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BUSINESS CONFIDENTIAL:
PROPRIETARY INFORMATION - DO NOT
DISTRIBUTE AS A PUBLIC RECORD
Initial Project Feasibility Study
American Municipal Power
Generating Station Project
American Municipal Power - Ohio, Inc,
June 2007 This report has been prepared for the use of the client for the specific purposes identified in the report The conclusiona, observations
and reconnmendations contained herein attributed to R. W. Beck, Inc. (R. W. Beck) constitute the op&iions of R. W. Beck. To the extent
that statements, information and opinions provided by the client or others have been used in the preparation of this report, R. W. Beck
has relied upon the same to be accurate, and for which no assurances are intended and no representations or wan'anties are made.
R. W. Beck makes no certification and gives no assurances except as explicitly set forth in this report.
Copyright ©2 0 0 7, R. W. Beck, Inc.
Ail rights reserved. XECUTIVE SUMMARY
American Municipal Powe r- Ohio, Inc. ("AMP-Ohio") is planning to construct a 960
net megawatt (MW)^ coal-fired generating station consisting of two 480 MW units
which will be located in Meigs County, Ohio, in the township of Letart Falls. The
station is titled the American Municipal Power Generating Station ("AMPGS"), which
together with other facilities and arrangementSj comprises the AMPGS Project, also
referred to herein as the Project.
AMP-Ohio has engaged R.W. Beck, Inc. ("R. W. Beck") to provide Owner Engineer
("OE") services for the AMPGS Project which include, among other things, the
preparation of a Project Feasibility Study. The purpose of the Project Feasibility
Study is to (1) address the technical, operational, and financial implications and risks
of the Project, and (2) provide a comprehensive examination of the Project. Under
the terms of the contract with AMP-Ohio with regard to the feasibility of the Project,
R.W. Beck must provide the following: (i) an Initial Project Feasibility Study based on
the most recent infonnation available including updated costs of the Project, (ii) a
Final Project Feasibility Study based on updated infonnation available after the
selection of an Engineer-Procure-Construct ("EPC") contractor; and (iii) summary
reports for Project financing updated to reflect the most recent information available
as of the date of the associated Official Statement, This report constitutes the Initial
Project Feasibility Study (the "Report") and summarizes our work up to the date of
this Report.
As used in this Report, the capitalization of any word not normally capitalized
indicates that such word is defined in the particular agreement or other document
discussed. References to and descriptions of such agreements or documents in this
Report represent our understanding of certain general principles thereof, but do not
purport to be complete and are qualified in their entirety by reference to such
agreements or documents.
Description of AMP-Ohio Organization
AMP-Ohio was formed in 1971 under Ohio Revised Code Chapter 1702 as a nonprofit
corporation. AMP-Ohio operates on a cooperative basis for the mutual benefit of its
members, each of which owns and operates an electric utility distribution system and
in some cases generating assets. As of May 7, 2007, AMP-Ohio had 120 members
("Members") - 81 in Ohio, 26 in Pennsylvania, seven in Michigan, four in Virginia
and two in West Virginia. Since May 7, 2007, an additional borough located in
The 960 MW rating reflects the projected summer capacity rating of the Project. The annual average
rating is projected to be 987 MW.
[^VOrlandoV003834 AMP-Ohicj\02-01633-01000-OE ServiceWoit PTOd\)cts\Fmal Reporf£S.doc EXECUTIVE SUMMARY
Pennsylvania has become a member of AMP-Ohio. An additional city in Virginia,
Front Royal, may become a member.
History and Development of Project
In 2002, AMP-Ohio completed a strategic plan which included a 20-year power
supply needs analysis that identified the need for new base load generating capacity.
The plan led AMP-Ohio to undertake a conceptual feasibility study and other studies,
including evaluation of available base load power supply options, technology
considerations, site altematives, and fuel availability. In 2004, AMP-Ohio entered
into a developmental agreement with Virginia-based Blue Ridge Power Agency
("BRPA" or "Blue Ridge") and Michigan South Central Power Agency ("MSCPA'')
to continue to investigate the development of a new base load resource on a joint
basis. Certain members of BRPA and MSCPA are also Members of AMP-Ohio and
potential participants in the new base load resource.
AMP-Ohio signed a contract with the engineering firm Sargent & Lundy ("S&L") in
May of 2003 to provide various services associated with the early planning, evaluation
and development of a base load generating facility. These services included: (i)
technology analysis; (ii) site screening analysis; (iii) fuel availability and delivery cost
analysis; (iv) site selection; (v) schematic design; (vi) summary project information for
permitting; and (vii) Ohio Power Siting Board application. S&L provided a report for
each task that summarized the methods and results of the investigations and
evaluations. Based on the results of the site evaluation process and the final field
surveys, the Letart Falls site in Meigs County, Ohio, was chosen as the preferred site.
As follow-up to their initial services, S&L has provided information to support Project
permit applications and other studies.
Overview of the Project Arrangement
As of the date of this Report, it is contemplated that approximately 97.5 percent of the
AMPGS Project will be owned by AMP-Ohio and that AMP-Ohio will enter into takeor-pay power sales contracts with each of the participating AMP-Ohio Members
(including those that are also members of BRPA or MSCPA). The remaining 2.5
percent of tlie AMPGS Project would be owned by the Central Virginia Electric
Cooperative ("CVEC"). Contractual arrangements with respect to joint ownership and
the operation of the AMPGS Project have not yet been developed. However, each of
the two owners would be responsible for the financing of the respective ownership
interest. In the event CVEC decides not to participate as a co-owner, AMP-Ohio
expects to retain the CVEC share and own 100 percent of the AMPGS Project
The AMP-Ohio Members that are participating in the AMPGS Project will execute
power sales contracts with AMP-Ohio authorizing AMP-Ohio to finance, construct
and operate the AMPGS Project and specifying the Member's obligations to take or
pay for the power and transmission service firom the AMPGS Project under the terms
of the contract. Each participating Member will be entitled to receive a fixed
entitlement share of the output of the AMPGS Project at a "postage stamp rate" that
E S - 2  R .  W .  B e c k R:\OrIaiido\003834 AMP-OiiiQ\02-01633-01000-OEService\WoikProducts\FinalRepCff^ EXECUTIVE SUMMARY
will be designed to recover the fixed and variable costs of the AMPGS Project and
certain related transmission services.
AMP-Ohio intends to finance the cost of acquisition and construction of the Project
with revenue bonds authorized under a Master Trust Indenture and secured by the
power sales contracts with the Members.
Project Timeline
The overall Project development timeline has a target of April 2013 for the
commercial operation date of Unit 1 and October 2013 for Unit 2. As shown in the
timeline below (Figure I), the major milestones that are on the critical path of the
Project schedule include:
s Ohio Members Ordinances passed by October 1, 2007
m Power Sales Contracts with Ohio Members signed by November 1, 2007
o Out-of-State (outside of Ohio) Power Sales Contracts signed by March 2008
m Exercise land options in July 2008
n Complete EPC Contract Negotiations by March 2009
a All construction permits approved by March 2009
n EPC Contract final Notice to Proceed ("NTP") for construction by April 2009
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Figure 1 - Project Development Timeline
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Project Description
The proposed AMPGS Project is a 960 MW^ coal-fired generating station which is to
be located in Meigs County, Ohio, in the township of Letart Falls. Figure 2 illustrates
the AMPGS Project site location.
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Figure 2 - AMPGS Srte Location
The AMPGS Project site is a green field site with access to the Ohio River. Prior use
of the site was primarily for agriculture. In total, the Project facilities, including the
landfill, will have a footprint of approximately 1,000 acres, not including 600 acres of
AMP-Ohio owned land to serve as a buffer.
The AMPGS Project will be operated as a base load plant comprised of two nominal
480 net MW generating units. Figure 3 provides a conceptual rendering of the Project
site and equipment layout.
The 960 MW rating reflects the projected summer edacity rating of the Project The annual average
rating is projected to be 987 MW.
ES-4 R.W.Beck  Sj\OriaiM3o\003834AMP<>hio\02-01633-01000-OEService\WoAProducts>Piii3lR^K)iftES.d(w EXECUTIVE SUMMARY
Figure 3 - Conceptuai Rendering of AMPGS Project
The AMPGS will be required to comply with federal New Source Performance
Standards ('"NSPS") and will be permitted as a major new air emission source in a
location designated as an "attainment" area for all criteria pollutants, AMP-Ohio
submitted an application for a Permit to Install ("PTI") to the Ohio EPA in May 2006.
The application for the PTI specifies that the Project will install Best Available
Control Technology ("BACT") for control of emissions fi^om AMPGS, including a
filter baghouse to control particulates, low nitrogen oxide (""NOx") burners and
selective catalytic reduction ("SCR") for control of NOx and Powerspan Corporation's
("Powerspan") multi-pollutant control technology ("ECO-SO2 ") which will control
emissions of sulfur dioxide ("SOi")^ fine particulate matter using a wet electrostatic
precipitation ("Wet ESP"), mercury ("Hg"), and sulfuric acid ("H2SO4").
The Powerspan technology is discussed in further detail in Section 3 and Appendix D
of this Report. This new technology is a wet flue gas desulfurization ("Wet FGD")
system that uses urea, which will be processed to produce ammonia, which will then
be used as a reagent in the wet FGD process to reduce SO? emissions from the plant's
flue gas. The product from the reaction of SO2 and ammonia is a liquid ammonium
sulfate, which will be processed through a crystallizing process to produce solid
ammonium sulfate, a fertilizer, which can be sold in the fertilizer market.
This technology has undergone a 50 MW demonstration test, but will need to be
scaled up for application to the Project. In the event that the Powerspan technology
R;\OrIaiido«MJ3S34 AWP-Ohio\02-OI633-01000^E S(!rv«M\WorJ{ Products\FuiaI Report^ES.doc  R.W.Beck ES-5 EXECUTIVE SUMMARY
cannot be appropriately guaranteed by the EPC contractor for the AMPGS Project, a
limestone wet scrubber could be developed to satisfy air permitting requirements for
the Project.
The proposed two generating units are to be capable of burning a blend of Ohio,
Central Appalachian and/or Southern Powder River Basin ("SPRB") coals. Coal will
be delivered by barge to the generating station and will be moved to the site using a
conveyor system. The steam generators for each unit are proposed to be subcritical
pulverized coal ("PC") boilers that use natural gas as the startup fiiel.
The AMPGS Project also includes: (i) the construction of an on-site switchyard and a
double-circuit 345 kV transmission line from the AMPGS to an interconnection point
at an existing transmission line; (ii) a tie point for the natural gas supply pipeline to the
generating station; and (iii) an on-site solid waste landfill.
Estimated Capital Costs and Financing Requirements
The estimated capital costs for construction of the AMPGS Project are summarized in
the following table. The total constmction costs include EPC costs, transmission
facilities (including an on-site 345 kV substation), land and infrastructure upgrades
and owner's costs. The estimated value for the EPC contract is $2,148 billion for the
two units and includes all costs associated with the engineering, design^ equipment,
material, construction and start-up of the Project facilities, and a provision for
contractor escalation and contingency. A six percent contingency was included in this
EPC contract estimate.
Other Project costs which will be contracted, constructed and paid separate from the
EPC contract by AMP-Ohio mclude interconnectmg 345 kV transmission line (double
circuit), interconnection 345 kV switchyard, various electric system upgrades and land
and infrastructure upgrades. Total estimated costs for these Other Project costs are
$134.3 million.
Owner's costs are estimated to be $250.3 million (other than fmancing costs). Such
costs include owner's engineer, envhonmental consultants, financial and legal
consultants and AMP-Ohio staff expenses, initial inventories, spare parts, initial
working capital and $100 million contingency. As of the date of this Report, the total
cost of construction is estimated to be approximately $2,532 billion as summarized in
Table 1 below.
E S - 6  R .  W .  B e c k lt\Orlaiido\003834AMP-Obio\02-01633-010CW<IESemcB\WorkPrtxlurts\FiDalReporftES.doc EXECUTIVE SUMMARY
Table 1
Estimated Costs of ConstructionC^l
Description
Caoitai Costs
EPC Costs [2]
Other Costs:
Transmission Line and Interconnection Switchyard
Transmission System Upgrades [3]
Land and Infrastructure Upgrades [4]
Total Capital Costs
Owner 's Costs
AMP-Ohio Staff. Legal, Engineers and Consutting Costs [51
Taxes and Insurance
Initial Inventories and Spare Parts [61
Start-up and Commissbning Expenses
Working Capital [7]
Owner's Cost Escalation
Owner's Contingency
Total Owner's Costs (w/o Financing Costs)
Total Esfimated Costs of Construction
Dollars  in
Thousands
$2,148,180
24,000
65,000
45,300
$2,282,480
$49,300
28,000
35.000
10.000
5,000 •
23,000
100,000
250.300
$2,532,780
|1] The development of Ihe estimated costs of cmstnjction of Die AMPGS Project is set forth in Section 3.5 herein.
|2] Amount includes allowance for cost escalatjcn, EPC profit and 6% contingency on EPC costs.
[3] Estimated coste associated witii Ir^smission system up^ades rdated to Jnterrannec^ng the Plant to the PJM  s ^ e m.
Does not 'delude costs for potential transmission system upgrades r^ating to transmission senrices required to  d ^ i v^
capadty to the MISO Participants.
[4] Includes estimated costs of a gas Sne, land costs, rights of way, landfSI develt^ment ^ infrastructure cosb.
[5] Include iniBal developmental costs to date, Die estimated costs of AMP-Giio staff costs related to management of
perniitSng,  l i c ^ ^ g and the EPC open book process, legal, engine^s and other consulting  ^ .
|6] Includes an aBowance of $20 million for inittal fuel and other commodity ifurenfofies and $15 mfflion for in/fiai spars
parts nv^tory.
[7] Based on one month of fixed and variable opa^tion and maintenance costs (excluding fuel and other commodties).
As shown in the table below, the total estimated amount of bonds to fund the cost of
the Project including construction costs, interest during construction, deposit to a
Reserve Account (as required by the Master Trust Indenture) and bond issuance
expenses is estimated to be approximately $2,912 billion. AMP-Ohio's fmancing plan
reflects issuance of variable-rate debt on an interim basis during the construction
period to fund construction costs and interest during construction. Following the
construction period, AMP-Ohio would then undertake permanent financing of the
Project through issuance of fixed-rate long-term bonds that would refund the
previously issued interim variable-rate debt. The estimated bond financing
requirements are shown below in Table 2.
R;\OrIaiido\003834AMP<mio\02-01633-01«)0-OESemce\WoricPn3dtBls\FmalRapo^  R .  W .  B c c k  E S - 7 EXECUTIVE SUMMARY
Table 2
Total Estimated Bond Amount
Description
Estimated Bond Amount
Construction Costs [1]
Net Interest During Construction (2]
Deposit to Reserve Account [3]
Issuance Expenses [4]
Total Estimated Bond Amount [5]
Dollars in
Thousands
$2,532,780
270.722
71,336
37,303
$2,912,141
|1] Per Table 6-1.
[2] Esfimated amount to be deposited  in lihe interesl Account to pay interest on tionds out^anding to July 1,
2013. Net of eslimsled interest earnings at an assumed rate of 3.75 percent on unexpended tralances in
the Construction Fund, Interest AccouM and Reserve Account during ihe construction periwl 2005
through 2013.
[3] Estimated amount required to be deposfted mto Ihe Reserve Account based on ons-tialf of the es&nated
maximum debt sen/ice on all Project permanenl ddiL
[41 Estimated expenses associated with bond underwriter's fees, legal fees, and other expenses incurred in
connection with the bond financings. Such amcajnts were based on 0.5 percent of the prindpal amount
of Bonds issued prior to permanent finandng and 1 percent of the prnc^ial amount of Bonds issued in
2013 ibf permanenl financing.
15] This amount reflects 100 percent of the AMPGS Project AMP-Ohio's ownerehip share at 97.5 percent
would be $2,839,337,500.
Flans for Constructing and Operating the Plant
Schedule and Plan for Construction
Activities that are ongoing as of the date of this Report generally include permitting^
Participant approvals, and the solicitation of EPC contractor proposals. It is expected
tliat all the Participant contracts would be in place by March 2008. The initial EPC
contract for preliminary design would begin in June 2008. The EPC contract is
scheduled to be finalized by March 2009, followed by an EPC contract final NTP in
April 2009. The final land purchase of the site is assumed to occur in July 2008. The
last permit approval required is scheduled for February 2009. The estimated EPC
schedule for engineering, procurement and constmction of Unit 1 is a 48-raonth
schedule beginning in April 2009 and ending with substantial completion in April
2013. The Unit 2 commissioning and substantial completion is assumed to occur
approximately 6 months later than Unit 1, or October 2013.
AMP-Ohio plans to contract with a single firm to engineer (and design), procure the
equipment, and construct ("EPC") the plant. This method reduces the number of
contracts executed which makes contract administration by AMP-Ohio less labor
intensive than having to negotiate several large contracts to accomplish the same tasks.
It also minimizes many of the risks associated with interfacing and coordinating
between different contractors.
In conjunction with using the EPC contracting method, establishing the contract as a
fixed-price contract will mitigate some of AMP-Ohio's risk in meeting the Project's
E S - 8  R .  W .  B e c k R;\Ortanao\003834AMP-Caite\02-01633-01000-OESemce\WoAPloducts\FmalR^or6ES.doc EXECUTIVE SUMMARY
schedule and budget. The key to successfully implementmg a fixed price EPC
contract is a well defmed scope of the project. A method for helping to assure that the
scope of the Project is defmed to a sufficient level of detail and that both AMP-Ohio
and the EPC contractor understand and agree on the scope is to develop the design of
the plant to a sufficient level of detail before fixing the price and the schedule. To
assure that AMP-Ohio is receiving a fair price and schedule for the Project, this upfront design work will be conducted under an "open book" policy which will provide
details (i.e. scope of work, scope of supply, plant performance, price, and schedule
guarantees) required to finalize the EPC contract between AMP-Ohio and the EPC
Contractor.
The EPC contract will cover the majority of Project facilities to be constructed, except
for the natural gas supply to the plant, the construction of the on-site switchyard and
transmission line from the plant site to the tie-in point with the existing transmission
grid, construction of transmission upgrades, the on-site landfill and communication
ties to AMP-Ohio's communication system. Design, procurement and construction
for these other facilities would be performed under separate contracts.
Plant Operation and Maintenance
As of the date of this Report, AMP-Ohio intends to assume the responsibilities of
operating and maintaining the Project. This includes fuel procurement, fuel and ash
handling, general materials procurement, environmental reporting and the overall
operation and maintenance of the plant. AMP-Ohio plans to contract with The
Andersons (a national agriculture company) for an initial 5-year period to operate and
maintain the fertilizer plant, including procurement and supply of urea and marketing
of the ammonium sulfate fertilizer produced from the Powerspan emission control
system.
A projection of the performance, commodity prices, and operating expenses of the
AMPGS Project for the period 2013 - 2032 is set forth in Attachment ES-1. The
estimated operation and maintenance expenses for the Project are summarized in
Table 3 below. Details associated with these estimates are included m Section 4,
Section 6 and Attachment ES-1.
Tables
Estimated Production Related O^M Expenses [1]
Category
Total Fixed OaM,$/kW-year
Variable 0&M.$/MWh
Fuel,$/MWh
Total Annual Operating Costs, $/i\^Wh
2013$
38.60
8.59
19.94
33.72
[1] Includes total lixed O&M, variable O&M, and fuel, including allowance costs {HOt. SO2, Hg and CO:).
R:\Oriando\003834 AMP<»h!o\{)2-01633-01000-OEService\WoikPrD(!ucts\Fiiia!R^  R .  W .  B c c k  E S - 9 EXECUTIVE SUMMARY
Fuel and Transportation
A blend of local high sulfur content coals with lower sulfur content coals is planned
for the fuel supply to AMPGS. Such blending is due to the typically high sulfur
content of the Ohio and other local bituminous coals. Blending Ohio coal is desirable
even though it is higher in sulfur because it has lower transportation costs, which make
it attractive for use in blending. In addition, there is also a possibility that a tax credit
or another type of credit could be granted for using Ohio coal. Preliminary coal
blending plans include options to blend Ohio coal and SPRB coal ("Western Blend")
or a blend of Ohio coal and Central Appalachia coal ("Eastern Blend"). Table 4 below
summarizes these coal blends and the estimated delivered cost
T a b le 4
Fuel  S u p p ly  C h a r a c t e r i s t i cs  a nd  C o s ts  f or  E a s t e rn  a nd  W e s t e rn  B l e n ds [1]
Percent Ohio Fuel (%1
Annual Tons for Blend [2]
Heating Value for Fuel Blend (Btu/lb)
Sulfur Content for Fuel Blend (%)
Ash Content for Fuel Blend {%)
Delivered Fuel Price for Blend ($/MMBtu) [31
Eastern Blend
34.00
66.00
(WV medium sulfur)
2.815,705
12.051
2.11
10.83
2.14
Western Blend
51.80
48,20
(SPRB)
3.338,354
10.535
1,84
7.85
2.18
[1] Based on information from Sargent & Lundy's Fuel Forecast Update, Report Number SL-008668, dated January 2006.
[2J Fuel consumption values are based on average annual plant output of 987 MW (net); design heal rales of  9 , ^3 Bftj/kWti (Eastern  B l a i d)
and 9,570 Btu/kWh (Western Blend); and an annual average capacity fector of 85 pacenL
[3] Fuel prices are escalated values for delivery In 2013.
The analyses in this Report reflect the Eastern Blend, since it results in the most cost
effective fuel blend as of the date of this Report. However, coal prices and
transportation costs are subject to market pressure that can affect the price of the
blends. To allow the flexibility to use a cost effective fuel blend during the operation
of the plant, a design basis fuel will be defined for the EPC Contract specifications;
however, efforts will be made to use equipment that can process both an Eastern Blend
and a Western Blend. A fuel supply plan will be developed, followed by the selection
of the final coal blends and final contract negotiations with coal suppliers and with rail
and barge transportation companies. It is anticipated that prior to issuing the EPC
contract, the contracts (or letters of intent) for the coal supply and its transportation
will be executed.
E S - 1 0  R .  W .  B e c k R:\OrIando\OO3S34 AMP-Ohio\02-0:633-01000-OESCTvice\Wo4Products\FiiislReport\ES.doc EXECUTIVE SUMMARY
Environmental Considerations and Requirements
The Project is being planned to include air emission control systems to comply with
the expected regulatory requirements, based on information in the air permit
application for the Project. The following emission limitations are expected:
Tables
Proposed Air Emission Limits and Controls
Pollutant Control Systems
Emission Limit
(Ibs/MMBtu)
SO2 Powerspan Wet Scrubber 0.15
NOx Low NOx Burners and SCR 0.07
PUfPmO Baghouse/Wet ESP 0.025
Hg[1] Baghouse/Powerspan Wet Scrubber 4.3x10-6
[ I] Hg limit allow? flexibility for die use of varying fuel blends (i.e. Eastern and Western blends).
The Project will be subject to certain environmental requirements that include, but are
not limited to: (i) NOx and SO2 allowance obligations, including those required under
the Clean Air Interstate Rule ("CAIR"); (iii) mercury emissions allowances
obligations under the Clean Air Mercury Rule ("CAMR") which includes the
establishment of a cap and trade program in which states, including Ohio, may choose
to participate; and (iv) potential CO2 emission allowances obligations in the form of
either a carbon tax imposed on emissions of CO2 or some form of a cap and trade
system comparable to what presently exists for SOo and NOx emissions.
The impact of complying with the these rules has been estimated in the projected
operating results discussed in Section 6 by assuming that the Project will purchase
allowances from the market. A carbon tax ranging between $5/ton to $15/ton (in 2006
dollars) is assumed to be in place beginning between 2012 and 2018. While there are
different points of view and opinions on the CO2 tax levels that may be imposed, the
$5/ton to $15/ton range, in R. W, Beck's view, represents a reasonable assumption for
the initial years of carbon regulation as supported by opinions expressed by other
investigations and trading of CO2 credits in European markets. Higher CO2 tax levels
may impact the AMPGS Project as well as the entire electric utility market in ways not
identified in this Report. Projections of allowance costs for SO2 and NOx are based
on EPA estimates and R, W. Beck's proprietary model that projects the marginal cost
of pollutant reductions to comply with the Acid Rain and CAIR regulations.
Projections of allowance costs for Hg are based on EPA estimates and R. W. Beck's
data base of mercury control costs for compliance with CAMR. The actual price of
allowances in the future will be market dependent and could be lower or higher than
the cost estimates herein.
R;\Orlaiido\003834AMP-Oh)o\02-Ol633-0!000-OESemce\WoricProducts\FmalRepo^  R .  W .  B o c k  E S - 1 1 EXECUTIVE SUWIIWARY
Status of Permits and Licenses Required
The Project must be constructed and operated in accordance with applicable
environmental laws, regulations, policies, guidelines, codes and standards. Based on
our review, AMP-Ohio has identified the major permits and approvals necessary for
the construction and operation of the Project. AMP-Ohio is presently in the process of
applying for/obtaining the key permits and approvals required to construct and operate
the Project.
Required Transmission Services
To deliver the output of the AMPGS Project, AMP-Ohio must: (i) interconnect with
PJM^ through PJM's generator interconnection process as a Capacity Resource; and
(ii) obtain firm point-to-point transmission service under the PJM Open Access
Transmission Tariff ("PJM OATT*') to deliver the Project output (or a portion thereof)
to the MISO"^ border for those Participants that are located within MISO. As of the
date of this Report, AMP-Ohio is in the process of taking the necessary steps to obtain
these services.
Studies conducted as of the date of this Report by PJM indicate that the direct
interconnection facilities for the Project totaling approximately $24 million include the
construction of a double-circuit 345 kV transmission line from the Project to an
interconnection point at an existing transmission line located approximately five (5)
miles from the Project site. In addition, interconnection service requires the
construction of approximately $58 million in transmission upgrades to the existing
transmission system. These costs have been included in the capital costs of the
Project. However, studies remain to be performed for point-to-point transmission
service to MISO and for transmission service within MISO. There is also a schedule
risk related to the time it will take to go through the interconnection process and
construct the necessary transmission upgrades. Most of the required upgrades are
estimated to take 12 months; however, some projects could take longer due to
equipment lead times.
The System Impact Study conducted by PJM also identified certain conditions under
which the plant output could be curtailed to 0 MW. One of these conditions is the
outage of a transformer, and a failure of the transformer could mean a long outage
(multiple months) for both the transformer and AMPGS. For purposes of this
3
PJM Interconoection (PJiVI) is a regional transmission organization (RTO) that coordinates the
movemenl of wholesale electricity over thirteen states in the northeastern United States. PIM
provides open access to transmission markets, long-term transmission planning and reliability, and
operates a wholesale energy market. PJM's energy markets operations include Day-Ahead, Real-Time
and Financial Transmission Rights markets. PJM also operates capacity markets.
The Midwest Independent Transmission System Operator, Inc. (MJSO) is a non-profit, member-based
organization that provides open access to transinission markets, long-term transmission planning, and
transparent prices and manages the security-constrained economic dispatch of generation over its
fifteen state territory. MISO's energy markets operations include Day-Ahead, Real-Time and
Financial Transmission Rights markets.
E S - i 2  R .  W .  B e c k R;\OrlaiidoN003S34Al^-Ohio\02-01633-010000EServk<AWoAProdiicts\Fmal^^ EXECUTIVE SUMMARY
Feasibility Study, we have assumed a $7 million cost to purchase a backup
transformer to mitigate this risk and have included this cost in the capital cost of the
Project.
Lacking studies from PJM and MISO concerning additional transmission service or
modifications to existing transmission service, we cannot know what potential
transmission upgrades might be required. AMP-Ohio has initiated load flow studies to
estimate the potential transmission upgrade costs to provide point-to-point
transmission service from the Project to the participants in MISO.
Another risk that all power supply ahematives face is pricing differentials between the
point of delivery and the point of receipt. la a Locational Marginal Pricing ("LMP")
market such as PJM and MISO, this "basis differential" risk consists of three parts: (i)
energy market basis differentials caused by congestion and marginal losses; (ii)
capacity market basis differentials due to implementation of a location based capacity
market which PJM implemented June 1, 2007; and (iii) potential p^ c aked charges
(the Project will bear charges in the form of RTO administration fees and ancillary
services charges for tlie point-to-point service to the PJM/MISO border based on the
existing PJM and MISO rate design). Additionally the Project could bear wheeling
charges based on any FERC approved transmission cost allocation methodology for
new transmission facilities. While these risks are not expected to be as significant as
the risks of new transmission upgrades, conditions can change over time.
Projected Operating Results of the AMPGS Project
R. W. Beck has prepared projections of the net power costs that will be the basis of the
charges to the Participants for the AMPGS Project ("Projected Operating Results") for
tlie period 2013 through 2032. These Projected Operating Results reflect 100 percent
of the costs of the AMPGS Project^ and are consistent with our understanding of the
terms and conditions of the drafts of the Power Sales Contract and Master Trust
Indenture, both dated as of April 2, 2007. The Projected Operatmg Results set forth
the costs that comprise the Postage Stamp Rate ("PSR") as defined in the Power Sales
Contract. The PSR is a uniform rate that will apply to all of the Participants. The
Projected Operating Results also include a projection of the activities in the funds that
are defined in the Master Trust Indenture and Power Sales Contracts.
Control of greenhouse gases such as CO2 is receiving a great deal of attention within
the United States Congress and many state legislatures. The predominant sentiment is
that regulation is inevitable and only the timing and metliod of regulation is not
presently known. In preparing the Projected Operating Results and other economic
analysis included in this report, we have assumed that there will be a carbon tax
imposed on emissions of CO2 or some form of a cap and trade system with CO2
emission allowances comparable to what presently exists for SO2 and NOx emissions.
Because CVEC will own approximately 2.3 percent of the AMPGS Project, the AMP-Ohio ownership share will
be approximately 97.5 percent which is less thsn 100 percent. However, we for purposes of the projections set
fortb here we have reflected 100 percent of the costs and output of the AMPGS Project.
R:\CWando\003834AMP-01uo\02-OI633-01000-OEService\WorkProducts\FmalI^  R .  W .  B c c k  E S - 1 3 EXECUTIVE SUfMMARY
The Projected Operating Results are set forth as Attachment ES-2 at the end of this
Executive Summary and are based on the principal considerations and assumptions set
forth in Section 9 of the Report. A summary of the projections are shown below in
Table 6 for selected yeaxs.
We have also estimated the Participant sales of energy from their share of the AMPGS
Project which are projected to be in excess of their load requirements and are assumed
to be sold into the market. The total estimated surplus energy amounts for each year
are shown on line 65 of Attachment ES-2. Such amount represents approximately 2.5
percent of the AMPGS Project energy. The estimated revenues from the sale of the
surplus energy into the wholesale market for each year are shown on line 64. The
projected net costs to the Participants after the credits for surplus energy sales shown
in dollars and on average ($/MWii) are set forth on Imes 61 and 69 of Attachment
ES-2.
E S - 1 4  R.  W .  B e c k R:\Orlai]do\W3834AMP<)hio\02-0163^0IOOO-OEService\WorfePioducts\FiaalRepo^^ EXECUTIVE SUMMARY
Table 6
Summary of AMPGS Projected Operating Results
Description 2015 2020 2025  2030  2032
Revenues:
1 Participant Revenues [1]
2 Otiief Revenues [2]
3 Total Revenues
Operating Expenses:
4 Fixed Operating Ct3sts [31
Variable OpsfBling Costs:
5 Fud Costs
6 Non-Fu^ Variable Operating Costs [4]
7 Variable Operating Cosis
fl Replacement Power 15)
9 Tofa/ Oper^ing Expenses
iO Net Revenues [6]
11 Deposit  to Worldng Caprtal Reser/e Account [7]
12 Debt Service [8)
13 Deposit to Reserve & Contingency Fund |9]
14 Total Revenue Requirements
Unit Operation:
15 Net Opacity
16 Gross Energy
17 Plus: Replacement Energy Purchases
18 Less: Surplus Energy Sales [IQJ
19 Net Energy
20 Capacity Factor
Average Projed Costs {with C02):
21 Net Fixed CMS
22 Net Non-Fuel VanaWe Costs
23 We( Fuel Costs
24 Average Costs to Participants
Average Project Costs (w/o C02):
25 Average Costs to Pafticipanfs [11]
$000
$000
$000
$000
$458,230 $537,820 $590,968 $654,258 $684,523
41.360 48,195 51,150 53.025 53,178
$499,590 $588,014 $642,118 $707,283 $737,700
$43,723 $48,522 $53,925 $60,009 $62,651
$000
$000
$000
$000
$000
$000
$000
$000
$000
$000
MW
GWh
GWh
GWh
GWh
%
$/m-mo
SMW)
$MM}
mm
152.332
94.361
246.693
21,731
312.148
$187,442
1.301
169.220
16,922
$499,590
960.0
7,349^
303.0
(504.0)
7.14a2
85.0%
18.36
13.20
20.73
64.10
168,821
154.043
322,869
26.822
398.213
$187,801
1,659
169.220
16.922
$586,014
960.0
7,349.2
303.0
(504.0)
7,148.2
85.0%
. 18.66
21.55
22.97
75.24
193,838
176,872
370,710
29,449
454,084
$188,034
1.892
169.220
16.922
$642,118
960.0
7.349.2
303.0
(504.0)
7.148.2
85.0%
. 19.12
24.74
26.38
82.67
224,709
203.756
428,465
29.314
517.788
$189,494
2,157
169.220
18.117
$707,283
960.0
7.349.2
303.0
(504.0)
7.148.2
85.0%
19.60
28.50
30.58
91.53
238.191
215.851
454,042
30.510
547.204
$190,497
2.280
169.220
18,997
$737,700
960.0
7.349.2
303.0
(504.0)
7.148.2
85.0%
20.01
30.20
32.41
95.76
$/Mm
56.81  60.87  66.50  73.32  76.67
[1] Participant Revenues are equal to Total Revenue Requirements (loie 14] less other revenues  i }m 2).
(2J Includes interest eamhgs. short-term market sales, iransf^s from R&C Fund and other Project revenues (if any).
[3] Inckides fixed O&M, fransmission costs, insurance, property taxes, AMP-Ohio A&G costs and bank and  ^ s t ee fees.
[4] Includes environmental costs (including estimated CO2 and mercury emissions costs), variable O&M, Powerspan cosis and credits for
tertaizer sales.
[5] Estimated cost of replacement power purchased from the short-temi energy market to replace AMPGS during scheduled and forced
[6] Equal to Total Revenues (line 3) less Total Operating Expenses (line 29).
{7] Deposit to Wwkirig  C a p^ Resen/e Account equal to 5% cJ the total montiily  O p e r ^g Expenses.
[8] Estimated debt sen/ice on Bonds projected to be issued to ifeiance the total cost of construction of the AMPGS Project
[9] Deposit to Renewal & ReplacemenI Account equal to the greater of 10% of Debt Sen/ice or Ihe esfimated renewals & replacements lor
such year.
[10] The quantity of short-tenm market energy sales thai are expected to be in excess of the energy required under Ihe Power Sales Contracts
wi&i Ihe Participants.
[11] Net Piojed costs without CO; emissions costs
R;\Orlando\003834 AMP-Ohio\(12-0I633-01000-OE ServiceWoric Pioduc(s\Fmal Report\ES.doc  R.W.Beck ES-15 EXECUTIVE SUMMARY
The development of the average AMPGS Project costs in $/MWh is shown on lines 45
through 59 of Attachment ES-2. The major components of the average annual Project
costs are shown below in Figure 4. Net debt service, which represents approximately
29 percent of the total costs, equals the total debt service, payments less interest
earnings. Fuel cost represents approximately 34 percent of the total costs and includes
the cost of coal purchases and coal transportation costs. CO2 costs make up
approximately 18 percent of the total costs and assume that a CO2 tax would be put m
place sometime during the period 2012-2018. Other environmental costs represent
approxiraately 6 percent of the total costs and include emission costs and/or allowance
costs related to SO2, NO^, and Hg. Other net operating costs include all other
operating costs (net of other revenues) and represent approximately 13 percent of the
total costs.
Annual Costs by Category ($/(\flWh)
$i2a.oa
sioo.ao
DCO2 Costs
•Other Environmerri^
Casts
DFuel Costs
QNel Opeisling Costs
DNel Debt Service
n 1 m lo f~
o a o o a
N N N M f«<
N <-) ^ in o (». «o
n  fj w
O t- M
Figure  4 - Projected Annual Power Costs by Category ($/IWWh)
ES-16 R.W.Beck  R:\Orlando\003834 AMP-O1UQ\02-0 1633-01000-OE S«vice\Wori: ProduclsNFmal Report\ES.doc EXECUTIVE SUMMARY
AMPGS Project Participants
There are 87 Members of AMP-Ohio that are participating m the development of the
AMPGS Project (the "Participants"). The Participants consist of 29 cities and 46
villages in Ohio, 2 boroughs in Pennsylvania, 3 cities and 1 town in Virginia, 3 cities
and 2 villages in Michigan and 1 city m West Virginia.
As set forth in Appendix A of the draft Power Sales Contract dated April 2, 2007, each
of the AMPGS Participants has initially committed to a Project entitlement share of
the AMPGS Project refenred to as the Power Sales Contract Resource Share ('TSCR
Share"). A list of the Participants and their respect PSCR Shares is shown on
Attachment ES-3^ included at the end of this Executive Summary.
The Participants' power supply arrangements may vary based on, among other things,
the power pool or investor-owned utility service area in which their system is located.
The majority of Members are associated with one of AMP-Ohio's power pools.
AMP-Ohio Members currently receive their power supply from a mix of resources
that includes:
0 wholesale power purchases through AMP-Ohio and on the open market
from investor-owned utilities and marketers;
s energy produced at AMP-Ohio's 213 MW, coal-fired Richard H. Gorsuch
Generating Station near Marietta, Ohio;
E3 individual community-owned generation facilities; and
n mtmicipal generation joint ventures, including the 42 MW Belleville
Hydroelectric Project at the Belleville Locks and Dam on the Ohio River;
the 7.2 MW AMP-Ohio/Green Mountain Energy Wind Farm located near
Bowling Green, Ohio and approximately 334 MW of distributed generation
(either owned by AMP-Ohio or a municipal joint venture) strategically
sited throughout the state, using natural gas and diesel technology.
The five Participants in Michigan are members of MSCPA which owns and operates a
50 MW (summer rating) power plant in Litchfield, Michigan on behalf of the MSCPA
members. These five Participants also own 76 MW of peaking units and hydro
resources. Also, MSPCA purchases partial requirements service from AMP-Ohio on
behalf of the MSCPA members.
The four Participants in Virginia are members of BRPA. These four Members have
purchased all requirements power from AMP-Ohio since July 2006.
Figure 5 below shows the total of the 87 Participants' projected peak demand, total
capacity requirements (peak demand plus an allowance for 12 percent reserves).
As of Hie date of this Report, there are 87 Participants, Front Royal, Virginia, is neither a Member of AMP-Ohio
nor a Participant in the AMPGS Project. However, AMP-Ohio anticipates that Front Royal may become a
Member and Participant in the AMPGS Project.
Attachment ES-3 is a copy of Appendix A taken from a draft of the Power Sales contract dated April
2, 2007 discussed below.
R:\Orlaado\003834 AMP-Ohio\02-01633-01000-OEService\Wcff^kPrQductE\FinalRepa^  R .  W .  B c c k  E S - 1 7 EXECUTIVE SUMMARY
existing power supply resources (coal, hydro, diesel, gas, wind and purchased power),
the projected 960 MW of capacity from the AMPGS Project, and additional future
power supply resource requirements over the period 2008-2027.
As can be seen from the figure, the capacity of the AMPGS Project is needed to fill
the base-load requirements of the Participants on a total aggregate basis.
t»
n
5
A  C A n CO.
4,bUU '
4,000 •
3,500 •
3,000 •
2,500 -
2,000 '
1,500 '
1,000 •
500 -
: .  ' - ' - ^ r ^ H ^ ^
:  • . . . .  ^ ^
I .... „-4i-*-^;fr^*1
.  - t-
•
.—1
.
1
;
^ /^
^,
==-^
. . . 4 > -
•
. 1 ^  ^ -
r-^v-
1 • ' •  • r - - - -  i- •  - -•
s ^
^*-^-'
^ ^
" t i i i 1 * " '
- ^
" ^
^ . . - ^ -
,r.-
^ ^
=-^-
^ .r
. --
.^^-^'^
^ ^ ^ J ^ ^ S
. .
c i o o - B - e s ^ r 3 ' ! j « 5 t o i ^ c o o i O T - N r o ' ! j i O ( O b .
a O t - T - t - t - - s - T - r - T - T - T - W M N M M r f M N
o o o o o o o o o o o o o o o o o o o o
OJ C4 M M CJ M  w Ol M w ra M
f^ CM (M  IN M M M
(
bxisting Coal  b ^ ^ ^ t ^ i s H na Hvdro 1
Existing Purchases
Existing Wind
Existing Diesel
i _ . -JO
1  ! •-
i . JA
ther
xisting Gas
MPGS
1 iFiihjrp RpfitiirfmRnts '™^*-"-^Pftak fferp^nfi
" r<~ Capacity Requirements
CM
Figure 5 - AMPGS Participants' Projected Load and Existing Capacity Resources
(Including AiillPGS)[1]
I I] Excludes demand, existing capacily, resources, and capacity from AMPGS for Front Royal and CVEC. Assumed on-line
dates of April 2013 for AMPGS Unit 1 and October 2013 for AMPGS Unit 2.
Power Sales Contracts Between AMP-Ohio and the
i d
The Power Sales Contract is the agreement that sets forth the rights and obligations of
AMP-Ohio and each Participant with respect to the AMPGS Project, Given the
corporate structure of AMP-Ohio, the governing bodies of the Members that enter into
contractual arrangements with AMP-Ohio must authorize an ordinance that provides
authority for the Member to enter into tiie Contract. Accordingly, with respect to the
ES-18 R.W.Beck  R:\OrIaDdo\003S34 AMP-Oliio\02-01633-01000-OE SwviceWorf: Prpducts\Fioal Report\ES.doc EXECUTIVE SUMMARY
Power Sales Contracts for the AMPGS Project, each Participant will be required to
pass an ordinance by their local governing body. The ordinances for the AMPGS
Project Power Sales Contract have been prepared for authorization by the governing
body of each Participant to authorize execution of the Power Sales Contract by the
Participant.
The Power Sales Contract referred to herein is the draft version of the document dated
as of April 2, 2007, Under the Power Sales Contract, the Participant is entitled to
receive its PSCR Share of the nominal power and associated energy from the Power
Sales Contract Resources, which include the electric power and energy firom AMPOhio's ownership share of AMPGS, all sources of replacement power, and certain
transmission services. See Attachment ES-3 for the respective PSCR Share for each
Participant These are the amounts set forth in the Power Sales Contract as of April 2,
2007. The final BSPR Shares will be determined after all Participants have passed
ordinances and executed the Power Sales Contract.
The Power Sales Contract is a "take or pay" contract between AMP-Ohio and each of
the AMPGS Participants, whereby those Participants agree that, in order to obtain
power and energy from the Power Sales Contract Resources, they are willing to pay
for their respective rights to that power and energy at rates sufficient to enable AMPOhio to recover all of its costs incurred with respect to the AMPGS Project. The
Participants are obligated to take or pay for their respective PSCR Share whether or
not the Power Sales Contract Resources are complete, operable, or operating.
Under the Contract, all costs of the Project as set forth on monthly invoices from
AMP-Ohio, including debt service, are to be recorded as an operation and
maintenance expense of the Participant's electric system fund. Debt issued to finance
the Project will be recorded on the books and records of AMP-Ohio. No AMPGS debt
will be recorded on the books of the Participant.
The Board of Trustees, after consultation with the Participants Committee (discussed
below), shall establish, maintain and adjust rates or charges, or any combination
thereof, for the capacity and output of the Power Sales Contract Resources sold to
Participants under this Contract. A Postage Stamp Rate and other rates and charges
under the Contract will be set at levels that are sufficient to meet the Revenue
Requirements of AMP-Ohio.
Project governance will be the responsibility of the AMP-Ohio Board of Trustees and
the Participants Committee, which is a committee of the Board of Trustees formed by
the Participants pursuant to provisions in the Power Sales Contract.
The by-Jaws of the Participants Committee are set forth in Appendix L of the Power
Sales Contract. The Participants Committee will review construction progress,
insurance, interim construction financing including capitalized interest, permanent
financing and other plant operating matters. The Participants Committee will also
make recommendations for rate setting to the Board of Trustees. The Participants
Committee will consist of Participants that in total comprise at least 51% of the
entitlement shares of AMPGS.
R;^Orlalldo\003834AM^OIlio^02•0I633-01000-OEService\WoI^cPToducts^F^lalRepor1\ES.d^  R .  W .  B e c k  E S - 1 9 EXECUTIVE SUMMARY
Some actions and authorizations require the approval of a Super Majority of the
Participants. A Super Majority of the Participants is defined as 75% of the
entitlements of all Participants.
Section 18 of the Power Sales Contract addresses the terms and conditions that are
applicable in the event of a defauh by a Participant due to non-payment or other acts
that would cause suspension of the rights of the defaulting Participant under the
Contract. In certain defauh events, each non-defaulting Participant will be required to
purchase a pro rata share of the defaulting Participant's entitlement to its PSCR Share,
and this amount is referred to in the Contract as "Step Up Power". The amount of
Step Up Power will not exceed an accumulated maximum kilowatts of 25% of the
non-defaulting Participant's original PSBR Share in kilowatts without the consent of
the non-defaulting Participant. Notwithstanding the provision for Step Up Power
under the Power Sales Contract, a defaulting Participant is not relieved of its
obligations under the Power Sales Contract.
Section 31 of the Power Sales Contract addresses various matters concerning the term
of the Contract, including the effective date, the period over which the Contract will
remain in effect, and termination by a Super Majority of Participants. Unless
otherwise terminated, the Contract will remain in effect until February 28, 2057, and
thereafter until all principal of, premium if any, and interest on all Bonds have been
paid or deemed paid in accordance with the Trust Indenture. The Participant remains
obligated to pay its respective share of the costs of terminating, discontinuing,
disposing of, and decommissioning all Power Sales Contract Resources.
This section also includes a provision allowing Participants that execute the Contract
prior to September 1, 2007, a one-time option to reduce the requested PSCR Share or
repudiate the Contract upon certain notice provision to AMP-Ohio and prior to the
defmed "Effective Date" of the Contract. The Effective Date of the Contract is the
date that is the later of March I, 2008, and the date, not later than January 1, 2009,
upon which Power Sales Contracts between AMP-Ohio and Participants have been
executed such that the aggregate PSCR Shares of such Participants are not less than a
nominal 750 MW.
Participant Need for Af^fiPGS Project
In late 2006, AMP-Ohio contracted with R. W, Beck to develop long-term power
supply plans for 119 of its Members. R. W. Beck prepared a report for each Member
that included a 20-year load forecast, a 20-year optimal power supply plan and the key
inputs and assumptions used to develop the plan. These reports were delivered to
AMP-Ohio and its Members in February 2007 (the "February 2007 Member Power
Supply Analysis").
hi developing the plan for each Member, a generation expansion plan was developed
assuming that the Member could participate in "slices" of future AMP-Ohio
generating resources equal to 15 percent of the Member's projected 2027 peak
demand (plus an allowance for 12 percent reserves). The generating resource options
included in this study were future generic base load coal, natural gas-fired combined
E S - 2 0  R .  W .  B e c k R:^ilairfo\003834AMP-Ofaitffl2-4)1633-0l000-OESeivice\WorkProdflCls\FffialR(TC^ EXECUTIVE SUMMARY
cycle and peaking resources, the AMPGS Project, the Prairie State Energy Campus (a
proposed mine-mouth coal plant in Illinois, referred to herein as "Prairie State"),
proposed AMP-Ohio hydroelectric plants along the Ohio River, and future wind
plants. The purchase power options included a 5-year peak load, 5x16 contract (five
days a week for 16 hours per day) and a 10-year baseload, 7x24 (seven days a week
for 24 hours per day) contract, as well as spot market purchases. The generation
expansion plan was developed by considering shares (in terms of slices) of each of
these options. The optimal power supply plan was developed by selecting the optimal
power supply strategy (amount and timing of resource additions) that minimized the
total net present value of power supply costs and risks over the 20-year period 2008-
2027. The AMPGS Project was included as an option for those members that are
participating in the development phase of the Project. The Prairie State project and
hydro projects were included as an option for all Members.
The initial power supply plan developed for each member was intended to give that
Member an indication of the optimal amount, timing, and type of power supply
resources needed over the 20-year study period. Over the short-term, this plan
provided each Member guidance on project participation levels among the future
AMP-Ohio generation projects currently planned. Over the longer-term, the plan will
be adjusted to take into consideration actual costs and other knowns that were
projected in the initial plan and new market conditions and resource options.
In developing the plan for each Member, R. W. Beck utilized its Stochastic
Econometric Regional Forecasting ("SERF") model and power supply pl aning
approach. SERF generates stochastic^ projections of fiiel and power prices, utility
loads and corresponding power costs for multiple portfolios of power supply
resources. Using the SERF model, R.W. Beck developed stochastic projections of
future power supply costs for each member using several alternative possible
portfolios of resources, and identified the power supply {X)rtfolios that resulted in the
lowest costs and risk to each Member over the 20-year period 2008-2027
A summary of power requirements and future resources for the aggregate of the
optimal power supply plans for all the AMP-Ohio Members under Uie Base Power
Supply Plan developed in February 2007 is sunmiarized below. Figure 6 shows the
aggregate of the 119 AMP-Ohio Members' projected peak demand, existing power
supply resources and future power supply resources over the period 2008-2027. As
can be seen from Figure 6, the need for future capacity and energy resources by 2013
is approximately 2,947 MW and increases to 3,360 MW by the end of the study
period.
Stochastic projections reflect the uncertainty and volatility in forecasting variables such as fuel costs
and electric loads. A stochastic projection is usually captured by forecasting future values based on
past economic behavior and numerous future outcomes. The resulting stochastic projection provides
a range of potential values instead of one forecasted value.
R;\Oriando\003gMAMP<)hio\02-01633-01000-OESemce\WorkProdiJcts\Find}tep(»t^  R .  W .  B e c k  E S - 2 1 EXECUTIVE SUMMARY
t - r - r - T - T - T - T - M M M C M C M M M N
o o o o o o o o o o o o o o o
' ' I Existing Coal
I I Other
:] AMPGS
35x-\S
E S ^a Purchases
C^ IZJ Existing DisssI
iEsisling Hydro
i l : £ >^ New Ccal
!• I Prairis State
' IG-ClassCC
r ^ —I F-Class CT
- *• Peak Demand
3 Existing Purchases
37x24
i : : ; ^ : ^New Hydro
t- •••--'Existing Wind
' I Existing Gas
'-; Capacity Requirements
Figure 6 - AMP-Ohio Grand Total Power Supply Plan - Base Case
The timing, amount of capacity and type of capacity resources needed as indicated by
the power supply plans is summarized in aggregate in Table 7 below. In addition to
the capacity resource additions shown in the table, the power supply plans reflected
annual forward purchases and short-term market purchases as needed to meet each
Member's projected capacity and energy requirements.
ES-22 R.W.Beck  R:\Orlando\003834 AMP-Ohio\02-01633-01000-OE ServiceWoric Prodiicte\FiiiBlReport\ES.doc EXECUTIVE SUMMARY
T a b l e?
S u m m a ry  of  A M P - O h io  T o t al  P ower  S u p p ly  P l an
Cumulative Capacity Additions at Selected Years (MW]
2013 2015 2020 2025 2027
AMPGS [1]
Prairie State [2]
Hydro [3]
Coal
G-Class CO
F-ClassCT
Contract Purchases [4]
Total
1,140
317
530
75
228
290
367
2,947
1,140
317
543
75
228
290
367
2.960
1,140
317
668
137
251
348
62
2,923
1.140
317
695
355
251
356
71
3.185
1,140
317
595
404
345
370
89
3,360
(1] The AMPGS Project was included as an option for those Members tfial are presently partjdpatiig in the development phase of the Project.
The total number of "slices' in the  o ^ ^ si power supply plans was not Omited by  ^e Members' adual partidpatbn level in the Project.
However, eadi Member was Smiled to a maximum of two slices. The total capacity afailable ftom the AMPGS Project is  ^ m a l ed to be
960 MW, which is less {by 180 MW) than the total amount of AMPGS capacity needed as indicated from the power supply plans devetoped
for all the Members In February 2007.
[2] The Prairie State project was included as an option for all Members. Accofdiig to AMP-Ohb, as of the date of this  R ^ r t. the total anwunt
of capadty available to the AMP-Ohio M^bers li'om this project Is 150 MW whidi is less (by 167 MW) than the amount needed indicted
from the power supply plais.
[3] According to AMP-Ohio, the amount of cspacity available from the proposed AMP-Ohio hydroelectric plants along the Ohio River Is
approximately 300 MW whidi is less (by 3d5 MW)  t h ^ the amount (rf hydro capadty needed as indicated from Oie power supply plans
developed for aU the Membws.
(4} Indudes 5x16 and 7x24 forward contract purchases and other on-pe^ purdias^ estimated lo be required in the ftiture.
In summary, the February 2007 Member Power Supply Analysis indicates that in
order to meet the Members projected power requirements, there is a requirement for
additional base, intermediate and peaking type capacity and energy resources. The
projected amount of additional capacity required is estunated to be 2,947 MW in 2013
growing to 3,360 MW by 2027. The amount of additional base load capacity
projected (represented by AMPGS, Prairie State and new generic coal) totals 1,531
MW in 2013 growing to 1,861 MW by 2027.
In addition to identifying the amount and timing of future generating resources, the
Power Supply Plans included a stochastic projection of the annual power supply costs
reflecting the optimal Power Supply Plan for the period 2006 through 2027. The
projected power supply costs for each Member were shown in tenns of expected
value, 5 percentile and 95* percentile^.
0
Expected value is the average of the 50 draws from the results of the stochastic model. There is a 5
percent probability that the results will be below the 5th percentile values and a 5 percent probability
that the results will be above the 95th percentile values
R:\Orlando\003S34 AMP<)iBo\02-01633-01000-OEServicB\WoritProdiKte\Fii!a]RcpQrt^  R .  W .  B C C k  E S - 2 3 EXECUTIVE SUMMARY
Beneficial Use of the AiVIPGS Project
In accordance with Section 2 (B) (x) of the AMPGS Power Sales Contracts, we have
prepared an analysis to determine if each Participant can beneficially utilize its PSCR
Share (as defmed in the Power Sales Contract) of the AMPGS Project, This analysis
is based on each Participant's current PSCR Share. The PSCR Share may be modified
and will be finalized after the execution of the Power Sales Contract which may differ
from the PSCR Share assumed herein.
We have prepared three types of analysis to detemiine if the Participant can
beneficially utilize its share of the AMPGS Project. The three analyses include:
0 a comparison of AMPGS PSCR Share as a percent of peak demand for
selected years,
a an analysis of potential surplus energy including identifying surplus energy
sales from AMPGS and incremental surplus energy sales from existing
Participant resources as a result of adding AMPGS, and
G an analysis of each Participant's projected power costs and risks, before and
after its PSCR Share of AMPGS.
AiyiPGS Share Compargd to Peak Demand
Power plants, such as AMPGS, that are designed to generate energy at its maximum
capability when available are considered "base-load" plants because these plants are
expected to be available to meet base (or minimum) load requirements. Therefore, in
developing a power supply plan a utility will generally plan for enough capacity fi-om
base load plants or contracts at least equal to its projected minimum load. Most
utilities plan for around 50-55 percent of their projected peak demand to be supplied
from base-load type generation. If a utility has more base-load generation than its
hourly load requirements, it must reduce the output of the base load plant or sell the
surplus energy in a given hour. Because all the Participants are in regions where
surplus energy can readily be sold, tliis planning criteria is not as important.
Attachment ES-4 at the end of this Executive Summary compares the AMPGS
Participants' 2006, 2015 and 2025 peak demands with their respective shares in the
AMPGS Project.
As shown in Attachment ES-4, tlie number of Participants with AMPGS Shares
greater than 50 percent of their projected peak demand is:
m 22 based on the 2006 peak demand,
B 10 based on the 2015 projected peak demand, and
B 4 based on the 2025 projected peak demand (these four Participants represent
approximately 45 MW of the Project capacity or approximately 5%).
On a total basis, the AMPGS capacity is approximately 30 percent of the aggregate
peak demand in 2015, In aggregate, the AMPGS Participants can beneficially use the
AMPGS capacity to meet their base load requirements.
E S - 2 4  R .  W .  B e c k R:SOriatido\003834AMP<>Wo\02-0l633-0I000<>EServke\WoricProdiicts\FiDalRqwirt\ES.aw EXECUTIVE SUMMARY
This analysis does not take into consideration that some of the Participants have
existing base-load type generation. However, the surplus energy analysis and the
power cost and risk analyses described below do reflect existing base-load generation.
Surplus Energy Analysis
As discussed below, we have prepared stochastic projections of the total power supply
cost for the period 2013 - 2027 for each of the AMPGS Participants for two cases.
The first case includes the Participant's existing power supply resources (Existing
Portfolio) and the second case includes the Participant's existing power supply
resources and its current PSCR Share of the AMPGS Project (Portfolio with AMPGS).
Based on the results of these projections, we computed the amount of the estimated
surplus energy sales and associated revenues for each Participant from its share of
AMPGS and the incremental surplus energy sales firom the Participant's existing
resources that result from adding its share of AMPGS. The results of this analysis are
summarized below:
o Surplus energy firom AMPGS
o 28 Participants are projected to have surplus energy on an average annual
basis ranging from 1 percent to 17 percent of the output from their
AMPGS PSCR Shares
Q 13 Participants are projected to have surplus energy on an average annual
basis greater than 5 percent of the output from their AMPGS PSCR Shares
B Additional surplus energy resulting from adding AMPGS to the Existing
Portfolio
H 50 Participants are projected to have surplus energy on an average aimual
basis ranging fi'om 3 percent to 90 percent of the output from their
AMPGS PSCR Shares
s 28 Participants are projected to have surplus energy on an average annual
basis greater than 15 percent of the output from their AMPGS PSCR
Shares
o 4 Participants are projected to have surplus energy on an average annual
basis greater than 50 percent of the output from their AMPGS PSCR
Shares (these four Participants represent approximately 36 MW of the
Project capacity or approximately 4 percent)
Impact of AMPGS Project on Participant Costs and Risks
Using the power supply models developed for the February studies, R. W. Beck
prepared stochastic projections of the total power supply costs for each of the AMPGS
Participants reflecting the Participant's existing power supply resources (Existing
Portfolio). The stochastic power cost projections produce a range of costs resulting
fi'om the estimated volatility in loads, fuel prices, market prices, and CO2 costs. A
sample of the projections for one Participant is shown in Figure 7 below.
R:\OrIando\003834AMP<)luo\02-01633-0100(K>EService\WorkProducts\FuiaIReport  R .  W .  B c c k  E S - 2 5 EXECUTIVE SUMMARY
5120
S100
S20
Lcvsljwd Average Cs^C 7l).34/MWh
Standard Devristian: G.Cfi'MWh
(,%  r fl »!i  .> »> '.'^  ^*  • J'  i ^  -J  -^ •>**  r6 ^^ «!• rA ^fc rfc  lA A
[  — E s p e c l ed Value  - ^ S l t t  P e r c s n t i le SSth  P e r c a n l i le
Pwiw Supply Poitfalia
o ^ .- .- — —
~ o o o o o
JVTM O* t*i PJ
[M IM  f j  r j IM
Figure 7 - Stochastic Projection of Participant Power Costs - Existing Portfolio
We also prepared stochastic projections of the total power supply costs for each
AMPGS Participant reflecting the Participant's existing power supply resources and
its current PSCR Share of the AMPGS Project (Portfolio with AMPGS). A sample of
the projections for one Participant is shown in Figure 8 below.
Uvelized Average  C i st GZ.27T.1Wli
Slandaid Deviation; S.SBItMlh
f - - ^ -
^^/A''VVV%V-/'£^VV•^•^>V'/'^V/
Etpecfed Value  - 3 - S th Parcenlile
r Supply Pontane
^m^.m^E'A
iPiachHO-Oa'ut
Figure S - Stochastic Projection of Participant Power Costs - Portfolio with AMPGS
Based on these power costs analyses, the projected power costs for every AMPGS
Participant are lower under the portfolio with AMPGS than the existing portfolio.
In addition, we have prepared stochastic projections of the total power supply cost for
the period 2013 - 2027 for each of the AMPGS Participants assuming that their
respective AMPGS PSCR Share is increased by 25 percent. We have included this
case to analyze the impact on the Participant's costs and risk of the 25 percent step-up
provision under the Power Sales Contract.
The stochastic power cost projections produce a range of costs resulting from the
estimated volatility in loads, fiiel prices, market prices, and CG2 costs. Based on this
analysis we have developed an expected average annual cost (annual cost present
valued to 2013 and averaged). From the results of the stochastic analysis we can
estimate the uncertainty in fixture power costs (or risks) by computing the standard
ES-26 RW.Be ck  R:\Orlando\003834 AMP-Ohio\02-01633-01000-OE Service\Work Products^Final Repoil\ES.doc EXECUTIVE SUMMARY
deviation ("STD") in the projected average annual power costs under the 50 draws
produced by the stochastic model.
The results of the stochastic analysis demonstrate that costs are lower under the
Portfolio with AMPGS than the Existing Portfolio for all of the Participants. Also,
costs are lower under the Portfolio with AMPGS including the 25 percent step-up than
the Existing Portfolio for ail of the Participants.
To illustrate the impact on costs versus risk for each Participant, we developed a chart
that depicts expected costs (average annual costs) on the x-axis and risks (in terms of
STD) on the y-axis for each of the three cases. A sample of the chart is shown in
Figure 9 below.
Expected Co st  v e r s us Risk
$7.00
$5.80
c
_o
ra $6.60
>
o
Q
$6.40
$6.20
$6.00
$5.80 ^
With AMPGS and Step-up
Existing Portfolio  — s -
With AMPGS
$59 $61 $63 $65 $67
L e v e l i z ed  C o st  ($/MWh)
$69  $71
Figure 9 - Expected Cost versus Risk Chart for Sample Participant
Even though costs are lowered by the addition of the AMPGS PSCR Shares for all
Participants, it is important to consider the impact on risks.
For all but four Participants, risks (as measured by the STD) are lower under the
Portfolio with AMPGS than the Existing Portfolio. These four Participants represent
approximately 36 MW or four percent of the AMPGS Project capacity. Also, for all
but seven Participants, risks are lower under the Portfolio with AMPGS including the
25 percent step-up than the Existing Portfolio for all of the Participants. These seven
Participants represent approximately 49 MW or 5 percent of the AMPGS Project
capacity.
R;\Orlando\003834 AMP-Ohio\02-01633-01000-OE ServKe\Wori: ProductsVFinal Report\ES.doc  R W . B e ck ES-27 EXECUTIVE SUMMARY
Analysis of Potential Project Risks
To address the potential risks of the AMPGS Project, we have prepared a qualitative
risk assessment and a quantitative risk assessment. An overview of the major
elements of the risk assessments are:
G Qualitative risk assessment
" Develop risk inventory of all risks of the Project
^ Evaluate risk in terms of likelihood of occurrence and potential impact
on Participant costs
° Identify risk mitigation strategies
E Quantitative risk assessment
° Develop stochastic projections of Participant power costs for beneficial
use analysis (Discussed herein under Beneficial Use of AMPGS
Project)
° Develop stochastic projactions of AMPGS annual power cost
projections that quantifies major risks of the AMPGS Project
Qualitative Risk Assessment
R. W. Beck and AMP-Ohio worked together to develop the qualitative risk assessment
of the AMPGS Project The qualitative risk assessment involved developing a risk
inventory of the risks that could occur for the AMPG Project, characterizmg each
relevant risk source as being "low," "moderate," or "high" and developing risk
mitigation strategies for each risk source.
Developing the risk inventory was approached from the perspective of three risk
environments. Internal risks are those risks that occur internal to tlie AMP-Ohio
organization or the AMPGS Project and can be controlled by processes implemented
by AMP-Ohio. Internal risks include: strategic risks, operational risks, financial risks
and technology risks. AMP-Ohio will have moderate control over the risks that occur
in the electric market environment. Risks included in the market environment include:
price risks, transmission cost risks, and credit risks. There are market derivatives and
hedging instruments available to manage market risks. External risks related to event
risks, hazard risks, legal and contractual risks and risks related to the political,
regulatory and environmental are the most difficult to control.
As demonstrated in Figure 10 below. In developing the overall risk level for each of
the risk soxirces, both the likelihood of the event occurring and the impact on cost were
considered. Risk were assessed both on a "Gross" and "Net" basis. The gross risk
assessment reflects the characterization of the risks before risk mitigation strategies
are considered. The net risk assessment reflects the characterization of the risks
assuming risk mitigation strategies are in place and effective. As illustrated in the
chart below, those risks that reside in the yellow, orange or red squares of the risk
matrix are likely to have the greatest impact on the Project. All other risks would be
considered low to moderate and would reside in the green and light green squares.
ES-2S R. W. Beck R:^Or]ando\003S34AMP-Ohio\02-01633-fll(H)0-OESemce^^Vorl:P^OIiIJcls\FiIlalRepori\ES.d^ EXECUTIVE SUMMARY
F i g u re  1 0 - R i s k Mat r ix
In summary, for each of the tliree risk environments the risks that would be considered
moderate to high risk are summarized below in Table 8. All other risks would be
considered low to moderate.
T a b le 8
S u m m a ry  of Qu a l i t a t h /e Ri sk  A s s e s s m e nt  R e s u l ts
Risk Category:  Major Source of Risk Characterized as Moderate  to High
Internal Risk
Market Risk
External Risk
Developmental and Construction Cost Risks (potential delays,
cost overruns and availability of human craft resources)
Price Risks (related to volatility in coal prices, fertilizer prices
and SO2, NOx allowance prices)
Regulatory Risks (related to more stringent environmental
laws associated with CO2 and mercury)
Risk Mitigation Strategies
The qualitative risk assessment process identified a number of potential, or existing,
risk mitigation strategies which are summarized below:
R;VDrlando\003S34 AMP-Otiio\02-01633-01000-OE ServiceWorfc Products\Fiiial Report\ES.doc  R W . B e ck ES-29 EXECUTIVE SUMMARY
Internal Risk Environment
Strategic risks related to potential changes in the Participants competitive position
would be mitigated by keeping the costs (and cost increases) of the Project to the
Participants as low (and stable) as possible though the use of longer-term debt, low
cost tax-exempt financing and use of rate stabilization funds (if needed).
Operational risks would be mitigated by developing procedures to attract and maintain
highly qualified staff, training programs, developing high standards for plant
performance, sound maintenance programs, and state-of-the-art systems.
Financial risk would be mitigated by (i) the establishment of reserves for the Project,
debt service coverage ratios, step-up provisions in the Power Sales Contracts;
(ii) development of a financial plan and use of interest rate swaps to mitigate the risk
of interest rate fluctuations; and (iii) AMP-Ohio's existing Member credit program.
Development and Construction risks deserve significant consideration. Mitigation
strategies include close oversight as owner through an experienced Owner's Engineer,
liquidated damages clauses, penalty clauses and incentive clauses in contracts and
procurement documents, early procurements and sound planning.
Technology risks would be mitigated through the incorporation of design
specifications and guarantees in the EPC contract.
Wlarket Risk Environment
Price risks would be mitigated by (i) development of appropriate coal purchase
agreements and designing the AMPGS plant with the flexibility to bum different types
of coal; (ii) development of an agreement with The Andersons to provide urea for the
Powerspan process and to market the sale of the fertilizer produced by the Powerspan
process and (iii) installation of best available technology to control SO2 and NOx
emissions.
Transmission risks would be mitigated by proper oversight of the processes required
to interconnect the AMPGS Project to the PJM grid and the use of allocated FTRs and
AARs to mitigate congestion costs.
Credit risks will be mitigated by screening of counterparties so that only large highly
rated fmancial institutions are used and only proposals from a limited number of large
nationally recognized fums are considered for the EPC contractor.
External Risk Environment
Event risks related to unplanned outages will be somewhat mitigated by the fact that
the AMPGS plant is a two unit plant. Event risks related to unplanned transportation
interruptions will be mitigated by the development of adequate storage for
commodities inventories to carry operations through any delivery interruptions.
Hazard risks can be mitigated through training programs, good oversight as an owner,
appropriate insurance instruments, establishment of reserves (if necessary) and
implementing a reliable and sound design for the plant.
Legal and contractual risks surrounding counterparty performance creates the need to
negotiate a comprehensive EPC contract prior to signing contracts. The contract will
E S - 3 0  R .  W .  B e c k R:\OrIando\OO3834AMP-Oliio\02-01S33-01000-OESemceWorkFVoducts\FiiialRcport\ES.^ EXECUTIVE SUMMARY
need to contain strong provisions to protect AMP-Ohio from liability of actions of the
counterparties. Legal and contractual risks related to potential Participant default are
mitigated by the step-up provisions m the Power Sales Contract.
Regulatory risks related to more stringent environmental regulations associated with
CO2 and mercury emissions may be somewhat mitigated by continued monitoring of
environmental regulations and planning for the potential impact on the Project, The
Powerspan technology will somewhat mitigate the additional costs for carbon capture
if required in the future.
Quantitative Risk Assessment
The quantitative risk analysis should take into consideration the risks that have been
identified under qualitative risk analysis that could have a substantial impact on future
power costs for each alternative. These risk variables include the following:
H price risks including: coal price volatility, market price volatility (effects
surplus energy sales), load forecast (effects surplus energy sales) and
fertilizer price volatility (revenues from Powerspan scrubber);
s construction cost risks including: potential increases in construction costs
and potential delays in on-line date;
0 interest rate risks including: short-term variable rate volatility and longterm fixed rates fluctuations; and
o environmental cost risks including: SO2 and NOx allowance costs and
potential CO2 and Mercury emission costs.
Based on the volatility defmed for each risk variable, we have used stochastic
modeling and statistical analysis techniques to analyze how in aggregate these risks
could impact AMP-Ohio's projected net Participant power costs. The results of the
risk analysis include a projection of the potential range (with a certain confidence
level) and expected value of the annual net cost to the Participants for the AMPGS
Project.
Figure 11, below, provides a graphical representation of the results of the probabilistic
analysis, in terms of the average net costs to the Participants associated with the
AMPGS Project with CO2 cost (in $/MWh), for an expected value and a 90%
confidence interval (area between the 5% and 95% confidence estimate). From a risk
perspective, the level of uncertainty or volatility in each case is proportional to the size
of the range between the 5% and 95% estimates. The band between the 5% and 95%
estimates represents the 90% confidence interval—in other words, you would expect
the average annual net Participant costs to be within this band 90% of the time.
R;\OrlaiMto\003S34Ahtf-OWo\02-^1633-0I000-OEService\WortI^diKts\FimlI^pcff(^  R .  W .  B C C k  E S - 3 1 EXECUTIVE SUMMARY
Projected Average Annual Net Par t icipant Co st  w i th CO2 ($/WIWh)
$140.00
$120.00
$100.00
_j- $80.00
^ $60.00
$40.00
$20.00
, ^ £ v - - - * ^ = ^^
_^^^,^^' . . ^
j l o s i sl
* » ^ i
,^^,.-^>
Expected Vahje
90% Confidence Interval
B MS Case
2014 2016 2018 2020 2022 2024 2026 2028 2030 2032
Figure 11 Net Participant Costs (with CO2) at 90% Confidence Interval ($/MWh)
The projected net Participant power costs with CO2 are projected to be approximately
$77.55 / MWh on an average annual levelized'^ basis over the period 2013 through
2032. The projected uncertainty in fiiture power costs as measured by the standard
deviation in the projected average annual levelized power costs is estimated to be
approximately $ 10.71 / MWh (or 14%).
In the case with CO2, the major risk factors that cause the uncertainty in power costs
and their contribution to the STD are shown in Table 9 below.
The average annual levelized net Participant power costs where developed by computing the net present value of
the net costs divided by the net present value of the net energy over ttie period 2013 tiarough 2032.
ES-32 R.W.Beck  R;\OrIaiido\003834 AMP<)iiio\02-01633-01000-OEServicG\WoricProducts\Final Repor^ES.doc EXECUTIVE SUMMARY
Table 9
Risk Factors Contribution to STD with CO2
Description
Coal Prices
Urea and Ammonium Sulfate Prices
CO2 Costs
Construction Cost, Scliedule, and Interest Rates
Surplus & Replacement Energy Costs
SO2, NOx, and IVlercury Costs
Total
Cont r ibut ion  to STD
$/MWh % of Total
2.90 27%
2.58 24%
2.34 22%
2.32 22%
0.36 3%
0.21 2%
10.71 100%
As shown above, in the case with CO2, the uncertainty in the projected net power costs
to the Participants is most influenced by CO2 costs, coal prices, urea and ammonium
sulfate priceSj and construction and fmancing cost uncertainty.
Obligations and Risks of Ownership
The ownership of the AMPGS Project will carry with it the obligations and attendant
risks in such ownership. An important goal of AMP-Ohio in developing the
contractual arrangements related to the AMPGS Project has been and will be to
mitigate, to the extent possible, the risks of developing, constructing and owning a 960
MW coal plant. However, inherent in any ownership are risks that require recognition
by AMP-Ohio and the potential Participants, and these risks could be substantial. The
potential impact of risks have been discussed and analyzed herein. These analyses and
discussions may not be all-mclusive. However, it should be pointed out that the
impact of many of the risks which are now the responsibilities of mvestor-owned
utilities or other wholesale providers supplying wholesale power to the Participants are
or would be reflected in the rates charged to the Participants for power and energy, but
usually at a higher cost of money than AMP-Ohio. hi considering approval of the
AMPGS Project, the individual Participants should carefully weigh the benefits and
responsibilities of ownership of the ANCPGS Project.
Initial Findings and Conclusions
For purposes of this Report, we have conducted our initial engineering studies and
reviews to consider the technical feasibility of the AMPGS Project and we have
prepared an initial economic analysis for the Project over the forecast period 2013-
2032.
In the preparation of the studies and analyses set forth in this Report, we have made
certain assumptions with respect to conditions that may occur in the fiiture. While we
believe these assumptions are reasonable for the purpose of this Report, they are
dependent upon future events and actual conditions may differ jfrom those assumed.
In addition, we have used and relied upon certain infonnation and assumptions
R:\OiiaiKlo\D03S34 AMP-<thio\02-01633-01000-OESernce\WoAProdiKts\FfaialReport^^  R .  W .  B c c k  E S - 3 3 EXECUTIVE SUMMARY
provided to us by AMP-Ohio and others. While we believe the sources to be reliable,
we have not independently verified the infonnation and offer no assurances with
respect thereto. To the extent that actual future conditions differ from those assumed
herein, the actual results will vary from those forecast Section 9.2 of the Report lists
the principal considerations and assumptions made by R. W. Beck in preparing the
studies and analyses set forth in this Report and rendering the initial findings and
conclusions set forth in Section 9.3 of the Report and repeated below.
Based upon such considerations and assumptions and upon the analyses and studies as
summarized in this Report, including all appendices, which Report and appendices
should be read in their entirety in conjunction with the following, we are of the
opinion that:
1. Provided that on-going site investigations do no reveal anything tliat would
prohibit construction, the site is suitable for the construction and operation of the
AMPGS Project,
2. The proposed pulverized coal-lired steam electric plant technology to be
incorporated in the AMPGS Project is a sound and proven method of electricity
production.
3. The scale up of the Powerspan ECQ-SO2 process from the commercial
demonstration unit to the size of the AMPGS Project is within technical feasibility
given the types of equipment involved and the vendors' demonstrated experience
with the equipment. However, it is not unreasonable to expect that issues not
presently contemplated could arise as the fiiH scale installation is designed,
constructed and tested. We expect that such issues can be accommodated by
adjustnents in the field and/or modifications to the equipment. Provided true and
meaningful "wrap" guarantees are obtained from the EPC/Process Contractor(s),
such modifications and the associated financial responsibilities would be the
responsibility of the EPC/Process Contractor(s).
4. Provided that the facility is designed, constructed and maintained as proposed, and
tlie required renewals and replacements are made on a timely basis, the AMPGS
Project should have a useful life of at least 40 years.
5. Proposed plans for design, construction and operation of the AMPGS Project are
being developed in accordance with good engineering practices and generallyaccepted industry practices.
6. Based on our review of the expected fuel quality and conceptual design
information developed by S&L, an availability factor of 88 percent, an annual
average capacity of 987 MW and a net heat rate of 9,325 Btu/kWh, assuming
utilization of an eastern coal fuel blend, are achievable.
E S - 3 4 R  W .  B e c k R:\Oriawk3\OO3834 AMP<)hio\02-01633-01000-OEService\WorkProduct5\FmalReptKt\ES.d^ EXECUTIVE SUMMARY
7. The plamited construction schedule with a duration of 48 months, preceded by an 8
to 9 month open book preliminary design phase, is reasonable for the AMPGS
Project.
8. AMP-Ohio has identified the key permits and approvals required for construction
and operation of the AMPGS Project, and has submitted permit applications to the
appropriate regulatory agencies for such key permits and approvals.
9. The prelimmary estimated total construction cost for the AMPGS Project of
$2,532 billion was prepared in accordance with generally-accepted practices and
methods and reflects equipment, material and labor market conditions in the region
of the AMPGS Project as of the date of this Report. The cost is comparable to
similar projects with which we are familiar.
10. The methodology for preparing the initial O&M cost estimate for the AMPGS
Project and the estimated O&M costs that are reflected in the projected power
costs of the AMPGS Project are reasonable for the proposed plant configuration
and are comparable with similar projects with which we are familiar, after
adjustment for incorporation of the Powerspan technology
11. It is presently estimated that an aggregate principal amount of bonds totaling
approximately $2,912 billion will be required to be issued over the period 2008
through 2013 to pay for the cost of construction of the AMPGS Project, based on
AMP-Ohio's proposed financing plan and the assumed bond interest rates and
financing requirements. The approximate bond amount for an AMP-Ohio
ownership share of 97.5 percent would be $2,839 billion.
12. The Participants' PSCR Shares in the AMPGS Project can be beneficially utilized
by the various AMPGS Participants as follows::
a) The projected power costs over the period 2013 through 2027 for
each AMPGS Participant are lower under the power supply
arrangement including 100 percent their PSCR Share of the AMPGS
Project compared to the existing power supply arrangement.
b) The projected power cost risks (as measured by the estimated
standard deviation in power costs for the risk variables evaluated, as
discussed in Section 2.5.4 of this Report) over the period 2013
through 2027 for all but four of the AMPGS Participants are lower
under the power supply aixangement including 100 percent their
PSCR Share of the AMPGS Project compared to the existing power
supply arrangement.
c) The aggregate amounts of capacity and energy from the AMPGS
Project, after giving effect to the sale of a portion of the AMPGS
Project output in the short-term energy market, can be beneficially
utilized by the Participants in serving the aggregate long-range baseload power and energy requirements of the Participants.
R;\OrIando\0a3834AMP43hioV02-01633-0100(K)ESenA»\WorkFtaducts\FmalRfiport\ES.^  R .  W .  B C C k  E S - 3 5 EXECUTIVE SUMMARY
13. The Participants' PSCR Shares adjusted to reflect a 25 percent step-up
requirement, (pursuant to Section 18 of the Power Sales Contract) can be
beneficially utilized by the various AMPGS Participants as follows:
a) The projected power costs over the period 2013 through 2027 for
each AMPGS Participant are lower under the power supply
arrangement including 125 percent of their PSCR Share of the
AMPGS Project compared to the existing arrangement.
b) The projected power cost risks (as measured by the estimated
standard deviation in power costs for the risk variables evaluated, as
discussed in Section 2.5.4 of this Report) over the period 2013
tlu-ough 2027 are lower for all but seven of the AMPGS Participants
under the power supply arrangement including 125 percent of their
PSCR Share of the AMPGS Project compared to the existing power
supply anangement.
14. The AMPGS Project can be interconnected to the PJM system at the
interconnection location selected by AMP-Ohio, and the proposed contracted
capacity can be delivered to the PJM Participants. In order for AMPGS Project
capacity to be delivered to the MISO Participants, further transmission system
upgrades may be required for firm transmission service, which could cause the
AMPGS Project postage stamp rates to increase. AMP-Ohio has initiated power
flow studies to estimate the potential transmission upgrades and associated costs to
provide firm transmission service from the Project to the MISO Participants.
15. The AMPGS Project represents a reasonable cost long-term base-load power
supply option for the AMPGS Project Participants.
16. AMP-Ohio recognizes that there are internal, market, and external risk events that
could occur in the future and adversely impact the AMPGS Project. AMP-Ohio
should be able to manage certain of those risks through prudent utility practices
and implementation of the risk mitigation strategies that have been identified.
E S - 3 6  R .  W .  B e c k R:\C>lBiido\003834AMP-Ohio\02^1633-01000-OEServ;ce\WorkProducB\Fma!ReporftES.d Ame r i c an Municipal Power Generat ing  S t a t i on
Projected Operating Costs of AMPGS Plant
Base Case
Attachment ES-t
Page 1 of 4
L i ne
N o,  D e s c r i p i i on
PERFORMAftCE
1
2
3
4
5
7
8
9
10
11
13
13
14
15
16
C a p a c i t / [ M W ) [ 2t
Capadty FaclDr(%)
Avai1ability(%)|31
Energy Gfsneralion {GWh) [4]
Net Plant Heal Rate (BtuAWh) [5]
Total Coal Consumption (BBtu) [S|
Healing Value of Coal (Btuflb)
Coal Consumption {Tons x  l O ') [6]
Total  N O K Allowances Purchased (Tons)  p ]
Mercury Allowances Purchased (Tons) |8]
S O] ABowafKBS Purchased (Tons) [9]
COzAilowances Purchased (Tons X  t O ^ ( 1 ^
Urea - SCR Consumption Rate (Tons) [111
U r 6 a C o n s i j m p f i o n ( T o n s x 1 0 ^ [ 1 2)
Ash  P r o A t d i on (Tons X 10^1131
COMUIODITY PRICES
17
13
13
20
21
22
23
24
25
26
27
General Inflation (%) 114]
Coal Commodity Price [SH'on) [15)
Coal Transportation Price (Blended) (S/Ton) {16]
AIMn Average Coal Price delivered  ( $MMB t u)
Urea Price  ( $ ^ o n) (17]
S Oi Allowances  ( V T o n ) l i ai
Mercury Allowances (S/Oz) (191
NOx ABoiwances - Annua! (VTon) \2Q]
N O x A B w a n c e s - O z o ne  ( 5 / r o n ) I 2 1i
C Oi Allovrances ($/Ton) [221
Actwated Cartion  C o sh (S/Ton) [231
OPERATING EXPENSES (5000) [24J
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
S3
54
55
56
57
58
59
60
61
S2
63
64
65
66
57
58
59
70
74
75
Coal Commodty
CoalTranspoflatian
AuxffiaryFuei
Start4JpFuel
Fixed O&M
Labor
Operator G&A
Other  F K e d ! 2 5I
F o e d O SM
Variable  O JM
Major Maffilenance/Capital E:tpenses (26]
Other Variable [27]
Variable O&M
EmissiohsAl lowaices
S O; gnvssions Aliowances
Mercury Emissions ABowances
NOx Emissions Allowances - Annual
NOx Emissions Aiicwacwes - Ozone
C O; Emissions ABowances
Emissiotis Wlowances
A d i v a l ed Carbon
U r e a - S CR
POTrerspan
Urea Cost (S/^r)
Waste Disposal Cost  ( I fCr)
AuaBary Power (S/Yr)
Other Operating Cosls
Labor
Trartsportation
SoBdFerOBzer.Creda
Liquid FeriiEzer Credit
Powerspan 1281
Maintenance Parts and ServicES
Water Treatment Chemicals
Sales Tax on Commodilies (291
Insurance and Property Tax [301
C o r p o J 3 t e G 4 A p iJ
T o t i Operafeg Expenses
AVERAGE BUSBAR COST [321
Total Annual Costs
Fixed Operating Cost (50C0)
Fixed Operating Cost (JAiW-yrl [33]
F K ed Operating Cost  ( $ / M m)
Total Variable Operating Cost (SODO)
Total Variable Operat i ig Costs  m m [341
Fuel Cost (JWWh)
Non-Fuel Variabte Opera&ig Costs  ( J M W i)
A VG. OPERATING COST (wiOi  C 0 2) ($/MWh}
A V a OPERATING COST [mahout  C 0 2)  ( $ M V h)
2013111
9B7
8 5 . 0%
3 8 . 0%
7,349
9.325
58,531
12,061
2,843
3,398
0.1473
5.140
7,367
5,587
114
356
2.40
$43.85
$7.69
S Z 14
$310
$1,291
$1,211
51,322
$2,163
$3.38
$0.00
$124,692
S21,84l
$0
SQ
S15.334
$576
$16,141
$32,051
$12,106
$8,647
$20,753
56,536
S5.709
53,171
52.162
$24,877
542,555
SO
51,733
$35,454
$4,106
($1,017)
( J T l)
$12,764
$657
H 1 2 0
($44,385)
($1,088)
5 1 0 ^
$0
$0
$0
$5,552
5500
$260,217
$260,217
$38,103
$38.60
$5.18
5222,114
$ 1 0 77
$19.94
$10.28
S3S.41
$32.02
2014
987
85.0%
88.0%
7.349
9.325
63,531
12.051
2.843
3,398
0.1473
5,140
7.357
5.587
114
356
2.40
44.84
7.85
2.19
313
1,389
1,302
1,411
2,320
5.19
0.00
127,498
$22,332
0
0
15,702
590
16,528
32,820
12.396
8,854
21.250
7,139
6.141
3.3S4
2,318
38,210
57,192
0
1,774
36,305
4,204
(1.041)
(72)
13.070
673
4.219
(45.451}
(1,114)
10,793
0
0
0
5,552
512
279,723
279,723
38,884
39.40
5.29
240,839
3 2 . n
2 a 39
1 ^ 38
38.06
32.86
2015
987
85.0%
88.0%
7.349
9.325
68,531
12.051
2.643
3.398
0.1473
5,140
7,367
5.587
114
356
2.40
45.59
7.98
2.22
325
1.486
1.398
1.505
2,437
7.08
0.00
129,627
22.705
0
0
16.079
604
16.925
33.608
12.694
9.067
21,761
7,638
6,589
3,611
2.485
52.170
72.493
0
1.817
37,176
4.305
(1.065)
(74)
13,384
689
4,321
(46.541)
(1,141)
11,052
0
0
0
5,552
624
299,140
299,140
39,684
40.21
5.4D
259,456
35.30
20.73
14.58
40.70
33.60
2D16
987
85.0%
38.0%
7,349
9.325
58,531
12,051
2,843
3,393
0.1473
5.140
7,367
5,587
114
356
2.40
46.47
8.14
Z2J
333
1,522
1.517
1,606
2,666
9.06
0.00
132,143
23,147
0
0
16.465
619
17,331
34,415
12.998
9,235
22,283
7,823
7.153
3,853
2.6B5
6 8 . 7n
38,271
0
1.860
38,068
4,408
(1.092)
(76)
13,705
706
4,424
(47,558)
(1,168)
11,313
0
0
0
5.552
537
319.526
315,526
40 504
41.04
5.51
279.022
37.97
21.13
16.64
43.48
34.39
3917
937
85.0%
8 8 . 0%
7,349
9,325
58,531
12.051
2.843
3,398
0.1473
5.140
7,367
5,587
114
356
2.40
47.43
8.31
2.31
341
1,558
1,642
1,714
2.359
11.14
0.00
134,853
23.621
0
0
16.880
634
17,747
35.241
13.310
9,507
22.817
8,008
7.740
4,111
2.857
82.056
104.772
0
1.905
38.982
4,514
(1.118)
(78)
14,034
723
4,530
(43,302)
(1.196)
11,589
0
0
0
5.552
S50
340.901
340,901
41,343
41.69
5.63
299,558
40.76
21.56
19.20
46.39
35.22
2018
987
8 5 . 0%
88.0%
7,349
9.325
68,531
12,051
2,843
3.398
0.1473
5,140
7,357
5,587
114
356
2.40
48.28
8.46
2.35
349
1,595
1.771
1.829
3.065
13.29
0.00
137.272
24;044
0
Q
17,264
649
18,173
36,086
13.630
9,736
23,366
8,203
8.352
4,386
3.063
37.932
121.936
0
1,951
39,917
4,623
(1.145)
(79)
14,371
740
4,639
(49,973)
(1.225)
11,867
0
0
0
5,552
563
362.637
362.637
42.201
• 42.78
5.74
320.436
43.60
21.95
21.65
49.34
3 6 . 0 2.
3 0 19
987
8 5 . 0%
8 8 . 0%
7,349
9,325
88,531
12,051
2,843
3,398
0.1473
5,140
7.367
5,587
114
355
2.40
49.36
8.65
2.41
353
1,634
1.906
1,951
3.2B6
13,61
0.00
140,366
24,587
0
0
17,579
665
18,609
36.953
13,957
9,969
23,926
3 3 9
8,988
4,680
3,284
1 0 0 3 2
125,633
0
1.998
40.875
4.734
(1,172)
(81)
14.716
758
4.750
(51,173)
(1.254)
12,152
0
0
0
5,552
576
371,745
371,745
43,081
43.65
5.B6
328,664
44.72
22.45
22.28
50.58
36.94
2020
987
85.0%
88.0%
7,349
9.325
63,531
12,051
2.843
3,398
0.1473
5,140
7.3S7
5,587
114
356
2.40
50.52
3.85
2.46
366
1,673
2,047
2,082
3,523
13.94
0.00
143,658
25.163
0
0
18,103
681
19. ( ^6
37.840
14,292
10,208
24.500
8,599
9,650
4,994
3,521
102.689
129.453
0
2,046
41.356
4.847
(1,200)
(83)
15.069
776
4.864
(52,401)
(1.284)
12.444
0
0
0
5,352
590
381,245
381,245
43.982
44.56
5.98
337,263
45.39
22.97
22.92
51.83
3 7 50
2021
987
85.0%
8 8 . 0%
7,349
9,325
68,531
12,051
2,843
3,393
0.1473
5,140
7.367
5.537
114
356
2.40
51.86
9.08
2.53
375
1,713
2,138
2,221
3.777
14.27
0.00
147,432
25,824
0
0
18,537
697
19,513
38.747
14,635
10,453
25,083
3,805
10.079
5,328
3.775
1 0 5 L 1 53
133,140
0
2.095
42,861
4,964
(1.229)
(85)
15,430
794
4.981
(53,659)
(1.315)
12.742
0
0
0
5.552
604
391.224
391,224
44,903
45.49
6.11
345,321
47.12
23.57
23.55
53.23
38.93
2 0 22
9B7
8 5 . 0%
8 3 . 0%
7,349
9,325
68,531
12.051
2,643
3,398
0.1473
5.140
7.367
5.587
114
356
2.40
53.21
9.32
2.59
384
1,754
2.233
^ 3 7 0
4 , 0 49
14.62
0.00
151,302
26.503
0
0
18,982
714
1 9 3 81
39.S77
14.986
10.704
25,690
9.015
10,527
5.665
4,047
107,677
136.951
0
2.145
43,880
5.083
(1.259)
(87)
15,801
814
5.101
(54,946)
(1.347)
13.048
0
0
0
5.552
619
401,487
401.487
45,848
45.45
a24
3 5 5 , 6 3 ai
4 8 . 3 |
2 4 . 1 3^
24.20
54.63
39.98
R:\OTk^dD^OC6834AMP-Ohio^jX^-0)633010QO•OESe^vice^Oata•Allllyti»l^opAMP•OH08(R^or^ A m e r i c an  M u n i c i p al  P ower Ge n e r a t i ng  S t a t i on
Projected Operating Costs  of AIWPGS Plant
Base Case
Attachment ES-1
Page 2  o f4
L i ne
Descr ipt ion  2B25  2024  2025  2026  2027  2028  2029  2030  2031  2032
PERFORMANCE
1 Capacity (MW) [2]
2 Capacity Factor (%)
3 Availabinty[%)(31
4 Energy GeneraSon (GWh) [4]
B  N e l P t a n l H e a l R a te  (Btuf tWi) jS)
7 Total Coal Consumption (BBtu) [6]
a Heating Value o( Coal (Bbirtb)
9  C o ^ Consumption (Tons x  1 0^ [6)
10 Total WOx Allowances Purchased (Tons) |7]
11 Mercury Allowances Purchased (Tons) 18]
12 SO2 Allowances Purdissed [Tons) [9J
13 CO3 Allowances Purchased [Tons x  1 0 ^ |10]
14 Ur e a - SCRCo n s ump t i or Rate (Tons) [11]
15 Urea Consumption (Tons x 10^) 112]
16 Ash Producfion [Tons x  1 0^ [15]
COMMODITY PRICES
17 GenBr3Mnflaflon(%)|14]
1 a Coal CommotSty Prce (S/Ton) 115)
19 Coal TransportaBMi Prica (Blended) (SyTon) [16]
20  A l Un A^i6fa98 Ccal Price Delivgied (J/MMBtu)
21 Urea Price (VTofi) 117]
22  S Oi Ailowances ($n"on) [18]
23 Mercury Allowances ($/0z) [19]
24  N OK Allowances - Armual (SATon) [20]
25 NOx Allowances - Ozone (VTor) [21]
26 CO3 Allowances {5/Ton} [32]
27 Aclivafed Carbon Costs (SlTon) [23)
OPERATING EXPENSES ($000) [24]
23  C o ^ Commodity
29 Co^Trsnspor tadon
Auxiriary Fuel
Slat l -UpFuel
Fixed O&M
Labor
Operator GiA
Other Fi;<ed|35]
Fixed O&M
Variable O&M
Major Maintensncs/Capilal Expenses [26]
Ot t iM Variable [271
Variable O&M
Emisaons Allokvances
SO2 Emissions Allowances
Mercuiy Emissions ABowances
NO)i Emissions Allowances - Annual
NOx Emissions Allowances - Ozone
CO2 Emissions Allowances
Emissions Aflowaices
Activated Cartion
U r e a - S CR
Powerspan
U r ^ a C o s l i V f r)
Waste Disposal Cost (VYr)
Auxiliary Power {%fX(\
Renewals. Replacements & Maintenance
Other Operating Costs
Labor
Transportation
Sc^dFeFffizerCretfit
Liquid FerfilzerCredil
Powerepan [28]
Maintenance Parts and Services
Water Treatment Chemicals
Sales Tax on Commodities [29]
Insurance  a i d Property Tat [30]
Corporate G&A [31]
Total Opsraling Expenses
•
3D
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
55
57
58
59
60
B1
52
AVERAGE BUSBAR COST |32]
63  T o td Annual Costs
64 Fixed Operabr^ Cost (SOQC)
65 Fixed Operating Cost  (Jft W^yr) 133]
65 FUeti Opeta&ig Cost  jS/MWi]
67 Tolal Variable Operating Cost ($000)
Tola!  V s i a b le Operating Costs ($/MWh) [34]
i9 Fuel Cost (SMWh)
70 Non-Fijel Variable C^erstjng Costs (J/MWh)
74 AVG. OPERATING COST [wilh C02) (S/MWh)
75 AVG.OPERATIMGC0ST(vivlhoutC02) ($/MWh)
987
85.0%
88,0%
7.349
3.325
68.531
12.051
2.843
3,398
0.1473
5,140
7,367
5,387
114
356
2.40
554.57
39.56
52.66
5393
51,796
52.332
$2,529
$4,341
$14.97
$9.00
$155,173
327,180
50
SO
$19,438
$731
$20,431
$40,630
$15,346
$10,961
526.307
55,231
$10,995
$6,068
54,339
$110,251
$140,892
$D
$2,196
544.943
$5,205
($1,2891
($89)
$16,180
$833
$5,223
($56,265)
($1,379)
$13,351
$0
$0
$0
55,552
$834
$411,926
5411,926
$4S,S16
$47,43
56.37
$365,110
549.68
$24.81
$24.87
556.05
$41,05
987
85.0%
88.0%
7,349
9,325
68,531
12,051
2,843
3,398
0.1473
5,140
7,367
6,537
114
356
2.40
56.27
9.86
2.74
403
1,840
2.436
2,699
4,554
15.33
O.M
160,011
28.027
0
0
19.904
748
20.952
41,604
15,714
11.224
26.938
9.457
11.484
5.473
4.652
112.908
144,974
0
2,249
46,022
5,330
( l . i ZQ)
(92)
16.568
853
5.349
(57.615)
{1,412)
13.682
0
0
0
5,552
649
423.687
423,687
47,805
48.43
6.50
375,882
51.15
25.59
25.56
57.63
42.29
9S7
85.0%
88.0%
7,349
9,325
68,531
12.051
2.843
3,398
0.1473
5,140
7,367
S,587
114
356
2.4Q
58.01
10.16
2.83
412
1,884
2,544
2,879
4.990
15.69
0,00
154.946
28,692
0
0
20,3S2
766
21,455
42,603
16,091
11,494
27.585
9,683
11.995
6,907
4.987
115.617
149,189
0
2,303
47.126
5,457
(1.352)
16,95m  6
874
5.477
(58,998)
(1.446)
14,010
0
0 .
0
5,552
665
435.745
435,745
48,820
49.46
6.64
386,926
32.65
26.38
26.27
59.29
43.55
987
85.0%
88.0%
7,349
9,325
68,531
12,051
2.843
3.398
0.1473
5.140
7.367
5,587
114
355
2.40
59.85
10.48
2,92
422
1,929
2,657
3.072
5.350
16.07
0.00
170,171
29,807
0
0
20.871
7S5
21.970
43,626
16,477
11.770
28,247
9.915
12.529
7,369
5.34?
115.392
153.552
0
2,358
48,257
5,588
0 . 3 8 4)
(96)
17.373
894
5.608
[ 6 0 , 4 1^
(1.481)
14,347
0
0
0
5,532
581
448,341
448.341
49.859
50.52
6.79
398,482
64.22
27.21
27.01
61.01
44.90
987
85.0%
68.0%
7.349
9,325
68,531
12.051
2.843
3,398
9.1473
5,140
7,367
5.587
114
355
zm
61.62
10.79
3.00
432
1,975
2,775
3,278
5,736
16.46
0.00
175,207
30,689
0
0
21,372
803
22,497
44,672
16,373
12,052
?R,97S
10.151
n,m
7.863
5,733
121,234
158,067
0
2,415
49.415
5.723
(1.417)
(93)
17,790
916
5,743
(51,854)
(1,516)
14,591
0
0
0
5.552
697
460,915
450,915
50,921
51.59
e.93
409.994
53.79
28.02
27.77
6 Z 72
4 6 J2
987
85.0%
88.0%
7,349
9,325
68.531
12,051
2,843
3,398
0.1473
5,140
7,367
5,587
114
356
i40
63.44
11.11
3.09
443
2,022
2,899
3,498
6,150
16.85
8.D0
180.389
31.597
0
0
21,885
823
23,037
45,745
17,278
12.341
29.619
10.395
13.668
8,350
6,146
124,143
1 5 i 7 42
0
2,473
- !7i>,Pni
5,860
(1.451)
(101)
18.217
938
5.881
(53,349)
(1.553)
15.044
0
0
0
5.552
714
473,875
473.875
52.011
52.70
7.08
421.864
57.40
28.84
28.56
54.48
47.99
987
85.0%
88.0%
7,349
9.325
68,531
12,051
2.643
3,398
0.1473
5,140
7.367
5,597
114
356
2.40
53.32
11.44
3.18
453
2,071
3,028
3,732
6.593
17.26
0.00
185.724
H ? f iV
0
0
22,410
842
23,590
46.842
17.692
12,637
30,329
10,644
14.276
8,952
5,589
127,123
167,584
0
2.532
51.81B
6,001
(1.486)
(103)
18,554
960
6.022
(64.869)
(1.590)
15,405
0
D
0
5.552
731
487J31
487,231
53.125
53.82
7.23
434.105
59.07
29.70
2 9 37
66.30
49.00
987
85.0%
88,0%
7,349
9.325
58,531
12,051
2,843
3,398
0.1473
5.140
7.367
5.587
114
366
2.40
67.25
11.78
3.28
4B4
2.121
3.163
3.982
7.069
17.67
0.00
191,216
33,493
0
0
22,948
853
24.156
47.967
18.117
12.941
31,058
10,900
14,911
9,552
7,065
130.174
172.602
0
2,593
53,059
6,145
(1.522)
(106)
19,102
983
6,166
(56,426)
(1.528)
15,774
0
0
Q
5,552
748
501,004
501,004
54.267
54.98
7.38
443,737
50.79
30.53
30.21
68.17
50.45
957
35.0%
83.0%
7,349
9,325
68,531
12,061
2,843
3,398
a i 4 73
5,140
7,357
5.587
114
356
2.40
6 9 ^4
12.13
3.38
475
2,172
3,303
4,249
7,579
18.09
0,00
195.869
34,453
0
0
23,499
883
24,736
49.118
18.552
13,251
31,803
11,161
15,574
10,192
7,574
133,298
177,799
0
2,655
54,333
6,292
(1.556)
(108)
19,550
1,007
5,314
(68,020)
(1.667)
16,153
0
0
0
5,552
756
615.199
515,199
55,435
56.17
7.54
459,763
62-56
31.48
31.08
70.10
5 1 56
987
86.0%
88.0%
7,349
9,325
68.531
12.051
2,843
3,398
0.1473
5,140
7,367
5.5S7
114
356
2.40
71.28
1 2«
3.4a
487
2.224
3.450
4.534
3,125
i a . 53
OiK)
202,688
36,503
0
0
24,063
905
25.330
50.298
18,997
13,569
32,566
11.429
16,267
10.875
3.121
136,497
183,189
0
2.719
55,63?
8.443
(1,395)
(111)
20,030
1,031
6;468
(69,5E5
(1.70?)
1S,S41
0
0
0
5.5S2
785
529,841
529,841
56,635
57.38
7.71
473.206
6 4 J9
32.41
31.98
72.10
53.52
R:\OiWdo\003a34 AMP -Ohio\02-01633-01OCO-OE ServkeMDala-AnalyticalNDpAMP-OiSH piepE)rt).xk Attachment ES-1
American Municipal Power Generating Station Page 3 of 4
Projected Operating Costs of AMPGS Plant
Base Case
NOTES:
[ I] Assumed commercial operation date of January 1,2013.
[2] Assumed net dependable capacity under normal operating conditions, including allovkfance for long-term degradation.
[3] Based on estimates provided by R. W. Beck for expected average annual maximum availability level. Includes provision for
both forced and scheduled outages.
[4] Assumes Project is base-loaded and operated at full load whenever the plant is available.
[5] Net plant heat rate assumed to average 9,325 Blu/kWh, as estimated by Sergeant Lundy ("S&L"), including an annual
allowance for plant degradation.
[6] Annual fuel consumption al the projected annua! capacity factors and heat rates, assuming a higher heating value of the coal
of 12,051 Btu/lb,
[7] NOx allowances that the Project is projected to purchase based on an assumed emissions rate of 0.07 Ibs/MMBtu.
[8] Mercury allowances that the Project Is projected to purchase based on an assumed emissions rate of 4.30x10-^ ibs/MMBtu.
[9] SO2 allowances that the Project is projected to purchase based on an assumed emissions rate of 0.15 Ibs/MMBtu.
[10] CO2 allowances that the Project is projected to purchase based on an assumed emissions rate of 215 Ibs/MMBtu.
[ I I] Annual quantity of urea required for operation of the SCR at the indicated capacity factors assuming an uncontrolled emission
rate of  0 25 Ibs/MMBtu and a conlrc^Ied rate of 0.07 Ibs/MMBtu and 2.11 percent sulfur fuel.
[12] Annual quantity of urea required for operation of the Powerspan Scmbber at the indicated capacity factors assuming 2.11
percent sulfur lliel.
[13] Annual quantity of bottom ash and fly ash produced, based on an ash content of the  c od of 10.83 percent.
[14] . Based on projections prepared by Blue Chip Economic Indicators.
[15] FOB price of coal as projected by the latest S&L report, in 2009 dollars and escalated at R.W. Beck's coal price escalation
rates from its most recent market price forecast.
[16] Based on estimates provided by S&L for coal delivery in early 2009, in 2009 dollars and escalated at a rate of 3 percent. .
[17] Based on an assumed urea price in 2007 of $270 per ton, escalated at the general rale of inflation thereafter.
[18] SO2 allowance costs assumed to be $1,094 per ton in 2006. Projections of allowance costs are based on EPA estimates and
R.W. Beck's proprietary model.
[19] Mercury allowance costs based on an assumed cost of $27.8 million per ton in 1999 dollars.
[20] NOx annual allowance cost assumed to be $1,120 per ton in 2006. Projections of allowance costs are based on EPA
estimates and R.W. Beck's proprietary model.
[21] NOx ozone season allowance cost assumed to be $1,833 per ton in 2007 dollars, Projections are based on EPA estimates
and R.W. Beck's proprietary model.
[22] A carbon tax is assumed to begin during the period 2012 to 2018 with a 28.6 percent probability of occurrence in 2012,
increasing to 100 percent by 2018. CO2 annual allowance cost assumed to be $10.24 per ton h 2007, escalated at the
general rate of inflation thereafter.
[23] No carbon injection assumed for Mercury control.
[24] O&M expenses estimated by R.W, Beck to reflect the nomnal range of costs for sffnilar coal-fired plants, equipped with
conventional limestone scrubber systems, with which R.W. Beck is familiar. These costs are assumed to escalate at the
general rate of inflation except as noted.
R:\OIando\003834 AMP-Ofiio\02-01633-01000-O£ Service\Data-Analytfcal\AMP Ohio Proforma Assumptions {Report}.doc ^
At tachment ES-1
American Municipal Power Generating Station Page 4 of 4
Projected Operating Costs of AMPGS Plant
Base Case
[25] Additional fixed operations and maintenance expenses estimated by R.W. Beck. Includes projected costs for routine
preventative maintenance performed during outages, plant support equipment and temporary labor, vehicle maintenance,
structure and grounds maintenance and demand-related backfeed electric charges.
[26] Maintenance expenditures as estimated by R.W. Beck. Includes projected cosls and capitalized expenditures for scheduled
major overhauls that require an extended outage.
[27] Additional variable operations and maintenance expenses, estimated by R.W. Beck. Includes projected costs for nimtine
scheduled maintenance perfomned during outages, raw and process water, sewage expenses, waste disposal, chemicals and
gases, consumable materials and supplies and energy-related backfeed electric charges.
[28] Powerspan variable costs include urea, ash disposal, adjustnnents for auxiliary power consumption and steam consumption,
adjustments for makeup water, cooling water, equipment air, natural gas, maintenance, labor and other fertilizer plant
operating costs. Also included are cosls for mercury disposal, ammonium sulfate transporlalbn and fertilizer revenues
associated with the operation of Powerspan. These costs are assumed to escalate al the general rate of inflatton except as
noted.
[29] Based on a sales rate of 0.0 percent applied to all Project equipment and materials which are tax exempt, coal commodity,
auxiliary fuel, urea, ammonia, carbon and water treatment chemical costs.
[30] Based on $0.10 per $100 of the estimated gross plant value to be insured. Property taxes are cun^ntly estimated to be the
same as insurance costs per year. Property taxes are estimated based on 0.10 percent of gross plant investment.
[31] Based on estimate provided by AMP Ohio, escalated thereafter by the general rate of inflation.
[32] Excludes costs associated with debt service.
33] Fixed Operating Costs include labor, othertixed expenses, insurance, property taxes and general and administrative costs.
[34] Variable Operating Costs include coal, coal transportation, auxiliary fuel, emissions allowances, activated cart3on, ash
disposal, Powerspan, ammonia, water treatment chemicals, and other variable expenses.
R:\Oriando\003834 AMP-Ohio\02-01633-01000-OE Service\Data-Anaiytical\AMP Ohio Proforma Assumptions (Report).doc A M P - O h io  G e n e r a t i ng  S t a t i on
P r o j e c t ed  O p e r a t i ng  R e s u l ts
At tachment ES-2
Page 1 of 5
Description  2013  2014  2015  201S  2017  2018  2 0 19  2 0 20  2 0 21  2 0 22
R E V E N U E S:
1 Panlcipanl Revenues [1]
2 Interest Earnings [2]
3 Shor t - lerm  (Ma A e t) Sales [3]
4 Other  P r a j ed Revenues
5 Transfers  I ram R&C Fund  [ 4]
6 Other Receipts
7 Tofal Ra\/Bnues  [5}
SOCO
$ 0 00
$ 0 00
5 0 0Q
5 1 7 6 , 7 19  $ 4 4 2 , 5 76  $ 4 5 8 , 2 30  3 4 7 9 , 1 31  5 4 9 8 , 9 10  S 5 1 8 ,!
5.181
5,543
a
0
0
6,541
29,746
0
0
a
5,263
30,571
0
4,526
0
6,212
31.929
0
4.228
0
6,196
35,451
0
3,924
0
6,184
37,377
0
3,612
0
6,178
37,952
0
3,292
0
B,080 5537,320 5543.594 $536,630
6.214 6,249 E.2B6
39,016 39.330 40.366
0 0 0
2.965 2.630 2,287
0 0 0
5167.443 5478.863 5499.590 5521,560 5544,481 $566.709 $575,503 $586.014 S59S.S03 S607.5S9
F'ued Op e r aUng  C o s t s:
8 Fixed  O &M
9  Insurance 4 Property Taxes [71
10 Transnriis»oa Cosls [B]
11  AMP -Oh io  A &G Costs [7]
12 Bank and Trustee Fees [7]
13 Other Direct Project Cosis
14 Fbted Operating Costs
V a r i a b le  O p e n t i ng  C o s t s:
15 Fuel Costs
16  S 02  E m i s ^ n s Costs
17  N O.  E r r u s ^ ns Costs
13 Hg Emissions Costs
19  C O,  Eml a ^ o ns Costs
20 Var iable O&M
21 Gross Urea and Powerspan Costs
22 Fertilizer Credits [9j
23 Vaiiab/e OperaSng Cosls
R e p l a c e m e nt  P o w er  [ 1 0 ]:
24  Capacity Purchases
25 Energy Pundisses
26 Transmission Costs
27  Total Replaeement Power  P u i z fms es
2S Tofai Operating Expenses
29  N e l R e v M u e s [ 1 11
30 Deposit to Working C&pU^ Reserve  A c c o u nI [12]
n F R T S P H V I C F -
31  P r i n d p al
32  Interesl
33  T o t ^ D a bl Service  !13}
34 Other Debt Payments
35 Total Da ta  S e i v ka Requiramertt
f P e o Q B i ts to  R &C  S i i h flcrr^untsl:
36 Overhaul Account
37 Renewal and Replacement Account [14]
36 Capital Improvements  A c c o u nl
39 Rata Stabiflzation Account
40 Environmental Improvement Account
41 Other
42 Total  R &C  F u nd
SDOO
5 D 00
5 0 00
SOOO
sooo
$000
s o oo
sooo
$000
sooo
sooo
s o oo
s o oo
s o oo
SODO
sooo
sooo
sooo
sooo
sooo
sooo
$000
sooo
sooo
sooo
sooo
sooo
516,026
2,804
1,837
500
125
0
S21.291
573.2S7
3.318
2.667
2.826
12,436
4.324
28,873
(22,737)
$104,975
SO
0
0
SO
5126,266
$31,182
$526
50
54,603
$54,603
0
$54,603
$32,820
5.607
3.7S3
512
128
0
S42.S30
$149,330
7,139
5,702
6,060
38,208
8,355
59,132
(46.564)
5228,381
SO
20.295
0
S20.295
S291.507
5187,353
51,215
$60,015
109.205
S 169,220
0
5169,220
$33,603
5,807
3,853
524
131
0
543,723
$152,332
7,633
6,095
6,524
52,167
9,067
60,551
(47.632)
3246,693
SO
21.731
0
S21.731
$312,146
$187,442
$1,301
562.265
10S.955
$169,220
0
$169,220
534.414
5.607
3,946
537
134
0
544,338
$155,290
7,823
6,517
7.083
66.773
9.285
62.004
(48.326)
5265,349
SO
23,440
0
$23,440
5334.027
$187,534
51.392
S34,6O0
104.520
5169,220
0
$169,220
$35,240
5.S07
4.040
530
137
0
$45,575
$158,474
8.006
6.968
7,664
82,051
9,507
63.492
(49,998)
S2B6.168
SO
25.111
0
S25.111
$356,852
$167,629
51.487
567,023
102.197
5169,220
0
5169,220
538.086
5.607
4.137
553
141
0
$46,534
$161,316
3,203
7,449
a.269
97.926
9.736
65.016
(51.198)
5306,717
50
25.737
0
525,737
S378.988
$187,721
51,579
SS9,53S
99.684
S169.220
0
$159,220
$36,952
5,607
4,237
576
144
0
547,516
5164,955
3,399
7,964
8,899
100,273
9,969
66.577
(52.427)
5314,612
50
25.618
0
525.616
S387.746
$187,757
S1.616
572.144
97,076
S169.220
0
$169,220
537,839
5,307
4.333
590
143
0
548.522
$168,821
8.599
6,514
9.554
102.683
10,209
68.175
(53.6S5)
5322.869
$0
26,822
0
$26,822
5396,213
5137,801
51.659
$74,849
94,371
S169.220
0
5169,220
538.747
5.607
4 . 4 42
6 04
1 51
Q
$49,552
$173,256
a.B05
9,103
9,979
105,147
10,454
6 3 . 3 11
( 5 4 . 9 7 4)
5331.581
SO
27.824
0
527,324
S40B.aS7
sia7,B4a
$1,704
S77.556
91.564
5169,220
0
5169,220
$39,677
5.607
4,549
6 19
155
0
$50,607
$177,805
9,015
9.732
10.423
107.671
10,704
71.466
(56,293)
S340.544
so
28.547
0 -
. s ^
5 4 1 9 , 6 9 3 ' '
3137.891
$1,743
s s f t s oa
88,652
SI 69,220
0
$169,220
SOOO
sooo
sooo
SOOO
sooo
s o oo
s o oo
so
6.053
0
0
0
0
so
16,322
0
0
0
0
SO
16,923
0
0
0
0
SO
16,922
0
0
0
0
$0
16.922
0
0
0
0
SO
16,922
0
0
0
0
so
16,922
0
0
0
0
so
16.922
0
0
0
0
so
16,922
0
0
0
0
56,053 $16,922 $16,922  $16,922  S 1 B , 9 22
A v a i l a b le  f or  T r a n s f er  lo Ge n e r al  A c c o u nl
Net Revenues  A v s i l ^ le for Transfer  lo General
43 Account [15] $000
Amounts Available from RSC Fund to Transfer
44  lo General Account [16] SOOO
45 Total Revenue Requirements [17] SOOO
(SO)
SO
5187.446
$4,526
5478.863
S4.228
$499,590
53,924
$521,560
53.612
$544,481
$3,292
$566,709
. S2.965 .
5575.503
$2,630
$536,014
S2.2B7
5396.803
$1,936
5507,589
F>OR  M o dd Version 20j ( ls BEFORE THE
LOUISIANA  PUBUC SERVICE COMMISSION
APPLICATION OF ENTERGY LOUISIANA,
LLC, FOR APPROVAL TO REPOWER THE
LITTLE GYPSY UNIT 3 ELECTRIC
GENERATING FACILITY AND FOR
AUTHORITY TO COMMENCE
CONSTRUCTION AND FOR CERTAIN COST
PROTECTION AND COST RECOVERY
DOCKET NO. U-30192
DIRECT TESTIMONY OF DAVID A. SCHLISSEL
ON BEHALF OF
THE ALLIANCE FOR AFFORDABLE ENERGY,
LOUISIANA ENVIRONMENTAL ACTION NETWORK,
SIERRA CLUB, GULF RESTORATION NETWORK, SAL
K. GIARDINI, JR., EARLENE ROTH, AND
WARREN PIERRE
PUBLIC VERSION
PROTECTED MATERIALS REDACTED
SEPTEMBER 14,2007 P u b l ic  V e r s i on -  P r o t e c t ed  M a t e r i a ls  R e d a c t ed
T a b le of  C o n t e n ts
1. Introduction 1
2. The Appropriate Carbon Dioxide Emission Allowance Prices To Use In
Evaluating Proposed Electric Generating Projects 4
3. The Probable Economic Impact of the Proposed Repowering Project 30
L i st of  E x h i b i ts
Exhibit DAS-1: Resume of David Schlissel
Exhibit DAS-2: Summary of Senate Greenhouse Gas C^-and-Trade Proposals in
Current U.S, 110*^ Congress
Exhibit DAS-3: Climate Change and Power: Carbon Dioxide Emissions Costs and
Electricity Resource Planning
Exhibit DAS-4: New Mexico Public Regulation Commission June 2007 Order
Adopting Standardized Carbon Emissions Cost for Integrated
Resource Plans
Exhibit DAS-5: Scenarios and Carbon Dioxide Emissions Costs from the
Assessment of U.S. Cap-and-Trade Proposals recently issued by
the MIT Joint Program on the Science and Policy of Global
Change
Exhibit DAS-6 ; Rising Utility Construction Costs: Sources and Impacts, the Brattle
Group, September 2007.
Exhibit DAS-7: [CONFIDENTIAL, IN PART] PROSYM Break-even Analyses
Assuming Non-zero CO2 Prices
Exhibit DAS-8: [CONFIDENTIAL, IN PART] Entergy Louisiana Data Responses 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
1.
Q.
A.
Q.
A.
Q.
A.
Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
Introduction
What is your name, position and business address?
My name is David A. Schlissel. I am a Senior Consultant at Synapse Energy
Economics, Inc, 22 Pearl Street, Cambridge, MA 02139.
Please describe Synapse Energy Economics.
Synapse Energy Economics (*'Synq>se") is a research and consulting firm
specializing in energy and environmental issues, including electric generation,
transmission and distribution system reliability, market power, electricity market
prices, stranded costs, efficiency, renewable energy, environmental quality, and
nuclear power.
Synapse's clients include state consumer advocates, public utilities commission
staff, attorneys general, environmental organizations, federal government and
utilities. A complete description of Synapse is available at our website,
www.svnapse-energv.com.
Please summarize your educational background and recent work experience.
I graduated from the Massachusetts Institute of Technology in 1968 with a
Bachelor of Science Degree in Engineering. In 1969,1 received a Master of
Science Degree in Engineering from Stanford University. In 1973,1 receiv«3 a
Law Degree from Stanford University. In addition, I studied nuclear engineerii^
at the Massachusetts Institute of Technology during Ihe years 1983-1986.
Since 1983 I have been retained by govemmentai bodies, publicly-owned utilities,
and private organizations in 28 states to prepare expert testmiony and analyses on
engineering and economic issues related to electric utilities. My recent clients
have included the New Mexico Public Regulation Commission, the General Staff
of the Arkansas Public Service Commission, the Staff of the Arizona Corporation
Commission, the U.S. Department of Justice, the Commonwealth of
Massachusetts, the Attorneys General of tiie States of Massachusetts, Michigan, 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
on
21
22
23
24
25
26
27
Q.
A.
Q.
A.
Q.
A.
Q.
A.
Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
New York, and Rhode Island, the General Electric Company, cities and towns in
Cotmecticut, New York and Virginia, state consumer advocates, and national and
local environmental organizations.
I have testified before state regulatoiy commissions in Arizona, New Jersey,
Connecticut, Kansas, Texas, New Mejuco, New York, Vermont, North Carolina,
South Carolina, Maine, Illinois, Indiana, Ohio, Massachusetts, Missouri, Rhode
Island, Wisconsin, Iowa, South Dakota, Georgia, Minnesota, Michigan, Florida
and North Dakota and before an Atomic Safety & Licensing Board of the U.S.
Nuclear Regulatory Commission.
A copy of my current resume is attached as Exhibit DAS-1.
On whose behalf are you testifying in this case?
I am testifying on behalf of the Alliance for Affordable Energy ("AAE")>
Louisiana Environmental Gulf Network, Sierra Club, Gulf Restoration Network,
Sal K. Giardini, Jr^ Earlene Roth, and Warren Pierre.
Have you testified previously before this Commission?
No.
What is the purpose of your testimony?
Synapse was retained by the Alliance for Affordable Energy to evaluate the
proposal by Entergy Louisiana, LLC ("Entergy Louisiana" or  ' ihe Company") to
repower the Little Gypsy Unit 3 electric fecility as a circulating fluid bed ("CFB")
generating unit that would bum a mixture of petroleum coke (petcoke) and coal.
This testimony presents the results of our analyses.
Please summarize your conclusions.
My conclusions are as follows:
1. The Fundamental and PROSYM analyses presented by Entergy Louisiana
to justify the Repowering Project as the lowest cost option reflect an
unreasonably range of potential carbon dioxide (CO2) emissions allowance
Page 2 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 costs. In particular, tiie "Reference Case" scenarios examined by the
2 Company which assume $0/ton CO2 prices (that is, no federal legislation
3 regulating greenhouse gas emissions) are highly unrealistic and unlikely.
4 2. The Commission should rely on tiie Synapse forecasts of likely CO2
5 emissions allowance prices when it considers the relative economics of tiie
6 proposed Repowering Project.
7 3. The Fundamental and PROSYM analyses presented by Enteigy Louisiana
8 do not reflect a reasonable range of altematives to the Repow^ing Project
9 For example, these studies do not reflect any demand side, management or
10 renewable resources as part of a portfolio oiF alternatives to the repowering
11 ofLittle Gypsy Unit 3.
12 4. Given the experience of other power plant projects and the worldwide
13 demand for power plant design and constmction resources, commoditi^
14 and labor, it is reasonable to expect that the cost of the Repowering Project
15 will increase before the project is completed.
16 5. The results of the Company's Fundamental Analysis do not show that the
17 Repowering Project would be the lower cost optk>n imder reasonable
18 assumptions regarding fiiture constmction costs, CO2 costs and natural gas
19 prices. For example, the repowering ofLittle Gypsy Unit 3 as a CFB plant
20 would be the  h i ^ er cost option if the constmction cost of tiie Repowering
21 Project increases by another 10 or 20 percent even if the Company's
22 unreasonably low forecasts of CO2 prices are used.
23 6. The results of the PROSYM analysis suggest that the Fundamental
24 Analysis significantiy overstates the economic benefits of the Repowering
25 Project.
26 7. Although Entergy Louisiana's PROSYM analysis shows a net present
27 value benefit to tiie Repowering Project, that analysis unrealisticalfy
28 reflects $0/ton CO2 prices. Even if tiic Company's unreasonably low base
29 or high C02 prices were reflected in the analysis, the Repowmng Project
30 would be the higher cost option.
31 8. Even though Entergy Louisiana's PROSYM analysis shows a net present
32 value benefit to the Repowering Project during the years 2012 through
33 2036, the CCGT altemative would be the lower cost option, on a
34 cumulative net present value basis, through the year 2031.
35 For these reasons, the Commission should reject Entergy Louisiana's request for
36 approval to repoweruig Littie Gypsy Unit 3 and for authority to commence
37 constmction and for certain cost protection and cost recovery. Entergy Louisiana - Littie Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Q. In general,  a re you in favor of the repowering of older, less efficient power
2 plants?
3 A. Yes. I believe that the repowering of older generating facilities often can provide
4 economic and envux>nmental benefits. Unfortunately, that does not appear to be
5 the case with  ^ t c r gy Louisiana's proposed repowering of the Littie Gypsy Unit 3
6 as a CFB coal-fired unit.
7 2. The Appropriate Carbon Dioxide Emission Allowance Prices To Use
8 In Evaluating Proposed Electric Generating Projects
9 Q. How does  E n t e i^ Louisiana view the prospects for carbon regulation?
10 A. Entergy Louisiana witness Schott has testified that "The Company believes that
11 fixture climate change legislation is possible, and based upon recent activity,
12 increasingly probable."*
13 Q. Do you agree with this assessm ent?
14 A. I believe that it is not a question of  " if with regards to federal regulation of
15 greenhouse gas emissions but rather a question of "when." In addition, we agree
16 with Entergy Louisiana witness Schott that there are uncertainties as to the design
17 and details of the CO2 regulations that ultimately will be adopted and
18 implemented.^
19 Q. What mandatory greenhouse gas emissions reductions programs have begun
20 to be examined in the U.S. federal government?
21 A, To date, the U.S. government has not required greenhouse gas ranission
22 reductions. However, a number of legislative initiatives for mandatoiy emissions
23 reduction proposals have been introduced in Congress. These proposals establish
24 carbon dioxide emission trajectories below the projected business-as-usual
25 emission trajectories, and they generally rely on market-based mechanisms (such
Direct Testimony of Matthew J. Schott, Jr., at pi^e 26, lines 13-14.
Direct Testimony of Matthew J. Schott, Jr., at page 24, line 9, to page 25, line 4.
Page 4 •
Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 as cap and trade programs) for achieving the targets. The proposals also include
2 various provisions to spur technology mnovation, as well as details pertainmg to
3 offsets, allowance allocation, restrictions on allowance prices and other issues.
4 Some of the federal proposals that would require greenhouse gas emission
5 reductions that had been submitted m Congress are summarized in Table 1
6 below."*
T a b le  1.
Proposed National
Policy
McCain Lieberman
S.139
McCain Lieberman
SA 2028
McCain Lieberman
S1151
National
Commission on
Energy Policy (basis
for BingamanDomenici
legislative work)
Jeffords S. 150
Carper S. 843
Feinstein
S u m m a ry of  M a n d a t o ry  E m i s s i o ns  T a r g e ts  in  P r o p o s a ls
D i s c u s s ed  in  C o n g r e s s^
Title or
Description
Climate
Stewardship Act
Climate
Stewardship Act
Climate
Stewardship and
Innovation Act
Greenhouse Gas
Intensity
Reduction Goals
Multi-pollutant
legislation
Clean Air
Planning Act
Strong Economy
and Climate
Protection Act
Year
Proposed
2003
2003
2005
2005
2005
2005
2006
Emission Targets
Cap at2000 levels 2010-2015.
Cap at 1990 levels beyond 2015.
Cap at 2000 levels
Cap at 2000 levels
Reduce GHG intensity by 2.4%/yr
2010-2019 and by  2 . 8 %^ 2020-
2025. Safety-valve on allowance
price
2.050 billion tons beguming 2010
2006 levels (2.655 biltion tons
CX)2) starting in 2009,2(K}1 levels
(2.454 billion tons CO2) starting in
2013.
Stabilize emissions through 2010;
0.5% cut per year from 2011-15;
1% cut per year &om 2016-2020.
Total goal would be 7.25% below
current levels.
Sectors Covered
Economy-wide, large
emittii^ sowces
Economy-wide, large
Econoiny-wide, large
knitting sources
Economy-wide, large
emittbig sources
Existing and new
fossil-fuel fired electric
generating plants > 15
MW
Existing and new
fossil-fuel fired,
nuclear, and renewable
electric gen^ating
plants>25MW
Economy-wide, large
enutting sources
•
Tablel is an updated version of Table ES-1 on page 5 of Exhibit DAS-3.
More detailed summaries of the bills that have been introduced in the U.S. Senate in the 110^
Congress are presented in Exhibit DAS-2,
Page 5 E n t e i ^ Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
Rep.Udall-Rep.
Petri
Carper S.2724
Kerry and Snowe
S.4039
Waxman
H.R. 5642
Jeffords
S. 3698
Feinstein- Carper
S.317
Kerry-Snowe
McCain-Lieberman
S.280
Sanders-Boxer
S.309
Giver,  e t al
HR620
Bingamarv-Specter
S.1766
Keep America
Competitive
Global Wanning
Policy Act
Clean Air
Planning Act
Global Warmmg
Reduction Act
Safe Climate Act
Global Warming
Pollution
Reduction Act
Electric Utility
C ^ & Trade Act
Global Warming
Reduction Act
Climate
Stewardship and
Itmovation Act
Global Warming
Pollution
Reduction Act
Climate
Stewardship Act
Low Carbon
Economy Act
2006
2006
2006
2006
2006
2007
2007
2007
2007
2007
2007
Establishes prospective baseline
for greenhouse gas emissions^ with
safety valve.
2006 levels by 2010,2001 levels
by 2015
No later than 2010, begin to
reduce U.S. onissions to 65%
below 2000 levels by 2050
2 0 1 0 - n ot to exceed 2009 level,
annual reduction of 2% per year
until 2020, annual reduction of 5%
tiiereafter
1990 levels by 2020,80% below
1990 levels by 2050
2006 level by 2011,2001 level by
2015, l%^ear reduction from
2016-2019.1.5%Vear reduction
starting in 2020
2010 level from 2010-2019,1990
level from 2020-2029, 2.5%/year
reductions from 2020-2029,
3.5%^ear reduction from 2030-
2050.65% below 2000 level in
2050
2004 level in 2012,1990 level in
2020,20% below 1990 level in
2030,60% below 1990 level in
2050
2%/year reduction from 2010 to
2020,1990 level in 2020,27%
below 1990 level m 2030, 53%
below 1990 level in 2040,80%
below 1990 level in 2050
Cap at 2006 level by 2012,
1%/year reduction from 2013-
2020.3%^ear reduction from
2021-2030.5%^ear reduction
from 2031 -2050. equivalent to
70% below 1990 level by 2050
2012 levels in 2012,2006 levels m
2020.1990 levels by 2030.
President may set furtiier goals
>60% below 2006 levels by 2050
contingent upon intemational
effort
Energy and energyintensive industries
Existii^ and new
frissil-fiiel fired,
nuclear, and renewable
electric generating
plants > 25 MW
Not specified
Not specified
Economy-wride
Electricity sector
Economy-wide
Economy-wide
Economy-wide
US national
Economy-wide
Page 6 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
In addition. Senators Lieberman and Warner have issued a set of discussion
principles for proposed greenhouse gas legislation. This legislation would
mandate 2005 emission levels in 2012,10% below 2005 levels by 2020,30%
below 2005 levels by 2030, 50% below 2005 levels by 2040, and 70% below
2005 levels by 2050.
The emissions levels tiiat would be mandated by the bills that have been
introduced in the current Congress are shown in Figure 1 below:
Figure 1: Emissions Reductions Required under Climate Change Bills in
Current US Congress
1 4 ^ 00
1 2 ^ 00
0*10,000
e
5 8,000
I
f. 6,000
o
M
c
S 4,000
i
2.000
Comparison of Economy-wide Climate Change Proposals
in  n o * Congress 1990-2050
Business  A s U K I BI  ^ ^ " *
8ush
Adirdnistretion
1990 2000 2010
0 W O R L D RESOURCES INSTITUTE
2 0 20  2 0 30  2 0 4 0  2 0 50
D o t t ed Knes indicate  e c t i a p o l a t i « is  of
Energy  Informat ion  A c M n l s O a t i on profecdons
The shaded area in Figure 1 above represents the 60% to 80% range of emission
•Auctions from current levels that many now believe will be necessary to
stabilize atmospheric CO2 concentrations by the middle of this century.
Many of the bills that have been introduced in the 110* Congress call for
emissions reductions to levels that are & below tiie levels that Entergy Louisiana
considered in the development of its base and high CO2 price forecasts.
Page? Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Q. Are individual states also taking actions to reduce greenhouse gas emissions?
2 A. Yes. A number of states are taking significant actions to reduce greenhouse gas
3 emissions. Table 2 below lists the ^nission reduction goals that have been
4 adopted by states in the U.S. Regional action also has been taken in the Northeast
5 and Western regions of the nation.
Pages Entergy Louisiana - Little Gypsy Repowering
Docket No. U.30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
Table 2: Announced State and Regional Greenhouse Gas Emission
Reduction Goals
state
Arizona
Callfbmta
Connecticut
Delaware
Florida
Hawaii
Illinois
Maine
Marvland
Massachusetts
Minnesota
New Hampshire
New Jersey
New Mexico
NewYorIt
Oregon
Rhode island
Utah
Vermont
Washington
GHG Reduction Goal
2000 levels by 2020;
50% below 2000 levels bv 2040
2000 levels by 2010;
1990 levels by 2020;
80% below 1990 levels bv 2050
1990 levels by 2010;
10% below 1990 levels by 2020; 75-65%
below 2QQ1
levels In ttie km^  t o rn
2000 levels by 2017.
1990 levels by 2025.
and 60 percent below
1990 iBvals bv 2050
1990 levels by 2020
1990 levels by 2020; 60% below 1990
levels by 2050
1990 levels by  2 6 l d:  l 6 ^ below 1990 '
levels by 2020; 75-80% below 2003
levels
1 9 ^ levels by  i 6 l 0;  1 b^ below  I dM
levels by 2020; 75-85% below 1990
levels
16% by 2015. 30% by 2025. "
80% bv 2050
1990 levels by 2010;  ^ 0% bekw 19d0
levels by 2020; 75-85% below 2001
levels
1990 levels by 2020; 80% below 2006
levels bv 2050
2000 levels by 2012; 10% below 2000
levels by 2020:
75% below 2000 levels bv 205D
5%betow1990levelsby2010:10%
below 1990 levels by 2020
Stabilize by 201D;
10% below 1990 levels by 2020;
75%  b e kw 1990 levels bv 2050
10% below 1990 levels by 2020;  7 5 ^ 0%
below aooi levels
in the lorw lenm
1990 levels by 26^6;
10% below 1990 levels by 2020; 75-85%
below 2001 levels
1990 levels by 2020; 25% below 1990
l e v e ls  by  2 0 3 5;
5 0%  b e l ow 199D  levels  bv  2 0 50
Vltostem Climate
liUtlalive member
(16% below 2005 levels by
2020)
yes
yes
yes
yes
yes
yes
R e g i o i ul Greenhouse Oa«
Inttiaftive member
(Cap atcunrent  leveb 2009>
2016, reduce  this by 10% by
2019)
yes
WB
•
yes
ves
yes
yes
yes
yes
yes
yes
Page 9 Entergy Louisiana - Little Gypsy Repowering
Docket No, U-30192
Direct Testimony of David A. Schlissel
PubUc Version - Protected Materials Redacted
1 Q.  Is it reasonable to believe  that the prospects for passage of federal legislation
2 for the regulation of greenhouse gas emissions have improved as a resalt of
3 last November's federal elections?
4 A. Yes. As shown by the number of proposals being introduced in Congress and
5 public statements of support for taking action, there certamly are an mcreasing
6 numbers of legislators who are inclined to support passage of legislation to
7 regulate the emissions of greenhouse gases.
8 Nevertheless, my conclusion that significant greenhouse gas regulation m the U.S.
9 is inevitable is not based on the results of any suigle election or on the fate of any
10 single bill introduced in Congress.
11 Q. Have recent polls indicated  that the American people are increasingly in
12 favor of government action to address global warming concerns?
13 A. Yes, A summer 2006 poll by Zogby Intemational showed that an overwhehnmg
14 majority of Americans are more convinced tiiat global warming is happenmg than
15 they were even two years ago. In addition, Americans also are connecting intense
16 weather events like Hurricane Katrina and heat waves to global wiarming.^
17 Indeed, the poll found that 74% of all respondents, including 87% of Democrats,
18 56% of Republicans and 82% of Independents, believe that we are experiencing
19 the effects of global warmmg.
20 The poll also indicated that there is strong support for measures to require major
21 industries to reduce their greenhouse gas emissions to improve the environment
22 without harming the economy - 72% of likely voters agreed such measures
23 should betaken.^
24 Other recent polls reported sunilar results. For example, a Time/ABC/Stanford
25 University poll issued in the spring of 2006 found 68 percent of Americans are in
"Americans Link Hurricane Katrina and Heat Wave to Global Warming," Zogby International,
August 21,2006, available at www.20gby.con1/news.
Page 10 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 favor of more government action to address climate chsmge.^ In addition, a
2 September 2006 telephone poll, conducted by NYU's Brademas Center for the
3 Study of Congress, reported that 70% of tiiose polled stated that they were
4 worried about global warming.*
5 At the same time, according to a recent public opinion survey for the
6 Massachusetts Institute of Technology, Americans now rank climate change as
7 the county's most pressing envu*onmental problem—a dramatic shift from three
8 years ago, when they ranked clunate change sbcth out of 10 environmental
9 concerns.^ Almost three-quarters of the respondents felt the government should do
10 more to deal with global warming, and mdividuals were willing to spend their
11 own money to help.
12 Q. What CO2 prices has Energy Louisiana used in its modeling of the proposed
13 Little Gypsy repowering project?
14 A. Entergy Louisiana presented a "Reference Case Analysis" that assumed $0/ton
15 CO2 prices.^*' The Company also prepared sensitivity analyses assuming what it
16 calls base CO2 and high CO2 emissions allowance prices."
17 Q. Is it prudent and reasonable to assume no CO2 emissions allowance prices in
18 the Reference Case Analysis?
19 A. No. It is not prudent to project that there will be no regulation of greenhouse gas
20 emissions at any point over the next thirty or more years. As I will discuss later in
21 this testimony, federal regulation of greenhouse gas emissions is highly likely in
22 the near future. States also have started to take actions to reduce greenhouse gas
"Polls find groundswell of belief in, concern about global warming." Greenwire, April  2 1 , 2 0 0 6,
Vol. 10  N o. 9. See also Zogby*s final report on  the poll which is  a v d l a b le at
httD://www.zogbv.comAvildlife/NrWFfiiiaireport8'17-06.htm.
Kaplun, Alex: "Campaign 2006: Most Americans  'wor r i ed' about energy, climate;" Greenwire,
September  2 9 . 2 0 0 6.
MIT Carbon Sequestration Imtiative,  2 0 06 Survey,
http ://5equestration.mit.edu/rBsearch/survey2006.html
Exhibit APW-11.
Direct Testimony of Anthony P. Wa l z, at page 34, lines 3-8.
Page  II Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A, Schlissel
Public Version - Protected Materials Redacted
1 emissions both on theu^ own and as part of regional initiatives. Moreover, given
2 all of their public statements about the dangers posed by global clunate change
3 and the necessity of addressing that threat, I tind it hard to accept that Entergy
4 believes that this is a reasonable scenario.
5
6
7
8
9
10
A.
Have you seen any projections of what Entergy's future CO2 emissions would
be under the Company's reference case assumption that there will be no
regulation of greenhouse gas emissions?
Yes. As shown in Figure 2 below, the results of the PROSYM analysis discussed
by Entergy Louisiana witness Walz show that Entergy's  C 02 emissions would
[Redacted] in the scenario with Little Gypsy Unit 3 repowered as a CFB:
11
12
13
Figure 2; Entergy COj Emissions Trajectory with Littie Gypsy Unit 3
Repowered as a CFB Coal-Fired Plant
14 Q. What C02 prices did  E n t e i^ Louisiana assume in its base and high CO2
15 sensitivities?
16 A. Entergy's base and high C02 price forecasts are presented in Table 3 below:
P ^ e l2 E n t e r gy Louisiana - Li t t le Gypsy Repowe r ing
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
Table  3; •  E n t e i ^ Loui s i ana CO2  P r i ce For e c a s ts
Q. How do these forecasts  c h a n ge after 2030?
A. The Company's base CO2 forecast would [
R EDAC T ED
would [
] . "
] *^ Entergy's high CO2 price forecast
R EDAC T ED
C02 Point of View, Entergy Corporation, December 13,2005, provided in the Response to
Question AAE 1-2, at pages 27 and 28.
Response to Question LPSC 1-30, at page LR168. A copy of this response is included in Exhibit
DAS-8.
Page 13 1
2
3
4
5
6
7
8
9
10
11
12
13
Q.
A.
Q.
A.
QA.
Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
How did Entergy Louisiana develop its base CO2 price forecast?
Entergy Louisiana witness Walz has testified that *The base CO2 cost
assumptions were developed by reviewmg various consulting forecasts for CO2
costs. As such, the base CO2 assumptions represent a consensus forecast."'^
When was this base CO2 price forecast prepared?
It appears that this base CO2 price forecast was developed m [ Redacted ]}^
How do the annual prices in Entergy's base COi forecast compare to the
forecasts on which the Company has said it relied based?
Figure 3 below compares Entergy Louisiana's base CO2 forecast with the other
"consulting" forecasts on which the Company has indicated it relied. As can be
seen,  E n t e i ^ 's base CO2 forecast is significantiy lower than all but one of the
other forecasts. Thus, it makes no sense to say that Entergy's base CO2 price
forecast represents a consensus with the other forecasts, as Mr. Walz testifies.
Direct Testimony of Anthony P. Walz, at page 34, lines 11-13.
C02 Point of View, Entergy Corporation, December 13,2005, provided in the Response to
Question AAE 1-2, at pages 27 and 28.
Page 14 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Figure 3: Entergy base  C 02 Prices vs. Other Forecasts Considered by
2 Entergy.
4 Q. How do the emissions levels assumed by  E n t e i^ in its base CO2 forecast
5 compare to the emissions target levels in the bills that have been introduced
6 in the current U.S. Congress?
7 A. Entergy's base CO2 price forecast assumes that starting [
8
9 REDACTED ] These emissirais
10 levels are substantially less strmgent than the emissions t^get levels in the bills
11 that have been introduced m the current U.S. Congress. For example, as shown in
12 Table 1 above, the current McCain-Lieberman bill, Senate Bill 280, would
13 mandate tiiat emissions be at 1990 levels by 2020 and 20% below 1990 levels by
14 2030. Similarly, the legislation proposed by Senators Feinstein and Carper,
Page 15 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Senate Bill 317, would require CO2 emissions be reduced to 2001 levels by 2015
2 and 13% below 2001 levels by 2026. Even the legislation recentiy proposed by
3 Senators Bingaman and Specter, which mclude safety-valve prices, would  r ^ u i re
4 tiiat emission levels be reduced to 1990 levels by 2030.
Entergy Louisiana witness Schott has testified concerning reductions in
greenhouse gas emissions intensity and has presented as an exhibit a March
2006 EIA report entitied ^Energy Market Inq>acts ofAhemathe Greenhouse
Gas Intensity Reduction Goals."'^ Are you aware of any major bill being
considered in the current Congress that would regulate the greenhouse gas
intensity of power plant emissions rather than mandating that overall
emissions levels be reduced?
No. The draft proposal that was circulated by Senator Bingaman in 2006 would
have regulated greenhouse gas emission intensity. However, this approach was
abandoned in the bill that Senators Bingaman and Specter actually introduced in
July 2007. This bill would require that overall greenhouse gas emissions levels be
capped at 2012 levels in 2012 and then be reduced to 2006 levels m 2020 and
1990 levels by 2030.
Is it reasonable to consider this Entergy forecast a **base'' CO2 price forecast,
as Entergy Louisiana has claimed?
No. It is much too low to be a base CO2 price forecast. It might be reasonable as
a low CQ2 price forecast except for the fact that it assumes that CO2 emissions
allowance prices [ REDACTED  ] . '^
How did Entergy develop Its high CO2 price forecast?
Entergy Louisiana's high CO2  F ^ ^ forecast is based on an [
REDACTED  ] . '*
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Q.
A.
Q.
A.
Q.
A.
Direct Testimony of Matthew S. Schott, Jr., at page 25, line 17, to page 26, h'ne 2.
C02 Point t^View, Entergy Corporation, December 13,2005, provided in tiie Response to
Questioct AAE 1-2, at pages 27 and 28.
Page 16 Entergy Louisiana - Little Gypsy Repowering
Docket No. U.30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Q. Is this a reasonable "high" CO2 price forecast?
2 A. No. Although the forecast is fer more reasonable than the Company's base CO2
3 price forecast, it still is too low to be considered the high end of a reasonable
4 range of possible future CO2 emissions allowance prices. In particular, Entergy's
5 high CO2 price forecast does hot reflect tiie emissions allowance prices that could
6 result from a number of the bills that have been introduced in Congress which
7 propose very significant emissions reductions.
8 Q. What carbon dioxide values are being used by utilities in electric resource
9 planning?
10 A. Table 6.1 on page 41 of 63 of Exhibit DAS-3 presents the carbon dioxide costs, in
11 $/ton CO2, that were being used as of 2006 by a number of utilities for both
12 resource plaiming and modeling of carbon regulation policies.
13 Q. Are you aware of any recent regulatory commission decisions concerning the
14 levels of carbon dioxide emissions prices that utilities should consider when
15 planning how to supply energy to their customers?
16 A. Yes. The New Mexico Public Regulation Commission recently ordered that
17 utilities should consider a range of CO2 prices hi then- resource planning. This
18 range runs from $8 to $40 per metric ton, beginning in 2010 and mcreases at the
19 overall 2.5 percent rate of inflation. This range includes significantiy higher CO2
20 prices than the base and high CO2 prices used by Entergy Louisiana m its analyses
21 of the Little Gypsy rcpowaing project.'^
22 Q. Has Synapse developed a carbon price forecast that would assist the
23 Commission in evaluating the proposed repowering ofLittle Gypsy Unit 3?
24 A. Yes. Synapse's forecast of future carbon dioxide emissions prices are pres^ted in
25 Figure 4 below.
Response to LPSC 1-30, at ps^e LR167.
A copy of the New Mexico Public Regulation Commission Order is included as Exhibit DAS-4.
Page 17 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Figure 4. Synapse Carbon Dioxide Prices
70
60
60
40
2
3 Q.
4 A.
5
EIASA202B EVKVCB'
- S A C a p & T Mt D EPAS.19()
• BF>AS.8I3 -«-T0ltU8S. 139
T0iiusSA2Q2a  - « ~ M n r a i 39
--Synapse High Case
— S y n a p se Mid Case
- ' Synapse Low Case
2030
What is Synapse's cairbon price forecast on a levelized basis?
Synapse's forecast, levelized^** over 20 years, 2011 - 2030, is provided in Table 4
below.
Table 4: Synapse's Levelized Carbon Price Forecast (2005$/ton of CO2)
Low Case
$8.23
Mid Case
$19.83
High Case
$31.43
7 Q, When were the Synapse CO2 emission allowance price forecasts shown in
8 Figure 4 developed?
9 A. The Synapse CO2 emission allowance price forecasts were developed in the
10 Spring of 2006.
Page 18 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Q. How were these CO2 price forecasts developed?
2 A. The basis for the Synapse CO2 price forecasts is described in detail in Exhibit
3 DAS-3, starting on page 41 of 63.
4 In general, the price forecasts were based, in part, on the results of economic
5 analyses of individual bills that had been submitted m the 108* and 109*
6 Congresses. We also considered the likely impacts of state, regional and
7 intemational actions, the potential for ofisets and credits, and the likely future
8 trajectories of both emissions constraints and technological program,
9 Q. Are the Synapse CO2 price forecasts shown in Figure 4 based on any
10 independent modeling?
11 A. Yes. Although Synapse did not perform any new modeling to develop our CO2
12 price forecasts, our CO2 price forecasts were based on the results of independent
13 modeling prepared at the Massachusetts Institute of Technology ("MTr*), the
14 Energy Information Administration of Ihe Department of Energy ("EIA"), Tellus,
15 and the U.S. Environmental Protection Agency ("EPA").^*
16 Q. Do the triangles, squares, circles and diamond shapes in Figure 4 above
17 reflect the results of all of the scenarios examined in the MIT, EIA, EPA and
18 Tellus analyses upon which Synapse relied?
19 A. As a general rule, Synapse focused our att^tion either on the modeler's primaiy.
20 scenario or on the presented high and low scenarios to bracket the range of
21 results.
22 For example, the blue triangles in Figure 4 represent the results from EIA's
23 modeling of the 2003 McCdn Lieberman bill, S.139. Synapse used the results
24 from EIA's primary case which reflected the bill's provisions that allowed: (a)
A value that is "levelized" is the present value of the total cost converted to equal annual
payments. Costs are levelized in real dollars (i.e., adjusted to remove the impact of inflation).
See Table 6.2 on page 42 of 63 of Exhibit DAS-3.
Page 19 Entergy Louisiana - Little Gypsy Repowering
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1 allowance banking; (b) use of up to 15 percent oflfeets in Phase 1 (2010-2015) and
2 up to 10 percent offsets in Phase II (2016 and later years). The S.139 case also
3 assumed commercial availability of advanced nuclear plants and of geological
4 carbon sequestration technologies in the electric power industry.
5 Sunilarly, the blue diamonds in Figure 4 represent the results from MIT's
6 modeling of the same 2003 McCain Lieberman bill, S,139. MIT examined 14
7 scenarios which considered the impact of &ctors such as the tightening of tiie cap
8 in Phase II, allowance banking, availability of outside credits, and assumptions
9 about GDP and emissions growth. Synapse included the results from Scenario 7
10 which included allowance banking and zero-cost credits, which effectively
11 relaxed the cap by 15% and 10% in Phase I and Phase II, respectively. Synapse
12 selected this scenario as the closest to the S.139 legislative proposal smce it
13 assumed that the cap was tightened in a second phase, as in Senate Bill 139.
14 At tiie same time, some of the studies only included a smgle scenario representing
15 the specific features of the legislative proposal being analyzed. For example, SA
16 2028, the Amended McCam Lieberman bill set the emissions cap at constant 2000
17 levels and allowed for 15 percent of the carbon emission reductions to be met
1S through offsets from non-covered sectors, carbon sequestration and qualified
19 intemational sources. EIA presented one scenario in its table for this policy. The
20 results from tiiis scenario are presented in the green triangles in Figure 4.
21 Q. Do you believe that technological Improvements and policy designs will
22 reduce the cost of CO2 emissions?
23 A. Yes. Exhibit DAS-3 identifies a number of  ^ t o rs that will afTect projected
24 allowance prices. These factors include: the base case emissions forecast;
25 whether there are complimentary policies such as aggressive investments in
26 energy efficiency and renewable energy independent of the emissions allowance
27 market; the policy implementation timelme; the reduction targets in a proposal;
Page 20 Entergy Louisiana - Little Gypsy Repowering
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Direct Testimony of David A. Schlissel
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1 program flexibility involving the mclusion of oflfeets (perhaps intemational) and
2 allowance banking; technological progress; and emissions co-benefits.^ In
3 particular, Synq)se anticipates that technological innovation will temper
4 allowance prices in the out years of our forecast.
5 Q. Could carbon capture and sequestration be a technological innovation that
6 might temper or even put a ceiling on CO2 emissions allowance prices?
7 A. Yes.
8 Q. Does Entergy see carbon capture technology as a currently commercially
9 viable way to mitigate CO2 emissions f^om pulverized coal plants like the
10 Littie Gypsy project?
11 A. No. Entergy has expressed the following position concerning the technical
12 feasibility of both CO2 capturc.and CO2 sequestration for the emissions from the
13 Little Gypsy project:
14 To date, carbon capture and sequestration has not been
15 demonstrated commercially on any power plant in the United
16 States. Even today, pilot scale projects are only riow being
17 developed in tfie United States. The Company does not believe
18 that this technology is commercially and reliably viable on a utility
19 scale at the current level of technology development. Significant
20 research and development in the performance, cost, and reliability
21 of carbon capture technology remains to be completed. In addition,
22 further research is also required on underground sequestration of
23 carbon, including costs, permitting, and technological
24 advancement such as q>propriate geological formations and
25 appropriateness for long term storage of carbon dioxide and the
26 transportation of CO2 gas.^
27 Q. Do you agree with this assessment?
28 A. I agree with this view of the current status of carbon cq>ture and sequestration
29 technology although I would note that tiiere is some experience witii tiie piping of
Exhibit DAS-3, at pages 46 to 49 of 63.
Response to Question No. LPSC 1-18. A copy of ftis response in included in DAS-8.
P ^ e 21 E n t e r gy Loui s i ana - Li t t le Gypsy Repowe r ing
Docket No. U-30192
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Public Version - Protected Materials Redacted
1 CO2 gas for enhanced oil recoveiy and industrial use in certain geogrsq^hical
2 areas.
3 Q. Is there any consensus when carbon capture and sequestration technology
4 will become commercially viable for plants like a repowered Little Gypsy
5 Unit 3?
6 A. No. I have seen estimates that carbon cq>ture and sequestration technology may
7 be proven and commercially viable from as early as 2015 to 2030 or later.
8 Q. What are the currentiy estimated costs for carbon capture and sequestration
9 at pulverized coal facilities?
10 A. Hope has been expressed concerning potential technological improvements and
11 learning curve effects that might reduce the estimated cost of carbon capture and
12 sequestration. However, I have seen recent estunates that the cost of carbon
13 capture and sequestration could increase the cost of producing electricity at coal-
14 fired power plants by 60-80 percent, on a $/MWh basis, A very recent study by
15 the National Energy Technology Laboratory ("NEIL") projects that the cost of
16 carbon capture and sequestration would be $75/tonne^ of CO2 avoided, in 2007
17 dollars, for pulverized coal plants. This translates in to $65/ton of CO2 avoided, in
18 2005 dollars. The March 2007 "Future of Coal Study" from the Massachusetts
19 Institute of Technology estimated that the cost of carbon capture and
20 sequestration would be about $28/ton although it also acknowledged that there
21 was uncertamty m tiiat figure.^^ The tables in that study also indicated
22 significantly higher costs for carbon capture for pulverized coal &cilities, m the
23 range of about $40/ton and higher.^
24 However, even when the technology for CO2 capture matures, there will always
25 be significant regional v^ations m the cost of storage due to the proximity and
A tonne or metric ton is a measurement of mass equal to ],000 kilograms or 1.1 tons.
The Future of Coed, Options for a Carbon-Constrained World, Massachusetts Institute of
Technology, March 2007, at page xi.
Page 22 Entergy Louisiana - Little Gypsy Repowering
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1 quality of storage sites. [
2  R EDAC T ED
3  I ' '
4 Q. Has  E n t e i ^ included any carbon capture and sequestration equipment or
5 features in the current design for the repowered Little Gypsy facility?
6 A. No.^^
7 Q. Do the Synapse CO2 price forecasts reflect the potential for the inclusion of
8 domestic offsets and, perhaps, international offsets in U.S. carbon regulation
9 policy?
10 A. Yes. Even the Synapse high CO2 price forecast is consistent witii, Mid in some
11 cases lower than, the results of studies that assume the use of some levels of
12 offeets to meet mandated emission limits. For example, as shown in Figure 4, the
13 highest price scenarios in the years 2015,2020 and 2025 were taken from the EIA
14 and MIT modeling of the original and the amended McCain-Liebennan proposals,
15 Each of the prices for these sc^arios shown in Figure 4 reflects tiie allowed use
16 of offsets.
17 Q. How do the Synapse CO2 price forecasts compare to the forecast used by
18 Entergy Louisiana in its recent analyses of the proposed repowering ofLittle
19 Gypsy?
20 A. The Synapse and Entergy Louisiana CO2 price forecasts are shown in Figure 5
21 below. As this Figure demonstrates, the Company's base CO2 price forecast is
22 similar to our Synapse low forecast and the Company's high CO2 price forecast is
23 similar to our mid-forecast.
14 at page 19.
Response to LPSC 1-30, at page LR168.
Response to AAE 1-47.
Page 23 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
Figure 5; Synapse and Entergy Louisiana CO2 Price Forecasts
•
ftfl
ou -
i "
0
1  ^ 0 •
S 10-
Entargy Louisiana
a Synapse C02 Price Scenarios
.-^S-
^ "^
-.
_ -^ "^
' - '
, - - • " • '
_ . - •
I f  ^ " ^
m  ^ ^
^ ^ -
- - • - '
_ . "
U 1 1 1 <
2010 2015 2020 2025  20
Synapse High
Synapse Mid
Synapse Low
PI 1  H i nh
30
3 Q. Have you seen any recent independent forecasts of future CO2 emissions
4 prices that are similar to the Synapse forecast?
5 A. Yes. The recent MIT study on The Future of Coal contained a set of assumptions
6 about high and low fiiture CO2 emission allowance price. Figure 6 below shows
7 that the CO2 price trajectories in the MTT study are very close to the high and low
8 Synapse forecasts.
Page 24 •
Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Figure 6: CO2 Price Scenarios - Synapse & MIT March 2007 Future of
2 Coal Study
4 Q.
5
6
7 A.
8
9
10
11
12
13
14
15
16
17
18
Synapse & MTT  C 02 Price Scenarios
Syrapse High
Syrapse Mid
Synapse Low
Mr rHigh
MIT Low
2010  2015  2020  2025
2030
Do you believe that the Synapse CO2 price forecasts remain valid despite
being based, in part, on analyses from 2003-2005 which examined legislation
that was proposed in past Congresses?
Yes. Synapse believes it is important for the Commission to rely on the most
current mformation available about future CO2 emission allowance prices, as long
as that mformation is objective and credible. The analyses upon which Synapse
relied when we developed our CO2 price forecasts were the most recent analyses
and technical information available when Syn^ se developed its CO2 price
forecasts in the Spring of 2006. However, new information shows that our CO2
prices remain valid even though the origmal bills that comprised part of the basis
for the forecasts expired at the end of the Congress in which they were
introduced.
Most importantly, many of the new greenhouse gas regulation bills that have been
introduced in Congress are significantiy more stringent than the bills that were
being considered prior to the sprmg of 2006. As I will discuss below, the
Page 25 Entergy Louisiana - Little Gypsy Repowering
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1 increased stringency of current bills can be expected to lead to higher CO2
2 emission allowance prices. The higher forecast natural gas prices that are being
3 forecast today, as compared to the natural gas price forecasts from 2003 or 2004,
4 also can be expected to lead to higher CO2 emissions allowance prices.
5 Q. Do the Synapse carbon price forecasts presented in Figures 4 and 6 reflect
6 the emission reduction targets in the bills that have been introduced in the
7 current Congress?
8 A. No. Synapse developed our price forecasts late last spring and relied upon bills
9 that had been mtroduced in Congress through tiiat time. The bills that have been
10 introduced in the current US Congress generally would mandate much more
11 substantial reductions in greenhouse gas emissions than the bills that we
12 considered when we developed our carbon price forecasts. Consequentiy, we
13 believe that our forecasts are conservative.
14 Q. Have you seen any analyses of the CO2 prices that would be required to
15 achieve the much deeper reductions in CO2 emissions that would be
16 mandated under the bills currently under consideration in Congress?
17 A. Yes. An Assessment of U.S. Cc^and-Trcuie Proposals was recently issued by
18 tiie MTT Joint Program on the Science and Policy of Global Change. This
19 Assessment evaluated tiie impact of the greenhouse gas regulation bills that are
20 being considered in the cuirent Congress.
21 Twenty nine scenarios were modeled in the Assessment. These scenarios reflected
22 differences in such factors as emission reduction targets (that is, reduce CO2
23 emissions 80% fiom 1990 levels by 2050, reduce CO2 emissions 50% from 1990
24 levels by 2050, or stabilize CO2 emissions at 2008 levels), whether banking of
25 allowances would be allowed, whether intemational trading of allowances would
26 be allowed, whether only developed countries or the U.S. would pursue
•
Page 26 Entergy Louisiana - Little Gypsy Repowering
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greenhouse gas reductions, whether there would be safety valve prices adopted as
part of greenhouse gas regulations, and other factors.
29
In general, the ranges of the projected CO2 prices in tiiese scenarios were higher
than the range of CO2 prices m the Synapse forecast For example, twelve of the
29 scenarios modeled by MIT projected higher CO2 prices in 2020 than the high
Synapse forecast. Fourteen of the 29 scenarios (almost half) projected higher CO2
prices in 2030 than the high Synapse forecast.
Figure 7 below compares the three Core Scenarios in the MIT Assessment with
the Synapse CO2 price forecasts.
10
11
Figure 7; CO2 Price Scenarios - Synapse and Core Scenarios in April
2007 MTT Assessment of U,S, Cap-and-Trade Proposals
12
$ 2 50
$ 2 00
»  $ 1 50
I
^ $100
2000  2 0 10  2020  2030  2040  2 0 50
Synapse Low Synapse Mid
Synapse High EPA Senate Scenario
- EPA Senate Scenario with Low  I n ti  A c t o rs - EPA Scenario with  U n l M t ed  O f f e rs
» EPA Senate Scenario No C^aets • EPA Senate Sc«i«Hio Lew Nudear
A EPA  S e r ^ te Scenario No CCS • EIA 8260 Core  S c « t a r io
• EIA Fixed  3 0% Offsets • EIA No International Offsets
The scenarios examined in the MIT Assessment ofU.S. C^qy-and-Treuk Proposals are listed in
Exhibit DAS-5.
P i ^ 2 7 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Q. Have you compared the Synapse CO2 emissions allowance price forecasts to
2 any oUier assessment of current bills in Congress?
3 A. Yes. Both EPA and the Energy Information Agency (EIA) of the Department of
4 Energy have analyzed the impact of the current version of the McCain-Lieberman
5 legislation (Senate Bill 280).^^ Figure 8 below shows that the Synap3e CO2 price
6 forecasts are consistent with the range of scenarios examined in the EPA and EIA
7 assessments:
Figure 8: Synapse CO2 Price Forecasts and Results of EPA and EIA
Assessment of Current McCain Lieberman Legislation
10
$250
2000  2010  2020  2030  2040  2050
—
—
-
*
«,
•
-Synapse Low
-Synapse High
EPA Senate Scenario with Low  I n ti Actions
EPA Senate Scenario No Offsets
EPA Senate Scenario No CCS
EIA Fixed  3 0% Offsets
™
-
•
•
•
-Synapse Mid
EPA Senate Scenario
EPA Scenario with Unlimited Offeets
EPA Senate Scenario Low Nudear
EIA S280 Cone Scenario
EIA No Intemationat Offeets
Energy Market and Economic Impacts ofS. 280, the Climate Stewardship and Innovation Act <f
2007. Enw^gy Information Administration, July 2007 and EPA Analysis of the Climate
Stewardship and Innovation Act of 2007, S. 280 in  I I (f Congress, July 16,2007.
Page 28 E n t e i^ Louisiana - Little Gypsy Repowering
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Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
Q. How do the Synapse CO2 forecasts compare to the safety valve prices in the
bill introduced by Senators Bingaman and Specter?
3 A. As shown in Figure 9 below, the safely valve prices in the legislation mtroduced
4 by Senators Bingaman and Specter fall between the Synapse mid and low
5 forecasts.
Figure 9: Synapse CO2 Price Forecasts and Safety Valve Prices in
Bingaman-Specter Legislation in llO''^ Congress
60
3 50
40
30
20
10
-  I I  . 1 .  . y — — I . II •• -  • — • • -  - — — • I  — . • I  i - n . .11..  • _ J - , i a il
. L  __  Xl "** *
—  i — ^ ,  ^ ^ _ _ _ ^ - E - s : : ^ -
- I  j p i ^ ^ ^ i i i . i T . , — - ,  — " ' ' ^ M •  „ • ' I  . . I I
/ - " '
H  t - n ^ f  - i - i— . — •
2010  J3aA£.  ' i r mn  onoK
' y n in
Synapse High
Synapse Low
Synapse Mid
- «— Bingaman-Specter Bi8
9
10
11
12
13
14
15
What are you recommendations concerning the CO2 prices that the
Commission should use in evaluating the proposed repowering of Littie
Gypsy Unit 3 as a CFB?
Given tiie uncertainty associated with the legislation that eventually will be
passed by Congress, we believe that the Commission should use the wide range of
forecasts of CO2 prices shown in Figure 4 above to evaluate the relative
economics of the proposed Repowering Project
Page 29 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
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1 Q. How much additional CO2 would the repowered Littie Gypsy Unit 3 emit
2 into the atmosphere?
3 A. The repowered Littie Gypsy Unit 3 would emit approximately 4 million tons of
4 CO2 annually.^'
5 Q. What would be the annual costs of greenhouse gas regulations to Entergy
6 Louisiana and its ratepayers under the Synapse CO2 price forecasts if the
7 Company proceeds with its plan to repower Littie Gypsy Unit 3 as a CFB
8 plant?
9 A. The range of the incremental annual, levelized cost to the Company and its
10 ratepayers from greenhouse gas regulations would be:
11 SynE^se Low CO2 Case: 4 million tons of CO2 * $8.23/ton = $33 million
12 Synapse Mid CO2 Case: 4 million tons of CO2 • $19.83/ton = $79 million
13 Synapse High CO2 Case: 4 million tons of CO2 • $31.43/ton = $126 million
14 3. The Probable Economic Impact of the Proposed Repowering Project
15 Q. Do the results of the Fundamental Analysis presented by Entergy Louisiana
16 witness Walz show that repowering Little Gypsy Unit 3 as a CFB is the
17 lowest cost, lowest risk option for the Company and its ratepayers?
18 A. No. The Fundamental Analysis is critically flawed in a number of ways that
19 result in its being biased in favor of the rqwwering altemative:
20 • AU of the Reference Case comparisons in the Fundamental Analysis tiiat
21 assume $0/ton CO2 prices (that is, no federal or state regulation of
22 greenhouse gas emissions) are extremely unrealistic and unlikely.
23 * Entergy Louisiana did not evaluate any demand side management or
24 renewable resources as part of a portfolio of altematives to the repowering
25 ofLittle Gypsy Unit 3.
This reflects an 85 percent average annual capacity fector and CO2 emissions of 21S0'lbs/MWh.
Page 30 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 • As I explained earlier, given the uncertainties concerning future CO2
2 prices the range reflected in the two CO2 forecasts considered as
3 sensitivities in the Fundamental Analysis is too narrow. In particular, the
4 Company's "base" and "high" sensitivity CO2 price forecasts are
5 unreasonably low.
6 • The current cost estimate for the Repowering Project assumes the use of a
7 number of existing site facilities. However, the cost estimate for the
8 altemative CCGT facility does not. Instead, the Company assumes tiiat
9 tiie altemative CCGT facility would be built at a Greenfield site.
10 Q. Did Entergy Louisiana include any costs for carbon capture and
11 sequestration in its Fundamental Analysis for either the Repowering Project
12 or the CCGT aHemative?
13 A. No.
14 Q. Did Entergy Louisiana reflect in the Fundamental Analysis any of the
15 performance penalties that can be expected from the addition and use of
16 carbon capture technology for either the Repowering Project or the CCGT
17 altemative?
18 A. No. It is generally accepted that the addition and operation of carbon capture
19 equipment is expected to have an adverse impact on power plant performance.
20 For example, operation of carbon capture equipment is expected to require
21 substantial amoimts of  e n e i ^. As a result, the power plant is expected to
22 experience an energy penalty of between 10 percent and 29 percent as a result of
23 adding the carbon capture technology resultii^ in a significant decrease in the
24 plant's net power output.^^ However, Entergy Louisiana did not reflect any such
25 performance penalties in its Fundamental or PROSYM analyses.
For example, see Update on Clean Coal Technologies and C02 C(q>ture & Storage, a June 27,
2007 presentation to the Oregon Public Utility Commission by Neville Holt, EPRI Technical
Fellow, Advanced Coal Generation Technology. Available at
http://wvm.puastate.or.us/PUameetings/pmemos/2007/062707/ChegonPUCCCrCCS62707.ppt
Page 31 E n t e i ^ Louisiana - Little Gypsy Repowering
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1 Q. Have you seen any evidence that Entergy Louisiana considered demand side
2 management or renewable resources as potential altematives, even in part,
3 for the repowering of Littie Gypsy Unit 3?
4 A. No. Entergy Louisiana essentially has focused on fossil altematives. I have seen
5 no evidence that it seriously considered and m detail investments in demand side
6 management or renewable options as part of the resource plannuig for the
7 repowering project. Indeed, tiie Company has indicated that it has not even
8 studied the potential for energy efficiency or renewable resources m its service
9 territory at any time in the past decade.^^
10 Q. What is the significance of this failure to seriously consider demand side
11 management and renewal resources?
12 A. Because Entergy Louisiana has failed to consider a wide range of altematives, the
13 Compmiy catmot demonstrate that there is not a lower cost, lower risk ahemative
14 than repowering Little Gypsy Unit 3. Such lower cost, lower risk plans might
15 include a portfolio of additional investments m demand side management, some
16 self-build or purchased wuid or renewable resources, and some natural gas-fired
17 capacity.
18 Q, Has Entergy Louisiana  ^ t ima t ed the savings associated with construction
19 the Little Gypsy Project as a repowering of Unit 3 rather than constructing
20 the unit as a stand-alone CFB project?
21 A. No. Entergy Louisiana has said that it has not prepared an estimate that compares
22 the cost of the Little Gypsy Repowermg Project with the cost of a Greenfield CFB
23 project.^* However, the Company generally believes that a repowermg project
Responses to Questions AAE 1-16 and AAE 1-17. Copies of these responses are included in
Exhibit DAS-8.
Response to Question LPSC I-IO. A copy of this response is included in Exhibit DAS-S.
Page 32 Entergy Louisiana - Little Gypsy Repowering
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1 would be less costiy than a Greenfield CF project because certain systems and
2 components of the existing facility will be reused.^^
3 Q. Does the Company's estimate for the cost of the alternative CCGT focility
4 similarly reflect savings from the reuse of existing facilities at the Little
5 Gypsy site?
6 A. No.^^
7 Q. Has the Company studied the potential cost of repowering Little Gypsy Unit
8 3 as a CCGT fiicility?
9 A. No.^^
10 Q. Is it reasonable to expect that the cost of repowering Little Gypsy Unit 3 as a
11 CCGT would be lower than the cost of building a new CCGT unit at a
12 greenfield site?
13 A. Yes. In general, for the same reasons that Entergy Louisiana expects savings In
14 the cost of the repowering project, it is reasonable to expect that the cost of
15 repowering Little Gypsy as a CCGT would be lower than tiie cost of building a
16 new unit at a greenfield site.
17 Q. Is it reasonable to expect  that the cost of the Repowering Project will
18 increase above the current $1.55 billion estimate?
19 A. Yes. Entergy Louisiana witness Long has noted that rising commodities and
20 labor prices have led to significant increases in power plant construction costs in
21 recent years.^^ It is reasonable to expect that tiie worldwide demand for power
22 plant design and constmction resources which underlies much of these
Id.
Response to Question AAE 1-19. A copy of this response is included in Exhibit DAS-8.
Response to Question AAE 1-20. A copy of this response is included in Exhibit DAS-8.
Direct Testimony of Jonathan E. Long, at page 29, lines 4-7, and at page 29, lme 17, to page 30,
line 5.
Page 33 Entergy Louisiana - Little Gypsy Repowering
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1 commodity and labor price increases, will continue to lead to further cost
2 increases m the future.
3 Q. Is it generally accepted that domestic U.S. and worldwide competition for
4 power plant design and construction resources, commodities, and
5 manufacturing capacity have led to significant increases in power plant
6 construction costs in recent years?
7 A. Yes. Soaring power plant constmction costs have been the subject of a number of
8 studies, assessments and articles in papers and magazines, as well as testimony
9 sponsored by companies that are proposing to build new fossil-fired generating
10 plants.
11 For example, in testunony filed at tiie North Carolina Utilities Commission on
12 November 29,2006, Duke Energy Carolinas emphasized the significant impact
13 that the competition for resources had been having on the costs of building new
14 power plants. This testimony was presented to explain the approximate 47 percent
15 ($1 billion) increase m the estimated cost of Duke Energy Carolinas' proposed
16 coal-fired Cliffeide Project that the Company announced in October 2006.
17 In fact, Duke Energy Carolinas' witness noted in testimony to the North Carolina
18 Utilities Commission that:
19 The costs of new power plants have escalated veiy rapidly. Tliis
20 effect appears to be broad based affecting many types of power
21 plants to some degree. One key steel price index has doubled over
22 the last twelve months alone. This reflects global trends as steel is
23 traded internationally and there is intemational competition among
24 power plant suppliers. Higher steel and otiier input prices broadly
25 affects power plant capital costs. A key driving force is a very
26 large boom in U.S. demand for coal power plants which in turn has
27 resulted from unexpectedly strong U.S. electricity demand growth
28 and high natural gas prices. Most integrated U.S. utilities have
29 decided to pursue coal power plants as a key component of their
30 capacity expansion plan. In addition, many foreign companies are
31 also expected to add large amounts of new coal power plant
32 capacity. This global boom is straining supply. Since coal power
33 plant equipment suppliers and bidders also supply other types of
Page 34 Entergy Louisiana - Little Gypsy Repowermg
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1 plants, there is a spill over effect to other types of electric
2 generating plants such as combined cycle plants.^^
3 Mr. Rose further noted that the actual coal power plant capital costs as reported
4 by plants already under constmction exceed government estimates of capita costs
5 by "a wide margin (i.e., 35 to 40 percent). Additionally, cuirent announced power
6 plants appear to face another increase in costs (i.e., approxunately 40 percent
7 addition."*^ Thus, according to Mr. Rose, new coal-fired power plant capital costs
8 have increased approximately 90 to 100 percent since 2002.
9 A June 2007 report by Standard & Poor*s, Increasing Construction Costs Could
10 Hamper U.S. Utilities' Plan to Build New Power Generation, similariy noted:
11 As a result of declinmg reserve margins in some U.S. regions  . ..
12 brought about by a sustained growth of the economy, tiie domestic
13 power industry is in the midst of an expansion. Standing in the way
14 are capital costs of new goieration that have risen substantially
15 over the past three years. Cost pressures have been caused by
16 demands of global infrastmcture expansion. In the domestic power
17 industry, cost pressures have arisen from higher demand for
18 pollution control equipment, expansion of the transmission grid,
19 and new generation. While the industry has experienced buildout
20 cycles in tiie past, what makes the current envbonment different is
21 the supply-side resource challenges faced by tiie constmction
22 industry. A confluence of resource limitations have contributed,
23 which Standard & Poors' Rating Services broadly classifies under
24 the followuig categories
25 • Global demand for commodities
26 • Material and equipment supply
27 • Relative inexperience of new labor force, and
28 • Contractor availability
29 The power industry has seen capital costs for new generation clrnib
30 by more than 50% in the past tlu^ee years, with more than 70% of
31 this increase resulting from engineering, procurem^t and
Direct Testimony of Judah Rose for Duke Energy Carolinas, North Carolina Utilities Conunission
Docket No. E-7, SUB 790, at  p ^ e 4, tines 2-14. Mr. Rose's testimony is available on the North
Carolina Utilities Commission website.
Ibid, at page 6, lines S-9, and page 12, Imes 11-16.
Page 35 E n t e i^ Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 constmction (EPC) costs. Continuing demand, both domestic and
2 intemational, for EPC services will likely keep costs at elevated
3 levels. As a result, it is possible that witii declining reserve
4 margins, utilities could end up building generation at a time when
5 labor and materials shortages cause capital costs to rise, well north
6 of $2,500 per kW for supercritical coal plants and approaching
7 $ 1,000 per kW for combined-cycle gas turbines (CCGT). In a
8 separate yet key point, as capital costs rise, energy efficiency and
9 demand side management already important from a climate change
10 perspective, become even more cmcial as any reduction in demand
11 will mean lower requirements for new capacity.^^
12 More recentiy, the president of the Siemens Power Generation Group told the
13 New York Times that 'There's real sticker shock out there."^^ He also estimate
14 that in the last 18 months, the price of a coal-fired power plant has risen 25 to 30
15 percent.
16 A September 2007 report on Rising Utility Construction Costs prepared by the
17 Brattie Group for the EDISON Foundation similarly concluded that:
18 Constmction costs for electric utility mvestments have risen
19 sharply over tiie past several years, due to factors beyond the
20 industiy's control. Increased prices for material and manufactured
21 components, rising wages, and a tighter market for construction
22 project management services have contributed to an across-the-
23 board mcrease m the costs of investing in utility mfrastmcture.
24 These higher costs show no immediate signs of abating.^^
25 The report further found that:
26 " Dramatically increased raw materials prices (e.g., steel, cement) have
27 mcreased constmction cost directly and indirectly through tiie higher cost
28 of manu&ctured components common in utility mfrastmcture projects.
29 These cost increases have primarily been due to high global demand for
30 commodities and manufactured goods, higher production and
Increasing Construction Costs Could Hamper U.S. Utilities' Plans to Build New Power
Generation, Standard & Poor's Rating Services, June 12,2007, at page 1. A copy of this report
was provided in response to Question LPSC 1-4 and is included in Exhibit DAS-8.
"Costs Surge for Building Power Plants, New York Times, July 10,2007.
Rising Utility Construction Costs: Sources and Impacts, prepared by The Brattle Group for the
EDISON Foundation, Septranber 2007, at page 31. A copy of this report is attached as Exhibit
DAS-6.
Page 36 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 transportation costs (in part owing to high fiiel prices), and a weakening
2 U.S. dollar.
3 • Increased labor costs are a smaller contributor to increased utility
4 constmction costs, although tiiat contribution may rise in the future as
5 large constmction projects across the country raise the demand for
6 specialized and skilled labor over cunnent or project supply. There also is a
7 growing backlog of project contracts at large engmeering, procurement
8 and constmction (EPC) firms, and constmction management bids have
9 begun to rise as a result. Although it is not possible to quantify tiie unpact
10 on fiiture project bids by EPC, it is reasonable to assume that bids will
11 become less cost-competitive as new constmction projects are added to tiie
12 queue.
13 • The price increases experienced over the past several years have affected
14 all electric sector investment costs. In the generation sector, ^1
15 technologies have experienced substantial cost increases m the past three
16 years, from coal plants to windpower projects.... As a result of these cost
17 increases, tiie Ieveli2Bd capital cost component of baseload coal and
18 nuclear plants has risen by $20/MWh or more - substantially narrowmg
19 coal's overall cost advantages over natural gas-fired combined-cycle
20 plants - and thus limiting some of the cost-reduction benefits expected
21 from expanding the solid-fuel fleet.
22 • The rapid increases experienced m utility constmction costs have raised
23 the price of recently completed mfrastmcture projects, but the impact has
24 been mitigated somewhat to the extent that constmction or materials
25 acquisition preceded the most recent price increases. The impact of rising
26 costs has a more dramatic impact on the estimated cost of proposed utility
27 infrastmcture projects, which fully mcorporates recent price tr«ids. This
28 has raised significant concerns that the next wave of utility investments
29 may be imperiled by the high cost environment. These rising constmction
30 costs have also motivated utilities and regulators to more actively pursue
31 energy efficiency and demand response initiatives to reduce the fiiture rate
32 impacts on consumers.'**
33
ld,aXpages 1-3.
Page 37 Entergy Louisiana - Littie Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Q. Do yon agree that with these reviews of the current market conditions
2 affecting the costs of proposed coal-flred power plants like the Littie Gypsy
3 Repowering Project?
4 A. Yes. These reviews of tiic factors affecting the estimated costs of new coal-fired
5 generating facilities appears reasonable and are consistent with other information
6 we have seen.
7 Q. Is it reasonable to expect that these same current market conditions also will
8 lead to increases in the estimated costs of other supply-side alteraatives such
9 as natural gas-fired or wind facilities?
10 A. Yes.
11 Q. Entergy Louisiana Exhibit APW-18 shows that a 10% increase in the cost of
12 the Repowering Project would reduce the net present value benefit of the
13 ^ Repowering Project versus the CCGT alternative in the Fundamental
14 Analysb by $190 million.^ Is it reasonable to expect that the constmction
15 cost of the Repowering Project could increase by more than 10%?
16 A. Yes. Although the current project cost estimate does mcrease some contingencies,
17 we believe that given recent history of large construction projects and current
18 market conditions, it is reasonable to assume that the actual cost of completing the
19 Littie Gypsy Repowering Project may be more than 10 percent higher than the
20 current cost estimate. This is especially tme because all project bids have not
21 been let and constmction has not even started.
22 Q. What would be the results of the Fundamental Analysis if all of the flaws that
23 you have identified were corrected?
24 A. Unfortunately, we have not had enough time to redo the Fundamental Analysis to
25 reflect the inclusion of demand side management and renewable resources as part
Exhibit APW-18.
•
Page 38 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 of a portfolio of altematives to the Repowermg Project Nor have we had tiie time
2 or the information to estimate the cost of repowering Little Qypsy as a CCGT.
However, Table 5 below shows what the results of the Fimdamental Analysis
would be if we made the modest assumption that the constmction costs of both
the Repowering Project and CCGT altemative fecility increase by 10 percent and
20 percent and/or if we assume that future CO2 prices will be moderately higher
(that is, SlOAon) than the Company's high CO2 price sensitivity.
Table No. 5: Results of the Fundamental Analysis Assuming Increased
Construction Costs and Altemative CO2 Prices
10
11
12
13
Scenario
$6.00/mmBtu Gas Price
$5.00/mmBtu Gas Price + 10%
increase in cost of Repowering
Project and CCGT Altemative
$5.00/mmBtu Gas Price + 20%
increase in cost of Repowering
Project and CCGT Alternative
$7.00/mmBtu Gas Price
$7.00/mmBtu Gas Price + 10%
Increase in cost of Repowering
Project and CCGT Altemative
$7.00/mmBtu Gas Price + 20%
increase in cost of Repowering
Project and CCGT Altemative
$8.00/mmBtu Gas Price
$8.00/mmBtu Gas Price + 10%
increase in cost of Repowering
Project and CCGT Altemative
$8.00/mmBtu Gas Price + 20%
increase in cost of Repowering
Project and CCGT Alternative
No CO2 Costs
Company
Base COz
Price
Set^sitivlty
Company
High CO2
Price
Sensitivity
Attemath^
COz Price.
Sensl^ity
Benefit/(C08t) to Repowering Project
(millions 2006$)
($424)
($564)
($704)
$461
$320
$180
$904
$760
$620
($80)
($220)
($360)
$82
($60)
($200)
$530
390
$250
($1,330)
($1,470)
($1,610)
($443)
($580)
($720)
$0
($140)
($280)
($1,630)
($1,770)
($1,910)
($743)
($880)
($1,020)
($300)
($440)
($580)
Each of the figures in the parentheses in Table 5 means that the Repowering
Project would be more expensive in that scenario, in 2006 dollars, tluin the
altemative CCGT facility. Thus, as can be seen from this Table, there are a large
Page 39 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 number of reasonable scenarios in which the Repowering Project would be a
2 significantly higher cost option. Clearly, the Company's Fundamental Analysis
3 shows that there is a substantial economic risk associated with pursuing the
4 Repowering Project.
5 Q. Haven't you just presented a series of worst case analyses in Table 5 above?
6 A. Not at all. Given the very high cost escalation that has been experienced by
7 power constiiiction costs in recent years, it is not unreasonable to expect that the
8 cost of both the Repowering Project and the CCGT altemative could increase by
9 significantly more than 20 percent by the time that design, procurement and
10 constmction actually are completed by 2011/2012. It also is possible that future
11 CO2 emissions allowance prices will be higher than that altemative prices that
12 underlie the figures shown in the right-hand column of Table 5.
13 Q. Have you seen any evidence that the levelized Fundamental Anafysis
14 presented by Entergy Louteiana witness Walz overstates the economic
15 benefits of the proposed Repowering Project?
16 A. Yes. The reference case in the Fundamental Analysis, with a $7/mmBtu gas price
17 and a $0/ton CO2 price shows a $461 million net present value benefit to the
18 repowering ofLittle Gypsy Unit 3 as compared to tiie CCGT altranative.'*^
19 However, the results of the Company's PROSYM analysis, which appear to
20 reflect the same main assumptions, shows only a $94 million net present value
21 benefit to the Repowaing Project.'*^
Exhibit APW-11.
Exhibit APW-19.
Page 40 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Q. Is it reasonable to expect that the difference in the results of tiie two analyses
2 in due to the differences in tiie length of the analyses, that Is 30 years for the
3 levelized Fundamental Analyst and 25 years for the PROSYM analysis?
4 A. No. The difference in tiie number of years considered in each analysis might have
5 some effect but would not result in such a startiing difference between the two
6 analyses. It is more likely tiiat tiie PROSYM simulation modeling more accurately
7 reflects the Entergy Louisiana system and, consequentiy, the relative costs of the
8 different projects than the simplistic levelized methodology used in tiie
9 Fundamental Analysis.
10 Q. Do the results of the PROSYM Analysis presented by Entergy Louisiana
11 witness Walz then show that repowering Littie Gypsy Unit 3 as a CFB is the
12 lowest cost, lowest risk option for the Company and its ratepayers?
13 A. No. The single scenario presented by Mr. Walz is significantly fiawed in several
14 ways. First, the PROSYM analysis does not reflect any CO2 emissions allowance
15 prices.^* As I have discussed earlier in this testimony, it is reasonable to assume
16 that there will be federal regulation of greenhouse gas emissions in tiie near
17 future. The costs of such greenhouse gas regulations should be considered in any
18 evaluation of the economics of pursuing fossil-fired generating altematives.
19 Second, the PROSYM analysis presented by Mr. Walz does not examine the
20 potential for including energy efficiency and/or renewable resoxwces as part of a
21 portfolio of ahematives to repowering Little Gypsy Unit 3 as a CFB. Third, Mr.
22 Walz only presents the results of a single PROSYM base case comparison that
23 does not reflect the risk of higher fuel costs or higher constmction costs for eitiier
24 the repowering ofLittle Gypsy Unit 3 or the CCGT alternative.
Direct Testimony of Anthony P. Walz, at page 42, Une I,
Page 41 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 Q, Did  E n t e i ^ Louisiana include any costs for carbon capture and
2 sequestration in the PROSYM Analysis for either the Repowering Project or
3 the CCGT altemative?
No.
Did Entergy Louisiana reflect in the PROSYM Analysis any of the
performance penalties that can be expected from the addition and use of
carbon capture technology for either the Repowering Project or the CCGT
alternative?
No.
Do you have any other observations about the results of the single PROSYM
analysis presented by Mr. Walz?
Yes. I have two other observations. Fu*st, the results of Mr. Walz' PROSYM
analysis are present valued to 2011 dollars. The $94 million net present value
benefit for the Little Gypsy Repowering Project would translate into about $65-70
million in 2006 dollars.
In addition, as shown on Table 6 below, although the results of the PROSYM
analysis show an overall net present value benefit to the Repowering Project, the
CCGT altemative actually would be the less expensive option until the year 2031,
or for the first 19 years of the analysis.
•
t
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
• / \ .
Q.
A.
Q.
A.
Page 42 Entergy Louisiana - Little Gypsy Repowering
Docket No, U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
Year
Table 6: PROSYM Break-even Analysis (
With Little Gvpsv
Total
PROSYM
Fuel and
Purchased
Power
Nor>4uel
Revenue.
Requirement  Total
Total
PROSYM
Fuel and
Purchased
WffliCCGT
nuementsi
Norvfuel
RrannuB
mOOOS)
Total
Bene(it/(Cost)
of Little Gypsy
over CCGT
Annual
Present Value
Benefit
(CosO
Cumulative
Present Value
Benefit
(CosO
(000$) 1
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
4.730.986
5.045.099
5.333.764
5.645.756
5,999.053
6.349,623
6.858,595
7.359.647
7.718.341
8.143,810
8,638.338
9,072,190
9.567.306
10,095,273
10,592,794
11,217,218
11.650,089
12,369.227
13.144.046
13.758.743
14.319,249
15.001.530
15.691.512
16.301,806
17,051.901
$81,821,143
245.874
241.976
234.650
227.719
221.152
214.924
209,011
203.391
198,042
192.751
167.474
223.213
217.966
213.737
208.522
204.325
199.144
194.980
189.834
184.707
180.597
177.076
176,142
174.228
173.335
4,976,860
5.287,075
5.568,435
5.873.475
6,220,204
6,564.447
7.067.606
7.663,038
7.916.363
8,336.561
8,825.612
9.295.403
9,785,273
10,303,010
10.801,316
11.421.543
12,049,233
12.564,207
13,333,880
13.943,450
14,499,846
15.178.606
15,867,654
16,476,035
17,225.236
4.861.385
5,171.743
5,463,829
5,775.373
6,143,604
6,496,735
7 . 0 1 5 L 5 09
7.522.847
7.885.442
8,319.821
8.823,774
9.260,730
9.764.396
10,300.341
10,807,107
11,440,854
12,080,559
12,607.545
13.389,429
14,015,212
14.580.151
15,270.528
16,969.328
16.583.457
17,344,543
59,992
58,839
56.881
55.016
53,234
51.533
49.905
48.346
46,849
45.366
43.885
52.036
50.562
49,326
47,858
46,628
45,167
43.945
42.491
41.041
39.830
38.755
38,288
37.591
37,132
Net Present Value
$2.174,120 $83,995,262  $83,575,446  $513,956
4.921,377
5.230.582
5,520.711
5.830.388
'6,166,838
6.548.268
7.065.414
7.571.192
7.932.291
8.365.187
8.867.660
9,312.766
9,814,956
10,349,667
10,854,965
11,467.482
12,125,727
1^651.490
13.431.921
14.066.253
14.619.960
15.309.283
16.007.616
16.621.046
17.381.675
$84,069,402
(56,483)
<66.493)
(47.724)
(43.087)
(23.366)
<16.179)
(2.192)
8.154
15.908
28,626
41,847
17.362
29,685
40,657
53.649
65.939
76.494
87.282
98.041
112.803
120.134
130,678
139.962
145,013
156.438
$94,140
($51,089)
($47,900)
( $ 3 7 , ^ 1)
($30,976)
($16^468)
(W.862)
($1,230)
$4,214
$7,571
$12,545
$16,887
$6,451
$10,157
$12,809
$15,564
$17,614
$18,816
$19,769
$20,447
$21,663
$21,244
$21,279
$20,986
$20,021
$19,888
($61,089)
($98,989)
($136,249)
( $ 1 6 7 . ^ 6)
($182,694)
($192.S5Q
($193,786)
($189.b/2)
($182,001)
($169,456)
($152,569)
($146,118)
($135,961)
($123,152)
($107,589)
($89,974)
($71,159)
($51,389)
($30,942)
($9,279)
$11,966
$33,244
$54,230
$74,251
$94,140
•
3 Q. Given these results, is it reasonable to assume that the resource plan that
4 includes the CCGT altemative would have been the lower cost plan in the
5 PROSYM if  E n t e i ^ Louisiana had included CO2 emissions allowance
6 prices?
7 A. Yes. The PROSYM analysis should properly be remn to reflect reasonable
8 forecasts of CO2. However, there has not been time or resources for us to do that
9 in this case.
10 Nevertheless, it is possible to approximate the effect of including CO2 prices by
11 multiplying the corrected annual CO2 emissions for the Repowering and CCGT
12 altemative plans looked at by Entergy Louisiana by tiie annual  C 02 price
13 assumed by the Company m its base and high CO2 price forecasts. The results of
14 this calculation are shown in Exhibit DAS-7.
Page 43 Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 As shown in Exhibit DAS-7, tiie Company's plan that includes the repowering of
2 Little Gypsy as a CFB plant would be more expensive than building a new CCGT
3 fecility by $247 million, net present value, under the Company's base CO2 price
4 forecast and by $682 million, net present value, under the Company's high CO2
5 forecast
6 Q. Why do you say that you included the ''corrected" annual CO2 emissions
7 under the Repowering and altemative CCGT plans considered by Entergy
8 Louisiana in its PROSYM analysis?
9 A. When we looked at the input and output files for the PROSYM analysis, we
10 discovered that Entergy had input a very, very low CO2 emission rate/MWh for
11 the repowered Little Gypsy plant. We revised this assumption to reflect the
12 information fi'om Entergy Louisiana that indicated that the repowered plant would
13 emit a much higher 2151 lbs of CO2 per MWh.
14 Q. Entergy Louisiana witness Walz discusses the benefits of the proposed
15 repowering of the Little Gypsy Unit for supply dive r s i ty/' Do you agree that
16 supply diversity is an issue that the Commission should consider as it
17 evaluates the proposed repowering project?
18 A. Yes. I think supply diversity is a very important consideration. However, I don't
19 believe that repowering Little Gypsy Unit 3 as CFB coal-fired plant is a
20 reasonable option for increasing  E n t e i ^ 's supply diversity.
21 Q. Why is considering a company's generation mix the appropriate way  to
22 evaluate its fuel diversity?
23 A. Because tiie issue of fuel diversity is a matter of the amount of each type of fiiel
24 that the company bums, and the cost consequences of burning that fuel. Simply
•
49
For example, see pages 14 through 16 of ttie Direct Testimony of Anthony P. Walz.
Page 44 •
Entergy Louisiana - Little Gypsy Repowering
Docket No. U-30192
Direct Testimony of David A. Schlissel
Public Version - Protected Materials Redacted
1 looking at its capacity mix does not offer any information about the utilization of
2 that capacity-
3 Q, Is fuel diversity a broader issue than merely deciding whether to build a coal-
4 or gas-fired generating unit?
5 A. Yes, it should be. Implementing demand side management programs and building
6 or buying power fi'om low carbon-emitting renewable resource facilities also
7 would increase a company's supply diversity. Invesfanents in d^nand side
8 management and renewable resources would provide real benefits in terms of
9 supply diversity by reducing Entergy's dependency on coal, oil and gas.
10 Q.  E n t e i^ Louisiana stresses the uncertainties associated with the price of
11 natural gas. Are there any similar uncertainties associated with the building
12 and operation of new coal-fired generating facilities?
13 A. Yes. There are a number of potential uncertainties associated with coal-fired
14 facilities that the Commission should consider as it evaluates the proposed
15 Repowering Project. The primary uncertainty is associated with the potential fi>r
16 greenhouse gas regulations. As I have noted earlier in this testimony, there is a
17 significant potential that substantial CO2 emissions allowance prices will be set as
18 part of a cap-and-trade plan for reducing carbon dioxide emissions by perhaps
19 60% to 80% by tiie middle of this century.
20 Rising power plant constmction costs also are a significant uncertainty associated
21 with adding new coal-fired generating units such as a repowered Little Gypsy
22 Unit 3.
23 Q. Does this conclude your testimony?
24 A. Yes.
Page 45 AFFIDAVrr
STATE OF NASSAg-ftHSef?^
COUNTY OF  y ^ l b P L g S ' g X
NOW BEFORE ME, tiie undersigned authority, personally came and appeared,
David Schlissel, who after being duly swom by me, did depose and say:
The above and foregoing in his swom testimony in this proceeding and that he
knovi^ the contents thereof, that the same are true as stated, except as to matters and
things, if any stated on information and belief, and that as to those matters and things, he
verily believes them to be tme.
^ •J /J.  I Xu
SOWRN TO AND SUBSCRIBED BEFORE ME
THIS  J ^ D AY OF  S ' ^ b t A, 2007
^ ^ ffOTARY PUBLIC
My commission expires, Vt/ljjJJuujk  )0 QJ3i^ ^  , ,^ Rising Utiiity Construction Costs:
Sources and Impacts
Prepared by:
Marc W. Chupka
Gregory Basheda
The Branle Group
Prepared  for:
T he
^ ^ ^ T ^  E D I S ON
^ • • m  F O U N D A T I ON
^ l
SEPTEMBER  2 0 07 The
E D I S ON
F O U N D A T I O N
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Furthering Thomas Alva Edison's spirit of invention, the
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i . n i r o u u c u o n  a n c i  J L x e c n u v e dummaij'•••••••••••«•••••••«•••••••••>••*•••*•*••*•*••••«••«>«•«••>«••**••••••••••**•«•••*•••••••*««*«*••« x
Proj e c t ed  Inve s tment Needs  a nd Re c ent  I n f r a s t r n c t n re Cost Increases—.,......^.,....*...»..,......^^.». 5
Current and Projected U.S. Investment in Electricity Infrastructure S
Generation 5
High-Voltage Transmission 6
Distribution ...-6
Construction Costs for Recently Completed Generation ^. 7
Rising Projected Construction Costs: Examples and Case Studies 10
Coal-Based Power Plants ....10
Transmission Projects ., 11
Distribution Equipment 12
F a c t o rs  S p u r r i ng Ri s ing Cons tmc t ion Cos ts »...,.,...,..,..,.„„.....«.«.*.,«».......»i«.......««...*.»...*.****».^*^*» 13
Material Input Costs.... 13
Metals 13
Cement, Concrete, Stone and Gravel 17
Manufactured Products for Utility Infrastructure 18
Labor Costs 20
Shop and Fabrication Capacity 21
Engineering, Procurement and Construction (EPC) Market Conditions - 23
Summary Construction Cost Indices , 24
Comparison with Energy Infomiation Administration Power Plant Cost Estimates .27 A Introduction and Executive Summary
In Why Are Electricity Prices Increasing? An Industry-Wide Perspective (June 2006), The Brattle Grotq>
identified fuel and purchased-power cost increases as the primaiy driver of die electricity rate incieases that
consumers currently are facing. That report also noted that utilities are once agam entering an infrastructure
expansion phase, witik significant investments in new baseload generatmg capacity, expansion of the bulk
transmission system, distribution system enhancements, and new environmental controls. The report
concluded that the industry could make the needed investments cost-effectively under a ^nerally supportive
rate environment.
The rate mcrease pressures arismg from elevated fuel and purchased power prices continue. However,
another major cost driver that was not explored in the previous work also will impact electric rates, namely,
the substantial increases in the costs of building utility infrastmctiue projects. Some of the factors
underlying these construction cost trends are straightforward—such as sharp increases in mat^als cost—
while others are complex, and sometimes less transparent m their impact. Moreover, the recent risein many
utility construction cost components follows roughly a decade of relatively stable (or even declining) real
construction costs, adding to the "sticker shock" that utilities experience when obtaining cost estimates or
bids and that state public utility commissions experience during the process of reviewing {^plications fxH*
approvals to proceed with construction. While the fiiU rate impact associated with construction cost
increases will not be seen by customers until infrastructure projects are completed, the issue of rising
construction costs currently affects industry investment plans and presents new challenges to regulators.
The purpose of this study is to a) document recent increases m &e construction cost of utility infrastructure
(generation, transmission, and distribution), b) identify the underlying causes of these increases, and c)
explain how these increased costs wilt translate into higher rates tiiat consumers might face as a result of
required infrastructure investment. This report also provides a reference for utilities, regulators and the
public to imderstand the issues related to recent construction cost increases. In summaxy, we find the
following:
• Dramatically increased raw materials prices {e.g., steel, cement) have increased construction cost
directly and indirectly through die higher cost of manu^tured components common in utili^
infrastructure projects. These cost increases have primarily been due to high global demand for
commodities and manufactured goods, higher production and transportation costs (in part owing to
high fuel prices), and a weakening U.S. dollar.
" Increased labor costs are a smaller contributor to increased utility construction costs, although that
contribution may rise in the future as large construction projects across the countiy raise tiie demand
for specialized and skilled labor over current or projected supply. There also is a growing backlog of
1 ^ Introduction and Executive Summary
project contracts at large engineering, procurement and constmction (EPC) fums, and construction
management bids have begun to rise as a result Although it is not possible to quantify the impact on
future project bids by EPC firms, it is reasonable to assume that bids will become less cost-competitive
as new constmction projects are added to the queue.
Tlie price increases experienced over the past several years have affected all electric sector investment
coste. In the generation sector, all technologies have experienced substantial cost increases m die past
three years, from coal plants to windpower projects. Large proposed transmission projects have
undergone cost revisions, and distribution system equipment costs have been rising rapidly. This is
seen in Figure ES-1, which shows recent price trends in generation, transmission and distribution
mfrastmcture 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 Figure ES-1, infrastructure costs were relatively stable during the 1990s, but have
experienced substantial price increases in the past several years. Between Januaty 2004 and January
2007, the costs of steam-generation plant, transmission projects and distribution equipment rose by 25
percent to 35 percent (compared to an 8 percent increase m the GDP deflator). For example, tiie cost
of gas turbmes, which was fairly steady m the early part of the decade, increased by 17 percent during
the year 2006 alone. As a result of these cost increases, the levelized capital cost component of
baseload coal and nuclear plants has risen by $20/MWh or more—substantially narrowing coal's
overall cost advantages over natural gas-fh*ed combmed-cycle plants—and thus limiting some of the
cost-reduction benefits exp^ted from e7q)anding the solid-fuel fleet.
FiguraES-1
National Average Utility Infrastructure Cost Indices
P  . ^ T o l r i P h r t .M  a mw (  •^—DJaMibt^aa \
in
l i s o
1991  I99Z 1993  I » 4 1995 1996 199T 1999 1999 2000 2001 2002 2003
Y M r
S m r t x s:  T l i eHB i K | ) i ^Wu i n i a r iOB d l eUi ) ,No.  1 6 5 i n < l i w U S . B u i e i u o f E c o n « n c A i u I ) i r i s.
S a q dc average  of  d l  T ^ o o d  c o n s o u R im  S K I equipoieai cost  i n d e i oi  f or the spetdRe^
2004 ZOOS 2006 2001
' The GDP deflator measures the cost of goods and services purchased by households, industry and government, aod as such
is a broader price index than the Consumer Price Index (CPI) or Producer Price Index (PPI). which track the costs of
goods and services purchased by households and industry, respectively. Rising Utility Construction Costs: Sources and Impacts
The rapid increases experienced in utility constmction costs have raised the price of recently
completed infrastructure projects, but the impact has been mitigated son^what to the extent tiiat
construction or materials acquisition preceded die most recent price increases. Hie impact of rismg
costs has a more dramatic unpact on the estimated cost of proposed utility infrastructure projects,
which fiilly incorporates recent price trends. This has raised signiflcant concerns that the next wave
of utility investments may be imperiled by the high cost envhonment These rising constmction costs
have also motivated utilities and legulators to more actively pursue eneigy efficiency and demai^
response initiatives in order to reduce the future rate hnpacts on consumers.
Despite the overwhelming evidence that construction costs have risen and will be elevated for some
time, these increased costs are largely absent from the capital costs specified m the Energy Infonnation
Admmistration's (EIA's) 2007 Annual Energy Outlook (AEO). The AEO generation capital cost
assumptions since 2001 are shown in Figure ES-2. Since 2004, capita] 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 growmg divergence between the AEO data assumptions and recent cost escalation is
now so substantial that the AEO data need to be adjusted to reflect recent cost increases to provide
reliable indicators of current or future capital costs.
•
Figure ES-2
EIA Generation Construction Cost Estimates
Year
2007  t ad from the U.S. Buresu  of EoonMnic Analysis. A Projected Investment Needs and Recent
Infrastructure Cost Increases
Current and Projected U.$. Investment in Eiectrioity infrastructure
The electric power industry is a very capital-intensive industry. The total value of geiwration, transmission
and distribution infrastructure for regulated electric utilities is roughly $440 billion (property in service, net
of accumulated depreciation and amortization), and capital expenditures are expected to exc^d $70 billion
in 2007.^ Althou^ tiie industry as a whole is always investing in capital, tiie rate of capital expenditures
was relatively stable durmg the 1990s and began to rise near the turn of the century. As shown hi Why Are
Electricity Prices Increasing? An Industry-Wide Perspective (June 2006), utilities anticipate substantial
increases in generation, transmission and distribution investment levels over the next two decades.
Moreover, the signifrcant need for new electricity infrastructure is a world-wide phenomenon: According to
tiie World Energy Investment Outlook 2006, investmcrits by power-sector companies tiiroughout the world
will total about $11 trillion dollars by 2030.^
Generation
As of December 31,2005, there were 988 gigawatts (GW) of electric generating capacity in service in the
U.S., with the majority of this capacity owned by electric utilities. Close to 400 GW of this total, or 39
percent, consists of natural gas-fired capacity, with coal-based capacity comprising 32 p^cent, or slightiy
more than 300 GW, of the U.S. electric generation fleet. Nuclear and hydroelectric pUuits comprise .
approximately 10 percent of the electric generation fleet. Approximately 49 percent of energy production is
provided by coal plants, with 19 percent provided by nuclear plants. Natural gas-fhed plants, which tend to
operate as intermediate or peaking plants, also provided about 19 percent of U.S. energy production in 2006.
The need for installed generating capacity is highly correlated with load growth and projected growth in peak
demand. According to EIA's most recent projections, U.S. electricity sales are expected to grow at an annual
rate of about 1.4 percent through 2030. According to tiie North American Electric Reliability Corporation
(NERC), U.S. non-coincident peak demand is expected to grow by I9percent(l4l GW) from 20()6 to 2015.
According to EIA, utilities will need to build 258 GW of new generating capacity by 2030 to meet tiie
^ Net property in service figure as of December 31,2006, derived from Federal Energy Regulatoiy Commission (FERC)
Form 1 data compiled by the Edison Electric Institute (EEI). Gross property is roughly $730 biUion, witii about $290
billion already depreciated and/or amortized. Annual capital e^qienditure estimate is derived from a sample of lOK rqraits
surveyed by EEI.
^ Richard Stavros, "Power Plant Development: Raising the Stakes." Public Unities Fortnightly, May 2007, pp. 36-4^. Projected Investment Needs and Recent Infrastructure Cost Increases
projected growth m electricity demand and to replace old, inefficient plants tiiat will be retired. EIA further
projects that coal-based capacity, that is more capital intensive than natural gas-fired capacity which
dominated new capacity additions over tiie last 15 years, will account for about 54 percent of total capacity
additions from 2006 to 2030. Natural gas-flred plants comprise 36 percent of the projected capacity
additions in AEO 2007. EIA projects that the remaining 10 percent of capacity additions will be provided t>y
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 constmction
costs but low operating costs.
High-Voitage Transmission
The U.S, and Canadian electric transmission grid includes more tiian 200,000 miles of high voltage (230 kV
and higher) transmission Imes that ultimately serve more than 300 million customers. This system was built
over tiie past 100 years, primarily by vertically integrated utilities that generated and transmitted electricity
locally for the beneflt of their native load customers. Today, 134 control areas or balancing autiiorities
manage electricity operations for local areas and coordinate reliability through the eight regional reliability
councils of NERC.
After a long period of decline, transmission investment began a signifrcant upward trend starting in the year
2000. Smce the beginnmg of 2000, the industry has mvested more than $37.8 billion in the nation's
transmission system. In 2006 alone, investor-owned electric utilities and stand-done transmission
companies invested an historic $6.9 billion in the nation's grid, while the Edison Electric Institute (EEI)
estimates that utility transmission mvestments will increase to $8.0 billion during 2007. A recent EEI survey
shows that its members plan to invest $31.5 billion in the transmission system frx)m 2006 to 2009, a nearly
60-percent increase over the amount mvested from 2002 to 2005. These mcreased mvestments in
transmission are prompted m part by the larger scale of base load generation additions that will occur farther
from load centers, creating a need for larger and more costly transmission projects than those built over the
past 20 years. In addition, new government policies and industry structures will contribute to greater
transmission investment. In many parts of the countiy, transmission planning has been formally
regionalized, and power markets create greater price transparency that highlights the value of transmission
expansion in some instances.
NERC projects that 12,873 miles of new transmission will be added by 2015, an increase of 6.1 percent in
the total miles of installed extra high-voltage (EHV) transmission Imes (230 kV and above) in North
America over the 2006 to 2015 period. NERC notes tiiat this expansion  l ^s demand growth and expansion
of generatmg resources in most areas. However, NERC*s figures do not include several major new
transmission projects proposed in the PJM Interconnection LLC, such as the major new lines proposed by
American Electric Power, Allegheny Power, and Pepco.
Distribution
While transmission systems move bulk power across wide areas, distribution systems deliver lower-voltage
power to retail customers. The distribution system includes poles, as well as metering, billing, and other
related infrastructure and software associated with retail sales and customer care functions. Continual Rising Utility Construction Costs: Sources and Impacts
investment in distribution facilities is needed, first and foremost, to keep pace with growth in customer
demand. In real terms, investment began to mcrease in the mid-1990s, preceduig the correspondmg boom in
generation. This steady climb m investment in distribution assets shows no sign of dhninishing. The need to
replace an aging infrastructure, coupled with increased population growth and demand for power quality and
customer service, is continuing to motivate utilities to improve their ultimate delivery system to customers.
Continued customer load grovt^ will require continued expansion m distribution system capaci^. In 2006,
utilities mvested about $17.3 billion m upgrading and expandmg distribution systems, a 32-percent mcrease
over the investment levels incurred in 2004. EEI projects tiiat distribution investment during 2007 will agam
exceed $17.0 billion. While much of tiie recent increase in distribution investment reflects expanding
physical infrastructore, a substantial portion of the mcreased dollar investment reflects the increased input
costs of materials and labor to meet current distribution infrastmcture needs.
Constmction Costs for Recently Completed Generation
The majority of recently constmcted plants have been either natural gas-fired or wmd power plants. Both
have displayed increasing real costs for several years. Since the 1990s, most of the new generatmg capacity
built in the U.S. has been natural gas-fu'ed capacity, either natural gas-fired combined-cycle units or naturd
gas-fu'ed combustion turbmes. Combustion turbme prices recentiy rose sharply after years of real price
decreases, while significant increases in the cost of installed natural gas combined-cycle combustion c^iacity
have emerged during the past several years.
Using commercially available databases and other sources, such as financial reports, press releases and
government documents. The Brattle Group collected data on the installation cost of natural gas-fired
combined-cycle generating plants built in the U.S. during tiie last major construction cycle, defined as
generating plants brou^t mto service between 2000 and 2006. We estunated that tiie average real
construction cost of all natural gas-fired combmed-cycle units brought online between 2000 and 2006 was
approximately $550/kilowatt (kW) (in 2006 dollars), with a range of costs between $400/kW to
approximately $l,000/kW. Statistical analysis confirmed that real installation cost was influenced by plant
size, the turbine technology, the NERC region in which tiie plant was located, and the commercial online
date. Notably, we found a positive and statistically significant relationship between a plant's construction
cost and its online date, meanmg that, everything else equal, tiie later a plant was brought online, the higher
its real installation cost^ Figure 1 shows the average yearly mstallation cost, ui nominal dollars, as |»edicted
by the regression analysis.^ This figure shows that the average installation cost of combined-cycle units
mcreased gradually from 2000 to 2003, followed by a fairly significant increase in 2004 and a very
significant escalation—more than $300/kW—^in 2006, This provides vivid evidence of the recent sharp
increase in plant construction costs.
To be precise, we used a "dummy" variable to represent each year in the analysis. The year-specific dummy variables
were statistically significant and unifoimiy positive i.e.,  t h ^ had an upward unpact on instfdlation cost
The nominal form regression results are discussed here to facilitate comparison vrith the GDP deflator measure used to
compare other price trends in other figures in this report. Projected Investment Needs and Recent Infrastructure Cost Increases
H g u r t tl
Muiti-Varlable Regression Estimation:
Average Nominal installation Costs Based on Online Year ($/WN)
2000
900
800
700
600'
4 0 0-
3 0 0-
200
100
0
^
::::::  z '
^
•"  ^
_, ,
•*
,
— ^ ^ -
- /
- < ^ -
2001  2002 2003 2004  2005  2006
O n l i ne  Y e ar
Sttirees and Note^
* Data on sipnmer cqiaci ^,  tot ti instaUadm  c o n. turbme tcdinol(%r. Gontraemd onlfaw  d ^
w«ra collected irom coniRtercisIly aviilable databues and other sourcci such u company websites and 10k raports.
Figure 2 compares the trend in plant mstallation costs to the GDP deflator, using 2000 as tiie base year. Over
the period of 2000 to 2006, the cumulative increase in the general price level was 16 percent while the
cumulative mcrease in the installation cost of new combined-cycle, units was almost 95 percent, with mudb
of this increase occurring in 2006.
Figure 2
Muiti-Variabie R^ression Estimation:
Average Nominal Installation Costs Based on Online Year (Index Year 2000  » 1 0 0)
2S0
200 -
150
100
50
' G DP Def lator
'  A v g a ge testallation Costs
• . ^
2 0 00  2001  2002  2003  2004  2005  2006
O n f i » V Mr
Sauices and Notes:
* Data on summN cspaci^, total instatlatioii cost, turbine technology, commercul online dale, and zip code for the period 2000-2006
wwe coUected ftoni fiomniercialbr Bvaikble databases and Mher sources  s u ^ BS company websites and 10k reports.
•* <3)p Deflator da» were coltected fiom the U.S. Bupsau of Economic Analysa. Rising Utility Construction Costs: Sources and Impacts
Anotiier major class of generation development durmg this decade has been wind generation, the costs of
which have also increased in recent years. The Northwest Power and Conservation Council (NPCC), a
regional planning council that prepares long-term elecfric resource plans for tiic Pacific Northwest, issued its
most recent review of the cost of wind power m July 2006.* The Council found tiiat the cost of new wmd
projects rose substantially m real terms in tiie last two years, and was much higher tiian that assumed m its
most recent resource plan. Specifically, the Council found tiiat the levelized lifecycle cost of power for new
wind projects rose 50 to 70 percent, with higher construction costs being the principal contributor to tiiis
increased cost. According to the Council, tiie construction cost of wind projects, in real dollars, has
increased from about $1150/kW to $l300-$1700/kW m tiie past few years, with an unweighted average
capital cost of wind projects in 2006 at $l,485/kW. Factors contributing to tiie increase m wind power costs
include a weakening dollar, escalation of commodity and energy costs, and increased demand for wind
power under renewable portfolio standards established by a growing number of states. The Council notes
that commodities used m the manu&cture and installation of wind turbines and ancillary equipm^it,
including cement, copper, steel and resm have experienced significant cost mcreases in recent yeais. Figure
3 shows real constmction costs of wind projects by actual or projected in-service date.
Figures
Wind Power Piqfect Capital Costs
S2.000
$1,500
j r o QO -
$500
$0
• Estimated overnight capital cost
— Poly. (Estimated overnight capital cost)
2000 2001 2002  2004 2005 2006 2007 2008 2009
Service Year
5'curcK The Noiibwest Power and ConsoviAion  C e n i d l, "Biennid Reriow (rf'dw  C ^
These observations were confirmed recently in a May 2007 report by tiie U.S. Department of Energy (DOE),
which found that prices for wind turbines (tiie primaiy cost component of mstelled wind capacity) rose by
more than $400/kW between 2002 and 2006, a nearly 60-percent increase.^ Figure 4 is reproduced from tiie
DOE report (Figure 21) and shows the significant upward trend in turbine prices since 2001.
The NPCC planning studies and analyses cover the following four states: Washington, Oregon, Idaho, and Montana. See
"Biennial Review of the Cost of Windpower" July 13.2006, at
wvvw.bpa.gov/En€Tgy/N/projects/post2006conservation/doo'Windpower_Cost_Review.doc. This study provides msaxy
reasons for windpower cost increases.
See U.S. Department of Energy, Annual Report on U.S. Wind Power Installation, Cost and Performance Trends: 2006
Figures], page 16. Projected Investment Needs and Recent Infrastructure Cost Increases
Figure 4
Wind Turliine Prices 1997 - 2007
$1,601-r
$1.40Q-
$1330-
|1,O00'
§
B 1800
e
I $600
I fi200
A 0nlaiB<1DQI tW
• Ordaisfnifli  1 0 0 - 3 00 MMr
• Qnloi8>&0QMW
PoJynDn^TnHid Una
SoffHt SeikeiefHo daCMw.
J n -m  J n - OI Ja-D2 Jn-OS  J B I - U
AinDMicHnenlDila
Jn-QG
Rising Protected Construction Costs: Examples and Case Studies
Although recently completed gas-fired and wind-powered capacity has shown steady real cost increases in
recent years, the most dramatic cost escalation figures arise  ^om proposed utility investments, which fully
reflect the recent, sharply rising prices of various components of construction and installation costs. The
most visible of these are generation proposals,  a l t l i o u^ several transmission proposals also have undergone
substantial upward cost revisions. Distribution-level mvestments 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 Rants
Evidence of tiie significant increase m tiie construction cost of coal-based power plants can be found in
recent applications filed by utilities, such as Duke Energy and Otter Tail Power Company, seekmg
regulatory approval to build such plants. Otter Tail Power Company leads a consortium of seven
Midwestem utilities that are seeking to build a 630-MW coal-based generatmg unit (Big Stone II) on the site
of the existmg Big Stone Plant near Milbank, South Dakota. In addition, the developers of Big Stone n seek
to build a new high-voltage transmission lme to deliver power from Big Stone U and from other sources,
including possibly wind and other renewable forms of energy. Initial cost estimates for the power plant were
about $1 billion, with an acUitional $200 million for the transmission line project. However, these cost
estimates increased dramatically, largely due to higher costs for constmction materials and labor.^ Based on
the most recent design refinements, the project, including transmission, is expected to cost $1.6 billion.
^ Other Actors contributing to the cost increase include design changes made by project participants to increase output and
improve the unit's efficiency. For example, the voltage of the proposed transmission line was increased fi'om 230 kV to
345 kV to accommodate more generation.
F'lO Rising Utility Construction Costs: Sources and Impacts
In June 2006, Duke submitted a filing with the North Carolina Utilities Commission  (NCUQ seeking a
certificate of public convenience and necessity for the construction of two 800 MW coal-based generating
units at the site of the existing Cliffeide Steam Station. In its initial application, Duke relied on a May 2005
preliminary cost estimate showing that the two units would cost approximately $2 billion to build. Five
months later, Duke submitted a second filing whh a significantly revised cost estimate. In its second filing,
Duke estimated tiiat the two units would cost approximately $3 billion to build, a 50 percent cost mc r e ^ e.
The North Carolina Utilities Commission approved the construction of one 800 MW imit at Clif&ide but
disapproved the other unit, primarily on the basis that Duke had not made a showing that it needed the
capacity to serve projected native load demands. Duke's latest projected cost for building one 800 MW unit
at Clif^ide is approximately $1.8 billion, or about $2,250^W. When financing costs, or allowance for fimds
used during construction (AFUDC), are included, the total cost is estimated to be $2.4 billion (or about
$3,000/kW).
Rising construction costs have also led utilities to reconsider expansion plans prior to regulatory actions. In
December 2006, Westar Energy announced tiiat it was deferring the consideration of a new 600 MW coalbased generation facility due to significant increases in the estimated construction costs, which increased
from $1.0 billion to about $1.4 billion smce the plant was first announced in May 2005.
Increased construction costs are also affecting proposed demonstration projects. For example, DOE
announced earlier this year that the jffojected cost for one of its most prominent clean coal demonstration
project, FutureGen, had nearly doubled.® FutureGen is a clean coal demonstration project being pursued by
a public-private partnership involving DOE and an alliance of industrial coal producers and electric utilities.
FutureGen is an experimental advanced Integrated Gasification Combined Cycle (IGCC) coal plant project
that will aim for near zero emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), mercury, particulates
and carbon dioxide (CO2). Its initial cost was estimated at $950 million. But after re-evaluatmg the price of
constmction materials and labor and adjusting for mfiation over time, DOE's Office of Fossil Energy
announced that the project's price had increased to $1.7 billion.
Transmission Projects
NSTAR, the electric distribution company that serves the Boston m^ropolitan area, recently built two 345
kV lines from a switching station in Stoughton, Massachusetts, to substations in the Hy<te Park section of
Boston and to Soutii Boston, respectively. In an August 2004 filmg before ISO New England Inc. (ISO-NE),
NSTAR indicated that tiie project would cost $234.2 million. In March 2007, NSTAR informed ISO-NE
that estimated project costs had increased by $57.7 million, or abnost 25 percent, for a revised total project
cost of $292 million. NSTAR stated that the mcrease is driven by increases in botii construction and material
costs, with construction bids coming in 24 percent higher than mitially estimated. NSTAR fiirther explained
that there have been dramatic increases in material costs, with copper costs mcreasing hy 160 percent, core
steel by 70 percent, flow-fill concrete by 45 percent, and dielectric fluid (used for cable cooling) by &6
percent.
' U.S. Department of Energy, April 10,2007, press release available at
http://www.fossil.energy.gov/news/techlines/2007/070l9-DOE_Signs_FutureGen_Agreementhtm!
11 Projected Investment Needs and Recent Infrastructure Cost Increases
Another aspect of transmission projects is land requhements, and in many areas of the country land prices
have increased substantially in tiie past few years. In March 2007, the California Public Utilities
Commission (CPUC) approved construction of the Southem California Edison (SCE) Company's proposed
25.6-mile, 500 kV transmission line between SCE*s existing Antelope and Pardee Substations. SCE initially
estimated a cost of $80.3 million for the Antelope-Pardee 500 kV line. However, the company subsequently
revised its estimate by updating the anticipated cost of acquiring a right-of-way, reflecting a rise in
California's real estate prices. The increased land acquisition costs mcreased the total estimate for the
project to $92.5 million, increasing the estimated costs to more than $3.5 million per mile.
Distribution Eauioment
Although most individual distribution projects are small relative to the more visible and public generation
and transmission projects, costs have been rising in this sector as well. This is most readily seen in HandyWhitman Index^ price series relating to distribution equipment and components. Several important
categories of distribution equipment have experienced sharp price increases over the past three years. For
example, the prices of line transformers and pad transformers have increased by 68 percent and 79 percent,
respectively, between January 2004 and January 2007, with increases during 2006 alone of 28 percent and 23
percent.^" The cost of overhead conductors and devices mcreased over the past three years by 34 percent,
and the cost of station equipment rose by 38 percent These are in contrast to the overall price increases
(measured by the GDP deflator) of roughly 8 percent over the past three years.
'° Handy-Whitman^ Bulletin No. 165, average increase of six U.S. regions. Used with permission.
12 A Factors Spurring Rising Construction
Costs
Broadly speaking, there are four primary sources of the increase ui construction costs: (I) material input
costs, including the cost of raw physical inputs, such as steel and cement as well as increased costs of
components manufactured from these inputs (e.g., transformers, turbines, pumps); (2) shop and frd>rication
capacity for manufactured components (relative to current demand); (3) the cost of construction field labor,
both unskilled and craft labor, and (4) the market for large construction project management, i.e., the queufaig
and bidding for projects. This section will discuss each of these factors.
Material Input Costs
Utility construction projects involve large quantities of steel, alummum and copper (and components
manufactured from tiiese metals) as well as cement for foundations, footings and structures. All of these
commodities have experienced substantial recent price increases, due to increased domestic and global
demands as well as increased energy costs m mineral extraction, processing and transportation. In addition,
since many of these materials are traded globally, the recent performance of the U.S. dollar will unpact the
domestic costs (see box on page 14).
Metajs
After being relatively stable for many years (and even declmmg hi real terms), the price of various metals,
including steel, copper and aluminum, has increased significantly m tiie last few years. These increases are
primarily the result of high global demand and increased production costs (mcluding the impact of high
energy prices). A weakenmg U.S. dollar has also contributed to high domestic prices for unported metals
and various component products.
Figure 5 shows price indices for primary inputs into steel production (iron and steel scrap, and iron ore) since
1997. The price of botii inputs fell in real terms during tiie 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 b*on and steel scrap prices rose nearfy 120 percent. The increa^ over tiie
last few years was especially sharp—between 2003 and 2006, prices for hon ore rose 60 percent and iron
and scrap steel rose 150 percent
13 Factors Spurring Rising Construction Costs
Exchange Rates
Many of tiie raw materials mvolved ui utility construction projects (e.g., steel, copper,
cement), as well as many major manufrtctured components of utility mfrastmcture
investments, are globally traded. This means that prices in the U.S. are also aflected
by exchange rate fluctuations, which have been adverse to the dollar in recent years.
The chart below shows trade-weighted exchange rates fix}m 1997. Although the dollar
appreciated against otiier currencies between 1997 and 2001, tiie graph also clearly
shows a substantial erosion of tiie dollar since the beginnmg of 2002, losing  r o u ^y 20
percent of its value against other major tradmg partners' currencies. This has had a
substantial impact on U.S. material and manufactured component prices, as will be
reflected in many of the graphs that follow.
Nominal Broad Dollar Index
•
Source:  U . 5. Fedvml Reserve BoanI, Statistic^ Release, Braad bidcK  D ^ ^
For e i si Exchange Value of  d» Dd l a r.
14 Rising Utility Construction Costs: Sources and Impacts
RgnreS
inputs to iron and Steel Production Cost indices
1997 1998 1999 2D00 ZOBl 2002 2009 WK
Year
S o u r c u: V.S. Geolagical  S i w c y,  M i n e nl Commodity  S w i n o a r i o,  and Ihe U.S.  B i m u  of Beonomic Analysis.
The increase in input prices has been reflected in steel mill product prices. Figure 6 compares tiie  t r ^d in
steel mill product prices to the general inflation rate (usmg tiie GDP deflator) over the past 10 years. Figure
6 shows that the price of steel has increased about 60 percent since 2003.
Figure 6
Steel Rflni Products Price indot
IfiO
§ 130
I
1 110
2004 2MS  l O O ti
Y c u-
&nmxs: U.S. Gaokigical Smvey, Mintfil Commodi^ Sumraaiies. and the U.S. Bureau of Bcowmic Analjisis.
15 Factors Spurring Rising Construction Costs
Various sources point to the rapid growth of steel production and demand m Chma as a primaiy cause of the
increases in botii steel prices and the prices of steelmaking inputs.^^ Chma has become botii the world's
largest steehnaker and steel consumer. In addition, some analysts contend that steel companies have
achieved greater pricuig power, partly due to ongoing consolidation of tiie mdustty, and note that recentiy
mcreased demand for steel has been driven largely by products used m energy and heavy industry, such as
plate and structural steels.
From the perspective of the steel industry, the substantial and at least semi-permanent rise in the price of
steel has been justified by the rapid rise m the price of many steehnakmg inputs, such as steel scrap, iron ore,
coking coal, and natural gas. Today's steel prices remain at historically elevated levels and, based on the
underlying causes for high prices described, it appears that hon and steel costs are likely to remam at these
high levels at least for the near fiiture.
Other metals unportant for utility infrastructure display sunilar price pattems: declining real prices over the
first five years or so of the previous 10 years, followed by sharp mcreases in the last few years. Figure 7
shows that aluminum prices doubled between 2003 and 2006, while copper prices nearly quadrupled over the
same period.
Figure?
Aluminum and Copper Price Indices
2S0
1-
100
5 0-
GD?DelUier
• S : : ^ ^  _ . . - - ' - " — — ^ ^
\ -^"^"^"^"^^ _--—^
Capper /
^ 7
1997 1»9S  i 9» 2000 2001 2002 2003 2004
Yewr
Simrces: U.S. Getdogical Survqr. Minenl Commodity Suramarios, and iba U.S. Bureau of Econunic Analysis.
'^ See, for example. Steel: Price and Policy Issues, CRS Report to Congress, Congressional Research Service, August 31,
2006.
16 Rising Utility Construction Costs: Sources and Impacts
These price increases were also evident in metals that contribute to important steel alloys used broadly in
electrical infrastructure, such as nickel and tungsten. The prices of these display similar patterns, as shown
in Figure 8.
R l ^ r eS
Nicicel and Tungsten Price Indices
3oe
as 200
1 5 0 -
1997 1998  t999  ZW1 2002 2003
Year
Sounxs: U.S. Ceotogicd Survey. Mineral Conr aodiv Smtmiarieit and the U.S. Bunau of Econonuc Aodysb.
Cement. Concrete. Stone and Gravel
Large infrastructure projects require huge amounts of cement as well as basic stone materials. The price of
cement has also risen substantially in the past few years, for tiie same reasons cited above for metals.
Cement is an energy-intensive commodity that is traded on intemational markets, and recent price pattems
resemble those displayed for metals. In utility construction, cement is often combined with stone and other
aggregates for concrete (often reinforced with steel), and there are other site uses for sand, gravel and stone.
These materials have also undergone significant price increases, primarily as a result of increased energy
costs in extraction and transportation. Figure 9 shows recent price increases for cem^it and crushed stone.
Prices for these materials have increased about 30 percent between 2004 and 2006.
17 Factors Spurring Rising Construction Costs
Figures
Cement and Crushed Stone Price Indices
150
I
I
1003  2006
Yew
Soiaves: U.S.Geolo^calSiirvey,MiitefalCoimnodi^SiaiaiuDiBC,anddteU.S.Bunau(tfEooiioaHcAiidy5is.
Manufactured Products for Utility Infrastructure
Although large utility construction projects consume substantial amounts of unassembled or semi-finished
metal products {e.g., reinforcing bars for concrete, structural steel), many of the components such as
conductors, transformers and other equipment are manufactured elsewhere and shipped to the constmction
site. Available price indices for these components displ^ similar patterns of recent sharp price increase.
Figure 10 shows the increased prices experienced m wu*e products compared to the inflation rate, according
to the U.S. Bureau of Labor Statistics (BLS), highligjiting the impact of underlying metal price increases.
Manufactured components of generating facilities—larp pressure vessels, condensers, pumps, valves—^have
also increased sharply since 2004. Figure 11 shows the yearly increases experienced in key component
prices since 2003.
F l8 Rising Utility Construction Costs: Sources and Infipacts
Figure 10
Qeciric Wire and Cable Price indices
g 180 .
I
B 140
130
NMf t r roiuWure
1997 1998 1999 2000 2001 2002 2003
Y e ar
Smme s: The  U S. Bureau of  L d »r Statistics and the U.5- BueaB of Ecoitomk AnalysiG.
Figure  11
Equlfmient Price increases
D 2P03 g 2004 g 21105 D 2006 I
0.7
0;6
OA
04 n
0 3
OJ
01
0 -
--
15%
2S%
n
7rz2
1 1 1 1 1
1 1 t 1 1
20K
3eH
—
lOK
2S%
m
—
«%
7%
• r «.
1S«
30«
«
•%
UK
«
9%
2S%
i
s»
«%
^
• -
. - - '  ^ > '
•^  ^ y ^ ^ ' ^ y ^ - ^
Source: "Who. Wtai,  V h t n , H a w' pn8entedQnbyIolmSit«d,BecfatdI>ia«mCorp.DeliveredatdMconi«wceanii^
GeneraHott ofCentnoioh  ( D n v^ Ballantine  L U ^ Vbty 4,200&
19 Factors Spurring Rising Construction Costs
Labor Costs
A significant component of utiiity construction costs is labor—both unskilled (common) labor as well as
craft labor such as pipefitters and electricians. Labor costs have also increased at rates higher than the
general inflation rate, although more steadily since 1997, and recent increases have been less dramatic than
for commodities. Figure 12 shows a composite national labor cost index based on simple averages of the
regional Handy-Whitman Index® for common and craft labor. Between January 2001 and January 2007, the
general inflation rate (measured by tiie GDP deflator) increased about 15 percent During the same period,
the cost of craft lat)or and heavy constmction labor mcreased about 26 percent, ^vhile common labor
increased 27 percent, or almost twice tiie rate of general inflation. ^^ While less severe than commodity cost
increases, mcreased labor costs contributed to the overall construction cost increases because of tiieir
substantial share in overall utility infrastructure construction costs.
H g u r e l2
National Average Labor Costs index
I W
MO
i
"g 130
120
110
100
1  — - U b o r E K H M y r C o n i l i w t i a D i n d R c i n f b n M O M a^
- ~ ^ ^
CiMMMOLBbor
>
y \ ^
^
— C r e n L A w
y ^ ^ ^
^ ^ ^ - .
^ /
G D P D e H i ur |
- < /
« * ^
^^^^^^'^
-""""^
19M 1992 1993 1994  t »5 199S 1997 199S 1999 2000 30M 20«2  2 0n 2004 3095 2006 2007
Year
S o a n x s:  I b e  H a i d y - v n u l n i M i O B u l l e t i iv  N o.  I f t S . a o d t be U.S.  B u e au  of Boonomic Analysis.
Simple  a m a ge  of  a il n^^ooal labor  c on te£ccs  l or the specifled Qpes tf  l ^ a r.
Although labor costs have not risen dramatically m recent years, there is growing concern about an emerging
gap between demand and supply of skilled construction labor—especially if the anticipated boom in utility
construction materializes. In 2002, the Construction Users Roimdtable (CURT), surveyed its members and
found that recmitment, education, and retention of craft workers continue to be critical issues for the
industry. ^^ The average age of the current construction skilled workforce is rising rapidly, and high attrition
rates in construction are compounding the problem. The industry has always had  h i ^ attrition at the entrylevel positions, but now many workers in the 35-40 year-old age group are leaving the industry for a variety
of reasons. Hie latest projections mdicate that, because of attrition and anticipated growth, the constmction
'^ These figures represent a simple average of six regional indices, however, local and regional labor markets can vary
substantially from these national averages.
'^ Confronting the Skilled Construction Wor^orce Shortage. The Construction Users Roundtable, WP-401, June 2004, p. 1.-
F^20 Rising Utility Construction Coste: Sources and Impacts
industry must recruit 200,000 to 250,000 new craft workers per year to meet fiiture needs. However, both
demographics and a poor industry image are workmg against the construction industry as it tries to address
this need. '^
There also could be a growing  g ^ between the demand and supply of electrical lineworkers vfho maintain
the electric grid and who perform much of the labor for transmission and distribution investments. These
workers erect poles and transmission towers and install or repair cables or wires used to carry electricity
from power plants to customers. Accordmg to a DOE report, demand for such workers is expected to
outpace supply over the next decade. ^^ The DOB analysis indicates a significant forecasted shortage in the
availability of qualified candidates by as many as 10,000 lineworkers, or nearly 20 percent of the current
workforce. As of 2005, lineworkers earned a mean hourly wage of $25/hour, or $52300 per year. The
forecast supply shortage will place upward pressure on the wages earned by lineworkers.**
Shop and Fabrication Capaci^
Many of the components of utility projects—including large components like turbines, condensers, and
transformers—are manufactured, often as special orders to coincide with particular constmction projects.
Because many of tiiese components are not held m large inventories, the overall capacity of thenmanufacturers can influence the prices obtained and the length of time between order and delivery. The
price increases of major manufactured components were shown in Figure 11. While equipment and
component prices obviously reflect underlying material costs, some of the price increases of manufactured
components and the delivery lags are due to manufacturing capacity constraints that are not readily overcome
in the near terra.
As shown in Figure 13 and Figure 14, recent orders have largely eliminated spare shop capacity, and
delivery times for major manufactured components have risen. These constrauits are addhg to price
increases and are difficuh to overcome with imported components because of the lower value of the dollar in
recent years.
The increased delivery times can affect utility construction costs through completion delays tiiat mcrease the
cost of financing a project. In general, utilities commit substantial funds during the construction phase of a
project that have to be financed either through debt or equity, called "allowance for fund used during
construction" (AFUDC). All else held equal, the longer the time from the mitiation through completion of a
project, the higher is the financing costs of tiie mvestment and the ultimate costs passed tinougji to
ratepayers.
*^ Worlforce Trends in the Electric Utility Industry: A Report to the United Staies Congress Pursuant to Section IIOI of the
Energy Policy Act of 2005. U.S. Department Of Energy, August 2006, p. xi.
' ^ I d . , p . 5.
2 1 ^ Factors Spurring Rising Construction Costs
Hgur e lS
Shop Capacity
Sovree:'Vho, What,  I f l ^ r ^ / i ^ w" pte3entati(mbyJohR5i^,BecfaldlV>weTCwp.DdivsKdBt4Kooii&imneiiti
Gejwrinfan fl^GmenitftiR (Dewqr BalUmine  I I J ), MQT 4,2006.
R g u r e l4
Delhiery Schedules
^ ^
^^
^ '
"  ' ^ • ^ _ y - ^ y
Smaee: "Vhr. Wlaa. H%efv.ffi»f"pKseinationlv John  S i ^ e L B e d i td Power C«p.I)d)vered at die  conEi r enc e emi l l edJ^
^ ^ 22 Rising Utility Construction Costs: Sources and Innpacts
Engineering, Procurement and Construction (EPC) Mlaricet Conditions
Increased worldwide demand for new generatii^ and other electric infrastructure projects, particularly in
China, has been cited as a significant reason for the recent escalation in the construction cost of new power
plants. This suggests that major Engineering, Procurement and Constmction (EPC) firms should have a
growing backlog of utility infrastructure projects in the pipelme. While we were unable to obtam specific
information from the major EPC firms on tiieir woridwide backlog of electric utility mfrastmcture projects
{i.e., the number of electric utility projects compart with other infrastructure projects such as roads, port
facilities and water infrastructure, in tiieir respective pipelmes), we exammed tiieu- financial statements,
which specify the financial value associated with their backlog of infrastmcture projects. Figure 15 shows
the cumulative aimual financial value associated with the backlog of infrastmcture projects at the following
four major EPC firms; Fluor Corporation, Bechtel Corporation, The Shaw Group Inc., and Tyco
Intemational Ltd. Figure 15 shows that the aimual backlog of infrastmcture projects  r o^ sharply between
2005 and 2006, from $4.1 billion to $5.6 billion, an increase of 37 percent. This significant increase in tiie'
annual backlog of infrastmcture projects at EPC firms is consistent with tiie data showing an mcreased
worldwide demand for infrastmcture projects in general and also utility generation, transmission, and
distribution projects.
Rg u r e lS
Annual Backlog  at Major EPC Firms
Year
Data are  c o i n p i l ed from  t he  A n t w al Et^rarts  of  R u w  C o i p o n t i o n, BecMel Cofprnst iDa.  T he  5 h^
International  L t d. For  B e d i t d . the data represent  n ew booJced  w a r k, as becklog » not reported.
The growth in construction project backlogs likely will dampen the competitiveness of EPC bids for fiiture
projects, at least until the EPC industry is able to expand edacity to m^uiage and execute greater volumes of
projects. This observation does not unply that this market is generally uncompetitive—rather it reflects the
limited ability of EPC firms with near-term capscify constrauits to service an upswing in new project
development associated with a boom period in infrastmcture constmction cycles. Such constraints.
23 Factors Spumng Rising Construction Costs
combined with a rapidly fillmg (or full) queue for project management services, lunit mcentives to bid
aggressively on new projects.
Although difficuh to quantify, this lack of spare capacity m the EPC market will undoubtedly have an
upward price pressure on new bids for EPC services and contracts. A recent filing by Oklahoma Gas.&
Electric Company (OG&E) seeking approval of the Red Rock plant (a 950 MW coal unit) provides a
demonstration of this effect. In Janiiary 2007, OG&E testimony indicated that theu* February 3,2006, cost
estimate of nearly $l,700/kW had been revised to more than  $ I , 9 0 0 ^W by September 29,2006. a 12-
percent increase m just nine months. More than half of the increase (6.6 percent) was ascribed to change m
market conditions which "reflect higher materials costs (steel and concrete), esc^ation in major eqmpment
costs, and a significant tightening of the market for EPC contractor services (as there are rekitively few
qualified fums that serve tiie power plant development market)."^^ In the detailed cost table, OG&E
mdicated that the estimate for EPC services had increased by more than 50 percent durmg tiie nine month
period (from $223/kW to $340/kW).
Summary Constmction Cost indices
Several sources publish summary constmction cost uidices that reflect composite costs for various
construction projects. Although changes in these uidices depend on the actual cost weights assumed e.g.,
labor, materials, manufactured components, they provide useful summary measures for large mfrastmcture
project construction costs.
The RSMeans Constmction Cost Index provides a general constmction cost index, which reflects primarily
building constmction (as opposed to utility projects). This mdex also reflects many of the same cost drivers
as large utility constmction projects such as steel, cement and labor. Figure 16 shows the changes in the
RSMeans Constmction Cost mdex since 1990 relative to the general inflation rate. While the index rose
slightly higher than the GDP deflator begummg 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 gwieral inflation.
•
" Testimony of Jesse B. Langston before the Corporation Commission of the State of (Mdahoma, Cause No. PUD
200700012. Januaiy 17,2007, page 27 and Exhibit JBL-9.
F'24 Rising Utttily Construction Costs: Sources and Impacts
Figure 16
RSMeans Historical Construction Cost  i n d«
ISO
S 140
S 130 •-
PH
"S 120
110
100
90
1990 1991 1992 1993 1994 I99S 1996 1997 I99S 1999 2000 SIOl 2002 2003 2004 2009 2006
Year
Sotmx: RSKteans, Heavy ConstnictionCoit Data, ZOttt Annual fidhian, 2006.
The Handy-Whitman Index^ publishes detailed indices of utility constmction costs for six tegioris, broken
down by detailed component costs in many cases. Figures 17 through 19 show tiie evolution of several of
the broad aggregate indices since 1991 compared with the general mflation mdex (GDP deflator).'* The
index numbers displayed on the graphs are for January 1 of each year displayed.
Figure 17 displays two indices for generation costs: a weighted average of coal steam plant constmction
costs (boilers, generators, piping, etc.) and a stand-alone cost index for gas combustion turbines.'
As seen on Figure 17, steam generation constmction costs tracked the general mflation rate feirly well
through the 1990s, began to rise modestly in 2001, and increased significantiy since 2004. Between Januaiy
1,2004, and January 1,2007, tiie cost of constmcting steam generating units mcreased by 25 percent—more
than triple the rate of inflation over the same time period. The cost of gas turbogenerators (combustion
turbines), on the other hand, actually fell between 2003 and 2005. However, during 2006, tiie cost of a new
combustion turbine mcreased by nearly 18 percent—roughly 10 times the rate of general inflation.
'* Used with permission. See Handy-Whitman* Bulletin, No. 165 for detailed data breakouts and regional vahies for six
regions: Pacific, Plateau, South Central, North Central, South Atiantic and Nortii Atiantic. The Figures shown reflect
simple averages of the six regions.
2 5 ^ Favors Spurring Rising Construction Costs
H g u r e l7
Nationai Average Generation Cost Index
1«0
170 -
f
•a  i pi
ito -
III I I —  1 1  , . . .  r . — , , . . (  • • • — , I. , I  , . — • I  i — . p  , 1 ,  I - I
1991  t m 1993 1994  m s 1996 1997 t99S 1999 2000 20(H 20IZ 2003 2004  » 05 30D6 2007
V e ar
S6urc*t: TlieHMdy-WlHtmanOBulletu),Na.lfi3tBdlheU.S.BareaBofEconaiiiicAtul3qu.
SimplB average oT all tegtonai coititniction and  e q u p n i ni coil indices fbr the spedfled  c o n i p o n ^
Figure 18 displays the increased cost of transmission investment, which reflects such items as towers, poles,
station equipment, conductors and conduit. The cost of transmission plant mvestments rose at about the rate
of inflation between 1991 and 2000, increased in 2001, and then showed an especially sharp increase
between 2004 and 2007, rising almost 30 percent or nearly four times the annual mflation rate over that
period.
Figure 18
National Average Transmission Cost index
HO
170
eri
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 Z003 Z004 20QS 20$6 2007
Year
S e a r e a: TheHandy-WtaitnunOBulietiti.ND. I65,aDdtheUS.BitfaBuofEcoiioinicAiutyris.
S i t t ^t avenge of all fegmul transcusnoii cost indices.
^ 2 6 Rising Utility Construction Costs: Sources and Impacts
Figure 19 shows distribution plant costs, which mclude poles, conductors, conduit, transfcmners and meters.
Overall distribution plant costs tracked the general inflation rate very closely between 1991 and 2003.
However, it then increased 34 percent between January 2004 and January 2007, a rate that exceeded four
times the rate of general inflation.
Rg u r e lS
Nationai  A v e r a^ Distribution Cost Index
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 SMI 2D02 2008 2004 20BS  U 06
Year
Sources: T1ieH«nd)r-Whitiiiai)OBtdletiii,Noi l65,andd»U.S.BwetuofEcoiianilcAiiitysis.
Simple  a v e i ^e of all regioDal dislribtition cost bMUcec
Comparteon with Energy Infomiation Administration Power Plant Cost Estimates
Every year, EIA prepares a long-term forecast of energy prices, production, and consumption (for electricity
and the other major energy sectors), which is documented in the Annual Energy Outlook (AEO). A
companion publication. Assumptions to the Annual Energy Outlook, hemizes the assumptions (e.g., fuel
prices, economic growth, environmental regulation) underlymg EIA's annual long-term forecast. Included
in the latter document are estimates of the "ovemighf' capital cost of new generating units (i.e., the capital
cost exclusive of financing costs). These cost estimates influence the type of new generating capacity
projected to be built during the 25-year time horizon modeled in the AEO.
The EIA capital cost assumptions are generic estimates that do not take into account the site-speciflc
characteristics that can affect constmction costs signiflcantiy.'^ While EIA's estunates do not necessarify
provide an accurate estimate of the cost of building a power plant at a specific location, they should, in
theory, provide a good "ballpark" estimate of the relative construction cost of different generation
EIA does incorporate regional multipliers to reflect minor variations in construction costs based on labor conditions.
27 Factors Spurring Rising Construction Costs
technologies at any given time. In addition, since they are prepared annually, these estimates also should
provide insight into constmction cost trends over time.
The EIA plant cost estunates are widely used by industry analysts, consultants, academics, and
policymakers. These numbers frequently are cited in regulatory proceedings, sometimes as a yardstick by
which to measure a utility's projected or incurred capital costs for a generating plant. Given this, it is
important that EIA's numbers provide a reasonable estimate of plant costs and incorporate both
technological and other market trends that significantiy affect these costs.
We reviewed EIA's estimate of overnight plant costs for the six-year period 2001 to 2006. Figure 20 shows
EIA's estimates pf the constmction cost of six generation technologies—combined-cycle gas-fired plants,
combustion turbines (CTs), pulverized coal, nuclear, IGCC, and wmd—over tiie period 2001 to 2006 and
compares these projections to the general mflation rate (GDP deflator). These sbc 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 Constmction Cost Estimates
Year
S o m a : Data ctrilectedfism die EiM(gyInfbnnai)onAdii^usiTdioii,^fnmj)tfflWMihj1mit«^
fttm die  U S. Bureau of Economic Analysts.
The general pattern in Figure 20 shows a dramatic change in several technology costs between 2001 and
2004 followed by a stable period of growth until 2006. The two exceptions to tiiis are conventional coal and
IGCC, which increase by a near constant rate each year close to the rate of inflation throughout the period.
The data show conventional CC and conventional CT experiencing a sharp increase between 2001 and 2002.
After this increase, conventional CC levels off and proceeds to increase at a pace near inflation, while
conventional CT actually drops significantiy before 2004 when it too levels near the rate of inflation. The
Was Rising Utility Construction Costs: Sources and lmpa<^
pattern seen with nuclear technology is near to the opposite. It falls dramatically until about 2003 and tiwn
increases at the same rate as the GDP deflator. Lastly, wmd moves close to inflation until 2004 when it
experiences a one-time jump and then flattens offthfiHigh 2006.
These pattems of cost estimates over time contradict the data and findings of this report Almost every otiier
generation constmction cost element has shown price changes at or near the rate of inflation tiirou^out the
early part of this decade witii a dramatic change in only the last few years. EIA appears to have reconsidered
several technology cost estimates (or revised the beiichmark technology type) in isolation between 2001 and
2004, without a systematic update of others. Meanwhile, during the period that overall constmction costs
were rising well above the general inflation rate, EIA has not revised its estimated capital cost figures to
reflect this trend.
EIA's estimates of plant costs do not adequately reflect the recent increase in plant constmction costs that
has occurred m the last few ye»^. Indeed, EIA itself acknowledges tiiat its estimated constmction costs do
not reflect short-term changes in the price of commodities such as steel, cement and concrete.^ While one
would expect some lag in the EIA data, it is troubling that its most recent estimates continue to show the
constmction cost of conventional power plants mcreasing only at the general rate of mflation, Empuical
evidence shows that tiie constmction cost of generating plants—both fossil-fired and renewable—^is
escalating at a rate well above the GDP deflator. Even the most recent EIA data fail to reflect important
market impacts that are driving plant constmction costs, and tiius do not provide a reliable measure of current
or expected constmction costs.
^° Annual Energy Outlook 2007, U.S. Energy Information Administration, p. 36.
29 A Conclusion
Constmction costs for electric utility investments have risen sharply over the past several years, due to
factors beyond the industry's control. Increased prices for material and manu&ctored components, rising
wages, and a tighter market for construction project management services have contributed to an across-tiieboard increase in the costs of investing in utility infrastructure. These higher costs show no immediate signs
of abating.
Despite these higher costs, utilities will contmue to invest in baseload generation, envhonmental controls,
transmission projects and distribution system e?q)ansion. However, rising constmction costs will put
additional upward pressure on retail rates over time, and may alter the pace and composition of investments
going forward. The overall impact on tiie industry and on customers, however, will be bome out m various
ways, depending on how utilities, markets and regulators respond to these cost increases. In tiie long run,
ctistomers ultin^tely will pay for higher construction costs—either directly in rates for completed assets of
regulated companies, less directiy in the form of higher energy prices needed to attract new generating
edacity in organized markets and in higher transmission taril^, or indirectiy when rising constmction costs
defer investments and delay expected benefits such as enhanced reliability and lower, more stable long-term
electricity prices.
31 mmmmmmmm^
•
HBiifi
i ^  i f ergy Power Plant
Reference
DOE/NETL-2007/1282
Bituminous Coal and Natural Gas
to Electricity Summary Sheets
M s 0 ^ ^ ^ ^
N=TL Overview — Bituminous & Na tur al Gas to Electricity^
Overview of Bituminous Baseline Study
Objective and Description
The objective of the Cost and Performance BaseHne for fossiJ Energy Plants; Volume / (Bftuminous Coal and Natural
Gas to Electridty) is  to determine cost and performance estimates of the near-term commercial offeroigs for
power plants, both with and without current technology for carbon capture and sequestration (CCS). The study
uses consistent design requirements for alt technologies examined, as well as up-to-date performance and capital
cost estimates. The study timeframe focuses on plants built now and commissioned in 2010. Each plant is built
at a greenfield site in the midwestern United States.
The fossil energ/ plant cost and performance estimates presented in the study can be used as a baseline for
additional comparisons and analyses. These systems anal}^es are a critical elem^it of planning and gukJing
Federal Fossil Energy Research and Development
Twelve different power plant configurations are analyzed in the Bituminous Baseline Study. The list includes six
integrated gasification combined-cycle (IGCC) cases utilizing General Electric Energy (GEE), ConocoPhlllips
(CoP),and Shell gasifiers, each with and without CCS; four pulverized coal (PC) cases,  two subcritical and  two
supercritical, each with and without CCS; and  two natural gas combined-cycle (NGCC) plants, one with and one
without CCS. The study matrix is provided in Table I.
Table  I.  S t u dy  M a t r ix
•
P l a n t T y pe
IGCC
PC
NGCC
S t a n d a rd
C o n d i t i o ns
ipsigr^r^TF)
1.000/1.050/1,050
1,800/1.000/1,000
2.400/1.050/1.050
3,500/1,100/1.100
2,400/1,050/950
Gas
l U r b i ne
F-Ctass
-
F-Class
G a s l f i e r / B o i l er
GEE
CoP E-Gas™
Shell
GEE
CoP E-Gas™
Shelt
Subcritical
Supercritical
Heat recovery steam
generators
A c id Gas Removal /
C Oj  S e p a r a t i on / Suf fur
Recovery
Selexol/-/Claus
MDEA/-/Glaus
Sutfinol-M/ - /Glaus
Selexol/Selexol/Claus
Selexol/Selexol/Claus
Selexol/Selexol/Claus
Wet flue gas desulfurization
(FGD)/ - /Gypsum
W et FGD/Econamine/Gypsum
Wet FGD/ - /Gypsum
Wet FGD/Econamine/Gypsum
-
- /Econamine/ •
C O,
C a p t u re
(%)
-
-
_
90
88
90
-
90
_
90
-
90 Overview — Bituminous & Na tur al Gas to Electricity
Assumptions
Technical
T he IGCC cases are dual-train gasification systems. Once  t he syngas is cleaned of acid gases and  o t h er
contaminants,  it is  fed  to  t wo advanced F-Ctass combustion  t u r b i r ^s (232  H We gross  o u t p ut each) couq)led  w i th
t wo heat recovery steam generators (HRSGs) and a single steam  t u r b i ne  to generate rougfily 750  M V ^ gross
plant  o u t p ut (about 630  M W e. net).  T he CCS cases require a water-gas-shift (WGS) and a two-stage Selexol
system  to capture  t he carbon dioxide  ( C O j) and compressors  to raise  t he CO^  to  t he pipeline requirements of
i 5.3 MPa (2,215 psia). These systems  requi re a significant amount of  e x t r a c t i on  s t ^ m and auxiliary  p o w ^ , which
reduces  t he  o u t p ut  of  t he steam  t u r b i ne and reduces  t he net plant  p ower  to about 520 MWe. Because  t he
IGCC system is constrained by  t he discrete F-Class  t u r b i ne size,  t he system cannot be scaled  to increase  t he  n et
o u t p ut  to match  t h at of  t he cases  w i t h o ut CCS.
A ll  f o ur PC cases employ a one-on-one configuration
comprising a state-of - the-art PC steam generator and
steam  turbine.  T he boi ler is a  d r y - b o t t o m, wall-fired unit
t h at employs  low-ni t rogen oMdes  ( N O x) burners  w i th
over-frre air and selective catalytic  reduct ion  f or  N Ox
c o n t r o l, a wet-limestone, forced-oxidation scrubber
f or sulfur dioxide (SOj) and mercury (Hg)  c o n t r o l, and
a fabric  f i l ter  f or particulate mat ter (PM)  c o n t r o l. In
t he cases  w i th CCS,  t he PC plant is equipped  w i th  t he
Econamine FG Plus™ process.  T he coal feed  rate is
increased in  t he CCS cases  to increase  t he gross steam
t u r b i ne  o u t p ut and account  f or the higher auxiliary
load of carbon capture and compression.  T he boi ler
and steam  turbine industry's ability  to match unit
size  to a custom specification has been commercially
demonstrated, enabling a  c o m m on  n et  o u t p ut of 550
M We  f or  t he PC cases in this study.
Table 2. Coal Analysis
Rank
Seam
Source
B i t u m i n o us
I l l i n o is  N o. 6  ( H e r r i n)
O ld  B en Mi ne
P r o x i m a te Analysis  ( w e i g ht  % )'
Moisture
Ash
Volatile matter
Fixed carbon
Total
Sulfur
Higher heating value. Btu/lb
Lower heating value, Btu/lb
A£ Received
11.12
9.70
34.99
44.19
100.00
2.51
11.666
11.252
D ry
0.00
10.91
39.37
49.72
100.00
2,82
13,126
1^712
'The above proximate analysis assumes sulfur as a vobtiie
matter.
An analysis of  t he Illinois  N o. 6 bituminous coal used in  t he  IGCC and PC cases is provided in Table 2.
T he  N G CC cases use  t wo F-Class turbines, each generating a gross 185 MV\fe. The  t wo turbines are coupled
w i th  t wo H RSGs and one steam  t u r b i ne generator in a multi-shaft 2x2x I configuration. For  t he CCS cases,
C O^ is removed in an Econamine process  t h at imposes a significant auxiliary  p ower load  on  t he system and
requires significant  e x t r a c t i on steam, reducing  t he steam  t u r b i ne power  o u t p ut Similar  to  t he  I G CC cases,  t he
N G CC cases are constrained by  t he combustion  t u r b i ne size.  T he  N G CC cases have a  t o t al net  p ower  o u t p ut
of 560 MWe  w i t h o ut CCS and 482 MWe  w i th capture. In ail CCS cases,  t he compressed  C Oj is  t ranspor ted  50
miles Table 3. Environmental Targets
 via pipeline  to a geologic sequestration field
f or injection into a saline aquifer. In addition  to
t r a n s p o rt and storage,  t he  C O^ is mo n i t o r ed  f or
80-years.
Environmental
T he environmental approach for  t he study was  to
choose environmental targets  f or each technology
t h at meet  or exceed regulatory requirements.  T he
IGCC targets we re chosen  to match  t he design basis of  t he Electric Power Research Institute  f or  t h e ir CoalFteet
for Tomorrow Iniaative. Best Available  C o n t r ol Technology was applied  to each  of  t he PC and  N G CC cases* and
Overview-2
P o l l u t a nt
SO,
N Ox
PM (fifterable)
Hg
I G CC
0.0128
Ib/MMBtu
15 ppmvd
@ 15% Oxygen
0.0071
Ib/MMBtu
> 90% capture
PC
0.085 IW
MMBtu
0.07 Ib/MMBtu
0.017 lb/
MMBtu
i . H l b / T B tu
N G CC
<0.6 gr SuHur
/lOOscf
2.5 ppmvd
@ 15% Oxygen
Negligible
Nc^li^ble Overview — Bituminous & Natural Gas to Electricity
Table 4. Ma j or  E c o n omic  A s s ump t i o ns
the resulting emissions compared  to 2006 New Source
Performance Standards limits and recent permit averages.
Economic
T he  t o t al plant cost (TPC)  f or each technology was
d e t e rmi n ed  through a combination of vendor quotes,
scaled estimates  f r om previous design/build projects,  or a
combinat ion of  t he  t w o. Total plant cost includes all equipment
(complete  w i th initial chemical and catalyst loadings), materials,
labor  ( d i r ea and indirect), engineering and  c o n s t r u c t i on
management, and contingencies (process and project ).
Own e r 's costs are  n ot included.
T he  c o st estimates car ry an accuracy of  ± 30 percent,
consistent  w i th  t he screening study level  of design er^gtneering
applied  to  t he various cases  in this study.  A ll cases  w e re
evaluated under  t he same set  of technical and economic assumptions allowing meaningful comparisons among
t he cases evaluated.
Startup date
Cost year (U.S. dollars) .
Coal cost ($/MMBtu)
Natural gas c6st.($/MMBtu) .
OHKJCM?^ factor (Sfe):: ';.
• r . : \ G c c - , .  : , : : • : • " ' .-
PGrt^Gc?: :
Capital charge factor (%):
High risk (AH IGCC.  PO
NGCC wi di  C O, capture)
U w r i s k C P O N G CC
Without  C Oj capture)
Plant Tife (years)
2010
2007
1.80
6.75
80
85
17.5%
16.4%
20
Table 4 lists  t he major economic assumptions. In  this study, dual trains  w e re used only wh en equipment capacity
requi red an additional  t r a i n, and no redundancy was employed  o t h er than normal sparing of  rotat ing equipment
For  t h o se cases  t h at feature CCS, capital and operat ing costs  w e re estimated for CO^  t r a n s p o r t, storage, and
mo n i t o r i n g. These costs we re then levelized over a twenty-year per iod.
This study assumes  that each new plant wo u ld be dispatched at  t he time  It becomes available and wo u ld be
capable of generating maximum capacity when onl ine. Therefore, capacity  factor (CF) is assumed  to equal
availability.  T he CF is  80 percent for  I G CC cases arxJ 85 percent  f or  b o th PC and  N G CC cases.
Results
Technictd
T he energy efficiency of  N G CC cases is  on  t he  o r d er  of 50 percent (higher heating value,  H H V );  fol lowed by
supercritical PC and  IGCC,  b o th about  40 percent  ( H HV basis); and subcritical PC,  w i th an efficiency  of about 37
percent  ( H HV basis). Rgure I shows  t he relative energy efficiency  of each technology case.
Figure  I.  P l a nt Efficiency
80%
^ 70%  " " © c c - ea
£ 60%
1 : 5 0%
g 40%
g 30%
lU
20%
10%
0%
DSubcritleal PC
• i G c c - e «M
•Supsrcrtlfcal PC
•IGCC-Slwll
•NOCC -Advanowl F-CiaM
50^%
38J%  m % 4 ^ 3 6 . 8 % 39.
43.7%
M ^ 31.7% 32*0%
w/o CCS  w / C CS
O v e r v i e w -3 Overview — Bituminous & Na tur al Gas to Electricity
Wi th CCS, the energy penalty is 12 percentage points for PC plants, 7 percentage points for NGCC, and 6-9
percentage points for IGCC. Even with CCS, NGCC still maintains the highest efficiency of the plants evaluated
at over 40 percent (HHV basis). The significant energy penalty for the PC plants reduces the efficiency  to about
26 percent (HHV basis). IGCC has an efficiency advantage over PC in the CCS cases primarily because tiie CO^
is more concentrated in IGCC syngas than in PC flue gas, thus requiring less energy  to capture. The efficiency of
the IGCC plants with CCS is about 32 percent (HHV basis).
Environmental
All cases meet or exceed the environmental requirements set forth in the study design basis. The natural
gas systems are the cleanest types of fossil povi^r plants due  to the low sulfur content and lower carbon-tohydrogen ratio of the methane fuel. IGCC plants are the cleanest coal-based systems, wi th significantly lower
levels of criteria pollutants than the PC plants. Figure 2 compares the results for these pollutant emissions for
the various technology cases.
ctfloe
Figure 2.  S O ,,  N O x,  a nd  PM Emissions
I S O j U b M M B t i i)  • N O x O t i M M B i B)  B P U  | I M l M  B t i i)
0.0000
GEE GEE E-Gas  B C m  S h e!  S l wl Stdxr i feal SuboHfeal  S v e t o l c a l SupenhBed  ^ ^ ^  - / a s
«rfoCCS wrfCCS  u t o C CS rtCCS »*»CCS  W C CS  P C « t e C CS  PCwfCCS  P C * * C C 5 PCwrfCCS  ^ " ^
> t •*' 4 _ »
IGCC
SO2 emissfons  f or  t i n PC Mtf CCS and  t ht NOCC cases  m r a iwgQBlblB.
PM eotfialons  for  b e NGCC cases  w a n I
PC  NGCC
Advanced
F-Clas8
All CCS cases vt/ere required  to remove 90 percent of the carbon present in the syrigas. Due  to a higher
methane content of the syngas in the CoP E-Gas™ case however, carbon capture was 88.4 percent NGCC
plants produce 40 percent less CO^ than the coal-based systems. Tiie uncontrolled coal-based systems emitted
as much as 204 Ib/MMBtu of CO^, but with CCS, emissions were reduced  to about 20 Ib/MMBtu. Rgure 3
compares the results for CO^ emissions for the various technology cases.
All cases were required to control Hg emissions. The environmental target for Hg removal is >90 percent
capture for IGCC plants and an emission rate of 1. 14 Ib/TBtu for PC plants. Rgure 4 depicts the Hg emissions
results for each case.
Water usage among the plants without CCS is lowest in the NGCC cases. The IGCC plants use about one-anda-half times as much water as do the NGCC cases, and the PC cases use more than twice the amount of v/ater
In all CCS cases, vrater usage increases.  V ^ t er usage for IGCC cases is similar  to an NGCC vtrith CCS, whereas
the PC case writh CCS plants requires three  to four times more water. Rgure 5 shovw the respective water
usage rates for each technology case.
Econonuc
Overview^4 Overview — Bituminous & Natural Gas to Electricity
F i g u re  3.  C O^  E m i s s i o ns
250
Shel Subcrfkat Subcnfeal SupsnriBcal
«^CCS PCwtoCCS PCwfCCS PCw/bCCS
IGCC  PC
vrfCCS
wtoCCS WGCS
NGCC
Advanced
F-Class
Figure 4.  M e r c u ry Emissions
1.400
1JI00
I 1.000
^ 0 JOO
M
C
^  0 . 6 00
O^MO
O J MW
0.000
• I G C C - O EE
• K 3 C C. E-Gm
• I G C C - S h e ll
DSUIRCIIUKMI PC
•Supercr t t ieal PC
Oisn as7i 0.5T1.
1.143 1.143
1
o s rt Qjm  0.571
1
1.143 1.143
wrfoCCS w/CCS 1
Emissions for the NGCC cases were listed hi the report as ''Negligil)le."
T he coal-based plants have a much higher TPC  t l ian  N G C C,  b o th  w i th and  w i t h o ut CCS. For  IGCC,  t he TPC is
about $ 1,800/kV\^, varying somewhat based  on  t he gasifier  type. This is about 20 percent higher than  t he TPC
f or a PC supercritical plant, wh i ch is about $1.500/kWe.
F i g u r e s.  P l a nt Raw  W a t er Usage
W/O CCS  w/CCS
O v e r v l e w -5 Overview — Bituminous & Na tur al Gas to Electricity
W i t h  C C S,  t he  T PC  f o r  N G C C  a nd  PC plants  ( $ / k W)  increases by  a b o ut 110  a nd  85  p e r c e nt  r e s p e c t i v e l y.  T he
T P C  f or  t he  I G CC  p l a nt  increases  by  a r o u nd  35  p e r c e nt  T h e  N G C C  p l a nt  c a p i t al  r e q u i r eme r Yt is  o v er  $ l » 0 0 0/
kV\ fe, v^rhile  t he  I G CC  p l a n ts  c o st  a p p r o x i m a t e ly  $ Z 4 0 0  t o  $ 2 , 6 0 0 / k V ^ .  a nd  t he  PC  p l a n ts  c o st  o v er  $ 2 , 8 0 ( ^ V ^ .
F i g u re 6  s h o ws  t h e T P C  f or  e a ch  t e c h n o l o gy case.
C o s t - o f - e i e c t r i c i ty  ( C O E ),  v / h i ch  a c c o u n ts for  b o th  e f f i c i e n cy  a nd  c a p i t al  c o s t, is  l e v e l i z ed  o v er a  2 0 - y e ar  p e r i od
a nd  e x p r e s s ed  in  m i l l s / k Wh  ( o ne  m i ll is  o n e - t e n th  of a  c e n t ).  T h e  e l e c t r i c i ty  c o st  f or cases  w i t h o ut  C CS  ranges
f r om  a b o ut  63  m i l l s / k Wh  f or  PC  t o  6 8 .4  m i l l s / k Wh  f or  N G C C  a nd  an average  of  7 7 .9  m i l l s / k Wh for  I G C C.
F i g u re 6.  P l a nt Ca p i t al Re q u i r eme n ts
w/o CCS
Total plant cost includes all equipment {connptete wfth Initial
latwr (direct and indirect), engineering, construction
project).
w/CCS
md catalyst loadinip), materials,
and contingeRctes (piDCess and
W i t h  C C S,  I G CC is  t he  least  e x p e n s i ve  c o a l - b a s ed  o p t i on  f or  C O j  r e m o v al  w i t h a  l e v e l i z ed  c o s t - o f - e l e c t r i c r ty
( L C O E)  r a n g i ng  f r om 102.9  m i l l s / k Wh  t o 110.4  m i l l s / k W h.  T h is is  a b o ut 9  p e r c e nt  l o w er  t h an  PC  p b n ts
e q u i p p ed  w i th  C C S.  v ^ i c h  g e n e r a te  e l e c t r i c i ty  at a  c o st  of 114.8  m i l l s / k Wh  t o 118.8  m i l l s / k W h.  F ^ r e 7  b r e a ks
o u t  t he  L C OE  c o s ts for  e a ch  t e c h n o l o gy case.
T h e  c o st  of  C O j  a v o i d ed  w as  c a l c u l a t ed  f or  e a ch  C CS case  a nd is  s h o wn  in  F i g u re  8.  O n  an  a v o i d ed  c o s t  of
C O j basis,  I G CC Is  t he  least  e x p e n s i ve  o p t i on  o v e r a ll  ( $ 3 2 - $ 4 2 / t o n)  w h i le  N G C C is  t he  m o s t  e x p e n s i ve  o p t i on
( $ 8 3 / t o n ).
F i g u re 7. Level ized  C o s t - o f - E l e c t r i c l ty
140
3- 120
I 100
1 «
8 60
BC^rildGcwta  • F t o d C oA
§
H
e li
III
OVKMriaCwto
s
•
1 i
li
• P M C OM
1
•
ll
1
• C 02  T M n p ^ S k n g * »  i l k M ^
1
- tp- r ::
•  . H
I •
i
•'
1
1
•  : • • • • •
•
1
• ^ -
s
1
wibCCS ii^CCS
E^BS  S Ca Shal  SM Suberifart SubcriMol SupHottcai Supenriferi  ^ « e WCC 1  S
•fcCCS »rt:cS rtiCCS w/CCS PCwfaCCS  p e a c es PCwteCCS PCrfCCS  ^ ^ * *
• • • — — I F <  - > <••. — >
PC NGCC
Advanced
F-Class
IGCC
Al M«t» aie In January 2007 U.S. doAars.
O v e r v i e w -6 Overview — Bituminous & Natural Gas to Electricity
F i g u re 9  i l l u s t r a t es  t h at  at  n e ar  80  p e r c e nt CF,  t he  L C OE  f o r  PC cases is less  t h an  t he  L C OE  f or  N G C C cases.
W i t h  i n c r e a s ed CR  t he gap in  L C OE  b e t w e en  I G CC cases  a nd  o t h er  t e c h n o l o g i es  n a r r o w s.  F or cases  w i th  C C S.
e v en  at  h i g h er  C F s,  t he  PC  L C OE always  f or  PC cases  r e m a i ns  t he  h i g h e st
Figure  8.  C o st  of  C O ,  A v o i d ed
1 00
90
80
70
60
SO
40
30
20
10
0
^ i
| $ C C - 6 EE
w / C CS
^ i
^ ^H
.  ^ ^ ^ ^ ^ ^ ^ 1
l 6 C C * E < « as
w / C CS
s
^ ^H
^ e  ^ M
^ ^H  ^ ^H
^^H ^^H
^ ^ ^ ^ ^ H  ^ ^ ^ ^ ^ 1
s
H H
H
^ ^H
^^H
^ ^ ^ ^ ^H
I G C C - S h e l l w/  S u b c r i t i c al  PC wf  S u p e r c r i t i c al  PC
C CS  C CS  w t o C CS
^L
' ^^H.
H
^ ^H '
^^H
^ ^ ^ ^ ^ 1
N G C C A d v a n c ed
F-Cla&swTCCS
A ll  c o s ts are  in January 2007 U.S. dol lars.
T h e  L C OE  s e n s i t i v i ty  t o  f u el  c o s ts for  t he cases  w i t h  a nd  w i t h o u t  C CS is  s h o wn  in  F i g i re 10.  T he  s o l id  l i ne is
t he  L C OE  of  N G C C  w i t h o u t  C CS as a  f u n c t i on  of  n a t u r al gas  c o s t  T he  d a s h ed  l i ne is  t he  L C OE  of  N G C C
w i t h  C CS as a  f u n c t i on  of  n a t u r al gas  c o s t  T he  p o i n ts  on  t he  l i n es  r e p r e s e nt  t he  n a t u r al gas  c o st  t h at  v ^ u l d  be
r e q u i r ed  t o  m a ke  t he  L C OE  o f  N G C C  e q u al  t o  t he  r e s p e c t i ve  PC  o r  I G CC  t e c h n o l o g i es  at a  g i v en  c o al  c o s t
T he  c o al  p r i c es  s h o wn  ($ 1.35, $ 1.804,  a nd  $ 2 .2  5 / M M B t u)  r e p r e s e nt  t he  b a s e l i ne  c o st  a nd a  r a n ge  of  ± 25  p e r c e nt
a r o u nd  t he  b a s e l i n e.
W i t h o u t  C C S,  at  t he  b a s e l i ne  c o al  c o st  of $  1 . 8 0 / M M B t u,  t he  L C OE  f o r  PC cases  e q u a ls  t h at  of  N G C C  d s e  at a
n a t u r al gas  p r i ce  of  $ 6 . 1 5 / M M B t u;  a nd  L C OE  f o r  I G CC cases  e q u a ls  t h at  of  N G C C  c a se  at a gas  p r i ce  of  $ 7 . 9 6/
M M B t u.  W i t h  C C S, for  t h e  c o a l - b a s ed  t e c h n o l o g i es  at a  b a s e l i ne  c c ^l  c o st  of $  1 . 8 0 / M M B t u,  t o  be  e q u al  t o  t he
N G C C case,  t he  c o st  of  n a t u r al gas  w o u ld have  t o  be  $ 7 . 7 3 / M M B tu  ( I G CC cases)  a nd  $ 8 . 8 7 / M M B tu  ( PC cases).
Figure 9.  A v e r a ge  L C OE  S e n s i t i v i ty  to Capaci ty  F a c t or
200.0
180.0
160.0
140.0
120.0
100.0
60.0
S0.0
40.0
204)
O.0
• K S C C A V Q.
-IGCC w/CCS Aug.
'PCAvQ.
' P C w / C C S A v g.
•NGCCAvg.
•NGCC w/CCS Avg.
Coal=$1.a04MM8tu
NatiinlG»"$l.raMMBtu
0 10 20 30 40
All costs are in January 2007 U.S. dtritars.
50  60  70
Capacity Factor, %
80  100
O v e r v i e w -7 Overview — Bituminous & Na tur al Gas to Electricity
Figure 10.  L C OE  S e n s i t i v i ty  to  F u el Co s ts
7 8
Natural Gas Price,  $ / H M ^
10
NGCCwtoCCB
NGOCWCCS
•  P C M t f i n l a l S t J S M n ki
• IGCCiirooalatS1.3SAINBli
A PC«/coalitS1.aQftMBlu
A leCCitfGOrislSliQIMMBki
« pciftoriitsusniieki
* i6ccwooaiat$zasAiiehi
A ll costs are in January 2007 U.S. doHars.
Contacts
Julianne M. Klara
Senior Analyst
National Energy Technology Laboratory
626 Cochrans Mill Road
RO.Box 10940
Pittsburgh, PA 15236
412-386-6089
julianne.klara@ned.doe.gov
John  G . W I m er
Systems Analysis Team Lead
National Energy Technology Laboratory
3610 Collins Fenry Road
P.O. Box 880
Morgantown.WV 26507
304-285-4124
john.wimer@netLdoe.gov
R e f e r e n c e:  C o s t  a nd  P e r f o r m a n ce Basel ine  f pr Fossil  E n e r gy  P l a n t s . \ f o l.  I.  D O E / N E T L - 2 0 0 7 / 1 2 8 1, May  2 0 0 7.
Overview 050107
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Janine L. Migden-Ostrander
Consumers' Counsel
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