20080505PacifiCorp FERC 203 Application.pdf

Jeffey K. Larsen
Vice President,
Regulation RECe.iVe.O
c: AlA 8: 51
tlB t\~l - J ttri ....~ ROCKY MOUNTAIN ..~tjØNPOER . ........vlA DIVISION OF PACIACORP \...flt\
201 S. Main Street, Suite 2300
Salt Lake City, UT 84111
[phone]
(801220-3116
May 2, 2008
Idaho Public Utilties Commission
472 W Washington St
Boise, Idaho 83720
Attention:Jean Jewell
Commission Secretay
CASE NO. P AC-E-08-02
RE: PacifCorp - FERC 203 Application
In the Matter of the Application of Rocky Mountain Power for an Accounting
Order to Establish a Regulatory Asset
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Dear Ms. Jewell:
On April 29, 2008, PacifiCorp fied a Joint Application Under Section 203 of the Federal
Power Act for Authorization for Transfer of Control of a Public Utilty and Merger and Request
for Expedited Consideration and Confidential Treatment, in FERC Docket No. EC08-_-000. In
footnote 7 thereof, PacifiCorp committed to share a copy of the public version of the filing (titled
"Volume I of II") with each state public utility commission.
While this fiing at FERC identifies the facility as Chehalis and, therefore, has made this
aspect of the transaction public, the details of the transaction included in the Purchase and Sales
Agreement and other aspects covered under the protective order issued by this commission
remain confdentiaL.
Should you have any questions or comments regarding this matter, please do not hesitate
to contact Ted Weston, at 801-220-2963.
Very truly yours,~IL~Tw.
Jeffrey K. Larsen
Vice President, Regulation
Enclosure
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PacifiCorp
TNA Merchant Projects,'lnc.
Chehalis Power Generating, LLC
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REC!1o
08 HAY"'5 AM 8: 57
und9tisvcf ¡i;
SSION
Docket No. EC8S-_ -000
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
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JOINT APPLICATION UNDER SECTION 203 OF THE FEDERA POWER ACT FOR
AUTHORIZATION FOR TRANSFER OF CONTROL OF A PUBLICUTILITYAND
MERGER AND REQUEST FOR EXPEDITED CONSIDERATIO:Nl\ND
CONFIDENTIAL TREATMENT
.Catherine P. McCarhy
Hugh E. Hiliard
S. Shamai Elstein
Dewey & LeBoeuf LLP
1101 New York Avenue, NW, Suite 1100
Washington, DC 20005-4213
202.986.8000
202.986.8102 Facsimile
catherine.mccarhy(qdl.com
selsteint§dl.com
Andrew B. Young
Wiliam M. Keyser
Kirkpatrick & Lockhar Preston Gates
Ells LLP
1601 K Street, NW
Washington, DC 20006-1600
202.778.9000
202.778.9100 Facsimile
andrew. young(qklgates.com
william.keyser(qklgates.com
, VOLUMEI OF II
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Jeffery B. Erb
Assistant General Counsel
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
503.813.5029
503.813.7252 Facsimile
jeff.erbt§pacificorp.com
Ray Cuningham
Sr. Attorney
SUEZ Energy Nort America, Inc.
1990 Post Oak Blvd, #1900
Houston, TX 77056
713.636.1 980
713.636.1364 Facsimile
ray.cunningham(qsuezenergyna.com
Counsel to PacifCorp Counsel to TNA Merchant Projects, Inc.
and Chehalis Power Generating, LLC.
April 29, 2008
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TABLE OF CONTENTS
.i. Executive Summar .......................................................... .................................. - 2 -
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II. Applicants ...........................................................................................................- 4-
A. Sellers....................................... ............................................................... - 4 -
.B. Purchaser ................................................................................................. - 4 -
III. The.Chehalis Facility ..........................................................................................- 8 -
iv. The Proposed Transaction.........................................................~......................... - 9 -
.V.PacifiCorp Native Load Obligation ..................................................................- 10-
VI. The Proposed Transaction Is Consistent with the Public Interest..................... - 13 -
A.The Proposed Transaction Wil Have No Adverse
Effects on Competition... ........................................... ........ ...... ............. - 13 -.
B. The Proposed Transaction Wil Have No Advere
Effects on Rates .................................................................................... - 27 -
C.The Proposed Transaction Wil Have No Adverse
Effects on Regulation. ................................................. .......................... - 28 -.
D. The Proposed Transaction Wil Not Result in
Cross-Subsidization ............................... .................... ........................... - 29 -
.E.The Proposed Transaction Raises No Reliabilty Concerns ................. - 29 -
VII. Information Required Under Section 33.2 of the
Commission's Regulations............................................................................... - 30 -
A.Exact Names of the Applicants and Their
Principal Places of Business: Section 33.2(a)......;...............................- 30-.
B. Names and Addresses of the Persons Authorized to
Receive Notices and Communications Regarding
This Application: Section 33.2(b)........................................................- 30-.C.Descrption of the Applicants and their Jurisdictional
Facilities: Sections 33.2(c) and (d) ......................................................- 30-
D. Narative Description of Transaction: Section 33.2(e) ........................-30-.E.All Contracts Associated with Transaction: Section33.2(f) ...............- 30-
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Statement that the Proposed Transaction is Consistent
with the Public Interest: Section 33.2(g).............................................. - 31 -
Map of Physical Property: Section 33.2(h)..........................................- 31 -
Other Approvals: Section 33.2(i) ......................................................... - 31 -
Commitments Related to Cross-Subsidization: Section 33.2(j) .......... - 31 -.VIII. Request for Confidential Treatment... ...... .......... ........... ........... ........................ - 31 -
ix. Proposed Accounting Entres under Section 33.5
of the Commission's Regulations ..................................................................... - 32 -
.x.Verifications under Section 33.7 of the Commission's Regulations ................- 34-
XI. Number of Copies under Section 33.8 of the Commission's Regulations .......- 34-
.XII. Request for Expedited Review under Section 33.1 1
of the Commîssion's Reguiations......................................~..............................- 35-
XIII. Conclusion ........................................................................................................ - 36 -
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UNITED STATES OF AMERICA
BEFORE THE
FEDERA ENERGY REGULATORY COMMISSION.
PacifCorp
TNA Merchant Projects, Inc.
Chehalis Power Generating, LLC
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Docket No. EC08- -000
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JOINT APPLICATION UNDER SECTION 203 OF THE FEDERAL POWER ACT FOR
AUTHORIZATION FOR TRASFER OF CONTROL OF A PUBLIC UTILITY AND
MERGER AND REQUEST FOR EXPEDITED CONSIDERATION AND
CONFIDENTIAL TREATMENT.
Pursuant to Sections 203(a)(1) and 203(a)(2) of the Federal Power Act ("FPA"), as
amended, i and Par 33 of the Federal Energy Regulatory Commission's ("FERC" or the."Commission") regulations,2 TNA Merchant Projects, Inc. ("TNA"), on behalf of itself and its
wholly-owned subsidiar, Chehalis Power Generating, LLC ("Chehalis") (the foregoing
collectively, "Sellers"), and PacifiCorp ("Purchaser") (Sellers and Purchaser, collectively,.
"Applicants"), submit this Joint Application ("Application") for Commission approval of a
proposed transaction that wil result in the transfer of control from TNA to PacifiCorp of
.Chehalis and the subsequent merger of Chehalis with and into PacifiCorp ("Proposed
Transaction"). Chehalis, a public utilty under the FP A, is currently a wholly-owned subsidiar
ofTNA. Pursuant to the Proposed Transaction, TNA wil sell and PacifiCorp wil purchase.100% of the issued and outstanding equity interests in Chehalis. Immediately following the
transfer of the equity interests in Chehalis, Chehalis wil merge with and into PacifiCorp and the
.jurisdictional assets owned by Chehalis wil become assets of PacifiCorp.
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16 U.S.C. §§ 824b(a)(l) and (a)(2).
18 C.F.R. Par 33.
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I. Executive Summary
.Chehalis is the owner of a 520 MW, natural gas-fired, electrc generation facility located
in Chehalis, Washington ("Chehalis Facility,,).3 The Chehalis Facilty is interconnected to the
transmission system of the Bonneville Power Administration ("BPA") and is located in BPA's
.balancing authority area. The output of the Chehalis Facilty is curently subject to a call option
agreement with PacifiCorp, entered into on March 1,2008.4
PacifiCorpand TNA entered into a Purchase and Sale Agreement dated Aprilll, 2008.
(the "Agreement"), which sets forth the ters for the sale of Chehalis to PacifiCorp. The
Agreement is attached hereto as Exhibit I in a separate non-public volume to this Application,
.subject to confidential treatment as requested in Par VIII of this Application.
PacifiCorp determined that the acquisition of an ownership interest in the Chehalis
Facilty, which has been in commercial operation since October 2003, and which is a clean-.buring, natural gas-fired plant, equipped with the latest environmental technology, would allow
PacifiCorp to gain access to a reliable, reasonably priced capacity resource. The Proposed
Transaction wil provide capacity that wil satisfy demand associated with PacifiCorp's above-.
average customer growth. For example, capacity from the Chehalis Facility would help offset
the shortfall that recently occurred in relation to PacifiCorp's 2012 RFP, discussed below in Par
.V of this Application.
.3 Throughout the Application, the Chehalis Facility is referred to as a natual gas generation facility.
Technically, the Chehalis Facilty is equipped to bur oil as well. However, the Chehalis Faciltys permits restrct
the use by the Chehalis Facilty of oil as an energy input. Specifically, oil can only be bured when natual gas is
unavailable. Unavailable for this purpose is not an economic term. If the cost of natual gas is higher than fuel oil,
the Chehalis Facility canot switch to buring oil simply because the natual gas is "economically unavailable".
Instead, the Chehalis Facility is prohibited from burnng oil except when natural gas is physically unvailable. Even
if such a circumstance occured, the maximum number of hours the Chehalis Facility can ru in a calendar year
when burning oil is 720 hours per year. Since its commercial operations date, the Chehalis Facility has been
operated exclusively as a natural gas generation facilty.4 See PacifCorp, Docket No. ER97-280 1-020, Notice of Change in Status (fied March 31, 2008).
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As demonstrated herein, the Commission should authorize the Proposed Transaction as
.consistent with the public interest because there are no substantive concerns raised by this
Application. The Proposed Transaction wil not have an adverse effect on competition in any
market, as furter explained below. Applicants are submitting with their application an
.economic analysis prepared by economic consultant Rodney Frame (the "Frame Affdavit") to
support this conclusion. Moreover, the Proposed Transaction wil not have an adverse effect on
rates or regulation, nor cause cross-subsidization of a non-utility associate company or any.pledge or encumbrance of utilty assets for the benefit of an associate company. Finally, the
Proposed Transaction raises no reliabilty concerns that could adversely affect the public interest
.and the Applicants wil comply with any reliability requirements that may become applicable as
a result of the Proposed Transaction.
Accordingly, Applicants respectfully request that the Commission act with its usual.expedition and approve the Proposed Transaction by July 17, 2008. Applicants are seeking a 21-
day notice perod, or shorter. Because the Proposed Transaction wil not have any adverse effect
on rates, regulation, or competition, and raises no cross-,subsidization or reliability concerns, a.
shortened notice perod is consistent with Commission precedent. 5 Consistent with similar
waivers granted in the past, the Applicants are requesting waivers of certain of the Commission's
.Revised Filing Requirements.6
.The Commission routinely allows a notice period of 2 1 days for FP A Section 203 applications such as this
Application. See, e.g., Centrica pic, Docket No. EC08-68, Combined Notice of Filing (issued April 14,2008)
(issuing a notice of FPA Section 203 application with a 21 -day comment period); Puget Energy, Inc., Docket No.
EC08-40, Combined Notice of Filing (issued Feb. 5,2008) (issuing a notice ofFPA Section 203 application with a
2 i -day comment period); Brookfeld Asset Mgmt., Inc., Docket No. EC07-72, Combined Notice of Filing (March
23, 2007) (issuing a notice of FPA Section 203 application with a 2 i -day comment period); Startrans 10, LL C,
Docket No. EC08-33, Combined Notice ofFiling (issued Jan. 10,2008) (issuing a notice ofFPA Section 203
application with a 21 -day comment period).
6 Revised Filng Requirements Under Part 33 of the Commission's Regulations, Order No. 642,1996-2000
FERC Stats. &'Regs., Regs. Preambles ~ 31,1 i 1 at 31,877 (2000), order on reh 'g, Order No. 642-A, 94 FERC
~ 61,289 (2001) ("Revised Filing Requirements" or "Order No. 642").
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II. Applicants
A. Sellers
TNA, a Delaware corporation, owns 100% of the issued and outstanding equity interests
in Chehalis. TNA is an indirect, wholly-owned subsidiar of SUEZ Energy Nort America, Inc.
("SENA"), which, in tu, is a wholly-owned subsidiar of SUEZ S.A. ("SUEZ"). SUEZ, a
French société anonyme, holds ownership interests in a number of energy-related subsidiaries
which internationally engage in: the production, transport and distrbution of electrcity; power
marketing; transportation and distrbution of natural gas; the transport and distrbution of
liquefied natural gas; and the worldwide development and ownership of energy projects. SENA
isa Delaware corporation with headquarers in Houston, Texas, and owns direct and indirect
interests in certain energy facilities within the United States, Canada and Mexico. SENA is the
business unit of SUEZ responsible for managing SUEZ's positions within the energy value chain
in Nort America, including electricity generation and cogeneration, natural gas and liquefied
natural gas, asset-based trading and origination, and retail energy sales and related services to
commercial and industral customers.
B. Purchaser
MidAmerican Energy Holdings Company ("MEHC"), through its subsidiar PPW
Holdings LLC, indirectly holds 100% of the issued and outstanding common stock of
PacifiCorp. Though its subsidiaries, MEHC generates, transmits, stores, distributes and supplies
energy. Berkshire Hathaway Inc. ("Berkshire Hathaway") owns approximately 88.2% of the
common stock ofMEHC. Berkshire Hathaway is a holding company owning subsidiaries
engaged in a number of diverse business activities. Though its interest in MEHC, Berkshire
Hathaway has ownership interests in electrc generation, transmission and distribution facilities.
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Other than through its interest in MEHC, Berkshire Hathaway and its affiliates have no
.controlling interest in electrc generation, transmission or distrbution facilties, or inputs used for
electrc power production or transmission or in fuel transportation facilties.
PacifiCorp, an Oregon corporation with its principal place of business in Portland,.Oregon, is primarly engaged in the business of providing retail electrc service to approximately
1.7 milion customers in six western states: Uta, Oregon, Wyoming, Washington, Idaho and
California. PacifiCorp is regulated by the following state public utility commissions: the Utah.
Public Service Commission ("UPSC"), the Oregon Public Utility Commission ("OPUC"), the
Wyoming Public Servce Commission ("WPSC"), the Washington Utilties and Transportation
.Commission ("WUTC"), the Idaho Public Utilties Commission ("IPUC"), and the California
Public Utilties Commission (IICPUCii).7 Approval of the Proposed Transaction is required from
the Washington Energy Facilty Site Evaluation Council and the UPSC. Furer, PacifiCorp wil.make submittals regarding the Proposed Transaction at the OPUC and the WUTC.
PacifiCorp owns approximately 15,800 miles of transmission lines ranging from 46 kV to
.500 kV and has approximately 10,000 MW of generation capacity from coal, hydro, wind power,
natural gas-fired combined cycles and combustion tubines, and geothermaL. Open access to
PacifiCorp's transmission lines is provided pursuant to PacifiCorp's Open Access Transmission
.Tarff ("OATT") on file with the Commission.s PacifiCorp operates in two balancing authority
areas, PacifiCorp East ("PACE") and PacifiCorp West ("PACW"). As a general matter, PACE
includes PacifiCorp's loads and resources in the states ofIdaho, Utah, and Wyoming,9 while.
.7 Applicants are servng a copy of this Application on each state public utilty commission.
S See PacifCorp, 107 FERC ii 61,318 (2004), on reh 'g, 110 FERC ii 61,072 (2005).
9 PACE also includes PacifiCorp's Cholla generating unit located in Arona and the Big Fork generation
station located in Montaa. Big Fork was in PACW until June 2007.
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PACW includes PacifiCorp's loads and resources in the states of Washington, Montana, Oregon,
and California.
10.
The entire PacifiCorp system, including both balancing authority areas, is controlled from
the System Power Control Center in Portland, Oregon and operated as a single integrated system.
.PacifiCorp operates the integrated system in accordance with operating critera established by the
Western Electrcity Coordinating Council ("WECC"). Furer, PacifiCorp voluntarly adopted a
Market Monitoring Plan in Docket No. EC05- 110-000. PacifiCorp's Market Monitor provides.
independent and imparial monitoring of "generation dispatch ofPacifiCorp and scheduled
loadings on constrained transmission facilties" and reports any anticompetitive behavior to
.FERC and PacifiCorp within 48 hours of its discovery.
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The Commission regulates the wholesale power sales and electrc transmission rates and
services ofPacifiCorp. Among its other FERC rate schedules, PacifiCorp has a market-based.rate schedule on file with the Commission.12 On November 13, 2007, the Commission acceted
PacifiCorp's market power analysis fied on August 27, 2007.13
Within WECC, PacifiCorp's CE Generation, LLC ("CE Generation") affiliatel4 owns the.
52.3 MW Yuma Facilty located in the Arzona Public Serice Company balancing authority
area and 345.7 MW of geotheral generating capacity located in the Imperial Irrgation Distrct
.balancing authority area in California. However, since all ofCE Generation's capacity in WECC
has been contracted to other parties on long-ter bases, it is not considered further in the
analyses herein..
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PACW also includes PacifiCorp's interest in the Jim Bridger generating station located in Wyoming.
MidAmerican Energy Holdings Co., et al., Docket No. EC05- 1 10-000, Application for Approval of
Disposition of Jursdictional Facilties Under Section 203 of the Federal Power Act, at Attachment 2 (Market
Monitoring Plan) (fied July 22, 2005).12 PacifCorp, 79 FERC ii 6 I ,383 (1997).
13 PacißCorp, Letter Order, Docket Nos. ER97-2801-01 7, -019 (Nov. 13,2007).
14 CE Generation is 50% owned by MEHC and 50% owned by TranAlta Corporation.
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PacifiCorp is the only MEHC-owned generation owner engaging in the sale, transmission
or distrbution of electrc energy in PACE, PACW or BPA balancing authority areas. MEHC's
other public utilty subsidiares include Cordova Energy Company LLC ("Cordova") and
MidAmercan Energy Company ("MEC"). Cordova operates the Cordova Energy Center, a611
MW (nameplate) gas-fired generating facility located in Rock Island County, Ilinois (the
"Cordova Facilty"), that is interconnected with the transmission systems of MEC and
Commonwealth Edison Company (the latter of which is integrated into the system ofPJM
Interconnection, LLC). The entire output of the Cordova Facilty is fully-committed under a
multi-year tollng power sales agreement with EI Paso Merchant Energy, L.P.IS The agreement
has since been assigned to a subsidiar of Constellation Energy Group, Inc.
MEC is a combination gas and electrc company located in the Midwest. MEC's retail
electrc service is regulated by the Iowa Utilties Board (tlIUB"), the Ilinois Commerce
Commission ("ICCti), and the South Dakota Public Utilties Commission (tlSDPUCtI). MEC's
retail gas serice is regulated by the ruB, the ICC, SDPUC, and various Nebraska muncipalities.
MEC also provides wholesale requirements service to municipal electrc utilities and
transmission service pursuant to a Commission-approved OA TT. In total, MEC owns or
controls approximately 6,600 MW of generating capacity, including majority ownership in five
of the six jointly owned coal-fired generating stations in Iowa and, in addition, jointly dispatches
capacity owned by cooperative and municipal utility systems.
Nortern Natural Gas Company ("Northern Natural") is a Delaware corporation and an
indirect wholly owned subsidiar ofMEHC and owns an interstate natural gas pipeline system
that reaches from Texas to Michigan's Upper Peninsula. Northern Natural is engaged in the
transmission and storage of natural gas for utilities, municipalities, other pipeline companies, gas
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15 Cordova Energy Co. LLC, 96 FERC ii 61,257 (2001).
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marketers, industrial and commercial users and other end uses. Kern River Gas Transmission
Company ("Ker River) is a Texas geeral parerhip and an indirect wholly owned subsidiar
ofMEHC. Kern River owns an interstate natual gas transportation pipeline system extending
from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and
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California.
III. The Chehalis Facilty
Chehalis is a Delaware limited liabilty company. TNA holds 100% ofthe issued and.
outstanding equity interests in Chehalis. TNA is not affliated with PacifiCorp. As noted above,
the Chehalis Facilty is a 520 MW natual gas-fired power generation facility located in Lewis
County; Washington, and is interconnected with the BPA transmission system in the BPA
balancing authorty ara. It is not díry inteconneced with PacifiCo.16 In May 203, the
Commission granted Chehalis the authority to sell energy and/or capacity at market-based
rates.l? The Commission also accepted Chehalis' cost-based rate schedule for the provision of
reactive power.IS Chehalis was granted Exempt Wholesale Generator status on August 29, 2001
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.in Docket No. EGOl-269.19
The Chehalis Facility
began commercial operations in October 2003. The output of
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Chehalis Facility is currently subject to a call option agreement between SUEZ Energy
Marketng NA, Inc. ("SEMNA "), an indirect subsidiar of SUEZ and affIíate of Chehalis, and
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16 Accordingly, other vertically-owned utilities in the Pacific Nortwest or others outside of the BPA
balancing authority area could have been potential purchasers of
the Chehalis Facilty.
11 Chehalis Power Generation. L.P., Letter Order, Docket No. ER03-717 (May 9,2003).
IS Chehalis power Generation. L.P., 112 FERC' 61,144 (2005) (accepting Chehalis' reactive power rate
schedule in Docket No. ER05-1056, suspending the rate schedule for a nominal period subject to refund and setting
it for hearing and settlement
judge procedures); Chehalis power Generation. L.P., 117 FERC' 61,235 (2006)
(conditionally accepting Chehalis' updated service factor schedule in Docket No. ER06-1548, subject to refud,
subject to the outcome of the pending proceeding in Docket No. ER05- i 056 and subject to a compliance filing);
Chehalis Power Generation. L.P., 123 FERC' 61,038 (2008) (affrming in part and reversing in par, the
Administrtive Law Judge's Initial Decision in Docket No. ER05-1056, and directing Chehalis to fie a revised
reactive power 'rate schedule consistent with the determnation made in the order).
19 Chehalis power Generation, L.P., 96 FERC ii 62,204 (2001).
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PacifiCorp puruant to which, effective as of March 1, 2008, PacifiCorp has the option of calling
upon firm energy from the Chehalis Facility. The term of the agreement is for approximately
nine months but the agreement contains a provision that could allow for its extension. The
paries to the agreement anticipate that this extension wil not be necessar because the Proposed
Transaction wil close once all required regulatory approvals are obtained, prior to the end of the
nine-month ter. The call option agreement was the subject of a Notice of Change in Status
submitted to the Commission on March 31, 2008 in PacifiCorp's market-based rate docket,
Docket No. ER97-2801-020. PacifiCorp plans to submit another Notice of Change in Status to
the Commission withn 30 days of the consumation ofthe Proposed Transaction and possibly
before the Proposed Transactionisconsummated. That analysis wil update the March 31, 2008
submittal, and depending on the outcome of the detailed updated market power analysis, it may
include a mitigation proposal related to certain peak perods.
iv. The Proposed Transaction
In accordance with the Revised Filng Requirements, Applicants have attached the
Agreement as confidential Exhibit I to this Application. Applicants have addressed the
protective order requirements of Section 33.9 of the Commission's regulations20 in Par VIII of
this Application.
The ownership interests in Chehalis immediately prior to the closing of the Proposed
Transaction wil be held directly by TNA. Pursuant to the Agreement, PacifiCorp wil acquire
100% of the equity interests in Chehalis from TNA. Specifically, TNA wil convey its equity
interests in Chehalis directly to PacifiCorp. Immediately following the closing of its transaction
with TNA, PacifiCorp plans to merge Chehalis with and into PacifiCorp pursuant to Delaware's
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20 18 C.F.R. § 33.9.
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short-form subsidiary merger statute.21 The net result is that PacifiCorp wil own the Chehalis
Facilty and an indirect transfer of control over the Chehalis Facility from SUEZ to Berkshire
Hathaway wil have occurred. In addition, the Proposed Transaction wil result in PacifiCorp
becoming the successor in interest to Chehalis for certain contract rights as a customer for
natual gas transportation service, natural gas storage serce and transmission service that relate
specifically to the operation of the Chehalis Facilty (i.e., existing customer rights Chehalis has
for natural gas-related services used to operate the Chehalis Facility and transmission capacity on
BPA's transmission system that Chehalis could use to reach certain delivery points).
V. PacifiCorp Native Load Obligation
PacifiCorp's proposed acquisition of Chehalis is par of a broad strategy for PacifiCorp to
fulfill its load obligations. Customer growt and increasing loads, coupled with environmental
requirements, are driving PacifiCorp to enter into power purchase agreements, invest in new
utilty plants or acquire existing plants, if available. As required by certain state regulations,
PacifiCorp uses an Integrated Resource Plan ("IRP") to develop a long-term view of prudent
futue actions required to help ensure that PacifiCorp continues to provide reliable and cost-
effective electrc service to its customers. The IRP process identifies the amount and timing of
PacifiCorp's expected future resource needs and an associated optimal future resource mix that
accounts for planning uncerainty, risks, reliability impacts and other factors. The IRP is a
coordinated effort with stakeholders in each of the six states where PacifiCorp operates.
PacifiCorp fies its IRP with the UPSC, OPUC, IPUC and the WUTC. The state regulators
review the IRP filings but do not approve them. Rather, the state public utilty commissions
have the abilty to "acknowledge" the IRP filings pursuant to those states' IRP adequacy
requirements.
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21 See DeL. Gen. Corp. Law § 253.
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In May 2007, PacifiCorp released its 2007 IRP. The 2007 IRP identified a need for
.approximately 3,171 MW of additional resources by summer 2016, which included an
incremental peak capacity need of over 2,400 MW by 2012, to satisfy the difference between
projected retail load obligations and available resources. This need would be met by a.combination of demand response and energy efficiency programs, the constrction and/or
purchase of additional generation (including cost-effective renewable energy, combined heat and
power, and thermal generation) and wholesale electrcity transactions..
Pursuant to the IR, PacifiCorp has issued a series of separate requests for proposals
("RFPS"), each of which focuses on a specific category of resources as provided in the IRP. The
.IRP and the RFPs provide for the identification and staged procurement of resources in future
years to achieve load/resource balance. As required by applicable laws and regulations,
PacifiCorp fies draft RFPs with the UPSC, the OPUC and the WUTC prior to issuance to the.market. In February 2007, PacifiCorp filed an RFP (the "2012 RFP") at the UPSC for base load
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supply-side resources capable of delivering energy and capacity in or to PacifiCorp'sNetwork
Transmission system and that fulfills the requirements of being a Network Resource.22 The 2012
RFP sought up to 1,700 MW of additional resources to become available beginning in 2012
through 2014.23 The 2012 RFP was approved by the UPSC and issued to the market in April
.2007.24 In June 2007, proposals from qualifying bidders were received by public utilty
commission-directed independent evaluators. These bids included varous strctures, ranging
from purchase or lease of coal, natural gas, and geothermal power plants to power purchase.
agreements. PacifiCorp initiated negotiations with short-listed bidders in Januar 2008.
22
.PacifiCorp Request for Proposals Base Load Resources (April 5, 2007), available at
. htt://ww.pacificorp.com/ ilelF ile73 793 .doc.23 ¡d. at 7.
24 Pacifi€orp Request for Proposals Base Load Resources (April 5, 2007), available at
htt://ww.pacificorp.com/ ilelF ile73 793 .doc.
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However, the 2012 RFP wil, at most, result in new system resources with total capacity
.substantially less than the amount solicited and thus, the RFP process wil result in a shortfall.
The Proposed Transaction is consistent with the 2012 RFP and wil help offset the shortfall in an
economically effcient maner.25
.Additionally, in Januar 2008, PacifiCorp issued to the market anRFP (the "2008 Small
Renewable RFP") seeking renewable energy from sources less than 100 MW in size or power
purchase agreements with a term of less than five years, to become available prior to December.2009.26 Bidders for the 2008 Small Renewable RFP may submit proposals in the form of a
power purchase or build-own-trsfer agreement. In Februar 2008, PacifiCorp filed an RFP
.(the "2008 All Source RFP") with the UPSC, the OPUC and the WUTC for base load,
interediate or third quarter summer peaking products delivered into PacifiCorp's system.27 The
2008 All Source RFP seeks up to 2,000 MW of resources to become available beginning in 2012.through 2016. Most recently, in response to a change in Utah law, PacifiCorp has begun the
process to issue an additional RFP for renewable energy (the "2008 Large Renewable RFP")
.seeking renewable energy from sources up to 300 MW in size. Bidders for the 2008 Large
Renewable RFP may submit proposals in the form of a power purchase or build-own-transfer
agreement.
.
2S
.PacifiCorp's filings with the OPUC and UPUC fuher detail the connection between the Proposed
Transaction and PacifiCorp's IRP and RFPs. See In re PacifCorp's Petition/or a Waiver o/Competitive Bidding
Guidelines Under Order No. 06-446, UM-1374 (Or. Pub. Util. Comm'n Apr. 1,2008) (stating that the Proposed
Acquisition is necessar to fulfill resource needs not satisfied by the 2012 RFP and is consistent with its IRP); In
re Request o/Rocky Mountain Power/or Waiver o/Solicitation Process and/or Approval o/Signifcant Energy
Resource Decision, Docket No. 08-035-35 (Uta Pub. Servo Comm'n Apr. 1,2008) (stating that the Proposed
Acquisition is necessar to fulfill resource needs not satisfied br-the 2012 RFP and is consistent with its IRP).26 PacifiCorp Request for Proposals Renewable Electrc'Resources (Januar 3 1,2008), available at
htt://ww.pacificorp.com/ ile/ ile79 1 64. pdf.27 All Source--Request for Proposal PacifiCorp (Febru 15, 2008), available at
htt://ww.pacificorp.com/ile/File79544 .pdf.
.
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.
VI. The Proposed Transaction Is Consistent with the Public Interest.Under Section 203 of the FP A, the Commission wil approve a transaction if the
Commission finds that the transaction "wil be consistent with the public interest." In reviewing
transactions under Section 203, the Commission follows a thee-par test set forth in its Inquiry.
Concerning the Commission's Merger Policy under the Federal Power Act: Policy Statement
("Merger Policy Statement"),28 as codified in Section 2.26 of
the Commission's regulations.29
Under this test, the Commission examines the transaction's effects on competition, rates, and.
regulation. In addition, Section 203 also requires the Commission to ensure that a proposed
transaction wil not result in cross-subsidization of a non-utilty associate company or pledge or.encumbrance of utilty assets for the benefit of an associate company. The Proposed Transaction
is consistent with the public interest with respect to each of these factors. In addition, the
.Proposed Transaction raises no concerns regarding reliabilty that would be adverse to the public
interest.
A. The Proposed Transaction Wil Have No Adverse Effects on Competition.In the Revised Filng Requirements, the Commission stated that its concern with respect
to a proposed transaction's effect on competition is to determine whether the proposed
transaction wil "result in higher prices or reduced output in electricity markets. ,,30 The Proposed
Transaction wil have no adverse effect on competition because the Proposed Transaction wil
.
create neither horizontal nor verical market power that raises competitive concers. As noted
.above, Applicants are submitting with their application, Attachment 1 hereto, an economic
28 Order No. 592, 1996-2000 FERC Stats. & Regs., Regs. Preambles ii 31,044 (1996),
order on
reconsideration, Order No. 592-A, 79 FERC ii 61,321 (1997).29 18 C.F.R. § 2.26.
30 Order No. 642 at 31,879.
.
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.
analysis prepared by economic consultant Rodney Frame that is consistent with the
.Commission's requirements in Par 33 of its regulations and its Merger Policy Statement.3!
1. Horizontal Market Power Impacts
As demonstrated in the Frame Affdavit, the relevant geographic markets are PACE,
.PACW, BPA and some of the balancing authority areas that are first tier to PACE, PACW and
BP A. Mr. Frame's analysis focuses on product markets for short-ter or non-firm energy and
also considers the effects of the Proposed Transaction on other markets such as capacity and.
ancilar services. The Frame Affidavit sets out Mr. Frame's conclusions regarding the addition
of the generation capacity from the Chehalis Facilty. In sum, given Mr. Frame's conclusions
.and PacifiCorp's need for additional energy and capacity to satisfy its load obligation, described
above, the Commission should find that the Proposed Transaction wil not raise any horizontal
market power concerns..Pursuant to the Commission's guidelines, Mr. Frame perormed a Delivered Price Test
("DPT") analysis to compute market shares and the changes in year 2008-2009 market
concentration indices resulting from the Proposed Transaction. Mr. Frame used two generation.
capacity measures: (1) Economic Capacity, a measure of total capacity which ignores native and
firm load obligations and is thus of no real relevance to the PacifiCorp market because
..PacifiCorp, like the other vertically-owned public utilities in the Pacific Northwest, stil has a
native load obligation; and (2) Available Economic Capacity, which reflects native load
obligations and thus provides a meanngful measure of the actual competitive situation. In each.
31
.
The Proposed Transaction relates only to generation in the BP A and PacifiCorp balancing authority areas.
It will result in no changes to the results of the Commission's market power tests for the other MEHC consolidated
subsidiaries, Cordova, MEC or CalEnergy. P.s noted above, all of the assets owned or controlled by Cordova and
MEC are in the Eastern Interconnection, electrcally remote from BPA, which is located in the Western
Interconnection. Also, CalEnergy's generation capacity is located remotely and is committed under long-term
contract. Thus; this submittal and the Frame Affdavit focus on the results of the Commission's market power tests
on PacifiCorp only.
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.
.
geographic market analyzed, Mr. Frame computed the Economic Capacity and the Available
Economic Capacity market share and Herfindahl-Hirschman Index ("HHI") statistics for 10
distinct load periods. The results are summarzed in Attachments 6 and 7 to the Frame Affdavit.
Mr. Frame's DPT analysis for PACW is supported by the Affidavit of Thomas N.
Tjoelker, attched hereto as Attachment 6, attesting to the Simultaneous Import Limit values
used by Mr. Frame for the DPT analysis for P ACW.
As described in fuher detail in the Affdavit of Mr. John Apperson, Attachment 2
hereto, PacifiCorp currently plans to integrate the Chehalis Facility into the P ACW balancing
authority area immediately upon consummation of the Proposed Transaction. Mr. Frame's
analysis assumes that such integration wil occur but he also considered whether any adverse
competitive effects would result if unforeseen circumstances arose and the Chehalis Facility was
not integrated into the P ACW balancing authority area. Mr. Frame concludes in his Affidavit, as
further supported by his work papers, that there would be no adverse effect on competition were
the Chehalis Facilty to remain in the BPA balancing authority area following consummation of
the Proposed Transaction.32
a. Available Economic Capacity
As explained in greater detail in the Frame Affdavit, Mr. Frame concludes that the
Proposed Transaction does not raise any competitive concers when the changes in market
concentration are computed for Available Economic Capacity, the generation capacity measure
which takes account ofPacifiCorp's native load obligations. More specifically, when market
share results are analyzed, there are no Available Economic Capacity screen failures for the
transaction induced concentration changes in any destination markets for all 10 seasons and load
.
.
.
.
.
.
.
.
32 Frame Affdavit at 0.38.
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.
level combinations, including P ACW where Chehalis wil be integrated post-transaction. 33
.According to Mr. Frame, this outcome is predictable given PacifiCorp's existing generation
shortfall in PACW under the DPT in comparson to what is required to meet its customer' load
requirements.
.In P ACW, the post-transaction HHIs always falls in the lower portion of the 1,000-1,800
rage that denotes a "moderately concentrated" market under the joint U.S. Deparment of
Justice and Federal Trade Commission Horizontal Merger Guidelines ("Merger Guidelines") that.
the Commission has adopted.34 The transaction-induced HHI changes in P ACW are zero in the
off-peak periods-since the Chehalis Facility is not "in-the-money then" under the DPT's
.procedures-and are either small or negative in the peak periods, resulting in no screen
failures.35 In the other destination markets, the post-transaction HHIs fall into either the
moderately concentrated or unconcentrated Merger Guidelines' ranges and in each instance.result in no screen failures. The largest trsaction-induced Available Economic Capacity HHI
changes, which occur in the BP A and Portland General destination markets and which remain
below the Merger Guidelines' thresholds, occur not because PacifiCorp's market shares increase.
but, instead, because the market shares of a third pary, BP A, increase when the output of the
Chehalis Facilty is integrated into PACW.36
.
33
.
Frame Affdavit at i/54. The absence of any Available Economic Capacity screen failures in either of
PacifiCorp's balancing authority areas distinguishes the Proposed Transaction from both Nevada Power Co., 113
FERC i/ 61,265 (2005) and Westar Energy Inc., 115 FERC i/ 61,228 (2006), where there were screen failures in the
applicants' balancing authority area as a result of the proposed transactions.34 Horizontal Merger Guidelines, Deparent of Justice and the Federal Trade Commission (Revised April 8,
1997), available at htt://ww.usdoj.gov/atr/public/guidelines/hg.htm.3S Specifically, the HHI increases in PACW for the Summer i -2, Winter 1 and Springlall 1 time periods are
2,1,33 and 46, respectively. The HHI decreases that occur for PACW in the Summer 3, Winter 2 and Springlall2
periods result principally from the fact that BPA's relatively large market share decreases very slightly as some of
the Simultaneous Import Limit ("SIL") is used to move the Chehalis Facility to PACW therefore lessening SIL
available to other paries (including BPA). Frame Affdavit at n.34.
36 Under the Available Economic Capacity analysis, PacifiCorp's market share in BPA and Portland General
only increase in the Summer 3 (from 0% to 1.2% and 0% to 4.6%, respectively) and Springlall 2 (from 0% to 1.6%
.
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.
Finally, PacifiCorp's post-transaction market share of Available Economic Capacity in all
.markets remains below 20% in all 10 time perods, with the exception of one off-peak season in
P ACE and two off-peak seasons in the Idaho Power balancing authority area that are unchanged
by the Proposed Transaction (i. e., the Proposed Transaction did not increase or otherwise modify
.these pre-existing percentages). In P ACW, the post-merger market share of Available Economic
Capacity ranges from 0-14.9%.37
b. Economic Capacity.
As Mr. Frame concludes, when the Commission's prescribed energy product definition
fails to consider native load obligations (i.e., Economic Capacity), application of the
.Commission's market power screens to a utilty such as PacifiCorp yields incomplete results
within that utility's balancing authority area because the analysis does not consider the utility's
capacity dedicated to serve native load.38 Mr. Frame's DPT results when Economic Capacity is.measured reflect screen failures within the PacifiCorp balancing authority areas that are
consistent with what would be expected for a utilty obligated to serve native load where its load
exceeds the resources under its control..
In Order No. 642, the Commission emphasized that where a screen failure exists,
applicants are directed to "provide evidence of relevant market conditions that indicate a lack of
.a competitive problem or they should propose mitigation. ,,39 With a limited exception that does
not affect PacifiCorp's capacity obligations, there are no plans at the state level to implement
retail competition with the exception of a limited number of retail access customers in Oregon.
.
and 0% to 3.3%, respectively) time periods and remains substatially below 20% in all 10 time periods ranging from
0% to 9.5% in BPA and 0% to 9.9% in Portland General. Frame Affdavit at Attchment 6.37 PacifiCorp's maket share of Available Economic Capacity furter distinguishes the competitive effects of
the Proposed Transaction from both Westar Energ and Nevada Power, where in one seasan Nevada Power's market
share of Available Economic Capacity was 21% and for Westa, where in one offour seasons analyzed, Westa's
market share of Available Economic Capacity following the proposed tranaction was 42%.38 Frame Affdavit at ~53.
39 Order No. 642 at 3 i ,897.
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under SB1 149, and thus, for the foreseeable future, PacifiCorp will continue to have a native
.load obligation.4o Given PacifiCorp's deficiency of owned generation and reliance on purchased
power, any amount of Economic Capacity it may acquire for the foreseeable future wil be
committed to sere native load durng peak periods and thus canot be used for sales into the
.wholesale market. As such, the Available Economic Capacity measure is a more appropriate
measure of market power than Economic Capacity. As the Commission concluded when
considerng Nevada Power Company's ("Nevada Power") acquisition of a 75% interest in the.
560 MW Silverhawk Power Station from a merchant generator within Nevada Power's balancing
authority area:
.
In (Kansas City Power & Light), we discussed how we evaluate the results of the
Delivered Price Test analysis when utilities dedicate some of their generation
resources to native load. Because of Nevada Power's significant native load
obligation, with no foreseeable prospect of that obligation being lifted, we agree
that Available Economic Capacity is the more relevant measure in the Nevada
Power market and, therefore, should be given more weight.41
.
PacifiCorp's purpose for entering into the Proposed Transaction is to acquire a cost-
effective resource needed to serve PacifiCorp's retail and wholesale customers. The incremental
.capacity being acquired wil not allow PacifiCorp to either withhold generation or foreclose
competitors. PacifiCorp must acquire this capacity to sere its retail and wholesale customer,
and therefore, other resource options - whether it is power purchased under long-term contract, a.
newly built plant, or acquisition of an existing plant - may increase its market shares in a way
40.State regulation in the six states where PacifiCorp operates generally prohibits retail competition.
However, under a 1999 Oregon law, certin PacifiCorp commercial and industral customers in Oregon have the
right to choose alternative electricity suppliers. As a result of this law, a group of customers having a total load of
approximately 12 average MW have chosen service from suppliers other than PacifiCorp. Significantly, however,
PacifiCorp retains an obligation to provide service to these customers and must account for them in its IRP and in
satisfyg it:; load obligations prospectively.41 Nevada Power Co., 113 FERC '161,265 at P 15 (2005) (citation omitted); see also Westar Energy Inc., 115
FERC '161,228 at P 72 (2006) (holding that Available Economic Capacity was more relevant than Economic
Capacity in measurg the competitive effects of Westa Energy's purchase of a generation facilty due to Westa
Energy's obligation to serve native load customers).
.
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.
that would yield the same type of screen failures found in the DPT analysis for Economìc
.Capacity.
The Economic Capacity analysis also reflects screen failures in BP A but these failures
are attrbutable to the increased market share of BP A rather than to any pary to the Proposed.Transaction. The Commission has recognized that the high concentration levels of ownership of
power supply in the Pacific Nortwest are inherently assocìated with BP A's ownership of a large
percentage of the overall Pacific Nortwest generation.42 In other contexts, the Commission has.
noted that the pre-existing high concentration of the BPA market, by itself, should not be an
impediment to entering into transactions subject to prior approval under Section 203.43 Also, the
.Commission has recognized that HHI screen failures attbutable to increases in market shares of
companies that are not paries to a transaction, such as BP A, do not raise concerns that
companies that are parties to a proposed transaction could adversely affect electricity prices or.
output following the consummation ofthe transaction.44 Finally, the "elimination" of Chehalis
as a competitor in the BP A market also does not raise concerns because its relative market share
.of Economic Capacity is so small that Chehalis canot exercise any "competitive discipline" 45
on the BP A market.46
42 Puget Sound Energy, Inc., 107 FERC ~ 61,082 at P 12 (2004) (stating that the main reason that ownership
and control of power supply is highly concentrated in the Pacific Nortwest market is BP A's control of over 60% of
the region's resources); Engage Energy America. UC, 98 FERC ~ 61,207 at61,751 n.13 (2002) (noting high
concentrtion levels were not the result of the proposed tranaction but due to BPA's extensive generation holdings).43 See Puget Sound Energy, 107 FERC ~ 61,082 at P 12 (approving transaction where the increase of
generation would have a de minimis effect on market concentration in a highly concentrted market); Engage
Energy America, 98 FERC at 61,750 (approvig disposition of jursdictional facilities in highly concentrated Pacific
Nortwest market when applicants' increase in market concentration was very small).44 See UtiliCorp United Inc., 95 FERC ~ 61,345 at 62,304 (2001); CP&L Holdings, Inc., 92 FERC ~ 61,023 at
61,054 (2000).4S UtilCorp, 95 FERC at 62,304.
46 See Sierra Pacifc Power Co., 93 FERC ~ 61,217 at 61,723 (2000)-. In the proposed Sierra Pacific -
Portland General transaction, a trsaction never consummated for other reasons, the Commission concluded that
certin screen failures did not raise concerns because they were attbutable to Sierra's pre-existing large market
shae rather thåD the combination of Portland General resources with that capacity. Specifically, FERC concluded
that with repect to the elimination of Portland General as a separate competitor in Sierra's market, "(iJt is unlikely
.
.
.
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.
Other than the BP A screen failures, no screen failures existed for the Economic Capacity
.meaure in first-tier markets, consistent with PacifiCorp's relatively small share of Economic
Capacity in first-tier markets outside its balancing authority area.
c. The Effects of the Proposed Transaction on Capacity and Ancilary
Services Market Raises No Competitve Concerns..
Mr. Frame also considered the effects of the Proposed Transaction on other markets such
as capacity and ancilar serces. As discussed above, PacifiCorp is entering into the Proposed
.Transaction in order to help it meet a pending shortfall of capacity in comparson to its load
obligations.47 As for capacity markets, the Frame Affdavit48 explains that a pary that is
purchasing generation capacity to make up for a current or pending shortfall is not in a position.to exercise market power over sales of capacity. Accordingly, Mr. Frame concludes that the
Proposed Transaction could not create competitive concers in short-term capacity markets.49
.He also adds that the position of a seller in short-ter capacity markets can be approximated by
its generation holdings as measured at peak demand times under the DPT.5o That PacifiCorp is
not likely to be a seller in short-ter capacity markets therefore is reinforced by PacifiCorp's
.PACW shortfall in the highest load perods (i.e., Sumer 1 and Winter 1) and its relatively
modest holdings in PACE (i.e., 267 MW in Winter 1 but 0 MW in Summer 1).5\ From this
perspective, the Proposed Transaction is "deconcentrating" in short-ter capacity markets.
because SUEZ on a pre-transaction basis is more "long" than PacifiCorp is on a post-transaction
.thatPGE's presence in the Sierra market (a 1.2% market share) provided any significant price discipline prior to the
merger." Id.47 Using a 12% planning reserve margin, PacifiCorp has a net "long" (i.e., resources that exceed load
obligation plus reserves) of i 13 MW for 2008 but forecasts a 791 MW deficit by 2010. Using a 15% planing
reserve margin, PacifiCorp has a net shortfall of 147 MW for 2008. Frame Affdavit at 116 i.48 Frame Affdavit at 1166.49 Id.so Id.51 Id..
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basis. Accordingly, Mr. Frame concludes that there should be no realistic concerns about post-
.transaction competitive problems in short-term capacity markets.52
The Frame Affidavit also explains that investigationsoflong-ter capacity markets
generlly focus on "entry barers." Mr. Frame notes that the entr barer expression, when used
.in conjunction with construction of new generation capacity, sometimes is used to refer to
control of electrc transmission systems, control of fuel supplies or control of fuel transport
facilties such as natural gas pipelines that might be used to thwart competition in generations. 53.
The Proposed Transaction does not involve any entr barers, wil not create any new barrers
and wil not enhance any barers that may exist. Thus, Mr. Frame concludes that the Proposed
.Transaction does not adversely affect competition in long-ter capacity markets. 54
As for the ancilar servces market, the Commission's guidelines for assessing the
competitive effects of proposed acquisitions of jurisdictional facilties require an assessment of.the effects of a proposed transaction on ancilar serices markets where the data to perform
such an analysis are available. 55 In this case, Mr. Frame concluded that the necessary data,
.including ancilar service capability of individual generators, are not available.
56 However,
given (1) the relatively small effect of the Proposed Transaction on market concentration as
measured using the DPT, (2) the small size of the Chehalis Facilty in comparison to the BPA
.market where it is located and (3) that there are ready and obvious alteratives for ancilary
serices in the BP A market, Mr. Frame concludes that it is simply not plausible that the Proposed
.
.
52
53
54
55
56
Id.
Frame Affdavit at iJ67.
Id.
Order'642 at 3 i ,884.
Frame Affdavit at iJ68.
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.
.
Transaction wil present the opportnity for adverse competitive effects in ancilary services
markets.
57
d. When the Larger Pacifc Northwest Market is Examined, the Proposed
Transaction Raises No Horizontal Market Power Issues.
.As noted above, the Frame Affdavit examines those markets that the Commission has
required applicants to examine in the Section 203 context and finds no competitive concers.
However, the Frame Affidavit also includes the results of Mr. Frame's examination of the
.competitive effect of the Proposed Transaction on the larger Pacific Northwest market. He
concludes that no competitive issues arise when considerng the effect of the Proposed
Transaction on the larger Pacific Nortwest market..
Specifically, Mr. Frame examined historical data on sales made by Chehalis and
PacifiCorp to determine ifPacifiCorp's acquisition of the Chehalis Facilty suggests any
.concerns about undue market concentration based on that data. Mr. Frame used historical sales
data to quantify both the total market size and PacifiCorp's portion of short-ter sales (defined
as transactions up to a year in duration) at the Mid-C, COB and NOBhubs.58 Mr. Frame.presents MWh volumes and percentage shares for each ofPacifiCorp and the Chehalis Facilty
on a month-by-month basis for 2007 as well as changes in market concentration determined
.using the "2 x a x b" approach.
59 The computations separately cover all days in this time period
and only those days when the Chehalis Facility actually operated.
.57
58
.
¡d.
Míd-C ís a líquid tradíng hub ín the Pacífic Nortwest where, accordíng to EQR filíngs, víally all of the
output from the Chehalís Facílity has been sold ín recent years.PacífiCorp has also been an actíve market
parcípant at Mid-C. COB (for Calífomia-Oregon border) and NOB (for Nevada-Oregon border) are other tradíng
hubs ín the Pacífic Nortwest, although wíth hístorical volumes far below those at Míd-C. A small portíon of the
output from the Chehalís Facilíty has been sold at COB ín recent years whíle PacífiCorp has made sales at both
COB and NOB.S9 Horizontal Merger Guidelínes, Deparent of Justíce and the Federal Trade Comiíssion at n.l 8 (revísed
Apríl8, 1997), avaílable at htt://ww.usdoj.gov/atr/public/guidelines/g.htm.
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.
Mr. Frame's larger Pacific Northwest market analysis indicates relatively low market
.shares for each of PacifiCorp and Chehalis and low transaction-induced HHI changes as a result
of the Proposed Transaction. When all days are considered in the analysis, the PacifiCorp
market shares average 4%, those for the Chehalis Facility average 2%, and the transaction-
.induced HHI changes average 12.60 When only days when the Chehalis Facility was operated
are considered, PacifiCorp market shares average 4%, those for the Chehalis Facility average
2%, and the transaction-induced HHI changes average 17.61 Mr. Frame concludes that even.these minimal transaction-induced HHI changes overstate the impacts of the Proposed
Transaction because they do not consider that, on most days in this time period, PacifiCorp was a
.net buyer, not a net seller, in the markets examined, and therefore would not likely benefit from a
transaction-induced price increase anyway. 62 Mr~ Frame also included in his workpapers
additional analyses that expand the range of Pacific Nortwest trading points beyond just Mid-C,.COB and NOB. He concludes that the results therein are little different from those shown in the
analysis for Mid-C, COB and NOB.63
2. Vertical Market Power.
The Proposed Transaction similarly raises no verical market power concerns. Other than
certain rights and assets related exclusively to the operation ofthe Chehalis Facilty, PacifiCorp
.wil not acquire any natural gas production, transportation or storage facilities or any other
essential facilities for electric power production as a result of the Proposed Transaction.64
.60
.
Frame Affdavit at ~63.
Id.
Id.
Id. at ~62.
As mentioned above, the Propos~d Transaction wil result in PacifiCorp becoming the successor in interest
to Chehalis for certain contract rights as a customer of natual gas transporttion service, natural gas storage service
and transmission service that relates specifically to the operation of the Chehalis Facility (i.e., existing cusiomer
rights Chehalis 'had for natual gas-related services used to operate the Chehalis Facility and transmission capacity
on BPA's transmission system Chehalis could use to reach certin delivery points). In addition, PacifiCorp will also
62
63
64
61
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.
Also, the Proposed Transaction does not involve the acquisition or transfer of control over any
.transmission or transportation facilties, either electrc or natual gas, other than the Chehalis
Facilty's interconnection facilties, which are facilities used only to transmit the Chehalis
Facilty's electrical output to the interstate transmission grd.65 Therefore, no interests in
.essential facilities for electrc power production or transmission facilities wil be affected by the
Proposed Transaction that would raise verical market power concers.
PacifiCorp continues to operate its transmission facilities pursuant to an OATT on file.
with the Commission. The Commission has held many times that having such a tarff on fie
adequately mitigates any transmission market power.66 Additionally, PacifiCorp and its affliates
.have not erected and wil not erect any barers to entr into the relevant markets. The Proposed
Transaction is an ars-length transaction between non-affliates and raises none of the affiliate
"safety net" concerns regarding the possible creation of barers to entry for merchant generation.investment that arose in Ameren or Cinergy.67 In addition, because the Chehalis Facility is not
.
interconnected with PacifiCorp, any competitive concers regarding the ability to exit the
industr also do not arise.68 Also possibly relevant to an analysis of barrers to entry is that
.acquire a lateral pipeline owned by Chehalis that is used exclusively to ship natual gas from the interstate natural
gas pipeline to the Chehalis Facility. The location and characteristics of the lateral pipeline prevent it from being
used for any other purose.6S These interconnection facilities include but are not limited to the related substation.
66 See Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancilary Services by Public
Utilties, Order No. 697, II FERC Stats. & Regs., Regs. Preambles' 3 i ,252, order on clarifcation, i 2 i FERC'
6 i ,260 at P 2 i (2007).67 See Ameren Energy Generating Co., i 08 FERC , 6 i ,08 i (2004); Cinergy Services, Inc., i 02 FERC ,
6 i, i 28 (2003). In Ameren and Cinergy, the Commission expressed concerns that a franchised utilitys ability to
acquire affliated merchant generation when market demand declined could give such an affiliated merchant
generation company a "safety net" that merchant generators not affiliated with a franchised utility did not have. The
Commssion expressed concern that the existence of the safety net could affect the incentive of new merchant
generators seeking to invest in new facilties erecting a "barer to entr" that hars the competitive process and
raises prices to customers in the long run because affliated merchant generation with a safety net option would not
be subject to the price discipline of a competitive market. The Proposed Tranaction does not present this issue.68 See Ameren, i 08 FERC '6 i ,08 i n. 61.
.
.
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.
PacifiCorp is not the local distrbution company for the provision of natual gas services in the
.P ACW or BP A balancing authority areas.
PacifiCorp is actively engaged in regional transmission planing initiatives with other
transmission owners in the Western Interconnection. In the Wester Interconnection, regional
.planing has evolved into a two-tiered approach where WECC, an interconnection-wide entity,
conducts regional planing at a ver high level and several sub-regional planing groups focus
with greater depth on their specific areas. In brief, WECC's role in meeting the region's need for.
regional economic transmission planing and analyses is to provide imparial and reliable data,
public process leadership, and analytical tools and serices.
.On the sub-regional level, PacifiCorp is a member of the Nortern Tier Transmission
Group ("NTTG"), formed in late 2006 to faciltate regional planing and develop consistent sub-
regional and regional coordination efforts. NTTG consists of a coalition of investor-owned and.public utilties, state governent agencies, transmission customers, and other stakeholders.
NTTG coordinates individual transmission systems operations, products, business practices, and
.planing of their high-voltage transmission network to meet and improve transmission services
that deliver power to consumers. As PacifiCorp has previously stated, NTTG's Planing
Agreement provides the framework for efficient and coordinated planing and expansion of the
.multi-state transmission system within the members' collective serice terrtories.
69
PacifiCorp remains responsible for maintaining its transmission system and planing for
transmission and generator interconnection serice pursuant to its DATT and other agreements..PacifiCorp also retains the responsibilty for the local planing process. PacifiCorp's planing
.69 Deseret Generation & Transmission Coop.. Inc., et al., Docket No. OA08-54-000 (fied Nov. 30,2007).
Sellers do not take a position with respect to PacifiCorp's planned transmission projects or NTG's Planning
Agreement.
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process, as detailed in Attachment K to its OATT, includes all of the relevant requirements of
Order No. 890.70.
In addition to increasing its generation portfolio to meet futue customer load growth,
PacifiCorp, in May 2007, entirely separate and apar from the Proposed Transaction, anounced
.plans to build its Energy Gateway Transmission Project, which includes two major 500 kV
trnsmission lines - Gateway South and Gateway West - with supplemental projects to meet
commitments and accommodate regional needs and customer requests. As proposed, the.
projects are a "hub and spoke" design and wil add more than 1,700 miles of new transmission
lines originating in Wyoming and connecting into Utah, Idaho, Oregon and the Southwest. The
.more than $4 bilion project is planed for completion in 2014. In addition to supporting
customer growt and improving system reliabilty, these projects are also aimed at deliverng
wind and other renewable generation resources to more customers throughout PacifiCorp's six-.state serice area and the Western region.
The new lines wil be the first major projects built under the oversight ofNTTG. NTTG
wil manage the public input process. PacifiCorp wil also be working with WECC and other.
subregional groups, including, the Northwest Transmission Assessment Committee,
ColumbiaGrid, and WestConnect, to ensure public and regional coordination is par of the
.process. PacifiCorp also continues to be an active paricipant in other regional transmission
projects.
.70
.
Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, II FERC Stats.
& Regs., Regs. Preambles' 31,131, order on reh'gand clarifcation, Order No. 890-A, II FERC Stats. & Regs.,
Regs. Preambles' 31,261 (2007). The requirements of Order No. 890 include: (1) the process for consulting with
customers and neighborig transmission providers; (2) the notice procedures and anticipated frequency of meetings;
(3) the methodology, criteria and processes used to develop transmission plans; (4) the method of disclosure of
criteria, assumptions and data underlying trsmission system plans; (5) the obligations of and methods for
customers to submit data to the transmission provider; (6) the dispute resolution process; (7) the transmission
provider's study procedures for economic upgrades to address congestion or the integration of new resources; and
(8) the relevant cost allocation procedures or principles.
- 26-.
.
3. Transactions Such As the Proposed Transaction Encourage
Investment in Merchant Generation.When merchant generating companies undertake the risk of developing and constrcting
new generating assets, they frequently plan to consider engaging in some form of transaction
.prospectively to minimize the merchant risk in the facility. A merchant generation company
would want the opportity to diversify its risk though any form of transaction that would be
commercially reasonable including, but not limited to, futue sale of the asset or entering into a
.long-term power sales agreement. A sale option provides immediate funds that could be used for
additional infrastrcture investment by a merchant generator. In that respect, a sale option is
unlike a power sale agreement, which would allow recovery of investment in plant over time..
Depending on the facts and circumstances, a sale option agreement could be a better option for a
merchant generating company. Thus, transactions such as the Proposed Transaction encourage
.investment in merchant generation.
B. The Proposed Transaction Wil Have No Adverse Effects on Rates
Under the Merger Policy Statement, the Commission examines whether existing.wholesale sales and bundled transmission customers wil be protected from adverse rate impacts
under the proposed transaction.71 PacifiCorp hereby makes a "hold harless" commitment that
it wil not seek to include transaction-related costs in excess of transaction savings in its cost-.
based energy and/or capacity rates (including its reactive power rates) or filed transmission
revenue requirements for a period of five years after the Proposed Transaction is consummated..The Commission has approved this type of commitment in its Merger Policy Statement and in a
number of subsequent cases.
.
71 Merger Policy Statement atJO,1 1 1-12.
- 27-.
.
PacifiCorp and Chehalis are both authorized to sell power at market-based rates. Those
.rates wil not be affected by the Proposed Transaction and do not raise concerns for purposes of
an analysis of the Proposed Transaction's adverse effect on rates.72 PacifiCorp's existing cost-
based wholesale power sales customers are served pursuant to fixed cost-based rates rather than
.formula rates.73 These fixed rate contracts include provisions that do not allow PacifiCorp to
increase its rates for sales to these wholesale cost-based customers without making a Section 205
filing with this Commission..
In addition, Chehalis and PacifiCorp have entered into the call option agreement
discussed above and PacifiCorp is the only curent power sales customer of Chehalis. Chehalis
.has a cost-based reactive power rate schedule that wil be transferred to PacifiCorp as par of the
Proposed Transaction. However, because the rates for service under that rate schedule are based
on Chehalis' costs (and not the seller's company-wide costs) the Proposed Transaction wil not.affect the rates for service under that rate schedule.
c. The Proposed Transaction Wil Have No Adverse Effects on Regulation
With the exception of Chehalis, the Proposed Transaction wil not have any effect on the.
maner or extent to which the Commission, any state, or any other federal agency may regulate
the Applicants. As noted above, Chehalis wil merge into PacifiCorp. Thus, FERC wil no
.longer regulate Chehalis as a public utility following the Proposed Transaction. However, FERC
wil stil continue to regulate the relevant jurisdictional assets owned by Chehalis after the
72.FERC has previously indicated that consideration of a public utility's market-based rate authority is
relevant to the Section 203 analysis concerning the effect of a proposed transaction on rates. See NorAm Energy
Services, Inc., 80 FERC ii 61,120 at 61,382-83 (1997) (stating that the Commission's ratepayer protection concerns
do not apply to customers charged market-based rates); Enron Corp., 78 FERC ii 61,179, at 61,738 (1997) (asserting
that the Merger Policy Statement requires consideration of the effect of the proposed merger on a company's
wholesale customer rates; however, since the public utility affliates at issue only made sales under their market-
based rate schedule, no concerns were raised that were relevant to this discussion).73 The Applicants recognize the distinction between the Commission's analysis' of rate effects in the Section
205 context and the Section 203 context, see Startrans 10, L.L.c., 122 FERC ii 61,307, P 25 (2008), but are
providing ths information because it might provide fuher support for a conclusion of no adverse effect on rates.
.
- 28-.
.
.
merger with PacifiCorp. PacifiCorp wil continue to be regulated by FERC and the various state
public utilty commissions noted above. Accordingly, neither state nor federal regulation of the
Applicants wil be adversely impacted by the Proposed Transaction.
D. The Proposed Transaction Wil Not Result in Cross-Subsidization
See Exhibit M.
E. The Proposed Transaction Raises No Reliabilty Concerns
The Proposed Transaction also raises no reliabilty concerns that could adversely affect
the public interest. As the Apperson Affidavit, Attachment 2 hereto, explains, ifPacifiCorp
chooses to integrate the Chehalis Facility into the P ACW control area, ths should not adversely
affect reliability in either the BP A balancing authority area or the P ACW balancing authority
area. PacifiCorp has integrated other resources from remote balancing authority areas to its own
balancing authority areas and is not aware that this has ever raised reliabilty concers related to
its own balancing authority areas or the balancing authority areas of others. As Mr. Apperon
explains, appropriate notice wil be provided to reliabilty authorities. In addition, PacifiCorp
and Chehalis commit to comply with any reliabilty requirements that may become applicable as
a result of the Proposed Transaction, including but not limited to any Wester Electricity
Coordinating Councilor Nort Amercan Electric Reliabilty Corporation requirements.
In fact, the Proposed Transaction may actually benefit reliabilty. PacifiCorp intends to
rely on the output of the Chehalis Facility, in par, to support its owned and purchased wind
generation capacity.
.
.
.
.
.
.
.
.
- 29-.
.
VII. Information Required Under Section 33.2 of the Commission's Regulations
.A. Exact Names of the Applicants and Their Principal Places of Business:
Section 33.2(a)
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232.
TNA Merchant Project, Inc.
1990 Post Oak Boulevard, Suite 1900
Houston, Texas 77056-3831
Chehalis Power Generating, LLC
1813 Bishop Road
Chehalis, W A 98532
B. Names and Addresses of the Persons Authorized to Receive Notices and
Communications Regarding This Application: Section 33.2(b).
.
Catherne P. McCarhy
S. Shamai Elstein
Dewey & LeBoeuf LLP
1101 New York Avenue, NW, Suite 1100
Washington, DC 20005-4213
202.986.8000
202.986.8102 Facsimile
catherne.mccarhy(qdl.com
selstein(qdl.com.
Counsel to PacifCorp
.
Andrew B. Young
Wiliam M. Keyser
Kirkpatrck & Lockhar Preston Gates
Ells LLP
1601 K Street, NW
Washington, DC 20006-1600
202.778.9000
202.778.9100 Facsimile
andrew.young(qklgates.com
wiliam.keyser~lgates.com
Counsel to TNA Merchant Projects. Inc.
and Chehalis Power Generating, LLC
C. Description of the Applicants and their Jurisdictional Facilties: Sections
33.2(c) and (d)
.See Pars I-II, above, and Exhibits A-G hereto.
D. Narrative Description of Transaction: Section 33.2(e)
See Par IV, above, and Exhibit H hereto.
.E. All Contracts Associated with Transaction: Section 33.2(t)
The agreement between the Applicants is memorialized in the Agreement, provided
hereto as Exhibit I in Volume II to this Application. Applicants respectfully request waiver of
.
.- 30-
.
18 C.F.R. § 33.2(f) to the extent it requires the inclusion of
the purchase and Sale Agreement's
.schedules and attachments.
F. Statement that the Proposed Transaction is Consistent with the Public
Interest: Section 33.2(g)
.See Par VI, above.
G. Map of Physical Property: Section 33.2(h)
See Exhibit K hereto. Exhbit K depicts the Chehalis Facilty in relation to other.PacifiCorp owned or controlled resources and transmission facilties.
H. Other Approvals: Section 33.2(i)
See Exhibit L hereto..
I. Commtments Related to Cross-Subsidization: Section 33.20)
See Exhibit M hereto.
.VIII. Request for Confidential Treatment
Applicants seek to protect the Agreement from public disclosure pursuant to Sections
33.9 and 388.112 of
the Commission's regulations.74 The information contained in the
Agrement, atached as Exhibitlto this Application (including but not
limited to the schedules
theret) and contaned in a separte confidential volume, is of a senitive commerial natu and
the prouct of an's-lengt negotiations. As such, public disclosu could impee the abilty of
the paries to the Proposed Transaction to engage in any future transactions of a similar nature
with other paries. Applicants have provided as Attachment 5 to this Application a draft
.
.
.protective order applicable to viewing the Agreement.
.
74 18 C.F.R. §§ 33.9 & 388.112.
- 31 -.
.
Applicants also seek to protect cerain portions of Mr. Frame's workpapers from public
.disclosure pursuant to Sections 33.9 and 388.112 of the Commission's regulations.75 The non-
public CD-ROM of Mr. Frame's workpapers, included as par of Volume II of the Application, is
of a sensitive commercial nature and contains confidential commercial and operational data, and
.propriety computer programs that the MidAercan Companies and their consultant consider to
be "commercial.. information obtained from a person (that is) privileged or confidentiaL.."
ix. Proposed Accounting Entries under Section 33.5 of the Commission's Regulations.
Pursuant to Section 33.5 of the Commission's regulations,76 proposed accounting entries
for the Proposed Transaction are provided in Attachment 3. Specifically, PacifiCorp is providing
.the pro forma accounting entres for the proposed accounting of the Proposed Transaction on its
books. Under the guidance of Electrc Plant Instruction 5, Electrc Plant Purchased or Sold, "the
costs of acquisition, including expenses incidental thereto" shall be charged to Account No. 102.(Electrc plant purchased or sold). The total cost of the Proposed Transaction wil include the
purchase price as set forth in the Purchase and Sale Agreement provided in Volume II ofthe
Application, as well as appropriate includible costs allowed under Electric Plant Instruction 5.
("Acquisition Cost"). As proposed, the amount to be included in PacifiCorp account 102 wil
represent the portion of the Acquisition Cost that is allocable to the Chehalis Facility rather than
.the original cost less depreciation recorded by Chehalis for the Chehalis Facilty. The amount
allocable to the plant wil be determined based on the relative values of all the assets acquired
and liabilities assumed in accordance with US GAA 77. The proposed accounting entres reflect.
7S
76
.
18 C.F.R. §§ 33.9,388.112.
18 C.F.R. § 33.5.
Financial Accounting Stanàards Board, Statement of Financial Accounting Standards No. 141, Business
Combinations, states that "Following the process described in paragraphs 36-46 (commonly referred to as the
purchas price allocation) an acquirg entity shall allocate the cost of an acquired entity to the assets acquired and
liabilties assumed based on their estimated fair values at the date of acquisition."
77
- 32-.
.
PacifiCorp's current expectation of the manner in which the Proposed Transaction ultimately wil
.be recorded for accounting puroses.
PacifiCorp is not aware of any binding Commission precedent regarding whether a
merchant generator making sales at market-based rates is considered to be "devoted to utilty.
servce" for purposes of the Uniform System of Accounts ("USofA,,)78 and therefore whether its
original cost is required to be entered into Account No. 102. In at least one case involving
.another utilty in the Pacific Nortwest and its acquisition of an interest in a merchant generation
facilty, Commission Staff, by delegated authority, determined that such a facility has not been
"devoted to public service.,,79 PacifiCorp is also aware that Commission Staff, under delegated
.authority, has made a different determination in at least two other cases, but it appears that in
those cases the applicant did not provide a justification for its proposed accounting treatment. 80
The Chehalis Facility was placed into service originally by Chehalis as a merchant.generator and never included in cost-of-servce rate base. When the Commission approved
Chehalis' market-based rates, the Commission granted Chehalis a waiver from Par 101 of the
.Commission's regulations, which establishes the USofA for public utilities.8! Accordingly, the
original purchase price paid for the Chehalis Facility has not previously been recorded in the
USofA. PacifiCorp understands that the purpose of the original cost requirement set forth in.
78
.
18 C.F.R. Par 101, Electric Plant Instrction 2(A) ("All amounts included in the accounts for electrc plant
acquired. . . shall be stated at the cost incurred by the person who first devoted the propert to utility service."); see
also Electrc Plant Instrction 5(A) ("When electric plant constituting an operating unit or system is acquired. . . the
costs of acquisition, including expenses incidental thereto. . shall be charged to account i 02 . . .. The original cost
of plant. . . shall be credited to account i 02 . . . and concurrently charged to the appropriate electrc plant in service
accounts. . ."); Definition 23 ("Original cost, as applied to electrc plant, means the cost of such propert to the
~erson first devoting it to public service.").
9 Puget Sound Energy, Inc., Letter Order, Docket No. AC05-34 (April 6, 2005) (accepting joural entr of
the purchase price consistent with Electrc Plant Instrction 2(A) where the "generating facility was not previously
devoted to public service.").80 See, e.g., Entergy Corporation, Letter Order, Docket Nos. AC06- i 9-000, et at. (Februar 2., 2007)
(involving a situation in which the purchase price was substantially less than the original cost net of depreciation);
American Electric Power, Letter Order, Docket No. AC06-161-000 (Februar 2,2007).
81 Chehalis Power Generation, L.P, Letter Order, Docket No. ER03-717 (May 9,2003).
.
- 33 -.
.
Electrc Plant Instrction 2(A) is to ensure that captive customers who pay cost-based rates for
.electrc energy do not pay twice for depreciation of the same asset (once prior to the original
owner of the facility and a second time to the second owner).82 In this case, however, no captive
customers have previously paid for electric energy from the Chehalis Facilty at cost-based rates,
.so the policy concern behind Electric Plant Instrction 2(A) does not apply. Applicants
respectfully request, therefore, that the Commission consider and accept its proposed accounting
entres for the Proposed Transaction, consistent with its treatment ofPuget Sound Energy, Inc., a.
similarly situated applicant in similar circumstances in Docket No. AC05-34.
.
X. Verifications under Section 33.7 of the Commission's Regulations
Pursuant to Section 33.7 of the Commission's Regulations,83 verifications on behalf of
Sellers and Purchasers are included as Attachment 4 to this Application.
.XI. Number of Copies under Section 33.8 of the Commission's Regulations
Pursuant to Section 33.8 of the Commission's regulations,84 Applicants are submitting an
original and eight copies of this Application. Five of those copies wil be Volume I, which is the
public volume, and thee copies of the copies wil be Volume II of this Application, which.
contains confidential Exhbit I, the non-public version of the Frame Affidavit, and the non-public
CD-ROM of Mr. Frame's workpapers. The contents of Volume II and the CD-ROM are marked
."Contains Privileged and Confidential Protected Materal - Do Not Release."
.
.
82 See Illnois Power Co., 51 F.P.C. 2179 at 2188-89 (1974) ("(tJhe Commission has consistently required
payments for acquisition of utility propert in excess of original cost to be accounted for below the line whether the
form of acquisition ;8 by purchase, or by lease. As Staff points out, the reason for the policy is simply that the
customers or users of propert devoted to public servce should not have to pay for it more th once.") (citing
Carolina Power & Light Co., 40 F.P.C. 1122, 1123 (1968)).83 18 C.F.R. § 33.7.
84 18 C.F.R. § 33.8.
- 34-.
.
.
XII. Request for Expedited Review under Section 33.11 of the Commission's Regulations
Pursuant to Section 33.11 of the Commission's regulations,85 Applicants respectfully
request that the Commission act on this Application with its usual expedition. Specifically,
Applicants respectfully request that the Commission grant a notice period of no more than 21
days and issue an order approving the Proposed Transaction on or before July 17, 2008.
.
.
.
.
.
.
.
.
85 18 C.F.R. § 33.11.
- 35 -.
.
.
XIß. Conclusion
Applicants respectfully request that the Commission approve the Proposed Transaction as
consistent with the public interest puruant to Section 203 ofthe FPA and grant all waivers.
requested in this Application and all other waivers necessar for such approvaL.
Respectfully submitted,
.
Andrew B. Young
Wiliam M. Keyser
Kirkpatrck & Lockhar Preston
Ells LLP
1601 K Stret, NW
Washington, DC 20006-1600
202.778.9000
202.778.9100 Facsimile
8 YOUtÆ~ ~,~ f? M-(fØ1c f r Catherne P. McCary 7 .
Hugh E. Hiliard
S. Shamai Elstein
Dewey & LeBoeuf LLP
1101 New York Avenue, NW, Suite 1100
Washington, DC 20005-4213
202.986-8000
202.986-8102 Facsimile
.
.
Jef B.
ssistant eneral Counsel
PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232
503.813.5029
503.813.7252 Facsimile
.
Ray nningham
Sr. ttomey
SUEZ Energy North America, Inc.
1990 Post Oak Blvd, #1900
Houston, TX 77056
713.636.1980
713.636.1364 Facsimile
.Counsel to TNA Merchant Projects. Inc.
and Chehalis Power Generating, LLC
Counsel to PacifCorp
Dated: Apri129,2008
.
.
36.
.
.
.
See Part II of this Application. Applicants have provided the information to be included
in Exhibit A in Par II of this Application and therefore request a waiver of the requirement to
file Exhibit A. Such a waiver is consistent with Commission precedent. 86
.
.
.)
.
.
.
.
86 See Gen. Elec. Capital Corp., 115 FERC' 62,024 (2006).
A-I.
.
EXHIBITB
ENERGY SUBSIDIARIES AND AFFILIATES OF APPLICANTS.
.
See Part II of the Application for information on Purchaser's energy subsidianes and
affiliates. Applicants request a waiver of this requirement to the extent it applies to Seller, as
Sellers and their affiliates will no longer be affiiated with the Chehalis Facility as a result of the
Proposed Transaction. Such a waiver is consistent with Commission precedent.87
.. '
.
.~
.
.
.
.
87 See Gen. Elec. Capital Corp., 1 is FERC' 62,024 (2006).
B-1.
.
EXHIBITC
ORGANIZATIONAL CHARTS.
.
The organizational charts contained in Exhibit C to this Application reflect the location of
Chehalis in Sellers' and Purchaser's corporate strctues before and after the closing of the
Proposed Transaction, respectively. These organizational chars depict only the relevant
companies of Applicants and do not include all energy subsidiares and energy affliates of
Applicants.
Applicants respectfully request that the Commission waive the requirements of Section
33.2(c)(3) of its regulations, 18 C.F.R. § 33.2(c)(3), to provide organizational charts depicting all
energy subsidiares and energy affiliates. In support of their waiver request, Applicants note that
the Proposed Transaction, due to its limited natue, wil not affect Applicants' corporate
structures other than to remove Chehalis from Sellers' corporate strcture and merge it into
Purchaser's corporate structure.
.
.
.
.
.
.
.
C-1.
.
Exhibit C-l: Organizational Structure Prior to Closing
.
.
SUEZ, S.A.
Electrabel S.A.
SUEZ- Tractebel S.A
SUEZ Energy Nort
America, Inc.
TNA Merchant Projects,
Inc.
Chehalis Power
Generating, LLC
.'
.
.
.
.
.
.
.
C-2.
.
Exhibit C-2: Organizational Chart After the Proposed Transaction
.(Including Acquisition of Chehalis and Merger of Chehalis With and Into PacifiCorp)
.Berkshire Hathaway Inc
MidAmerican Energy
Holdings Company
PPW Holdings LLC
PacifiCorp (owner of
Chehalis Facility)
.
.
.
.
.
.
.
C-3.
.
.
EXHIBITD
JOINT VENTURES, STRATEGIC ALLIANCES, TOLLING ARRGEMENTS AND
OTHER BUSINESS ARGEMENTS
Applicants respectfully request that the Commission waive the requirements of Section
.33.2(c)(4) of its regulations, 18 C.F.R. § 33.2(c)(4), to provide a description of all joint ventures,
strategic alliances, tolling arrangements or other business arrangements, both current and
planned to occur within a year, to which Applicants' parent companies, energy subsidiares and
.energy affiliates are a pary. In support of their waiver request, Applicants note that the ,f
Proposed Transaction wil not affect the business interests of Applicats' parent companies,
energy subsidiaries, and energy affliates, other than resulting in a change in the ownership of.Chehalis and the Chehalis Facility, as described in this Application.
.
.
.
.
.
D-1.
.
EXHIBITE
COMMON OFFICERS OR DIRECTORS.
Sellers, on the one hand, and Purchasers, on the other hand, share no common officers or
directors..
.
.
.
.
.
.
.
E-l.
.
EXHIBITF
.WHOLESALE POWER SALES CUSTOMERS AND UNBUNDLED TRASMISSION
SERVICES CUSTOMERS
As described in Part II in the Application, PacifiCorp and Chehalis sell power pursuant to
their market-based rate authority. The generation capacity and electric energy output of the.Chehalis Facility is currently sold to PacifiCorp pursuant to a call option agreement entered into
on March 1, 2008 that will terminate upon consummation of the Proposed Transaction. Chehalis
.will also fie a Notice of Cancellation to cancel its market-based rate schedule, effective upon
closing of the Proposed Transaction (i. e., the day when Chehalis is merged with and into
PacifiCorp). The wholesale market-based rate energy and/or capacity sales transactions for both.Chehalis and PacifiCorp, and customers served pursuant to those companies' market-based rate
taiffs, are reported though the Commission's Electric Quarerly Report ("EQR") system.
Chehalis also has a reactive power rate schedule on file with FERC to cover sales of.
reactive power to BP A. The Proposed Transaction includes the transfer of that rate schedule
from Chehalis to PacifiCorp, and PacifiCorp plans to fie a Notice of Succession under Section
.205 following the consummation of the Proposed Transaction. PacifiCorp also has certain cost-
based wholesale power sales customers served pursuant to fixed rates. The Proposed
Transaction does not involve any transmission facilities, except for the limited interconnection.equipment associated with the Chehalis Facility.
PacifiCorp requests partial waiver of this exhibit requirement because: (1) PacifiCorp
.provides information on its wholesale sales of energy and transmission service provided pursuant
to its Open Access Transmission Tariff ("OATT"), including identification of its customers, in
EQRs;and (2) the transfer wil not adversely affect Commission jurisdictional rates for
.customers of PacifiCorp. Specifically, as explained in furher detail in Section VI of the
F-l.
.
Application, the Proposed Transaction does not raise concerns that PacifiCorp's FERC
jurisdictional rates will be adversely affected..
.
.
.
.
.
.
.
.
F-2.
.
EXHIBITG
.JURISDICTIONAL FACILITIES OWNED, OPERATED OR CONTROLLED BY
APPLICANTS, THEIR PARENT COMPANIES, SUBSIDIARIES, AFFILIATES AND
ASSOCIATED COMPANIES
The jurisdictional facilities owned, operated and controlled by Sellers that are relevant to.
the Proposed Transaction are described in Par II of the Application. The only jursdictional
facilities, owned, operated or controlled by Sellers that wil be affected by the Proposed
.Transaction consist of the Chehalis Facility's interconnection facilities and Chehalis' maret-
"
based rate and reactive power rate schedules, and varous books, records and contracts related to
its rate schedules..The junsdictional facilities owned, operated and controlled by Purchasers are described
in Par II of the application. In addition, attached are the relevant pages from the most recet
.FERC Form No. 1 submitted by PacifiCorp. These pages identify the junsdictional facilties for
PacifiCorp. PacifiCorp also has agreements for the provision of wholesale power sales and
transmission service, rate schedules on file with the Commission, and related accounts, contracts,
.books, and records.
.
.
.
.G-1
.N~eo~ ~4~.l~ie8b 2 FERC PDF (Unoffic ¡~il ~&glP8 Date of Report Year/Period of Report
PacifiCorp (Mo, Da, Yr)End of 2007/Q4
(2) Fi A Resubmission 04/0412008
.TRANSMISSION LINE STATISTICS
1. Report infonnation conceming transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Repo transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Unifonn System of Accounts,Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wo or steel; (2) H-frame wo, or steel poles; (3) tower;
or (4) underground constrution If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portons of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (I) and (g) the total pole miles of each transmission line. Show in column (I) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on strutures the cost of which is reped for another line. Report
poe miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respec to such structures are included in the expenses reported for the line designated.
Line (Indicate where Type of LENGJiH roie miles)
. iilll e a~of Number
No.other than u dergroun hnes
60 cvcle 30hasel Supportng report circuit miles)Of
From To Operating Designed I un Structure vgf~~1WJrs CircuitsStructureof LineDesiarated Line
(a)(b)(c)(d)(e)(g)(h)
1 Malin, OR Indian Springs, CA SOO.O 500.00 Steel Tower 47.00 1
2 Midpoint, 10 Malin, OR 500.0 500.00 Steel Tower 446.00 1
3 Malin, OR Medford, OR 500.0 500.00 Steel Tower 84.00 1
4 Alvey Sub, OR Dixonville Sub, OR SOO.O 500.00 Steel Tower 58.00 1
5 Malin, OR Captain Jack, OR 500.0 500.00 Steel Tower 7.00 1
6 Dixonville, OR Meridian, OR SOO.O 500.00 SleelTower 74,)0 1
7 Colstrip 4, MT Switchyard, MT SOO.O 500.00 Steel Tower 1.00 1
8 Colstrip, MT Broadview A, MT SOO,O 500.00 SleelTower 112.00 1
9 Colstrip, MT Broadview B, MT SOO.O SOO.OO Steel Tower 116.00 1
10 Broadview, MT Townsend A, MT 500.0 500.00 Steel Tower 133.00 1
11 Broadview, MT Townsend B, MT 500.0 500.00 Steel Tower 133.00 1
12 50 kV expenses
13
14 Subtotal SOO kV 584.00 627.00 11
15
16 Ben Lomond Sub., UT Borah Substation, 10 345.0C 345.00 Steel-H 133.00 t
17 Ben Lomond Sub., UT Tenninal Substation, UT 345.0(345.00 Steel.D 47.00 2
18 Spanish Fork Sub., UT Camp Wiliams Sub., UT 345.0 345.00 Sleel.SP 35.00 2
19 Huntington Plant, UT Sigurd Substation, UT 345.0 345.00 Steel-H 95.00 1
20 Huntington Pit. Sub., UT Spanish Fork Sub., UT 345.0 345.00 Steel.H 78.00 1
21 Terminal Substation, UT Ninety South Sub., UT 345.0 345.00 Sieel-SP t6.00 2
22 Emery Substation, UT Sigurd Substation, UT 345.0l 345.00 Steel.H 75.00 1
23 Sigurd Substation, UT Camp Wiliams Sub., UT 345.01 345.00 Steel-H.P 116.00 1
24 Camp Willams Sub., UT Ninety South Sub., UT 345.01 345.00 Steel.SP 11.00 2
25 Tenninal Substation, UT Camp Willams Sub., UT 345.01 345.00 Steel. 0 26.00 1
26 Emery Substation, UT camp Wiliams Sub., UT 345.0 345.00 Steel.H 121.00 1
27 Newcastle, UT Utah - Nevada Border 345,0 345,00 Sleel.D 54.00 1
28 Sigurd Substation, UT Newcstle, UT 345.0C 345.00 Sleel.D 137.00 1
29 Goshen Substation, 10 Kinport Substation, 10 345.0C 345.00 Steel-H 41.00 1
30 Huntington Plant, UT Four Comers Sub., NM 345,OC 345.00 Wood-U 101.00 1
31 Camp Willams Sub., UT Huntington Plant, UT 345.0C 345.00 Wood.U 107.00 1
32 Huntington Plant, UT Pinto Substation, UT 345.0 345.00 Woo.U 160.00 1
33 Camp Wiliams Sub., UT Sigurd Substation, UT 345,0 345.00 Wood.U 70.00 1
34 Jim Bridger Plant #3, WY Borah Substation, 10 345,0 345,00 SleelTower 240.OC 1
35 Jim Bridger Plant #2, WY Kinport Substation, 10 345.0 345.00 Steel Tower 234.00 1
36 TOTAL 15,494.00 77700 210
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-87)Page 422
.Na¿eo~ 84~,f~ie8b 2 FERC PDF (Unoffic ¡~if ~~glj)8 Date of Report Year/Period of Report
PacifiCorp (Mo, Da, Yr)End of 2007/Q4
(2) 0 A Resubmission 0410412008
TRANSMISSION LINE STATISTICS
1. Report information conceming transmission lines, cost of lines, and expnses for year. List each transmission line having nominal voltage of 132
kilovOlts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower:
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a diferent type of construction need not be distinguished from the
remainder of the line.c_
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such strutures are included in the expenses reported for the line designated.
Line (Indicate .J~7J Type of LENG;hH &poie wiles)NumberNBte lfONo.other than u ergrou hnes
60 cvcle 30hase)Supportng report circuit miles)Of
From To Operating Designed un ~rrt~~re uri.~rru~~wes CircuitsStructreof AlJot erDesinratedline(a)(b)(c)(d)(e)(g)(h)
1 Currant Creek Swtchrd, UT Mona Substation, UT 345.0(345.00 Steel-SP 1.00
2 Camp Willams Sub, UT Mona Sub, UT 345.0(345.00 Woo-SP 8.00 42.00 1
3 34 kV expenses
4
5 Subtotal 34 kV 1,906.00 42.00 25
6
7 Fairvew, OR Isthmus, OR 230.0(230.00 H Frame Wood 12.00 ,1
8 Antelope Sub., 10 Lost River 230kV Line, 10 230.0C 230.00 Wood-H 20,00 1
9 Walla Walla, WA Hells Canyon, 10 230.0(230.00 H Frame Wood 78.00 1
10 Bethel, OR Fry, OR 230.0C 230.00 H Frame Wood 26.00 1
11 Fry, OR Dixonvile, OR 230.0(230.00 H Frame Woo 45.00 1
12 Alvey, OR Dixonvile, OR 230.0(230.00 H Frame Woo 59.00 1
13 Troutdale, OR Linneman, OR 230.0C 230.00 Steel Tower 6.00 1
14 Troutdale, OR Gresham, OR 230.0C 230.00 Steel Tower 6.00 1
15 McNary, WA Walla Walla, WA 230.0(230.00 H Frame Wood 56.00 1
16 BPA Heppner, OR Dalred Substation, OR 230.0C 230.00 H Frame Woo 1.00 1
17 Sigurd Substation, UT Garfield, UT 230.0C 230.00 Wood-U 117.00 1
18 Dixonvile, OR Reston, OR 230.0C 230.00 H Frame Woo 17.00 1
19 Yamsey, OR Klamath Falls, OR 230.0C 230.00 H Frame Wood 56.00 1
20 Yamsey,OR Klamath Falls, OR 230.0C 230.00 Steel Tower 6.00 1
21 Dixonvile, OR Lone Pine, OR 230.0C 230.00 H Frame Wood 8.00 1
22 Klamath Falls, OR Medford, OR 230.0(230.00 H Frame Wood 76.00 1
23 Klamath Falls, OR Malin, OR 230.0(230.00 H Frame Wood 35.00 1
24 Table Rock, SW Station, OR Grants Pass, OR 230.0C 230.00 H Frame Wood 35.00 1
25 Grants Pass, OR Days Creek, OR 230.0(230,00 H Frame Woo 7100 1
26 Dixonvile, OR Dixonville, OR 230.0(230.00 Wood 1.00
27 Sigurd Substation, UT Pavant Substation, UT 230.0(230.00 Woo-U 43.00 1
28 Pavant Substation, UT Nevada - Utah State line 230.0(230.00 Woo.U 98.00 1
29 Bannock Pass, 10 Antelope Sub., 10 230.0(230.00 Woo-U 76,00 1
30 Brady Substation, 10 Treasureton Sub., 10 230.0(230.00 Wöod-U 66,00 1
31 Ben Lomond Sub., UT Naughton PIt. #1, WY 230.0(230.00 Woo-U 88.00 1
32 Sigurd Substation, UT Arizona - Utah State line 230.0C 230.00 Wood.U 149.00 1
33 Birch Creek Sub., WY Railroad Substation, WY 230.0(230.00 Woo.HSW 12.00 1
34 Birch Creek Sub., WY Railroad Substation, WY 230.0(230.00 Wood.HSW 7.00 1
35 Ben Lomond Sub., UT Naughton PIt. #2, WY 230.0C 230.00 Wood.U 59.00 1
36 TOTAL 15,494.00 777,00 210
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-87)Page 422.1
.N~eo~ oi.rttl~ieBb 2 FERC . 1SIP(lJW~Date of Report Year/Period of ReportPDF(Unoffic ~ 'g11J8PacifiCo (Mo, Da. Yr)End of 2007/04
(2) n A Resubmission 0410412008
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wo or steel; (2) H-frame wo, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supportng structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or party owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line (Indicate where Type of LENGJiH rOle miles)NumberIiln e aSJ ofNo.other than u dergroun hnes
60 cvcle 3 nhase)Supportng report circuit miles)Of
From To ! un 'l1fllure vnft!tru:fures CircuitsOperatingDesignedStructreof Lin~o Ano er
Desi(la ed Line(a)(b)(c)(d)(e)(g)(h)
1 Ben Lomond Sub., UT Naughton PIt. #2, WY 230.0(230.00 Wood-U 29.00 1
2 Chppel Creek, WY Naughton Plant, WY 230.0(230.00 Woo Tower 46.00 1
3 Ben Lomond Sub., UT Terminal Substation, UT 230.0(230.00 Steel-D-P 76.00 1
4 Naughton Plant, WY Treasureton Sub., 10 23O.0(230.00 Woo-U 79.00 1
5 Naughton Plant, WY Treasureton Sub., 10 230.0(230.00 Woo-U 1.00 1
6 Swift Plant #1, WA Cowlitz Co. Line, WA 230.0(230.00 H Frame Woo 3.OC 1
7 Swift Plant #2, WA BPA Woodland, WA 230.0(230.00 H Frame Wood 23.00 1
8 Union Gap, WA BPA Midway, WA 230.0(230.00 H Frame Wood 39.00 1
9 Walla Walla, WA Lewiston, 10 230.0(230,00 HFrameWood 45.00 1
10 Walla Walla, WA Wanapum, WA 230.0(230.00 H Frame Wood 33.00 1
11 Pomona, WA Wanapum, WA 230.0(230.00 H Frame Wood 37.00 1
12 Pomona, WA Wanapum, WA 230.0(230.00 H Frame Wood 8.00 1
13 Meridian Sub, OR Lone Pine Sub, OR 230.0(230.00 Steel-DC 5.00
14 Meridian Sub, OR Lone Pine Sub, OR 230.0(230.00 Steel.DC 5.00
15 Goose Creek, WY Yellowtail, MT 230.01 230.00 H Frame Wood 59,00 1
16 Yellowtail, MT Muddy Ridge, WY 230.01 230.00 H Frame Wood 176.00 1
17 Sheridan, WY Decker, MT 230.¡j 230.00 H Frame Wood 12.00 1
18 Dave JohnSton Plant, WY Casper, WY 230.0 230.00 H Frame Woo 31.00 1
19 Yellowtail, MT Casper, WY 230.0 230,00 H Frame Wood 149.00 1
20 Rock Springs, WY Kemmerer, WY 230.0 230.00 H Frame Wood 71.00 1
21 Rock Springs, WY Atlantic City, WY 230.0(230.00 H Frame Wood 69.00 1
22 Thermopolis, WY Riverton, WY 230.0r 230.00 H Frame Wood 51.00 1
23 Casper, WY Riverton, WY 230.0(230.00 H Frame Wood 110.00 1
24 Dave Johnston Plant, WY Rock Springs, WY 230.0(230.00 H Frame Wood 209.00 1
25 Dave Johnston Plant, WY Spence, WY 230.0(230.00 H Frame Woo 31.00 1
26 Riverton, WY Atlantic City, WY 230.0(230.00 H Frame Wood SO.OO 1
27 Rock Springs, WY Flaming Gorge, UT 230.0(230,00 H Frame Wood 48.00 1
28 Palisades, WY Green River, WY 230.0(230.00 H Frame Woo 5.00 1
29 Bufalo, WY Gilette, WY 230.0(230,00 H Frame Wood 69.00 1
30 Jim Bridger Plant, WY Point of Rocks, WY 230,0(230.00 H Frame Wood 4.00 1
31 Jim Bridger Plant, WY Point of Rocks, WY 230.0(230.00 H Frame Wood 5.00
32 Dave Johnston Plant, WY Yellowcake, WY 230,O(230.00 H Frame Wood 69,00 1
33 Wyodak, WY Sub. Tie Line, WY 230.0(230.00 H Frame Wood 1.00 1
34 Jim Bridger Plant, WY Point of Rocks Ln 2, WY 230,O(230.00 H Frame Wood 8.00 1
35 Blue Rim, WY South Trona, WY 230.0(230.00 H Frame Wood 13,00 1
36 TOTAL 15.494.00 77700 210
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-87)Page 422.2
.N~i~fo~ 64~~ige8b 2 FERC PDF (Unoff ic t¡~IT ~~giP 8 uate of Report
I
Yearweno(1 Of Heport
PacifiCorp (Mo. Oa, Yr)End of 2007/04
(2) Fi A Resubmission 0410412008
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Propert.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame woo, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total poe miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or party owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line (Indicate J~';Type of LENGJi roie ~iles)NumberhiD e ai¡0No.other than u dergroun hnes Of60 cvcle 30hase)Supportng report circuit miles)
From To Operating Designed VI ~lflciure ugt~~lhigrs CircuitsStructureof Lineoesi(lrated Une(a)(b)(c)(d)(e)(g)(h)
1 Monument, WY Exxon Plant, WY 23O.0C 230.00 H Frame Wood 13.00 1
2 Firehole, WY Mansface, WY 230.0C 230.00 Steel Pole 2.00 1
3 Firehole, WY Mansface, WY 230.0(230.00 H Frame Wood 10.00 1
4 Monuments, WY South Trona, WY 230.0C 230.00 H Frame Wood 4.00 1
5 Spence Sub., WY Jim Bridger Plant, WY 230.0C 230.00 H Frame Wood 47.00
6 Jim Bridger Plant, WY Mustang Sub., WY 230.0(230.00 H Frame Woo 73.00 1
7 Spence Sub., WY Mustang Sub., WY 230.0(230.00 H Frame Woo 7700 1
8 Rock Springs, WY Flaming Gorge, UT 230.0C 230.00 Steel Tower 7,00 1
9 Une 59, CA Copcoll,CA 230.0C 230.00 H Frame Wood 5,00 1
10 Arizona/Utah State Line Glen canyon Sub., AZ 230.0C 230.00 H Frame Woo 10.00 1
11 Miners Sub., WY Foote Creek Sub., WY 230.0C 230.00 Woo.H 29.00 1
12 Monument Sub., WY Craven Creek Sub., WY 230.0C 230.00 Wood. H 20.00 1
13 Point of Rocks Sub., WY Rock Springs, WY 230.0C 230,00 Wood.H 27.00 1
14 230 kV expenses
15
16 Subtotal 230 kV 3,317.00 5.00 72
17
18 Montana-Idaho State line Grace Plant, 10 161.0C 161.00 Wood.H 57.00 90.00 1
19 Goshen Substation, 10 Rigby Substation, 10 161.0(161.00 Wood.H 61.00 1
20 Goshen Substation, 10 Antelope Substation, 10 161.0(161.00 Woo-H 45,00 1
21 Goshen Substation, 10 Sugar Mil Substation, 10 161.0C 161.00 Wood.SP 17.00 1
22 Sugar Mil Sub., 10 Rigby Substation, 10 161.0(161.00 Wood-SP'17.00 1
23 Goshen Substation, 10 Bonnevile Sub., 10 161.0(161.00 Wood-SP.H 23.00 1
24 Bilings, MT Yellowtail, MT 161.0 161.00 H Frame Woo 46.00 1
25 Big Grassy Sub., 10 Idaho Power Line, 10 161.0 161.00 Wood.H 1.00 1
26 Rigby Sub., 10 Jefferson Robert, 10 161.0 161.00 Woo.SP 18.00 1
27 Themopolis Sub, WY Wapa Tie Line, WY 161.0C
28 161 kVexpenses
29
30 Subtotal 161 kV 285.00 90.00 9
31
32 Naughton Plant, WY Evanston Substation, WY 138.0C 138.00 Wood .H 67.00 1
33 Evanston Substation, WY Anschutz Substation, WY 138.0C 138.00 Wood.H 6.00 1
34 Evanston Substation, WY Anschutz Substation, WY 138.0C 138.00 Wo\i. H 15.00 1
35 Naughton Plant, WY Carter Creek Sub., WY 138.0C 138.00 Wood.H 36.00 1
36 TOTAL 15,494,00 77700 210
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-87)Page 422.3
.'''':16~o~ s~~~~e8b 2 FERC PDF (UnOffict~ll ~&giP8 Date of Report Year/Penod of Report
PacifiCorp (Mo, Oa, Yr)End of 2007/04
(2) Fi A Resubmission 040412008
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of Iines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not reportsubstation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutilty Propert.
5. Indicate whether the tye of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H.frame wo, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supportng struture, indicate the mileage of each type of construction
by th use of brackets and extra lines. Minor portons of a transmission line of a different type of construction nee not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the poe miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned struures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line IKVI
Type of LEtlG~H loie WiieS)
No.(Indicate wtere ote'm0 Numberother than u ë1ergrou hnes
60 cvcle 3 Dhase\Supportng report circuit miles)Of
From To Operating Designed un ~tllcture I unf~ru~reres CircuitsStructreof. Line o 1)0 er
(a)(b)(c)(e)Desl(lrated Line
(d)(g)(h)
1 Railroad Sub., WY carter Creek Sub., WY 138.0!138.00 Wood.H 17.00 1
2 Painter Substation, WY Natural Gas Sub., WY 138.0!138.00 Woo.H 5.00 1
3 Grace Plant, ID Termn!. Sub., UT (103'104)138.0!138.00 Steel.S 42.00 2
4 Grace Point, ID Termn!. Sub., UT (103-104)138.0!138.00 Woo-H 211.00 2
5 Grace Plant, 10 Terminal Sub., UT (105)138.0(138.00 Woo.H 143.00 2
6 Grace Plant, 10 Sod Plant, ID 138.0 138.00 Woo.H 8.00 4.00 2
7 Oneida Plant, 10 Ovid Substation, 10 138.0!138.00 Woo.H 23.00 1
8 Antelope Substation, 10 Scoville Sub., 10 138.0!138.00 Wood.H 1.00 1
9 Soda Plant, Idaho Monsanto Sub., 10 138.0!138.00 Wood.H 8.0(1
10 caribou Substation, 10 Grace Plant, 10 138.0!138.00 Woo.H 16.00 1
11 Caribo Substation, 10 Becker Substation, 10 138.0(138.00 Woo.H 5.00 1
12 Treasureton Sub., 10 Franklin Sub., 10 138.0!138.00 Wood.H&S 10.00 1
13 Franklin Substation, 10 Smithfield Sub., UT 138.(138.00 Woo.H 25.00 1
14 Midvalley Substation, UT Thirty South Sub., UT 138.0(138.00 Wood.H 1.00 1
15 Angel Substation, UT Smith's UT 138.0!138.00 Wood.H 1.00 1
16 Terminal Substation, UT 30 South Switch Rack, UT 138.!138.00 Steel'S 7.00 1
17 Jordan, UT Terminal Substation, UT 138.(138.00 Wood. H 6.00 1
18 Wheelon Substation, UT American Falls Sub.. UT 138.0(138.00 Wood.H 82.00 1
19 Cutler Plant, UT Wheelon Substation, UT 138.0!138.00 Wood.H 1.00 1
20 Terminal Substation, UT Helper Substation, UT 138.0 138.00 Woo.H 116.00 1
21 Hale Plant, UT Nebo Substation, UT 138.0C 138.00 Wood. H 54.00 1
22 Carbon Plant, UT Helper Substation, UT 138.0C 138.00 Wood.H 2.00 1
23 Terminal Substation, UT Toole Substation, UT 138,0 138.00 Wood.H 42.00 1
24 Wheelon Substation, UT Smithfield Sub., UT 138.0 138.00 Wood.H 19.00 1.00 2
25 Helper Substation, UT Moab Substation, UT 138.0(138.00 Woo.H 118.00 t
26 Ninetieth South Sub, UT Carbn Plant, UT 138.0(138.00 Wood. H 75.00 2
27 Terminal Substation, UT Ninetieth South Sub, UT 138.01 138.00 Woo.H 16.00 2
28 30 South Switch Rack, UT McClelland Sub., UT 138,O(138.00 Wood.SP 6.00 1
29 Moab Substation, UT Pinto Substation, UT 138.0(138.00 Woo.H 68.00 1
30 Pinto Substation, UT Abajo, UT 138.0(138.00 Wood.H 45.00 1
31 Carbn Plant, UT Ashley Substation, UT 138.01 138.00 Wood.H 92.00 1
32 McClelland Sub., UT Cottonwood Sub., UT 138.0(138.00 Wood.SP 6.00 1
33 Ashley Substation, UT Vernal Substation, UT 138.0(138.00 Wood.H 12.00 1
34 Sigurd Substation, UT West Cedar Substation, UT 138.0 138.00 Woo. H 120.00 1
35 Ben Lomond Sub., UT EI Monte Substation, UT 138.0C 138.00 Wood. H Sub 19.00 1
36 TOTAL 15,494.00 77700 210
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-87)Page 422.4
.N~Tlfo~ ~4~!2ieBb 2 FERC PDF (Unoffie ~if Ptgit) 8 Date of Report Year/Period of Report
PacifiCorp (Mo, Da, Yr)End of 2007/04
(2) n A Resubmission 040412008
TRANSMISSION LINE STATISTICS
1. Report information conceming transmission lines, cost of lines, and expnses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Prort.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single poe wo or steel; (2) H.frame wo, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supportng structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of constrution need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (1) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such ocupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line I iui'!
(Indicate J~i:Type of LENGJ,H lole miles)Number~IO t e ai¡ ofNo.other than u dergroun lines
60 cycle, 3 phase)Supporting report circuit miles)Of
From To Designed I un ~trcture uri,qt!:~ures CircuitsOperatingStructreof Line of MO erDesi(lated Line(a)(b)(c)(d)(e)(g)(h)
1 Cottonwoo Sub., UT Ninetieth South Sub, UT 138.0C 138.00 Woo.SP 11.00 1
2 Terminal Substation, UT Rowley Substation, UT 138.0(138.00 Woo.H 56,00 1
3 Huntington Plant, UT McFadden Substation, UT 138.0 138.00 Woo.H 7.00 1
4 Ben Lomond Sub., UT EI Monte Substation, UT 138.0(138.00 Wood.H 13.00 1
5 Cottonwoo Sub., UT Silvercreek Sub., UT 138.0(138.00 Woo.SP 37.00 1
6 Ninetieth South Sub, UT Taylorsvile Sub., UT 138.0 138.00 Wood.SP 9.00 1
7 Gadsby Plant, UT McClelland Sub., UT 138.0 138.00 Wood.SP 4,00 1
8 Ninetieth South Sub, UT Oquirrh Substation, UT 138.0C 138.00 Woo.SP 10.00 2
9 Nebo, UT Jerusalem, UT 138.0 138.00 Wood Tower 26.00 1
10 Ben Lomond Sub., UT Westem Zircon Sub., UT 138,0 138.00 Wood.H 14.00 1
11 Toole Substation, UT Oquirr Substation, UT 138.0 138.00 Wood.SP 21.00 1
12 Wheelon Substation, UT Nucor Steel Sub., UT 138.0 138.00 Woo.H 14.00 4.00 1
13 Nebo Substation, UT Martin.Marietta Sub., UT 138.0(138.00 Woo.H 30.00 1
14 West Cedar Sub., UT Middleton Substation., UT 138.0(138.00 Woo.H 69.00 1
15 Gadsby Plant, UT Terminal Substation, UT 138.0C 138.00 Woo.H 6.00 1
16 Oquirrh Substation, UT Kennecott Sub., UT 138.0C 138.00 Wood.H 4.00 1
17 Oquirrh Substation, UT Bamey Substation, UT 138.0C 138.00 Wood.HS 7,00 2
18 West Cedar Sub., UT Pepcon Substation, UT 138.0C 138.00 Wood.SP 13.00 1
19 Taylorsville Substation, UT Mid.Valley Substation, UT 138,OC 138.00 Sleel.SP 5.00 1
20 Warren Substation, UT Kimberly Clark Sub., UT 138.0C 138.00 Woo.HP 1.00 1
21 Honeyvile, UT Promontory, UT 138.0C 138.00 Woo Tower 22.00 1
22 Ninetieth South Sub, UT Hale Plant, UT 138.0C 138.00 Wood Tower 47,00 1
23 Dumas, UT Bimple, UT 138.0C 138.00 Wood Tower 4.00
24 Columbia Sub, UT Sunnyside Co. Gen., UT 138.0C 138.00 Wood Tower 2.00 1
25 Syracuse Sub, UT Ben Lomond Sub, UT 138.0C 138.00 Steel.D.P 26.00 1
26 Hale Plant, UT Midway Sub, UT 138.0C 138.00 Wood-H 19,00 1
27 Jordan 138 kV, UT Fift West 138 kV, UT 138.0(138.00 Steel Tower 1.00 1
28 Gadsby 138 kV, UT Jordan 138 kV, UT 138.0C 138.00 SteelTower 1.00 1
29 Panther, UT Wilow Creek, UT 138.0C 138,00 Wood Tower 1,00 1
30 Hammer Substation, UT Butlervile Substation, UT 138.0C 138.00 Wood Tower 5.00 1
31 Midway Substation, UT Silver Creek Sub, UT 138.0C 138.00 Woo Tower 14.00 1
32 Midway Substation, UT Cottonwo Sub, UT 138,OC 138.00 Woo Tower 10.00 1
33 McFadden Substation, UT Blackhawk Substation, UT 138.0C 138.00 Wood.H 11.00 1
34 West Valley Sub., UT Keams Substation, UT 138.0C 138.00 Wood. SP 2.00 1
35 Syracuse Substation, UT Clearfeld South Sub., UT 138.0C 138.00 Wood .SP 1.00 1
36 TOTAL 15,494,00 77700 210
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FERC FORM NO. 1 (ED. 12-87)Page 422.5
.N%eo~ ~4tl~ie8b 2 -¡~il ~rAgip 8 Date of Report Year/Period of ReportFERCPDF(Unoffic (Mo. Da, Yr)End of 207/04PacifCorp
(2) Fi A Resubmission 040412008
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines. cost of Iines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all fines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual fines for all voltages if so required by a State commission.
4. Exclude from this page any transmission fines for which plant costs are included in Account 121, Nonutilty Proprt.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wo or steel; (2) H-frame wo, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of constrution need not be distinguished from the
remainder of the line.
6. Report in COlumns (I) and (g) the total pole miles of each transmission line. Show in column (I) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in coumn (g) the poe miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned strutures in column (g). In a footnote. explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Line
(Indicate ..~i'Type of LE~G~ ~oie 'fileS)lot ~o NumberNo.other than u dergrou hnes
Of60 cvcle 3 ohase \Supportng report circuit miles)
To Operating I un ::tNclure un;wnmres CircuitsFromDesignedStructreof Lin~o L1~e er
(a)(b)(c)(d)(e)Desiara ed
(g)(h)
1 Farmington Substation, UT Parrish Substation, UT 138,0 138.00 Steel-DC 5.00 1
2 Midvalley Substation, UT Cottonwood Substation, UT 138.0 138.00 Woo.DC 5.00 1
3 Taylorsville Substation, UT West Valley Substation, UT 138.01 138.00 Steel. DC 3.00 3.00 1
4 Dynamo Sub, UT Tri-City Sub, UT 138.01 138.00 Woo.SP 2.00 2
5 Oqruirr Sub, UT Tri-City Sub, UT 138.0l 138.00 Wood-SP 22.00 2
6 Bridgerland Sub, UT Green Canyon Sub, UT 138.0 138.00 Wood.SP 16.00 1
7 138 kV expenses
8
9 Subtotal 138 kV 2,122.00 12.00 90
10
11
12 All 115 kV lines 115.0(115.00 Woo & Steel 1,548.00
13 All 69 kV lines 69.0(69.00 Woo & Steel 2,962.00 1.00
14 All 57 kVlines 57.0(57.00 Woo & Steel 113.00
15 All 46 kV lines 46.0(46.00 Wood & Steel 2,615.00
16
17
18 Unclassified Plant at 12/31
19 Chappel Creek Unclassified Plant 230.0(230.00 Woo.H 35.00 1
20 Craven Creek Unclassified Plant 230.0C 230.00 Woo.H 3.00
21 Marengo Wind Plant Trans Unclassified Plant 230.0C 230.00 WoodH Frame 4.00 1
22 Blundell Steam Plant Unclassified Plant 69.DC 69.00 WooSP 1
23 Unclassified Plant (Under $1,000,000 Projects)
24
25
26
27
28
29
30
31
32
33
34
35
36 TOTAL 15,494.00 77700 210
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.FERC FORM NO. 1 (ED. 12-87)Page 422.6
.N~'lM~ ~4~~ieBb 2 FERC PDF (Unoffic ¡~i~ ~~gi08 Date of Report Year/Period of Repon
(Mo, Da. Yr)End of 2O07/Q4
PacifiCorp (2) ri A Resubmission
04/041208
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twce. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If tw or more transmissìon line structres support lines of the same voltage. report the
pole miles of the primary structure in coiumn (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or porton thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease. and amount of rent for year. For any transmission line other than a leased line. or portion thereof. for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of. fumish a succinct statement explaining the
arrangement and givìng particuiars (details) of such matters as percent ownership by respodent in the line, name of co-owner. basis of sharing
expnses of the Line. and how the expenses bome by the respondent are accounted for. and accounts affected. Speify whether lessor, cowner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease. annual rent for year. and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (i) on the bok cost at end of year.
CO::T 01- LINE: \inClude in coiumn (j Land.EXPENSES. EXCEPT DEPRECIATION AND TAXES
Size of Land nghts. and cleanng nght-of-way)
Conductor
and Matenal
Land Construction and Total Cost operation Maintenance Rents Totl ine
Other Costs Expenses Expenses (0)
Expenses No.
(i)(j)(k)(I)(m)(n)
(p)
"-1852 134.351 5,551,720 5,686,076
1
12720 3,086,40 151.381.956 154,468.356
2
1272.0 2,907,17 38,015,889 40,923,064
3
1272.0 1,468,20 19,597,617 21,065,821
4
1272.0 9,23 1,460,042 1,469,272
5
~2720 4,769,43'26,255,866 31,025,301
6
r795 KCM ACSR
25,657 25,657
7
95 KCMACSR 218,75E 5,413,613 5,632,372
8
795 KCMACSR 276,82!7,158,284 7,435,109
9
95KCMACSR 418,61 6,568,174 6,986,787
10
95KCM ACSR 436,16 6,491,204 6,927,372
11
16,507 853,926 99,:¡969,63.12
13
13,725,16e 267,920,022 281,645,187 16,507 853,926 99,:¡969,632 14
15
S54.0 5,229,65~35,321,732 40,551,385
16
h27.0 9,369,70t 22,112,724 31,482,432
17
1272.0 5,508,40~10,158,595 15,667,004
18
S54.0 343,17 20,080,785 20,423,959
19
S54.0 855,93E 17,683,269 18,539,205
20
1272.0 2,557,85'7,457,557 10,015,412
21
954.0 320,3H 13,619,157 13,939,47~
22
S54.0 510,49(25.192.646 25,703,136
23
1272.0 482,86E 3,895,71~4,378,579
24
12720 4,301,93 7,970,335 12,272,272
25
S54.0 926,251 27.921,108 28,847,359
26
54.0 2,320,87 50,682,835 53,003.707
27
54.0 56,05(13,605,651 13.661,701
28
95.0 313,471 2,571,824 2,885,301
29
954.0 117,66,2,893,802 3,011,464
30
95.0 893,96 19,882,390 20,776,355
31
95,0
32
1795.0 179,50:16,211,906 16.391,408
33
12720 1,128,2~26,302,241 27.430,463
34
1272.0 l,099,79E 28,083,728 29,183,524
35
85,897,343 1,695,585,078 1,781,482.421 125,807 13,323,841 1,316,314 14,765,96 36
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FERC FORM NO.1 (ED. 12-87)
Page 423
...~ 'Ò"'O~ 6'4'l4'~'8"'ò'b 2 FERC PDF (Unoific ~If 7RidgiP 8
I
uate 01 Hepon
I
YearlPenoO 01 Report
(Mo, Da, Yr)End of 2007/04PacifiCo
(2) Fî A Resubmission 04/0412008
RANSMISSION LINE STATISTICS (Cotinued)
7. 00 not report the same transmission line structure twce. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If tw or more transmission line struures support lines of the same voltage, report the
pole miles of the primary strcture in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and tenns of Lease, and amount of rent for year. For any transmission line other thn a leased line, or porton thereof. for
which the respöndent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expnses borne by the respondent are accounted for, and accounts affected. spedfy whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and tenns of lease, annual rent for year, and how
detennined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns ul to (I) on the book cost at end of year.
l,U::1 i 11Ii= Iincluoe in l,oiumn UJ Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Exenses Expenses (0)Expenses No.(i)ul (k)(I)(m)(n)(p)
1,178,476 1,178,479 1
1272 9,578,059 9,578,059 2
1,160,237 246,299 1,406,53€3
4
36,516,141 362,404,536 398,920,677 1,160,23 246,299 1,406,53E 5
6
54.0 285,32~1,702,52 1,987,84'7
95.0 12,926 1,200,282 1,213,211 8
1272.0 64,39~11,244,114 11,308,508 9
1272.0 351,98.1,908,416 2,260,398 10
1272.0 485,89E 4,968,451 5,454,347 11
54.0 1,428,24 14,703,211 16,131,458 12
54.0 423,03E 423,036 13
54.0 363,71 574.074 937,791 14
1272.0 220,961 3,403,51~3,624,481 15
95.0 108,2!108,025 16
95.0 468.99 7.660,34,8.129,33!17
39,971 1,558,34,1,598,314 18
95.0 19
95.0 473,36 4,453,059 4,926,425 20
95.0 439,56 4,128,249 4,567,812 21
95.0 173,60 6,065,263 6.238,871 22
1272.0 115,4 1,798,928 1,914,376 23
IsS,tO 191,12 5,203.72 5,394,596 24
1272.0 379,961 11,874,57"12,254,533 25
1272.0 508,736 508,736 26
1795.0 41,49 4,372,038 4,413,537 27
f15.0 28
1272.0 5,10 2,481,761 2,486,864 29
95.0 72,1H 2,165,408 2,237,526 30
95.0 426,121 4,570,641 4,996,767 31
1954.0 22,64 4,584,254 4,606,897 32
1954.0 165.05'1,299,642 1,464,696 33
1954.0 181,04 1.520,220 1,701,267 34
1272.0 736,03(5,273,727 6,009,757 35
85,897,34,1,695,585,078 1,781,482,421 125.807 13,323,841 1,316,314 14,765,96 36
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.FERC FORM NO. 1 (EO. 12-87)Page 423.1
.Nëleo~ ~4~~ie8b 2 FERC PDF (Unoffic ¡in W~giP8 Date of Report Year/Period of Report
(Mo, Da, Yr)End of 2007/04PacifiCorp
(2) Fi A Resubmission 04/0412008
TRANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twce. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If tw or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structre in column (I) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or porton thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and tenns of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof. for
whiCh the respodent is not the sole owner but which the respodent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and acconts affected. Specify whether lessor, co-owner. or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
detennined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns u) to (I) on the bo cost at end of year.
COST ni= i INi= /Include in Column 0) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Oter Costs Expenses Expenses (0)Expnses No,(i)ü)(k)(I)(m)(n)(p)
1272.0 1,721,522 t ,721 ,522 1
954.0 170,96 5,900,151 6.071,118 2
1272.0 572,45 10,217,612 10,790,071 3
954.0 56,49 3,070,270 3,126,768 4
~54.0 56 27,377 27,946 5
~54.0 1,29 335,329 336,622 6
~54.0 103,53~2,598,0M:2,701,580 7
1272.0 172,451 1,709,377 1,881,828 8
1272.0 366,29C 6,331,575 6,697,865 9
954.0 235,53~2,389,938 2,625,70 10
1780.0 207,12~2,664,144 2,87t,267 11
~56.5 16E 1,514,180 1,514,349 12
1272 2,003,740 2,003,740 13
14
1272.0 t,714,52E 2,100,252 3,814,781 15
1272.0 1,615,02'5,951,730 7,566,755 16
1272.0 26,09~630,118 656,211 17
1795.0 14,921 1,147,317 1,162,24~18
~271.0 130,19 9,689,026 9,819,223 19
1271.0 52,901 3,439,244 3,492,150 20
54.0 31,85(3,001,62,3,033,482 21
1272.0 57,11 2,100,040 2,157,152 22
54.0 67,85 5,083,127 5,150,984 23
1272.0 58,10 11,533,953 11,592,055 24
1272.0 33,0 2,658.645 2,691,653 25
12710 48,281 3,806,177 3,854,458 26
1272.0 30.76 2,662,969 2,693,738 27
1272.0 1,697,350 697,362 28
1272.0 361,351 4,344,62(4,705,971 29
1272.0 4,80(140,312 145,11,30
1272.0 130,166 130,166 31
1272.0 294,29(6,158,106 6.52,396 32
1272.0 15,274 15,274 33
1272.0 3,96 441,494 445,46ì 34
1272.0 872,981 872,981 35
85,897,34~1,695,585,078 1,781,482,421 125,807 13.323,841 1,316.314 14,765,96 36
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FERC FORM NO. 1 (ED. 12-87)Page 423.2
.
NePlM~ ~4tt~ie8b 2 -~--~" ~~_-~ Year/Period of ReportFERCPDF(Unoffic ¡~if WW~glP8 Date of Report
PaciliCorp (Mo, Da, Yr)End of 207/04
(2) Ei A Resubmission 0410412008
RANSMISSION LINE STATISTICS (C:otinued)
7, Do not repor the same transmission line structure twce. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnte if
you do not include Lower voltage lines with higher voltage lines. If tw or more transmission line structures support lines of the same voltage, report the
poe miles of the primary structre in column (f) and the poe miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such prpert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or poon thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Speify whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns ul to (I) on the bok cost at end of year.
,"v;: I VI' LINt: (lnciuae in U)iumn OJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operatin Maintenance Rents Total Line
Other Costs Expenses Expenses
(0)
Expenses No.(i)(j)(k)(I)(m)(n)(p)
1272.0 160,129 160,129 1
1272.0 2
1272.0 2,674,008 2,674,008 3
1272.0 2,726,304 2,726,304 4
1272.0 170,295 170,295 5
1272.0 9,760,523 9,760,523 6
1272.0 9,565,742 9,565,742 7
~272.0 4,48 744,631 749,113 8
4,33 820,071 824,410 9
11,901 451,363 463,264 10
4,972,560 4,972,560 11
4,548,527 4,548,527 12
5,939,085 5,939,085 13
31,548 2,896,603 396,993 3,325,14"14
15
13,597,79€259,375,327 272,973,125 31,54 2,896,603 396,993 3,325,14"16
17
97.5 18,97€1,585,831 1,604,809 18
397.5 27,52C 808,384 835,904 19
97.5 8,85 2,667,758 2,676,61~.20
97.5 48,22 1,482,266 1,530,493 21
97.5 27,53€1,210,177 1,237,71 22
54.0 362,27S 2,835,396 3,197,675 23
56.5 1,523,64.1,830,017 3,353,659 24
56.5 26,208 26,208 25
56.5 76,30€1,284,658 1,360,964 26
12,306 12,306 27
41,929 251,180 4,540 297,64~28
29
2.093,34=13,743,001 15,836,346 41,929 251,180 4,54 297,64!J 30
.31
95.0 146,64=4,036,209 4,182,854 32
95.0 129,12Ç 504,914 634,043 33
95.0 3,381 290,803 294,184 34
95.0 41,411 3,577,596 3,619,007 35
85,897,343 1,695,585,078 1,781,482,421 125.807 13,323,841 1,316,314 14,765,96,36
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.FERC FORM NO. 1 (ED. 12-87)Page 423.3
.N~eo~ ~4mi~ie8b 2 FERC PDF (Unoffic ~if W~gij)8 Date of Report Year/Period of Report
PacifiCorp (Mo, Da, Yr)End of 2007104
(2) Fi A Resubmission 0410412008
RANSMISSION LINE STATISTICS (i;otinued)
7. Do not report the same transmission line structure twce. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If tw or more transmission line strures support lines of the same voltage, report the
pole miles of the primary struture in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or porton thereof. for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of cownr, basis of sharing
expenses of the Line, and how the expenses borne by the respodent are accounted for, and accounts affeced. Specify whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns Ol to (I) on the bo cost at end of year.
--OSl ,(lnCIUae in (.oiumn OJ Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operatin Maintenance Rents Total Line
Other Costs Exses Expenses (0)
Expenses No.
(i)Ol (k)(I)(m)(n)(p)
95.0 72,62:3,821,010 3,893,632 1
95.0 .12,42~-278,836 .291,260 2
95.0 765,18t 13,267,187 14,032,37:i 3
95.0 4
~50.0 132,96 16,032,079 16,165,03 5
95.0 3,291 157,216 160,5ò 6
13.0 4,81 596,581 601,398 7
137.5 14'41 190 8
137.5 2,55 295,902 298,45 9
1795.0 18,28 420,886 439,170 10
ß97.5 14,42/145,941 160,365 11
1795.0 39,101 541,498 580.599 12
97.5 47,61 1,094.655 1,142,268 13
192,647 192.647 14
20,229 20,229 15
00.0 1,83 1,256,746 1,258,583 16
661,44 1,776,211;2,437.662 17
50.0 118.18l 6,191,321 6,309,501 18
50.0 69,072 69,072 19
SO.O 458,79!12,490,719 12,949,518 20
97.5 27,54!4,607.792 4.635,337 21
1154.0 78l 150,403 151.189 22
ß97.5 9,46(8.47,186 8,416,646 23
ß97.5 188,0t!1,056,437 1,244,455 24
ß97.5 33,961 3,033.558 3,067,526 25
95.0 345.831 5,622,147 5.967.98;26
1272.0 426,74l 1,228,422 1,655.168 27
1795.0 58.03(l,564,31E 1.622,346 28
ß97.5 40,11 1,070,458 1,110.57;29
ß97.5 100,35 2,100,398 2,200,751 30
ß97.5 80,861 1,750,314 1,831.175 31
95.0 13,73~1,500,760 1,514,49~32
ß97.5 5.54t 325,444 330,990 33
ß97:~62.15!3,548,776 3.610,931 34
1795.0 18,54!850,357 869,202 35
85,897,34;1,695,585,078 1,781,482,421 125,807 13,323,841 1,316,314 14,765,00 36
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FERC FORM NO. 1 (ED. 12-87)Page 423.4
., '': 'ira'S Ö ',rtJ4':''trò'i 2 FERC PDF (Unoffic ~~l) ~~giP8 UC:Lt1 ul nt:lJll
I
't:df/ïtHlUU UL ntilJrI
(Mo, Da, Yr)End of 2007104PacifiCo
(2) i9 A Resubmission 0410412008
RANSMISSION LINE STATISTICS (( ontinued)
7. Do not rep th same transmission line structure twe. Report Lower voltage Unes and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voage lines with higher voltage lines. If tw or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structre in column (f) and the poe miles of the other line(s) in column (g)
8, Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or porton thereof, for
which the respodent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co~wner, basis of sharing
expses of the Une, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co~wner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns u) to (I) on the book cost at end of year.
\.v;: I vI" LINE (incluae in COlumn ~J Lana,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right~f-way)
Coductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total UneOther Costs Exenses Expenses (0)Expenses No.(i)(j)(k)(I)(m)(n)(p)
95.0 549,06A 2,230,643 2,n9,707 1
95.0 222,28€2,283,128 2,505,414 2
97.5 26 238,883 239,148 3
95.0 24,901 1,017,499 1,042,400 4
97.5 177,82 6,159,264 6,337,088 5
95.0 5,17 2,550,199 2,555,377 6
95.0 56,75 925,590 982,349 7
95.0 243,44 3,548,477 3,791,922 8
97.5 253,53 2,264,963 2,518,502 9
50.0 96,45 968,211 1,064,668 10
95.0 252,891 3,057,455 3,310,34E 11
95.0 46,94 909,120 956,067 12
397.5 66,45 1,796,523 1,862,975 13
97.5 25,14 2,178,964 2,204,112 14
1272.0 668,771 810,47~1,479,244 15
95.0 251,54~251,54,16
95.0 16,66 457,439 474,107 17
95.0 43,59l 1,088,222 1,131,812 18
1272.0 33,46l 2,500,072 2,533,538 19
97.5 14,72 141,422 156,144 20
ß97.5 475,68~2,874,162 3,349,844 21
ß97.5 146,2 7,793,509 7,939,934 22
ß97.5 3,136,585 3,136,585 23
ß97.5 -41 2 .39 24
1272.0 353,104 353,104 25
ß97.5 246,50 4,038,881 4,285,38 26
1272.0 1 1,104,840 1,104,857 27
1272.0 75!381,900 382,655 28
ß97.5 40,890 40,890 29
188,391 3,364,794 3,553,185 30
2,755,012 2,755,012 31
69O,02!5,581,57,6,271,598 32
1,747,45,1,747,452 33
268,234 268,234 34
677376 677,376 35
85,897,343 1,695,585,078 1,781,482,421 125,807 13,323,841 1,316,314 14,765,96,36
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.FERC FORM NO. 1 (ED. 12-87)Page 423.5
.
"~'ò~o1l Ò'.nr4~trò'b 2 FERC PDF (Unoffic ~~') lF~gllJ8
I
Uèiie 01 nepon
I
T ear/r-enou 01 nepon
(Mo. Da, Yr)End of 2007/04PacifiCorp
(2) Fi A Resubmission 04041208
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line strcture twce. Rep lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If tw or more transmission line structres support lines of the same voltage, report the
pole miles of the primary structure in column (I) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or porton thereof for which the respondent is not the sole owner. If such propert is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or poon thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specfy whether lessor, co-owner, or
other part is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual renl for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (i) on the bo cost at end of year.
(.u~ i ut' LINE (Include in Column OJ Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Malerial Land Construction and Total Cost Operation Maintenance Rents Total LineOter Costs Expenses Expenses (0)Expenses No.(i)(j)(k)(I)(m)(n)(p)
902,058 902,058 1
4,655,525 4,655,52~2
2,002,980 2,002,98C 3
':795 9,221,850 9,221,850 4
1557 41,207,67C 41,207,67C 5
1272 9,233,88 9,233,881 6
~1,479,297 86,27:1,565,581 7
8
8,607,53 240,037,77 248,645,306 ~1,479,297 86,27E 1,565,581 9
10
11
3,510,35 126,231,356 129,741,711 17,044 2,482,147 323,31E 2,822,51C 12
3,354,06 212,041,651 215,395,724 16,40(1,735,641 119,26~1,871,30~13
41,23-8,169,256 8,210,490 ~4,464 331 4,79!14
4,451,70 184,802,664 189,254,369 2,366 2,460,34E 4O,O~2,502,801 15
16
17
18
1272 11,499,447 11,499,44i 19
826,735 826,735 20
95 1,823,720 1,823,720 21
97 520,637 520,637 22
6,188,947 6,188,947 23
24
25
26
27
28
29
30
31
32
33
34
35
85,897,343 1,695,585,078 1,781,482,421 125,807 13,323,841 1,316,31-1 14,765,96 36
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.FERC FORM NO. 1 (ED. 12-87)Page 423.6
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20080404-8002 FERC PDF (Unofficial) 04/04/2008
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/04/2008 2007/04
FOOTNOTE DATA
¡Schedule Page: 422 Line No.: 4 Column: a
The Alvey - Dixonvile 500kV line is jointly owned by the respondent and the Bonnevile Power Administration ("the BPA").
Ownership of the line is as follows: PacifiCorp 50.0%, the BP k50.0%. Cost reported for this line reflects the respondents 50.0%
share. Operation and maintenance costs are shared between the two paries and responsibility is as follows: PacifiCorp 58.0% and the
BPA42.0%.
¡Schedule Page: 422 Line No.: 6 Column: a
The Dixonvile - Meridian 500kV line is jointly owned by the respondent and the Bonneville Power Administration ("the BPA").
Ownership of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Cost reported for this line reflects the respondents 50.0%
share. Operation and maintenance costs are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and the
BPA42.0%.
!Schedule Page: 422 Line No.: 7 Column: a
The Colstrip 4 - Switchyard 500kV line is jointly owned by the respondent, NortWestern Corporation. Puget Sound Power & Light.
Washington Water Power Company and Portland General Electric. Ownership of the line is as follows: PacifiCorp 6.8%. all others
93.2%. Plant cost and operation and maintenance costs reported for this line reflects the res ndent's share.
,Schedule Page: 422 Line No.: 8 Column: a
The Colstrip - Broadview A 500kV line is jointly owned by the respondent. NortWestern Corporation. Puget Sound Power & Light.
Washington Water Power Company and Portland General Electric. Ownership of the line is as follows: PacifiCorp 6.8%. all others
93.2%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.
!Schedule Page: 422 Line No.: 9 Column: a
The Colstrip - Broadview B 500kV line is jointly owned by the respondent ,NorthWestern Corporation. Puget Sound Power & Light.
Washington Water Power Company and Portland General Electric. Ownership of the line is as follows: PacifiCorp 6.8%. all others
93.2%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.
¡Schedule Page: 422 Line No.: 10 Column: a
The Broadview - Townsend A 500k V line is jointly owned by the respondent, NorthWestern Corporation, Puget Sound Power &
Light. Washington Water Power Company and Portland General Electric. Ownership of the line is as follows: PacifiCorp 8.1 %. all
others 91.9%. Plant cost and 0 eration and maintenance costs re rted for this line reflects the res ndent's share.
ISchedule Pa e: 422 Line No.: 11 Column: a
The Broadview - Townsend B 500kV line is jointly owned by the respondent, NorthWestern Corpration. Puget Sound Power &
Light, Washington Water Power Company and Portland General Electric. Ownership of the line is as follows: PacitiCorp 8.1 %, all
others 91.9%. Plant cost and operation and maintenance costs reported for this line reflects the respondent's share.
IFERC FORM NO.1 (ED. 12-87)Page 450.1
.Nëped~ ~4~~ie8b 2 FERC PDF (Unoffic ~if WrdgiP8 Date of Report Year/Period of Report
(Mo, Da, Yr)End of 2007/Q4PacifiCorp
(2) Fi A Resubmission 04/041208
RANSMISSION LINES ADDED DURING YEAR
1.Report below the information catted for concerning T.ransmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (I) to (0), it is permissible to report in these columns the
Line LINt:IIVN I-III,!,11/'1\:H:: I HUi;rUR
No.
Lerigth ."~'t:'\;':-Present UltimateFromToinTypeNumber per Miles Miles
(a)(b)(c)(d)(e)(f)(g)
1 BDOSub, UT Warren-Kimber1y Clark, UT 1.24 Woo SP 15.00 1 1
2 Green Canyon Sub, UT Bridger1and Sub, UT 16.00 WooSP 15.00 1 1
3 Camp Wiliams, UT Mona, UT 50.00 Steel Obi Ckt 10,00 ~2
4 Chappel Creek, WY Jonah Field/Bridger, WY 35.00 Woo H Frame 10.OC 1 1
5 Craven Creek, WY Enterprise/Pioneer, WY 3.00 Woo H Frame 12,OC 1 1
6 McClelland, UT Emigration, UT 1.40 Woo DbCkt 19.00 2 2
7 Meridian, OR Lone Pine, OR 2.70 Wood H Frame 12.00 1 1
8 TImp,UT Cheriyod, UT 1.68 WoodSP 14.00 1 1
9 Sunrise, UT Oquirrh, UT 2.37 Steel SP 14.00 ::2
10 Dynamo, UT Tri-City, UT 2.42 WooSP 15.00 2 2
11 Bangerter, UT Oquirrh, UT 327 Wood SP 14.OC ::2
12 70th Sout, UT West Jordan, UT 1.50 Woo Db Ckt 18.00 1 2
13 Marengo Wind Plant, WA Talbot Sub, WA 4.00 Wood H Frame 10.00 1 1
14
15
16
17
18
19
20
21
22
23
2l
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44 TOTAL 124.58 178.00 18 H
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FERC FORM NO.1 (REV. 12-()Page 424
.N~eo~ ~4~~ie8b2 FERC PDF (Unoffic ¡~if ~iAgiiJ 8 Date of Report Year/Period of Report
(Mo, Da, Yr)End of 2007/04PacifiCorp
(2) n A Resubmission 04041208
TRAN MISSION LINES ADDED DURING YEAR (Cotinued)
costs. Designate, however, if estimated amounts are r~ported. Include costs of Clearing land and Rights-of-Way, and Roads and
Trails, in column (I) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
Voltage ,.Line
Size Specification Conf~uratiOn KV Land and Poles, Towers Conductors Asset Total No.
and pacing (Operating)Land Rights and Fixtures and Devices Retire. Costs
(h)(i)OJ (k)(I)(m)(n)(0)(p)
397.5 ACSR Horizonl10'138 625,47,625,471 1,250,943 1
1272 ACSR VerticaV10'138 6,291.04 2,942.840 9.233.887 2
1272 ACSR VerticaV25'345 9,578,059 9.578.059 3
1272 ACSR Horizl19.6'230 6,824,92.4,674,525 11.499.447 4
1272 ACSR Horizl17.5'230 413,36f 413.367 826.735 5
1557 ACSR VerticaV10'138 682,523 682.523 6
1272 ACSR Horizon/12'230 185,431 669,8n 855,308 7
1557 ACSR VerticaV10'138 5,186,39~751,773 5.938.172 8
1557 ACSR VerticaV10'138 22,960,29f 5,558.269 28,518.567 9
2-795 ACSR VerticaV10'138 5,055,4H 4,166,432 9,221.850 10
1557 ACSR VerticaV10'138 11
1557 ACSR VerticaV10'138 1,615.07 273,460 1.888,537 12
795 ACSR VerticaV12'230 911,86(911,860 1,823,720 13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
50,069.29,31,248,456 81,317,748 44
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.FERC FORM NO.1 (REV. 12-03)Page 425
20080404-8002 FERC PDF (Unofficial) 04/04/2008.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, oa, Yr)
PacifiCorp (2)A Resubmission 04042008 2oo7/Q4
FOOTNOTE DATA.
!Schedule Page: 424 Line No.: 11 Column: 0
Costs included in Sunrise - Oquirrh line above.
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I FERC FORM NO. 1 (ED. 12-87)Page 45.1
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.. :t,ThIS 'ært Is:I
Date of RePort -Year/Period of Report1'l~eO~ B4ij,f~~e8b 2
FERC PDF (Unoffic ~) ~g1lIàJ)8 (Mo. Da. Yr)2007/Q4PacifiCoEnd of(2) ì1 A Resubmission 0410412008
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individuai stations in
column (f).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Seconary Tertiary
(a)(b)(c)(d)(e)
1 california
2 BELMONT DISTRIBUTION-UNATTEN 69.00 12.47
3 BIG SPRINGS DISTRIBUTION-UNATTEN 69.00 12.47
4 CANBY #2 DISTRIBUTION-UNATTEN 69.00 2.40
5 CASTELLA DISTRIBUTION-UNATTEN 69.00 2.40
6 CLEAR LAKE DISTRIBUTION-UNATTEN 69.00 12.47
7 CRESCENT CITY DISTRIBUTION-UNATTEN 12.47 4.16
8 DOG CREEK DISTRIBUTION-UNATTEN 69.00 2.40
9 DORRIS DISTRIBUTION-UNATTEN 69.00 12.47
10 FORT JONES DISTRIBUTION-UNA TTEN 69.00 12.47
11 GASQUET DISTRIBUTION.UNATTEN 115.00 12.47 .
12 GREENHORN DISTRIBUTION-UNATTEN 69.00 12.47
13 HAMBURG DISTRIBUTION.UNATTEN 69.00 2.40
14 HAPPY CAMP DISTRIBUTION-UNATTEN 69.00 12.47
15 HORNBROOK DISTRIBUTION.UNATTEN 69.00 12.47
16 INTERNATIONAL PAPER DISTRIBUTION-UNATTEN 69.00 2.40
17 LAKE EARL DISTRIBUTION-UNATTEN 69.00 12.47
18 UTTLE SHASTA DISTRIBUTION-UNATTEN 69.00 7.20
19 LUCERNE DISTRIBUTION-UNATTEN 69.00 12.47
20 MACDOEL DISTRIBUTION-UNA TTEN 69.00 20.80
. 21 MCCLOUD DISTRIBUTION.UNATTEN 69.00 12.47
22 MILLER REDWOOD DISTRIBUTION.UNATTEN 69.0C 12.47
23 MONTAGUE DISTRIBUTION-UNATTEN 69.00 12.47
24 MOUNT SHASTA DISTRIBUTION.UNA TTEN 69.00 12.47
25 NEWELL DISTRIBUTION-UNATTEN 69.00 12.47
26 NORTH DUNSMUIR DISTRIBUTION.UNATTEN 69.00 12.47
27 NORTHCREST DISTRIBUTION-UNATTEN 69.00 12.47
28 NUTGLADE DISTRIBUTION-UNATTEN 69.00 2.40
29 PATRICKS CREEK DISTRIBUTION.UNATTEN 115.00 7.20
30 PEREZ DISTRIBUTION-UNATTEN 69.00 12.47
31 REDWOOD DISTRIBUTION-UNATTEN 69.00 12.47
32 SCOTT BAR DISTRIBUTION.UNATTEN 69.00 12.47
33 SEIAD DISTRIBUTION.UNATTEN 69.00 12.47
34 SHASTINA DISTRIBUTION-UNATTEN 69.00 20.80
35 SHOTGUN CREEK DISTRIBUTION-UNA TTEN 69.00 12.47
36 SIMONSON DISTRIBUTION-UNATTEN 69.00 12.47
37 SMITH RIVER DISTRIBUTION-UNATTEN 69.00 12.47
38 SNOW BRUSH DISTRIBUTION.UNA TTEN 69.00 7.20
39 SOUTH DUNSMUIR DISTRIBUTION-UNA TTEN 69.00 4.16
40 TULELAKE DISTRIBUTION-UNA TTEN 69.00 12.47
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.FERC FORM NO.1 (ED. 12-96)Page 426
.. -:m-o-a O'4U'4~'~r6ti 2 FERC PDF (UnOffict~~'r æJ~gilJ8
I
uaie 01 Mepon
I
l earwenoa 01 Meport
(Mo, Da, Yr)End of 2007/04PacifiCorp
(2) ri A Resubmissio 04041208
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Loction of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 TUNNEL DISTRIBUTION-UNA TTEN 69.00 12.47
2 TURKEY HILL DISTRIBUTION-UNATTEN 69.00 12.47
3 WALKER BRYAN DISTRIBUTfON.UNATTEN 69.00 12.47
4 WEED DISTRIBUTION-UNATTEN 69.00 12.47
5 YUBA DISTRIBUTION-UNA TTEN 69.00 12.47
6 YUROK DISTRIBUTION.UNA TTEN 69.00 12.47
7 Total 3140.47 48.96
8 NUMBER OF SUBSTATIONS UNATTENDED - 45
9
10 ALTURAS TID-UNATTENDED 115.00 12.47 69.00
11 FALL CREEK HYDROI TID-UNATTENDED 69.00 2.30
12 YREKA T/D.UNATTENDED 115.00 12.47 69.00
13 Tot 299.00 27.24 138.00
14 NUMBER OF SUBSTATIONS TID UNATTENDED. 3
15
16 AGER TRANSMISSION.ATTEND 115.00 69.00
17 COPCO #1 HYDRO PLANT TRANSMISSION-ATTEND 69.00 2.30
18 COPCO #2 HYDRO PLANT TRANSMISSION-ATTEND 69.00 6.60
19 COPCO#2 TRANSMISSION.ATTEND 69.00 12.47
20 COPCO#2 TRANSMISSION-ATTEND 230.00 115.00
21 Total 552.00 205.37
22 NUMBER OF SUBSTATIONS TRANS ATTEND - 5
23
24 CRAG VIEW TRANSMISSION-UNATTEN 115.00 69.00
25 DEL NORTE TRANSMISSION-UNATTEN 115.00 69.00
26 IRON GATE HYDRO PLANT TRANSMISSION-UNA TTEN 69.00 6.60
27 WEED JUNCTION TRANSMISSION-UNATTEN 115.00 69.00
28 Total 414.00 213.60
29 NUMBER OF SUBSTATIONS TRANS UNATTENDED - 4
30
31 Idaho
32 ALEXANDER DISTRIBUTION.UNATTEN 46.00 12.47
33 AMMON DISTRIBUTION.UNA TTEN 69.00 12.47
34 ANDERSON DISTRIBUTION-UNATTEN 69.00 12.47
35 ARCO DISTRIBUTION-UNATTEN 69.00 12.47
36 ARIMO DISTRIBUTION-UNATTEN 46.00 12.47
37 BANCROFT DISTRIBUTION-UNATTEN 46.00 12.47
38 BELSON DISTRIBUTION.UNATTEN 69.00 12.47
39 BERENICE DISTRIBUTION-UNATTEN 69.00 12.47
40 CAMAS DISTRIBUTION-UNATTEN 69.00 12.47
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.FERC FORM NO. 1 (ED. 12-96)Page 426.1
.
1~~'ò'b't 6'4if.l~'s~Òlb2 FERC PDF (UnOffict~~') ~iÄgiP8
I
uaie 01 Hepori
I
yearwenoo 01 Hepori
PacifiCorp (Mo, Da. Yr)End of 2007/04
(2) 0 A Resubmission 0410412008
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale. may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individuai stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secndary Tertiary
(a)(b)(e)(d)(e)
1 CANYON CREEK DISTRIBUTION-UNA TTEN 69.00 24.90
2 CHESTERFIELD DISTRIBUTION-UNA TTEN 46.00 12.47
3 CINDER BUTTE DISTRIBUTION-UNA TTEN 161.00 12.47
4 CLEMENTS DISTRIBUTION-UNA TTEN 69.00 12.47
5 CLIFTON DISTRIBUTION-UNATTEN 46.00 12.47
6 COVE DISTRIBUTION-UNATTEN 46.00 6.60
7 DOWNEY DISTRIBUTION.UNA TTEN 46.00 12.47
8 DUBOIS DISTRIBUTION-UNATTEN 69.00 12.47
9 EASTMONT DISTRIBUTION-UNATTEN 69.00 12.47
10 EGIN DISTRIBUTION-UNA TTEN 69.00 12.47
11 EIGHT MILE DISTRIBUTION-UNA TTEN 46.00 12.47
12 GEORGETOWN DISTRIBUTION-UNA TTEN 69.00 12.47
13 GRACE CITY STATION DISTRIBUTION-UNA TTEN 46.00 12.47
14 HAMER DISTRIBUTION-UNATTEN 69.00 12.47
15 HAYES DISTRIBUTION-UNA TTEN 69.00 12.47
16 HENRY DISTRIBUTION-UNATTEN 46.00 12.47
17 HOLBRooD DISTRIBUTION-UNATTEN 69.00 12.47
18 HOOPES DISTRIBUTION-UNATTEN 69.00 12.47
19 HORSLEY DISTRIBUTION-UNATTEN 46.00 12.47
20 IDAHO FALLS DISTRIBUTION-UNATTEN 46.00 12.47
21 INDIAN CREEK DISTRIBUTION-UNATTEN 69.00 12.47
22 JEFFCO DISTRIBUTION-UNATTEN 69.00 24.90
23 KETLE DISTRIBUTION-UNA TTEN 69.00 24.90
24 LAVA DISTRIBUTION-UNA TTEN 46.00 12.47
25 LUND DISTRIBUTION.UNA TTEN 46.00 12.47
26 MCCAMMON DISTRIBUTION-UNA TTEN 46.00 12.47
27 MENAN DISTRIBUTION-UNATTEN 69.00 12.47
28 MERRILL DISTRIBUTION-UNA TTEN 69.00 12.47
29 MILLER DISTRIBUTION-UNATTEN 69.00 12.47
30 MONTPELIER DISTRIBUTION-UNATTEN 69.00 12.47
31 MOODY DISTRIBUTION-UNA TTEN 69.00 24.90
32 NEWDALE DISTRIBUTION-UNA TTEN 69.00 12.47
33 OSGOOD DISTRIBUTION-UNATTEN 69.00 12.47
34 PRESTON DISTRIBUTION-UNATTEN 46.00 12.47
35 RAYMOND DISTRIBUTION-UNA TTEN 69.00 12.47
36 RENO DISTRIBUTION-UNATTEN 69.00 12.47
37 REXBURG DISTRIBUTION-UNATTEN 69.00 12.47
38 RIRIE DISTRIBUTION-UNATTEN 69.00 12.47
39 ROBERTS DISTRIBUTION-UNA TTEN 69.00 12.47
40 RUDY DISTRIBUTION-UNATTEN 69.00 12.47
.
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.
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.
.FERC FORM NO.1 (ED. 12.96)Page 426.2
.,eo~ ~.rd.l~~e8b2 ---
- . :t,ThiS ~rt Is:I
Date of Report
I
YearlPeriod of Report
FERC PDF (Unoffic ~1l) ~giP8 (Mo, Da, Yr)End of 2007/04PacifiCorp(2) 0 A Resubmissio 040412008
SUBSTATIONS
1. Report below the information called for conceming substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 SAND CREEK DISTRIBUTION-UNA TTEN 69.00 12.47
2 SANDUNE DISTRIBUTION-UNATTEN 69.00 24.90
3 SHELLEY DISTRIBUTION-UNA TTEN 46.00 12.47
4 SMITH DISTRIBUTION-UNATTEN 69.00 12.47
5 SODA DISTRIBUTION-UNATTEN 138.00 7.20
6 SOUTH FORK DISTRIBUTION-UNATTEN 69.00 12.47
7 SPUD DISTRIBUTION-UNA TTEN 46.00 12.47
8 ST. CHARLES DISTRIBUTION-UNA TTEN 69.00 12.47
9 SUGAR CITY DISTRIBUTION-UNATTEN 69.00 12.47
10 SUNNYDELL DISTRIBUTION-UNA TTEN 69.00 12.47
11 TANNER DISTRIBUTION-UNATTEN 46.00 12.47
12 TARGHEE DISTRIBUTION-UNATTEN 46.00 12.47
13 THORNTON DISTRIBUTION-UNATTEN 69.00 12.47
14 UCON DISTRIBUTION-UNATTEN 69.00 12.47
15 WATKINS DISTRIBUTION-UNA TTEN 69.00 12.47
16 WEBSTER DISTRIBUTION-UNATTEN 69.00 12.47
17 WESTON DISTRIBUTION-UNATTEN 46.00 12.47
18 WINDSPER DISTRIBUTION-UNA TTEN 69.00 24.90
19 Total 4301.00 898.93
20 NUMBER OF SUBSTATIONS DIST UNATTENDED - 67
21
22 MALAD TID-UNATTENDED 138.00 46.00 12.41
23 MUD LAKE TID-UNATTENDED 69.00 12.47
24 RIGBY TID-UNATTENDED 161.00 12.47 69.00
25 SAINT ANTHONY TID-UNATTENDED 69.00 46.00 12.47
26 Total 437.00 116.94 93.94
27 NUMBER OF SUBSTATIONS TID UNATTENDED - 4
28
29 GRACE HYDRO TRANSMISSION.A TTEND 138.00 46.00 6.60
30 Total 138.00 46.00 6.60
31 NUMBER OF SUBSTATIONS TRANS ATTENDED. 1
32
33 AMPS TRANSMISSION.UNATTEN 23.00 69.00
34 ANTELOPE TRANSMISSION.UNA TTEN 230.00 161.00
35 ASHTON PLANT TRANSMISSION.UNA TTEN 46.00 2.40
36 BIG GRASSY TRANSMISSION.UNATTEN 161.00 69.00
37 BONNEVILLE TRANSMISSION-UNA TTEN 161.00 69.00
38 CARIBOU TRANSMISSION.UNATTEN 138.00 46.00
39 CONDA TRANSMISSION.UNA TTEN 138.00 46.00
40 FISH CREEK TRANSMISSION.UNA TTEN 161.00 46.00
.
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.
.
.
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.
.
.
FERC FORM NO. 1 (ED. 12-96)Page 426.3
.N'Teo~ ~4*d¡~~e8b 2 ------This 187 Is:--~
I
Year/Period of Report(Unoffic Date of ReportFERC PDF ~~ ) ~giP 8 (Mo, Da, Yr)2007/04PacifiCoEnd of
(2) A Resubmission 0410412008
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3: Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(e)(d)(e)
1 FRANKLIN TRANSMISSION-UNATTEN 138.00 46.00
2 GOSHEN TRANSMISSION-UNATTEN 345.00 161.00 46.00
3 JEFFERSON TRANSMISSION-UNATTEN 161.00 69.00
4 LIFTON HYDRO TRANSMISSION-UNATTEN 69.00 2.30
5 ONEIDA TRANSMISSION-UNATTEN 138.00 12.50
6 OVID TRANSMISSION-UNATTEN 138.00 69.00
7 SCOVILLE TRANSMISSION-UNATTEN 138.00 69.00 46.00
8 SUGARMILL TRANSMISSION-UNATTEN 161.00 46.00 69.00
9 TREASURETON TRANSMISSION-UNATTEN 23.00 138.00
10 Total 2783.00 1121.20 161.00
11 NUMBER OF SUBSTATIONS TRANS UNATTENDED - 17
12
13 Oregon
14 26TH STREET DISTRIBUTION-UNATTEN 20.80 4.16
15 35TH STREET DISTRIBUTION-UNATTEN 20.80 2.40
16 AGNESS AVE DISTRIBUTION-UNATTEN 115.00 12.47
17 ALDERWOOD DISTRIBUTION-UNATTEN 69.00 12.47
18 ARLINGTON DISTRIBUTION-UNATTEN 69.00 12.47
19 ATHENA DISTRIBUTION-UNA TTEN 69.00 12.47
20 BANDON TIE DISTRIBUTION-UNATTEN 20.80 12.47
. 21 BEACON DISTRIBUTION-UNA TTEN 69.00 12.47
22 BEALL LANE DISTRIBUTION-UNATTEN 115.00 12.47
23 BEATT DISTRIBUTION-UNA TTEN 69.00 12.47
24 BELKNAP DISTRIBUTION-UNATTEN 69.00 12.47
25 BLALOCK DISTRIBUTION-UNATTEN 69.00 12.47
26 BLOSS DISTRIBUTION-UNA TTEN 115.00 12.47
27 BLY DISTRIBUTION-UNA TTEN 69.00 12.47
28 BOISE CASCADE DISTRIBUTION-UNA TTEN 69.00 11.00
29 BONANZA DISTRIBUTION-UNATTEN 69.00 12.47
30 BOND STREET DISTRIBUTION.UNA TTEN 69.00 12.50
31 BROOKHURST DISTRIBUTION-UNATTEN 115.00 12.47
32 BROWNSVILLE DISTRIBUTION-UNA TTEN 69.00 20.80
33 BRYANT DISTRIBUTION-UNATTEN 69.00 12.47
34 BUCHANAN .DISTRIBUTION.UNATTEN 115.00 20.80
35 BUCKAROO DISTRIBUTION.UNATTEN 69.00 12.47
36 CAMPBELL DISTRIBUTION-UNA TTEN 115.00 12.47
37 CANNON BEACH DISTRIBUTION-UNA TTEN 115.00 12.47
38 CARNES DISTRIBUTION-UNA TTEN 69.00 12.47
39 CASEBEER DISTRIBUTION.UNA TTEN 69.00 20.80
40 CAVEMAN DISTRIBUTION-UNATTEN 115.00 12.47
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-96)Page 426.4
.N~eo~ oi4~,f~~e8b 2
=t,ThiS ~rt Is:I
Date of Report
I
Year/Period of ReportFERCPDF(Unoffic ~). ~glP8 (Mo, Da, Yr)End of 2007/Q4PacifiCorp(2) ñ A Resubmission 0404208
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secndary Tertiary
(a)(b)(c)(d)(e)
1 CHERRY LANE DISTRIBUTION-UNATTEN 69.00 12.47
2 CHILOQUIN MARKET DISTRIBUTION-UNATTEN 69.00 12.47
3 CHINA HAT DISTRIBUTION-UNATTEN 69.00 12.47
4 CIRCLE BLVD DISTRIBUTION-UNATTEN 115.00 20.80
5 CLEVELAND AVE DISTRIBUTION-UNATTEN 69.00 12.47
6 CLINE FALLS HYDRO DISTRIBUTION-UNATTEN 12.47 2.40
7 CLOAKE DISTRIBUTION-UNATTEN 69.00 20.80
8 COBURG DISTRIBUTION-UNATTEN 69.00 20.80
9 COLISEUM DISTRIBUTION-UNATTEN 20.80 4.16
10 COLUMBIA DSITRIBUTION-UNATTEN 115.00 12.47 57.00
11 COOS RIVER DISTRIBUTION-UNATTEN 115.00 20.80
12 COQUILLE DISTRIBUTION-UNA TTEN 115.00 20.80
13 CREEK DISTRIBUTION-UNA TTEN 69.00 34.50
14 CROOKED RIVER RANCH DISTRIBUTION-UNA TTEN 69.00 20.80
15 CROWFOOT DISTRIBUTION-UNATTEN 115.00 12.47
16 CULLY DISTRIBUTION-UNATTEN 115.00 12.47
17 CULVER DISTRIBUTION-UNA TTEN 69.00 12.47
18 CUTLER CITY DISTRIBUTION-UNA TTEN 20.80 4.16
19 DAIRY DISTRIBUTION-UNATTEN 69.00 12.47
20 DALLAS DISTRIBUTION-UNATTEN 115.00 20.80
21 DALREED DISTRIBUTION-UNATTEN 230.00 34.50
22 DESCHUTES DISTRIBUTION-UNATTEN 69.00 12.47
23 DEVILS LAKE DISTRIBUTION.UNA TTEN 115.00 20.80
24 DIXON DISTRIBUTION-UNATTEN 115.00 4.16
25 DODGE BRIDGE DISTRIBUTION-UNATTEN 69.00 20.80
26 EAST VALLEY DISTRIBUTION-UNATTEN 115.00 12.47
27 EMPIRE DISTRIBUTION-UNA TTEN 115.00 20.80
28 ENTERPRISE DISTRIBUTION-UNATTEN 69.00 12.47
29 FERN HILL DISTRIBUTION-UNATTEN 115.00 12.47
30 FIELDER CREEK DISTRIBUTION.UNA TTEN 115.00 20.80
31 FOOTHILLS DISTRIBUTION-UNA TTEN 69.00 12.47
32 FRALEY DISTRIBUTION-UNA TTEN 69.00 12.47
33 GARDEN VALLEY DISTRIBUTION-UNA TTEN 69.00 20.80
34 GAZLEY DISTRIBUTION-UNA TTEN 69.00 12.47
35 GEARHART DISTRIBUTION-UNATTEN 12.47 4.16
36 GLENDALE DISTRIBUTION-UNA TTEN 230.00 12.47
37 GLENEDEN DISTRIBUTION-UNA TTEN 20.80 4.16
38 GLIDE DISTRIBUTION-UNA TTEN 115.00 12.47
39 GOLD HILL DISTRIBUTION-UNATTEN 69.00 12.47
40 GORDON HOLLOW DISTRIBUTION-UNATTEN 69.00 12.47
.
.
.
.
.
.
.
.
.
.
FERCFORM NO.1 (ED. 12-96)Page 426.5
."~'ÒWO'M'~tr4~'èwò'b2 FERC PDF (UnOffict~~') ~r,g1f)8
I
uaie oi Hepoii
I
yearwenoo 01 Heport
(Mo, Da, Yr)End of 2007/04PacifiCorp
(2) n A Resubmission 040412008
SUBSTATIONS
1.Repor below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 GOSHEN DISTRIBUTION.UNA TTEN 115.00 20.80
2 GRANT STREET DISTRIBUTION.UNA TTEN 115.00 20.80
3 GRASS VALLEY DISTRIBUTION.UNATTEN 20.80 4.16
4 GREEN DISTRIBUTION.UNATTEN 69.00 12.47
5 GRIFFIN CREEK DISTRIBUTION.UNATTEN 115.00 12.47
6 HAMAKER DISTRIBUTION.UNA TTEN 69.00 12.47
7 HARRISBURG DISTRIBUTION.UNATTEN 69.00 20.80
8 HENLEY DISTRIBUTION.UNATTEN 69.00 12.47
9 HERMISTON DISTRIBUTION.UNATTEN 69.00 12.47
10 HILLVIEW DISTRIBUTION.UNATTEN 115.00 20.80
11 HINKLE DISTRIBUTION.UNA TTEN 69.00 12.47
12 HOLLADAY DISTRIBUTION.UNATTEN 115.00 12.47
13 HOLLYWOOD DISTRIBUTION.UNATTEN 115.00 12.47
14 HOOD RIVER DISTRIBUTION.UNATTEN 69.00 12.47
15 HORNET DISTRIBUTION.UNA TTEN 69.00 12.47
16 INDEPENDENCE DISTRIBUTION.UNATTEN 69.00 20.80
17 JACKSONVILLE DISTRIBUTION.UNA TTEN 115.00 12.47 69.00
18 JEFFERSON DISTRIBUTION.UNATTEN 69.00 20.80
19 JEROME PRAIRIE DISTRIBUTION.UNATTEN 115.00 12.47
20 JORDAN POINT DISTRIBUTION.UNATTEN 115.00 12.47
21 JOSEPH DISTRIBUTION.UNATTEN 20.80 12.47
22 JUNCTION CITY DISTRIBUTION.UNATTEN 69.00 20.80
23 KENWOO DISTRIBUTION.UNATTEN 69.00 12.47
24 KILLINGWORTH DISTRIBUTION.UNATTEN 69.00 12.47
25 KNAPPA SVENSEN DISTRIBUTION.UNA TTEN 115.00 12.47
26 LAKEPORT DISTRIBUTION.UNATTEN 69.00 12.47
27 LAKEVIEW DISTRIBUTION.UNA TTEN 69.00 12.47
28 LANCASTER DISTRIBUTION.UNATTEN 69.00 20.80
29 LEBANON DISTRIBUTION.UNATTEN 115.00 20.80
30 LINCOLN DISTRIBUTION.UNATTEN 115.00 12.47
31 LOCKHART DISTRIBUTION.UNA TTEN 115.00 20.80
32 LYONS DISTRIBUTION.UNATTEN 69.00 20.80
33 MADRAS DISTRIBUTION.UNA TTEN 69.00 12.47
34 MALLORY DISTRIBUTION.UNATTEN 115.00 12.47
35 MARYS RIVER DISTRIBUTION.UNATTEN 115.00 20.80
36 MEDCO DISTRIBUTION.UNATTEN 115.00 12.47
37 MEDFORD DISTRIBUTION.UNA TTEN 69.00 12.47
38 MERLIN DISTRIBUTION.UNA TTEN 115.00 12.47
39 MERRILL DISTRIBUTION.UNA TTEN 69.00 12.47
40 MINAM DISTRIBUTION.UNATTEN 69.00 12.47
.
.
.
.
.
.
.
.
.
.FERC FORM NO.1 (ED. 12-96)Page 426.6
.Na¡eo~ ~4ff~'BeBb 2
. :tcThlS ~rt Is:I
Date of Report
I
Year/Period of ReportFERC PDF (Uno f fi c "'~) fAgi/18 (Mo, Da, Yr)End of 2oo7/Q4PacifCorp
(2) 0 A Resubmission 041041208
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities. reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertary
(a)(b)(c)(d)(e)
1 MODOC DISTRIBUTION-UNATTEN 69.00 12.47
2 MORO DISTRIBUTION-UNATTEN 20.80 2.40
3 MURDER CREEK DISTRIBUTION-UNATTEN 115.00 20.80
4 MYRTLE CREEK DISTRIBUTION-UNA TTEN 69.0C 12.47
5 MYRTLE POINT DISTRIBUTION.UNATTEN 115.00 20.80
6 NELSCOTT DISTRIBUTION-UNATTEN 20.80 4.16
7 NEW O'BRIEN DISTRIBUTION.UNATTEN 115.00 12.47
8 OAK KNOLL DISTRIBUTION-UNATTEN 115;00 12.47
9 OAKLAND DISTRIBUTION-UNATTEN 115.00 12.47
10 ORCHARD STREET DISTRIBUTION-UNATTEN 12.41 4.16
11 OVERPASS DISTRIBUTION-UNATTEN 69.OQ 12.47
12 PALLETTE DISTRIBUTION-UNA TTEN 69.00 20.80
13 PARK STREET DISTRIBUTION-UNATTEN 115.00 12.47
14 PARKROSE DISTRIBUTION-UNATTEN 57.00 12.47
15 PENDLETON DISTRIBUTION-UNATTEN 69.00 12.47
16 PILOT ROCK DISTRIBUTION.UNA TTEN 69.00 12.47
17 POWELL BUTTE DISTRIBUTION-UNATTEN 115.00 12.47
18 PRINEVILLE DISTRIBUTION-UNATTEN 115.00 12.47
19 PROVOLT DISTRIBUTION.UNATTEN 69.00 12.47
20 QUEEN AVE DISTRIBUTION.UNATTEN .'69.00 20.80
21 RED BLANKET DISTRIBUTION.UNATTEN 69.00 4.16
22 REDMOND DISTRIBUTION-UNATTEN 115.00 12.47
23 RICH MANUFACTURING DISTRIBUTION.UNATTEN 57.00 12.47
24 RIDDLE DISTRIBUTION.UNATTEN 69.00 12.47
25 RIDDLE VENEER DISTRIBUTION-UNA TTEN 69.00 12.47
26 ROGUE RIVER DISTRIBUTION-UNA TTEN 69.00 12.47
27 ROSEBURG DISTRIBUTION-UNATTEN 115.00 20.80
28 ROSS AVE DISTRIBUTION-UNATTEN 69.00 12.47
29 ROXY DISTRIBUTION-UNATTEN 115.00 12.50
30 RUCH DISTRIBUTION.UNATTEN 69.00 12.47
31 RUNNING Y DISTRIBUTION-UNATTEN 69.00 20.80
32 RUSSELLVILLE DISTRIBUTION.UNA TTEN 115.00 12.47
33 SAGE ROAD DISTRIBUTION-UNATTEN 115.00 12.47
34 SCENIC DISTRIBUTION-UNA TTEN 115.00 12.47 69.00
35 SCIO DISTRIBUTION-UNATTEN 69.00 12.47
36 SEASIDE DISTRIBUTION-UNATTEN 115.00 12.47
37 SELMA DISTRIBUTION-UNATTEN 115.00 12.47
38 SHASTA WAY DISTRIBUTION-UNATTEN 12.47 4.16
39 SHEVLIN PARK DISTRIBUTION-UNATTEN 69.00 12.50
40 SIMTAG BOOSTER PUMP DISTRIBUTION-UNATTEN 34.50 4.16
.
.
.
.
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.
.
.
.
.FERC FORM NO.1 (ED. 12-96)Page 426.7
.---This~rtIS:N~eO~ ~4~~ie8b2 (Unoffic Date of Report Year/Period of ReportFERC PDF ~) ~giP8 (Mo. Da. Yr)End of 2007/04PacifiCo
(2) Õ A Resubmission 040412008
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (t).
Une VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertary
(a)(b)(c)(d)(e)
1 SOUTH DUNES DISTRIBUTION-UNA TTEN 115.00 12.47
2 SOUTHGATE DISTRIBUTION-UNATTEN 69.00 20.80
3 SPRAGUE RIVER DISTRIBUTION-UNATTN 69.00 12.47
4 STATE STREET DISTRIBUTION-UNATTEN 115.00 20.80
5 STAYTON DISTRIBUTION-UNATTEN 69.00 12.47
6 STEAMBOAT DISTRIBUTION-UNATTEN 115.00 7.20
7 STEVENS ROAD DISTRIBUTION-UNA TTEN 115.00 20.80
8 SUTHERLIN DISTRIBUTION-UNATTEN 115.00 12.47
9 SWEETHOME DISTRIBUTION-UNATTEN 115.00 20.80
10 TAKELMA DISTRIBUTION-UNA TTEN 115.00 20.80
11 TALENT DISTRIBUTION-UNATTEN 69.00 12.47
12 TEXUM DISTRIBUTION-UNATTEN 69.00 12.47
13 TILLER DISTRIBUTION.UNATTEN 115.00 12.47
14 TOLO DISTRIBUTION-UNA TTEN 69.00 12.47
15 UMAPINE DISTRIBUTION-UNATTEN 69.00 12.47
16 UMATILL DISTRIBUTION.UNATTEN'69.00 12.47
17 US PLYWOOD DISTRIBUTION-UNATTEN 20.80 4.16
18 VERNON DISTRIBUTION-UNA TTEN 69.00 12.47
19 VILAS DISTRIBUTION-UNATTEN 115.00 12.47
20 VILLAGE GREEN DISTRIBUTION-UNATTEN 115.00 20.80
'21 VINE STREET DISTRIBUTION.UNA TTEN 69.00 20.80
22 WALLOWA DISTRIBUTION.UNA TTEN 69.00 12.47
23 WARM SPRINGS DISTRIBUTION-UNA TTEN 69.00 20.80
24 WARRENTON DISTRIBUTION.UNATTEN 115.00 12.47
25 WASCO DISTRIBUTION-UNATTEN 20.80 4.16
26 WECOMA BEACH DISTRIBUTION-UNA TTEN 20.80 4.16
27 WESTERN KRAFT DISTRIBUTION.UNATTEN 115.00 12.47
28 WESTON DISTRIBUTION-UNA TTEN 69.00 12.47
29 WESTSIDE HYDRO DISTRIBUTION-UNATTEN 69.00 12.47
30 WEYERHAUSER DISTRIBUTION-UNATTEN 69.00 12.47
31 WHITE CITY DISTRIBUTION-UNATTEN 115.00 12.47
32 WILLOW COVE DISTRIBUTION-UNA TTEN 34.50 4.16
33 WINSTON DISTRIBUTION-UNA TTEN 69.00 12.47
34 YOUNGS BAY DISTRIBUTION-UNA TTEN 115.00 12.47
35 Total 15039.28 2472.84 195.00
36 NUMBER OF SUBSTATIONS DIST UNATENDED -181
37
38 ALBINA TID-UNATTENDED 115.00 12.47 69.00
39 APPLEGATE TID-UNATTENDED 115.00 69.00 12.47
40 ASHLAND TID-UNATTENDED 115.00 69.00 12.47
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-96)Page 426.8
.
N'Peo~ Qi4tt~(~f8b 2
:Fnis~I
Date of Report
I
Year/Period of ReportFERC PDF (Unoffic ~) .QlP8 (Mo, Da. Yr)End of 2oo7/Q4PacifiCorp
(2) Õ A Resubmission 04/0412008
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 BEND PLANT TID-UNATTENDED 69.00 4.16 12.47
2 CAVE JUNCTION TID-UNATTENDED 115.00 12.47 69.00
3 HAZELWOOD TID-UNATTENDED 115.00 69.00 12.47
4 KNOTT TID- UNATTENDED 115.00 12.47 57.00
5 MILE HI TID-UNATTENDED 115.00 69.00 12.47
6 PILOT BUTTE TID-UNATTENDED 230.00 69.00 12.47
7 WINCHESTER TID-UNATTENDED 115.00 12.47 69.00
8 Total 1219.00 399.04 338.82
9 NUMBER OF SUBSTATIONS TID UNATTENDED -10
10
11 CLEARWATER #1 HYDRO PLANT TRANSMISSION-ATTEND 138.00 6.90
12 CLEARWATER #2 HYDRO PLANT TRANSMISSION-ATTEND 138.00 12.00
13 FISH CREEK HYDRO TRANSMISSION-ATTEND 115.00 6.90
14 JC BOYLE HYDRO TRANSMISSION-ATTEND 230.00 11.00
15 LEMOLO #1 HYDRO TRANSMISSION-ATTEND 115.00 12.47
16 LEMOLO #2 HYDRO TRANSMISSION-ATTEND 115.00 12.00
17 PROSPECT 1 HYDRO TRANSMISSION-ATTEND 69.00 2.30
18 PROSPECT 2 HYDRO TRANSMISSION-ATTEND 69.00 6.60
19 PROSPECT 3 HYDRO TRANSMISSION-ATTEND 69.00 12.47
20 TOKETEE HYDRO TRANSMISSION-ATTEND 115.00 6.90 :
21 Total 1173.00 89.54
22 NUMBER OF SUBSTATIONS TRANS ATTENDED -10
23
24 BEND PLANT TRANSMISSION-UNA TTEN 4.16 2.40
25 CALAPOOYA TRANSMISSION-UNATTEN 230.00 69.00
26 CHILOQUIN TRANSMISSION-UNA TTEN 230.00 115.00 69.00
27 COLD SPRINGS TRANSMISSION-UNATTEN 230.00 69.00
28 COVE TRANSMISSION-UNATTEN 230.00 69.00
29 DAYS CREEK TRANSMISSION-UNA TTEN 115.00 69.00
30 DIAMOND HILL TRANSMISSION-UNATTEN 230.00 69.00
31 DIXONVILLE 115/230 TRANSMISSION-UNATTEN 230.00 115.00 69.00
32 DIXONVILLE 500 TRANSMISSION-UNATTEN 50.00 230.00
33 EAGLE POINT HYDRO TRANSMISSION-UNA TTEN 115.00 2.40
34 EAST SlOE HYDRO TRANSMISSION-UNATTEN 46.00 12.47
35 FISH HOLE TRANSMISSION-UNATTEN 115.00 69.00
36 FRY TRANSMISSION-UNA TTEN 230.00 115.00
37 GRANTS PASS TRANSMISSION-UNA TTEN 230.00 115.00 69.00
38 GREEN SPRINGS PLANT TRANSMISSION-UNATTEN 115.00 69.00
39 HURRICANE TRANSMISSION-UNATTEN 230.00 69.00 2.40
40 ISTHMUS TRANSMISSION-UNA TTEN 230.00 115.00
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 426.9
."~'Ò"'o'M'4tr~'è"6'b2 FERC PDF
:t,JIII~~II~;I
uate or Heport
I
YearlPenod or Report(Uno f fi c ,,1l) ~giP 8 (Mo. Da. Yr)End of 2007104PacifiCorp
(2) n A Resubmission 0410412008
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Loction of Substation Character of Substation
Pnmary Secondary Tertiary
(a)(b)(e)(d)(e)
1 KENNEDY TRANSMISSION-UNATTEN 69.00 57.00
2 KLAMATH FALLS TRANSMlSSION-UNATTEN 230.00 69.00
3 LONE PINE TRANSMISSION-UNATTEN 230.00 115.00 69.00
4 MERIDIAN TRANSMISSION-UNATTEN 500.00 230.00
5 MONPAC TRANSMISSION-UNATTEN 115.00 69.00
6 PONDEROSA TRANSMISSION-UNATTEN 230.00 115.00
7 POWERDALE PLANT TRANSMISSION-UNATTEN 69.00 7.20
8 PROSPECT CENTRAL TRANSMISSION-UNATTEN 115.00 69.00
9 ROBERTS CREEK TRANSMISSION-UNATTEN 115.00 69.00
10 SLIDE CREEK HYDRO TRANSMISSION-UNATTEN 115.00 7.00
11 SODA SPRINGS HYDRO TRANSMISSION-UNATTEN 115.00 7.00
12 TROUTDALE TRANSMISSION-UNATTEN 230.00 . 115.00 69.00
13 TUCKER TRANSMISSION-UNATTEN 115.00 69.00
14 WALLOWA FALLS HYDRO TRANSMISSION-UNATTEN 20.80
15 Total 5578.96 2372.47 347,40
16 NUMBER OF SUBSTATIONS TRANS UNATTEND - 31
17
18 Utah
19 106TH SOUTH DISTRIBUTION-UNATTEN 138.00 12.50
20 118TH SOUTH DISTRIBUTION-UNA TTEN 138.00 12,47
21 70TH SOUTH DISTRIBUTION-UNATTEN '138.00 12.47
22 ALTAVIEW DISTRIBUTION-UNATTEN 46.00 12,47
23 AMALGA DISTRIBUTION-UNATTEN 46.00 12,47
24 AMERICAN FORK DISTRIBUTION-UNATTEN 138.00 12,47
25 ARAGONITE DISTRIBUTION-UNATTEN 46.00 7.20
26 AURORA DISTRIBUTION-UNATTEN 46;00 12,47
27 BANGERTER DISTRIBUTION-UNA TTEN 138.00 12,47
28 BEAR RIVER DISTRIBUTION-UNATTEN 46.00 12,47
29 BENJAMIN DISTRIBUTION-UNATTEN 46.00 12,47
30 BINGHAM DISTRIBUTION-UNATTEN 46.00 12,47
31 BLUE CREEK DISTRIBUTION-UNATTEN 46.00 12,47
32 BLUFF DISTRIBUTION-UNATTEN 69.00 12,47
33 BLUFFDALE DISTRIBUTION-UNA TTEN 46.00 12,47
34 BOTHWELL DISTRIBUTION-UNA TTEN 46.00 12.47
35 BOX ELDER DISTRIBUTION-UNA TTEN 46.00 12,47
36 BRIAN HEAD DISTRIBUTION-UNA TTEN 46.00 12,47
37 BRICKYARD DISTRIBUTION.UNA TTEN 46.00 12,47
38 BRIGHTON DISTRIBUTION.UNATTEN 46.00 24.90
39 BROOKLAWN DISTRIBUTION-UNATTEN 46.00 12,47
40 BRUNSWICK DISTRIBUTION-UNATTEN 46.00 12,47
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 426.10
.. ;tcinis~is:I
Date of Report
I
Year/Period of Report -1..~rò~o\M'4''d.l~%e8b2 FERC PDF
PaeifiCorp (Unoffic ai~) ~giP8 (Mo, Da, Yr)End of 2007/04
(2) A Resubmission 04/0412008
SUBSTATIONS
1.Report below the information called forconceming substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secdary Tertiary
(a)(b)(e)(d)(e)
1 BURTON DISTRIBUTION-UNATTEN 34.50 12.47
2 BUSH DISTRIBUTION-UNATTEN 46.00 12.47
3 CANNON DISTRIBUTION-UNA TTEN 46.00 12.47
4 CANYONLANDS DISTRIBUTION-UNATTEN 69.00 12.47
5 CAPITOL DISTRIBUTION-UNATTEN 46.00 12.47
6 CARBIDE DISTRIBUTION-UNA TTEN 46.00 7.20
7 CARBONVILLE DISTRIBUTION-UNATTEN 46.00 12.47
8 CARLISLE DISTRIBUTION-UNATTEN 138.00 12.50
9 CASTO SUBSTATION DISTRIBUTION-UNA TTEN 46.00 12.47
10 CENTENNIAL DISTRIBUTION.UNATTEN 138.00 12.47
11 CENTERVILLE DISTRIBUTION.UNATTEN 46.00 12.47
12 CENTRAL DISTRIBUTION-UNATTEN 46.00 12.47
13 CHAPEL HILL DISTRIBUTION-UNATTEN 138.00 12.47
14 CHERRYWOOD DISTRIBUTION-UNATTEN 138.00 12.47
15 CIRCLEVILLE DISTRIBUTION.UNATTEN 69.00 12.47
16 CLEAR CREEK DISTRIBUTION.UNA TTEN 46.00 12.47
17 CLEARLAKE DISTRIBUTION-UNA TTEN 46.00 12.47
18 CLEARFIELD SOUTH DISTRIBUTION.UNA TTEN 138.00 12.47
19 CLINTON DISTRIBUTION.UNA TTEN 138.00 12.47
20 CLIVE DISTRIBUTION.UNATTEN 46.00 12.47
21 COALVILLE DISTRIBUTION-UNATTEN 46.00 12.47
22 COLD WATER CANYON DISTRIBUTION.UNATTEN 138.00 12.47
23 COLEMAN DISTRIBUTION.UNATTEN 138.00 69.00 12.47
24 COLTON WELL DISTRIBUTION-UNATTEN 46.00 12.47
25 CORINNE DISTRIBUTION.UNATTEN 46.00 12.47
26 COVE FORT DISTRIBUTION.UNA TTEN 46.00 12.47
27 CRESCENT JUNCTION DISTRIBUTION-UNATTEN 46.00 7.20
28 CROSS HOLLOW DISTRIBUTION-UNATTEN 138.00 12.47
29 CUDAHY DISTRIBUTION-UNATTEN 138.00 12.47
30 DAMMERON VALLEY DISTRIBUTION-UNATTEN 34.50 12.47
31 DECKER LAKE DISTRIBUTION-UNA TTEN 138.00 12.47
32 DELLE .DISTRIBUTION-UNA TTEN 46:00 12.47
33 DELTA DISTRIBUTION.UNATTEN 46.00 12.47
34 DESERET DISTRIBUTION-UNATTEN 46.00 4.16
35 DEWEYVILLE DISTRIBUTION-UNA TTEN 46.00 12.47
36 DIMPLE DELL DISTRIBUTION-UNA TTEN 138.00 12.47
37 DIXIE DEER DISTRIBUTION-UNA TTEN 34.50 12.47
38 DRAPER ' DISTRIBUTION.UNATTEN 46.00 12.47
39 DUMAS DISTRIBUTION-UNA TTEN 138.00 12.47
40 EAST BENCH DISTRIBUTION.UNA TTEN 138.00 12.47
.
.
.
.
.
.
.
.
.
.FÉRC FORM NO. 1 (ED. 12-96)Page 426.11
.
1'I'Ttb~ S4~,f~(lf8b 2 FERC PDF
'iinis~rtls:I
Date of Report
I
Year/Period of Report(Unoffic ~1)) IAgiP8 (Mo. Da. Yr)2007/04PaeifiCo
(2) ri A Resubmission 0410412008 End of
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Seconry Tertary
(a)(b)(e)(d)(e)
1 EAST HYRUM DISTRIBUTION-UNATTEN 46.00 12.47
2 EAST LAYTON DISTRIBUTION-UNATTEN 138.00 12.47
3 EAST MILLCREEK DISTRIBUTION-UNATTEN 46.00 12.47
4 EDEN DISTRIBUTION-UNATTEN 46.00 12.47
5 ELBERTA DISTRIBUTION-UNATTEN 46.00 12.47
6 ELK MEADOWS DISTRIBUTION-UNATTEN 46.00 12.47
7 ELSINORE DISTRIBUTION-UNATTEN 46.00 12.47
8 EMERY CITY DISTRIBUTION-UNATTN 69.00 12.47
9 EMIGRATION DISTRIBUTION-UNA TTEN 46.00 12.47
10 ENOCH DISTRIBUTION-UNATTEN 138.00 12.47
11 ENTERPRISE VALLEY DISTRIBUTION-UNATTEN 138.00 12.47
12 EUREKA DISTRIBUTION-UNATTEN 46.00 12.47
13 FARMINGTON DISTRIBUTION-UNATTEN 138.00 12.47
14 FAYETTE DISTRIBUTION-UNATTEN 46.00 12.47
15 FERRON DISTRIBUTION-UNATTEN 46.00 12.47
16 FIELDING DlSTRIBUTION-UNATTEN 46.00 12.00
17 FIFTH WEST DISTRIBUTION-UNATTEN 138.00 12.47
18 FLUX DISTRIBUTION-UNATTEN 46.00 12.47
19 FOOL CREEK DISTRIBUTION-UNATTEN 46.00 12.47
20 FOUNTAIN GREEN DISTRIBUTION-UNATTEN 46.00 12.47
'21 FREEDOM DISTRIBUTION-UNATTEN 46.00 7.20
22 FRUIT HEIGHTS DISTRIBUTION-UNATTEN 46.00 12.47
23 GARDEN CITY DISTRIBUTION-UNATTEN 46.00 12.47
24 GATEWAY DISTRIBUTION-UNATTEN 69.00 12.47
25 GORDON AVENUE DISTRIBUTION-UNA TTEN 138.00 12.50
26 GOSHEN DISTRIBUTION-UNATTEN 46.00 12.47
27 GRANGER DISTRIBUTION-UNA TTEN 46.00 12.47
28 GRANTSVILLE DISTRIBUTION-UNATTEN 46.00 12.47
29 GREEN RIVER DISTRIBUTION-UNATTEN 46.00 12.47
30 GROW DISTRIBUTION-UNATTEN 138.00 12.47 46.00
31 GUNLOCK HYDRO DISTRIBUTION-UNATTEN 34.50 2.30
32 GUNNISON DISTRIBUTION-UNATTEN 46.00 12.47
33 HAMILTON DISTRIBUTION.UNATTEN 34.50 12.47
34 HAMMER DISTRIBUTION-UNA TTEN 138.00 12.47
35 HAVASU DISTRIBUTION-UNA TTEN 69.00 12.47
36 HELPER CITY DISTRIBUTION-UNA TTEN 46.00 4.16
37 HENEFER DISTRIBUTION-UNA TTEN 46.00 12.47
38 HIAWATHA DISTRIBUTION-UNATTEN 46.00 4.16
39 HIGHLAND DIST DISTRIBUTION.UNA TTEN 46.00 12.47
40 HOGGARD DISTRIBUTION-UNA TTEN 138.00 12.47
.
.
.
.
.
I
.
.
.
.
.FERC FORM NO.1 (ED. 12-96)Page 426.12
.NCleocg ~4W2~~eBb 2 (unoffic This~rtIS:Date of Report
\
Yearwenoa Ul n,,~"
FERC PDF ai~ ) ~git) 8 (Mo, Da, Yr)End of 2oo7/Q4
PacifiCorp (2) ñ A Resubmission
04/041208
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations With capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line
VOLTAGE (In MVa)
No.Name and Loction of Substation Charaåer of Sub~ation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 HOGLE
DISTRIBUTION-UNATIEN 46.00 12.47
2 HOLDEN
DISTRIBUTION-UNATIEN 46.00 12.47
3 HOLLADAY
DISTRIBUTION-UNATIEN 46.00 12.47
4 HUNTER
DISTRIBUTION-UNATIEN 46.00 12.47
5 HUNTINGTON CITY
DISTRIBUTION-UNATIEN 69.00 12.47
6 HURRICANE FIELDS
DISTRIBUTION-UNATIEN 34.50 12.47
7 IRON MOUNTAIN
DISTRIBUTION-UNA TIEN
34.50 7.20
8 IRON SPRINGS
DISTRIBUTION-UNATIEN 34.50 12.47
9 IRONTON
DISTRIBUTION-UNATIEN 46.00 12.47
10 IVINS
DISTRIBUTION-UNATIEN 34.50 12.47 .
11 JORDAN NARROWS
DlSTRIBUTION-UNATIEN 46.00 2.40
12 JORDAN PARK
DISTRIBUTION-UNA TIEN
138.00 12.47
13 JORDANELLE
DISTRIBUTION-UNATIEN 138.00 12.47
14 JUAB
DISTRIBUTION-UNA TIEN
46.00 12.47
15 JUNCTION
DISTRIBUTION-UNA TIEN
69.00 12.47
16 KAIBAB
DISTRIBUTION-UNATIEN 69.00 12.47
17 KAMAS
DISTRIBUTION-UNA TIEN
46.00 12.47
18 KANARRAVILLE
DISTRIBUTION-UNA TIEN 34.50 12.47
19 KEARNS
DISTRIBUTION-UNATIEN 138.00 12.47
20 KENSINGTON
DISTRIBUTION-UNATIEN 46.00 4.16
21 LAKE PARK
DISTRIBUTION-UNATIEN 138.00 12.47
22 LARK
DISTRIBUTION-UNATIEN 46.00 12.47
23 LASAL
DISTRIBUTION-UNATIEN 69.00 12.47
24 LAYTON
DISTRIBUTION-UNATIEN 46.00 12.47
25 LEGRANDE
DISTRIBUTION-UNA TIEN
46.00 12.47
26 LEWISTON
DISTRIBUTION-UNA TIEN
46.00 12.47
27 LINCOLN
DISTRIBUTION-UNA TIEN
46.00 12.47
28 LINDON
DISTRIBUTION-UNA TIEN
46.00 12.47
29 LISBON
DISTRIBUTION-UNATIEN 69.00 12.47
30 L1TILE MOUNTAIN
DISTRIBUTION-UNA TIEN 46.00 12.47
31 LOAFER
DISTRIBUTION-UNA TIEN 46.00 12.47
32 LOGAN CANYON
DISTRIBUTION-UNATIEN 46.00 7.20
33 LONETREE
DISTRIBUTION-UNA TIEN
34.50 12.47
34 LOWER BEAVER
DISTRIBUTION-UNATIEN
46.00 6.60
35 LYNNDYL
DISTRIBUTION-UNATIEN 46.00 12.47
36 MAESER
DISTRIBUTION-UNATIEN 69.00 12.47
37 MAGNA
DISTRIBUTION-UNATIEN 138.00 12.47
38 MANILA
DISTRIBUTION-UNA TIEN
46.00 12.47
39 MANTUA
DISTRIBUTION-UNATIEN 46.00 12.47
40 MAPLETON
DISTRIBUTION-UNA TIEN
46.00 12.47
.
.
.
.
.
.
.
.
.
.
FERC FORM NO.1 (ED. 12-96)Page 426.13
.. ":m-oll 0 '4tr4':.'~rO'b 2 FERC PDF (UnOffictl~l) '~~giIJ8
I
uaie 01 Hepori
I
yearwenoa Of Hepon
PacifiCorp (Mo, Da, Yr)End of 2007/04
(2) ri A Resubmission 040412008
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale. may be grouped according
to functional character. but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page. summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)
No.Name and Loction of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 MARRIOTI DISTRIBUTION-UNA TIEN 46.00 12.47
2 MARYSVALE DISTRIBUTION-UNATIEN 46.00 12.47
3 MATHIS DISTRIBUTION.UNATIEN 46.00 12.47
4 MCCORNICK DISTRIBUTION.UNA TIEN 46.00 12.47
5 MCKAY DISTRIBUTION-UNATIEN 46.00 12.47
6 MEADOWBROOK DISTRIBUTION-UNATIEN 138.00 12.47 46.00
7 MEDICAL DISTRIBUTION-UNATIEN 46.00 12.47
8 MELLING DISTRIBUTION-UNATIEN 34.5C 4.16
9 MIDLAND DISTRIBUTION-UNA TIEN 138.00 12.47
10 MIDVALE DISTRIBUTION-UNATIEN 46.00 12.47
11 MILFORD DISTRIBUTION.UNATIEN 46.00 12.47
12 MILFORD TV DISTRIBUTION.UNA TIEN 46.00 7.20
13 MILLVILLE DISTRIBUTION.UNATIEN 46.00 12.47
14 MINERSVILLE DISTRIBUTION-UNATIEN 46.00 12.47
15 MOAB CITY DISTRIBUTION-UNA TIEN 69:00 12.47
16 MONTEZUMA DISTRIBUTION.UNATIEN 69.00 12.47
17 MOORE DISTRIBUTION-UNA TIEN 69.00 12.47
18 MORGAN DISTRIBUTION-UNATIEN 46.00 4.16
19 MORONI DISTRIBUTION-UNATIEN 46.00 12.47
20 MORTON COURT DISTRIBUTION-UNA TIEN 138.00 12.47
21 MOSS JUNCTION DISTRIBUTION-UNA TIEN 46.00 12.47
22 MOUNTAIN DELL DISTRIBUTION-UNA TIEN 46:00 12.47
23 MOUNTAIN GREEN DISTRIBUTION-UNA TIEN 46.00 12.47
24 MYTON DISTRIBUTION-UNA TIEN 69.00 12.47
25 NEW HARMONY DISTRIBUTION.UNA TIEN 69.00 12.47
26 NEWGATE DISTRIBUTION-UNA TIEN 46.00 12.47
27 NEWTON DISTRIBUTION.UNATIEN 46.00 12.47
28 NIBLEY DISTRIBUTION-UNA TIEN 46.00 24.90
29 NORTH BENCH DISTRIBUTION-UNATIEN 46.00 12.47
30 NORTH CEDAR DISTRIBUTION.UNA TIEN 34.50 4.16
31 NORTH FIELDS DISTRIBUTION-UNA TIEN 46.00 12.47
32 NORTH LOGAN DISTRIBUTION-UNA TIEN 46.00 12.47
33 NORTH OGDEN DISTRIBUTION-UNA TIEN 46.00 12.47
34 NORTH SALT LAKE DISTRIBUTION-UNA TIEN 46.00 12.47
35 NORTHEAST DISTRIBUTION-UNA TIEN 46.00 12.47
36 NORTHRIDGE DISTRIBUTION-UNATIEN 46.00 12.47
37 OAKLAND AVE DISTRIBUTION-UNA TIEN 46.00 12.47
38 OAKLEY DISTRIBUTION-UNA TIEN 46.0C 12.47
39 OGDEN DEFENSE DEPOT DISTRIBUTION-UNA TIEN 46.00 12.47
40 OLYMPUS DISTRIBUTION-UNA TIEN 46.00 12.47
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 426.14
.
Na¿eo~ oi4~~9f8b 2 FERC PDF
. :t,inis~rtls:I
Date of Report
I
YearfPenod of Report(Unoffic ~:~) ~gi1J8 (Mo, Da, Yr)2007/04PacifiCorp(2) 0 A Resubmission 040412008 End of
SUBSTATIONS
1.Report below the informatiOn called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Pnmary Secdary Tertary
(a)(b)(c)(d)(e)
1 OPHIR DISTRIBUTION-UNATIN 46.00 12.47
2 ORANGE DISTRIBUTION-UNATIEN 46.00 12.47
3 ORANGEVILLE DISTRIBUTION-UNATIEN 69.00 12.47
40REM DISTRIBUTION-UNATIEN 46.00 12.47
5 OREMET DISTRIBUTION-UNATIEN 115.00 12.47
6 PACK CREEK RESERVOIR DISTRIBUTION.UNATIEN 46.00 12.47
7 PANGUITCH DISTRIBUTION.UNATIEN 69.00 12.47
8 PARIETIE STATION DISTRIBUTION-UNATIEN 69.00 24.90
9 PARK CITY DISTRIBUTION-UNATIEN 46.00 12.47
10 PARKWAY DISTRIBUTION-UNATIEN 138.00 12.47
11 PARLEYS DISTRIBUTION.UNATIEN 46.00 12.47
12 PELICAN POINT DISTRIBUTION-UNATIEN 46.00 12.47
13 PINE CANYON DISTRIBUTION-UNATIEN 138.00 12.47
14 PINE CREEK DISTRIBUTION-UNATIEN 46.00 12.47
15 PINNACLE DISTRIBUTION.UNATIEN 46.00 12.47
16 PLAIN CITY DISTRIBUTION-UNATIEN 138.00 12.47
17 PLEASANT GROVE DISTRIBUTION-UNATIEN 46.00 12.47
18 PLEASANT VIEW DISTRIBUTION-UNATIEN 46.00 12.47
19 PORTER ROCKWELL DISTRIBUTION-UNATIEN 138.00 12.47
20 PROMONTORY DISTRIBUTION-UNATIEN 46.00 12.47
21 QUAIL CREEK DISTRIBUTION.UNATIEN 34.50 12.47
22 QUARRY DISTRIBUTION.UNATIEN 138.00 12.47
23 QUITCHAPA DISTRIBUTION-UNATIEN 34.50 12.47
24 RAINS DISTRIBUTION-UNATIEN 46.00 7.20
25 RANDOLPH DISTRIBUTION-UNATIEN 46.00 12.47
26 RASMUSON DISTRIBUTION-UNATIEN 46.00 12.47
27 RATILESNAKE DISTRIBUTION.UNATIEN 69.00 24.90
28 RED MOUNTAIN DISTRIBUTION-UNA TIEN 69.00 34.50
29 RED ROCK DISTRIBUTION-UNA TIEN 69.00 4.16
30 REDWOOD DISTRIBUTION-UNA TIEN 46.00 12.47
31 RESEARCH PARK DISTRIBUTION-UNA TIEN 46.00 12.47
32 RICH DISTRIBUTION.UNA TIEN 69.00 12.47
33 RICHFIELD DISTRIBUTION.UNATIEN 46.00 12.47
34 RICHMOND DISTRIBUTION.UNATIEN 46.00 12.47
35 RIDGELAND DISTRIBUTION-UNATIEN 138.00 12.47
36 RITER DISTRIBUTION.UNA TIEN 46.00 12.47
37 ROCK CANYON DISTRIBUTION-UNA TIEN 69.00 12.47
38 ROCKVILLE DISTRIBUTION-UNATIEN 34.50 12.47
39 ROCKY POINT DISTRIBUTION-UNA TIEN 138.00 13.20
40 ROSE PARK DISTRIBUTION.UNATIEN 46.00 12.47
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 426.15
.NaflMil ~iItl¿~~e8b 2 --' -~ThÎs ~rt Is: ....--Date of Report
I
Year/Period of ReportFERCPDF (Unoffic ~~) ~giP8 (Mo, Da, Yr)2oo7/Q4PacifiCorp(2) n A Resubmission 04042008 End of
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
Name and Loction of Substation Character of SubstationNo.Pnmary Secondry Tertiary
(a)(b)(c)(d)(e)
1 ROYAL DISTRIBUTION-UNATIEN 46.00 4.16
2 SALINA DISTRIBUTION-UNATIEN 46.00 12.47
3 SANDY DISTRIBUTION-UNA TIEN 138.00 12.47
4 SARATOGA DISTRIBUTION-UNATIEN 138.00 12.47
5 SCIPIO DISTRIBUTION-UNA TIEN 46.00 12.47
6 SCOFIELD RESERVOIR DISTRIBUTION-UNATIEN 46.00 7.20
7 SCOFIELD DISTRIBUTION-UNATIEN 46.00 12.47
8 SECOND STREET DISTRIBUTION-UNATIEN 46.00 12.47
9 SEVEN MILE DISTRIBUTION-UNATIEN 46.00 12.47
10 SHARON DISTRIBUTION-UNA TIEN 46.00 12.47
11 SHIVWITS DISTRIBUTION-UNATIEN 34.50 4.16
12 SIXTH SOUTH DISTRIBUTION-UNATIEN 46.00 12.47
13 SKULL POINT DISTRIBUTION-UNA TIEN 46.00 12.47
14 SNARR DISTRIBUTION-UNA TIEN 46.00 12.47
15 SNOWVILLE DISTRIBUTION-UNATIEN 69.00 12.47
16 SNYDERVILLE DISTRIBUTION-UNATIEN 138.00 12.47
17 SOLDIER SUMMIT DISTRIBUTION-UNA TIEN 69.00 12.47
18 SOUTH JORDAN DISTRIBUTION-UNATIEN 138.00 12.47
19 SOUTH MILFORD DISTRIBUTION-UNATIEN 46.00 12.47
20 SOUTH MOUNTAIN DISTRIBUTION-UNATIEN 138.00 12:47
, 21 SOUTH OGDEN DISTRI¡aUTION-UNATIEN 46.00 12.47
22 SOUTH PARK DISTRIBUTION-UNATIEN 46.00 12.47
23 SOUTH WEBER DISTRIBUTION-UNATIEN 138.00 12.47
24 SOUTHEAST DISTRIBUTION-UNATIEN 138.00 12.47 46.00
25 SOUTHWEST DISTRIBUTION-UNATIEN 46.00 12.47
26 SPANISH VALLEY DISTRIBUTION-UNATIEN 69.00 12.47
27 SPRINGDALE DISTRIBUTION-UNATIEN 34.50 12.47
28 ST. JOHNS DISTRIBUTION-UNATIEN 46.00 12.47
29 STAIRS DISTRIBUTION-UNATIEN 12.47 2.40
30 STANSBURY DISTRIBUTION-UNATIEN 46.00 12.47
31 SUMMIT CREEK DISTRIBUTION-UNATTN 138.00 12.47
32 SUMMIT PARK DISTRIBUTION-UNA TIEN 46.00 12.47
33 SUNRISE DISTRIBUTION-UNATIEN 138.00 12.47
34 SUPERIOR DISTRIBUTION-UNATIEN 69.00 12.47
35 SUTHERLAND DISTRIBUTION-UNATIEN 46.00 12.47
36 TAYLOR DISTRIBUTION-UNATIEN 46.00 12.47
37 THIEF CREEK DISTRIBUTION-UNATIEN 138.00 24.90
38 THIRD WEST DISTRIBUTION-UNATIEN 46.00 12.47
39 THIRTEENTH SOUTH DISTRIBUTION-UNA TIEN 46.00 12.47
40 THOMPSON DISTRIBUTION-UNA TIEN 46.00 4.16
.
.
.
.
.
.
.
.
.
.FERC FORM NO.1 (ED. 12-96)Page 426.16
.N~?M~ ~rd4'~ie8b 2
:t~iSl~IS:I
Date ot Heport
I
yearl"'enoa OJ nepori
FERC PDF (Unoffic ) ~gHP8 (Mo. Da, Yr)2007/04PacifiCorpEnd of
(2) A Resubmission 0410412008
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
1 TOOELE DEPOT DISTRIBUTION-UNATIEN 46.00 12.50
2 TOQUERVILLE DISTRIBUTION-UNAIEN 69.00 12.47 34.50
3 TRI CITY DISTRIBUTION-UNATIEN 138.00 12.47
4 TWENTYHIRD STREET DISTRIBUTION-UNATIEN 46.00 12.47
5 UINTAH DISTRIBUTION-UNATIEN 46.00 12.47
6 UNION DISTRIBUTION-UNATIEN 46.00 12.47
7 UNIVERSITY DISTRIBUTION-UNATIEN 46.00 4.16
8 VALLEY CENTER DISTRIBUTION-UNATIEN 46.00 12.47
9 VERMILLION DISTRIBUTION-UNATIEN 46.00 12.47
10 VERNAL DISTRIBUTION-UNATIEN 69.00 12.47
11 VE:OHYDRO DISTRIBUTION-UNATIEN 34.50 2.40
12 VICKERS DISTRIBUTION-UNATIEN 46.00 12.47
13 VINEYARD OISTRIBUTION.UNATIEN 46.00 12.47
14 WALFARE DISTRIBUTION-UNATIEN 46.00 12.47
15 WALLSBURG DISTRIBUTION-UNATIEN 138.00 12.47
16 WALNUT GROVE DISTRIBUTION-UNATIEN 138.00 12.50
17 WARREN DISTRIBUTION-UNATIEN 138.00 12.47
18 WASATCH STATE PARK DISTRIBUTION-UNATIEN 46.00 12.47
19 WASHAKIE DISTRIBUTION-UNATIEN 138.00 4.16
20 WELBY DISTRIBUTION-UNA TIEN 46.00 12.47
21 WELLINGTON DISTRIBUTION-UNATIEN 46.00 12.47
22 WEST COMMERCIAL DISTRIBUTlON-UNATIEN 46.00 12.47
23 WEST JORDAN DISTRIBUTION-UNATIEN 138.00 12.47
24 WEST OGDEN DISTRIBUTION-UNATIEN 138.00 12.47
25 WEST ROY DISTRIBUTION-UNATIEN 46.00 12.47
26 WEST TEMPLE DISTRIBUTION-UNATIEN 46.00 4.16
27 WESTFIELD OISTRIBUTION-UNATIEN 138.00 12.47
28 WESTWATER DISTRIBUTION-UNATIEN 69.00 12.47
29 WHITE MESA DISTRIBUTION-UNATIEN 69.00 12.47
30 WILLOW CREEK DISTRIBUTION-UNATIEN 46.00 12.47
31 WILLOWRIDGE DISTRIBUTION-UNA TIEN 46.00 12.47
32 WINCHESTER HILLS DISTRIBUTION-UNATIEN 34.50 12.47
33 WINKLEMAN DISTRIBUTION-UNA TIEN 46.00 7.20
34 WOLFCREEK DISTRIBUTION-UNA TIEN 69.00 12.47
35 WOOD CROSS DISTRIBUTION-UNA TIEN 46.00 12.47
36 WOODRUFF DISTRIBUTION-UNATIEN 46.00 12.47
37 Total 19907.47 3641.89 184.97
38 NUMBER OF SUBSTATIONS DIST UNATIENDED - 298
39 ,
40 ANGEL T/D-UNATIENDEO 138.00 12.47 46.00
.
.
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.
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.
.
.FERC FORM NO.1 (ED. 12-96)Page 426.17
.;W0804U4-8002 FERC PDF (UnOffict,,~) '~rMglP8
I
,-u,ç VI I IvtJl'
I
i oalfl C"IIVU Vi r~C"~vli
(Mo, Da, Yr)End of 2007/04PacifiCorp
(2) ñ A Resubmissio 041042008
SUBSTATIONS
1.Report below the information called for conerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale. may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)Name and Loction of Substation Character of SubstationNo.Primary Secondary Tertary
(a)(b)(c)(d)(e)
1 BDO TID-UNATTENDED 138.00 12.47
2 BUTLERVILLE TID-UNATTENDED 138.00 46.00 12.47
3 COTTONWOOD TID-UNATTENDED 138.00 12.47 46.00
4 EMMA PARK TID-UNATTENDED 138.00 12.47
5 HALE TID-UNATTENDED 138.00 46.00 12.47
6 HIGHLAND TID-UNATTENDED 138.00 12.47 46.00
7 JORDAN TID-UNATTENDED 138.00 46.00 12.47
8 JUDGE TID-UNATTENDED 46.00 12.47
9 MCCLELLND TID-UNATTENDED 138.00 46.00 12.47
10 OQUIRRH T/O-UNA TTENDED 138.00 46.00 12.47
11 PARRISH TID-UNATTENDED 138.00 12.47 46.00
12 PIONEER PLANT TID-UNATTENDED 138.00 2.30 46.00
13 RIVERDALE TID-UNATTENDED 138.00 46.00 12.47
14 SEVIER TID-UNATTENDED 138.00 46.00 12.47
15 SILVER CREEK TID-UNATTENDED 138;00 12.47 46.00
16 SPHINX TID-UNATTENDED 46.00 12.47
17 SYRACUSE TID-UNATTENDED 138.00 46.00 12.47
18 TAYLORSVILLE TID-UNATTENDED 138.00 46.00 12.47
19 TERMINAL TID-UNATTENDED 345.00 12.47 46.00
20 TIMP TID-UNATTENDED 138.0C 46.00 12.47
21 TOOELE TID-UNATTENDED 138.00 46.00 12.47
22 WEST VALLEY TID-UNATTENDED 138.00 12.47
23 Total .3197.00 645.47 459.17
24 NUMBER OF SUBSTATIONS TID UNATTENDED - 23
25
26 BLUNDELL PLANT TRANSMISSION-ATTEND 46.00 12.47
27 CARBON PLANT TRANSMISSION-ATTEND 138.00 13.80
28 EMERY TRANSMISSION-ATTEND 138.00 6.90 69.00
29 GADSBY PLANT TRANSMISSION-ATTEND 138.00 13.80 46.00
30 GADSBY TRANSMISSION-ATTEND 138.00 46.00
31 HUNTER PLANT TRANSMISSION-ATTEND 345.00 23.00
32 HUNTINGTON PLANT TRANSMISSION-ATTEND 345.00 23.00
33 Total 1288.00 138.97 115.00
34 NUMBER OF SUBSTATIONS TRANS ATTENDED-7
35
36 90TH SOUTH TRANSMISSION-UNA TTEN 345.00 138.00
37 ABAJO TRANSMISSION-UNATTEN 138.00 69.00
38 ASHLEY TRANSMISSION-UNA TTEN 138.00 46.00
39 BARNEY TRANSMISSION-UNA TTEN 138.00 46.00
40 BEN LOMOND TRANSMISSION-UNA TTEN 345.00 230.00 138.00
.
.
.
.
.
.
.
.
.
.FERC FORM NO.1 (ED. 12-96)Page 426.18
.
'"'2'0-013 0'4LT'r::-rfO'02 FERC PDF (UnOffict~~') 'iI~g1j)8
I
UQ\'I VI n'ltJl L
I
l ~ai, r e'IIVU Vi nctJvi l
(Mo, Da. Yr)End of 2007/04PacifiCorp
(2) ri A Resubmission 040412008
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Une VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertary
(a)(b)(e)(d)(e)
1 BLACKHAWK TRANSMISSION-UNATTEN 138.00 69.00 46.00
2 BOOKCLIFFS TRANSMISSION-UNATTEN 69.00 46.00
3 CAMERON TRANSMISSION-UNATTEN 138.00 46.00
4 CAMP WILLIAMS TRANSMISSION-UNATTEN 345.00 138.00 12.47
5 CARBON TRANSMISSION-UNATTEN 46.00 2.40
6 COLUMBIA TRANSMISSION-UNATTEN 138.00 46.00
7 CRICKET MOUNTAIN REG STA TRANSMISSION-UNATTEN 46.00 46.00
8 CUTLER TRANSMISSION-UNATTEN 138.00 46.00
9 ELMONTE TRANSMISSION-UNATTEN 138.00 46.00
10 GARKANE TRANSMISSION-UNATTEN 69.00 46.00
11 GREEN CANYON TRANSMISSION-UNATTEN 138.00 46.00
12 GRINDING TRANSMISSION-UNATTEN 138.00 13.80
13 HELPER TRANSMISSION-UNATTEN 138.00 46.00
14 HONEYVILLE TRANSMISSION-UNATTEN 138.00 46.00
15 HORSESHOE TRANSMISSION.UNATTEN 138.00 46.00 12.47
16 HUNTINGTON TRANSMISSION-UNATTEN 345.00 138.00 69.00
17 JERUSALEM TRANSMISSION-UNATTEN 138.00 46.00
18 LAMPO TRANSMISSION-UNATTEN 138.00 46.00
19 MCFADDEN TRANSMISSION.UNATTEN 138.00 46.00
20 MIDDLETON TRANSMISSION-UNATTEN '138.00 69.00 34.50
21 MIDVALLEY TRANSMISSION-UNATTEN 345.00 138.00
22 MIDWAY CITY TRANSMISSION-UNA TTEN 138.00 46.00
23 MINERAL PRODUCTS TRANSMISSION.UNATTEN 69.00 46.00
24 MOAB TRANSMISSION-UNATTEN 138.00 69.00
25 NEBO TRANSMISSION-UNATTEN 138.00 46.00
26 OLMSTED TRANSMISSION-UNATTEN 46.00 2.40
27 PAROWAN VALLEY TRANSMISSION.UNATTEN 230.00 138.00 34.50
28 PAVANT TRANSMISSION-UNATTEN 230.00 46.00
29 PINTO TRANSMISSION-UNATTEN 345.00 138.00 69.00
30 RED BUTTE TRANSMISSION-UNATTEN 230.00 138.00
31 SAND COVE HYDRO TRANSMISSION-UNATTEN 34.50 2.40
32 SIGURD TRANSMISSION-UNA TTEN 345.00 230.00 138.00
33 SMITHFIELD TRANSMISSION-UNATTEN 138.00 46.00 12.47
34 SPANISH FORK TRANSMISSION-UNATTEN 345.00 138.00 46.00
35 STGEORGE TRANSMISSION-UNA TTEN 138.00 16.50
36 UPPER BEAVER HYDRO TRANSMISSION-UNA TTEN 46.00 2.30
37 WEBER PLANT TRANSMISSION-UNATTEN 46.00 2.30
38 WEST CEDAR TRANSMISSION.UNA TTEN 230.00 138.00 34.50
39 Total 7187.50 2986.10 646.91
40 NUMBER OF SUBSTATIONS TRANS UNATTENDED - 43
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 426.19
."~'ò~o'S Ò '4lt4~'8~ò'b 2 FERC PDF (UnOffict~'r 'i!W#/t)8
1
Udlt: Vi nt:lJll
I
't:diirt:IIVU Vi nt:IJUll
(Mo, Da, Yr)End of 2007/04PacifiCo
(2) i: A Resubmission 04/0412008
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Pnmary Secondary Tertiary
(a)(b)(c)(d)(e)
1
2 Washington
3 ATTAllA DISTRIBUTION-UNATTEN 69.00 12.47
4 BOWMAN DISTRIBUTION-UNATTEN 69.00 12.47
5 CASCADE KRAFT DISTRIBUTION-UNATTEN 69.00 12.47 4.16
6 CLINTON DISTRIBUTION-UNATTEN 115.00 12.47
7 DAYTON DISTRIBUTION-UNATTEN 69.00 12.47
8 DODD ROAD OISTRIBUTION-UNATTEN 69.00 20.80
9 GRANDVIEW DISTRIBUTION-UNATTEN 115.00 12.47 69.00
10 HOPLAND OISTRIBUTION-UNATTEN 115.00 12.47
11 MILLCREEK DISTRIBUTION-UNATTEN 69.0C 12.47
12 NACHES HYDRO DISTRIBUTION-UNATTEN 115.00 12.47
13 NOB HILL DISTRIBUTION-UNATTEN 115.00 12.47
14 NORTH PARK DISTRIBUTION-UNATTEN 115.00 12.47
15 ORCHARD DISTRIBUTION-UNATTEN 115.00 12.47
16 PACIFIC DISTRIBUTION.UNATTEN 115.00 12.47
17 POMEROY DISTRIBUTION-UNATTEN 69.00 12.47
18 PROSPECT POINT DISTRIBUTION.UNATTEN 69.00 12.47
19 PUNKIN CENTER DISTRIBUTION-UNA TTEN 115.00 12.47
20 RIVER ROAD DISTRIBUTION-UNATTEN 115.00 12.47
, 21 SELAH . DISTRIBUTION-UNATTEN 115.00 '12.47
22 SULPHUR CREEK DISTRIBUTION.UNA TTEN 115.00 12.47
23 SUNNYSIDE DISTRIBUTION-UNATTEN 115.00 12.47
24 TIETON DISTRIBUTION-UNATTEN 115.00 12.47 34.50
25 TOPPENISH DISTRIBUTION.UNATTEN 115.00 12.47
26 TOUCHET DISTRIBUTION-UNATTEN 69.00 12.47
27 VOELKER DISTRIBUTION.UNATTEN 115.00 12.47
28 WAITSBURG DISTRIBUTION.UNA TTEN 69.00 12.47
29 WAPATO DISTRIBUTION-UNA TTEN 115.00 12.47
30 WENAS DISTRIBUTION-UNATTEN 115.00 12.47
31 WHITE SWAN DISTRIBUTION-UNATTEN 115.00 12.47
32 WILEY DISTRIBUTION.UNA TTEN 115.00 12.47
33 Total 2990.00 382.43 107.66
34 NUMBER OF SUBSTATIONS DIST UNATTENDED - 30
35
36 CENTRAL TID-UNATTENDED 69.00 12.47
37 UNION GAP TID-UNATTENDED 230.00 115.00 12.47
38 Total 299.00 127.47 12.47
39 NUMBER OF SUBSTATIONS TID UNATTENDED - 2
40
.
.
.
.
.
.
.
.
.
.FERC FORM NO.1 (ED. 12-96)Page 426.20
.
l'l~eo~ ó'.rd~~(~f8b 2
:t inis ~rt IS:I
Date of Report
I
YearlPeríod of ReportFERC PDF (Unoffic ~~) ~(J8 (Mo, Da, Yr)PacifCorp End of 2007/04
(2) Õ A Resubmission 0410412008
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Loction of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(e)(d)(e)
1 CONDIT PLANT TRANSMISSION-ATTEND 69.00 2.30
2 MERWIN PLANT TRANSMISSION-ATTEND 115.00 13.20
3 YALE PLANT TRANSMISSION-ATTEND 230.00 13.80
4 Total 414.00 29.30
5 NUMBER OF SUBSTATIONS TRANS ATTENDED - 3
6 .
7 OUTLOOK TRANSMISSION-UNATTEN 230.00 115.00
8 PASCO TRANSMISSION-UNATTEN 115.00 69.00 7.20
9 POMONA HEIGHTS TRANSMISSION-UNATTEN 230.00 115.00
10 SWIFT 1 PLANT TRANSMISSION-UNATTEN 230.00 13.00
11 WALLA WALLA 230KV TRANSMISSION-UNATTEN 230.00 69.00
12 WALLULA TRANSMISSION-UNATTEN 230.00 69.00
13 Total 1265.00 450.00 7.20
14 NUMBER OF SUBSTATIONS TRANS UNATTENDED - 6
15
16 Wyoming
17 AIR BASE DISTRIBUTION-UNA TTEN 12.47 2.40
18 ANTELOPE MINE DISTRIBUTION-UNATTEN 230.00 34.50
19 ASTLE STREET DISTRIBUTION-UNATTEN 34.50 13.20
20 BAILEY DOME DISTRIBUTION-UNA TTEN 57.00 12.47
21 BAR X DISTRIBUTION-ÙNATTEN 230.00 34.50
22 BID MUDDY DISTRIBUTION-UNA TTEN 69.00 12.47
23 BIG PINEY DISTRIBUTION-UNA TTEN 69.00 24.90
24 BLACKS FORK DISTRIBUTION-UNATTEN 230.00 34.50
25 BRIDGER PUMP DISTRIBUTION-UNA TTEN 230.00 34.50 13.20
26 BRYAN DISTRIBUTION-UNATTEN 115.00 12.47
27 BUFFALO TOWN DISTRIBUTION-UNA TTEN 20.80 4.16
28 BYRON DISTRIBUTION-UNA TTEN 34.50 4.16
29 CASSA DISTRIBUTION-UNATTEN 57.00 20.80
30 CENTER STREET DISTRIBUTION-UNA TTEN 115.00 4.16
31 CHAPMAN STATION DISTRIBUTION-UNA TTEN 46.00 12.47
32 CHATHAM DISTRIBUTION-UNATTEN 34.50 4.16
33 CHUKAR DISTRIBUTION-UNATTEN 12.47 4.16
34 CHURCH AND DWIGHT DISTRIBUTION-UNATTEN 34.50 0.48
35 COKEVILLE DISTRIBUTION-UNA TTEN 46.00 24.90
36 COLUMBIA-GENEVA DISTRIBUTION-UNATTEN 230.00 13.80
37 COMMUNITY PARK DISTRIBUTION-UNATTEN 69.00 12.47
38 CROOKS GAP DISTRIBUTION-UNA TTEN 34.50 12.47
39 DEER CREEK DISTRIBUTION-UNA TTEN 69.00 12.47
40 DJCOALMINE DISTRIBUTION-UNA TTEN 69.00 34.50
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 426.21
.NClTlM~~!!f.l~ie8b2 FERC PDF (Unoffic
ThiS~~i:8 Date of Report
\
1 ~dll' iiIIV.. ... . --r ~~~) .'(Mo. Da. Yr)End of 2007/04
PacifiCorp (2) i: A Resubmission
0410412008
SUBSTATIONS
1.Report below the information
called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substatio"" capomes 01 Less than 10 MVa e""ept thos se",ing cutome" wnh ene'gy to' ,eseie, may be gmuped ae,ding
to functional character, but the number of such substations must be shown.
4. Indicale In column (b) Ihe tunctional ch..acte' 01 each substaon, deignating wheth' i""mission '" d~lriuilon and whlhe'
attende 0' unattende. At the end of the page, summari aenlng fo Iunction !he capcities ,eported tm fhe indi~dual stions in
column (f).
Line
VOLTAGE (In MVa)
Name and Location of Substation
Character of Substation
No.
Primary Secondary Tertiary
(a)
(b)(c)(d)(e)
1 DOUGLAS
DISTRIBUTION-UNATTEN
57.00 2.30
2 DRY FORK
DISTRIBUTION-UNATTEN
69.00 4.16
3 ELK BASIN
DISTRIBUTION-UNATTEN
34.50 7.20
4 EMIGRANT
DISTRIBUTION-UNATTEN
115.00 12.47
5 EVANS
DISTRIBUTION-UNATTEN
69.00 12.47
6 EVANSTON
DISTRIBUTION-UNA TTEN
138.00 12.47
7 FARMERS UNION
DISTRIBUTION-UNA TTEN
34.50 4.16
8 FiREHOLE
DISTRIBUTION-UNATTEN
230.00 34.50
9 FORT CASPER
DISTRIBUTION-UNATTEN
69.00 12.47
10 FORT SANDERS
DISTRIBUTION-UNATTEN
115.00 13.20
11 FRANNIE
DISTRIBUTION-UNATTEN
230.00 34.50
12 FRONTIER
DISTRIBUTION-UNA TTEN
69.00 4.16
13 GARLAND
DISTRIBUTION-UNATTEN
230.00 34.50
14 GLENDO
DISTRIBUTION-UNATTEN
57.00 4.16
15 GRASS CREEK
DISTRIBUTION-UNATTEN
230.00 34.50
16 GREAT DIVIDE
DISTRIBUTION-UNATTEN
115.00 34.50
17 GREYBULL
DISTRIBUTION-UNATTEN
34.50 4.16
18 HANNA
DISTRIBUTION-UNATTEN
34.50 12.47 .
19 JACKALOPE
DISTRIBUTION-UNATTEN
115.00 12.47
20 KEMMERER
DISTRIBUTION-UNATTEN
69.00 24.90
21 KIRBY CREEK PUMPING STATION
DISTRIBUTION-UNATTEN
34.50 2.40
22 KIRBY CREEK
DISTRIBUTION-UNATTEN
34.50 4.16
23 LANDER
DISTRIBUTION-UNATTEN
34.50 12.47
24 LARAMIE
DISTRIBUTION-UNATTEN
115.00 13.20
25 LATHAM
DISTRIBUTION-UNATTEN
230.00 34.50
26 LINCH
DISTRIBUTION-UNATTEN
69.00 13.80
27 LITTLE MOUNTAIN
DISTRIBUTION-UNA TTEN
230.00 34.50
28 LOVELL
DISTRIBUTION-UNATTEN
34.50 4.16
29 MANDERSON
DISTRIBUTION-UNA TTEN
34.50 4.16
30 MILLIRON
DISTRIBUTION-UNA TTEN
34.50 13.80
31 MILLS
DISTRIBUTION-UNATTEN
12,4i 4.16
32 MURPHY DOME
DISTRIBUTION-UNATTEN
34.50 13.20
33 NUGGETT
DISTRIBUTION-UNATTEN
69.00 7.20
34 OPAL
DISTRIBUTION-UNA TTEN
46.00 24.90
35 ORIN
DISTRIBUTION-UNATTEN
57.00 12,47
36 ORPHA
DISTRIBUTION-UNATTEN
57.00 7.20
37 PARCO
DISTRIBUTION-UNATTEN
34.50 12.47
38 PINEDALE
DISTRIBUTION-UNA TTEN
69.00 24.90
39 PITCHFORK
DISTRIBUTION-UNA TTEN
69.00 24.90
40 POINT OF ROCS
DISTRIBUTION-UNATTEN
230.00 34.50
.
.
.
.
.
.
.
.
.
.
FERC FORM NO.1 (E. 12-96)
Page 426.22
."~'cro1Hl4'CC'8"ò'b2 FERC PDF (UnOffict~~I) (g~g'ilßJ)8
I
Date ot Report
I
Year/Period of Report
(Mo. Da. Yr)2007/04PacifiCorp
(2) 0 A Resubmission 040412008 End of
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
.
Una VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Seconry Tertary
(a)(b)(c)(d)(e)
1 POISON SPIDER DISTRIBUTION-UNATTEN 69.00 2.40
2 POLECAT DISTRIBUTION-UNA TTEN 34.50 12.47
3 RAINBOW DISTRIBUTION-UNATTEN 34.50 13.20
4 RAVEN DISTRIBUTION-UNATTEN 230.00 34.50
5 RED BUTE DISTRIBUTION-UNATTEN 69.00 12.47
6 REFINERY DISTRIBUTION-UNATTEN 115.00 12.47
7 SAGE HILL DISTRIBUTION-UNATTEN 34.50 13.20
8 SHOSHONI DISTRIBUTION-UNATTEN 34.50 2.40
9 SLATE CREEK DISTRIBUTION-UNA TTEN 69.00 12.47
10 SOUTH CODY DISTRI8UTION-UNATTEN 69.00 24.90
11 SOUTH ELK BASIN DISTRIBUTION-UNA TTEN 34.50 4.16
12 SOUTH TRONA DISTRIBUTION-UNATTEN 23.00 34.50
13 SPRING CREEK DISTRIBUTION-UNATTEN 115.00 13.20
14 SVILAR DISTRIBUTION-UNATTEN 34.50 4.16
15 TEN MILE DISTRIBUTION-UNATTEN 69.00 34.50
16 THERMOPOLIS TOWN DISTRIBUTION-UNATTEN 34.50 4.16
17 THUNDER CREEK DISTRIBUTION-UNA TTEN 57.00 12.47
18 VETERANS DISTRIBUTION-UNATTEN 34.50 13.20
19 WELCH DISTRIBUTION-UNATTEN 57.00 2.40
20 WERTZ-SINCLAIR DISTRIBUTION-UNA TTEN 57.00 4.16 12.50
21 WEST ADAMS .OISTRI8UTION-UNATTEN 34.50 4.16
22 WESTERN CLAY DISTRIBUTION-UNATTEN 34.50 0.48
23 WESTVACO DISTRIBUTION-UNA TTEN 230.00 34.50
24 WORLAND TOWN DISTRIBUTION-UNA TTEN 34.50 4.16
25 WYOPO DISTRIBUTION-UNATTEN 230.00 34.50
26 WYUTA DISTRIBUTION-UNA TTEN 46.00 12.47
27 Total 7885.21 1357.50 25.70
28 NUMBER OF SUBSTATIONS DIST UNATTENDED. 90
29
30 LABARGE T/D-UNA TTENDED 69.00 24.90
31 BUFFALO TID-UNATTENDED 230.00 20.80
32 HILLTOP T/D-UNATTENDED 115.00 34.50 20.80
33 RIVERTON 230 T/D-UNA TTENDEO 230.0(12.47 34.50
34 YELLOWCAKE T/D-UNATTENDED 230.00 34.50
35 Total 874.00 127.17 55.30
36 NUMBER OF SUBSTATIONS T/D UNATTENDED - 5
37
38 DAVE JOHNSTON PLANT TRANSMISSION-ATTEND 230.00 115.00 69.00
39 JIM BRIDGER 34KV TRANSMISSION-ATTEND 345.00 230.00 34.50
40 JIM BRIDGER UNITS 1-4 TRANSMISSION-ATTEND 345.00 22.00
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 426.23
.. .~ 'ó~o'S Ó '4''C4'::'tm'b 2 FERC PDF (UnOffict~~') 'i!~glj)8
I
uaie 01 nepon
I
T eam-enoo oi Hepon
(Mo, Da, Yr)End of 2007/04PacifiCorp
(2) ñ A Resubmission 04041208
SUBSTATIONS
1.Report below the information called for conceming substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(e)(d)(e)
1 NAUGHTON TRANSMISSION-ATIEND 230.00 69.00
2 WYODAK 230KV TRANSMISSION-ATIEND 230.00 69.00
3 WYODAK PLANT TRANSMISSION-ATIEND 230.00 22.00
4 Total 1610.00 527.00 103.50
5 NUMBER OF SUBSTATIONS TRANS ATIENDED - 6
6
7 BAIROIL TRANSMISSION-UNATIEN 115.00 34.50 57.00
8 CASPER TRANSMISSION-UNATIEN 230.00 115.00 69.00
9 CHAPPELL CREEK TRANSMISSION-UNA TIEN 230.00 69.00
10 FOOTE CREEK WIND FARM TRANSMISSION-UNATIEN 230.00 34.50
11 GLENDO AUTO TRANSMISSION-UNATIEN 69.00 57.00
12 MANSFACE TRANSMISSION-UNATIEN 230.00 34.50
13 MIDWEST TRANSMISSION-UNATIEN 230.00 69.00 34.50
14 MINERS TRANSMISSION-UNATIEN 230.00 115.00 34.50
15 MUSTANG TRANSMISSION-UNATIEN 230.00 115.00
16 OREGON BASIN TRANSMISSION-UNA TIEN 230.00 34.50 69.00
17 PLATIE TRANSMISSION-UNATIEN 230.00 115.00 34.50
18 RAILROAD TRANSMISSION-UNA TIEN 23.00 138.00
19 ROCK SPRINGS 230 TRANSMISSION-UNATIEN 230.00 34.50
20 SAGE TRANSMISSION-UNATIEN 69.00 46.00
, 21 THERMOPOLIS TRANSMISSION-UNA TIEN 230.00 115.00
22 YELLOWTAIL TRANSMISSION-UNATIEN 230.00 161.00
23 Total 3243.00 1287.50 298.50
24 NUMBER OF SUBSTATIONS TRANS UNATIENDED - 16
25
26 .
27 CALIFORNIA
28 Distribution - 45
29 TID -3
30 Transmission - 9
31
32 IDAHO
33 Distribution - 67
34 TID -4
35 Transmission - 18
36
37 OREGON
38 Distribution - 181
39 TID -10
40 Transmission - 41
.
.
.
.
.
.
..
.
.
.
FERC FORM NO.1 (ED. 12-96)Page 426.24
.
N,%eo~ C4~~~eBb 2
: t' i nis ~rt IS:I
Date of Report
I
YearlPenod of ReportFERCPDF(Unoffic ~~) ~P8 (Mo, Da, Yr)End of 2007/04PacifiCorp(2) 0 A Resubmissio 04/0412008
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Loction of Substation Character of Substation Pnmary Secdary Tertiary
(a)(b)(c)(d)(e)
1
2 UTAH
3 Distnbution . 298
4 TID - 23
5 Transmission - 50
6
7 WASHINGTON
8 Distnbution - 30
9 TID. 2
10 Transmission - 9
11
12 WYOMING
13 Distnbution - 90
14 TID -5
15 Transmission - 22
16
17 ALL STATES
18 Distnbution . 711
19 TID - 47
20 Transmission - 149
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
.
.
.
.
.
.
.
.
.
.FERC FORM NO.1 (ED. 12-96)Page 426.25
."~'ÒVO'M'4Lr4~tiÇ6'b 2 FERC PDF (Unof f ict~~.) '~~gij) 8
I
Udlt1 UI Mepon
I
T ear/r-enoa OT Mepon
(Mo, Ca. Yr)End of 2007/04PacifiCorp
(2) Õ A Resubmission 0410412008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party ii; an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)Transfonners Spare Type of Equipment Total capacity No.In Servce Transfonners Number of Units
(In MVa)
(f)(a)(h)(i)(j)(k)
1
25 1 2
6 1 3
1 3 4
2 3 5
4 3 6
3 6 7
1 8
8 3 9
6 1 10
9 1 11
13 1 12
1 1 13
8 3 14
4 3 15
9 3 16
13 1 17
2 3 18
4 1 19
31 2 20
6 1 21
4 3 22
6 1 23
16 4 24
8 3 25
6 6 26
20 4 27
2 3 28
1 1 29
2 3 30
9 3 31
2 3 32
2 3 33
18 3 34
1 1 35
5 3 36
6 3 37
3 38
2 3 39
20 1 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO.1 (ED. 12-96)Page 427
.N~eo~ S4~.l~~e8b 2 + i~is ~rt Is:
I
Date of Report
I
Year/Period of ReportFERCPDF(Unoffic ~) ~~P8 (Mo. Da, Yr)End of 2007/04PacifiCorp
(2) Õ A Resubmission 0410412008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Type of Equipment Total capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)u)'(k)
6 6 1
13 3 2
7 1 3
13 1 4
4 3 5
4 3 6
332 113 7
8
9
31 4 10
3 3 11
95 2 12
129 9 13
14
15
5 3 16
28 6 2 17
60 3 1 18
2 3 19
125 1 20
220 16 3 21
22
23
19 3 24
150 2 25
19 1 26
38 3 27
226 9 28
29
30
31
4 1 32
11 1 33
20 1 34
6 1 35
8 1 36
4 1 37
13 1 38
11 1 39
14 1 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 427.1
.N~eo~ oi4tt,f~ie8b 2 FERC PDF
. :t,ThiS (grt Is:I
Date of Report
I
Year/Period of Report(Uno f f i c ",~) lAgiP 8 (Mo, Da, Yr)2007/04PacifiCorp
(2) 0 A Resubmission 0410412008 End of
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co.owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, ccrowner, or other part is an associated company.
capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total capacity No.In Service Transformers Number of Units
(In MVa)
(f)(9)(h)(i)ü)(k)
20 1 1
5 1 2
30 1 1 3
5 1 4
4 1 5
21 4 6
5 1 7
13 1 8
14 1 9
14 1 1-
3 1 11
6 1 12
5 1 13
14 1 14
9 1 15
3 1 16
6 1 17
9 1 18
4 1 19
20 1 20
3 1 21
22 1 22
14 1 23
3 1 24
5 1 25
3 1 26
11 1 27
20 1 28
5 . 1 29
8 1 30
14 1 31
20 1 32
20 1 33
13 1 34
2 1 35
20 1 36
33 2 37
9 1 38
8 1 39
7 1 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 427.2
.N,%eo~ ~4m'~ie8b 2 (Unoffic ThiS~Date of Report Year/Period of ReportFERCPDF~) .QiP8 (Mo. Da. Yr)End of 2007/04PacifiCorp(2) A Resubmission 0410412008
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)
Transformers Spare Type of Equipment Total capacity No.In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)(j)(k)
40 2 1
20 1 2
20 1 3
20 1 4
22 1 5
14 1 6
8 1 7
5 1 8
13 1 9
13 1 10
4 1 11
4 1 12
7 1 13
7 1 14
14 1 15
20 1 16
4 1 17
20 1 18
796 72 1 19
20
21
71 4 1 22
14 1 23
189 4 24
40 2 25
314 11 1 26
27
28
115 4 29
115 4 30
31
32
75 2 1 33
250 1 .34
25 3 35
67 1 36
67 1 37
27 1 38
67 1 39
25 3 40
.
.
.
.
.
.
.
.
.
.
FERC FORM NO.1 (ED. 12-96)Page 427.3
.
N~eo~ Ql4~.l~cse8b 2
:t' inis ~n IS:I
Date of Repon
I
YearWenoa 01 HeponFERC PDF (Unoffic ~1)) rMgll-ßJ)8 (Mo, Da, Yr)End of 2oo7/Q4PacifiCorp
(2) r' A Resubmission 0404/2008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reaSon of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co.owner or other party, explain basis of sharing expenses or other accounting between the parties. and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transfonners Spare Type of Equipment Total capacity No.In Service Transfonners Number of Units
(In MVa)
(f)(0)(h)(i)Ol (k)
75 1 1
763 8 1 2
233 3 3
6 2 4
40 2 5
30 1 6
76 2 7
168 3 8
533 2 9
2527 37 2 10
11
12
13
5 1 14
30 6 15
25 1 16
25 1 17
5 1 18
9 1 19
8 3 1 20
11 3 21
25 1 22
6 1 23
40 2 24
2 3 25
32 2 26
8 3 27
3 1 28
8 3 29
25 1 30
50 2 31
13 1 32
34 2 33
40 2 34
34 2 35
20 1 36
13 1 37
9 3 38
20 1 39
45 2 40
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 427.4
.
Nepeo~ oi4im~ie8b 2
;t~is WWrt Is: ----Year/Period of ReportDate of ReportFERC PDF (Unoffic ) ~~P8 (Mo, Da, Yr)2oo7/Q4PacifiCorpEnd of
(2) n A Resubmission 040412008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
capacity of Substation Number of Number~f CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Total Capacity No.In Service Transformers Typ of Equipment Number of Units
(In MVa)
(1)(g)(h)(i)(j)(k)
25 1 1
5 3 2
25 1 3
80 2 4
45 2 5
1 3 6
20 1 7
1 3 8
9 2 9
55 2 1 10
20 1 11
40 2 12
5 1 13
25 2 14
20 1 15
25 1 16
.13 1 17
2 3 18
25 1 19
50 2 20
75 3 21
13 1 22
50 2 23
7 1 24
13 1 25
45 2 26
20 1 27
19 2 28
13 1 29
25 1 30
21 4 31
5 3 32
20 1 33
8 3 34
8 3 35
25 2 36
5 1 37
13 1 38
11 3 39
6 1 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 427.5
.
N~eo~ ai4W.l~(~f8b 2
:t' lOiS ~rt is:I
Date of Report
I
Y ea~Period of ReportFERCPDF(Unoffic ~~) ~gii:8 (Mo, Da, Yr)End of 2007/04PacifiCo
(2) n A Resubmissio 04/0412008
SUBSTATIONS tContinlJed)
5. Show in columns (I), m, and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacit of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Servce) (In MVa)Transfonners Spare Type of Equipment Total Capacity No.In Service Transfonners Number of Units
(In MVa)
(I)(Q)(h)(i)Ol (k)
20 1 1
45 2 2
1 4 3
25 1 4
20 1 5
8 3 6
13 1 7
6 3 8
40 2 9
45 2 10
20 1 11
75 3 12
50 2 13
40 2 14
20 1 15
20 1 16
75 2 17
13 1 18
20 1 19
20 1 20
6 1 1 21
25 2 22
3 3 23
40 2 24
6 1 25
50 2 26
9 3 27
13 3 28
40 2 29
105 3 30
40 2 31
9 1 32
25 2 33
25 1 34
20 1 35
20 1 36
79 14 37
45 2 38
17 6 39
1 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO.1 (ED. 12-96)Page 427.6
.
N~eo~ ~4ml~~e8b2
- , ~rn~ ~rt fs:
Date of Report
I
Yearwenoa Of HepoiiFERC PDF (Unoffic ~~) ~gif)8 (Mo, Da, Yr)2007/04PacifiCorp(2) Õ A Resubmission 040412008 End of
SUBSTATIONS lContinued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)
Transfonners Spare Type of Equipment Tota capacity No.In Service Transfonners Number of Units
(In MVa)
(f)(0)(h)(i)(j)(k)
6 3 1
2 3 2
100 4 3
14 1 4
9 1 5
4 1 6
9 1 7
45 2 8
8 1 9
2 3 10
45 2 11
1 1 1 12
40 2 13
39 2 14
46 7 1 15
22 2 16
6 1 17
50 2 18
11 3 19
50 2 20
2 3 21
50 2 22
8 1 23
14 1 24
25 1 25
25 2 26
50 2 27
9 3 28
25 1 29
9 1 30
9 1 31
45 2 32
40 2 33
70 3 34
8 1 35
40 2 36
9 1 37
2 3 38
25 1 39
19 2 40
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-96)Page 427.7
.N~eo'l 84~,f~ie8b 2
:tinis ~rt Is:I
Date of Report
I
Year/Period of ReportFERC PDF (Uno f fie ",~) rAg11J 8 (Mo, Da, Yr)End of 2007/04PacifiCorp
(2) r1 A Resubmission 0410412008
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-wner, or other party. is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Seivice) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Seivice Transformers Number of Units
(In MVa)
(f)(g)(h)(i)ü)(k)
9 1 1
20 1 2
7 3 3
.40 2 4
55 2 5
1 6
25 1 7
13 1 8
42 2 9
13 1 10.
50 2 11
17 6 12
1 1 13
11 1 14
13 1 15
25 2 16
13 2 17
50 2 18
25 1 19
40 2 20
22 4 21
7 1 22
13 3 23
25 2 24
3 3 25
3 1 26
50 2 27
22 2 28
23 9 29
40 2 30
60 3 31
28 3 32
23 3 33
37 2 34
4409 365 5 35
36.
37
177 9 38
65 2 39
70 2 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO.1 (ED. 12-96)Page 427.8
.Na¿eo~ 84~~(~f8b 2
:tc i nis ~rt IS:I
Date of Report
I
YearWenOd ot HeportFERC PDF (Unoffic ",~) ~gíP8 (Mo, Da, Yr)2007/Q4PacifiCorpEnd of
(2) Õ A Resubmission 040412008
SUBSTATIONS (Cotinue)
5. Show in columns (I), (j. and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
penod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(0)(h)(i)0)(k)
23 3 1
70 2 2
132 4 3
187 8 4
39 4 5
400 4 6
75 5 7
1238 43 8
9
10
17 3 11
31 3 12
13 3 13
89 2 1 14
48 7 1 15
40 4 16
5 3 17
40 6 1 18
10 6 19
50 9 .20
343 46 3 21
22
23
3 3 24
75 1 25
119 4 26
60 1 27
67 3 28
50 1 29
75 1 30
34 6 31
650 3 1 32
3 1 33
3 3 34
7 3 35
500 2 36
458 4 37
19 3 38
29 2 39
250 1 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 427.9
.
. -:1'-013 O'4tr'r:'T3~(ltJ 2 FERC PDF (Uno ff i c t~iF '~rig1P 8
I
Uiiltl Vi nepori
I
Tear/i-enoa oi Heport
PacifiCorp (Mo, Da, Yr)End of 2oo7/Q4
(2) A Resubmission 04/0412008
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Number of Units Total Capacity No.In Service Transformers (In MVa)
(f)(g)(h)(i)Ii)(k)
33 1 1
251 6 1 2
733 10 3
1300 6 1 4
50 1 5
250 1 6
8 3 1 7
47 4 8
50 1 9
21 3 10
13 3 11
500 3 12
100 2 13
2 3 14
6070 89 4 15
16
17
18
30 1 19
30 1 20
1 21
45 2 22
11 1 23
30 1 24
1 1 25
3 1 26
50 1 27
17 2 28
2 1 29
11 1 30
2 3 31
1 3 32
9 1 33
4 1 34
14 1 35
14 1 36
9 1 37
26 2 38
6 1 39
60 3 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO.1 (ED. 12-96)Page 427.10
.
N~ed~ ~4~~1f8b2 FERC PDF (Unoffic ~il ~~gi08 Date of Report
I
Year/Period of Report
(Mo. Da, Yr)End of 207/04
PacifiCorp (2) ri A Aesubmission 04/0412008
SUBSTATIONS (Continued)
5. Show in columns (i), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxilary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwse than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)
Transformers Spare Type of Equipment Total Capacity No,
In Service Transformers Number of Units
(In MVa)
(f)(g)(h)(i)ül (k)
4 1
1
9 1
2
13 1
3
1 1
4
20 1
5
3 1
6
6 1
7
30 1
8
25 1
9
40 2 10
22 1
11
2 1
12
30 1
13
25 1
14
3 1
15
4 1
16
3 17
60 2 18
50 2 19
4 1
20
20 2 21
30 1
22
106 4 23
1 3 24
3 1
25
2 3 26
1 1
27
22 1
28
22 1
29
42 1
30
55 2 31
6 1
32
23 2 33
2 1
34
4 1
35
60 2
36
2 1
37
.
23 2 38
60 2 39
30 1
40
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-96)Page 427.11
.
1~~IÒt:O~ 6'4m'~'èt:6'b2
t..iii~~I
uaie OT Mepon
I
Tedfli-eriUU Ul MeponFERCPDF(Unoffic ~~) 'gìlfàJJ8 (Mo, Da. Yr)2007/04PacifiCo
(2) Õ A Resubmission 040412008 End of
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)Transfonners Spare Total Capacity No.In Service Transfonners Type of Equipment Number of Units
(In MVa)
(1)(q)(h)(i)u)(k)
6 1 1
30 1 2
20 1 3
12 2 4
5 1 5
3 1 6
2 1 7
3 3 8
25 1 9
14 1 10
10 1 11
3 1 12
30 1 13
1 2 14
5 1 15
6 1 16
30 1 17
4 1 18
2 1 19
2 1 20
1 21
22 1 22
6 1 23
28 2 1 24
30 1 25
2 1 26
43 2 27
10 1 28
5 2 29
72 3 30
1 1 31
11 1 32
1 3 33
60 2 34
3 1 35
3 3 36
1 3 37
1 3 38
25 1 39
50 2 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 427.12
.Ncli(M~ ~4~~ieBb 2 -+ThiS l~ Is:Date of Report Year/Period of ReportFERCPDF(Unoffic ~~) rAgiP8 (Mo, Da, Yr)2oo7/Q4PacifiCorpEnd of(2) A Resubmission 04041208
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(f)(a)(h)(i)(j)(k)
22 1 1
4 1 2
32 2 3
22 1 4
13 2 5
1 3 6
1 1 7
5 3 8
2 1 9
22 1 10
13 2 11
30 1 12
30 1 13
2 3 14
3 1 15
5 1 16
7 1 17
1 .3 18
60 2 19
7 1 20
53 2 21
6 1 22
5 1 23
40 2 24
2 1 25
14 1 26
20 1 27
20 1 28
4 1 29
20 1 30
1 31
1 32
20 1 33
1 3 34
4 1 35
13 1 36
30 1 37
22 1 38
2 1 39
14 1 40
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-96)Pagè 427.13
.
i~~ 'Ò"'O~ ó'4tt4'~~eBb 2 FERC PDF
:t' i nis ~rt IS:I
Dale of Report
I
Year/Period of Report-
PacifiCorp (Unoffic ~) rAgiliMl8 (Mo, Da, Yr)End of 2oo7/Q4
(2) ii A Resubmission 04/0412008
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other part, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)Transformers Spare Total capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)(I)(a)(h)(i)0)(k)
20 1 1
2 3 2
9 1 3
6 1 4
20 1 5
42 2 6
58 4 7
5 1 8
30 1 9
25 1 10
14 1 11
1 1 12
13 1 13
2 1 14
19 2 15
13 1 16
3 1 17
3 1 18
6 1 19
25 1 20
6 3 21
5 1 22
6 1 23
6 1 24
7 1 25
20 1 26
5 1 27
14 1 28
25 1 29
5 1 30
2 1 31
25 1 32
22 1 33
13 1 34
45 10 35
14 1 36
24 2 37
6 1 38
11 5 3 39
22 1 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 427.14
.
1"'~IÒeo~ ó'4ff~(~fBb 2
:tinis~is:1
Date of Report
I
Year/Period of ReportFERC PDF (OnoH ic ",~) ~giP8 (Mo, Da, Yr)2007/04PacifiCorpEnd of
(2) r1 A Resubmission 041041208
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Servce Transformers Number of Units
(In MVa)
(1)(a)(h)(i)(j)(k)
3 1 1
20 1 2
14 1 3
48 2 4
55 2 5
4 1 6
5 1 7
4 3 8
35 2 9
50 2 10
16 2 11
6 1 12
20 1 13
2 1 14
14 1 15
22 1 16
25 1 17
14 1 18
30 1 19
2 1 20
4 1 21
60 2 22
4 1 23
15 1 24
2 1 25
1 3 26
14 1 27
13 1 28
3 1 29
45 2 30
45 2 31
5 1 32
22 2 33
11 1 34
40 2 35
20 1 36
5 1 37
4 1 38
30 1 39
24 3 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 427.15
.N~eo~ ~4tf¡~~eBb 2 This~rtIS:-Year/Period of Report(Unoffic Date of ReportFERC PDF ~1l ) rAgÌP 8 (Mo. Da, Yr)2007/Q4PacifiCorpEnd of
(2) Õ A Resubmission 040412008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)
Transformers Spare Type of Equipment Number of Units Total capacity No.In Service Transformers (In MVa)
(f)(g)(h)(i)ul (k)
3 1
11 1 2
60 2 3
30 1 4
1 3 5
1 6
1 3 7
13 2 8
5 3 9
20 1 10
6 1 11
20 1 12
2 1 13
40 2 14
5 1 15
30 1 16
13 1 17
30 1 18
20 2 19
60 2 20
25 1 21
14 1 22
50 1 23
50 2 24
22 2 25
6 1 26
4 1 27
4 1 28
2 1 29
20 1 30
14 1 31
7 1 32
30 1 33
8 1 34
6 1 35
14 1 36
14 1 37
40 2 38
24 3 39
2 1 40
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-96)Page 427.16
A.",~=--.
.NCleoei ~4tf,f~ie8b 2 (Unoffìc This~rtIS:
I
Date of Report
I
Year/Period of ReportFERC PDF ai~ ) ~gij) 8 (Mo, Da, Yr)2oo7/Q4PacifiCorp(2) Õ A Resubmission 04104208 End of
SUBSTATIONS (Cotinued)
5. Show in columns (I), (j, and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reàson of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(In MVa)
(f)(a)(h)(i)OJ (k)
14 1 1
34 2 2
30 1 3
13 1 4
39 2 5
50 2 6
48 4 7
22 1 8
3 1 9
33 2 10
2 3 11
2 1 12
25 1 13
5 1 14
13 1 15
30 1 16
30 1 17
2 3 18
14 1 19
22 1 20
4 1 21
22 1 22
28 1 23
30 1 24
25 1 25
60 3 26
20 1 27
1 3 28
14 1 29
6 1 30
14 1 31
4 1 32
1 33
6 1 34
20 1 35
2 1 36
5164 432 4 37
38.
39
135 3 40
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-96)Page 427.17
.. ':ro-O'804tr4:'~~ò'b2 FERC PDF (UnOffict~~'r '~gìiJ8
I
Uèil'" ur Nepon
I
T earwenoo or NepoTl
(Mo, Da, Vr)2007/04PacifCorp
(2) n A Resubmission 0410412008 End of
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc,and auxiliary equipment for
increasing capacity,
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Servce) (In MVa)Transformers Spare Type of Equipment Number of Units Total Capacity No.In Service Transformers
(In MVa)
(f)(g)(h)(i)ul (k)
30 1 --1
175 3 2
289 7 3
8 1 4
114 2 5
97 2 6
164 2 7
22 1 8
340 4 9
135 3 10
97 2 11
51 7 12
180 3 13
26 4 14
100 2 15
3 4 3 16
600 5 17
358 4 18
1108 6 2 19
130 2 20
158 3 21
30 1 22
4350 72 5 23
24
25
25 1 26
225 5 27
783 13 1 28
568 17 29
318 2 30
1513 5 1 31
981 4 32
4413 47 2 33
34
35
1538 6 1 36
67 1 37
133 2 38
100 1 39
1813 5 40
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 427.18
.i~~eocg R4~.l~~e8b 2 FERC PDF
. :t' inis ~rr IS:I
Date 01 Report
I
YearWenOd 01 Heport(Unoffic ~) rAgiP8 (Mo, Da, Yr)End of 2007/04PacifiCorp
(2) Õ A Resubmission 04/041208
SUBSTATIONS (Continued)
5. Show in columns (I), (j, and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)Transformers Spare Type of Equipment Total capacity No.In Service Transformers Number of Units
(In MVa)
(f)(0)(h)(i)ul (k)
100 2 1
6 3 1 2
25 3 3
169 2 4
8 1 5
33 1 6
15 1 7
70 2 8
313 3 9
33 1 10
67 2 11
225 3 12
142 2 13
35 1 14
80 2 15
270 4 16
67 1 17
75 1 18
45 1 19.
141 4 20
900 2 21
67 1 22
13 1 23
67 1 24
68 2 25
15 1 26
138 2 27
133 2 28
258 3 29
400 1 30
1 31
1124 6 32
63 2 33
1017 5 34
100 3 1 35
5 1 36
7 1 37
131 2 38
10076 92 3 39
40
.
.
.
.
.
.
.
.
.
.FERC FORM NO. 1 (ED. 12-96)Page 427.19
.N%eo~ ~4~~~e8b2
- . :FTfiSWWrtIS:I
Date of Report
I
YearlPenOO ot Heport
FERC PDF (Unoffic ~~) íAgiPS (Mo. Da, Yr)End of 2007/04PacifCorp(2) M A Resubmission 040412008
SUBSTATIONS (Continued)
5. Show in columns (I), m, and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)
Transformers Spare Typ of Equipment Number of Units Total Capacity No.In Service Transformers (In MVa)
(f)(g)(h)(I)ü)(k)
1
2
25 1 3
45 2 4
117 6 5
25 1 6
23 2 7
25 4 8
56 2 9
34 2 10
45 2 11
20 1 12
42 2 13
45 2 14
50 2 15
28 3 16
9 1 17
40 2 18
20 2 19
51 4 20
45 2 21
25 1 22
45 2 23
29 2 24
50 2 25
6 1 26
25 1 27
9 1 28
45 2 29
25 2 30
22 2 31
45 2 32
1071 61 33
34
35
14 1 36
348 5 37
362 6 38
39
40
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-96)Page 427.20
.
N~eO~~4~ie8b2 (Unoffic ThiS~IS:Date of Report
I
Year/Penod of Report
FERC PDF ai) rAgiP8 (Mo, Da, Yr)2007/04
PacifiCorp End of
(2) 0 A Resubmission 0410412008
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwse than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)
Transformers Spare Type of Equipment Total Capacity No.
In Service Transformers Number of Units
(In MVa)
(f)(0)(h)(i)ü)(k)
13 6 1 1
183 9 1 2
144 3 1 3
340 18 3 4
5
6
125 1
7
39 9 8
30 2 9
261 3 1 10
300 2 11
120 2 12
1145 19 1
13
14
15
16
1 3 17
25 1
18
13 1
19
2 1
20
25 1
21
7 1
22
8 1
23
150 2 24
73 4 25
25 1
26
2 3 27
2 3 28
2 6 1
29
13 1
30
4 1
31
3 32
1 3 33
3 2 34
4 1
35
45 2 36
40 2 37
5 3 38
9 1
39
13 1
40
.
.
.
.
.
.
.
.
.
.
FERC FORM NO. 1 (ED. 12-96)Page 427.21
.N%eo~ ~4W.l~ie8b 2 (Unoffic This~rtIS:Date of Report YeartPenod of ReportFERCPDF~1) ) rAg11J 8PacifiCorp (Mo, Da, Yr)End of 2007/Q4
(2) D A Resubmission 041041208
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity. .
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwse than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
penod of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transformers Spare Type of Equipment Total capacity No.In Service Transformers Number of Units
(In MVa)
(f)(0)(h)(i)Ü)(k)
6 3 1
9 1 2
5 1 3
13 1 4
9 1 5
40 2 6
2 3 7
50 2 8
25 1 9
20 1 10
50 2 11
6 1 12
45 2 13
3 4 14
25 1 15
20 1 16
3 1 17
6 1 18
25 1 19
10 1 20
3 3 21
2 3 22
25 2 23
50 2 24
25 1 25
13 1 26
20 1 27
4 3 28
1 3 29
13 1 1 30
1 3 31
5 1 32
1 33
8 1 34
2 3 35
3 3 36
5 1 37
8 1 38
17 9 2 39
25 1 40
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FERC FORM NO. 1 (ED. 12-96)Page 427.22
."~'ò"o~ 6'4m'~'è"6'b 2
:t' i nis ~"ls:I
Date of Report
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Year/Period of ReportFERC PDF (Unoffic 'ttl) 1Agi1J8 (Mo, Da. Yr)2oo7/Q4PacifiCorpEnd of
(2) ¡= A Resubmission 04/0412008
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment forincreasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's bookS of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of COVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units
(In MVa)
(1)(a).(h)(i)ul (k)
3 1 1
2 3 2
13 1 3
200 2 4
20 1 5
45 2 6
6 1 7
2 3 8
1 1 9
14 3 1 10
2 6 11
150 2 12
25 1 13
2 3 14
13 1 15
5 1 16
9 1 17
25 2 18
3 3 19
2 6 20
3 1 21
1 1 22
25 1 23
5 1 24
20 1 1 25
1 26
1670 173 6 27
28
29
8 6 30
20 1 31
45 2 1 32
50 3 33
25 1 34
148 13 1 35
36
37
1358 17 38
1084 22 39
1122 2 40
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.FERC FORM NO. 1 (ED. 12-96)Page 427.23
.'''~'6''d~ B4~%e8b2
il~IS~nIS:I
Date of Repo
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Year/Period of ReportFERC PDF (Unoffic ~) ~~P8 (Mo, Da, Yr)End of 2007/Q4PacifiCorp
(2) ri A Resubmission 04l2008
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwse than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Une
(In Service) (In MVa)Transformers Spare Type of Equipment Total capacity No.In Service Transformers Number of Units
(In MVa)(f)(g)(h)(i)ü)(k)
1232 15 1 1
60 1 2
503 3 1 3
5359 60 2 4
5
6
53 3 7
517 6 8
67 1 9
196 2 10
15 2 11
20 1 12
91 4 13
58 4 1 14
200 2 15
115 4 16
165 4 17
400 1 18
75 3 19
22 1 20
175 2 21
100 1 22
2269 41 1 23
24
25
26
27
332 28
129 29
446 30
31
32
796 33
314 34
2642 35
36
37
4409 38
1238 39
6413 40
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.FERC FORM NO. 1 (ED. 12-96)Page 427.24
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N~eO~~4~~~eBb 2 ThiS~IS:-----
I
YeavPenod of ReportDate of ReportFERC PDF (Unoffie ~~) ~gii:8 (Mo, Da, Yr)End of 2007/Q4PacifiCorp(2) tl A Resubmission 040412008
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other part is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
(In Service) (In MVa)
Transfonners Spare Type of Equipment Total Capacity No.In Servce Transfonners Number of Units
(In MVa)
(I)(g)(h)(i)(i)(k)
1
2
5164 3
4350 4
14489 5
6
7
1071 8
362 9
1485 10
11
12
1670 13
148 14
7628 15
16
17
13442 18
.6541 19
33103 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
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FERC FORM NO. 1 (ED. 12-96)Page 427.25
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EXHIBITH
JURISDICTIONAL FACILITIES AND SECURITIES ASSOCIATED WITH OR
AFFECTED BY THE PROPOSED TRANSACTION
The Proposed Transaction wil result in the conveyance of Chehalis to Purchasers and the
.merger immediately thereafter of Chehalis into PacifiCorp. The jurisdictional facilities involved
include the interconnection facilities that connect the Chehalis Facility to the interstate grid,
Chehalis' market-based rate schedule (accepted for filing in Docket No. ER03-717-000) and
.reactive power rate schedule (accepted for fiing and suspended in Docket No. ER06-1548-000),
and associated accounts, books and records. A Notice of Cancellation of Chehalis' market-based
rate schedule and Notice of Succession of PacifiCorp for Chehalis' reactive power rate schedule.
to be effective upon closing of the Proposed Transaction wil be made under separate cover.
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EXHIBIT I
CONTRACTS RELATED TO THE PROPOSED TRANSACTION.
A copy of the Agreement is provided in Volume II of the Application.
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CONFIDENTIAL INFORMATION HAS BEEN REMOVED.
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EXHIBIT J
.STATEMENT OF FACTS DEMONSTRATING THAT THE PROPOSED
TRANSACTION IS CONSISTENT WITH THE PUBLIC INTEREST
See Part VI of this Application.
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EXHIBITK
MAPS.
Attached is a map depicting the location of the Chehalis Facilty in relation to
PacifiCorp's balancing authority areas and PacifiCorp's generation and transmission resources..
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PacifiCorp service area
~ Coal plants
. Natural gas plants
.. Geothermal and other
. Hydro systems
. Wind plants
o Wind projects under
construction
& Coal mines
- PacifiCorp-owned primary
transmission lines
~ ~ ~ Transmission access
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MONTANA
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.NEVADA
A. ....'~~.....
.,.,
:COLORADO
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ARIZONA ..r¡. . .. , .. . ', , ,.:..... ..:.:... .",. .
NEW MEXICO \
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EXHIBIT L
LICENSES, ORDERS OR OTHER APPROVALS
At the federal level, in addition to obtaining required FERC approvals, a fiing under the
Har-Scott-Rodino Act, 15 U.S.c. § 18, will be made. In addition, authorization from the
. Federal Communications Commission under Section 310 of the Communications Act of 1934,
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47 U.S.c. § 310(d), for the transfer of wireless radio licenses is required. At the state level,
approval is required from the Washington Energy Facility Site Evaluation Council and the Utah.
Public Service Commission. Submittals regarding the Proposed Transaction will also take place
at the Oregon Public Utility Commission and the Washington Utilties and Transportation
. Commission.
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EXHIBITM
.EXPLANATION OF HOW THE PROPOSED TRASACTION WILL NOT RESULT IN
CROSS-SUBSIDIZATION
Section 203(a)(4) of the FPA states that the Commission shall approve a proposed
transaction if it finds that the transaction is consistent with the public interest and "wil not result.
in cross-subsidization of a non-utility associate company or the pledge or encumbrance of utility
assets for the benefit of an associate company, unless the Commission deterines that the cross-
.subsidization, pledge, or encumbrance will be consistent with the public interest.,,88
"
The Commission explained in Order No. 669:
.In our Merger Policy Statement, the Commission explained that, in
determining whether a merger is consistent with the public interest,
one of the factors we consider is the effect the proposed merger
wil have on rates. The Commission's main objective in applying
this factor is to protect captive customers who are sered under
cost-based rates that could be adversely affected by a Section 203
transaction. The new provision in amended Section 203(a)(4)
concering cross-subsidization is rooted in similar concers. 89.
"In sum," the Commission concluded, "the concern about cross-subsidization is principally a
concer over the effect of a transaction on rates. ,,90 The same facts that demonstrate that the.Proposed Transaction wil not adversely affect rates also show that the Proposed Transaction
does not raise cross-subsidization concerns. The Proposed Transaction threatens no existing
.customers with cross-subsidization. Rates under the Chehalis reactive power rate schedule are
based on the costs of the generator and wil not change as a result of the Proposed Transaction.
In addition, the only current customer purchasing output from the Chehalis Facility is PacifiCorp.
88
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16 U.S.C. § 824b(a)(4).
Transactions Subject to FPA Section 203, Order No. 669,2001-2005 FERC Stats. & Regs., Regs.
Preambles ii 31,200, at P 166 (2005), order on reh'g, Order No. 669-A, II FERC Stats. & Regs., Regs. Preambles ii
31,214, order on reh'g and clarication, Order No. 669-B, II FERC Stats. & Regs., Regs. Preambles ii 31,225
(2006).90 ¡d. at P 167.
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under the terms of the call option agreement described in this Application. The Proposed
.Transaction wil also not affect the rates paid by PacifiCorp's customers for wholesale power
pursuant to cost-based rate schedules or PacifiCorp's transmission customers because PacifiCorp
has made a hold harmless commitment.
.In Order Nos. 669 and 669-A, the Commission also identified a four-factor test that
applicants must satisfy in order to address the concers identified in Section 203 regarding any
possible cross-subsidization, pledge or encumbrance of utilty assets associated with the.proposed transaction. Under this test, the Commission examines whether a proposed transaction
results, at the time of the transaction or in the future, in:
.(1)any transfer of facilities between a traditional public utilty associate company
with wholesale or retail customer sered under cost-based regulation and an
associate company;
(2)any new issuance of securities by a traditional public utility associate company
with wholesale or retail customers served under cost-based regulation for the
benefit of an associate company;.
(3) any new pledge or encumbrance of assets of a traditional public utilty associate
company with wholesale or retail customers sered under cost-based regulation
for the benefit of an associate company; or.
(4)any new affliate contract between a non-utilty associate company and a
traditional public utility associate company with wholesale or retail customers
served under cost-based regulation, other than non-power goods and serices
agreements subject to review under sections 205 and 206 of the Federal Power
Act.91.
As required by Order No. 669-A, 669-B and the Commission's Supplemental Policy
Statement on FPA Section 203,92 Applicants herein provide a detailed showing regarding each of.these factors that the Proposed Transaction wil not result in cross-subsidization of a non-utilty
associate company or the pledge or encumbrance of utility assets for the benefit of an associate
.91
92
18 C.F.R. § 33.2(j)(l)(ii).
FPA Section 203 Supplemental Policy Statement, 120 FERC ii 61,060 at P 23 -(2007).
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company. This showing relates both to the time of the Proposed Transaction and in the future,
and is based on facts and circumstances that are known to the Applicants or are reasonably
foreseeable.
(1) Transfer of Facilities
Other than the transfer of Chehalis and the Chehalis Facility (including associated
interconnection facilities, rate schedules and various books and recrds) to PacifiCorp from
TNA, which is not an associate company ofPacifiCorp, the Proposed Transaction does not call
for any transfers of facilities, much less any transfers between a traditional utilty company and
an associate company, either at the time of the Proposed Transaction or in the future.
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.(2)New Issuance of Securities
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No new securities wil be issued by PacifiCorp for the benefit of an associate company in
connection with the Proposed Transaction, either at the time of the Proposed Transaction or in
the future. Furthermore, the Proposed Transaction wil benefit PacifiCorp, which is a traditional
utilty, and enable it to obtain capacity needed to serve its native load customers at the lowest
reasonable cost.
(3) New Pledge or Encumbrance
PacifiCorp wil not enter into any new pledge or encumbrance for the benefit of an
associate company in connection with the Proposed Transaction, either at the time of the
Proposed Transaction or in the future. To the extent not fuded with existing cash or other short-
ter sources, PacifiCorp may publicly issue its typical first mortgage bonds in connection with
the Proposed Transaction, but such issuance wil not involve or benefit an associate company.
Moreover, the Proposed Transaction wil benefit PacifiCorp, which is a traditional utilty, and
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enable it to obtain capacity needed to serve its native load customers at the lowest reasonable
.cost. No associate company wil receive any benefit from the transaction.
(4) New Affliate Contract
The Proposed Transaction wil not result in any new affliate contract between a non-
.utilty associate company and a traditional public utility associate company with wholesale or
retail customers sered under cost-based regulation. As noted below, Chehalis wil be merged
into PacifiCorp immediately following the transfer of the equity interest in Chehalis from TNA.to PacifiCorp. This wil not result in any new affliate transactions in connection with the
Proposed Transaction. The call option agreement between SEMNA and PacifiCorp wil
.terminate at the closing of the Proposed Transaction.
Based on the above, it is clear that the Proposed Transaction satisfies the Commission's
four-part test. The Proposed Transaction is not the type of transaction where cross-subsidization.is likely to be an issue. Instead, it is a traditional acquisition of a generation facility by an
electrc utilty requiring additional capacity to sere its native load.
.Finally, to the extent that the Commission had any concers regarding PacifiCorp's
dealings with affliates prospectively, PacifiCorp is currently ring fenced. PacifiCorp first
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adopted ring fencing commitments when it was acquired by Scottish Power. Subsequently, those
ring fencing commitments were enanced when MEHC acquired PacifiCorp in 2005.93
PacifiCorp's ring fencing commitments are frequently held out as an example of the types of ring
fencing commitments that protect customers from the possibilty of adverse effects of cross-.subsidization. Because the Proposed Transaction does not raise any cross-subsidization
.93 See Inre Joint Application oj MidAmerican Energy Holdings Co. & PacifCorp, Order No. 07, Docket No.
UE-OSI090, 2006 Wash. UTe LEXIS 80,248 PUR 4th 442 (Feb. 21,2006).
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concers, Applicants request waiver of any additional requirement to disclose existing pledges
and/or encumbrances of utility assets.
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A TT ACHMENT 1
AFFIDAVIT OF RODNEY FRAME.
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
PacifCorp
TNA Merchant Projects, Inc.
Chehalis Generating, LLC
)
)
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Docket No. EC08-_-000
Affdavit of Rodney Frame
I.
1.
INTRODUCTION AND SCOPE
My name is Rodney Frame. I am a Managig Principal with Analysis Group, Inc.
(Analysis Group), a consulting firm that provides microeconomic, strategy and
financial analyses. My business address is 1899 Pennsylvania Avenue, N.W.,
Suite 200, Washington, DC 20006. Analysis Group has approximately 420
employees and offices in Boston, Chicago, Dallas, Denver, Los Angeles,
Montreal, Menlo Park, New York City, San Francisco and Washington, D.C. I
have been employed by Analysis Group since Januar 1998. Prior to my
affiliation with Analysis Group, I was a Vice President at National Economic
Research Associates, Inc., where I was employed from 1984 to Januar 1998. A
copy of my résumé, which provides information on my background and
qualifications, is included as Attchment 1.
2.Most of my work in the last several years has involved consulting with electrc
industr clientsona variety of matters including restrcturing issues, wholesale
bulk power markets and competition, trnsmission access and pricing, contractual
terms for wholesale service, mergers and acquisitions and contracting for
generation supplies from non-utility suppliers.. I have testified on numerous
occasions on these and related topics, before the Federal Energy Regulatory
Commission (Commission or FERC), i state regulatory commissions, federal and
local courts and the Commerce Commission of New Zealand.
J. Attchment 2 is a listing of the abbreviations used in this affdavit and accompanying attachments.
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3.The Chehalis Generation Facilty (Chehalis Facilty) is a 520 MW (summer
rating) natural gas-fired combined cycle electrc generator located in Chehalis,
WAin the Balancing Authority Area (BAA)2 operated by the Bonnevile Power
Administration (BP A) and interconnected with the BP A trnsmission system.
The Chehalis Facility is owned by Chehalis Power Generating, LLC (Chehalis), a
wholly-owned subsidiar of TNA Merchant Projects, Inc. (TNA). TNA, in tu,
is an indirect and wholly-owned subsidiar of SUEZ, S.A. (SUEZ). PacifiCoip is
a wholly-owned subsidiary of MidAerican Energy Holdings Company (MEHC)
and an indirect and wholly-owned subsidiar of Berkshire Hathaway, Inc. The
applicants are seekig Commission approval for a proposed trnsaction pursuant
to which PacifiCorp wil purchase 100 percent of the issued and outstanding
interests in Chehalis, which then wil be merged into PacifiCorp (Proposed
Transaction). As a result, the Chehalis Facilty wil become owned by
PacifiCorp.3 Following the transaction, the Chehalis Facility wil become
integrated with the P ACW BAA operated by PacifiCorp.
4.My affidavit provides a competitive assessment of the Proposed Transaction.
Section II below provides a sumary. Section III then provides certin
background information on PacifiCorp and its affiiates, the BAAs operated by
PacifiCorp and their interconnections that is helpful in providing context for a
competitive assessment of the Proposed Transaction. Section IV provides a
general description of the methodology of the delivered price test (DPT) analysis
that is used by the Commission to assess the competitive effects in non-firm
energy markets of proposed mergers and acquisitions (such as the Proposed
Transaction). Section V then discusses the application of the DPT to the
Proposed Transaction, including a discussion of the geographic "destination"
markets that are examined and the data sources that are employed in the analysis.
Section VI presents and interprets the results of the DPT analysis and a separte
2
3
BAAs formeriy were referrd to as control areas.
PacifiCorp and SUEZ affliate SUEZ Energy Marketing NA entered into a Call Option Agreement
effective March i, 2008 pursuant to which PacifiCorp has acquired the electrc energy and capacity
from the Chehalis Facility for an approximately 9-month term potentially subject to extension.
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analysis of historical sales at key Pacific Northwest trading hubs. Section VII
considers the effects of the Proposed Transaction on capacity and ancilar
services markets. Section VIII assesses the Proposed Transaction in a vertical
context. Finally, Section IX provides my conclusion.
II.
5.
SUMMARY
My affdavit provides a competitive analysis ofPacifiCorp's proposed acquisition
of the Chehalis Facility. I apply the DPT analysis to several destination markets
in the Pacific Nortwest including BPA where the Chehalis Facility now is
located and P ACW where it wil be integrted post-trnsaction. I determine that,
when the Available Economic Capacity measure is used for the analysis, as is
appropriate for the Pacific Northwest, the trnsaction-induced concentration
changes, for all destination markets and for all season and load level
combinations, always are less than the threshold standards that the Commission
uses to identify transactions that potentially might suggest competitive concerns.
I also provide an analysis of actul historical energy sales in the Pacific Nortwest
which reinforces the conclusion of the DPT that this is not a trnsaction which
presents competitive concern in energy markets. I separately consider whether
the Proposed Transaction creates any potential for competitive concern in
capacity and ancilary service markets, or for vertical market power concerns, and
conclude that it does not.
.IIi. BACKGROUND INFORMATION ON PACIFICORP AND THE
PROPOSED TRANSACTION
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6.PacifiCorp is a traditional, vertically-integrated electric utility in the Western
Electrc Coordinating Council (WECC)4 region that, based on its most recent
integrated resource plan, has a 2008 forecast coincident peak load of 9,440 MW
and a forecast coincident peak load growth rate of 2.6 percent per year thrugh
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WECC encompasses roughly the western one-third of the "lower 48" portion of the United States, the
Canadian provinces of Alberta and British Columbia and portions of northwest Mexico.
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2016.5 PacifiCorp provides regulated retail electrc service In the states of
Oregon, Washington, Californa, Idaho, Utah and Wyoming. PacifiCorp operates
, two BAAs in WECC, an eastern BAA referred to as PACE and a western BAA
referred to as PACW. As a general matter, PACE includes PacifiCorp's loads and
resources in the states of Idaho, Utah and Wyoming6 while PACW includes
PacifiCorp's loads and resources in the states of Washington, Oregon and
Californa.7
7.Attachment 3 is a listing of the generation resources owned by PacifiCorp and its
affliates in WECC. Most of the generation resources owned by PacifiCorp are
located electrically in PACE or PACW. In addition, PacifiCorp owns a 78.1 MW
(summer rating) interest in the Hayden coal-fired facilty located in the Public
Service Company of Colorado (PSCo) BAA and a 164.5 MW (sumer rating)
interest in the Craig coal-fired facility located in the Western Area Power
Administration-Colorado Missour (WACM) BAA. As are PACE and PACW,
both PSCo and W ACM are În WECC.
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8.Within WECC, PacifiCorp's CE Generation, LLC (CE Generation) affliateS
owns the 52.3 MW Yuma Facilty located in the Arzona Public Service Company
(APS) BAA and 345.7 MW of geothermal generating capacity located in the
Imperial Irrgation Distrct BAA in California. However, since all of CE
Generation's capacity in WECC has been contracted to other parties on long-term
bases, it is not considered further in the analyses herein.
9.PacifiCorp also is affliated with MidAmerican Energy Company (MEC), which
is headquartered in Des Moines, lA, and which owns electric transmission assets
and more than 5,000 MW of generating capacity in the Midwest Reliability
5 See 2007 Integrated Resource Plan, available at htt://www.pacificorp.comlFile/File74765.pdf.at
page 65.6 'PACE also includes PacifiCorp's Cholla generating unit located in Arizona and (since June 2007) its
Big Fork generating unit located in Montana.7 PACW also includes PacifiCorp's portion of the Jim Bridger generating station located in Wyoming
and its portion of the Colstrp station located in Montana.8 CE Generation is owned 50 percent by MEHC and 50 percent by TransAlta.
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Organization reliability region, and with th Cordova Energy Company, LLC
(Cordova), which owns a 537 MW natual gas-fired combined cycle generator in
PlM Interconnection, L.L.c. However, the generation capacity of MidAmerican
and Cordova is at least five transmission links away from the BP A BAA where
the Chehalis Facilty is located and, for that reason, is far too remote to be
considered in a competitive assessment of the Proposed Trasaction.
The following 13 BAAs are first-tier to PACE and/or PACW: APS, Avista, BPA,
the Californa Independent System Operator (CAISO), the Grant County Public
Utility Distrct (Grant PUD), Idaho Power Company (Idao Power), the Los
Angeles Departent of Water and Power (LADWP), Nevada Power Company
(Nevada Power), NorthWestern Energy (NortWestern), Portland General
Electrc Company (PGE), Sierra Pacific Power Company (Sierra Pacific), WACM
and Western Area Power Admstration-Lower Colorado (WALC). Each of
these 13 BAAs is in WECC. Attachment 4 is a schematic diagr depicting (i)
the PACE and PACW BAAs, (ii) each BAA that is first-tier to one or both of
PACE and P ACW, (iii) other BAAs where PacifiCorp affiiates own generating
capacity, and (iv) BAAs or market areas that are first-tier to PacifiCorp's
transmission-owning MEC affliate.
The BPA BAA where the Chehalis Facility is located includes approximately
29,000 MW of electrc generating capacity, the largest portion of which is owned
by BP A and most of which is hydroelectric. BP A is the largest electrcity
supplier in the Pacific Northwest, owning or having under contract greater than
14,000 MW of (mostly hydroelectrc) generating capacity. BPA also has an
extensive transmission system which includes roughly 15,000 miles oflines that
covers portions of Washington, Oregon, Idaho and Montana. The BP A
transmission system is directly interconnected with numerous other BAAs in the
Pacific Northwest region including, among. others, PACW, Avista, British
Columbia Hydro, Idaho Power, NorthWestern, Puget Energy, Seattle City Light
ànd Sierra Pacific. BPA's transmission system is heavily integrated with that of
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PacifiCorp and other regional suppliers. Indeed, PacifiCorp relies in par on
transmission service provided by BP A to integrate the loads and generation
resources on its own system. My understanding is that PacifiCorp intends to use
firm transmission service from BP A in order to integrate the output from the
Chehalis Facilty into PACW.
12.SUEZ is a French société anonyme (i.e., corporation) that holds ownership
interests in a number of energy-related subsidiares internationally engaging in the
production, transport and distrbution of electrcity; power marketing; the
trnsporttion and distrbution of natual gas; the transport and distrbution of
liquefied natural gas; and the worldwide development and ownership of energy
projects.
"
iv.
13.
DPT ANALYSES
The DPT, which pertains to non-firm energy markets, is the principal analytical
technique used by the Commission to examine potential competitive effects of
transactions under Section 203 of the Federal Power Act. The DPT is described
in Appendix A of Order No. 592, the Commission's Merger Policy Statement,9 in
Order No. 642, Revised Filing Requirements Under Part 33 of the Commission's
Regulations10 and in Appendix F of AEP i. i 1
14.The basic approach under the DPT is to define individual destination markets,
determine the "competitive price" in each of these individual destination markets,
and then measure concentration and transaction-induced changes in concentration
9 Inquiry Concerning the Commission's Merger Policy Under the Federal Power Act: Policy
Statement, Order No. 592, 77 FERC ii 6 1,263 (i 996).
Revised Filing Requirements Under Part 33 ofthe Commission's Regulations, Final Rule in Docket
No. RM98-4-000, Order No. 642, 93 FERC ii 6 i, 164 (2000).
AEP 1 refers to AEP Power Marketing, Inc., et al., 107 FERC ii 61,018 (2004). HistoricaJly, the
Commission has used the DPT to analyze the potential competitive effects of proposed mergers and
acquisitions of generating assets. In AEP 1, the Commission extended the use of the DPT to a new
context-as part of the process to consider the appropriateness of market-based rate authority. In that
contèxt, the DPT can be used to provide potentiaJly exculpatory evidence to overcome the market
power presumption that the Commission makes for suppliers that have failed one or both of its
indicative horizontal market power screens.
10
II
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of ownership or control of generating resources that are located in or can be
delivered to each destination market at a delivered price (taing into account
transmission prices, losses and constraints) that is no more than 1.05 times the
competitive price in that destination market. Concentrtion and changes in
market concentration are measured using the HHI (for Herfndahl-Hirschman
Index).12 In addition to HHIs, market shares also are computed.
15.Two different generation capacity measures are used for DPT analyses. The first
of these, Economic Capacity, is all generation capacity that can be delivered to
the destination market being examined at a price that is no greater than i .05 times
the competitive price in that market. The Economic Capacity measure ignores
retail load and wholesale contract obligations. The second generation capacity
measure, Available Economic Capacity, does take retail load and wholesale
contract obligations into account. Available Economic Capacity is equal to
Economic Capacity less the capacity required to meet a supplier's obligation to its
retail customers and its pre-existing wholesale commitments.
16.In determining which supplies can be economically delivered to the destination
market or markets being studied, DPT analyses incorporate transmission prices
and losses and reflect transmission system limits. Determining which generating
resources actually can compete in each destination market for each season and
load-level, combination, at a price that is no greater than 1.05 times the
competitive price, requires taking into account variable costs (fuel, O&M and
emissions) on a generator-by-generator basis and transmission limits, prices and
losses.
17.DPT analyses are pedorred for multiple season and load level combinations in
order to reflect a range of different demand and supply conditions. Appendix F of
AEP I indicates that there shouH be a total of 10 different season and load level
12 The \lHI is equal to the sum of the squared market shares of the finns in a market. Thus, a market
with i 0 equally-sized finns has an HHI of 1,000 (equal to lOx 102) while a market with four equally-
sized finns has an HHI of2,500 (equal to 4 x 252).
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combinations examined-four load levels durng the Sumer and three load
levels during each of the Winter and combined Spring/all (or Shoulder) seasons.
18.The destination markets that are used for DPT analyses depend on the nature of
the specific transaction. For a transaction that involves the acquisition of a single
generator, those destination markets are likely to include the BAA (or, if
appropriate, RTO or iso footprint) where the to-be-acquired generator is located
and, if different, the BAA (or RTO/ISO footprint) where the acquiring pary is
located. Other directly interconnected BAAs also may be included in the analysis
if there is the potential that signficant competitive effects might occur there.
DPT analyses of mergers of two generation and transmission owning entities are
likely to include a broader range of destination markets.
.'
19.The transaction-induced HHI changes computed under a DPT analysis, for each
geographic (destination) market examined, for each season and load-level
combination and for each of the Economic Capacity and Available Economic
Capacity measures, are compared to the "safe harbor" thresholds from the joint
US Deparent of Justice and Federal Trade Commission Horizontal Merger
Guidelines (Merger Guidelines) that the Commission has adopted. A safe harbor
exists if: (i) the post-transaction HHI is less than 1,000; (ii) the post-transaction
HHI is between 1,000 and 1,800 and the transaction-induced HHI change is less
than 100, or (iii) the post-transaction HHI is greater than 1,800 and the
transaction-induced HHI change is less than 50.13 When transaction-induced HHI
changes exceed these levels, the applicants can propose mitigation measures or
seek to demonstrte why no mitigation is necessary notwithstanding the presence
of "screen violation(s)."
13
Under the Merger Guidelines, an HHI that is less than 1,000 is said to denote an "unconcentrated
marJ(et", an HHI between 1,000 and 1,800 is said to denote a "moderately concentrated" market and
an HHI that exceeds-I,800 is said to denote a "highly concentrated" market.
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V. APPLYING THE DELIVERED PRICE TEST ANALYSIS TO
PACIFICORP'S ACQUISITION OF CHEHALIS.20.
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While it is questionable in my mind whether it is appropriate to do so for an
integrated regional electricity market such as the Pacific Northwest, I nevertheless
adhere herein to the Commission's traditional DPT paradigm and largely focus
my DPT analysis on individual BAAs. The individual BAAs that I examine are '
PACW, PACE, Idaho Power, Avista, BPA and PGE. The rational for including
these six destination markets is provided below. The six destination markets are
depicted schematically in Attchment 5, which also shows the various BAAs that
are modeled as potential supply sources in these DPT analyses (including all
BAAs first-tier to PACW and/or PACE) and various transmission links between
these external BAAs and the six destination markets.
14
The Chehalis Facility is located in the BPA BAA. However, as indicated, my
understanding is that PacifiCorp intends to use firm transmission service from
BPA in order to be able to integrate the Chehalis Facility into PACW.
Accordingly, PACW is one of the geographic markets that should be examined to
assess the competitive effects of the Proposed Transaction.
I include PACE in the list of BAAs examined since PacifiCorp owns
approximately 6,500 MW of generating capacity there. This generation
ownership creates at least the potential for measurable transaction-related
concentration changes in PACE. I include Idaho Power in the list of BAAs
examined since it is interconnected with both PACW (where PacifiCorp also has
important generation holdings and where the Chehalis Facility wil be integrated
post-transaction) and with PACE. I include Avista and PGE in the list of BAAs
examined because they are also first-tier to PACW. Finally, I include BPA in this
list since it is where the Chehalis Facility is located and is also first-tier to PACW.
.
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14 Unlike for the application of its indicative generation market power screens, the Commission does not
restrict the potential suppliers that can be included in DPT analyses just to those that are first-tier to
the geographic market being examined. Of course, in application, the presence of more remote
suppliers in the geographic market being studied tends to be diluted by the additional transmission
costs and potential transmission constraints that they face.
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23.Two other BAAs (CAISO and Grant PUD) also are first-tier to PACW, where the
Chehalis Facility wil be integrated post-trsaction, but are not included as
destination markets for the analyses herein. The CAISO BAA is simply too large
(e.g., more than 50,000 MW of generation capability and roughly 20,000 MW of
simultaneous import capability) for there to be any noticeable transaction-related
concentration effect there, especially given that PacifiCorp does not own 'or
control any generation capacity in CAISO. As concern Grant PUD, for puroses
of the competitive analyses herein, Grat PUD is more properly considered on a
combined basis with the BP A BAA rather than on a separate basis, and therefore
is examined on such a combined basis herein. 15
"
24.I also do not include as destination markets other BAAs that are first-tier to PACE
because of their remoteness from PACW (and BPA) and therefore the
inevitability that transaction-related concentration changes there would be trviaL.
That this must be tre is demonstrated by the relatively small trnsaction-induced
concentration changes in the markets that are examined, as demonstrated below.
The transaction-induced concentration changes in more remote markets
necessarily would be even smaller than those reported herein.
IS The load in the Grant PUD BAA is approximately 550 MW while the generation capacity located
there, pnncipally the Pnest Rapids and Wanapum hydroelectnc stations on the Columbia River,
exceeds 2,000 MW. The Grant PUD BAA is highly integrated with the Douglas County PubJic
Utility Distnct (Douglas PUD) BAA and the Chelan County Public Utility Distnct (Chelan PUD)
BAA where other large, non-federal hydroelectnc stations on the Columbia River are located. Within
the Douglas PUD BAA, where the 840 MW Wells hydroelectnc station is located, peak load is only
about 330 MW. Within the Chelan pub BAA, where the 624 MW Rock Island and 1,280 MW
Rocky Reach hydroelectnc stations are located, peak load is less than 600 MW. Grant PUD, Douglas
PUD and Chelan PUD operate their buses as a single point of deJivery and receipt known as the Mid-
Columbia (Mid-C) market bus for scheduling electcity trnsactions. Mid-C is the most active
trding hub in the Pacific Northwest and pnces there are routinely reported by a number of finns,
including Dow Jones, Powerdex and MW Daily. Grant PUD, Douglas PUD and Chelan PUD also are
tightly interconnected with the BP A system, which has established a composite point of receipt and
delivery (Northwest Market Hub) at five of its substations that surround the five non-federal
hydroelectnc projects on the Columbia River owned by Grant PUD, Douglas PUD and Chelan PUD
(i.e., Pnest Rapids, Wanapum, Wells, Rock Island and Rocky Reach). My understañding is that
transmission between the Mid-C hub and the BPA system is unconstrained and that the generation
owners at Mid-C do not incur any trnsmission charges to get to the BPA system. Given the strong
intertonnections among Grant PUD, Douglas PUD, Chelan PUD and BPA, I think that it is
appropnate to combine these systems for purposes of the market analyses herein and therefore have
done so.
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25.My analysis includes only BAAs located in WECC. As discussed, affliates of
PacifiCorp own generation capacity in certain BAAs outside of WECC, but that
generation capacity is simply too remote from the destination BAAs examined
herein to have any noticeable effect on the results of DPT analyses. For example,
generation capacity owned by PacifiCorp's MEC affliate is five transmission
links away from PACW.
26.Since adverse competitive effects from a proposed transaction, if any, wil occur
in the future, it is appropriate to use a forward-looking study year for DPT
analyses of potential mergers and acquisition.16 Accordingly, I use a 'study year
beginning December 1,2008 and extending though November 30,2009. I refer
to this as the 2008/9 Study Year. The 2008/9 Study Year represents the first full
December I-November 30 study year (or large portion of such study year) after
the expected closing of the Proposed Transaction.
27. Providing a DPT analysis requires developing data in a number of areas including
generator characteristics, loads, market-clearing prices (MCPs) and transmission
capacity, prices and losses.
16 While the Commission requires the use of historical study years for puroses of applying its indicative
generation market power screens, and for DPT analyses that are used to seek to overcome the "market
power presumption" of any such failed screens, I am unaware that the Commission has ever made a
similar determination that historical study years are appropriate for the analyses ~f mergers and
acquisitions. Most of the Section 203 DPT analyses with which I am familar have used forward-
looking study years. For example, in Docket No. EC0543, concerning the proposed merger of
Exelon and PSEG, the application, which was submitted to the Commission on February 4, 2005,
used a prospective 2006 study year. See, e.g., 112 FERC' 61,01 1 at P 12. In Docket No. EC05-103,
concerniHg the merger of Duke and Cinergy, the appljçation, which was originally submitted to the
Commission on July 12,2005 (and later amended), used a 2006 study year. See, e.g., 113 FERC 1
61,297 at P 24. In Docket No. EC 05-110, concerning MEHC's acquisition of PacifiCorp, the
application, which was originally submitted to the Commission on July 22, 2005 (and later amended),
used a 2006 study year. See, e.g., 113 FERC' 61,298 at P. 19. Each of these three tranasactions was
approved by the Commission, although the Exelon and PSEG merger was never consummated.
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28.The base data source that I use for much of the generator-related information for
the DPT analyses is Platts' BaseCase,17 which is commercially available. This
information includes generator names and owners, summer and winter ratings,
heat rates, non-fuel varable O&M expenses and emissions rates. The information
in Platts' BaseCase is taken from a variety of publicly-available sources including
FERC Forms 1 and 423, EIA Forms 411, 767, 860, 861 and 906 (and predecessor
Form 759) and NERC GADS. I believe that ths database is a widely-used source
of industr information and, as corrected in the fashion described below, is
appropriate for puroses of my analyses.
"
29.Both for generating unts owned by PacifiCorp and generating units owned by
other suppliers, I used planed and forced outage factors from Platts' BaseCase to
de-rate (non-hydroelectric and non-wind) generator capacities to levels that are
appropriate for use in DPT analyses under the Commission's procedures.
Scheduled outages were assumed to occur during the combined Springlall
season while forced outages were assumed to occur throughout the year.
30.The non-fuel variable O&M figures in Platts' BaseCase include estimates of SOi
emissions costs for coal units. Accordingly, it was not necessary separately to
develop information for sulfu content of fuel, allowance prices, the identity of
units with scrubbers, or changes in O&M costs attbutable to scrubbing. The
geographic portion of the countr covered by the DPT analyses lies outside the
portion of the countr where generators must obtain NOx allowances and thus it
was not necessary to incorporate the cost of NO x allowances in the study.
31.As is always the case for a study like this, certin corrections to the base data set
were appropriate. Among other things, these corrections include moving to
PacifiCorp's generation "bucket" long-term purchases that might be deemed to
17 The information in Platts' BaseCase was supplemented, as appropriate, with information from the
WECC "Existing Generation and Significant Changes" fies, e.g., when information from the latter
was helpful in determning the BAA location of particular generators and to determne the market
sales potential of industrial generators.
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convey to it operational contrl of generating capacity; using seasonal rating, heat
rate and non-fuel variable O&M information provided by PacífiCorp for
PacifiCorp's own thermal generators (and the thermal generators that it owns
jointly with others); using information found on the websites of the Uta
Associated Municipal Power Systems and the Utah Municipal Power Authority to
identify generators owned by those systems' member and, where the assignent
of generators to owners and BAAs was incorrect, making those assignents
correct. My workpapers include a copy of the final generator database that was
used for the DPT analyses.
32.Under the Commission's procedures, it is appropriate in DPT computations to
combine generation capacity owned by affliates. However, CE Generation is
PacifiCorp's only generation-owning affliate in WECC. Because all of the
output from CE Generation's generation capacity in WECC has been sold to other
paries on long-term bases, I appropriately do not combine it with PacifiCorp's
generation holdings in the DPT analyses provided herein. Other generation
capacity owned by PacifiCorp's affliates, as noted, is far too remote to have any
noticeable effect on the DPT analyses provided herein.
33.For DPT analyses, it is necessar to develop delivered fuel prices for individual
electric generators. For generators fueled by natural gas, I mapped individual
generators to western natural gas hubs based on the location of the generators and
their distance from the hubs and used forecast natural gas prices from Bloomberg
for each of the individual hubs.18 For generators fueled by coal I used plant-level
forecast coal prices from Platts' BaseCase. For oil-fired generators, I used
forecast monthly oil prices also taken from Platts' BaseCase. For the remaining
generators in my analysis (nuclear, hydro, solar, geothermal, wind, wood, waste
18 An exception involves PacifiCorp's Hermiston facility, the natural gas for which is supplied under a
fixedprice contract. For Hermiston, 1 used the natural gas prices reported in PacifiCorp'sFERC
Form i, escalated and adjusted as appropriate to reflect study year contrct price increases.
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and refuse), I assumed a suffciently low fuel price to ensure that these generators
always were in the dispatch when available. 19
34.The analyses herein reflect generation capacity additions and retirements if the in-
service date or retirement date is indicated to be prior to the beginning of the
summer season in the DPT.
35.Order No. 697 allows applicants for market-based rate authority to derate
hydroelectrc and wind generation capacity to reflect actual output levels during
an historical 5-year period. I use this same derating process herein. For
PacifiCorp, I do this derating using actual historical hour-by-hour output levels
that are mapped to the 10 season and load level combinations used in the DPT.
For most of BPA's hydroelectrc facilities, and those of Grant PUD, Chelan PUD
and Douglas PUD, I estimated hour-by-hour output levels using monthly output
data from Platts' BaseCase and hour-by-hour water flow information from
Columbia River DART.2o For other hydroelectric generators in the Pacific
Northwest, where I did not have comparable hour-by-hour water flow data, I used
the same output shapes that I developed for BPA's, Grant PUD's, Chelan PUD's
and Douglas PUD's hydroelectric generators. For hydroelectrc generators
outside the Pacific Nortwest, where I likewise did not have comparable hour-by-
hour water flow data, I used actual historical month-by-month output data from
Platt' BaseCase and assumed the limited water supply was used to "peak shave".
For PacifiCorp's wind generators where there is no 5-year history, I have used
estimated hour-by-hour capacity factors provided by PacifiCorp.
"
36.As indicated, in accordance with the Commission's discussion in Appendix F of
AEP I, I have divided the year into 10 periods and performed computations for
each such "DPT period". There are three seasons, consisting of Summer (June,
19 As noted below, however, I derated hydroelectric generating capacity to reflect average achieved
outpat levels during an historical 5-year period.
Columbia River DART refers to Columbia River Data Access in Real Time. See
htt://ww.cbr.washington.edu/dartgas_com.htmI.
20
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July and August), Winter (December, January and February) and a combined
Spring/all or Shoulder (March, April, May, September, October and November).
There are four separate load levels in the Summer (Extreme Peak, Super Peak,
Peak and Off-Peak) and three separate load levels in the Winter and Spring/all
(Super Peak, Peak and Off-Peak). The Extreme Peak in the Sumer consists of
the one percent of peak hour with the highest demand levels while the Super
Peak consists of the remaining (after taing into account the Extreme Peak hour)
portion of the ten percent of peak hours with the highest demand levels. The Peak
consists of all remaining (after taking into account the Extreme Peak and the
Super Peak) peak hours. The Off-Peak is defined as Sundays, certin holidays
and the overnight hours between 2200 and 0600. The load periods in the Winter
and Spring/all seasons are similar, with the only difference being that there is no
separate Extreme Peak period in the Winter and Spring/all. I refer to these 10
separate DPT periods as Summer 1 (Summer Extreme Peak), Sumer 2 (Sumner
Super Peak), Summer 3 (Summer Peak) and Summer 4 (Summer Off-Peak);
Winter 1 (Winter Super Peak), Winter 2 (Winter Peak) and Winter 3 (Winter Off-
Peak); and Spring/all 1 (Spring/all Super Peak), Spring/all 2 (Spring/all
Peak) and Spring/all 3 (Spring/all Off-Peak). The period with the lowest
number each season (e.g., Summer 1) is the period with the highest demand.
It is necessary to assemble hour-by-hour load data for the study year in order to
determine Available Economic Capacity for PacifiCorp and other suppliers. For
this purose, PacifiCorp provided forecast 2008/9 Study Year loads for PACW
and PACE, both for the BAA taken as a whole and for the portion that is
PacifiCorp's load responsibility. For other suppliers and BAAs, I used historical
load data obtained from WECC and escalated as appropriate to the 2008/9 Study
Year using regional growth rates contained in the North American Electrc
Reliability Corporation's 2007 Long-Term Reliability Assessment, 2007-2016.
Where load data for a particular supplier were not available, I conservatively
omitted that supplier in the Available Economic Capacity computations.
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38.Because generation capacity that is used to provide spinning and regulating
reserves cannot simultaneously be used to make wholesale sales of electrc
energy, the load data as described above were adjusted to incorporate spinning
and regulating reserve requirements. For PACE, I developed actual historical
hour-by-hour spinning and regulating reserve amounts for each of PacifiCorp's
thermal generators within PACE for the December 1, 2005 though Januar 31,
2008 time period. I then expressed these as a percent of load for each DPT
period2J and assumed that these same percentages wil apply during the 2008/9
Study Year, both for PacifiCorp in PACE and for other suppliers with the
exception of BPA and PacifiCorp for its PACW load. For PACW, I used a
similar approach as I did for PACE except that I excluded spinning reserve and
regulating reserve requirements met from hydroelectrc generation sources in the
determination of the percentages. For suppliers in BP A, I assumed that all
spinning and regulating reserve requirements could be met by hydroelectrc
generation not being used to provide energy and therefore, given the 5-year
derating procedure used for hydroelectric generation, that no separate spinning
and regulating reserve adjustment was appropriate.
"
For the analysis of the PACW, BPA, Avista and POE BAA destination markets, I
used MCPs estimated by PacifiCorp for the Mid-C hub from forward price curves
developed from broker quotes and hourly scaling factors. These hour-by-hour
prices then were averaged across the hours durng each of the 10 season and load
level combinations used in the DPT study. I used similar estimates for the Palo
Verde hub to develop MCPs for the PACE and Idaho Power BAAs.
For market analyses under the Commission's procedures, it is appropriate to move
generation capacity from the bucket of the seller to the bucket of the buyer when
long-term sale transactions involve a conveyance of operational control of
generation capacity from the seller to the buyer. .. PacifiCorp does not have any
sales that fall into this category. However, it does have two long-term firm
~1 These amounts ranged between i.9 percent and 2.8 percent across the i 0 DPT periods..
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purchases, involving the Hermiston22 and Goshen23 facilities, which potentially
fall into this category. Accordingly, I adjusted PacifiCorp's generation holdings
to reflect those two purchases.
41.As concerns suppliers other than PacifiCorp, I am not aware of any data source or
easy-to-implement procedure that would allow ready identification of long-term
purchase and sale transactions that convey operational control of generation
capacity.24 However, I did review the market screen filings to the Commission of
a number of the other major suppliers included in the geographic region covered
by the DPT analyses25 to see whether they identified any long-term transactions
where operational control of generation capacity was conveyed to the purchaser.
I identified only thee such instances from that review where the requisite transfer
of operational control is present.26 Two of these involve an affliate of Avista27
"
22 PacifiCorp owns 50 percent of the 465.8 MW (summer rating) Hermiston combined cycle facility and
purchases the other 50 percent of the output from the facility's joint owner, Hermston Generating
Company. While Hermston Generating Company operates the facility, PacifiCorp has dispatch
nghts for all of the output. The Hermston facilty is located electncally in the PACW BAA but
trnsmission from BPA is required to deliver its output to PACW loads.
Goshen is owned by Airtcity Developments, Ltd., Invenergy, LLC and Ridgeline Energy LLC, but
i 00 percent of its output is sold to PacifiCorp under a long-term contract that expires in 2026. Whíle
PacifiCorp does not operate Goshen, under the long-term contrct between it and the facilites' owners
PacifCorp has the nght to curtail its purchases from the facilty. Arguably, therefore, PacifiCorp may
be considered to have the ability to prevent the energy from Goshen from reaching the market. For
this reason, I conservatively have assigned Goshen to PacifiCorp in the analyses herein.
There are data sources, such as FERC Form i and the Commission's Electnc Quarterly Reports,
which contain information on purchase and sale transactions. However, there are none, of which I am
aware, that identify long-term purchases and sales that convey operational control of generation
capacity.
The suppliers included in this review APS, Avista, Idaho Power, Nevada Power, NorthWestern,
PacifiCorp's former affliate PPM Energy (PPM), PPL Montana and its affliates, PSCo and Sierr
Pacific.
My review identified other long-term purchase and sale trnsactions, but none where the applicants
submitting those screen analyses indicated that the requisite conveyance of operational control of
generating capacity to the buyer was present.
Avista's September 27,2004 market screen fiing in Docket Nos. ER99-1435-006 et al., indicates that
A vista Utilities leases and operates a two-unit natural gas-fired CT facilty ("the Rathdrum project.")
and that A vista Energy has all dispatch and output nghts to the Lancaster Natural Gas Combined
Cycle Generation plant (owned by Rathdrum Power LLC). Each of these two facilties is included in
Avi&ta's bucket in the DPT analyses reported on herein. Also, Idaho Power's market screen study
. indicated that it had in place a 30 MW load-following sale to NorthWestern. I also reflect this in my
analysis.
23
24
25
26
27
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while the third involves PacifiCorp's former PPM affliate.28 In each of these
three cases, my analysis appropriately places these facilties in the buyers'
buckets. Of course, because the data sources in ths area are imperfect, it is
possible that there are long-term trnsactions involving entities other than
PacifiCorp where the requisite operational control of generation capacity passes
from the seller to the buyer but which have not been identified for my analyses.
However, to the extent that this is tre, the omission is not likely to have a
noticeable effect on the DPT results. What is most importt for purposes of this
DPT analysis is to obtain accurte information on PacifiCorp's purchases and
sales, and I have been supplied with this information for PacifiCorp. While it
would be desirable to have perfect information for all market participants'
transactions, errors or omissions with respect to other market participants'
transactions wil have a much less importt effect (if any) on study results than
wil errors or omissions concerning PacifiCorp's transactions.29
42.DPT analyses require developing data on transmission prices and losses. For this
purose, I generally used varous transmission providers' open-access
transmission tarffs (OATTs). I used the ceiling rates for non-firm service. In
cases where there were separate peak and off-peak rates, I incorporated these in
the analyses. Where there were no separate peak and off-peak rates, I used a
single ..all-hour" rate. Where they were separately stated on a pe MWh basis, I
added ancilary service charges for (i) Scheduling, System Control and Dispatch
28 PPM owns the 519 (nameplate rating) Klamath Falls combined cycle facility (Klamath Falls) jointly
with the City of Klamath Falls, OR. Klamath Falls is located in the BPA BAA. PPM operates this
facility and markets all of its output.
There are other reasons to think that any errors that hypothetically might be introduced because of
imperfect and incomplete data on purchase and sale trnsactions of other market participants wi) be'
of very limited importnce, if any. The Idaho Power BAA is one of the destination market BAAs
studied in the DPT analysis and Idaho Power's market screen studies have indicated that it did not
have any long-term purchases or sales that convey operational control of generation capacity. The
PACE and P ACW BAAs are also included as destination markets and PacifiCorp is the largest
generation owner in each of these. PacifiCorp's long-term purchases appropriately have been
reflected in the analyses provided herein. Also, BPA is the largest generation owner in the geogrphic
area covered by the DPT study. PacifiCorp is among the entities that purchase wholesale electricity
from BPA but none of its purchases are of the type conveying operational control of generation
. capacity. To the extent that BPA's contractual arrangements with other of its customers are similar to
those with PacifiCorp, then BPA does not have any wholesale trnsactions where operational control
of generation capacity is conveyed.
29
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and (ii) Reactive Supply and Voltage Control from Generation Sources services.
Where there were no such separate ancilar servce charges provided, I assumed
that they were included in the base non-firm "access" charge.
DPT analyses also generally require developing Total Transmission Capabilty
(TIC) data for individual transmission paths between BAAs and estimates of
simultaeous import limits (SIL) into the individual destination markets that are
being examined.
PacifiCorp developed estimates of SIL into the PACE and P ACW BAAs using
techniques outlined by the Commission in Appendix E of AEP I. The estimates
for PACE are the same as those used in prior DPT analyses for PacifiCorp and
previously provided in affidavit form to the Commission. My understanding is
those prior SIL estimates are valid for the 2008/9 Study Year examined herein.
The SIL estimates for PACW are provided in Mr. Tjoelker's affdavit. For each
of the PACE and P ACW BAAs, I reduced the SIL estimates to reflect
PacifiCorp's remote generation resources.
.'
PacifiCorp's Cholla and Big Fork resources are included as par of the PACE
BAA but remote from the area for which the PACE SIL was estimated.
Accordingly, I reduced the PACE SIL to reflect the import of those resources.
PacifiCorp's interests in the Craig and Hayden resources are not part of the PACE
BAA-;raig is in the W ACM BAA while Hayden is in the PSCo BAA-but
PacifiCorp has obtained certain transmission rights that allow the import into
PACE of its Craig and Hayden interests. I therefore also reduced the SIL into the
PACE BAA to reflect PacifiCorp's Craig and Hayden interests. I also reduced the
PACE SIL to reflect a 100 MW "dynamic overlay" path that PacifiCorp has
obtained that allows its PACW resources to be used to provide spinning reserve
and regulation for PACE.
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46.I made analogous reductions to the PACW SIL estimated by Mr. Tjoelker.
PacifiCorp's interests in the jointly-owned Bridger and Colstrp coal-fired
facilities, its Swift hydroelectrc generator, its Goodnoe Hils wind project, a
portion of its owned and purchased interests in Hermiston,30 and its Leaning
Junper facility all are PACW resources but located outside the area for which Mr.
Tjoelker has estimated the PACW SIL. Accordingly, I reduced the PACW SIL
amount to reflect each of these remote P ACW generators. As well, for the post-
transaction computations, as described below, I assumed that the Chehalis Facilty
has been moved from its BP A location to P ACW and therefore further reduced
the P ACW SIL to reflect this import..'
47.For the Idaho Power BAA, I used SIL estimates developed and used by Idao
Power in its own indicative screen fiings and posted on Idao Power's OASIS. I
reduced these SILs to reflect Idaho Power's remote owned generation resources,
i.e., its 707 MW (sumer rating) interest in the Jim Bridger station, its 261 MW
(summer rating) interest in the Nort Valmy station and its 58.5 MW (summer
rating) interest in the Boardman unit. For the Avista and PGE BAAs, I used SIL
estimates developed and used by A vista and PGE, respectively, in their
Commission-accepted indicative screen filings. While my understanding is that it
was not fied with FERC, I used a SIL estimate that BP A used in its own market
screen study for the BPA BAA.3 i
48.These SIL values-adjusted as described for the PACE, PACW and Idaho Power
BAAs-then served as a cap on BAA imports for the DPT analyses herein. This
cap was implemented by proportionally reducing each of the single path TTC (or
30 A portion of the Hermiston facility is deemed to be inside the area for which Mr. Tjoelker developed
the PACW SIL estimate. Accordingly, it was only necessary and appropriate to reduce the PACW
SIL estimate to reflect the remaining portion.31 . See page C-28 of Wholesale Power Rate Development Study, November 2005, WP-07-E-BPA-05,
available at htts://secure.bpa.gov/RateCaselUploads/wp-07 -e-bpa-05 .pdf.
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equivalent) values so that, when summed, they were equal to the SIL value
(adjusted as appropriate) discussed above.32
49. . For the TIC values for the individual BAA-to-BAA transmission paths, I used
several sources including OASIS data provided by PacifiCorp, the WECC Path
Rating Catalog, the US Deparent of Energy's "Western Interconnection 2006
Congestion Assessment Study" and prior DPT analyses provided to the
Commission. As noted, these TTC values ultimately were "squeezed" so that,
when sumed, the TTC values into the destination markets did not ex-ceed the
SIL values. As I did for the SIL values, I reduced certin of the individual path
TTC values (into the PACE, PACW and Idaho Power BAAs) to reflect remote
owned generation resources and, for the PACW-PACE path, the 100 MW
dynamic overlay.
"
50.In instances where the amount of supply deemed to be competing to use a
particular transmission path exceeded the capacity of that path, I used a
"proportional" method to allocate that path capabilty among potentially
competing suppliers. Under this approach, I first summed supplies deemed to be
competing to use a particular path and then attbuted to each supplier the amount
of the path represented by the proportion that its competing supplies are of the
total of all competing supplies. That is, if supplier X has 200 MW of capacity
deemed by the analysis to be competing to use a particular 400 MW path, and
four other competing suppliers each have 200 MW as well, then supplier X wil
receive an allocation of 80 MW or its pro rata share.
51.I used this proportional method because it recognizes the presence of all
competing suppliers in the analyses. The principal alternative to this proportional
allocation method is an "economic" method that assigns limited transmission
capability to the suppliers with the lowest deliv.ered costs. The economic
32 Thus, for example, if there are three 500 MW paths into a BAA where the SIL is 1,000 MW, each of
these'three paths would have its value reduced by i /3. After this reduction, when summed, the three
individual path values wil total the 1,000 MW SIL.'.
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allocation method overlooks entirely in the HHI determinations all suppliers other
than those that gain an allocation of the limited transmission capabilty even
though those other suppliers also can deliver energy into the destination market at
a price less than or equal to 1.05 times the competitive price. Therefore, the
economic method ignores the competitive pressures from those other suppliers
and, as a result, may artificially overstate market concentration as measured by
the HHI. The proportional allocation method has been accepted by the
Commission on prior occasions.
VI.
52.
DPT RESULTS AND INTERPRETATION
Summary results of the DPT analyses are contained in Attchments 6(A vaiJable
Economic Capacity) and 7 (Economic Capacity). These summary results provide
post-transactions shares for PacifiCorp, post-transaction market concentration and
transaction-induced changes in market concentration. More detailed results for
each of the individual destination markets examined are contained in Attchments
8-13 (Available Economic Capacity) and 14-19 (Economic Capacity).
53.While I have included the Economic Capacity analyses in Attchments 7 and 14-
19, in conformance with the Commission's requirements, I do not think that those
Economic Capacity analyses have any value whatsoever for assessing whether or
not PacifiCorp might be able to exercise market power in wholesale electrcity
markets. The reason for this is that the Economic Capacity measure entirely
ignores the very load obligations that are the linchpin of the resource planning
processes of traditional suppliers such as PacifiCorp. The Economic Capacity
measure in essence assumes that traditional suppliers such as PacifiCorp do not
have any native load obligations, or are free to disregard them, whereas, in fact,
that clearly is not the case.33 For this reason, my discussion below focuses on the
DPT results using the Available Economic Capacity measure.34
33 PacifiCorp's Form 10-K report to the Securities and Exchange Commission for the year ending
Dec~mbeT 31, 2007, at page 15, indicates that while PacifiCorp operates "its retail business under
state regulation, which generally prohibits retail competition", there is a 1999 Oregon law that allows
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54.The Attchment 6 summar indicates that the Proposed Transaction does not
create any screen violations in any of the six destination markets examined,
including PACW where the Chehalis Facility wil be integrted post-transaction.
In PACW, the post-transaction HHI always falls in the lower portion of the 1,000-
1,800 range that denotes a moderately concentrated market under the Merger
Guidelines. The transaction-induced HHI changes are zero in the off-peak
periods-since the Chehalis Facility is not in-the-money then under the DPT's
procedures--and either very small or negative in the peak periods.35 These
results are consistent with a priori expectations since PacifiCorp does not have
any Available Economic Capacity in P ACW on a pre-transaction basis during any
of the peak periods (i.e., Summer 1, 2 and 3; Winter 1 and 2; and Springlall 1
and 2).
"
55.In the other destination markets, the post-transaction HHIs fall into either the
moderately concentrated or unconcentrated Merger Guidelines' rages. The
largest transaction-induced HHI changes, which occur in the BP A and PGE
destination markets and which stil are below the Merger Guidelines'
34
certain commercial and industral customers to choose alternative electrcity suppliers. However,
dunng 2007, the average load for such customers was only 12 MW.
In several recent decisions, including involving PacifiCorp, the Commission appear to have
concurred that the Available Economic Capacity measure is the more relevant of the two for assessing
competitive conditions in areas of the county where the trditional industry strctural paradigm
remains. For example, in approving Nevada Power Company's acquisition of the Silverhawk Power
Station, the Commission indicated, where there are significant native load obligations, with "no
foreseeable prospect that they wil be lifted", as is the case for PacifiCorp's servce to customers in
PACW and PACE, "Available Economic Capacity is the more relevant measure." See Nevada Power
Company and GenWest LLC, 113 FERC , 61,265 (2005). Also, in several recent proceedings, the
Commission has emphasized the results of Available Economic Capacity computations in OPT
analyses, rather than Economic Capacity computations, in supportng its determination that the
applicants in those proceedings had rebutted the presumption of market power in wholesale electncity
markets in their home BAA based upon failed market screen analyses. See Arcadia Power Partners.
LLC et al.,1 13 FERC '61,073 (2005), Kansas City Power and Light Company. et al., 113 FERC'
61,074 (2005), Public Service Company of New Mexico, I is FERC' 61,239 (2006), PPL Montana.
LLC. et al., i is FERC , 6 1,204 (2006), PacifCorp, et al., i 15 FERC , 6 i ,349 (2006) and Tucson
Electric Power Company, 116 FERC' 61,052 (2006).
The HHI decreases that occur for PACW in the Summer 3, Winter 2 and Spnnglall 2 penods result
pnncipally from the fact that BPA's relatively large market share decreases very slightly as some of
the SIL is used to move the Chehalis Facility to PACW therefore lessening SIL available to Other
parties (including BPA).
3S
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thresholds,36 occur not because PacifiCorp's market shares increase but, instead,
because those for a thrd part, BPA, increase.37
56.Under § 33.3(d)(6) of the Commission's regulations, applicants must demonstrate
that the results of their DPT analyses "do not var significantly in response to
small varations in actual and/or estimated prices." Accordingly, I have
conducted sensitivity analyses where I increase and decrease the MCPs by 10
percent. The results of these sensitivity analyses, which are provided in my
workpapers, are little different than the results of the "base case" analyses in
Attchments 6_19.38
57.The Commission's recent Order No. 697-A (123 FERC ~ 61,055 (2008)) at P 144,
provides that market-based rate sellers in their indicative screen computations
must allocate to themselves SIL capability associated with their firm transmission
reservations that are greater than one month in duration. The extent to which ths
requirement constitutes a deparure from prior practice is unclear, including, in
particular, whether the requirement is intended to apply only to transmission
36 For example, in the BPA market, the Winter i and 2 trnsaction-induced HHI changes are 90 and 87,
respectively, while the post-transacton HHls are 1,451 and 1,263, respectively. In the PGE market,
the SpringlFall 1 trnsaction-induced HHI change is 76, while the post-trnsaction HHI is 1,002. In
the Summer 1 and 2 periods, the transacton-induced HHI changes are 72 and 74, respectively, while
the post-trnsaction HHIs are 1,079 and 1,110, respectively.
BPA's shares increase from pre-transaction to post-transaction because the size of the total market
decreases. The size of the total market decreases from pre-trnsaction to post-trnsaction because, in
the pre-transaction analysis, all of the Chehalis Facility is included as part of the market (i.e., is
included in the denominator) but in the post-trnsaction analysis it instead is used to serve
PacifiCorp's PACW load and therefore is not included as part of any supplier's Available Economic
Capacity (and therefore the denominator) in the periods when PacifiCorp's pre-trnsaction shortfall is
greater than the size of the Chehalis Facility and reflected only in part in the periods (Summer 3,
Winter 2 and Spring/all 2) when PacifiCorp's pre-transaction shortall is less than the size of the
Chehalis Facility.
As indicated, it is PacifiCorp's intention to integrate the Chehalis Facility intoPACW. As discussed
in Mr. Apperson's affdavit, under the Proposed Transaction, PacifiCorp wil obtain 100 MW offirm
transmission rights from the Chehalis Facility to PACW. As also discussed by Mr. Apperson,
PacifiCorp intends to seek additional firm transmission rights to allow the output from the Chehalis
Facility to be moved to PACW. The DPT analyses provided herein assume that PacifiCorp is
successful in acquiring those additional firm transmission rights. I have also prepare separate
analyses under the assumption that PacifiCorp does not acquire any firm trnsmission rights to move
the output from the Chehalis Facility to PACW beyond the 100 MW included as part of the Proposed
Transaction. The results of those additional DPT analyses are contained in my workpapers and, as is
tre for the Available Economic Capacity results provided in Attachments 6 and 8-13, indicate no
screen violations in any market in any of the 10 DPT periods.
37
38
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60.
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reservations that are associated with the applicants' remote generation resources
consistent with Commission precedent or whether it is intended' as well to
encompass other firm, greater-than-one-month transmission reservations that an
applicant may have secured. It is also unclear whether any such new requirement
would apply to DPT analyses in Section 203 contexts, as discussed herein.
As explained above, and evidenced in my workpapers, I have accounted for
PacifiCorp's firm transmission reservations by allocating to PacifiCorp suffcient
SIL capabilty to allow the import to P ACW and PACE of its remote owned and
purchased generation resources. I believe that ths approach is proper for a
competitive assessment of the Proposed Transaction and consistent with
Commission precedent. However, out of an abundance of caution, I have also
provided additional sensitivity DPT analyses for the Proposed Transaction that
directly allocate to PacifiCorp not just suffcient SIL capabilty to allow the
import of its remote owned and purchased generation resources, but also all other
firm transmission reservations of one month in duration that it has secured for the
2008/9 Study Year. I provide the results of these sensitivity analyses in my
workpapers.
"
Significantly, even under this approach, there are no Available Economic
Capacity screen violations in PACW, the BAA where the Chehalis Facility may
be integrated post-transaction, for any of the 10 DPT periods, using the Available
Economic Capacity measure. Also, there are no Available Economic Capacity
screen violations under this additional sensitivity, in any of the BPA, PGE or
A vista BAAs, for any of the 10 DPT periods, using the Available Economic
Capacity measure.
The sensitivity analyses, however, do result in screen violations in the PACE and
Idaho Power BAAs for e~ch of the Summer 3 and Springlall 2 periods. These
screen violations are largely "technical" in natue. I describe them in this fashion
because they occur not, as might be the ordinary situation, because a significant
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pre-transaction independent market presence would be eliminated by the
Proposed Transaction,39 but instead because the Chehalis Facility is much more
competitive under the DPT's procedures in, the PACE and Idaho Power BAAs on
a post-transaction basis having been moved to the PACW BAA than it is on a pre-
transaction basis when it resides in the BP A BAA.4o Because it is more
competitive post-transaction, it receives a larger allocation of the SIL under the
DPT's procedures. Such an outcome hardly depicts any realistic competitive
concern, however, since improving the competitive position of a generation
resource should benefit, not har customers. There is also a separate reason why
the screen violations under ths sensitivity do not realistically depict potential
trnsaction-related market power concerns. Since the Chehalis Facilty is located
outside of each of the BAAs where the screen violations occur, it cannot be
withheld as part of any effort to raise prices in the PACE or Idaho Power BAAs
since the very act of withholding would free transmission capacity that might be
used by others in a fashion to undercut the potential price-increasing effects of the
withholding. Accordingly, attempting to raise market prices in the PACE and
Idaho Power BAAs by withholding the Chehalis Facilty would be self-defeating
as a way to exercise market power.
61.I do not believe that the limited and largely technical screen violations that are
present under this sensitivity analysis depict any systematic competitive concerns
with the Proposed Transaction, a conclusion that is reinforced by my base case
DPT analyses and, as discussed below, the historical sales analyses of the larger
Pacific Northwest market.
39 The pre-transaction presence of the Chehalis Facility in the PACE and Idaho Power BAAs is very
small. The periods when the screen violations occur under these sensitivity analyses are Summer 3
and Springlall2. The pre-trnsaction share of the Chehalis Facility in PACE in Summer 3 is only 10
MW (or 0.2 of I percent) and in SpringIFall2 it is only I I MW (or 0.2 of I percent). The comparable
figures for the Idaho Power BAA are 10 MW (0.6 of I percent) and 14 MW (0.3 of I percent):--It is
only these relatively small amounts of potentially competing independent supply that the Propoed
Trans,action might be said to eliminate under this sensitivity.
These screen violations would not occur ifPacifiCorp elects to keep the Chehalis Facility in the BPA
BAA.
40
"
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62.To supplement the DPT analyses herein, I have also examined historical data on
actual sales made by the Chehalis Facility and PacifiCorp to see if PacifiCorp's
acquisition of the Chehalis Facility suggests any concerns about undue market
concentration on the basis of shares of historical sales. I used historical sales data
reported in Electric Quarterly Report (EQR) filings with FERC for 2007 to
quantify both the total market size and PacifiCorp's portion of short-term sales
(defined as transactions up to a year in duration) at the Mid-C, COB and NOB
hubs. Mid-C is a liquid trading hub in the Pacific Northwest where, according to
EQR filings, virtally all of the output from the Chehalis Facilty has been sold in
recent years. PacifiCorp has also been an active market paricipant at Mid-C.
COB (for Californa-Oregon border) and NOB (for Nevada-Oregon border) are
other trading hubs in the Pacific Nortwest, although with historical volumes far
below those at Mid-C. A small portion of the output from the Chehalis Facility
has been sold at COB in recent years while PacifiCorp has made sales at both
COB and NOB. My understanding is that the available EQR data for sales from
the Chehalis Facility includes hedging and other tyes of trsactions by the
current owners and therefore cannot be used by itself to quantify the historical
output of the Chehalis Facility. Accordingly, for this purpose, I use a combination
of data from EIA Form No. 920, the Environmental Protection Agency's
Continuous Emissions Monitoring System and Platts' BaseCase to quantify
output (and therefore sales) from the Chehalis Facilty.
"
63.The results of this analysis are presented in Attachments 20 and 21, each of which
presents MWh volumes and percentage shares for each of PacifiCorp and the
Chehalis Facility on a month-by-month basis for 2007 as well as changes in
market concentration determined using the "2 x a x b" approach.41 The
Attachment 20 computations cover all days during 2007 whereas the Attchment
21 computations cover only those days during 2007 when the Chehalis Facility
actually operated. These attachments indicate relatively low market shares for
41 Und~r the "2 x a x b" approach, the transaction-induced HHI change is equal to 2 times the product of
the combining suppliers' pre-transaction market shares.
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each of PacifiCorp and the Chehalis Facility and therefore relatively low
transaction-induced HHI changes. Thus, PacifiCorp's market shares average 4
percent, those for the Chehalis Facilty average 2 percent and the trnsaction-
induced HHI changes average 12 when all days are considered. When only days
when the Chehalis Facilty operated are considered, PacifiCorp's market shares
average 4 percent, those for the Chehalis Facilty average 2 percent and the
transaction-induced HHI changes average 17. Moreover, small as they are, I
believe that these transaction-induced HHI changes overstate the impacts of the
Proposed Transaction since they give no weight whatsoever to the fact that, for
most days in ths time period, PacifiCorp was a net buyer, not net seller, in the
markets examined, and therefore would not likely benefit from a transaction-
induced price increase anyway.42 I have also prepared a similar analysis that
expands the range of Pacific Nortwest trding points beyond just Mid-C, COB
and NOB. The results of these analyses, which are provided in my workpapers,
are little different than those in Attachments 20 and 21.
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.64. Workpapers supporting my DPT and market share analyses are contained on two
CDs, one of which is public and one of which contains confidential information.
.VII. CAPACITY AND ANCILLARY SERVICES MARKETS
65. The DPT analysis focuses on markets for short-term or non-firm energy. It also is
helpful to consider the effects of the Proposed Transaction on other markets such
as capacity and ancilar services..
66.PacifiCorp is entering into the Proposed Transaction in order to help it meet a
pending shortfall of capacity in comparson to its load obligations. PacifiCorp's
load and resource balance is depicted in Tables 4-12 and 4- 13 of its 2007
Integrated Resource Plan. Using a 12 percent planning reserve margin,
PacifiCorp has a net "long" (i.e., resources that exceed load obligation plus
.
.42 i hav~ also included in my workpapers additional historical sales analyses that expand the range of
Pacific Northwest trading points beyond just Mid-C, COB and NOB. The results therein are little
different from those shown in Attchments 20 and 2 i. .
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reserves) of 113 MW for 2008 but forecasts a 791 MW deficit by 2010. Using a
15 percent planning reserve margin, PacifiCorp has a net shortfall of 147 MW for
2008. A party that is purchasing generation capacity to make up for a current or
pending shortfall is clearly not in a position to be able to exercise market power
over sales of capacity. That is, a pary that is a purchaser of a product, not a
seller, is interested in a lower price, not higher prices which might be gained from
any hypothesized exercise of market power. For this reason, concerns that the
Proposed Transaction might create competitive concerns in short-term capacity
markets can be sumarly dismissed. Moreover, the position of a par as a
potential seller in short-term capacity markets can be approximated by its
generation holdings as measured at peak demand times under the DPT. That
PacifiCorp is not likely to be a seller in short-term capacity markets therefore is
reinforced by PacifiCorp's PACW shortfall in the highest load periods (i.e.,
Summer 1 and Winter 1), as depicted in Attachment 8, and its relatively modest
holdings then in PACE (i.e., 267 MW in Winter 1 but 0 MW in Summer 1), as
depicted in Attachment 9. In fact, in this sense the Proposed Transaction is
"deconcentrating" in short-term capacity markets since SUEZ on a pre-transaction
basis is more "long" than is PacifiCorp on a post-transaction basis. Accordingly,
there should be no realistic concerns about trnsaction-created competitive
problems in short-term capacity markets.
"
Investigations of long-term capacity markets generally focus on "entr barrers".
The entry barrer expression, when used in conjunction with construction of new
generation capacity, sometimes is used to refer to control of electric transmission
systems, control of fuel supplies or control of fuel transport facilities such as
natural gas pipelines that might be used to thwar generation competitors. But the
Proposed Transaction does not involve any entry barrers, wil not create any new
ones and wil not enhance any that may exist. There is simply no discernable way
that the Proposed Transaction might adversely affect competition in long-term
capacity markets.
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68.
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The Commission's rules for assessing the competitive effects of proposed
acquisitions of jursdictional facilities require an assessment of the effects of the
acquisition on ancilar services markets where'the data to pedorr such an
analysis are available. In this case, the necessary data, including ancilar service
capability of individual generators, are not available. However, given the
relatively small effect of the transaction on market concentration as measured
using the DPT, the small size of the Chehalis Facility in comparson to the BPA
BAA where it is located and the fact that there are ready and obvious alternatives
for ancilar services in the BP A BAA, it is simply not plausible that the Proposed
Transaction wil present the opportty for adverse competitive effects in
ancilar services markets.
VIII. VERTICAL ANALYSIS
69.
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The discussion above has focused on potential horizontal competItive concerns
from the Proposed Transaction. A horizontal acquisition is one that combines
production capacity in the same segment of business, such as electrc generation.
Some acquisitions also can have an important vertical aspect, as when a supplier
at one level of a production process merges with or acquires a supplier at another
leveL. An example is where a supplier of inputs to electrc generation (such as a
coal producer or a natural gas pipeline) merges with or acquires an electrc
generator. The Proposed Transaction involvc::s the acquisition of a generating
facility by a vertically-integrated electrc utilty and does not have any important
vertical components. Therefore, necessarily, it wil not have any adverse vertical
competitive effects. Of course, PacifiCorp owns electric transmission facilities
but it does not own transmission assets in the BPABAA where the Chehalis
Facility is located. Accordingly, the Proposed Transaction wil not result in a
combination of generation and transmission assets in the same market area. In
any case, of course, Pacificorp's transmission system is available for use by others
under PacifiCorp's Commission-approved OATT. MEHC also owns two natural
gas pipelines, Northern Natural Gas and Kern River Gas Transmission Company
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but neither of these traverses either the BPA BAA where the Chehalis Facility
now is located or the PACW BAA where it will be integrated post-transaction.
ix. CONCLUSION
70.The transfer of ownership of the Chehalis Facilty to PacifiCorp wil have no
adverse effect on competitive conditions in any relevant market. It wil not
increase concentration to any meaningfl degree in any potentially affected
market and carres witl it no implications with respect to barers to entr or the
vertical enhancement or exercise of market power. This fairly intuitive
conclusion is confirmed by the Appendix A analysis that I have conducted.
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
.
PacifiCorp
TNA Merchant Projects, Inc.
Chehalis Generating, LLC
)
)
)
Docket No. EC08-_-000
Affidavit of Rodney Frame
.Rodney Frame, being first duly sworn, deposes and says that he has read the
, foregoing Affidavit of Rodney Frame, and that the matters and things set forth therein are
true and correct to the best of his knowledge, information, and belief..
ROdn~~.
Sworn to and subscribed before me this
. My Commission Exire
Decmber 14, 2011
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List of Attachments
Rodney Frame CV
2 List of Abbreviations
3 WECC Generation Capacity Owned by PacifiCorp and Affliates
Schematic Diagram Showing Generation Location ofPacifiCorp and Affliates and PACE,
P ACW and MidAmerican First-Tier4
5 OPT Topology for Chehalis Acquisition
6 OPT Summary Results, Available Economic Capacity, Base Case
7 OPT Summary Results, Economic Capacity, Base Case
8 Available Economic Capacity, Base Case, PACW
9 Available Economic Capacity, Base Case, PACE
io Available Economic Capacity, Base Case, BPA
ii Available Economic Capacity, Base Case, PGE
12 Available Economic Capacity, Base Case, Avista
13 Available Economic Capacity, Base Case, Idaho Power
14 Economic Capacity, Base Case, PACW
15 Economic Capacity, Base Case, PACE
16 Economic Capacity, Base Case, BPA
17 Economic Capacity, Base Case, PGE
18 Economic Capacity, Base Case, A vista
19 Economic Capacity, Base Case, Idaho Power
Volumes and Market Shares for Electrcity Sales at Mid-C, COB and NOB,
2007, All Days
Volumes and Market Shares for Electrcity Sales at Mid-C, COB and NOB,
2007, Days When Chehalis Facilty Generates
20
21
.
Attachment 1
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.RODNEY FRAME
Managing Principal
Phone: [phone]
Fax: [phone]
rfmec?analysisgroup.com
1899 Pennsylvania Avenue. NW
Suite 200
Washington. DC 20006.
.
Mr. Frame has consulted with electric utility clients on a vanety of matters including industr
restrctunng, retail competition, wholesale bulk power markets and competition, market power and
mergers, transmission access and pncing, contrctual terms for wholesale service, and contracting for
non-utility generation. A substantial portion of the work has been in conjunction with litigated antitrust
and federal and state regulatory proceedings.
.Mr. Frame frequently speaks before electrc industry groups on competition-related topics. He has
testified in federal and local courts, before federal and state regulatory commissions, and before the
Commerce Commission of New Zealand.
.Pnor to joining Analysis Group, Mr. Frame was a Vice President at National Economic Research
Associates. Mr. Frame graduated from George Washington University and pursued grduate work there
under a National Science Foundation Traineeship. His areas of specialization were public finance and
urban economics. He completed all requirements for his Ph.D. degree in economics with the exception of
the thesis..
.EDUCATION
1970 B.B.A., George Washington University
1970 - 73 Ph.D. coursework (all requirements for degree in economics completed except
thesis), George Washington University
.PROFESSIONAL EXPERIENCE
1998 - Analysis Group
Managing Principal
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.
1984 - 1998
1975 - 1984
1974 - 1975
1973 - 1974
1973
Attachment 1
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National Economic Research Associates
Vice President and Senior Consultant. Participated in projects dealing with retail
competition, wholesale competition, market power assessment and determination of
relevant markets for electricity supply, electric utility mergers, transmission access' and
pricing, partial requirements ratemaking, contractual terms for wholesale service, and
contracting for non-utility generation supplies. Principal clients were investor-owned
electric utilities.
Transcomm, Inc.
Senior Economist. Worked on a variety of projects concerning market structure, pricing
and cost development in regulated industries. Clients included the U.S. Departments of
Commerce, Defense and Energy, the Nuclear Regulatory Commission, the State of
Oregon, bulk mailers and various communications equipment manufacturers and service
providers. Participated in numerous federal and state regulatory proceedings and was
principal investigator for a multi-year Department of Energy study addressing various
aspects of electric utility competition.
Independent Economic Consultant
Advised telephone equipment manufacturers concerning cost and rate development for
competitive telephone offerings, analyzed alternative travel agent compensation
arrangements and examined nonbank activity by bank holding company firms.
Program of Policy Studies in Science and Technology
Research Staff
Urban Institute
Research Staff
.TESTIFYIN.G EXPERIENCE
.
.
.
.
Affdavit on behalf of PacifiCorp, before the Federal Energy Regulatory Commission in Docket
No. ER97-2801 et al., providing updated indicative horizontal market power screen, delivered
price test and other analyses to support continued market-based pricing by PacifiCorp after its
acquisition by contract of new generation capacity and after commercial operation of certain new
generating facilities, March 3 i, 2008.
.
Supplemental affdavit on behalf of the FirstEnergy Operating Companies et al., before the
Federal Energy Regulatory Commission in Docket No. EROI-1403 et al., responding to
intervenor arguments supporting certain adjustments to previously-submitted horizontal market
power screen analyses, March 31, 2008.
.
Affdavit on behalf of Idaho Power Company, before the Federal Regulatory Commission in
Docket No. ER97-1481, updating Idaho Power's market screen analysis to reflect the addition of
its new Danskin No. i generator, March 2 i, 2008.
.
Affdavit on behalf of various affliates of Southern Company, before the Federal Energy
Regulatory Commission in Docket No. ER98-780 et al., providing updated market screen
analyses to support continued market-based pricing by those affliates after the operation of
Southern Power Company's new Franklin 3 generating facility, February i 1,2008.
.
.
.
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· Affdavit on behalf of Public Service Electric and Gas Company et 01, before the Federal Energy
Regulatory Commission in Docket No. ER99-3151 et 01., applying the Commission's pivotal
supplier and market share screens to Public Service Electric and Gas Company and its affliates,
providing a delivered price test analysis for PJM East and assessing the need for additional
market power mitigation measures, January 14,2008.
.· Affdavit on behalf of the FirstEnergy Operating Companies et 01., before the Federal Energy
Regulatory Commission in Docket No. EROI-1403 et 01, applying the Commission's pivotal
supplier and market share screens to the FirstEnergy Operating Companies, January 14,2008.
· Affdavit on behalf of FirstEnergy Mansfield Unit 1 Corp, before the Federal Energy Regulatory
Commission in Docket No. ER08-107, assessing the appropriateness of market-based rate
authority for FirstEnergy Mansfield, October 26,2007..· Affdavit on behalf of various affliates of Southern Company, before the Federal Energy
Regulatory Commission in Docket No. ER98-780 et 01., providing updated market screen
analyses to support continued market-based pricing by those affliates after Southern Companies'
purchase of capacity and energy from Calpine, August 3 I, 2007.
.· Affidavit on behalf of PacifiCorp, before the Federal Energy Regulatory Commission in Docket
No. ER97-2801, providing updated delivered price test and other analyses to support continued
market-based pricing by PacifiCorp after commercial operation of its new Lake Side, Marengo
and Goodnoe Hils generating facilities, August 27, 2007.
.· Affdavit on behalf of various affliates of Southern Company, before the Federal Energy
Regulatory Commission in Docket No. RM04-7-000, identifying and assessing the significance
of various aspects ofFERC's Order No. 697, its Final Rule pertining to regulations governing
market-based rate authority for wholesale sales of electricity, July 23, 2007.
.
· Affdavit on behalf ofPacifiCorp, before the Federal Energy Regulatory Commission in Docket
No. ER97-2801 et 01., providing updated market screen analyses to support continued market-
based pricing by PacifiCorp after commercial operation of its new Lake Side, Marengo and
Goodnoe Hils'generating facilties, June 8, 2007.
.
· Affdavit on behalf of affliates of MidAmerican Energy Holdings Company, before the Federal
Energy Regulatory Commission in Docket No. ER96-719 et 01., concerning the extent to which
MidAmerican Energy Company's operation of Council Bluffs Energy Center Unit 4, the Victory
Wind Project and the Pomeroy Wind Project represents a significant change in status regarding
the characteristics relied upon by the Commission in granting market-based pricing authority to
affliates ofMEHC, March 2, 2007.
.
· Rebuttal Testimony on behalf of Southern Company Services, Inc. before the Federal Energy
Regulatory Commission in Docket No. EL04-124 et 01.. concerning various computational and
conceptual issues that arise in applying the Commission's delivered price test to Southern
Companies for the Southern Control Area, February 20, 2007.
.
· Affdavit on behalf of PSEG Energy Resources & Trade LLC et 01.. before the Federal Energy
Regulatory Commission in Docket No. ER99-3151 et 01.. applying the Commission's pivotal
supplier and wholesale market share screens to Public Service Electric and Gas Company and its
affiiates, November 29, 2006.
.
.
Attachment 1
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.Affdavit on behalf of PacifiCorp and PPM Energy, Inc. before the Federal Energy Regulatory
Commission in Docket No. ER97-2801 et al., providing revised delivered price test analyses to
support continued market-based rate authority by PacifiCorp and PPM Energy, Inc., November 6,
2006.
.
.Affdavit on behalf of Southern Company Services, Inc. et al.. before the Federal Energy
Regulatory Commission in Docket No. ER96-780 et al.. concerning the extent to which Southern
Company's acquisition of the Rowan generating station represents a significant change in status
regarding the characteristics relied upon by the Commission in grnting market-based pricing
authority to affliates of Southern Company, October 2,2006.
.
.Affdavit on behalf of Oleander Power Project, L.P., before the Federal Energy Regulatory
Commission in Docket No. EROO-3240-_, applying the Commission's pivotal supplier and
wholesale market share screens to affiiates of Southern Company, September 27,2006..
· Direct Testimony on behalf of Southern Company Services, Inc. before the Federal Energy
Regulatory Commission in Docket No. ER04-124 et al., applying the Commission's delivered
price test to Southern Companies for the Southern Control Area, September 18, 2006..· Supplemental Testimony on behalfofPacifiCorp, before the Federal Energy Regulatory
Commission in Docket No. ER97-2801-007 and ER97-2801-0lO, providing updated market
screen, delivered price test and other analyses to support continued market-based pricing by
PacifiCorp after commercial operation of its new Currant Creek, Goshen and Leaning Juniper
generators, August 21, 2006..· Affdavit on behalf of various affliates of D.E. Shaw, before the Federal Energy Regulatory
Commission in Docket No. ER03-879 et al., applying the Commission's pivotal supplier and
wholesale market share screens to the D.E. Shaw affliates, July 24, 2006.
.· Affidavit on behalf of DeSoto County Generating Company, LLC, before the Federal Energy
Regulatory Commission in Docket No. ER03-1383 et al., demonstrating that the company's
acquisition by Southern Power allows certain restrictions on its market-based rate authority to be
removed, June 30, 2006.
.
· Affidavit on behalf of Southern Power Company, before the Federal Energy Regulatory
Commission in Docket No. EC06-132-000, concerning competitive issues raised by Southern
Power's proposed acquisition of Rowan County Power, LLC from Progress Energy, June 16,
2006.
.
· Affdavit on behalf of MidAmerican Energy Company and its affliates, before the Federal
Regulatory Commission in Docket No. ER96-7 i 9-_ et al., examining the extent to which
MidAmerican's acquisition of PacifiCorp presents a departure from the conditions relied upon by
the Commission in granting market-based rate authority to MidAmerican and its affliates, April
20,2006.
· Affdavit on behalf of Southern Power Company, before the Federal Energy Regulatory
Commission in Docket No. EC06-112-000, concerning competitive issues raised by Southern
Power's acquisition of the DeSoto Generating Station from Progress Energy, April 14,2006..
.
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.Affdavit on behalf of PPM Energy, Inc. before the Federal Energy Regulatory Commission in
Docket No. EL05-95-_ and ER03-478-_, providing a market screen analysis to reflect the
change of status as a result of the acquisition of PPM's former affiiate PacifiCorp by
MidAmerican Energy Holdings Company, April 10, 2006.
.Supplemental Testimony on behalf of PacifiCorp and PPM Energy, Inc. before the Federal
Energy Regulatory Commission in Docket No. ER97-2801-006 et al., providing additional
market screen and delivered price test analyses to assess whether PacifiCorp and PPM have
market power for wholesale sales of electricity, March 29, 2006.
.Supplemental Testimony on behalf of Public Service Electric and Gas Company and Exelon
Corporation (with Michael M. Schnitzer), before the State of New Jersey Board of Public Utilties
in BPU Docket No. EM05020I06 and OAL Docket No. PUC-1874, addressing analyses provided
by PJM's Market Monitoring Unit and market power mitigation measures proposed by Joint
Petitioners, March l7, 2006.
.Affdavit on behalf of PSEG Power Connecticut, LLC, before the Federal Energy Regulatory
Commission in Docket No. ER99-967-_, applying the Commission's pivotal supplier and
wholesale market share screens to PSEG Connecticut, February 28, 2006.
.Affdavit on behalf of Union Electric Company d//a AmerenUE and NRG Audrain Generating,
LLC, before the Federal Energy Regulatory Commission in Docket No. EC06-55-000,
concerning competitive issues raised by AmerenUE's proposed acquisition of the Audrain
generating station from NRG, December 28, 2005.
.Affdavit on behalf of Union Electric Company d//a AmerenUE and affiiates of Aquila, Inc.
before the Federal Energy Regulatory Commission in Docket No. EC06-56-000, concerning
competitive issues raised by AmerenUE's proposed acquisition of the Goose Creek and Raccoon
Creek generating stations from Aquila, December 28,2005.
.Supplemental Rebuttal Testimony on behalf of Public Service Electric and Gas Company and
Exelon Corporation, before the Board of Public Utilities of New Jersey in BPU Docket No.
EM05020106 and OAL Docket No. PUC-1874-05, responding to testimony on behalf of the BPU
staff concerning the horizontal competitive effects of the proposed merger of Public Service
Enterprise Group and Exelon, December 12, 2005.
.Rebuttal Testimony on behalf of Public Service Electric and Gas Company and Exelon
Corporation, before the Board of Public Utilities of New Jersey in BPU Docket No. EM05020106
and OAL Docket No. PUC-L 874-05, responding to intervenor concerns about the competitive
effects of the proposed merger of Public Service Enterprise Group and Exelon, December 5,
2005.
.Affdavit on behalf of Electric Energy, Inc. before the Federal Energy Regulatory Commission in
Docket No. ER05-I482-000, applying the Commission's pivotal supplier and wholesale market
share screens to the Electric Energy, Inc. control area, November 3,2005.
.Direct Testimony on behalf of Southern Company Services, Inc. before the Federal Energy
Regulatory Commission in Docket No. EL04-124 providing various delivered price test analyses
to support Southern Companies' request for continuing market-based rate authority, September
20,2005.
.
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Page 6 of27
.· Surrebuttal Testimony on behalf of the Ameren Companies, before the Ilinois Commerce
Commission in Docket No. OS-O 1 60 et al., responding to intervenor concerns about the
underlying maturity and competitiveness of the wholesale electrcity markets in which Ilinois
BGS auction participants can procure the wholesale supplies needed to support their auction bids,
August 29, 200S.
.· Additional Testimony on behalf of Public Service Electric and Gas Company, before the State of
New Jersey Board of Public Utilities in BPU Docket No. EMOS020lO6 and OAL Docket No.
PUC-l 874-0S, that addresses the effect of the proposed merger ofPSEG and Exelon on
competition in the New Jersey Basic Generation Service Auction and that applies FERC's market
power screen measures to the post-merger firm, August is, 2OOS.
.· Rebuttal Testimony on behalf of the Ameren Companies, before the Ilinois Commerce
Commission in Docket No. OS-0160 et al., responding to intervenor arguments that there are
likely to be competitive problems with Ameren's proposed competitive procurment of wholesale
supplies used to provide "basic generation service," July 13, 200S.
.· Direct Testimony on behalfofPacifiCorp and PPM Energy, Inc. before the Federal Energy
Regulatory Commission in Docket No. ER97-2801-_ et al., providing a delivered price test and
other evidence rebutting the Commission's presumption that PacifiCorp and PPM possess market
power over wholesale sales of electricity, July 8, 200S.
.
· Supplemental Affdavit on behalf of PacifiCorp and PPM Energy, Inc. before the Federal Energy
Regulatory Commission in Docket No. ER97-2801-_ et al., providing additional information
and analyses concerning the application of the Commission's pivotal supplier and wholesale
market share screens to PacifiCorp and PPM, June 8, 200S.
· Affdavit on behalf of Astoria Energy, LLC, before the Federal Energy Regulatory Commission
in Docket No. EROI-3lO3-_, applying the Commission's pivotal supplier and wholesale
market share screen to Astoria, May 23, 200S..· Supplemental Testimony on behalf of various affliates of Southern Company, before the Federal
Energy Regulatory Commission in Docket No. ER97-4166-01S et al., responding to issues raised
by intervenors Calpine Corporation and Shell Trading Gas and Power Company concerning the
"delivered price test" competitive analysis provided by Southern Company, May 16, 200S.
.· Affdavit on behalf of Lake Road Generating Company, L.P., before the Federal Energy
Regulatory Commission in Docket No. ER99-1 714-_, applying the Commission's pivotal
supplier and wholesale market share screens to Lake Road, May 13, 200S.
.
· Supplemental Testimony on behalf of Public Service Electric and Gas Company, before the State
of New Jersey Board of Public Utilities in BPU Docket No. EMOS020lO6 and OAL Docket No.
PUC-1874-0S, addressing revised market power mitigation proposal of merging parties PSEG
and Exelon Corporation, May 12, 200S.
· Affdavit on behalf of Idaho Power Company, before the Federal Regulatory Commission in
Docket No. ER97-148 1-009, updating Idaho Power's market screen analysis to reflect the
addition of its new Bennett Mountain generator, May 2, 200S..
.
.
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Page 7 of 27
.· Affidavit on behalf of Southern Power Company, before the Federal Energy Regulatory
Commission in Docket No. EC05-71-000, concerning competitive issues raised by Southern's
proposed acquisition of the Oleander Power Project from Constellation Energy Group, April 20,
2005.
.· Affdavit on behalf ofUGI Development Company and UGI Energy Services, before the Federal
Energy Regulatory Commission in Docket No. ER97-28i 7 et al.. applying the Commission's
pivotal supplier and wholesale market share screens to UGI, April 12, 2005.
· Affdavit on behalf of La Paloma Generating Company, LLC, before the Federal Energy
Regulatory Commission in Docket No. EROO-I07-_, applying the Commission's pivotal
supplier and wholesale market share screens to La Paloma and its affliates, March 31, 2005..· Supplemental Affdavit on behalf of the Detroit Edison Company and certain of its affliates,
before the Federal Energy Regulatory Commission in Docket No. ER93-324 et al.. providing
additional information concerning the application of the Commission's new interim generation
market power screens to Detroit Edison, March 21,2005.
.· Direct Testimony on behalf of Public Service Electric and Gas Company, before the State of New
Jersey Board of Public Utilities, in BPU Docket No. EM05020106 and OAL Docket No. PUC-
1874-05, assessing the competitive effects of the proposed merger of Public Service Enterprise
Group Incorporated and Exelon Corporation, February 28, 2005.
.· Direct Testimony on behalf of various affliates of Southern Company, before the Federal Energy
Regulatory Commission in Docket No. ER97-4166-015 et al., providing a delivered price test and
other evidence rebutting the Commission's presumption that Southern Company possesses
market power over wholesale sales of electrcity, February 15,2005.
.
· Affdavit on behalf ofPacifiCorp and PPM Energy, Inc. before the Federal Energy Regulatory
Commission in Docket No. ER97-2801-005 et al., applying the Commission's new pivotal
supplier and wholesale market share screens to PacifiCorp and PPM, Februar -14,2005.
· Affidavit on behalf of PSEG Lawrenceburg Energy Company LLC and PSEG Waterford Energy
LLC, before the Federal Energy Regulatory Commission in Docket No. EROI-2460-002 et al.,
applying the Commission's pivotal supplier and wholesale market share screens, February 7,
2005..
· Affdavit on behalf of the First Energy Operating Companies et al., before the Federal Energy
Regulatory Commission in Docket No. EROI-1403-_ et al.. applying the Commission's pivotal
supplier and wholesale market share screens, February 7,2005.
.· Supplemental Affdavit on behalf of Idaho Power Company, before the Federal Regulatory
Commission in Docket No. ER97-1481-003, responding to issues raised in a Commission Staff
letter relating to Idaho Power's application of the Commission's pivotal supplier and wholesale
market share screens, January 19, 2005.
.
· Affdavit on behalf of various affliates of Ameren Corporation, before the Federal Energy
Regulatory Commission in Docket No. ER-01-294-002 et aI., applying the Commission's new
pivotal supplier and wholesale market share screens to Ameren's affiiates, December 27,2004.
.
.
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.· Affdavit on behalf of Detroit Edison and various of its affliates, before the Federal Energy
Regulatory Commission in Docket No. ER02-963-002 et al., applying the Commission's new
pivotal supplier and wholesale market share screens to Detroit Edison Company and its affliates,
December 23,2004.
.· Affdavit on behalf of various affliates of Black Hils Corporation, before the Federal Energy
Regulatory Commission in Docket No. ER-OO- I 952-000 et al.. applying the Commission's new
pivotal supplier and wholesale market share screens to Black Hils' affliates, December 23,2004.
· Affdavit on behalf of Minnesota Power Company, before the Federal Energy Regulatory
Commission in Docket No. EROI-2636-001, applying the Commission's new pivotal supplier and
wholesale market share screens to Minnesota Power and its affliates, November 9,2004..· Affdavit on behalf of Oasis Power Parters, LLC, before the Federal Energy Regulatory
Commission in Docket No. ER05-_-000, applying the Commission's new screens for market-
based rate authority to enXco, the owner of OASIS, October 12,2004.
.· Affdavit on behalf of Idaho Power Company, before the Federal Energy Regulatory Commission
in Docket No. ER97-1481-003, applying the Commission's new pivotal supplier and wholesale
market share screens to Idaho Power Company, September 27,2004.
· Affdavit on behalf of Allant Energy Corporate Services, Inc. before the Federal Energy
Regulatory Commission in Docket No. ER99-230-002, applying the Commission's new pivotal
supplier and wholesale market share screens to Allant Energy, August 20,2004..· Affdavit on behalf of various affliates of Southern Company, before the Federal Energy
Regulatory Commission in Docket No. ER96-2495-018 et al., concerning the application ofthe
Commission's new screens for determining the appropriateness of market-based rate authority to
Southern Company, August 9, 2004.
.· Affdavit on behalf of Fulton Cogeneration Associates, L.P. and Renssalaer Plant Holdco, L.L.c.
in Docket No. ER04- i 044-000, ER04- i 045-000 and ER04- i 046-000 before the Federal Energy
Regulatory Commission applying FERC's new screens for determining the appropriateness of
market-based rate authority, July 28, 2004.
.· Rebuttal Testimony on behalf of Ameren Corporation, before the Ilinois Commerce Commission
in Docket No. 04-0294, concerning issues raised by Ameren's acquisition of Ilinois Power
Company, July 23, 2004.
.
· Direct Testimony on behalf of Ameren Energy Marketing Company and Central Ilinois Public
Service Company d//a AmerenCIPS, before the Federal Energy Regulatory Commission in
Docket No. ER04-_, concerning competitive issues raised by the two year extension of a power
supply agreement between AEM and AmerenCIPS, July 9, 2004.
· Affidavit on behalf of Constellation Generation Group, before the New York State Public Service
Commission in Case No. 04-E-0630, concerning competitive issues raised by Constellation's
proposed acquisition of an interest in the Flat Rock Wind Project currently in development, May
27,2004..
.
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Page 9 of 27
.· Additional Affdavit on behalf of vanous affliates of Southern Company, before the Federal
Energy Regulatory Commission in Docket No. PL02-8-000 et al., addressing the new market
power screens and mitigation rules contained in the Commission's April 14, 2004 Order on
Rehearing (107 FERC' 61,018), May 14,2004.
.· Affdavit on behalf of Interstate Power and Light Company, before the Federal Energy
Regulatory Commission in Docket No. EC04-61-000, concerning competitive issues raised by
IPL's acquisition of an additional interest in the George Neal Generating Station Unit 4, April 26,
2004.
.
· Direct Testimony on behalf of Ameren Corporation and Dynegy, Inc. before the Federal Energy
Regulatory Commission in Docket No. EC04-81-000, concerning competitive issues raised by
Ameren's proposed acquisition of Ilinois Power Company, March 25, 2004.
· Affdavit on behalf of Constellation Energy Group and Rochester Gas and Electric Corporation,
before the Federal Energy Regulatory Commission in Docket No. EC04-79-000, concerning
competitive issues raised by Constellation's proposed acquisition of the R.E. Ginna Nuclear
Generating Station from Rochester Gas and Electnc Corporation, March 23, 2004..· Affdavit on behalf of Constellation Energy Group and Rochester Gas and Electric Corporation,
before the New York State Public Service Commission in Case No. 03-E-1231, concerning
competitive issues raised by Constellation's proposed acquisition of the R.E. Ginna Nuclear
Generating Station from Rochester Gas and Electnc, February 2, 2004.
.· Rebuttal Testimony on behalf of Southern Power Company, before the Federal Energy
Regulatory Commission in Docket No. ER03-7 i 3-000 et al., responding to claims of intervenor
witnesses that Southern Power Company's long-term power sales to its Georgia Power Company
and Savannah Electnc and Power Company affliates, among other things, represent "affliate
abuse," embody cross-subsidization, are a result of improper advantages and otherwise adversely
affect wholesale competition, and rejecting intervenor's proposed recommendations as anti-
competitive, designed to reward ineffcient competitors and likely to increase customers' costs,
January 31, 2004..
.
· Second Affdavit on behalf of Ameren Energy, Inc. and other affiiates of Ameren Corporation,
before the Federal Energy Regulatory Commission in Docket No. EROI-294 et al., responding to
intervenor arguments concerning the manner in which the Commission's SMA test should be
applied to Ameren, January 15, 2004.
· Affdavit on behalf ofvanous affliates of Southern Company, before the Federal Energy
Regulatory Commission in Docket No. PL02-8-000 et al.. addressing alternatives to the SMA and
proposed market power mitigation as contained in the Commission's Staff Paper, January 6,
2004..· Affdavit on behalf of Public Utility Subsidianes of FirstEnergy Corp., before the Federal Energy
Regulatory Commission in Docket No. ER-04-363, concerning the appropriateness of market
based rate authority for the Public Utility Subsidiaries of FirstEnergy Corp., December 31, 2003.
.· Affdavit on behalf of Ameren Energy, Inc. and other affiiates of Ameren Corporation, before
the Federal Energy Regulatory Commission in Docket No. EROO-2687 et aI., concerning the
appropnateness of market based rate authority for affliates of Ameren Corporation, December
10,2003.
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.Affdavit on behalf of Idaho Power Company before the Federal Energy Regulatory Commission
in Docket No. ER97-1481-003 applying the Commission's SMA test to Idaho Power Company
and its affliates, October 9,2003.
.Rebuttal Testimony on behalf of Ameren Energy Generating Company and Union Electric
Company d//a AmerenUE, before the Federal Regulatory Commission in Docket No. EC03-53-
000 rebutting intervenor claims that AmerenUE's purchase of generating units from its AEGC
affliate would create competitive concerns, October 6,2003.
.Direct Testimony on behalf of Southern Power Company, before the Federal Energy Regulatory
Commission in Docket No. ER03-7 I 3-000 et at.. concerning competitive issues raised by long-
term power sales agreements between Southern Power and its Georgia Power Company and
Savannah Electric and Power Company affliates, September 22,2003.
· Third Affidavit on behalf of Allant Energy Services, Inc. applying the Commission's SMA test to
various control area markets, before the Federal Energy Regulatory Commission in Docket No.
ER99-230-002 and ER03-762-000, August 15,2003.
.Affdavit on behalf of The Connecticut Light and Power Company (CL&P) concerning incentive
and public interest considerations associated with NRG Energy's attempt to discontinue standard
offer service to CL&P, before the Federal Energy Regulatory Commission in Docket No. EL03-
123-000 and EL03-134-000, July 18,2003.
.Direct Testimony on behalf of Ameren Energy Generating Company and Union Electric
Company d//a AmerenUE, before the Federal Energy Regulatory Commission in Docket No.
EC03-53-000, concerning competitive issues raised by AEGC's proposed sale of two affliated
merchant generating stations to AmerenUE, June 10,2003.
.Affdavit on behalf of DTE East China, LLC, before the Federal Energy Regulatory Commission
in Docket No. ER03-931-000, concerning the appropriateness of market based rate authority for
DTE East China, an affiliate of Detroit Edison Company, June 5, 2003.
· Testimony on behalf of Detroit Edison Company, before the Michigan Public Service
Commission in Case No. U-13797, addressing market power issues raised by restructuring
legislation in Michigan, May 29, 2003.
· Testimony on behalf of the PJM Transmission Owners, before the Federal Energy Regulatory
Commission in Docket No. ER03-738-000, concerning the appropriate equity return and
depreciation lives for new transmission assets constructed by transmission owners pursuant to a
regional transmission expansion plan, April 11,2003.
· Affdavit on behalf of Baltimore Gas & Electric and various of its affiiates before the Federal
Energy Regulatory Commission in Dockets No. ER99-2948-002 et at., concerning application of
the Commission's SMA test to those entities, March 28, 2003.
· Affdavit on behalf of Ameren Energy Generating Company and Union Electric Company d//a
AmerenUE, before the Federal Energy Regulatory Commission in Docket No. EC03-53-000,
concerning competitive issues raised by the proposed transfer of certain generating facilities from
Ameren Energy Generating Company to AmerenUE, March 13,2003.
.
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Attachment i
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.Rebuttal Testimony on behalf of Public Service Electrc and Gas Company, before the Federal
Energy Regulatory Commission in Docket No. EL02-23-000 (Phase II), concerning financial
responsibility for redispatch costs and market power issues associated with certain transmission
agreements between Public Service Electric and Gas Company and Consolidated Edison
Company, February 20, 2003.
.Testimony on behalf of FirstEnergy Corp and its operating company affliates The Cleveland
Electric Iluminating Company, The Toledo Edison Company, and Ohio Edison Company, before
the Public Utilties Commission of Ohio in Case No. 02-1 944-EL-CSS, concerning the terms and
conditions under which the operating companies should purchase the accounts receivables of
competitive retail electric service providers, Februar 19, 2003.
.Affdavit on behalf of Detroit Edison and various of its affliates in Dockets No. ER97 -324-004 et
al., applying the Commission's SMA test to those entities, January 31, 2003.
.Rebuttal testimony on behalf of certain "Classic" PJM Transmission Owners before the Federal
Energy Regulatory Commission in Docket No. EL-02-l1l-000, concerning the appropriateness of
"seams" charges for trasmission service between the MISO and PJM regions, December 10,
2002.
· Affdavit on behalf of various affliates of Black Hils Corporation before the Federal Energy
Regulatory Commission in Docket No. EROO-31 09 et al., concerning application of the
Commission's SMA test to those affliates, November 25, 2002
· Direct testimony on behalf of certain "Classic" PJM Transmission Owners before the Federal
Energy Regulatory Commission in Docket No. EL-02- i 1 i -000, concerning the appropriateness of
"seams" charges for trnsmission service between the MISO and PJM regions, November 14,
2002.
· Affdavit on behalf of Southern Company Services, Inc. before the Federal Energy Regulatory
Commission in Docket No. PL02-8, Conference on Supply Margin Assessment, assessing the
Commission's proposed SMA market screen and accompanying market power mitigation
measures, October 22, 2002.
· Second affdavit on behalf of Gamet Energy LLC in Docket No. ER02- i 190-000, before the
Federal Energy Regulatory Commission, responding to intervenor claims about the proper
method for applying the Commission's application for market pricing authority, August 2002.
.Direct Testimony on behalf of Ameren Services Company before the Federal Energy Regulatory
Commission in Docket No. EC02-96-000 concerning competitive issues raised by Ameren's
proposed acquisition of Central Ilinois Lighting Company, July 19,2002.
· Affdavit on behalf of Gamet Energy LLC in Docket No. ER02- 1 i 19-000, before the Federal
Energy Regulatory Commission, concerning application of the Commission's SMA test to
Gamet, an affliate ofIdaho Power Company, July 1 i, 2002.
· Testimony on behalf of Public Service Electric and Gas Company concerning vertical market
power issues associated with certain transmission agreements between Public Service Electric
and Gas Company and Consolidated Edison Company, before the Federal Energy Regulatory
Commission in Docket No. EL-02-23-000, July i, 2002.
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Affidavit on behalf of applicants Wisvest Corporation, Wisvest-Connecticut, LLC and PSEG
Fossil LLC concerning competitive issues presented by PSEG Fossil's proposed acquisition of
Wisvest-Connecticut, before the Federal Energy Regulatory Commission in Docket No. EC02-
87-002, ER02-2204-000 and ER99-967-002, June 28, 2002.
.Direct testimony on behalf of Ameren Corpration concerning competitive issues raised by
Ameren's proposed acquisition of Central Ilinois Lighting Company, before the Ilinois
Commerce Commission in Docket No. 02-0428, June 19,2002.
· Rebuttal testimony on behalf of PSEG Power in New York Public Service Commission Case No.
02-M-0132 responding to intervenor concerns about alleged horizontal and vertical market power
problems arising from PSEG's construction of the Cross Hudson Project, May, 2002.
· Affdavit on behalf of Southern Company Services, Inc. in Docket No. ER96-780-005, before the
Federal Energy Regulatory Commission, describing appropriate procedures for triennial market
pricing update and addressing whether Southern Company Services, Inc. has market power in
wholesale electricity markets, April 30, 2002.
· Direct testimony on behalf of PSEG Power in New York Public Service Commission Case No.
02-M-0132 concerning market power implications of the application ofPSEG Power to construct
an approximately eight mile radial connection between Bergen Generating Station in New Jersey
and Consolidated Edison Company's West 49th Street Substation in New York City, April 26,
2002.
· Expert report on behalf of Virginia Electric and Power Company in Virginia Electric and Power
Company v. International Paper Company, Civil Action No. 2:0lcv703, United States District
Court, Eastern District of Virginia, Norfolk Division, Concerning damages issues associated with
terminated NUG contract, March 21, 2002.
· Affdavit on behalf of Crete Energy Venture, LLC in Docket No. ER02-963, before the Federal
Energy Regulatory Commission, concerning application of the Commission's SMA test to ajoint
venture of Entergy and DTE, February 4, 2002.
· Second Affidavit on behalf of Allant Energy Service, Inc. in Docket No. ER99-230-002, before
the Federal Energy Regulatory Commission, concerning appropriate computational procedures
and data sources for applying the Commission's SMA test, January 24, 2002.
· Affdavit on behalf of Rainy River Energy Corporation-Taconite Harbor in Docket No. ER02-
124-000, before the Federal Energy Regulatory Commission, to apply the Supply Margin
Assessment test to Minnesota Power and its affiiates, January 7, 2002.
· Affdavit on behalf of Alliant Energy Services, Inc. in Docket No. ER99-230-002, before the
Federal Energy Regulatory Commission, to apply the Supply Margin Assessment test to Allant
Energy Corporation to determine whether mitigation is required for affliates of Allant with
market pricing authority under the procedures recently promulgated by the Commission,
December 18,2001.
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Page 13 of27
.Affdavit on behalf of Southern Company Services, Inc. in Docket No. ER96-2495-0 1 5, ER97-
4143-003, ER97-1238-010, ER98-2075-009, ER 98-542-005 and ER91-569-009 before the
Federal Energy Regulatory Commission addressing the economic underpinnings of the
Commission's SMA test, including its usefulness as a market power screening device, as well as
the appropriateness of the mitigation measures that the Commission has ordered, December 14,
2001.
.
..Affdavit on behalf of Rainy River Energy Corporation - Wisconsin before the Public Service
Commission of Wisconsin in Docket No. 05-CE-128, providing a market power screen analysis
to support Rainy River's application to the Wisconsin Public Service Commission to construct,
own and operate the Superior project, December 3,2001.
.Affdavit on behalf of Attala Energy Company, LLC before the Federal Energy Regulatory
Commission in Docket No. ER02-40-000 providing a Supply Margin Assessment, consistent with
proposed FERC rules, for its generation, November 5, 2001.
.
.Prepared Rebuttal Testimony on behalf of Appalachian Power Company d//a American Electric
Power before the State Corporation Commission of Virginia in SCC Case No. PUEO 100 1 1,
concerning AEP's corporate separation plan, October 5,2001..
· Affdavit on behalf of Southern Company Services, Inc. before the Federal Energy Regulatory
Commission in Docket No. RMO 1-8-000 concerning potential competitive harms that could result
if commercially sensitive trnsaction data are made available to the public, October 5, 2001.
.· Affdavit on behalf of PSEG Lawrenceburg before the Federal Energy Regulatory Commission in
Docket No. ER01-01-2460 concerning market power issues associated with construction of new
generation facilities, June 27, 2001.
.
· Affidavit on behalf of PSEG Waterford Energy Company before the Federal Energy Regulatory
Commission in Docket No. ER-01-2482, concerning market power issues associated with
construction of new generation facilties, June 27, 2001.
· Prepared Rebuttal Testimony on behalf of Applicants FirstEnergy and Jersey Central Power &
Light before the New Jersey Board of Public Utilties in BPU Docket No. EMOO i 10870 and OAL
Docket No. PUCOTOI585-01N, responding to allegations about defects in the competitive
analysis of the proposed FirstEnergy-GPU merger, April 23, 2001..
· Affdavit on behalf of Nine Mile Point Nuclear Station, LLC, before the Federal Energy
Regulatory Commission in Docket No. EROI-1654-000, concerning market based pricing by
Nine Mile Point Nuclear Station, LLC, March 30,2001.
.· Affdavit on behalf of Niagara Mohawk Power Corporation, New York State Electric & Gas
Corporation, Rochester Gas and Electric Corporation, Central Hudson Gas & Electric
Corporation and Nine Mile Point Nuclear Station, LLC before the Federal Energy Regulatory
Commission in Docket No. ECOI-75-000 concerning competitive issues raised by the proposed
acquisition of the Nine Mile Point 1 nuclear unit and a portion of Nine Mile Point 2 nuclear unit
by an affiliate of Constellation Energy Group, February 28, 2001.
.· Affdavit on behalf of Constellation Energy Group et al., before the Federal Energy Regulatory
Commission in Docket No. ECOI-50-000 and EROI-824-000, concerning market based pricing
by affliates of Constellation Energy Group, December 28, 2000.
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Page 14 of 27
.Prepared Direct Testimony on behalf of FirstEnergy and GPU, Inc. before the Federal Energy
Regulatory Commission in Docket No. ECOI-22-000 concerning competitive issues raised by the
proposed merger of FirstEnergy and GPU, November 9,2000.
.
.Prepared Direct Testimony on behalf of FirstEnergy and GPU, Inc. before the Pennsylvania
Public Utility Commission in Application Docket No. A-I 10300F0095, et al concerning
competitive issues raised by the proposed merger of FirstEnergy and GPU, November 9, 2000..
· Prepared Direct Testimony on behalf of FirstEnergy and GPU, Inc. before the Board of Public
Utilities of the State of New Jersey in Docket No. EMOOI 10870 concerning competitive issues
raised by the proposed merger of FirstEnergy and GPU, November 9, 2000.
.· Deposition in the matter of Ilinois Power Company and Ilinova Corporation v. Wegman Electric
Company et aI., No. 98-L-280, Circuit Court of the third Circuit of Ilinois, Madison County,
concerning damages from having electric generating stations out of service, October 17, 2000.
.
· Affdavit and Declaration on behalf of Alabama Power Company before the Environmental
Protection Agency in FOIA RlN 003111-99, concerning appropriateness of protecting certain
competitively valuable documents from public release, October 13, 2000.
. Affdavit on behalf of Northeast Utilities Service Company and Select Energy, Inc. before the
Federal Energy Regulatory Commission in Docket No. ELOO- I 02-000, concerning the cost of
providing ICAP to New England capacity market, September 25,2000.
.· Affdavit on behalf of Ameren Energy, Inc. before the Federal Energy Regulatory Commission in
Docket No. ER97-3664 and EROO-2687-000 concerning market based pricing of wholesale
electricity by Ameren, September 22, 2000.
.
· Affdavit on behalf of Alabama Power Company before the Federal Communications
Commission in P.A. No. 00-003, concerning appropriateness of protecting certain competitively
sensitive information from public release, September 6, 2000.
· Affdavit on behalf of Gulf Power Company before the Federal Communications Commission in
P.A. No. 00-004, concerning appropriateness of protecting certain competitively sensitive
information from public release, September 6, 2000.
.. Affidavit on behalf of Southern Company and Southern Energy, Inc. before the Federal Energy
Regulatory Commission in Docket No. ECOO- I 21-000, concerning whether the proposed spin-off
of Southern Energy, Inc. would create competitive concerns, August i 5, 2000.
.
. Affidavit on behalf of Northeast Utilities Service Company before the Federal Energy Regulatory
Commission in Docket No. ELOO-62-001 and EROO-2052-002 concerning proposed termination
of ICAP market and proposed mitigation of ICAP prices, May 30, 2000.
· Prepared Rebuttal Testimony on behalf of Detroit Edison Company before the Michigan Public
Service Commission in Case No. U- i 2 I 34 concerning the design of a code of conduct for
implementing retail customer choice, March 2 I, 2000.
.· Affidavit on behalf of Split Rock Energy LLC in Docket No. EROO-1857 -000 concerning Split
Rock LLC's application for market based pricing authority, March 10,2000.
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Attachment i
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.Affdavit on behalf of Baltimore Gas and Electric Company, Calvert Cliffs, Inc., Constellation
Enterprises, Inc. and Constellation Generation, Inc. in Docket No. ECOO-57-000 and on behalf of
Baltimore Gas and Electric Company, Calvert Cliffs, Inc., Constellation Generation, Inc., and
Constellation Power Source, Inc. in Docket No. EROO-1598-000 concerning the application of
Calvert Cliffs, Inc. and Constellation Generation, Inc. for market based pricing authority,
February ll, 2000.
.Deposition in the matter of Cleveland Thermal Energy Company v. Cleveland Electric
Iluminating Company, Case NO.1: 97 CV 3023, United States District Court, Northern District
of Ohio, Eastern Division, October 15, December 7 and December 8, 1999, concerning
competitive issues and damages.
.Supplemental Expert Report on behalf of Cleveland Electric Iluminating Company in Cleveland
Thermal Energy Corp. v. Cleveland Electrc Iluminating Company, Case NO.1: 97 CV 3023,
United States District Court, Northern District of Ohio, Eastern Division, December I, 1999,
concerning damages issues.
.Expert Report on Behalf of Cleveland Electric Iluminating Company in Cleveland Thermal
Energy Corp. v. Cleveland Electric Iluminating Company, Case NO.1: 97 CV 3023, United
States District Court Northern District of Ohio, Eastern Division, September 27, 1999, concerning
allegations that a clause giving Cleveland Electrc Iluminating Company the right to purchase
electricity at avoided costs from a cogeneration plant that Cleveland Thermal Energy Corp. would
have constructed was anticompetitive and an unreasonable restraint of trade, and computing
damages.
.Deposition in the matter of Florida Municipal Power Agency v. Florida Power & Light Company,
Case No. 92-35-CIV -ORL22C, United States District Court, Middle Distrct of Florida, Orlando
Division, concerning damages and market issues, August 31, 1999.
.Expert Report on Behalf of Florida Power & Light Company in Florida Municipal Agency v.
Florida Power & Light Company in Case No. 92-35-CIV -ORL22C, United States District Court,
Middle District of Florida, Orlando Division, concerning damages and market issues, August 26,
1999.
.Affdavit on behalf of AmerGen Energy Company before the Federal Energy Regulatory
Commission in Docket No. EC99-104-000 and ER99-754-001 concerning AmerGen's proposed
acquisition of the Clinton nuclear unit, August, 1999.
· Affidavit on behalf of AmerGen Energy Company before the Federal Energy Regulatory
Commission in Docket No. EC99-98-000 and ER99-754-002 concerning AmerGen's proposed
acquisition of the Nine Mile Point 1 nuclear unit and a portion of the Nine Mile Point 2 nuclear
unit, July, 1999.
· Affdavit on behalf of Minnesota Power, Inc. before the Federal Energy Regulatory Commission
in Docket No. ER99-3586-000 concerning Minnesota Power's application for market based
pricing authority, July, 1999.
· Deposition in the matter of Allegheny Energy, Inc. v. DQE, Inc., Civ. A. No. 98-16396 (RJC),
United States District Court, Western District of Pennsylvania, June i 1,1999, concerning issues
relating to the value of plaintiff s generating assets.
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Affdavit on behalf of Public Service Electric and Gas Company (PSEG) before the Federal
Energy Regulatory Commission concerning PSEG's request to transfer its generating assets to an
affliate in Docket No. EC99-79-000 et al., June 4, 1999.
.Expert Report on behalf of Allegheny Energy in Allegheny Energy, Inc. v. DQE, Inc. Civ. A. No.
98-16396 (RJC), United States District Court, Western District of Pennsylvania, May 17, 1999,
concerning issues relating to the value of plaintiffs generating assets.
· Affdavit on behalf of Baltimore Gas & Electric (BG&E) Company before the Federal Energy
Regulatory Commission concerning BG&E's application for market based pricing authority in
Docket No. ER99-2948-000, May 13, 1999.
· Affdavit on behalf of Florida Power & Light in Florida Municipal Power Agency v. Florida
Power & Light Co., Case No. 92-35-CIV -ORL-22 concerning legitimacy of Florida Power &
Light's conduct, March 22, 1999.
· Affdavit on behalf ofPECO Energy before the Federal Energy Regulatory Commission
concerning PECO's application of market based pricing authority in Docket No ER99-1872-000,
February, 1999.
.Affdavit on behalf of Northeast Utilties before the Federal Energy Regulatory Commission
concerning Norteast Utilties application for market based pricing authority in Docket No. ER
99-1829-000, February, 1999.
.Affdavit on behalf of AmerGen Energy Company, LLC (AmerGen) before the Federal Energy
Regulatory Commission in Docket No. EC99- i 1-000, EL99- i 3-000 and ER99-754-000
concerning (i) AmerGen's acquisition of Three Mile Island No. i from GPU, Inc. and (ii)
AmerGen's application for market based pricing authority, November, 1998.
.Affdavit on behalf of Constellation Energy Source, Inc. (CES) before the Federal Energy
Regulatory Commission in Docket No. ER99- i 98-000 concerning CES' s application for market
based pricing authority, October 14, 1998.
· Affdavit on behalf of Select Energy, Inc. (Select) before the Federal Energy Regulatory
Commission in Docket No. ER99-14-000 concerning Select's application for market based
pricing authority, October i, 1998.
.Rebuttal Testimony on Retail Market Power Issues on behalf of Mississippi Power Company,
before the Mississippi Public Service Commission in Docket No. 96-UA-389 concerning whether
Mississippi Power Company wil be able to exercise market power in deregulated retail markets
in Mississippi, September 1 i, 1998.
.Prepared Testimony and Report on Retail Market Power Issues on behalf of Mississippi Power
Company, before the Mississippi Public Service Commission in Docket No. 96-UA-389,
concerning whether Mississippi Power Company will be able to exercise market power in
deregulated retail markets in Mississippi, August 7, 1998.
.Affdavit on behalf of Southern California Edison Company to the Federal Energy Regulatory
Commission concerning market power issues associated with the supply of ancilary services to
the California ISO, July 13, 1998.
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Attachment i
Page 17 of27
.· Prepared Rebuttal Testimony on Behalf of Public Service Electric & Gas Company, with Paul
Joskow, before the State of New Jersey, Board of Public Utilties, in Docket No. EX94120585Y,
E097070457, E097070460, E097070463 and E097070466, responding to market power issues
raised by intervenor witnesses, including in paricular the role of transmission constraints in
market power analyses, appropriate mitigation measures for "load pocket" situations, proper
standards for granting market based pricing authority, the role of transitional mechanisms in
mitigating market power concerns and the use and role of market simulations in addressing
market power topics, April 13, 1998..
.
· Prepared Rebuttal Testimony on Behalf of Atlantic City Electrc Company, with Paul Joskow,
before the State of New Jersey, Board of Public Utilities, in Docket No. EX94120585Y,
E097070457, E094770460, E09707463 and E097070466, responding to market power issues
raised by intervenor witnesses, including in particular the role of transmission constraints in
market power analyses, appropriate mitigation measures for "load pocket" situations, proper
standards for granting market based pricing authority and the use and role of market simulations
in addressing market power topics, April 13, 1998.
.· Prepared Additional Supplemental Direct Testimony on behalf of Ohio Edison and Centerior
Energy, before the Federal Energy Regulatory Commission, Docket No. EC97-5-000, concerning
the competitive analyses associated with Ohio Edison's merger with Centerior Energy, August 8,
1997.
.
· Prepared Testimony on behalf of Public Service Electric and Gas Company on Market Power
Issues, with Paul Joskow, before State of New Jersey, Board of Public Utilities, concerning
market power issues associated with PSEG's proposal to implement retail customer choice in its
competitive fiings in New Jersey, July 30, 1997.
.
· Affdavit on behalf of Union Electric Development Corporation before the Federal Energy
Regulatory Commission in Docket No. ER97.:3663-000, concerning Union Electrc Development
Corporation's request for the right to make wholesale bulk power sales at market-determined
prices, July 8, 1997.
· Affdavit on behalf of Union Electric Company before the Federal Energy Regulatory
Commission in Docket No. ER97-3664-000, concerning Union Electric's request for the right to
make wholesale bulk power sales at market-determined prices, July 8, 1997.
.· Rebuttal Testimony on Reopening on behalf of Union Electric Company and Central Ilinois
Public Service Company, before the Ilinois Commerce Commission in Docket No. 95-0551,
addressing competitive issues raised by witnesses for intervenors and the staff of the iCC in
response to previous testimony, May 23, 1997.
.· Rebuttal Testimony on behalf of Wisconsin Power and Light Company, Interstate Power
Company and IES Industries, Inc. before the Public Service Commission of Wisconsin in Docket
No. 6680-UM-IOO, responding to concerns raised by intervenors regarding competitive issues
associated with the proposed merger of the three companies, May 20, 1997.
.
· Direct Testimony on Reopening on behalf of Union Electric Company and Central Ilinois Public
Service Company, before the Ilinois Commerce Commission in Docket No. 95-0551, responding
to ICC's request that applicants apply the screening analysis contained in Appendix A of the
Federal Energy Regulatory Commission's Order 592 to the effects of the proposed merger on
existing and future Ilinois retail markets, April 14, 1997.
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Page 18 of27
.Prepared Rebuttal Testimony on behalf of IES Utilities, Inc., Interstate Power Company,
Wisconsin Power & Light Company, South Beloit Water, Gas & Electric Company, Heartland
Energy Services and Industral Energy Applications, Inc. before the Federal Energy Regulatory
Commission in Docket No. EC96~ I 3-000, responding to issues raised by intervenors concerning
the proposed merger and the application of the screening analysis contained in Appendix A of
FERC's Order 592, April 14, 1997.
.Affdavit on behalf of Constellation Power Source, Inc. before the Federal Energy Regulatory
Commission in Docket No. ER97-2261-000, concerning Constellation's request for the right to
make wholesale bulk power sales at market-determined prices, March 25, 1997.
.Prepared Supplemental Direct Testimony on behalf of Ohio Edison Company, Pennsylvania
Power Company, The Cleveland Electrc Iluminating Company and The Toledo Edison
Company, before the Federal Energy Regulatory Commission in Docket No. EC97-5~000,
concerning the application of the screening analysis contained in Appendix A of FERC' s Order
592 to the applicants' proposed merger, March 20, 1997.
.Prepared Additional Direct Testimony on behalf of IES Utilities, Inc., Interstate Power Company,
Wisconsin Power & Light Company, South Beloit Water, Gas & Electric Company, Heartland
Energy Services and Industrial Energy Applications, Inc. before the Federal Energy Regulatory
Commission in Docket No. EC96~13~OOO, concerning the application of the screening analysis
contained in Appendix A ofFERC's Order 592 to the applicants' proposed merger, February 27,
1997.
.Prepared Rebuttal Testimony on behalf of Union Electric Company and Central Ilinois Public
Service Company before the Federal Energy Regulatory Commission in Docket No. EC96-7-000,
et al addressing competitive issues related to the proposed merger of Union Electric Company
and Central Ilinois Public Service Company, January 13, 1997.
Affdavit on behalf of Union Electric Company and Central Íllnois Public Service Company
before the Federal Energy Regulatory Commission in Docket No. EC96-7-000 et al., concerning
the effect oftne FERC's Policy Statement on mergers (Order No. 592) on the proposed merger of
Union Electric Company and Central Ilinois Public Service Company, January 13, 1997.
.
.Prepared Supplemental Direct Testimony on behalf of Union Electric Company and Central
Ilinois Public Service Company before the Federal Energy Regulatory Commission in Docket
No. EC96-7-000, et al concerning the effects of transmission constraints on the potential to
exercise market power as a result of the proposed merger of Union Electric and Central Ilinois
Public Service Company, November 15, 1996.
.Direct Testimony on behalf of Ohio Edison Company and Centerior before the Federal Energy
Regulatory Commission in Docket No. EC97-5-000 concerning the effect of the proposed merger
of Ohio Edison and Centerior on market power and competition, November 8, 1996.
.Prepared Direct Testimony on behalf of Union Electric Company before the Missouri Public
Service Commission in Case No. EM-96-149, concerning the effects on various market power
conçerns of the proposed merger between Union Electric Company and Central Ilinois Public
Service Company, November i, 1996.
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Attachment 1
Page 19 of27
.· Testimony on behalf of Virginia Electric and Power Company in the matter of Gordonsvile
Energy, L.P. v. Virginia Electric and Power Company before the Circuit Court of the City of
Richmond, Case No. LA-2266-4, concerning damages suffered by VEPCO as a result of a NUG
outage, and the appropriateness of a liquidated damages provision in the contract between
VEPCO and the NUG, October 23, 1996.
.· Prepared Direct Testimony on behalf of Southern Company Services, Inc. before the Federal
Energy Regulatory Commission in Docket No. ER96-780-000, concerning whether constraints on
the Florida/Southern interface give Southern the abilityto exercise market power, September 23,
1996.
.· Deposition in the matter of Gordonsvile Energy, L.P. v. Virginia Electric and Power Company
before the Circuit Court of the City of Richmond, Case No. LA-2266-4, concerning damages
suffered by VEPCO as a result of a NUG outage, September 17, 1996.
· Prepared Rebuttal Testimony on behalf of Public Service Company of New Mexico before the
Federal Energy Regulatory Commission in Docket No. ER95-1800-000 et al., addressing market
power issues raised by intervenors in response to previous testimony, August 30, 1996..· Prepared Testimony on behalf of Public Service Company of New Mexico before the Federal
Energy Regulatory Commission in Docket No. ER96- 155 I -000, concerning whether PNM
possesses market power in transmission-constrained areas, July 10, 1996.
.· Affdavit on behalf of Central Louisiana Electric Company before the Federal Energy Regulatory
Commission in Docket No. ER96-2677-000, concerning CLECO's request for the right to make
wholesale bulk power sales at market-determined prices, July 9, 1996.
.
· Supplemental Direct Testimony on behalf of IES Utilities, Inc., Interstate Power Company,
Wisconsin Power & Light Company, South Beloit Water, Gas & Electric Company, Heartland
Energy Services and Industral Energy Applications, Inc. before the Federal Energy Regulatory
Commission in Docket No. EC96-13-000, examining the effects of the proposed formation ofa
regional Independent System Operator on the analyses and conclusions contained in previous
testimony in support ofthe companies' proposed merger, June 5, 1996.
.
· Prepared Testimony on behalf of Minnesota Power & Light Company before the Federal Energy
Regulatory Commission in Docket No. EC95- 16-000, concerning Minnesota Power & Light's
request for the right to make wholesale bulk power sales at market-determined prices, May 16,
1996.
.
· Prepared Rebuttal Testimony on behalf of IES Industries, Inc., Interstate Power Company and
WPL Holdings, Inc. before the Iowa Utilities Board in Docket No. SPU-96-6 addressing market
power and competition issues raised by intervenors in response to previous merger testimony,
April 22, 1996.
.
· Prepared Direct Testimony on behalf of IES Utilities, Inc., Interstate Power Company, Wisconsin
Power & Light Company, South Beloit Water, Gas & Electric Company, Heartland Energy
Services and Industrial Energy Applications, Inc. before the Federal Energy Regulatory
Commission in Docket No. EC96- 1 3-000, concerning the effects of their proposed merger on
market power and competition, February 29, 1996.
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Attachment 1
Page 20 of27
.· Deposition in the matter ofWestmoreland-LG&E Partners v. Virginia Electric and Power
Company, Case No. LX-2859-1, concerning interpretation of capacity payment provisions in
power purchase agreement under which Westmoreland-LG&E sells output of non-utility
generator to VEPCO, February 23, 1996 and October 9, 1998.
.· Prepared Testimony on behalf of Union Electric Company and Central Ilinois Public Service
Company before the Federal Energy Regulatory Commissioiiin Docket No. EC96-7-000 and
ER96-679-000, concerning the effects of their proposed merger on market power and
competition, December 22, 1995.
.
· Prepared Testimony on behalf of Northeast Utilities before the Federal Energy Regulatory
Commission in Northeast Utilities Service Company, Docket No. ER95-1686-000, concerning
FERC's generation dominance standard in support of Northeast Utilties' request for market-
based pricing authority, November 13, 1995.
.
· Sur-reply affdavit on behalf of Rochester Gas & Electric before the U.S. District Court, Western
District of New York, in Kamine/Besicorp Allegheny L.P. v. Rochester Gas & Electric
Corporation, Case No. 95-CIV-6045L, in response to motion by Kamine/Besicorp Allegheny L.P.
for a preliminary injunction, July 10, 1995.
· Prepared Supplemental Rebuttal Testimony on Transmission NOPR Issues on behalf of Florida
Power & Light Company before the Federal Energy Regulatory Commission in Florida Power &
Light Company, Docket No. ER93-465-000 et al., addressing transmission NOPR issues raised
by FERC Staff and Intervenors, May 19, 1995..
· Prepared Direct Testimony on Transmission NOPR Issues on behalf of Florida Power & Light
before the Federal Energy Regulatory Commission in Florida Power & Light Company, Docket
No. ER93-465-000, et ai, concerning the effects of FERC's recent Notice of Proposed
Rulemaking on issues in FPL's ongoing case, Apri125, 1995.
.· Affdavit on behalf of Rochester Gas & Electric before the U.S. District Court, Western District
of New York, in Kamine/Besicorp Allegheny L.P. v. Rochester Gas & Electric Corporation, Case
No. 95-CIV-6045L, in support of its opposition to a request by Kamine/Besicorp Allegheny L.P.
for a temporary restraining order, March 9, 1995.
.· Testimony on behalf of Virginia Power before the Circuit Court of the City of Richmond in Case
No. L W -730-4, Doswell Limited Partnership v. Virginia Electric Power Company concerning the
level of fixed gas transportation costs associated with the proxy unit which forms the basis for
VEPCO's payments to Doswell, March 2, 1995.
.· Prepared Rebuttal Testimony on behalf of American Electric Power Service Corporation before
the Federal Energy Regulatory Commission in Docket No. ER93-540-001 addressing issues
concerning FERC's new comparability standard and its implications for AEP's transmission
service offerings, January 17, 1995.
· Deposition on behalf of El Paso Electric Company and Central and South West Services, Inc.
before the Federal Energy Regulatory Commission in Docket No. EC94- 7 -000 and ER94-898-
000 concerning comparability and other transmission issues, December 22, 1994..
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.Prepared Rebuttal Testimony on behalf of Florida Power & Light Company before the Federal
Energy Regulatory Commission in Florida Power & Light Company, Docket No. ER93-465-000
et al. concerning market power and competitive issues, comparability and other transmission
issues, wholesale electric service tariff revisions, and issues concerning interchange contract
revisions, December 16, 1994.
.Prepared Rebuttal Testimony on behalfofEI Paso Electric Company and Central and South West
Services, Inc. before the Federal Energy Regulatory Commission, Dockets No. EC94-7-000 and
ER94-898-000, concerning network transmission service and point-to-point transmission service,
December 12, 1994.
.Prepared Direct Testimony on behalf of Midwest Power Systems, Inc. and Iowa-Ilinois Gas and
Electric Company before the Federal Energy Regulatory Commission, Docket No. EC95-4-000.
concerning competitive issues raised by their proposed merger to form MidAmerican Energy
Company, November 10,1994.
.Deposition on behalf of Florida Power Corporation in Orlando Cogen, Inc. et al., v. Florida
Power Corporation, Case No. 94-303-CIV -ORL- 1 8, US District Court in and for the Middle
District of Florida, Orlando Division, involving a contrct dispute between FPC and one of its
NUG suppliers, August 30, 1994.
.Prepared Direct Testimony on Comparability Issues on behalf of Florida Power & Light
Company in Florida Power & Light Company, Docket No. ER93-465-000 and ER93-922-000
concerning a discussion of the differences between types of transmission services, usage of
transmission systems by their owners, transmission services that FPL provides, and how those
services compare and contrst with FPL's own uses of the transmission system, August 5, 1994.
.Prepared Answering Testimony on behalf of Florida Power & Light Company in Florida Power
& Light Company, Docket No. ER93-465-000 and ER93-922-000 concerning (i) whether
municipal systems should receive biling credits for certain transmission facilities which they own
which were argued to be part of an "integrated" transmission grid, and (ii) FPL's obligation to
sell wholesale power under its Nuclear Regulatory Commission antitrust license conditions, July
7, 1994.
.Deposition on behalf of Virginia Electric & Power Co. in re: Doswell Limited Partnership v.
Virginia Electric & Power Co., Case No. L W - 730-4, Circuit Court for the City of Richmond,
involving an alleged fraud and breach of contract relating to payments by VEPCO to one of its
NUG suppliers, April 5, 1994.
· Prepared Final Rebuttal Testimony on behalf of Central Louisiana Electric Company before the
Federal Energy Regulatory Commission in Docket No. ER93-498-000, examining an allegation
of predatory pricing, March 16, 1994.
· Prepared Rebuttal Testimony on behalf of Central Louisiana Electric Company before the Federal
Energy Regulatory Commission in Docket No. ER93-498-000, examining an allegation of a
municipal joint action agency that Central Louisiana's contract to provide bulk power service to a
new municipal system customer constituted predatory pricing, December 23, 1993.
· "Comments on the Commerce Commission's Draft Determination Concerning Trans Power's
Proposal to Recover Fixed/Sunk Transmission Costs," testimony on competitive issues prepared
at the request of The Electricity Industry Committee, New Zealand, November 30, 1993.
.
Attachment 1
Page 22 of27
.· Prepared Direct Testimony on behalf of Florida Power & Light Company in Florida Power &
Light Company, Docket No. ER93-465-000 and ER93-922-000 concerning competitive
implications of wholesale tariff revisions, interchange contract revisions and a proposed "open
access" transmission tariff, November 26, 1993.
.· Deposition on Behalf of Florida Power & Light in Florida Municipal Power Agency v. Florida
Power & Light Co. Case No. 92-35-CIV -ORL-22 concerning damage related issues, July 21 and
22, 1993.
· Affdavit on behalf of Florida Power & Light in Florida Municipal Power Agency v. Florida
Power & Light Co. Case No. 92-35-CIV-ORL-22 concerning damage related issues, July 14,
1993..
.
· Prepared Direct Testimony on behalf of the Detroit Edison Company In the Matter of the
Application of the Association of Businesses Advocating Tarff Equity for Approval of an
experimental retail wheeling tariff for Consumers Power Company, Case No. U- 1 0 143, and In the
Matter on the Commission's own motion, to consider approval of an experimental retail wheeling
tariff for The Detroit Edison Company, Case No. U-101 76 before the Michigan Public Service
Commission, March 1, 1993.
· Deposition on behalf of Florida Power & Light in Florida Municipal Power Agency vs. Florida
Power & Light Company, Case No. 92-35-CIV -ORL-22, concerning relevant markets, market
power and competitive issues, February 25, 1993.
.· Deposition in Tucson Electric Power Company v. SCE Corporation et al., Superior Court of the
State California, Case No. 628170, June 19, 1992.
· Affdavit on behalf ofIowa Power Inc. and Iowa Public Service Company, Federal Energy
Regulatory Commission, Concerning the Competitive Effects of a Merger of the Two Companies,
1991..· Testimony on behalf of Defendants Union Electric and Missouri Utilities, in City of Malden,
Missouri v. Union Electric Company and Missouri Utilities Company, U.S. District Court,
Eastern District of Missouri, Southeastern Division, Civil Action No. 83-2533-C, 1988.
.· Testimony on behalf of Defendant Union Electric, in City of Kirkwood, Missouri v. Union
ElectricCompany, U.S. District Court, Eastern District of Missouri, Civil Action No. 86-1787-C-
6 (deposition testimony), 1987.
· Testimony on behalf of Defendant Union Electric Company, in Citizens Electric Corporation v.
Union Electric Company, U.S. District Court, Eastern District of Missouri, Eastern Division,
Civil Action No. 83-2756C(c), 1986..· Testimony on behalf of Advo-System, Inc. before the Postal Rate Commission, Docket No. R84-
1, Concerning Rates for Third Class Mail, 1984.
· Testimony on behalf of D/FW Signal, Inc. before the Federal Communications Commission,
Docket No. CC83-945, Concerning Cellular Telephone Service in Dallas-Fort Worth, 1983..· Testimony on behalf of the Department of Defense, before the Montana Public Service
Commission, Docket No. 82.2.8, Concerning Telephone Service Rate Structure, 1982.
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Attachment i
Page 23 of27
.Testimony on behalf of Multnomah County, before the Public Utility Commissioner of Oregon.
Docket UF 3565, Concerning Telephone Service Rate Structure, 1980.
.Testimony on behalf of the Louisiana Consumer League, before the Louisiana Public Service
Commission, Docket No. U-14078, Concerning Marginal Cost Pricing for Louisiana Power and
Light Company, 1979.
.Testimony on behalf of the State of Oregon, City of Portland, and County of Multnomah, before
the Public Utility Commissioner of Oregon, Dockets UF3342 and UF3343, concerning Rates for
Centrex and ESSX Telephone Service, 1978.
SELECTED REPORTS AND PAPERS
."Comments" in Federal Energy Regulatory Commission Docket No. RM04-7-000 concerning
rules governing short-term transactions between generation-owning regulated electric utilities and
their marketing affliates, June 30, 2004.
."Large RTOs and Traditional Transmission Pricing Don't Mix," with Michael Quinn, prepared
for The Electricity Journal, January/February 2002.
· "Potential Adverse Consequences of Poor Transmission Pricing," prepared for Southern
Company Services, Inc., October 23,2001.
."An Economic Assessment ofthe Benefits of Repealing PUHCA," with John Landon, Ajay
Gupta and Virginia Perr-Failor, prepared for Mid-American Energy Holdings, April 2000.
· Updated Market Power Analysis for Detroit Edison Company, concerning Detroit Edison
Company's market based pricing authority, submitted to the Federal Energy Regulatory
Commission, December 17, 1999.
.Report of Ameren to the Public Service Commission of Missouri on Market Power Issues,
concerning whether Ameren, created by the merger of Union Electric Company and Central
Ilinois Public Service Company, is likely to have market power if deregulation and retail
competition are introduced in Missouri, February 27, 1998.
...Supporting Companies' Report on Horizontal Market Power Analysis," with Paul Joskow,
concerning analysis of market power issues in connection with a proposed reorganization of the
PJM Pool, July 14, 1997.
· .'International Electricity Sector Investment by US Electric Utilities," with Graham Hadley, Paul
Hennemeyer and Barbara MacMullen, prepared for The Kansai Electric Power Company, Inc.,
March 5, 1997.
...Report on Horizontal Market Power Issues," with Paul Joskow, prepared for Southern California
Edison Company in FERC Docket No. ER96-1663-000, May 29, 1996.
..'Recent Developments in North American Electric Generation Capacity Procurement Systems,"
with Mahim Chellappa, prepared for Electricite de France (EDF), Paris, France, August 1994.
.'.Comments on Transmission Reform Proposals," report prepared for the Edison Electric Institute,
October i 993.
.
Attachment i
Page 24 of27
.· "Sunk Transmission Cost Recovery Issues," report prepared for The Electricity Industry
Committee, New Zealand, September 1, 1993.
."Opportunity Cost Pricing for Electrc Transmission: An Economic Assessment," report
prepared for Edison Electric Institute, June 1992.
.· "Transmission Access and Pricing: What Does A Good 'Open Access' System Look Like,"
NERA Working Paper #14, January 1992.
· "Evaluation of Qualifying Facility Proposals," prepared for Florida Power Corporation, March
1991.
.· "Design of Capacity Procurement Systems," prepared for Electricite de France, January 1991.
· "Issues in the Design of Generating Capacity Procurement Systems," prepared for TransAlta
Utilties, January 1991.
.· "Government Regulators and Market Power Issues," prepared for Edison Electric Institute,
January 1991.
· "A Critique and Evaluation of the Large Public Power Council's Transmission Access and
Pricing Proposal," prepared for Edison Electric Institute, December 1990.
.· "The Effects of a Premature Shutdown of the Trojan Nuclear Power Plant," prepared for Portland
General Electric Company, October 1990.
· "An Examination of the Proper Role for Utilties in Promoting Conservation Expenditures,"
prepared for Public Service Electric and Gas Company with T. Scott Newlon, 1990.
.· "Issues Concerning Selection Criteria Development for Capacity RFPs," prepared for the
Bonnevile Power Administration, February 15, 1990.
· "Nonutility Generators and Bonnevile Power Administration Resource Acquisition Policy,"
prepared for the Bonnevile Power Administration, with David L. Weitzel, January 31, 1990.
.· "An Evaluation of Resource Solicitation Alternatives," prepared for the Bonneville Power
Administration, January 31, 1990.
· "Approaching the Transmission Access Debate Rationally," Transmission Research Group
Working Paper Number 1, with Joe D. Pace, November 1987.
· "The Essential Facilities Doctrine," NERA, June 1985..· "The Nuclear Regulatory Commission's Antitrust Review Process: An Analysis of the Impacts,"
Transcomm, Inc., prepared for the U.S. Department of Energy, 1981.
."Competitive Aspects of Utility Involvement in Cogeneration and Solar Programs," Transcomm,
Inc., prepared for the U.S. Department of Energy, June 1981..· "An Appraisal of Antitrust Review Extension in the Context of Small Utility Fuel Use Act
Compliance," Transcomm, Inc., prepared for the U.S. Department of Energy, July 28, 1980.
.
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Attachment 1
Page 25 of27
.· "Analysis of Proposed License Conditions with Respect to Antitrust Deficiencies," Transcomm,
Inc., prepared for the U.S. Nuclear Regulatory Commission, 1978.
."Analysis of NRC Staffs Proposed License Conditions for Midland Units," Transcomm, Inc.,
prepared for the U.S. Nuclear Regulatory Commission, August 7, 1978.
.SELECTED SPEECHES
· Panelist at Edison Electric Institute's Supply Policy Task Force conference discussing various
topics associated with proposed revisions to FERC's procedures for determining when market-
based as opposed to cost-based pricing is appropriate, Washington, DC, July 18,2006
.· "Resource Acquisition and Market Power Topics: Overview of FERC's Curent and Evolving
Practices," presented to Edison Electric Institute Workshop on Market Power Policies and
Current Practices at the NARUC's Summer Committee Meetings, Salt Lake City, Utah, July 10,
2004.
.· "Examining the Commission's Recent Treatment of Market Power and Competitive Issues,"
speech presented to the Edison Electric Institute Spring Legal Conference, Scottsdale, Arizona,
March 29, 2004.
· Presentation on Transmission Pricing Issues to the EEl Winter Chief Executive Conference and
Board of Directors Meeting, Scottdale, AZ, January 10, 2002.
.· Presentation to the Board of Directors of the Salt River Project on Code of Conduct Issues
Associated with Industr Restructuring, November 9, 1998.
· "FERC's Approach To Addressing Horizontal Market Power in Electric Mergers," speech
presented to Infocast Conference on Utility Mergers & Acquisitions, Washington, D.C., July 17,
1998..· "Problems in Applying the Appendix A Analytical Screen," speech presented to the Edison
Electric Institute Workshop on Practical Applications of the FERC Merger Policy Guidelines,
Arlington, Virginia, April i, 1997.
.· "Evolving Market Power Issues in the Context of Electric Restructuring," speech presented to
Eastern Mineral Law Foundation Forum on Natural Resources and Energy Law, Sanibel Island,
Florida, February 13,1997.
· "An Overview of Antitrust in the Electric Industry," speech presented to Antitrust Law &
Economics for the Electric Industry, sponsored by Energy Business, Inc., Washington, D.C.,
February 22, 1996..
· "Moving From Here to There: Some Implications for Electric Transmission," speech presented to
the Infocast Power Industry Forum, Palm Springs, California, February 17, 1995.
.· "What Does 'Comparability' Really Mean?," speech presented to The Federal Energy Bar
Association, Washington, D.C., November i 7, 1994.
· "Current Transmission Topics" and "Trans Alta's Unbundled Rate Proposal," presented to the
Canadian Electrical Association, Montreal, PQ, Canada, May 9, i 994.
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Attachment 1
Page 26 of27
· "Retail Wheeling Issues," speech presented to the Edison Electric Institute National Accounts
Workshop, Atlanta, Georgia, Februar 7, 1994.
."Retail Wheeling: Doing It the Right Way," speech presented to the Retail Wheeling
Conference, Denver, Colorado, November 8, 1993.
· "Retail Wheeling," speech presented to the Missouri Valley Electric Association Division
Conference, Kansas City, Missouri, October 22, 1993.
."An Economic Perspective on Current Transmission Pricing Issues," speech presented to the
Edison Electric Institute 1993 Fall Legal Committee Meeting, Minneapolis, Minnesota, October
7, 1993.
."Charcteristics of a 'Good' Retail Wheeling System," speech presented to the Second Annual
Electricity Conference sponsored by Executive Enterprises, Inc., Washington, D.C., April 21-22,
1993.
."Characteristics of a 'Good' Retail Wheeling System," speech presented to the Electric Utilty
Business Environment Conference sponsored by Electric Utility Consultants, Inc., Denver,
Colorado, March 16-17, 1993.
."Change in the Industr," seminar presentation on privatization and service unbundling presented
to Ontario Hydro management and special strategy task force, Ontaro, Canada, February 3, 1993.
."The U.S. Experience and What Is To Come," speech presented to NERA Seminar on
Competition in the Regulated Industries (Electric/Telecommunications), Rye Town Hilton, Rye
Town, New York, October 30, 1992.
."Emerging Transmission Pricing Issues," speech presented to Electrc Utility Consultants, Inc.'s
3rd Annual Transmission & Wheeling Conference, Chicago, Ilinois, September 22-23, 1992.
."Emerging Transmission Pricing Issues," speech presented to Executive Enterprises, Inc., 1992
Electricity Conference: Restructuring the Electricity Industry, Washington, D.C., September 15-
16, 1992.
."A Pragmatic Look at Open Access," presented to DOEINARUC Workshop on Electricity
Transmission, Stockbridge, Massachusetts, June 2, 1992.
."Some Thoughts About Open Access," presented to EMA's Issues and Outlook Forum, Atlanta,
Georgia, May 5, 1992.
."Transmission Access: How Should We Proceed?" Speech presented to the Second Annual
Transmission and Wheeling Conference, Denver, Colorado, November 2 I, 1991.
."Can We Implement Reasonable Transmission Pricing and Access Procedures?" presented to the
Edison Electric Institute System Planning Committee, Dallas, Texas, October 24, 1990.
."Issues in the Design of Competitive Bidding Systems," presented at the Pennsylvania Electric
Association System Planning Meeting," 1990.
.
Attachment 1
Page 27 of27
."Should We Use Opportunity Cost Pncing for Transmission?" presented to the Edison Electric
Institute Interconnection Arrangements Committee, 1990..
· "Recent Changes in the Electnc Power Industry and Pressures on the Trasmission System,"
presented at seminar "Competitive Electncity: Why the Debate?" Sponsored by the Electncity
Consumers Resource Council, 1988..· "Some Thoughts on New Trasmission Access and Pncing Proposals," presented at conference
"Transmission Pncing and Access: Reinventing the Wheel," sponsored by Cogeneration and
Independent Power Coalition of Amenca and Amencan Cogeneration Association, i 988.
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Attachment 3
Page 1 of4
.WECC Generation Capacity
Owned by PacifiCorp and Affliates
Plant Name Fuel Type Summer Capacity Winter Capacity.(M (MW
PacifCorp
PACE BAA
Ashton Hydro 7.20 7.20
BigFork!Hydro 4.15 4.15.Blundell Geothermal 23.00 23.00
Blundell ie Geothermal 11.00 11.00
Carbon Coal 172.00 172.00
Cholla Coal 380.00 380.00.Curant Creek Gas 497.00 542.00
Cutler Hydro 29.00 29.00
Dave Johnston Coal 757.20 762.00
Foote Creek3 Wind 32.60 32.60
Fountain Green Hydro 0.16 0.16.Gadsby Gas 343.10 347.00
Glen Rock t Wind 99.00 99.00
Glen Rockm4 Wind 39.00 39.00
Goshen Wind 64.50 64.50
Grace Hydro 33.00 33.00.Granite Hydro 1.20 1.20
Gunlock Hydro 0.50 0.50
Hunter3 Coal 1,122.50 1,122.50
Huntington Coal 895.00 895.00
Lake Side Gas 553.00 559.00.Last Chance Hydro lAO lAO
Little Mountain Gas 12.00 14.00
Naughton Coal 695.00 700.00
Olmstead Hydro 9.60 9.60
Oneida Hydro 27.99 27.99.Paris Hydro 0.72 0.72
Pioneer Hydro 4.00 4.00
Rollng Hils4 Wind 99.00 99.00
Sand Cove Hydro 0040 0.50
Seven Mile Hil5 Wind 99.00 99.00.Seven Mile Hil Expansion5 Wind 19.50 19.50
.
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Attachment 2
Page 2 of3
.Abbreviation Description
MEHC
Merger Guidelines
.MidAmerican or MEC
.
MEHC
Mid-C
MISO
MMBTU
Muscatine
MW
MWh
.NERCGADS
Nevada Power
NOB
NO..NPPD
NorthWestern orNWE
.
NYISO
OASIS
OATT
OPPD
PACE
PACW
PGE
PJM
PPM
.
.
Proposed Transaction
PSCo
PSNM
Puget
RTO
Sierr Pacific.SIL
.
MidAmerican Energy Holdings Company
Joint US Departent of Justice and Federal Trade Commission
Horizontal Merger Guidelines
MidAmerican Energy Company
MidAmerica Energy Holdings Company
Mid-Columbia trading hub
Midwest Independent System Operator
One Milion British Thermal Units
Muscatine Power & Water
MegaWatt
MegaWatt Hour
North American Electric Reliability Corporation's Generating
Availabilty Data System
Nevada Power Company
Nevada-Oregon Border trading hub
Nitrogen Oxides
Nebraska Public Power District
NorthWestern Energy
New York Independent System Operator
Open-Access Same-Time Information System
Open-Access Trasmission Tariff
Omaha Public Power District
PacifiCorp East
PacifiCorp West
Portland General Electric Company
PJM Interconnection
PPM Energy
Proposed acquisition of Chehalis by PacifiCorp
Public Service Company of Colorado
Public Service Company of New Mexico
Puget Sound Energy
Regional Transmission Organization
Sierra Pacific Power Company
Simultaneous Import Limit
.
Attachment 2
Page 3 of3
.Abbreviation Description
SOi Sulfur Dioxide
SUEZ SUEZ, SA
TNA TNA Merchant Projects, Inc..TIC Total Transmission Capability
WACM Western Area Power Administration - Colorado Missouri
WALC Western Area Power Administration - Lower Colorado
WECC Western Electricity Coordinating Council.Westar Westar Energy
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.Privileged & Cofidential Information Removed
Attachment 3
Page i of4
.WECC Generation Capacity
Owned by PacifiCorp and Affiliates
Plant Name Fuel Type Summer Capacity Winter Capacity
(MW)(MW).
PacifiCorp
PACE BAA
Ashton Hydro 7.20 7.20
Big Forkl Hydro 4.15 4.15.Blundell Geothermal 23.00 23.00
Blundell ie Geothermal 11.00 11.00
Carbon Coal 172.00 172.00
Cholla Coal 380.00 380.00
Currant Creek Gas --.Cutler Hydro 29.00 29.00
Dave Johnston Coal 757.20 762.00
Foote Creek3 Wind 32.60 32.60
Fountain Green Hydro 0.16 0.16.Gadsby Gas 343.10 347.00
Glen Rock 14 Wind 99.00 99.00
Glen Rock m4 Wind 39.00 39.00
Goshen Wind 64.50 64.50
Grace Hydro 33.00 33.00.Granite Hydro 1.0 1.20
Gunlock Hydro 0.50 0.50
Hunter3 Coal 1.122.50 1.122.50
Huntington Coal 895.00 895.00
Lake Side Gas -...Last Chance Hydro 1.40 1.40
Little Mountain Gas 12.00 14.00
Naughton Coal 695.00 700.00
Olmstead Hydro 9.60 9.60
Oneida Hydro 27.99 27.99.Paris Hydro 0.72 0.72
Pioneer Hydro 4.00 4.00
Rolling Hils4 Wind 99.00 99.00
Sand Cove Hydro 0.40 0.50
Seven Mile Hiii5 Wind 99.00 99.00.Seven Mile Hil Expansion5 Wind 19.50 19.50
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Attachment 3
Page 3 of4
.Plant Name Fuel Type Summer Capacity Winter Capacity
(MW) (MW)
.
Toketee
Wallowa Falls
West Side
Yale
Total PACW BAA
PSCoBAA
Hayden3 Coal
Hydro
Hydro
Hydro
Hydro
.WACMBAA
C .3raig Coal
Gas 52.30 55.60
Geothermal 10.90 10.90
Geothermal 35.80 35.80
Geothermal 35.80 35.80
Geothermal 35.80 35.80
Geothermal 10.00 10.00
Geothermal 18.10 18.10
Geothermal 53.90 53.90
Geothermal 47.50 47.50
Geothermal 58.30 58.30
Geothermal 39.60 39.60
345.70 345.70
398.00 401.30
10,589. II 10,666.17
Total PacifCorp
CE Generation, LLCIO.1i.APSBAA
Yuma
.
lID BAA
CE Turbo
Del Ranch
Elmore
Leathers
Salton Sea I
Salton Seä II
Salton Sea II
Salton Sea iv
Salton Sea V
Vulcan
.
45.00 45.00
0.90 1.00
0.60 1.00
134.00 134.00
3,430.14 3,425.01
78.10 78.10
164.50 164.50
10,191.11 10,264.87
.Total lID BAA
Total CE Generation, LLC
Total.
Sources: PacifiCorp and Platts' BaseCase.
Notes:
Figures above for wind facilities represent nameplate ratings provided by PacifiCorp. Figures
above for hydro facilities represent seasonal ratings in Platts' BaseCase. In the OPT analyses
herein. hydroelectric and wind generators are derated to reflect actual output levels..
.
.
.i Big Fork was electrically moved from PACW to PACE in October 2006.
2 Blundell II went into commercial operation on December 1.2007.
3 Figures reflect only the shares ofPacifiCorp and its affliates.
4 Glenrock I. Glenrock II and
,Rollng Hils are expected to enter commercial operation in
December 2008 but may come online as early as mid-2008.
5 Seven Mile Hil and Seven Mile Hil Expansion are expected to begin commercial operation in
December 2008 but may come on line as early as July 2008.
Ó West Valley is owned by PPM but leased to PacifiCorp under an agreement that expires
May 3 I, 2008.
7 The output of Goodnoe Hils. which is located in BPA. is transmitted to PACW.
KHermiston is 50% owned by PacifiCorp and 50% owned by Hermiston Generating Company.
Figure in table represents entire facility, reflecting PacifiCorp's dispatch control.
9 Marengo II is expected to enter commercial operation in July 2008.
10 All of the output from CE Generation's facilities is under long-term contracts with other parties.
ii CE Generation is 50% owned by MEHe and 50% owned by TransAlta.
Figures in table reflect the entire capacity of each facility owned by CE Generation.
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Attachment 3
Page 4 of 4
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Attachment 4
Schematic Diagram Showing Generation Location of
PacifiCorp and Affliates and PACE, PACW and MidAmerican First-Tier.
.
Western
Interconnection
I
I
I
I
I
I
I
I
I~
I
I
Eastern
Ilit"rCOIlIllctioli
.
.
.D Areas where PacifiCorp owns generation
D Areas where PacifiCorp affiiates own generation GRCOY
ERCOT
Iiit.'rcoiincction
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Attachment 5
DPT Topology for Chehalis Acquisition.
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Attachment 8
.Available Economic Capacity
Base Case
Destination Market: P ACW
Summer Winter Spring I Fall
i 2 3 4 2 3 i :z 3.-
Pre Acquisition
PacifiCorp Capacity (MW)362 330 175
PacifiCorp Market Share 0.0%0.0%0.0%14.8%0.0%0.0%12.3%0.0%0.0'%6.5%
SUEZ Capacity (MW)60 59 64 75 99 94
SUEZ Market Share 2.9%2.8%3.1%0.0%3.2%0.0%0.0%3.9%3.7%0.0%.Total Market Size (MW)2.059 2,068 2,107 2.451 2.358 2,363 2,690 2,500 2.521 2.711
Post Acquisition
PacifiCorp Capacity (MW)208 '362 297 330 209 175
PacifiCorp Market Share 0.0%0.0"10 11.%14.8%0.0%13.7%12.3%0.0"/.9.4%6.5%
Total Market Size (MW)1.60 1,569 1,815 2.451 1,859 2,163 2.690 2,000 2.230 2,11.Pre Acquisition HHI 1,121 1.152 1.296 1.143 1,220 1.295 1,057 958 1.153 959
Post Acquisition HHI 1,123 1,153 1,174 1,143 1.253 1,0%1,057 1,00 1.068 959
Transaction-Induced HHI Change 2 (122)33 (198)46 (85)
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Attachment 9
.Available Economic Capacity
Base Case
Destination Market: PACE
Summer Winter Spring I Fall
2 3 4 2 3 I 2 3.--
Pre Acquisition
PacifiCorp Capacity (MW)337 1.254 267 532 661 116 204
PacifiCorp Market Share 0.0%0.0010 7.7%25.4%5.8%11.4%14.4%0.0%2.7%4.9%
SUEZ Capacity (MW)24 24 26 19 27
SUEZ Market Share 0.6%0.6%0.6%0.0%0.0%0.0%0.0%0.4%0.6%0.0%.Total Market Size (MW)4.063 4,077 4,355 4,939 4,563 4,675 4,590 4.234 4,358 4.122
Post Acquisition
PacifiCorp Capacity (MW)494 1.254 267 532 661 288 204
PacifiCorp Market Share 0.0%0.00/0 11.%25.4%5.8%11.4%14.4%0.0%6.6%4.9%
Total Market Size (MW)4.063 4,077 4.353 4.939 4,563 4,675 4,590 4,234 4.358 4.122.Pre Acquisition HHI 580 609 430 997 652 572 697 667 488 638
Post Acquisition HHI 584 613 486 997 652 572 697 671 495 638
Transaction-Induced HHI Change 4 4 56 3 7
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Attachment 10
.Available Economic Capacity
Base Case
Destination Market: DP A
Summer Winter Spring I Fall
i 2 3 4 2 3 I 2 3.
Pre Acquisition
PacifiCorp Capacity (MW)450 98 661 202
PacifiCorp Market Share 0.0%0.0%0.0%5.3%0.7%0.0%9.5%0.0%0.0%3.20/0
SUEZ Capacity (MW)510 510 510 510 510 510 510
SUEZ Maret Share 3.1%3.0%3.1%0.0%3.6%4.3%0.0010 3.8%3.9%0.0%.Total Market Size (MW)16,587 16,758 16.599 8.546 14.103 11,975 6.979 13,555 13,073 6.256
Post Acquisition
PacifiCorp Capacity (MW)199 450 98 661 199 202
PacifiCorp Market Share 0.0%0.0%1.%5.3%0,7%0.0%9.5%0.0010 1.6%3.2%
Total Market Size (MW)16.077 16,249 16,289 8.546 13.593 11.465 6,979 13.045 12.763 6,256.Pre Acquisition HHI 1.195 1.242 1.97 1.03 1.61 1,176 847 930 1.26 892
Post Acquisition HHI 1.62 1,3 II 1,338 1,203 1.451 1.263 847 989 1.168 892
Transaction.lnduced HHl Change 67 69 42 90 87 59 42
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Attachment i i
.Available Economic Capacity
Base Case
Destination Market: PGE
Summer Winter Spring I Fall.I 2 3 4 2 3 I 2 3--
Pre Acquisition
PacifiCorp Capacity (MW)339 400 201
PacifiCorp Market Share 0.0%0.0%0.0%7.9%0.0%0.0%8.9%0.0%0.0%3.3%
SUEZ Capacity (MW)119 117 128 222 209
SUEZ Market Share 2.8%2.7%3.0%0.0%0.0"10 0.0%0.0"/0 3.7%3.5%0.0%.Total Market Size (MW)4.310 4.310 4.310 4.310 4.515 4.515 4.515 6.025 6.025 6.025
Post Acquisition
PacifiCorp Capacity (MW)199 339 400 199 201
Paci fiCorp Market Share 0.0%0.0%4.6%7.9%0.0%0.0%8.9%0.0%3.3%3.3%
Total Market Size (MW)4.310 4.310 4.310 4,310 4.515 4.515 4.515 6,025 6,025 6.025.Pre Acquisition HHI 1.007 1.036 1.85 1.18 1.81 1.19 955 926 1,126 861
Post Acquisition HHI 1.079 1,110 1.183 1.218 1.81 1,319 955 1.002 1.68 861
Transation-Induced HHI Change 72 74 (2)76 42
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Attachment i 2
.Available Economic Capacity
Base Case
Destination Market: Avista
Summer Winter Spring I Fall
i 2 3 4 2 3 i 2 3.-
Pre Acquisition
PacifiCorp Capacity (MW)25 6 83 31
PacifiCorp Markel Share 0.0%0.0%O.()"/o 2.4%0.3%0.0%5.0%0.0%0.0%2.2'%
SUEZ Capacity (MW)\6 \6 17 30 29 40
SUEZ Market Share \.5%1.%1.6%0.0%1.8%0.0%0.0%2.I~ó 2.9%0.0%.Total Markei Size (MW)\,055 1.055 1.055 1.054 1,670 1.669 1,668 1.92 1.392 1.91
Post Acquisition
PacifiCorp Capacity (MW)13 25 6 83 19 31
PacifiCorp Markel Share 0.0%0.0%1.2%2.4%0.3%0.0%5.0%0.0%1.4%2.2%
Total Markei Size (MW)1.055 1.055 1.055 1.054 1,670 1,669 1.668 1.392 1.392 1.39\.Pre Acquisition HHT 539 545 757 661 792 870 690 544 761 643
Post Acquisition HHI 564 570 788 661 824 870 690 572 820 643
Transaction-Induced HHT Change 25 25 31 32 28 59
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Attachment 13
.Available Economic Capacity
Base Case
Destination Market: Idaho Power
Summer Winter Spring I Fall.i 2 3 4 2 3 2 3---
Pre Acquisition
PacifiCorp Capacity (MW)38 374 42 44 496 10 204
PacifiCorp Market Share 0.0%0.0%2.1%20.0%2.4%2.4%26.1%0.0%0.5%9.8%
SUEZ Capacity (MW)20 18 20 17 35
SUEZ Market Share l.%1.0%l.%0.0%0.0%0.0"10 0.0%0.9%1.7%O.O'Ó.Total Market Size (MW)1,801 1,792 1,835 1.865 1.742 1.815 1.900 1.917 2.031 2,068
Post Acquisition
PacifiCorp Capacity (MW)236 374 42 44 496 210 204
PacifiCorp Market Share 0.0"/.0.0%12.9%20.0%2.4%2.4%26.1%0.0"/.10.3%9.8%
Total Market Size (MW)1.801 1.792 1.835 1.865 1.742 1.815 1.900 1.917 2.031 2.068.Pre Acquisition HHI 356 369 369 726 580 564 937 552 504 474
Post Acquisition HHI 368 380 427 726 580 564 937 567 487 474
Transaction-Induced HHI Change 12 II 58 15 (17)
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Attachment 14
.Economic Capacity
Base Case
Destination Market: P ACW
Summer Winter Spring I Fall
i 2 3 4 2 3 i 2 3.
Pre Acquisition
PacifiCorp Capacity (MW)2,495 2,477 2.426 2.405 2,637 2.651 2.559 2.272 2.212 2.145
PacifiCorp Market Share 52.4%52.1%51.3%53.4%52.8%52.8%51.6%45.7%46.9%45.9%
SUEZ Capacity (MW)30 31 35 36 44 49
SUEZ Market Share 0.6%0.7%0.7%0.0%0.7%0.0%0.0%0.9%1.0%0.0%.Total Market Size (MW)4,760 4,750 4.733 4.505 4.997 5,022 4,962 4,972 4.721 4,672
Post Acquisition
PacifiCorp Capacity (MW)2.989 2,971 2.919 2,405 3,131 3.144 2,559 2.767 2.706 2.145
PacifiCorp Market Share 62.8%62.5%61.7%53.%62.7%62.6%51.6%55.7%57.3%45.9"10
Total Market Size (MW)4.760 4,750 4.733 4.505 4.997 5.022 4.962 4.972 4.721 4.672.Pre Acquisition HHI 3.043 3.010 2.948 3.174 3,134 3,136 2.979 2,472 2.608 2.520
Post Acquisition HHI 4.117 4,083 3.994 3,174 4,140 4.125 2.979 3,346 3.549 2.520
Transaction-Induced HHI Change 1.074 1,073 1.046 1.006 988 875 941
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Attachment 15
.Economic Capacity
Base Case
Destination Market: PACE
Summer Winter Spring I Fall
i 2 3 4 2 3 i 2 3.-
Pre Acquisition
PacifiCorp Capacity (MW)6.133 6.131 6.137 5.715 5.874 5.838 4.949 5.049 5.09 4,169
PacifiCorp Market Share 55.0%55.0%55.8%56.8%55.1%55.9%52.2%51.2%51.4%48.8%
SUE Capacity (MW)12 11 13 9 9
SUE Market Share 0.1%0.1%0.1%0.0%0.0"10 0.0%0.0"/.0.1%0.1%0.0%.Total Market Size (MW)11.153 11,147 11.000 10.063 10,664 10,454 9.486 9,852 9.823 8.545
Post Acquisition
PacifiCorp Capacity (MW)6,145 6.143 6.151 5.715 5.874 5.838 4.949 5,051 5.065 4,169
PacifiCorp Market Share 55.1%55.1%55.9%56.8%55.1%55.9%52.2%51.%51.6%48.8%
Total Market Size (MW)11,153 11.147 11,000 10,063 10,664 10.454 9.486 9.852 9.823 8,545.Pre Acquisition HHI 3.144 3.144 3,226 3.340 3.167 3,237 2,859 2,766 2.775 2,530
Post Acquisition HHI 3,155 3,156 3,240 3.340 3.167 3.237 2.859 2.768 2.791 2.530
Transaction-Induced HHI Change 12 12 14 2 17
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Attachment 16
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Attachment 17
.Economic Capacity
Base Case
Destination Market: PGE
Summer Winter Spring I Fall...3 4 2 3 i 2 3
Pre Acquisition
PacifiCorp Capacity (MW)531 531 568 567 682 680 683 877 877 875
PacifiCorp Market Share 8.5%8.5%9.1%11.0%10.6%10.6%11.%11.21%11.%12.9%
SUEZ Capacity (MW)51 52 58 88 99
SUEZ Market Share 0.8%0.8%0.9%0.0%0.0%0.0%0.0%1.%1.%0.0%.Total Market Size (MW)6,266 6.261 6,257 5,173 6.459 6,408 5.929 7,831 7.628 6,808
Post Acquisition
PacifiCorp Capacity (MW)541 54\573 567 682 680 683 885 885 875
PacifiCorp Market Share 8.6%8.6%9.2%11.0%10,6%10.6%11.5%11.%11.6%12.9%
Total Market Size (MW)6,266 6,261 6.257 5.173 6,459 6,408 5,929 7,831 7.628 6.808.Pre Acquisition HHI 1.492 1.477 1,509 1,101 1.542 1.504 1,205 1.260 1,241 1,079
Post Acquisition HHI 1.512 1.496 1.53\1,101 1.542 1.504 1.05 1.291 \,278 1,079
Transaction-Induced HHI Change 20 20 23 30 37
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Attachment is
.Economic Capacity
Base Case
Destination Market: Avista
Summer Winter Spring I Fall
i 2 3 4 2 3 2 3.---
Pre Acquisition
PacifiCorp Capacity (MW)38 38 43 48 70 74 81 55 62 66
PacifiCorp Market Share 1.5%1.5%1.7%2.7%2.9%3.1%3.7%2.1%2.9%3.4%
SUEZ Capacity (MW)8 9 9 14 14 15
SUEZ Market Share 0.3%0.3%0.4%0.0%0.6%0.0%0.0010 0.5%0.7%0.0%.Total Market Size (MW)2.578 2.565 2,496 1.753 2.433 2.366 2.209 2.651.2.123 1.959
Post Acquisition
PacifiCorp Capacity (MW)38 38 43 48 70 74 81 55 62 66
PacifiCorp Market Share 1.5%1.%1.7%2.7%2.9%3.1%3.7%2.1%2.9%3.4%
Total Market Size (MW)2.578 2.565 2,496 1.753 2.433 2.366 2.209 2.651 2.123 1.959.Pre Acquisition HHI 3,400 3.383 3.268 1.784 1,402 1.376 1.094 2.358 1.571 1.245
Post Acquisition HHI 3,403 3.386 3.272 1.784 1,413 1.376 \,094 2.365 1.582 1.245
Transaction-Induced HHI Change 3 3 4 II 7 Ii
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Attachment 19
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Attachment 20
Volumes and Market Shares for Electricity Sales
at Mid-C, COB and NOB
2007, All Days
Volume (MWh)Market Share (%)
Delta
Year Month Chehalis PacifiCorp Market Chehalis PacifiCorp Combined HHIFaciltyFacility
2007 1 54,865 488,940 9,997,603 1%5%5%5
2 125,957 454,516 8,720,757 1%5%7%15
3 26 522,702 12,723,381 0%4%4%0,
4 8,633 316,710 9,245,354 0%3%4%1
5 14,733 294,778 9,829,458 0%3%3%I
6 63,592 338,346 9,361,860 1%4%4%5
7 221,369 215,870 9,020,275 2%2%5%12
8 269,937 251,766 9,219,559 3%3%6%16
9 329,030 215,623 8,282,399 4%3%7%21
10 375,541 339,996 8,758,013 4%4%8%33
11 233,130 333,580 9,007,853 3%4%6%19
12 190,637 438,099 9,598,919 2%5%7%18
Notes:
PacifiCorp and Market volumes developed from FERC EQR fiings. Chehalis Facility volume developed using data from Platts' BaseCase.
. EPA CEMS and ETA Form 920. See text and workpapers.
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Attachment 21
Volumes and Market Shares for Electricity Sales
at Mid-C, COB and NOB
2007, Days When Chehalis Facility Generates
Volume (MWh)Market Share (%)Delta
Year Month Chehalis PacifiCorp Market Chehalis PacifiCorp Combined "HIFacilityFacility
2007 1 54,865 108,739 2,277,781 2%5%7%23
2 125,957 233,403 4,546,611 3%5%8%28
3 26 15,861 364,959 0%4%4%°
4 8,633 60,607 1,788,031 0%3%4%3
5 14,733 24,581 982,636 1%3%4%8
6 63,592 131,881 3,560,219 2%4%5%13
7 221,369 178,584 7,727,042 3%2%5%13
8 269,937 230,533 8,732,694 3%3%6%16
9 329,030 215,623 8,282,399 4%3%7%21
10 375,541 339,996 8,758,013 4%4%8%33
11 233,130 287,810 7,905,756 3%4%7%21
12 190,637 335,404 7,855,223 2%4%7%21
Notes:
PacifiCorp and Market volumes developed from FERC EQR fiings. Chehalis Facility volume developed using data from Platts' BaseCase,
. EPA CEMS and EIA Form 920. See text and workpapers.
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.ATTACHMENT 2
AFFIDAVIT OF JOHN APPERSON
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
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PacifiCorp
TNA Merchant Projects, Inc.
Chehalis Power Generating, LLC
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Docket No. EC08-_-000
AFFIDAVIT OF JOHN A. APPERSON ON BEHALF OF PACIFICORP
REGARDING THE RELIABILITY IMPACTS AND TRANSMISSION
ARRNGEMENTS ASSOCIATED WITH INTEGRATING THE CHEHALIS FACILITY
INTO PACIFICORP'S WESTERN BALANCING AUTHORITY AREA.
1. My name is John A. Apperson. My business address is 825 NE Multnomah
Street, Suite 600, Portland, OR 97232.
. .2.I received a Bachelor of Science degree in electrical engineering at Oregon State
University in 1978.
3. I am currently the trading director in the commercial and trading deparment at.
PacifiCorp. I have held this position since 2000. Between 1995 and 2000, I held varous
positions in the merchant business unit ofPacifiCorp, and between 1982 and 1995, I held various
.positions in transmission planing with PacifiCorp. Prior to 1982, I worked for CP National in
distribution planning and operation roles.
4. The purpose of my affidavit is to describe the system reliabilty impacts and.transmission arangements associated with integrating Chehalis Power Generating, LLC's
("Chehalis") 520 MW, natural gas-fired combined cycle, electric generation facilty located in
Lewis County, Washington ("Chehalis Facility") into the PacifiCorp West balancing authority.
area ("PACW") following PacifiCorp's acquisition of Chehalis and the simultaneous merger of
Chehalis into PacifiCorp.
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5. The Chehalis Facilty is curently interconnected to the Bonnevile Power
.Administration ("BPA") transmission system and is located in BPA's balancing authority area.
6. Following the acquisition and merger of Chehalis into PacifiCorp, PacifiCorp wil
probably "move" the Chehalis Facilty from the BPA balancing authority area into the PACW.balancing authority area. i
7. The acquisition of Chehalis and integration of the Chehalis Faciiity into the
P ACW balancing authority area will not have a material impact, or adverse impact, to the.
reliability of firm transmission service within the Pacific Northwest.
8. In order to integrate the Chehalis Facility into the PACW balancing authority area
.as planed, PacifiCorp would install telemeter equipment at the Chehalis Facility to provide a
signal to the PacifiCorp and BPA energy management systems. The operation of the telemeter
equipment would remove the output of the Chehalis Facilty from the BPA balancing authority.
area and add (or integrate) the output of the Chehalis Facilty into the PACW balancing authority
area. As I explain below, PacifiCorp curently relies on the operation of telemeter equipment to
.integrate other resources owned by PacifiCorp in the BP A balancing authority area into
PacifiCorp's PACW balancing authority area.
9. PacifiCorp would register the Chehalis Facilty as a PacifiCorp source with the
.North American Reliability Corporation ("NERC"), effective on the day PacifiCorp becomes the
owner and operator of the Chehalis Facility, to comply with NERC's Transmission System
Information Network requirements. Concurrently, Chehalis would deactivate the Chehalis.
.The PACW balancing authority area is one of two PacifiCorp balancing authority areas and includes
service territory in portions of Washington, Oregon and California plus remote generation in Montana and
Wyoming. The other balancing authority area operated by PacifiCorp, the PacifiCorp East ("PACE") balancing
authority area, includes service territory in portions of Idaho, Utah and Wyoming, plus remote generation in Arizona
and Montana.
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Facilty as a Chehalis source with NERC. Additionally, PacifiCorp would register the Chehalis
Facilty as a point of receipt within the PACW balancing authority area upon moving the
Chehalis Facility from the BP A to PACW balancing authority area.
10. Because it is operationally feasible to have the Chehalis Facilty continue to reside
in the BP A balancing authority area, PacifiCorp is also evaluating this as an alternative to
"moving" the Chehalis Facilty into the PACW balancing authority area.
11. "Moving" the Chehalis Facilty from the BPA balancing authority area to the
PACW balancing authority area wil not adversely impact reliabilty. PacifiCorp has significant
experience in dispatching remote facilties (i.e., integrating its remote resources into the PACW
and PACE balancing authority areas) and PacifiCorp and, to PacifiCorp's knowledge, the
transmission owners where such facilties are physically located, including but not limited to
BP A, have experienced no adverse reliability impact due to these arrangements. PacifiCorp
currently dispatches several facilities that are physically remote from the P ACW and PACE
transmission facilities. One example is the Hermiston 480 MW natural gas-fired, combined
cycle plant located near Hermiston, Oregon ("Hermiston Facilty"). The Hermiston Facilty is
physically connected to the BP A transmission system but telemetered into (integrated with or
"moved" to) PacifiCorp's PACW balancing authority area in the same manner as PacifiCorp
plans to telemeter the Chehalis Facility into PACW. Specifically, all of the Hermiston Facilty's
output is scheduled across BP A transmission facilities to the P ACW balancing authority area.
Similarly, PacifiCorp's 380 MW coal-fired Cholla unit no. 4 ("Cholla Facility") in Arizona is
located remote from the rest of the PACE balancing authority area but is telemetered into PACE.
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12. The Chehalis Facilty has been dispatched at PacifiCorp's request beginning
.March 1, 2008 pursuant to a call option agreement that will expire upon closing of the
acquisition of Chehalis by PacifiCorp.
13. PacifiCorp curently utilzes, as par of the call option agreement, 100 MW of.firm transmission rights on BPA's transmission system from the Chehalis Facilty to the
Troutdale 230 kV bus, which is an interface between the BPA and PACW balancing authority
.areas. Each day, PacifiCorp routinely schedules up to 100 MW of the Chehalis Facilty's output
to the Troutdale 230 kV bus. Additionally, as par of the call option agreement, PacifiCorp
utilzes 250 MW of firm transmission rights, which will increase to 500 MW on November 1,
.2008, on BPA's transmission system from the Chehalis Facilty to the Columbia 230 kV bus,
which is located in the BPA balancing authority area. Significantly, however, PacifiCorp
.routinely requests and receives a firm redirect of the Columbia 230 kV bus point of delivery to
either Mid-Columbia2 or points of delivery within the PACW balancing authority area. Mid-
Columbia is an interface between the BPA and PACW balancing authority areas. Therefore,
.PacifiCorp can routinely schedule up to 250 MW before November 1, 2008, and 500 MW after
that date, from the Chehalis Facilty to Mid-Columbia to make sales to other paries or directly to
points of delivery in the P ACW balancing authority area to meet its load obligation..14.Upon closing of the acquisition, PacifiCorp will integrate the Chehalis Facility
into its system by accepting assignment, as par of the asset purchase, of 100 MW of firm
transmission rights on BPA's transmission system from the Chehalis Facility to the Troutdale.
230 kV bus which, as noted, is an interface between the BPA and PACW balancing authority
.2 "Mid-Columbia" referencéd in this affdavit is described as "Mid-Columbia" on PacifiCorp's Open Access Same-
time lnfonnation System and is described as "Mid-Columbia Remote" on BPA's Open Access Same-time
Infonnation System.
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areas. Similar to what it does now, as I described above, each day, PacifiCorp wil schedule up
to 100 MW of the plant output to Troutdale 230 kV, using these firm transmission rights on the
BPA system. Additionally, as part of the acquisition, PacifiCorpwil accept assignment of an
additional 250 MW of firm transmission rights, which wil increase to 500 MW on November 1,
2008, on BPA's transmission system from the Chehalis Facility to the Columbia 230 kV bus.
15. PacifiCorp plans to use transmission rights from the Chehalis Facilty to the
Columbia 230 kV bus as par of the integration of the Chehalis Facilty into the PACW balancing
authority area. PacifiCorp plans to submit a long-term firm redirect request to BPA upon closing
of the acquisition. Such request will give PacifiCorp a firm redirect of the Columbia 230 kV
point of delivery to Mid-Columbia. This redirection will allow PacifiCorp to make sales at the
liquid Mid-Columbia market sourced from the Chehalis Facilty. It will also give PacifiCorp the
abilty to use the plant output to serve PacifiCorp's loads by scheduling the power from the
Chehalis Facilty to Mid-Columbia and then from Mid-Columbia to varous points of delivery in
the P ACW balancing authority area. The schedules from Mid-Columbia to P ACW would rely
on PacifiCorp's existing transmission rights.
16. As an alternative to serving PacifiCorp loads utilzing PacifiCorp's firm
transmission rights from Mid-Columbia to varous points of delivery within the P ACW
balancing authority area, PacifiCorp may request from BPA short-term redirects of the Mid-
Columbia point of delivery to other points of delivery within P ACW balancing authority area.
17. The 100 MW transmission right from the Chehalis Facility to the Troutdale 230
kV bus is firm. The 500 MW transmission right from the Chehalis Facilty to BPA's Columbia
230 kV Substation is firm, and after the long-term firm redirect request PacifiCorp plans to make
to BPA, the 500 MW transmission right to Mid-Columbia is anticipated to be firm. PacifiCorp
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anticipates BPA wil grant this long-term firm redirect based on BPA's business practice
specifying the calculation of available transfer capability ("A TC") impacts of long-term firm
redirects using a single network composite point of delivery for all points of delivery within the
BP A network. This A TC calculation method ensures a long-term firm redirect from one point of
delivery to another point of delivery on the BP A network. PacifiCorp' s curently-existing
transmission rights from Mid-Columbia to the various points of delivery in the P ACW balancing
authority area are also firm. The potential short-term redirect from Mid-Columbia to varous
points of delivery in the PACW balancing authority area may be firm, depending on BPA's
analysis ofPacifiCorp's request.
18. Scheduling power from the Chehalis Facility to either Mid-Columbia or points of
delivery within the P ACW balancing authority area after the acquisition takes place wil have no
material or adverse impact on reliabilty. The output of the Chehalis Facilty will continue to be
scheduled from the Chehalis Facility to either Mid-Columbia or points of delivery with the
PACW balancing authority area after closing of the acquisition in the same manner as it is being
scheduled under the curent call option agreement.
19. The scheduling process described above is the same process whether the Chehalis
Facilty is integrated into the PACW balancing authority area or remains as par of the BPA
balancing authority area. PacifiCorp will create the electronic tags in either case to schedule the
plant output and it wil specify the source balancing authority area as either P ACW orBP A,
depending on the electrical location of the Chehalis Facility.
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This concludes my affdavit.
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AFFIDAVIT.
County of Multnomah
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State of Oregon
.John A. Apperson, being duly sworn, deposes and states that he prepared or oversaw the
preparation of the Affidavit of John A. Apperson On BehalfOfPacifiCorp, and that the
statements contained therein are true and correct to the best of his knowledge and belief..
~;( A~ ~-=
John A. A~son.
SUBSCRIBED AND SWORN TO BEFORE ME, this the 25th day of April, 2008.
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OFFICIAl SEAL
TERRICA M REY
NOTARY PUBl~. OREGO
COMMISSIN NO. 419127
MY COMMISSION EXPIRES AUGUS 26. 2011
-(;~~iC
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My Commission Expires ~ 26, lot I
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ATTACHMENT 3
PROPOSED ACCOUNTING ENTRIES
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.Journal Entr)
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Proposed Journal Entries
Account Description Debits Credits
1) 186 Miscellaneous deferred debits (xxx,xxx,xxxJ131 Cash (xxx,xxx,xxxJ
To record the initial exclusivity deposit as part of the cost of acquisition in accordance with CFR
18, Part 101, Balance Sheet Accounts, 186.
2)186
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Miscellaneous deferred debits
Cash
(xxx,xxx,xxx J
(xxx,xxx,xxx J
To record external, incremental, direct costs of acquisition in accordance with CFR 18, Part 101,
Electric Plant Instructions, 5A and Balance Sheet Accounts, 186
3)123. I
186
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Investment in subsidiary companies
Miscellaneous deferred debits
Cash
(xxx,xxx,xxx J
(xxx,xxx,xxx J
(xxx,xxx,xxxJ
To record the purchase of Chehalis Power Generating, LLC in accordance with CFR 18, Part 101.
Balance Sheet Accounts, 123.1. (Includes the purchase price adjustments for working capital and
CSA and clears amounts booked above in account 186)
4)102 Electric plant purchased or sold (xxx,xxx,xxx)13 I Cash (xxx,xxx,xxx)142 Accounts receivable (xxx,xxx,xxxJ
154 Materials and supplies inventory (xxx,xxx,xxxJ
151 Fuel inventory (xxx,xxx,xxxJ165 Prepaid assets (xxx,xxx,xxx)232 Accounts payable (xxx,xxx,xxxJ236 Taxes accrued (xxx.xxx,xxxJ
230 Asset retirement obligations (xxx.xxx,xxx)
123.1 Investment in subsidiary companies (xxx,xxx,xxxJ
To record the dissolution of Chehalis Power Generating, LLC and the allocation of the purchase
price to assets and liabilities acquired in accordance with CFR 18, Part 101, Electric Plant
Instructions, 5A.
5)101 Utility plant (xxx,xxx,xxxJ102 Electric plant purchased or sold (xxx,xxx,xxxJ
To record PacifCorp's acquisition cost of the Chehalis facility in acco.rdance with CFR 18, Part
101, Electric Plant Instructions, 5B (/).
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.ATTACHMENT 4
VERIFICATIONS
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.UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
.PacifCorp
TNA Merchant Projects, Inc.
Chehalis Power Generating, LLC
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Docket No. EC08-_-000
VERIFICATION
.Stefan A. Bird, Senior Vice President, Commercial and Trading, PacifiCorp, being duly
sworn, deposes and states that he is a representative legally authonzed to bind PacifiCorp, that he
has read the attached Joint Application for Commission Approval under Section 203 of the
Federal Power Act, that he knows the contents thereof and that the statements therein are true
and correct to the best of his knowledge, information and be .
te Bir
Senior Vice President, Commercial and Trading
PacifiCorp
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Subscribed and sworn to before me ::~f ~
(Y ary PublicOFFICIA SEA
TERRICA M REYESNOTARYPUBUC-OREGON My commission expires:
COMMISSION NO. 419127
MY COMMISSION ~~~~~~ AUGUST 26,2011 l4 ~ Z' / 20/1
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UNTED STATES OF AMRICA
BEFORE THE
FEDERA ENERGY REGULATORY COMMSSION.
PacifiCorp
TNA Merchant Projects, Inc.
Chehalis Power Generating, LLC
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Docket No. EC08-_-000
.VERIICATION
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Rachel W. Kilpatrck, being duly sworn, deposes and states that she is a representative
legally authorized to bind lNA Merchant Projects, Inc., that sh~ has read the attched Joint
Application for Commssion Approval under Section 203 of the Federal Power Act, th she
knows the contents thereof, and that the statements therein regaring lNA Merchant Projects,
Inc. and Chehalis Power Generating, LLC are tre and correct to the best of her knowledge,
inormation and belief.
.~/úJ~Rachel W. Kilpatrck . V
Vice President
lNA Merchant Projects, Inc. and
Chehalis Power Generatig, LLC
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.Subscnbed and sworn to before me ths J5 day of ApriI2008.
~-lì,h.No ublic Q.~o~
.My commssion expires: 5" J i 1 J2- 0 I)
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ELIZABETH D. ROGERS
Notary Public
STATE OF TEXAS
My Comm. Exp. May 11, 2011
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ATTACHMENT 5
PROTECTIVE ORDER
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
PacifiCorp
TNA Merchant Projects, Inc.
Chehalis Power Generating, LLC
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Docket No. EC08- -000
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PROTECTIVE ORDER
(Issued )
.This Protective Order shall govern the use of all Protected Materials produced by, or on
behalf of, any Participant. Notwithstanding any order terminating this proceeding, this Protective
Order shall remain in effect until specifically modified or terminated by the Presiding
Administrative Law Judge ("Presiding Judge") or the Federal Energy Regulatory Commission
("Commission")..This Protective Order applies to the following two categories of materials: (A) A
Participant may designate as protected those materials which customarily are treated by that
Participant as sensitive or proprietary, which are not available to the public, andwhich, if
disclosed freely, would subject that Participant or its customers to risk of competitive
disadvantage or other business injury; and (B) A Participant shall designate as protected those
materials which contain critical energy infrastructure information, as defined in 18 C.F .R. §
388.113(c)(l) ("Critical Energy Infrastructure Infonnation").
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Definitions. For puroses of this Order:
.The term "Participant" shall mean a Participant as defined in 1 8 C.F.R. §
385.102(b).
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(1) The term "Protected Materials" means (A) materials (including
depositions) provided by a Participant in response to discovery requests and designated by such
Participant as protected; (B) any information contained in or obtained from such designated
materials; (C) any other materials which are made subject to this Protective Order by the
Presiding Judge, by the Commission, by any court or other body having appropriate authority, or
by agreement ofthe Participants; (D) notes of Protected Materials; and (E) copies of Protected
Materials. The Participant producing the Protected Materials shall physically mark them on each
page as "PROTECTED MATERIALS" or with words of similar import as long as the term
"Protected Materials" is included in that designation to indicate that they are Protected Materials.
If the Protected Materials contain Critical Energy Infrastructure Information, the Participant
producing such information shall additionally mark on each page containing such information
the words "Contains Critical Energy Infrastructure Information - Do Not Release."
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.The term "Notes of Protected Materials" means memoranda, handwritten notes, or any other
form of information (including electronic form) which copies or discloses materials described in
Paragraph 5. Notes of Protected Materials are subject to the
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same restrictions provided in this order for Protected Materials except as specifically provided in
this order..(3) Protected Materials shall not include (A) any information or
document contained in the fies of the Commission, or any other federal or state agency, or any
federal or state court, unless the information or document has been determined to be protected by
such agency or court, or (B) information that is public knowledge, or which becomes public
knowledge, other than through disclosure in violation of this Protective Order, or (C) any
information or document labeled as "Non-Internet Public" by a Participant, in accordance with
Paragraph 30 of FERC Order No. 630, FERC Stats. & Regs. ~ 31,140. Protected Materials do
include any information or document contained in the fies of the Commission that has been
designated as Critical Energy Infrastructure Information.
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.(c) The term "Non-Disclosure Certificate" shall mean the certificate anexed
hereto by which Participants who have been granted access to Protected Materials shall certify
their understanding that such access to Protected Materials is provided pursuant to the terms and
restrictions of this Protective Order, and that such Participants have read the Protective Order
and agree to be bound by it. All Non-Disclosure Certificates shall be served on all paries on the
official service list maintained by the Secretary in this proceeding..
(d) The term "Reviewing Representative" shall mean a person who has signed
a Non-Disclosure Certificate and who is:
(1) Commission Trial Staff designated as such in this proceeding;.
(2) an attorney who has made an appearance in this proceeding for a
Paricipant;
.(3) , attorneys, paralegals, and other employees associated for purposes
of this case with an attorney described in Subparagraph (2);
(4) an expert or an employee of an expert retained by a Participant for
the purpose of advising, preparing for or testifying in this proceeding;
.(5) a person designated as a Reviewing Representative by order of the
Presiding Judge or the Commission; or
(6) employees or other representatives of Participants appearing in this
proceeding with significant responsibility for this docket.
.4. Protected Materials shall be made available under the terms of this Protective
Order only to Participants and only through their Reviewing Representatives as provided in
Paragraphs 7-9.
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5. Protected Materials sp-all remain available to Participants until the later of the date
that an order terminating this proceeding becomes no longer subject to judicial review, or the
date that any other Commission proceeding relating to the Protected Material is concluded and
no longer subject to judicial review. If requested to do so in writing after that date, the
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Participants shall, within fifteen (15) days of such request, return the Protected Materials
(excluding Notes of Protected Materials) to the Participant that produced them, or shall destroy
the materials, except that copies of fiings, official transcripts and exhibits in this proceeding that
contain Protected Materials, and Notes of Protected Material may be retained, if they are
maintained in accordance with Paragraph 6, below. Within such time period each Participant, if
requested to do so, shall also submit to the producing Paricipant an affidavit stating that, to the
best of its knowledge, all Protected Materials and all Notes of Protected Materials have been
retured or have been destroyed or wil be maintained in accordance with Paragraph 6. To the
extent Protected Materials are not returned or destroyed, they shall remain subject to the
Protective Order.
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6. All Protected Materials shall be maintained by the Participant in a secure place.
Access to those materials shall be limited to those Reviewing Representatives specifically
authorized pursuant to Paragraphs 8-9. The Secretary shall place any Protected Materials filed
with the Commission in a non-public fie. By placing such documents in a non-public fie, the
Commission is not making a determination of any claim of privilege. The Commission retains
the right to make determinations regarding any claim of privilege and the discretion to release
information necessar to cary out its jurisdictional responsibilties. For documents submitted to
Commission Trial Staff ("Staff'), Staff shall follow the notification procedures of 18 C.F.R. §
388.112 before making public any Protected Materials..
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7. Protected Materials shall be treated as confidential by each Paricipant and by the
Reviewing Representative in accordance with the certificate executed pursuant to Paragraph 9.
Protected Materials shall not be used except as necessar for the conduct of this proceeding, nor
shall they be disclosed in any maner to any person except a Reviewing Representative who is
engaged in the conduct of this proceeding and who needs to know the information in order to
car out that person's responsibilties in this proceeding. Reviewing Representatives may make
copies of Protected Materials, but such copies become Protected Materials. Reviewing
Representatives may make notes of Protected Materials, which shall be treated as Notes of
Protected Materials if they disclose the contents of Protected Materials..
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8. (a) If a Reviewing Representative's scope of employment includes the
marketing of energy, the direct supervision of any employee or employees whose duties include
the marketing of energy, the provision of consulting services to any person whose duties include
the marketing of energy, or the direct supervision of any employee or employees whose duties
include the marketing of energy, such Reviewing Representative may not use information
contained in any Protected Materials obtained through this proceeding to give any Participant or
any competitor of any Participant a commercial advantage.
.(b) In the event that a Participant wishes to designate as a Reviewing
Representative a person not described in Paragraph 3( d) above, the Participant shall seek
agreement from the Participant providing the Protected Materials. If an agreement is reached that
person shall be a Reviewing Representative pursuant to Paragraphs 3( d) above with respect to
those materials. If no agreement is reached, the Participant shall submit the disputed designation
to the Presiding Judge for resolution..
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9. (a) A Reviewing Representative shall not be permitted to inspect, participate
in discussions regarding, or otherwise be permitted access to Protected Materials pursuant to this
Protective Order unless that Reviewing Representative has first executed a Non-Disclosure
Certificate; provided, that if an attorney qualified as a Reviewing Representative has executed
such a certificate, the paralegals, secretarial and clerical personnel under the attorney's
instruction, supervision or control need not do so. A copy of each Non-Disclosure Certificate
shall be provided to counsel for the Paricipant asserting confidentiality prior to disclosure of any
Protected Material to that Reviewing Representative..
(b) Attorneys qualified as Reviewing Representatives are responsible for
ensuring that persons under their supervision or control comply with this order.
.i O. Any Reviewing Representative may disclose Protected Materials to any other
Reviewing Representative as long as the disclosing Reviewing Representative and the receiving
Reviewing Representative both have executed a Non-Disclosure Certificate. In the event that any
Reviewing Representative to whom the Protected Materials are disclosed ceases to be engaged in
these proceedings, or is employed or retained for a position whose occupant is not qualified to be
a Reviewing Representative under Paragraph 3( d), access to Protected Materials by that person
shall be terminated. Even if no longer engaged in this proceeding, every person who has
executed a Non-Disclosure Certificate shall continue to be bound by the provisions of this
Protective Order and the certification.
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11. Subject to Paragraph 17, the Commission shall resolve any disputes arising under
this Protective Order. Prior to presenting any dispute under this Protective Order to the
Commission, the paries to the dispute shall use their best efforts to resolve it. Any participant
that contests the designation of materials as protected shall notify the party that provided the
protected materials by specifying in writing the materials the designation of which is contested.
This Protective Order shall automatically cease to apply to such materials five (5) business days
after the notification is made unless the designator, within said five (5)-day period, files a motion
with the Commission, with supporting affidavits, demonstrating that the materials should
continue to be protected. In any challenge to the designation of materials as protected, the burden
of proof shall be on the participant seeking protection. If the Commission finds that the materials
at issue are not entitled to protection, the procedures of Paragraph 17 shall apply. The procedures
described above shall not apply to protected materials designated by a Participant as Critical
Energy Infrastructure Information. Materials so designated shall remain protected and subject to
the provisions ofthis Protective Order, unless a Participant requests and obtains a determination
from the Commission's Critical Energy Infrastructure Information Coordinator that such
materials need not remain protected.
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12. All copies of all documents reflecting Protected Materials, including the portion
of the hearing testimony, exhibits, transcripts, briefs and other documents which refer to
Protected Materials, shall be fied and served in sealed envelopes or other appropriate containers
endorsed to the effect that they are sealed pursuant to this Protective Order. Such documents
shall be marked "PROTECTED MATERIALS" and shall be fied under seal and served under
seal upon the Commission and all Reviewing Representatives who are on the service list. Such
documents containing Critical Energy Infrastructure Information shall be additionally marked
"Contains Critical Energy Infrastructure Information B Do Not Release." For anything fied
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under seal, redacted versions or, where an entire document is protected, a letter indicating such.
wil also be fied with the Commission and served on all parties on the service list and the
Presiding Judge. Counsel for the producing Paricipant shall provide to all Paricipants who
request the same, a list of Reviewing Representatives who are entitled to receive such materiaL.
Counsel shall take all reasonable precautions necessar to assure that Protected Materials are not
distributed to unauthorized persons.
.13. If any Paricipant desires to include, utilize or refer to any Protected Materials or
information derived therefrom in testimony or exhibits during the hearing in these proceedings in
such a maner that might require disclosure of such material to persons other than reviewing
representatives, such participant shall first notify both counsel for the disclosing paricipant and
the Commission of such desire, identifying with particularity each of the Protected Materials.
Thereafter, use of such Protected Material wil be governed by procedures determined by the
Commission..
14. Nothing in this Protective Order shall be constred as precluding any Participant
from objecting to the use of Protected Materials on any legal grounds.
.15. Nothing in this Protective Order shall preclude any Paricipant from requesting
the Presiding Judge, the Commission, or any other body having appropriate authority, to find that
this Protective Order should not apply to all or any materials previously designated as Protected
Materials pursuant to this Protective Order. The Commission may alter or amend this Protective
Order as circumstances warant at any time during the course of this proceeding.
.16. Each party governed by this Protective Order has the right to seek changes in it as
appropriate from the Presiding Judge or the Commission.
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17. All Protected Materials fied with the Commission, the Presiding Judge, or any
other judicial or administrative body, in support of, or as a part of, a motion, other pleading,
brief, or other document, shall be fied and served in sealed envelopes or other appropriate
containers bearing prominent markings indicating that the contents include Protected Materials
subject to this Protective Order. Such documents containing Critical Energy Infrastructure
Information shall be additionally marked "Contains Critical Energy Infrastructure Information -
Do Not Release.".
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18. Ifthe Commission finds at any time in the course of this proceeding that all or
par of the Protected Materials need not be protected, those materials shall, nevertheless, be
subject to the protection afforded by this Protective Order for three (3) business days from the
date of issuance of the Commission's determination, and if the Participant seeking protection
fies an interlocutory appeal or requests that the issue be certified to the Commission, for an
additional seven (7) business days. None of the Participants waives its rights to seek additional
administrative or judicial remedies after the Commission's decision respecting Protected
Materials or Reviewing Representatives, or the Commission's denial of any appeal thereof. The
provisions of 18 C.F.R. §§ 388.112 and 388.113 shall apply to any requests under the Freedom
ofInformation Act. (5 U.S.C. § 552) for Protected Materials in the fies of the Commission..
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19. Nothing in this Protective Order shall be deemed to preclude any Participant from
independently seeking through discovery in any other administrative or judicial proceeding
information or materials produced in this proceeding under this Protective Order.
20. None of the Participants waives the right to pursue any other legal or equitable
remedies that may be available in the event of actual or anticipated disclosure of Protected
Materials.
.21. The contents of Protected Materials or any other form of information that copies
or discloses Protected Materials shall not be disclosed to anyone other than in accordance with
this Protective Order and shall be used only in connection with this proceeding. Any violation of
this Protective Order and of any Non-Disclosure Certificate executed hereunder shall constitute a
violation of an order of the Commission..
Kimberly D. Bose, Secretar.
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
PacifiCorp
TNA Merchant Projects, Inc.
Chehalis Power Generating, LLC
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Docket No. EC08- -000
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NON-DISCLOSURE CERTIFICATE
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I hereby certify my understanding that access to Protected Materials is provided to me
pursuant to the terms and restrictions of the Protective Order in this proceeding, that I have been
given a copy of and have read the Protective Order, and that I agree to be bound by it. I
understand that the contents of the Protected Materials, any notes or other memoranda, or any
other form of information that copies or discloses Protected Materials shall not be disclosed to
anyone other than in accordance with that Protective Order. I acknowledge that a violation of this
certificate constitutes a violation of an order of the Federal Energy Regulatory Commission..
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By:
Title:
Representing:
Date:
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.DC 388083. 52261 000 4/25/2008 08:29am
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ATTACHMENT 6
AFFIDAVIT OF THOMAS N. TJOELKER
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.UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
.Berkshire Hathaway Inc.
MidAmerican Energy Holdings Company
PPW Holdings LLC
PacifiCorp
SUEZ, S.A.
TNA Merchant Projects, Inc.
Chehalis power Generating, LLC
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Docket No. EC08-_ -000
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AFFIDAVIT OF THOMAS N. T JOELKER
ON BEHALF OF PACIFICORP
REGARDING SIMULTANEOUS IMPORT LIMIT FOR
PACIFICORP-WEST CONTROL AREA
1.My name is Thomas N. Tjoelker. My business address is 825 NE Multnomah
Suite 1800, Portland,' OR 97232.
.2.I am a degreed electrical engineer with a Bachelor of Science in Electrcal
Engineering from Washington State University. I have 27 years of engineering experience with
PacifiCoip..3.I am presently the Manager of Transmission Planing for PacifiCoip. In this
position, my responsibilties include the coordination of planing studies associated with
transmission service and generator interconnection requests and performing planing and.operating studies which are used to determine trasfer limits and the need for future facilities.
4. The purpose of this affidavit is to provide a description of, and support for the
Simultaneous Import Limits ("SILs") for the PacifiCorp-West ("PACW") control area provided.
as inputs to Mr. Rodney Frame's Delivered Price Test ("OPT") analysis related to its proposed
acquisition of Chehalis Power Generating, LLC and the simultaneous merger of Chehalis Power
.Generating, LLC into PacifiCorp.
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5. The specific SIL values used as inputs in Mr. Frame's DPT analysis for PACW.
are detailed below. I have reached this determination based on methods compliant with
Appendix E of the Federal Energy Regulatory Commission's Order on Rehearing and Modifing
Interim Generation Market Power Analysis issued April 14, 2004 ("Appendix E"). AEP Power
Mktg., Inc., 107 FERC ~ 61,108 (2004). The studies used to determine these SIL values are
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based on peak seasonal loadings. PacifiCorp's system peaks in winter and summer.
.6.Based on my review of relevant information, I have determined that the P ACW
SIL values are as follows.
.PERIOD PACWSIL
Winter (January i though April 30, 2009)4111 MW
Summer (May i though September 30, 2009)3805 MW
Winter (October 1 through December 31, 2009)4111 MW
.This concludes my affdavit.
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AFFIDAVIT.
County of Multnomah
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State of Oregon
.Thomas N. Tjoelker, being duly sworn, deposes and states that he prepared or oversaw
the preparation of the Affidavit of Thomas N. Tjoelker on Behalf ofPacifiCorp, and that the
statements contained therein are true and correct to the best of his knowledge and belief..
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SUBSCRIBED AND SWORN BEFORE ME, this the llø +Aday of April, 2008
. OFFICIAL SEA
. A8IGJ\IL A BAY
. \. .. NOTArlY PUBUC-QREGON
'.. COMMISSiÜN NO. 411829
MY COMIV~SSION EXIRES NOV. 13, 2010
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