand
for specialized and skilled labor over curent or projected supply. There also is a growing backlog of
Exhibit No. 11
Case Nos AVU-E-08-0l & AVU-G-08-0l
D. DeFelice, Avista
Schedule 1
Page 5 of 33
1 "I
Introduction and Executive Summary
project contracts at large engineering, procurement and constrction (EPC) firms, and constrction
management bids have begu to rise as a result. Although it is not possible to quantify the impact on
futue project bids by EPC firms, it is reasonable to assume that bids wil become less cost-competitive
as new constrction projects are added to the queue.
· 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 distrbution system equipment costs have been rising rapidly. This is
seen in Figue ES-l, which shows recent price trends in generation, transmission and distribution
infrastrctue 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.! As
shown in Figue ES-l, inastrctue costs were relatively stable durng 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 distrbution equipment rose by 25
percent to 35 percent (compared to an 8 percent increase in the GDP deflator). For example, the cost
of gas tubines, which was fairly steady in the early part of the decade, increased by 17 percent durng
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 natual gas-fired combined-cycle plants-and thus liiiting some of the
cost-reduction benefits expected from expanding the solid-fuel fleet.
Figure ES-l
National Average Utilty Infrastrcture Cost Indices
uo --------------------
-Tota Plant.AII Sic Genention -Gas Twbgctoni -GOP Def -Transmiion
190
180 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
no - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
i~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -s
~ 150.!ø-
ê 140..
i 130
lIO
100
90
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 200 2005 200 2007
Year
Sourcs: The Handy-WhitmanO Bulleli No. 165 and the U.S. Bure of Ecoomic Analysis.
Simple averge of all regionl constrtion and equipment cosl indexes for the specified components.
1 The GDP deflator measures the cost of goods and services purchased by households, industr and governent, 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 servces purchased by households and industr, respectively.
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 6 of 33
""2
Rising Utilty Construction Costs: Sources and Impacts
· The rapid increases experienced in utility constrction costs have raised the price of recently
completed infrastrctue projects, but the impact has been mitigated somewhat to the extent that
constrction 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 infrastrctue projects,
which fully incorporates recent price trends. Ths has raised signficant concerns that the next wave
of utilty investments may be imperiled by the high cost environment. These rising constrction costs
have also motivated utilities and regulators to more actively pursue energy effciency and demand
response initiatives in order to reduce the futue rate impacts on consumers.
· Despite the overwhelmng evidence that constrction costs have risen and wil be elevated for some
time, these increased costs are largely absent from the capital costs specified in the Energy Information
Admstration's (BIA's) 2007 Annual Energy Outlook (ABO). The ABO generation capital cost
assumptions since 2001 are shown in Figue 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 ABO data need to be adjusted to reflect recent cost increases to provide
reliable indicators of curent or future capital costs.
Figure ES.2
EIA Generation Construction Cost Estimates
Convtiona Co Contional CC Conventional CT Wind Advanc Nuclear-ioce -Wind -AdvaNuclear -Conven1ODICT -GpPPefl
135
100
-GDP-
Denator
130
125
120s
;: 115,!."." 110~"~ 105
.s
95
~ ---------------------
85
2001 2002 2003 2004 2005 2006
Year
Source: Dat collected from the U.S. Energy Infonoation Administation Assump,ion to ,he Annual Ener au,look 2002 to
2007 and from the U.S. Buru of Economic Analysis.
Exhibit No. 11
Case Nos AVU-E-08-0l & AVU-G-08-0l
D. DeFelicer Avista
Schedule 1
Page 7 of 33
3~
~ Projected Investment Needs and Recent
Infrastructure Cost Increases
Current and Projected U.S. Investment in Electricity Infrastructure
The electrc power industr is a very capital-intensive industr. The total value of generation, transmission
and distrbution infrastrctue for regulated electrc utilities is roughly $440 bilion (propert in service, net
of accumulated depreciation and amortization), and capital expenditues are expected to exceed $70 bilion
in 2007.2 Although the industr as a whole is always investing in capital, the rate of capital expenditues
was relatively stable durng the 1990s and began to rise near the tu of the centu. As shown in Why Are
Electricity Prices Increasing? An Industry-Wide Perspective (June 2006), utilties anticipate substantial
increases in generation, transmission and distrbution investment levels over the next two decades.
Moreover, the signficant need for new electrcity infrastrctue is a world-wide phenomenon: According to
the World Energy Investment Outlook 2006, investments by power-sector companies thoughout the world
wil total about $11 trilion 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 ths capacity owned by electrc utilities. Close to 400 GW of ths total, or 39
percent, consists of natual gas-fired capacity, with coal-based capacity comprising 32 percent, or slightly
more than 300 GW, ofthe US. electrc generation fleet. Nuclear and hydroelectrc 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. Natual gas-fired plants, which tend to
operate as intermediate or peaking plants, also provided about 19 percent of US. energy production in 2006.
The need for installed generating capacity is highly correlated with load growt and projected growt in peak
demand. According to EIA's most recent projections, US. electrcity sales are expected to grow at an anual
rate of about 1.4 percent through 2030. Accordig to the North American Electrc Reliabilty 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 wil need to build 258 GW of new generating capacity by 2030 to meet the
2 Net propert in service figue as of December 3 i, 2006, derived from Federal Energy Regulatory Commission (pERC)
Form i data compiled by the Edison Electrc Institute (EEl). Gross propert is roughly $730 bilion, with about $290
billon already depreciated and/or amortized. Anual capital expenditue estimate is derived from a sample of 10K reports
sureyed by EEL
3 Richard Stavros. "Power Plant Development: Raising the Stakes." Public Utilties Fortnightly, May 2007, pp. 36-42.
Exhibit No. 11
Case Nos AVU-E-OB-Ol & AVU-G-08-0l
D. DeFelice, Avista
Schedule 1
Page 8 of 33
5~
Projected Investment Needs and Recent Infrastructure Cost Increases
projected growth in electrcity demand and to replace 01d, inefficient plants that wil be retired. EIA fuer
projects that coal-based capacity, that is more capital intensive than natual gas-fired capacity which
dominated new capacity additions over the last 15 years, wil account for about 54 percent of total capacity
additions from 2006 to 2030. Natual gas-fired plants comprise 36 percent of the projected capacity
additions in AEO 2007. EIA projects that the remainig 10 percent of capacity additions wil 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 constrction
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 millon customers. Ths system was built
over the past 100 years, primarly 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 10cal areas and coordinate reliability through the eight regional reliability
councils ofNERC.
After a 10ng period of decline, transmission investment began a signficant upward trend staing in the year
2000. Since the beginning of 2000, the industr has invested more than $37.8 bilion in the nation's
transmission system. In 2006 alone, investor-owned electrc utilities and stand-alone transmission
companies invested an historic $6.9 bilion in the nation's grd, while the Edison Electrc Institute (EEl)
estimates that utility transmission investments wil increase to $8.0 bilion during 2007. A recent EEl surey
shows that its members pIan to invest $31.5 bilion 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 par by the larger scale of base 10ad generation additions that wil occur farer
from 10ad centers, creating a need for larger and more costly transmission projects than those built over the
past 20 years. In addition, new governent policies and industr strctues wil contrbute to greater
transmission investment. In many pars of the countr, transmission plannng 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 wil 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 ths 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 PlM Interconnection LLC, such as the major new lines proposed by
American Electrc Power, Allegheny Power, and Pepco.
Distribution
While transmission systems move bulk power across wide areas, distrbution systems deliver lower-voltage
power to retail customers. The distrbution system includes poles, as well as meterig, biling, and other
related infrastrctue and softare associated with retail sales and customer care fuctions. Continual
Exhibit No. 11
Case Nos AVU-E-08-0l & AVU-G-08-0l
D. DeFelice, Avista
Schedule 1
Page 9 of 33
"'6
Rising Utility Construction Costs: Sources and Impacts
investment in distrbution facilities is needed, first and foremost, to keep pace with growt 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 distrbution assets shows no sign of diminishing. The need to
replace an aging infrastrctue, coupled with increased population growt and demand for power quality and
customer service, is continuing to motivate utilties to improve their ultimate delivery system to customers.
Continued customer load growt wil require continued expansion in distribution system capacity. In 2006,
utilities invested about $17.3 bilion in upgrading and expandig distribution systems, a 32-percent increase
over the investment levels incured in 2004. EEl projects that distrbution investment durg 2007 wil again
exceed $17.0 billion. Whle much of the recent increase in distrbution investment reflects expanding
physical infrastrctue, a substatial portion of the increased dollar investment reflects the increased input
costs of materials and labor to meet curent distrbution inastrctue needs.
Construction Costs for Recently Completed Generation
The majority of recently constrcted plants have been either natual 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 natual gas-fired capacity, either natual gas-fired combined-cycle unts or natual
gas- fired combustion tubines. Combustion tubine prices recently rose sharly after years of real price
decreases, while significant increases in the cost of installed natual 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
governent documents, The Brattle Group collected data on the installation cost of natua 1 gas-fired
combined-cycle generating plants built in the U.S. durng the last major constrction cycle, defined as
generating plants brought into service between 2000 and 2006. We estimated that the average real
constrction cost of all natual gas-fired combined-cycle units brought online between 2000 and 2006 was
approximately $550/klowatt (kW) (in 2006 dollars), with a range of costs between $400/kW to
approximately $L,OOO/kW. Statistical analysis confirmed that real installation cost was influenced by plant
size, the tubine technology, the NERC region in which the plant was located, and the commercial online
date. Notably, we found a positive and statistically signficant relationship between a plant's constrction
cost and its online date, meang that, everying else equal, the later a plant was brought online, the higher
its real installation cost. 4 Figue 1 shows the average yearly installation cost, in nominal dollars, as predicted
by the regression analysis.5 This figue shows that the average installation cost of combined-cycle unts
increased gradually from 2000 to 2003, followed by a fairly signficant increase in 2004 and a very
significant escalation-more than $300/kW-in 2006. Ths provides vivid evidence of the recent shar
increase in plant constrction costs.
4 To be precise, we used a "dumy" varable to represent each year in the analysis. The year-specific dumy variables
were statistically significant and uniformly positive; i.e., they had an upward impact on installation cost.
5 The nominal form regression results are discussed here to facilitate comparson with the GDP deflator measure used to
compare other price trends in other figues in this report.
Exhibit No. 11
Case Nos AVU-E-08-0l & AVU-G-08-0l
D. DeFelice, Avista
Schedule 1
Page 10 of 33
7~
Projected Investment Needs and Recent Infrastructure Cost Increases
Figure 1
Multi-Variable Regrssion Estimation:
Average Nominal Installation Costs Based on Online Year ($/kW)
1000
900
800
700
600
i 500
400
300
200
100
0
- --------------- --- --- ----------- -- - -------- ~~--
------- - ---_.. ----- ------~""_.._--~+.._-------
- - ~~ - - - - - ~~ - - - - - -~~ - - - - - ~,~ - - - - - - - - - - - - - - - - - - - - - - - -
2000 2001 2002 2003
Onlie Year
2004 2005 2006
Sour and Notes:
. Data on summer capacity. tota insllatioo cost . tubine tehnology, commeral online date, and zip code for the perod 2000-2006
were collected frm commerially available databas and other source such as compay websites and 10k reort.
Figue 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 occurng in 2006,
Figure 2
Multi-Variable Regression Estimation:
Average Nominal Installation Costs Based on Online Year (Index Year 2000 = 100)
2S0
l..oDP Deflator I
I.. Average Installation Costs I ,0,"
200
ISO - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 5 - - - - - - -5 - - - - - - - - -,i; ,i;".. ,~ ",~~ - ' ,~.:
,i§,~""r§..~Io..,~~ --....
;;,10 --100
SO - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
o
2000 2001 2002 2003 2004 200S 2006
OnUneYear
". 8
Sources and Notes:
. Data on summer capacity. total instalation cost, turbine tehnology. commercial online date. and zip code for the perod 2000-2006
were collecte from commercially available databases and other sources such as company websiie and 10k reort.
.. GDP Deflator data were collecte frm the U.S. Burau of Economic Analysis.Exhibi t No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 11 of 33
Rising Utility Construction Costs: Sources and Impacts
Another major class of generation development durng ths decade has been wind generation, the costs of
which have also increased in recent years. The Nortwest Power and Conservation Council (NCC), a
regional plang council that prepares 10ng-term electric resource plans for the Pacific Nortwest, 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 pIan. Specifically, the Council found that the levelized lifecycle cost of power for new
wind projects rose 50 to 70 percent, with higher constrction costs being the pricipal contrbutor to ths
increased cost. According to the Council, the constrction 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 contrbuting 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 stadads established by a growing number of states. The Council notes
that commodities used in the manufactue and installation of wind tubines and ancilar equipment,
, including cement, copper, steel and resin have experienced significant cost increases in recent years. Figue
3 shows real constrction costs of wind projects by actual or projected in-service date.
Figure 3
Wind Power Project Capital Costs
l $2.000
CD....N $1,50
$1,00
$500
..
. Estimated overnight capital cost
- Poly. (Estimated overnight capital cost)
$0
200 2001 2002 20 20 2005 2006 2007 2008 2009
Service Year
Source: The Nortwest Power and Conseration Council, "Bienial Revew of the Cost of Wind power" July 13, 2006.
These observations were confirmed recently in a May 2007 report by the U.S. Deparent of Energy (DOE),
which found that prices for wind tubines (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 (Figue 21) and shows the signficant upward trend in tubine prices since 2001.
6 The NPCC planng studies and analyses cover the following four states: Washington, Oregon, Idaho, and Montaa. See
"Biennal Review of the Cost of Wind power" July 13,2006, at
ww.bpa.govÆnergylN/projects/post2006conservation/doc/Windpower_Cost_Review.doc.This study provides many
reasons for windpower cost increases.
7 See U.S. Deparent of Energy, Annual Report on U.S. Wind Power Installation, Cost and Performance Trends: 2006
Figure 21, page 16.
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 12 of 33
9~
Projected Investment Needs and Recent Infrastructure Cost Increases
Figure 4
Wind Turbine Prices 1997 . 2007
$1.00
1$1'40
æ $1.200
!l "'1000.. 'l t
i lrl ~
J~ $40~
¡3 (¡00
::~.::__d: .::. :... ..:. ...::::'..::':::.::::::::::::.:::::::: :::. .:::::::...:::.:..:.:::............. ::~: :~. ...::: :::.... . ... ........... ..... ..--.. ........ ..... ........ .,...... ..... ...........--.. ....... .:..... ......... .. ...A ~ . ..
........................ .......................... ,. . ..........................................
............................................................
" Orders ..1 00 MW
. Orders from 1'00 - :lOll 'MW
. Orders ;:300 MW
- POl)'QmiiilTreoo Une
fl
JI-91 Ja-91 JI-£S 111-00 JI-01 111-02 JI-03 Ja-(\ Jm-Ii 111-06 JI-oi
SWæ: ilyLstl i1tm. Mniiunaime DlI
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 arse from proposed utilty investments, which fully
reflect the recent, sharly rising prices of various components of constrction and installation costs. The
most visible of these are generation proposals, although several transmission proposals also have undergone
substantial upward cost revisions. Distrbution-Ievel 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 constrction cost of coal-based power plants can be found in
recent applications fied by utilities, such as Duke Energy and Otter Tail Power Company, seekig
regulatory approval to build such plants. Otter Tail Power Company leads a consortum of seven
Midwestern utilties that are seeking to build a 630-MW coal-based generatig unt (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,
includig possibly wind and other renewable forms of energy. Intial cost estimates for the power plant were
about $1 bilion, with an additional $200 millon for the transmission line project. However, these cost
estimates increased dramatically, largely due to higher costs for constrction materials and labor.s Based on
the most recent design refiements, the project, including transmission, is expected to cost $1.6 bilion.
8 Other factors contributing to the cost increase include design changes made by project parcipants 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
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 13 of 33
Rising Utility Construction Costs: Sources and Impacts
In June 2006, Duke submitted a filing with the North Carolina Utilties Commssion (NCUC) seeking a
certficate ofpublic convenience and necessity for the constrction of two 800 MW coal-based generating
units at the site of the existing Cliffside Steam Station. In its intial application, Duke relied on a May 2005
prelimnary cost estimate showing that the two unts would cost approximately $2 bilion 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 unts would cost approximately $3 bilion to build, a 50 percent cost increase.
The North Carolina Utilities Commssion approved the constrction of one 800 MW unit at Cliffside but
disapproved the other unit, priarly 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 unt
at Cliffside is approximately $1.8 bilion, or about $2,250/kW. When financing costs, or allowance for fuds
used during constrction (AFUDC), are included, the total cost is estimated to be $2.4 bilion (or about
$3,000/kW).
Rising construction costs have also led utilties to reconsider expansion plans prior to regulatory actions. In
December 2006, Westa Energy anounced that it was deferrg the consideration of a new 600 MW coal-
based generation facility due to signficant increases in the estimated constrction costs, which increased
from $1.0 bilion to about $1.4 bilion since the plant was first anounced in May 2005.
Increased constrction costs are also affecting proposed demonstration projects. For example, DOE
anounced earlier this year that the projected cost for one of its most prominent clean coal demonstration
project, FutueGen, had nearly doubled.9 FutureGen is a clean coal demonstration project being pursued by
a public-private parership involving DOE and an alliance of industral coal producers and electrc utilities.
FutueGen is an experimental advanced Integrated Gasification Combined Cycle (IGCC) coal plant project
that wil aim for near zero emissions of sulfu dioxide (S02), nitrogen oxides (NOx), mercur, parculates
and carbon dioxide (C02), Its initial cost was estimated at $950 million. But after re-evaluating the price of
constrction materials and labor and adjusting for infation over time, DOE's Office of Fossil Energy
anounced that the project's price had increased to $1.7 bilion.
Transmission Projects
NST AR, the electric distrbution company that serves the Boston metropolitan area, recently built two 345
kV lines from a switchig 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. (lSO-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 millon. NST AR stated that the increase is drven by increases in both constrction and material
costs, with constrction bids comig in 24 percent higher than intially estimated. NST AR fuer 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 dielectrc fluid (used for cable cooling) by 66
percent.
9 U.S. Deparent of
Energy, April 10, 2007, press release available at
htt://ww .fossil.energy.gov Inews/techlines/2007 1070 19-DOE _Signs _ FutueGen _ Agreement.html
Exhibit No. 11
Case Nos AVU-E-08-0l & AVU-G-08-0l
D. DeFelice, Avista
Schedule 1
Page 14 of 33
11~
Projected Investment Needs and Recent Infrastructure Cost Increases
Another aspect of transmission projects is land requirements, and in many areas of the countr land prices
have increased substantially in the past few years. In March 2007, the Californa Public Utilities
Commssion (CPUC) approved constrction of the Southern Californa 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 millon for the Antelope-Pardee 500 kV line. However, the company subsequently
revised its estimate by updating the anticipated cost of acquirig 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 millon, increasing the estimated costs to more than $3.5 million per mile.
Distribution Equipment
Although most individual distrbution 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-
Whtman IndexlO price series relating to distribution equipment and components. Several important
categories of distribution equipment have experienced shar 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 Januar 2004 and Janua 2007, with increases during 2006 alone of28 percent and 23
percent. io 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 thee years.
10 Handy- WhitmaniC Bulletin No. i 65, average increase of six U.S. regions. Used with permssion.
"-12
Exhibit No. 11
Case Nos AVU-E-08-0l & AVU-G-08-0l
D. DeFelice, Avista
Schedule 1
Page 15 of 33
~ Factors Spurring Rising Construction
Costs
Broadly speakg, there are four primar sources of the increase in constrction costs: (1) material input
costs, including the cost of raw physical inputs, such as steel and cement as well as increased costs of
components manufactued from these inputs (e.g., transformers, tubines, pumps); (2) shop and fabrication
capacity for manufactured components (relative to curent demand); (3) the cost of constrction field labor,
both unskilled and craft labor; and (4) the market for large constrction project management, i.e., the queuig
and bidding for projects. Ths section wil discuss each of these factors.
Material Input Costs
Utility constrction projects involve large quantities of steel, alumum and copper (and components
manufactued from these metals) as well as cement for foundations, footings and structues. 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 varous metals,
including steel, copper and aluminum, has increased signficantly in the last few years. These increases are
primarily the result of high global demand and increased production costs (includig the impact of high
energy prices). A weakening U.S. dollar has also contrbuted to high domestic prices for imported metals
and varous component products.
Figue 5 shows price indices for primar inputs into steel production (iron and steel scrap, and iron ore) since
1997. The price of both inputs fell in real terms durng 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 sharpbetween 2003 and 2006, prices for iron ore rose 60 percent and iron
and scrap steel rose 150 percent.
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 16 of 33
13~
Factors Spurring Rising Construction Costs
Exchange Rates
Many of the raw materials involved in utilty constrction projects (e.g., steel, copper,
cement), as well as many major manufactued components of utility infrastrctue
investments, are globally traded. Ths 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 curencies between 1997 and 2001, the graph also clearly
shows a substantial erosion of the dollar since the beginning of 2002, 10sing roughly 20
percent of its value against other major trading parers' curencies. Ths has had a
substantial impact on U.S. material and manufactued component prices, as wil be
reflected in many of the graphs that follow.
Nominal Broad Dollar Index
135
130
US
S=0..II uo..0\0\e..115..'C
oS
110
105
100~~~~.~ ~~~ ~ ~ ~~ ~~##
""~ ",::' 4:~' ""~' ",~"i' 4.~ "".."'- ",;1- 4.","I :'.."I ",,,"I 4.",,, "".."I ",,,,, 4.~ ""'"..'t ",'i ~ 'i,' 4i ~ ..'t ",'i ~~ ..~ 4i ~~ ..'t 4i ~~ ..'t
Source: U.S. Federal ReSOle Board. Stastical Release, Broad Index Date
Foreign Exchange Value of the Dollar.
"'14
Exhibi t No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 17 of 33
Rising Utility Construction Costs: Sources and Impacts
Figure 5
Inputs to Iron and Steel Production Cost Indices
225
GDPDeßator
wo - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
175
s..
i iso
~
~ 125!
100 -
75 ----------
so
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Year
Sources: U.S. Gelogical Survey. Minerl Commodity Summes. and the U.S. Burau of Economic Analysis.
The increase in input prices has been reflected in steel mill product prices. Figue 6 compares the trend in
steel mill product prices to the general infation rate (using the GDP deflator) over the past lO years. Figue
6 shows that the price of steel has increased about 60 percent since 2003.
Figure 6
Steel Mil Products Price Index
100 -
160
150 - - - - - - - - - - - - - - - - - - - - - - - - .- -- - - - - - - - - - - - - - - - - - - - - - - - - -
140
g 130
~ lW
~
.s 110
90
80
1997 1998 1999 2000 2001 2002 2003 200 2005 2006
Year
Sources: U.S. Geologica Surey, Miner Commodity Summares, and the U.S. Buru of Economic Analysis.
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 18 of 33
15~
Factors Spurring Rising Construction Costs
Various sources point to the rapid growt of steel production and demand in China as a primary cause of the
increases in both steel prices and the prices of steelmakng inputs.!! China has become both the world's
largest steelmaker and steel consumer. In addition, some analysts contend that steel companes 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 industr, such as
plate and strctual steels.
From the perspective of the steel industr, 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 steelmakng inputs, such as steel scrap, iron ore,
coking coal, and natual 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 futue.
Other metals important for utilty infrastrctue display simlar 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. Figue 7
shows that alumnum prices doubled between 2003 and 2006, while copper prices nearly quadrpled over the
same period.
Figure 7
Aluminum and Copper Price Indices
300
Copper
2~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
s~ 200
,!....e...~ i~
.5
GDPDeOator
100
~
1997 1998 1999 2000 2001 2002 2003 200 2005 2006
Year
Sources: U.S. Geological Survey. Minerl 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
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 19 of 33
Rising Utilty Construction Costs: Sources and Impacts
These price increases were also evident in metals that contrbute to important steel alloys used broadly in
electrical infrastrctue, such as nickel and tugsten. The prices of these display simlar patterns, as shown
in Figue 8.
FigureS
Nickel and Tungsten Price Indices
350
3UO - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
~O --------------------------------------------- ------
~
J!
;. 200
~
oS 150 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
100 -
50
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006
Year
Sources: U.S. Geological Surey, Minerl Commodity Summares, and the U.S. Bureau of Economic Analysis.
Cement. Concrete. Stone and Gravel
Large infrastrctue 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 utilty constrction, 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 signficant price increases, priarily as a result of increased energy
costs in extraction and transporttion. Figue 9 shows recent price increases for cement and crushed stone.
Prices for these materials have increased about 30 percent between 2004 and 2006.
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, AvistaSchedule i
Page 20 of 33
17~
Factors Spurring Rising Construction Costs
Figure 9
Cement and Crushed Stone Price Indices
ISO
i~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
~
,!'"
ê 120
~.s 110
UO --------------------------------------------- - ----
100 - -
Crusbed Stone
90
1997 1998 1999 2OÐO 2001 2002 2003 2OÐ4 2005 2006
Year
Sources: U.S. Geological Survey, Miner Commodity Summaries, and the U.S. Buru of Economic Analysis.
Manufactured Products for Utility Infrastructure
Although large utility constrction projects consume substantial amounts ofunassembled or semi-finished
metal products (e.g., reinorcing bars for concrete, strctual steel), many of the components such as
conductors, transformers and other equipment are manufactued elsewhere and shipped to the constrction
site. Available price indices for these components.display similar patterns of recent shar price increases.
Figue 10 shows the increased prices experienced in wire products compared to the inflation rate, according
to the U.S. Bureau of Labor Statistics (BLS), highlghtig the impact of underlying metal price increases.
Manufactued components of generating facilities-large pressure vessels, condensers, pumps, valves-have
also increased sharly since 2004. Figue 11 shows the yearly increases experienced in key component
prices since 2003.
"'18
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 21 of 33
Rising Utility Construction Costs: Sources and Impacts
Figure 10
Electric Wire and Cable Price Indices
240
120
Nonferrous Wire
220
200
S 180;:
~; 160
_i:=~140
100
80
1997 1998 1999 2000 2001 2002 2003 2004 200S 2006
Year
Sources: The U.S. Bureau of Labor Statistics and the U.S. Burau of Econmic Analysis.
Figure 11
Equipment Price Increases
02003 ii2004 0200S 02006
0.4
0.8
0.7
0.6
O.S
0.3
0.2
0.1
........ ...¡... ..~'"..-t ~I; .1;~., .#CJ~
Souce: YWha, What, Wher. How" presetaton by John Siegel, Bechtel Powe Co. Delivered at the coferenc entitled Next
Generation of Generation (Dewey Ballantine LLP). May 4, 2006.
'l".,~~ø'C~"
twOV"'~."~."i-"
..\-" tS.,,\~ v."w..'( rp"
Exhibi t No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 22 of 33
19~
Factors Spurring Rising Construction Costs
Labor Costs
A signficant component of utility constrction 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 nationallabor cost index based on simple averages of the
regional Handy-Whitman Index4; for common and craft labor. Between Januar 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 constrction 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 contrbuted to the overall constrction cost increases because of their
substantial share in overall utility infastrctue constrction costs.
Figure 12
National Average Labor Costs Index
180
I - Labor for Hea Coston an Renforc Co -Commn La -Cr Labo -GOP Deflor I
no - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
120
160
g 150
:E'"; 140
ti
:š 130
110
100
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Year
Sourcs: The Handy.WhítmanO Bulletin, No. J65, and the U.S. Buru of Economic Anlysis.
Simple average of all regional labor cost indice for the specified tys 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 constrction labor-especially if the anticipated boom in utilty
constrction materializes. In 2002, the Constrction Users Roundtable (CURT), sureyed its members and
found that recruitment, education, and retention of craft workers continue to be critical issues for the
industr.13 The average age ofthe curent constrction skilled workforce is rising rapidly, and high atttion
rates in constrction are compounding the problem. The industr has always had high atttion at the entr-
level positions, but now many workers in the 35-40 year-old age group are leaving the industr for a varety
of reasons. The latest projections indicate that, because of atttion and anticipated growt, the constrction
12 These figues represent a simple average of six regional indices, however, local and regional labor markets can var
substantially from these national averages.
13 Confonting the Skilled Constrction Workforce Shortage. The Constrction Users Roundtable, WP-401, June 2004, p. 1.
Exhibit No. 11
Case Nos AVU-E-OB-Ol & AVU-G-OB-Ol
D. DeFelice, Avista
Schedule 1
Page 23 of 33
"'20
Rising Utility Construction Costs: Sources and Impacts
industr must recruit 200,000 to 250,000 new craft workers per year to meet futue needs. However, both
demographics and a poor industr image are working against the constrction industr as it tres to address
this need.
14
There also could be a growing gap between the demand and supply of electrcallineworkers who maintain
the electnc grid and who perform much of the labor for transmission and distrbution investments. These
workers erect poles and transmission towers and install or repair cables or wires used to car electricity
from power plants to customers. According to a DOE report, demand for such workers is expected to
outpace supply over the next decade. is 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 curent
workforce. As of 2005, lineworkers eared a mean hourly wage of $25/hour, or $52,300 per year. The
forecast supply shortage wil place upward pressure on the wages earned by lineworkers. 16
Shop and Fabrication Capacity
Many of the components of utilty projects-including large components like tubines, condensers, and
transformers-are manufactued, often as special orders to coincide with paricular constrction projects.
Because many of these components are not held in large inventones, the overall capacity of their
manufactuers can influence the pnces obtained and the length of time between order and delivery. The
pnce increases of major manufactued components were shown in Figue 11. Whle equipment and
component pnces obviously reflect underlying matenal costs, some of the pnce increases of manufactued
components and the delivery lags are due to maufactuing capacity constraints that are not readily overcome
in the near term.
As shown in Figue 13 and Figue 14, recent orders have largely elimnated spare shop capacity, and
delivery times for major manufactued components have nsen. These constraints are adding to pnce
increases and are diffcult to overcome with imported components because of the lower value of the dollar in
recent years.
The increased delivery times can affect utility constrction costs though completion delays that increase the
cost of financing a project. In general, utilities commit substantial fuds during the constrction phase of a
project that have to be financed either through debt or equity, called "allowance for fud used during
constrction" (AFUDC). All else held equal, the longer the time from the initiation though completion of a
project, the higher is the financing costs of the investment and the ultimate costs passed though to
ratepayers.
14 Id., p. 1.
15 Worliorce Trends in the Electric Utilty Industr: A Report to the United States Congress Pursuant to Section 1101 of the
Energy Policy Act of 2005. U.S. Departent of Energy, August 2006, p. xi.
16 Id., p. 5.
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 24 of 33
21 ~
Factors Spurring Rising Construction Costs
Figure 13
Shop Capacity
1.4
.2004 Shop Load . Current Shop Load . Anticipated 2006 Shop Load
1.2
0.8
0.6
0.4
0.2
...,. 'i~V' ..,-rf!~.tI ,,0'co'~ Co"
Source: "Who. What. Where, How" preentation by John Siegel, Behtel Power Corp. Deliver at the cofeence entitled Next
Generation of Generation (Dew Ballantine LLP), May 4, 2006.
coo'\e'Øto
+0\0"",,,6'
~~~'o
Figure 14
Delivery Schedules
120
.2004 .2005 .2006
80
100
~ 60~
40
20
if." ii~'to,C iI+0\0"
V-~.
Source: "Who, What. Where, How" presentation by John Siegel, Bechtel Powe Corp. Deliverd at the confeence entitled Nexi
Generation of Generation (Dewey Ballantine LLP). May 4, 2006.
....
~'...'yio~~
~..co'"....~..,,0"
~ co~'l'
.,'I" .;(J .. ~~'"~~" ,,0'~.\.. Co.
'ftf
"'22
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 25 of 33
Rising Utilty Construction Costs: Sources and Impacts
Engineering, Procurement and Construction (EPC) Market Conditions
Increased worldwide demand for new generating and other electrc infastrctue projects, parcularly in
China, has been cited as a signficant reason for the recent escalation in the constrction cost of new power
plants. Ths suggests that major Engineerg, Procurement and Constrction (EPe) firms should have a
growing backlog of utility infrastrctue projects in the pipeline. Whle we were unable to obtain specific
information from the major EPC firms on their worldwide backlog of electrc utility infrastrctue projects
(i.e., the number of electrc utility projects compared with other infrastrctue projects such as roads, port
facilities and water infrastrctue, in their respective pipelines), we examined their financial statements,
which specify the financial value associated with their backlog of infrastrctue projects. Figure 15 shows
the cumulative anual financial value associated with the backlog of infrastrcture projects at the following
four major EPC firms; Fluor Corporation, Bechtel Corporation, The Shaw Group Inc., and Tyco
Intemational Ltd. Figue 15 shows that the anual backlog of infrastrctue projects rose sharly between
2005 and 2006, from $4.1 bilion to $5.6 billion, an increase of37 percent. This signficant increase in the
anual backlog of infrastrctue projects at EPC firms is consistent with the data showing an increased
worldwide demand for infrastrctue projects in general and also utility generation, transmission, and
distribution projects.
Figure 15
Annual Backiog at Major EPC Firms
65000
60000 ----------------------------------------------- ----
55000 - .- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -i;..
~ 50000=
æ
~ 45000
..
is 40000e-0 35000 - - - - - - - - - - - - - .- - - - - - - - - - - - - - - - - - - - - - - - - - -
30000 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
25000
2002 2003 2004 2005 2006
Year
Data are compiled from the Annual Repor of Fluor Corporation. Bechtel Corporion, The Shaw Grup Inc.. and Tyc
Interational Ud. For Bechtel, the data represent new boked worl. as backlog i. not reorted.
The growth in constrction project backlogs likely wil dapen the competitiveness of EPC bids for futue
projects, at least until the EPC industr is able to expand capacity to manage and execute greater volumes of
projects. This observation does not imply that ths 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 infrastrctue constrction cycles. Such constraints,
Exhibi t No. 11
Case Nos AVU-E-08-0l & AVU-G-08-0l
D. DeFelice, Avista
Schedule 1
Page 26 of 33
23 'I
Factors Spurring Rising Construction Costs
combined with a rapidly fillng (or full) queue for project management services, lit incentives to bid
aggressively on new projects.
Although difficult to quatify, this lack of spare capacity in the EPC market wil undoubtedly have an
upward price pressure on new bids for EPC services and contracts. A recent fiing by Oklahoma Gas &
Electrc Company (OG&E) seeking approval of the Red Rock plant (a 950 MW coal unt) provides a
demonstration of this effect. In Januar 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)."!? In the detailed cost table, OG&E
indicated that the estimate for EPC services had increased by more than 50 percent durng the nine month
period (from $223/kW to $340/kW).
Summary Construction Cost Indices
Several sources publish sumar constrction cost indices that reflect composite costs for varous
constrction projects. Although changes in these indices depend on the actual cost weights assumed e.g.,
labor, materials, manufactued components, they provide useful sumar measures for large inastrctue
project construction costs.
The RSMeans Constrction Cost Index provides a general constrction cost index, which reflects primarly
building constrction (as opposed to utility projects). This index also reflects many of the same cost drivers
as large utility constrction projects such as steel, cement and labor. Figure 16 shows the changes in the
RSMeans Constrction Cost index since 1990 relative to the general inflation rate. While the index rose
slightly higher than the GDP deflator beginnng 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 Commssion of the State of Oklahoma, Cause No. PUD
200700012, January 17, 2007, page 27 and Exhibit JBL-9.
Exhibi t No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 27 of 33
"'24
Rising Utility Construction Costs: Sources and Impacts
Figure 16
RSMeans Historical Construction Cost Index
IW - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
170
RSMeas Histoncal
ISO - - - -- - - --- --- --- -- - - - ----- - - - - -Cõñšniõtr.ñC.stlna.i-- - - -- ----
~ 140
II=
~ 130
e-
II
:š 120
110
100 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
90
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 200
Year
Source: RSMeas, Heavy Constction Cost Data, 20th Annual Edition, 200.
The Handy-Whtman Indexlt 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 Janua 1 of each year displayed.
Figue 17 displays two indices for generation costs: a weighted average of coal steam plant constrction
costs (boilers, generators, piping, etc.) and a stad-alone cost index for gas combustion tubines.
As seen on Figue 17, steam generation constrction costs tracked the general inflation rate fairly well
though the 1990s, began to rise modestly in 2001, and increased signficantly since 2004. Between Janua
1,2004, and Januar 1,2007, the cost of constrcting steam generating units increased by 25 percent-more
than trple the rate of inflation over the same time period. The cost of gas tubo generators (combustion
turbines), on the other hand, actually fell between 2003 and 2005. However, during 2006, the cost of a new
combustion tubine increased by nearly 18 percent-roughly 10 times the rate of general inflation.
18 Used with permission. See Handy-WhitmanO Bulletin, No. 165 for detailed data breakouts and regional values for six
regions: Pacific, Plateau, South Central, Nort Central, South Atlantic and Nort Atlantic. The Figues shown reflect
simple averages of the six regions.
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, AvistaSchedule i
Page 28 of 33
25~
Factors Spurring Rising Construction Costs
Figure 17
National Average Generation Cost Index
-Totl Plant-All Stem Genetion -Gas Turgcertol1 -GDP Deflato
180
no ------------------------------------------------- -
1~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
S 158'"
Jt 140'"'"e 130
:l'C
,! 120
110
100
90
1991 1992 1993 1994 1995 19% 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Year
Sources: The Hidy-WhitmCl Bullet, No. 165 an the U.S. Buru of Eeonomie Analysis.
Simple average of all regional constcton and equipment cost indices for the specfied components.
Figue 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 shar increase
between 2004 and 2007, rising almost 30 percent or nearly four times the anual inflation rate over that
period.
Figure 18
National Average Transmission Cost Index
190
~o - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
120
1~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - --
160s
~ 150
.!
; 140
"
~ 130.s
110
100 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
90
1991 1992 1993 1994 1995 19% 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007
Year
Sources: The Handy-WhitmanCl Bulletn, No. 165, and th U.S. Bur of Ecnomie Analysis.
Simple average of all regiona trission cost indice.
"-26
Exhibi t No. 11
Case Nos AVU-E-08-0l & AVU-G-08-0l
D. DeFelice, Avista
Schedule 1
Page 29 of 33
Rising Utilty Construction Costs: Sources and Impacts
Figue 19 shows distribution plant costs, which include poles, conductors, conduit, transformers and meters.
Overall distrbution plant costs tracked the general inflation rate very closely between i 99 i and 2003.
However, it then increased 34 percent between Januar 2004 and Janua 2007, a rate that exceeded four
times the rate of general infation.
Agure 19
National Average Distribution Cost Index
ISO
i~ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
MO - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
BO ------~-------~------------------------------- ----
~
.! 140;
;; 130..
:š 120
110
100
90
1991 1992 1993 1994 1995 1996 1991 1998 1999 2000 2001 2002 2003 2004 200 200 2001
Year
Sources: The Handy-WbitanlO Bulletn, No. 165, and the U.S. Bureu of Ecomic Analysis.
Simple averge of all regional distbution cos indices.
Comparison with Energ Information Administration Power Plant Cost Estimates
Every year, EIA prepares a long-term forecast of energy prices, production, and consumption (for electrcity
and the other major energy sectors), which is documented in the Annual Energy Outlook (ABO). A
companon publication, Assumptions to the Annual Energy Outlook, itemizes the assumptions (e.g., fuel
prices, economic growt, environmental regulation) underlying EIA's anual long-term forecast. Included
in the latter document are estimates of the "overnight" capital cost of new generating unts (i.e., the capital
cost exclusive of financing costs). These cost estimates influence the tye of new generating capacity
projected to be built durg the 25-year time horizon modeled in the ABO.
The EIA capital cost assumptions are generic estimates that do not take into account the site-specific
characteristics that can affect constrction costs signficantly.I9 Whle EIA's estimates do not necessarly
provide an accurate estimate of the cost ofbuilding a power plant at a specific location, they should, in
theory, provide a good "ballpark" estiate of the relative constrction cost of different generation
19 EIA does incorporate regional multipliers to reflect minor variations in constrction costs based on labor conditions.
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 30 of 33
27~
Factors Spurring Rising Construction Costs
technologies at any given time. In addition, since they are prepared anually, these estimates also should
provide insight into constrction cost trends over time.
The EIA plant cost estimates are widely used by industr analysts, consultants, academics, and
policymakers. These numbers frequently are cited in regulatory proceedigs, sometimes as a yardstick by
which to measure a utility's projected or incured capita costs for a generatig plant. Given this, it is
importt that EIA's numbers provide a reasonable estimate of pi ant costs and incorporate both
technological and other market trends that signficantly affect these costs.
We reviewed EIA's estimate of overnght plant costs for the six-year period 2001 to 2006. Figure 20 shows
EIA's estimates of the constrction cost of six generation technologies--ombined-cycle gas-fired plants,
combustion tubines (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
-Convenion Col -ConntionalCC -CovcntionlCT -Wind -Advanc Nuclea
-lGce -Wind -Advanc:Nuclea -ConvenlionlCT -ODPDeRllor
135
100
-GDP
Deflator
130
125
120s
;; 115,!
l. 110..~ 105
.s
90 ---------------------
85
2001 2002 2003 2004 2005 2006
Year
Sources: Data collected from the Enegy Inormation Admnistration, Assumptions to the Annual Energ 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 growt 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 thoughout the period.
The data show conventional CC and conventional CT experiencing a shar increase between 2001 and 2002.
After ths increase, conventional CC 1evels 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
Exhibit No. 11
Case Nos AVU-E-08-0l & AVU-G-08-0l
D. DeFelice, Avista
Schedule 1
Page 31 of 33
~28
Rising Utilty 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 constrction cost element has shown price changes at or near the rate of infation thoughout the
early par of ths 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 tye) in isolation between 2001 and
2004, without a systematic update of others. Meanwhile, durg the period that overall constrction costs
were rising well above the general inflation rate, EIA has not revised its estimated capital cost figues to
reflect ths trend.
EIA's estimates of plant costs do not adequately reflect the recent increase in plant constrction costs that
has occured in the last few years. Indeed, EIA itself acknowledges that its estimated constrction costs do
not reflect short-term changes in the price of commodities such as steel, cement and concrete.20 Whle one
would expect some lag in the EIA data, it is troubling that its most recent estimates continue to show the
constrction cost of conventional power plants increasing only at the general rate of inflation. Empirical
evidence shows that the constrction 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 importt
market impacts that are driving plant constrction costs, and. thus do not provide a reliable measure of curent
or expected constrction costs.
20 Annual Energy Outlook 2007, U.S. Energy Information Administration, p. 36.
Exhibit No. 11
Case Nos AVU-E-08-01 & AVU-G-08-01
D. DeFelice, Avista
Schedule 1
Page 32 of 33
29~
~ Conclusion
Constrction costs for electric utility investments have risen sharly over the past several years, due to
factors beyond the industr's control. Increased prices for material and manufactued components, rising
wages, and a tighter market for constrction project management services have contrbuted to an across-the-
board increase in the costs of investig in utility infrastrctue. These higher costs show no immediate signs
of abating.
Despite these higher costs, utilities wil contiue to invest in baseload generation, environmental controls,
transmission projects and distrbution system expansion. However, rising constrction costs wil 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 industr and on customers, however, wil be borne out in varous
ways, dependig on how utilities, markets and regulators respond to these cost increases. In the long ru,
customers ultiately wil pay for higher constrction costs--ither directly in rates for completed assets of
regulated companies, less directly in the form of higher energy prices needed to attact new generating
capacity in organzed markets and in higher transmission tarffs, or indirectly when rising constrction costs
defer investments and delay expected benefits such as enhanced reliability and lower, more stable long-term
electricity prices.
Exhibit No. 11
Case Nos AVU-E-OB-Ol & AVU-G-OB-Ol
D. DeFelice, Avista
Schedule 1
Page 33 of 33
31~
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