20060606Exhibit G.pdf

--------.-.,..,-""....-....,.--,,---
Page 1 of 160
10-1 plOk.htm PACIFICORPIOK03312006 ~c-E -06-07 EXHIBIT G
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washlngtan, D.C. 20549
FORM lO-
(Mark One)
... -
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHA~GE ACT OF1934
For the fiscal year ended March 31, 2006
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ;(CT
OF 1934
For the transition period from
Commission File Number 1-5152
ACIFICORP
(Exact name of registrant as specified in its charter)
State of Oregon
(State or other jurisdiction
of incorporation or organization)
93-0246090
(I.S. Employer Identification No.
825 N .E. Multnomah Street, Portland, Oregon
(Address of principal executive offices)
97232
(Zip Code)
[phone]
(Registrant's telephone number)
Securities registered pursuant to Section 12(g) of the Act:
Title of each Class
5% Preferred Stock (Cumulative; $100 Stated Value)
Serial Preferred Stock (Cumulative; $100 Stated Value)
No Par Serial Preferred Stock (Cumulative; $100 Stated Value)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Sec\lTities Act.
Yes No lID
Indicate by check mark if the registrant is not required to file reports pursuant 10 Section 13 or Section I5( d) of the Exchange
Act.
Yes No I2iI
Indicate by check mark whether the Registrant (1) has filed aU reports required to be filed by Section 13 or 15(d) orthe
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required
to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes 1&:1 NoD
http://www.sec.gov/Archives/edgar/datal75594/000007 5 59406000028/p 1 Ok.htm 5/31/06
....-,----..........---"..,--,-....-.-..--...,...,..--..,..,-.,---
Page 2 of 160
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and
wiu not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by
reference in Part 111 of this Form lOoK or any amendment to this Form IO-K. (&l
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See
definition of "accelerated filer and large accelerated filer" in Rule 12b-2 oftbe Exchange Act).
Large accelerated filer Accelerated filer Non-accelerated filer(&l
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 ofthe Exchange Act).
Yes No (&l
Class Oulstandlng all'llay 19, 2006
Common Stock, no par value 357,060 915 shares
All shares of outstanding common stock are indirectly owned by MidAmericnn Energy Holdings Company, 666 Grand
Avenue, Des Moines, Iowa.
DOCUMENTS INCORPORATED BY REFERENCE
None.
http://www .see.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htrn 5/31/06
!!!llilr~l!m!ml:
Pt:Jjl1iH~m~
Part I
!!~n...L
Page 3 of 160
TABLE OF CONTENTS
!!~.
~ill~~~
J !~m gi~k_f.!!!;!.m~
.A~,
I ! 1;.111 m '!)J1~"!;ji91~!;_Q.IDaf(i:.9-'!!!II~-'-TI~
I!~!n.4."
cln
H~m:!.
Part II
J1~nLi.
1!~I11..
H~mI,
PI.Q11~ni9~
L..q lli!l.e.rm:.~!illi!!g~
~.\!~J:n!~!!i.9J.LQLr~ta.!l\:.rs to a V otc oLSecJ.!!ib'-U91~I~r~
arkcLf..QLRe U..nL1i CQ.mmQ1Lg~lUiJx..J~_~Lq1!;:1L~\m:.l1()lder Maucrs -Uu.!..h5!lcr r.lrc!.l.\l..s~$.....Q..r
E!1~lily SecuriJj~.ft
Sd~~9..fJnaJ!g!l.lQ!!ti!
lli!g.cment's Discussion I!,nd AnaJysis...9f Fi!!Q.nC!fll..C:i!11.~!.i!ion and Results of Oper!lliolls
Quantitative amLQY.!!lita!h.'P'!~cloJill!~ AQ ar~eJJil'L~Item
JJ"mJi,Ei,!!.!!!!.~i~L~J!ltem~nls nnd S4QP.klTI.~ill!.!,1;X Oal,\
!It;.m_Q, ~lmng!;~ in and..Di:i~gr!;~m~!J.!;L~.tlLA.~!;Q.\!m9I!~1.9"L~I!~.!m!1ti.!1~.!llLE-'.!m.!!~i;!lQi~IjQ~l!-..LI;,
Item .:oU!tqg;..nndl'..wccdnrc!!28.
U~.m.2.Et 9J!1~I.ln.nnatiQJ!
Part lIt
Itcm J.Q,
It~m,
It!;ln...lb
!!.em.
H~mJ.4-"
Part IV
HL! ~,
~.ig!1atHrt;5
pjr.~!;.tQJ~J!.!!!!.f..~t;.I;.mi.Ofjjc~rs o(!b~_R.tegL'!wwt
J;!'\.~!!!h:~tc:.9 !nR~IISn 1 ion
~e1J.rj.!J'. O\'yn~r~hin-9f (;~1!!!i!1_H~_!!~lifi~l O\~l!:r_~jl11tl~'\;mqg~m,
!!.
!Jt t!Jl~U~.j:J.ill.~_Stocls.!wld
Matt~
~~r.!.!!!).LRCiI!!!iQn~l!il2ij- and Rt;l;1,
~~~.
.Tm!l~J1.~!iQn~
PJ:inciPJtLA~counti!!g Fe~s
!:!!!g..
~I~L!;.~,
!~:-,;hilil!~-, ,.fJ!Ja.!1~ji!L~J!!. !~!n~ ~U - ~ c! !~f!U!~~
f;IJt~
104
105
106
107
110
http://www.see.goy/ Archives/edgar/data/75594/000007 559406000028/p 1 Ok.htm 5/31/06
"'--"----"'.'-
Page 4 of160
DEFINITIONS
I.!!.!m
When the following terms are used in the text, they witl have the meanings indicated:
M~nl1
CPUC
FERC
IPUC
KWh
MEHC
1vlWh
OPUC
PacifiCorp
PHI
PPW Holdings LLC
ScottishPower
SEC
SFAS
UPSC
WPSC
WUTC
California Public Utilities Commission
Federal Energy Regulatory Commission
Idaho Public Utilities Commission
Kilowatt-hour(s), one kilowatt continuously for one hour
MidAmerican Energy Holdings Company, an Iowa corporation and indirect parent company of
PacifiCorp
Megawatt
Megawatt-hour(s), one megawatt continuously for one hour
Oregon Public Utility Commission
PacifiCorp, an Oregon corporation and direct, wholly owned subsidiary ofPPW Holdings LLC
PacifiCorp Holdings, Inc., a Delaware corporation and non-operating United States holding
company and the former direct parent company ofPacifiCorp
PPW Holdings LLC, the direct parent company of PacifiCorp
Scottish Power pIc, the fonner ultimate, indirect parent company of PHI and PacifiCorp
Securities and Exchange Commission
Statement of Financial Accounting Standards
Utah Public Service Commission
Wyoming ~ub1ic Service Commission
Washington Utilities and Transportation Commission
http://www .see.goYI Archiyes/edgar/data/75594/000007559406000028/pl Ok.htm 5/31/06
Page 5 of 160
PARTl
ITEM 1. BUSINESS
OVERVIEW
Ownership by MEHC; Sale of PacifiCorp
On March 21, 2006, MidAmerican Energy Holdings Company ("MEHC") completed its purchase of all ofPacifiCorp
outstanding common stock from PacifiCorp Holdings, Inc. ("PHl"), a subsidiary of Scottish Power pIc ("ScottishPower
pursuant to the Stock Purchase Agreement among MEHC, ScottishPower and PHI dated May 23, 2005, as amended on
March 21, 2006 (the "Stock Purchase Agreement"). The cash purchase price was $5.1 billion. PacifiCorp s common stock
was directly acquired by a subsidiary of MEHC, PPW Holdings LLC. As a result of this transaction, MEHC controls the
significant majority ofPacifiCorp s voting securities, which include both common and preferred stock. MEHC, a global
energy company based in Des Moines, Iowa, is a majority-owned subsidiary of Berkshire Hathaway Inc. ("Berkshire
Hathaway ). AU descripth:ms of the terms of the Stock Purchase Agreement contained in this Annual Report are modified in
their entirety by reference to the terms of such agreement, which is included as an exhibit hereto.
Operations
PacifiCorp is a regulated electricity company serving retail customers in portions of the states of Utah, Oregon, Wyoming,
Washington, Idaho and California. As a vertically integrated electric utility, PacifiCorp owns or has contracts for fuel sources
such as coal and natural gas and uses these fuel sources, as well as wind, geothermal and water resources, to generate
electricity at its power plants. This electricity, together with electricity purchased on the wholesale market, is then transmitted
via a grid of transmission lines throughout PacifiCorp s six-state region. The electricity is then transformed to lower voltages
and delivered to customers through PacifiCorp s distribution system. PacifiCorp sells electricity primarily in the retail
market, with sates to residential, commercial and industrial customers. PacifiCorp also sells electricity in tbe wholesale
market in cOimection with excess electricity generation or balancing activities. Subsidiaries ofPacifiCorp support its electric
utility operations by providing coal mining and other fuel-related services, as well as environmental remediation.
PacifiCorp s goal is to provide safe, reliable, low-cost electricity to its customers, with fair and increasing earnings to its
common shareholder. PacifiCorp expects that costs prudently incurred to provide service to its customers will be included as
allowable costs for slate rate-making purposes.
Following the closing ofPacifiCorp s sale, MEHC annOlmced a new organizational struclure under the direction of a newly
appointed chairnlan and chief executive officer, who oversees the company s entire operations. The PacifiCorp Energy
operational unit is responsible for PacifiCorp s electric generation, commercial and energy trading, and coal-mining
functions. The Pacific Power operational unit is responsib1e for delivering electricity to customers in Oregon, Washington
and California. The Rocky Mountain Power operational unit is responsible for delivering electricity to customers in Utah,
Wyoming and Idaho.
Regulation
PacifiCorp is subject to comprehensive regulation by the Federal Energy Regulatory Commission (the "FERC"), the Utah
Public Service Commission (the "UPSC"), the Oregon Public Utility Commission (the "OPUC"), the Wyoming Public
Service Commission (the "WPSCn), the Washington Utilities and Transportation Commission (the "WUTC"), Idaho Public
Utility Commission (the "IPUC"), the California Public Utilities Commission (the "CPUC"), and other federal, state and
local regulatory agencies. ll1ese agencies regulate many aspects ofPacifiCorp s business, including customer rates, service
territories, sales of securities, asset acquisitions and sales, accounting policies and practices, wholesale sales and purchases of
electricity, and the operation of its electric generation and transmission facilities.
Employees
On March 31 , 2006, PacifiCorp had 6 750 employees, 58.4% of which were covered by union contracts, principally with the
International Brotherhood of Electrical Workers, the Utility Workers Union of America, International Brotherhood of
Boilemtakers and the United Mine Workers of America.
Location and Information Requests
The location ofPacifiCorp s principal offices is 825 N.E. Multnomah Street, Portland, Oregon 97232. PacifiCorp s website
address is www.pacificorp.com. PacifiCorp makes available free of charge, 011 or through its website, its annual, quarterly
and current reports, and any amendments to those reports, as soon as reasonably practicable after electronically filing such
reports with the United States Securities and Exchange Commission (the "SEC"). Information contained on PacifiCorp
http://www.see.goY/Arehiyes/edgar/data/75594/000007 5 59406000028/p 1 Ok.htm 5/31/06
.....,.....,..,.....-....,.....,-,.,......-..---
Page 6 of 160
website is not part of this report. Reports and other information regarding PacifiCorp that are required to be filed with the
SEC may also be obtained from the SEC's website at www.sec.gov
http://www.see.gov/ Archives/edgar/data/75594/0000075 59406000028/p 1 Ok.htm 5/3 i /06
....-...-.-...--...
Page 7 of 160
POWER AND FUEL SUPPLY
Generating Plants
PacifiCorp owns, or has interests in, the following types of electricity generating plants:
Total
Nameplale Net rlanl
ltallng Capability
Plants (MW)(I\tW)
585.104.4
348.174.
083.159.4
32.32.
050.470.4
Coal
Natural gas and ot1\er
Hydroelectric
Wind
The natural gas and other plants include the Currant Creek Power Plant, which commenced fun combined-cyde operation in
March 2006, adding 523.0 megawatts ("MW") of capability to PacifiCorp s generation portfolio.
The following table shows the estimated percentage ofPacifiCorp s total energy requirements supplied by its generation
plants and through short- and long-term contracts or spot market purchases during the years ended March 31, 2006, 2005 and
2004. See "Wholesale Sales and Purchased Electricity" below for more information.
Years Endetll\hreh )1.
20116 2005 2004
67.5%67.3%67.
78.76.78.1
21.8 23.21.9
100.100.100.
Coal
Natural gas and other
Hydroelectric
Wind
Total energy generated
Purchase and exchange contracts
Total
The share ofPacifiCorp s energy requirements generated by its plants wilt vary from year to year and is detemlilled by
factors such as planned and unplanned outages, availability and price of coal and natural gas, precipitation and snowpack
levels, environmental considerations and the market price of electricity.
Coal
As of March 31, 2006, PacifiCorp had an estimated 248.3 million tons of recoverable coal reserves in mines owned or leased
by it. During the year ended March 31 2006, these mines supplied 32.3% ofPacifiCorp s total coal requirements, compared
to 28.6% during the year ended March 31, 2005 and 30.4% during the year ended March 31 , 2004. TIle remaining coal
requirements are acquired thmugh other long-term and short-term contracts. PacifiCorp-owned mines are located adjacent to
many of its coal-fired generating plants, which significantly reduces overall transportation costs included in fuel expense. For
further information, see "Item 2. Properties.
In an effort to lower costs and obtain better quality coal. the Jim Bridger Mine is in the process of developing an underground
mine to access 57.0 million tons ofPacifiCorp s coal reserves. Underground mine development and limited coal production
began during the year ended March 31, 2005 and sustained operations are expected to begin by March 31, 2007. The life of
the underground mine is expected to be approximately 15 years.
http://www.see.gov/Arehives/edgar/data/75 594/000007 559406000028/p 1 Ok.htm 5/31/06
Page 8 of 160
http://www .see.gov/ Arehives/edgar/datal75594/000007559406000028/p 10k.htm 5/31/06
Page 9 of 160
Natural Gas
PacifiCorp currently utilizes natural gas to fuel four owned and one leased generating plants (composed of 16 generating
units) that, at full capacity, require a maximum of 324 000 MMBtu(million Uritisb thermal units) of natural gas per day.
Additional electric generation resources required by PacifiCorp s Integrated Resource Plans discussed below, including the
Lake Side Power Plant, could increase the natural gas requirement to 415,000 MMBtu per day or morc. PacifiCorp has
entered into transportation contracts to facilitate movement of natural gas to tbe Lake Side Power Plant. These contracts
reflect PacifiCorp s fuel strategy that focuses on the management and mitigation of risks associated with supplying natural
gas.
l1le growth ofPacifiCorp s natural gas requirements requires a prudent, disciplined and wel1~documented approach to natural
gas procurement and hedging. PacifiCorp has developed a natural gas strategy that addresses the need to economically hedge
the commodity risk (physical availability and price), the transportation risk and the storage risk associated with its forecasted
and potentially growing natural gas requirements. This natural gas strategy, combined with the prospect for increasing natural
gas requirements, is expected to increase the volume and types ofPaeifiCorp s procurement and economic hedging activity.
PacifiCorp manages its natural gas supply requirements by entering into forward commitments for physical delivery of
natural gas. PacifiCorp also manages its exposure to increases in natural gas supply costs through forward commitments for
the purchase of physical natural gas at fixed prices and financial swap contracts that settle in cash based on the difference
between a fixed price tllat PacifiCorp pays and a floating market-based price that PacifiCorp receives. As of March 31, 2006,
PacifiCorp had economically hedged 100.0% of its forecasted physical and financial exposure for the remainder of calendar
2006 and had economically hedged 100.0% of its forecasted physical and financial exposure for calendar 2007. For calendar
2008, PacifiCorp currently has hedged 88.0% of its physical exposure and 96.0% of its fmancial exposure. This economic
hedging includes the additional supply requirements arising from the Lake Side Power Plant and the recently constructed
Currant Creek Power Plant.
Hydroelectric
PacifiCorp s hydroelectric portfolio consists of 51 plants with Ii net plant capability of 1 159.4 MW. l1lese plants account for
approximately 14.0% ofPacifiCorp s total generating capacity, helping satisfy a significant portion ofPacifiCorp s reserve
requirements and providing operational benefits such as flexible generation and voltage control. Hydroelectric plants are
located in tile following states: Utah, Oregon, Wyoming, Washington, Idaho, California and Montana.
The amount of electricity PacifiCorp is able to generate from its hydroelectric plants depends on a number of factors,
including snowpack in the mountains upstream of its hydroelectric facilities, reservoir storage, precipitation in its watersheds,
plant availability and restrictions imposed by oversight bodies due to competing water management objectives. When these
factors are favorable, PncifiCorp can generate more electricity using its hydroelectric plants. When these factors are
unfavorable, PacifiCorp must increase its reliance on more expensive thermal plants and purchased electricity.
PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses from t1le FERc. These
licenses are granted by the FERC for periods of30 to 50 years. Several ofPacifiCorp s long-term operating licenses have
expired or will expire in the next few years. Hydroelectric facilities operating under expired licenses may operate under
annual licenses granted by tlle FERC until new operating licenses are issued. Hydroelectric relicensing and the related
environmental compliance requirements are subject to a degree of uncertainty. PacifiCorp expects that future costs relating to
these matters may be significant and consist primarily of additional relicensing costs and capital expenditures. Electricity
generation reductions may also result from additional environmental requirements. At March 31, 2006, PacifiCorp had
incurred $70.3 million in costs for ongoing hydroelectric relicensing, which are included in Construction work-in-progress on
PacifiCorp s Consolidated Balance Sheet. See "Hydroelectric Relicensing" and "Hydroelectric Decommissioning" both
discussed below.
Wind and Other Renewable Resources
PacifiCorp is pursuing renewable power as a viable, economic and environmentally prudent means of generating electricity.
The benefits of renewable energy include low to no emissions and no fossil fuel requirements. Resources such as wind and
http://www.see.gov/Archives/edgar/data/75 5 94/000007 559406000028/p 1 Ok.htm 5/31/06
Page 10 of160
solar arc intermittent, so complementary thermal or hydroelectric resources are important to integrating intermittent
renewable resources into the electric system.
Pat:ifiCorp acquires wind and other renewable power through one PacifiCorp-owned wind farm in Wyoming and various
purchased electricity agreements with wind farms in Oregon and Wyoming. as well as with renewable facilities classified as
qualifying facilities" under the Public Utility Regulatory Policies Act. PacifiCorp also owns a geothermal plant in Utah. For
the year ended March 31, 2006. PacifiCorp received 256 371 MWh from its owned wind farm and geothermal plant. In this
same period. 303, I 58 MWh were purchased from other wind sources. not including qualifying facilities.
To encourage the use of wind energy, PacifiCorp has generation, storage and delivery agreements with various other utilities.
For the year ended March 31, 2006, electricity generated for delivery to customers under these agreements totaled 532 103
MWh in addition to the wind energy generated or purchased for PacifiCorp s own use.
In connection with its sale to MEHC,PacifiCorp has committed to state regulatory commissions that it will bring at least
100.0 MW of cost-effective wind resources in service by March 21, 2007 and, to the extent available, add 400.0 MW
inclusive of the 100.0 MW commitment, of cost-effective renewable resources in PacifiCorp s generation portfolio by
December 31,2007.
Future Generation and Conservation
Integrated Resource Plans
As required by state regulators, PacifiCorp uses Integrated Resource Plans to develop a long-term view of prudent future
actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its
customers. T11e Integrated Resource Plan process identifies the amount and timing ofPacifiCorp s expected future resource
needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts and
other factors. The Integrated Resource Plan is a coordinated effort with stakeholders in each of the six states where
PacifiCorp operates. Each state commission that has Integrated Resource Plan adequacy rules judges whether the Integrated
Resource Plan reasonably meets its standards and guidelines at the time the Integrated Resource Plan is filed. If the Integrated
Resource Plan is found to be adequate, then it is formally "acknowledged." TIle Integrated Resource Plan can then be used as
evidence by parties in rate-making or other regulatory proceedings.
In November 2005, PacifiCorp released an update to its 2004 Integrated Resource Plan. TIle updated 2004 Integrated
Resource Plan identified a need for approximately 2 113.0 MW of additional resources by summer 2014, to be met with a
combination of thermal generation (1 936.0 MW) and load control programs (177.0 MW). PacifiCorp also planned to
implement energy conselVation programs of 450.0 average MW, to continue to seek procurement of 1,400.0 MW of
economic renewable resources and to use wholesale electricity transactions to make up for the remaining difference between
retail load obligations and available resources.
In addition to new generation resources, substantial transmission investments could be required to deliver power to customers
and provide system reliability. The actual investment requirement will depend on the location and other characteristics of the
new generation resources. See "Transmission and Distribution" discussion below.
WHOLESALE SALES AND PURCHASED ELECTRICITY
In addition 10 its portfolio of generating plants, PacifiCorp purchases electricity in the wholesale markets to meet its retail
load obligations, long-term wholesale obligations, and energy and capacity balancing requirements. For the year ended
March 31, 2006, 21.8% of PacifiCorp s energy requirements were supplied by purchased electricity under short- and long-
tern1 purchase arrangements, both as defined by the FERC. PacifiCorp sencrgy requirements supplied by purchased
electricity under short- and long-term purchase arrangements were 23.1% for the year ended March 31, 2005 and 21.9% for
the year ended March 31, 2004.
Many of PacifiCorp 's purchased electricity contracts have fixed-price components, which provide some protection against
price volatility. PacifiCorp enters into wholesale purchase and sale transactions to balance its supply when generation and
relailloads are higher or lower than expected. Generation varies with the levels of outages, hydroelectric generation
conditions and transmission constraints. Retail load varies with the weather, distribution system outages, consumer trends and
the level of economic activity. In addition, PacifiCorp purchases electricity in the wholesale markets when it is more
http://www .sec.govl Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
"....--............"............."".,-"""-,."",..,,,,-'.'""."."""""".'."'"""""""'-"'-"""."-'-.-"-""'.""-"............-........
Page 11 of 160
economical than generating it at its own plants. PacifiCorp may also sell into the wholesale market excess electricity arising
from imbalances between generation and retail load obligations, subject to pricing and transmission constraints.
PacifiCorp s wholesale transactions are integral to its retail business, providing for a balanced and economically hedged
position and enhancing the elTIcient use of its generating capacity over the long term. Historically, PacitiCorp has been able
to purchase electricity from utilities in the western United States for its own requirements. These purchases are conducted
through PacifiCorp and third party transmission systems, which connect with market hubs in the Pacific Northwest to provide
access to normally low-cost hydroelectric generation and in the southwestern United States to provide access to normally
higher-cost fossil-fuel generation. The transmission system is available for common use consistent with open-access
regulatory requirements.
TRANSMISSION AND DISTRIBUTION
Electric transmission systems deliver energy from electric generators to distribution systems for final delivery to customers.
PacifiCorp plans, builds and operates a transmission system. During the year ended March 31, 2006, PacifiCorp delivered
810 861 MWh of electricity to customers in its two control areas through 15,580 miles of transmission lines and its 59 510
mile system of distribution lines. For further detail, see "Item 2. Properties - Transmission and Distribution.
PacifiCorp s transmission system is part of the Western IntercOimection, the regional grid in the west. The Western
Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of
Mexico that make up the Western Electric Coordinating Council. The map under "Service Territories" below shows
PacifiCorp s transmission grid. PacifiCorp s transmission system, together with contractual rights on other transmission
systems, enables PacifiCorp to integrate and access generation resources to meet its customer load requirements. Due to
PacifiCorp s continuing commitment to improve customer service and network safety and to enhance system reliability and
performance, PacifiCorp has focused on infrastructure improvement projects in targeted areas. PacifiCorp and MEHC have
committed to a number of transmission and distribution system investments in connection with regulatory approval of
PacifiCorp s sale to MEHc. For discussion of specific planned spending see "Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operation - Liquidity and Capital Resources - Future Uses of Cash - Capital
Expenditure Program.
PacifiCorp operates one control area on the western portion of its service territory and one control area on the eastern portion
of its service territory. A control area is a geographic area with electric systems that control generation to maintain schedules
with other control areas and ensure reliable operations. In operating the control areas, PacifiCorp is responsible for
continuously balancing electric supply and demand by dispatching generating resources and interchange transactions so that
generation internal to the control area, plus net import power, matches customer loads. PacifiCorp also schedules power
deliveries over its transmission system and maintains reliability in part by verifying that customers are properly using the
system within established bounds.
PacifiCorp s wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp
Open Access Transmission Tariff. In accordance with the Open Access Transmission Tariff, PacifiCorp offers several
transmission services to wholesale customers:
Network transmission service (guaranteed service that integrates generating resources to serve retail loads);
Long~term and short-term firm point-to-point transmission service (guaranteed service with fixed delivery and receipt
points); and
. Non-firm point-to~point service ("as available" service with fixed delivery and receipt points).
These services are offered on a non-discriminatory basis, meaning that all potential customers are provided an equal
opportunity to access the transmission system. PacifiCorp s transmission business is managed and operated independently
from the generating and marketing business in accordance with the FERC Standards of Conduct. Transmission costs are not
separated from, but rather are "bundled" with, generation and distribution costs in retail rates approved by state regulatory
commissions. See "Regulation - Federal Regulatory Matters" below for further information related to the Energy Policy Act
of 2005, which requires that the FERC establish and enforce standards for electric reliability.
http://www.see.goy! Arehives/edgar!data/75594/000007 559406000028/p 1 Ok.htm 5/31/06
- .......-....-..
-,-,_.____n__...
_'.-
Page 12 of 160
Regionll. Transmission Coordination
In December 1999, the FERC encouraged all companies with tTansmission assets to form regional tTansmission organizations
that would manage certain operational functions of the transmission grid and plan for necessary expansion. In response
several northwest utilities, including PacifiCorp, formed a regional transmission entity, known as Grid West, that was
intended to coordinate transmission functions in all or portions of eight western states and western Canada.
In Apri12006, the Grid West board voted to dissolve the Grid West entity. This decision resulted primarily from the decision
of key participants, including the Bonneville Power Administration to discontinue support and funding of Grid West efforts.
To address the continuing need for some degree of regional transmission coordination, PacifiCorp and the other parties are
considering smaller-scale initiatives that could provide value for customers.
SERVICE TERRITORIES
PacifiCorp serves approximately 1.6 million retail customers in service territories aggregating approximately 136 000 square
miles in portions of six western states: Utah, Oregon, Wyoming, Washington, Idaho and California. The combined service
territory s diverse regional economy ranges from rural, agriculturallind mining areas to urbanized manufacturing and
government service centers. No single segment of the economy dominates the service territory, which mitigates PacifiCorp
exposure to economic fluctuations. In the eastern portion of the service territory, mainly consisting of Utah, Wyoming and
southeast Idaho, the principal industries are manufacturing, health services, recreation and mining or extraction of natural
resources. In tbe western portion of the service territory, mainly consisting of Oregon, southeastern Washington and northern
California, the principal industries are agriculture and manufacturing, with forest products, food processing, high leclmology
and primary metals being tbe largest industrial sectors. The foUowing map highlights PacifiCorp s retail service territory,
plant locations and PacifiCorp s primary transmission lines. PacifiCorp s generating facilities are interconnected tluough
PacifiCorp s own transmission tines or by contract through the transmission tines owned by others. See "Item 2. Properties
for additional information on PacifiCorp s plants.
http://www .see.goy/ Archives/edgar/data/75594/O00007559406000028/p 1 Ok.htm 5/31/06
""'-'-""".'--"."'---.""".'--."".....-,....-....,.,-,..--.--..-....-..............--..-...-...
Page 13 of 160
'. ~ """";-."
" r".""~-_."-""_.'--
'-.,-""--,......"""-.,_",-".",,,--,,,,.--"..,..-.", ......
, , 1J -
- - - -
1 j ;/1
...."" ' ~---\ ,
1 ."J ,," ':'-
-' ,. -\ .,. !..-// -
'1
j '... ./ "
W"AS-tt1NIGTO'~f ,.
..,... , '
1 (' J ~--
\,:" '\ /
" MONTANA
, '...j, . ,";:'" ,--' . ~ -
-.I" - """..l""-~
~",~" .~~.", ,"':,-
0.'
. ..------~" ""
';;r"! ~
. --~.....
..\;..o
1"'_
."
'1\
, '\ '.........-- __...-
1-.
! ,
-::""'.,J
.. / , ~
I'4'JI'\ ...,.
, "
.. ttp',Fl.EGON 'i IOAHO \.', I
( "
ifi. I" i \
j ,
J .
::.- .. :, - ..,:-' .. ,"" '
I -. : 1
--' -'~-"__.-.._.._.,.,: -, \ -. ;
: I -
--- ,.. .'-
!iJ
-:::::."'"'.", '' '
1'1
' :
.;1,' NEVADA :1
"..-y" "-...
I '' -4-'--- 0I, /I -: I COLORADO,
.I.
, '
) I f I
.. '" \
. I I ''J.\I '1/
:,..------
:;'- I "
. \
~, i. I: I, "
- ..'"
1 ' . ~
-- '/ ~("', '
;1 .. -
: -~,.-.- ./.../.----.....--...-.-...'
.'--"" 1""
,.,
"C~\.IFOP.NIA
, /
/~r "'----- t--
;=-
~ -II
....\.. '.. --
rl"'-..j J..r,"- 1..,'
' \.
-.J------
-- _. ,,.. ....., '... ,,
" oI'.
~" ,.. '\
n"'~,
..
'I .
..., "...';:-;':~'"!
,AIRIZ t+t ' I
.., '~", ,."",
";f r' .
'" --
.... I I 0
"\-..",......,, "" .../"
l "'
,. "", ,- "-= '.,
NEW XICQ
,/-,,-'.. .. ....:-.... /..., ~ ".'-:,'" "'" *:.... ~.-;
,r
..---(----" \"",_
il'
_,, ,~ '... "
"1 ..
~----,--
J ..." \ 1
" , .. .-.
'J 1 -, I
..,...-""
h ,--
...,....-... -'..."..-..,.........__...--_.._
.....l,
,.....,
...0
P:1dOCorp ~erv!ce :area
. Thenml planu (17totaJ)
I-fydro$ystllms (S I IOU! p.1:u1ts)
.. WlI1d pl""t ~I teal)
Cool mines (3 tOtal)
Pa.tlfiCorp~owned primary
tT;l.l\$.lTlission Una
u...Tr;mmiulon :\cceu
- ~ - TransmissIon lines owned by
other entities
TIle geographic distribution ofPacifiCorp I s retail electric operating revenues for the years ended March 31, 2006, 2005 and
2004 was as follows:
Utah
Oregon
Wyoming
Washington
Idaho
California
Yean Ended Marcb 31.
2006 200S 2004
40.40.38.
29.29.3 3L5
13.3 13.12.
8.4 8.4
6.1 6.3
2.4 2.4 2.5
100.100.100.
PacifiCorp receives authorization from state public utility commissions 10 serve areas within each state. This authorization is
perpetual until withdrawn by the state public utility commissions. In addition, PacifiCorp has received franchises to provide
electric service to customers inside incorporated areas within the states, Most franchises have terms of five years or more, but
http://www .see.gov/ Archivesfedgarfdata/75594/000007559406000028fp 1 Ok.htm 5/31/06
Page 14 of 160
some have indefinite terms. PacifiCorp must renew franchises that expire. Governmental agencies have the right to
http://www.see.gov/Archives/edgar/datal7 5594/000007 559406000028/p 1 Ok.htm 5/31106
Page 15 of 160
challenge PacifiCorp s right to serve in a specific area and can condemn PaciiiCorp s property under certain circumstances in
accordance with the Jaws in each state. However, PacifiCorp vigorously challenges any attempts from individuals and
governmental entities to undertake forced takeover of any portions of its service territory. PacifiCorp is subject to energy
regulation, legislation and political risks. Any changes in regulations and rates or legislative developments may adversely
affect its business, financial condition, results of operations and cash nows. See "Item lA. Risk Factors" for further
information.
CUSTOMERS
Electricity sold to retail customers and the number of retail customers, by class of customer, for the years ended March 31
2006, 2005 and 2004, were as follows:
Years End~d Murch 31,
2006 2005 2004
(Thousands of MWh)
MWh sold
Residential 880 29.117 28.14,460 29.
Commercial 14,887 29.642 29.14,413 29.
Industrial 19,746 39.4 454 39.133 39.
Other 599 1.2 706 1.4 673 1.4
Total MWh sold 112 100.919 100.679 100.
Number of retail customers (in thousands)
Residential 1,404 85.373 85.5%341 85.4%
Commercial 198 12.194 12.1 190 12.
Industrial 2.1 2.1
Other 0.3
Total 640 100.605 100.570 I OO~O%
Retail customers
Average annual usage percustorner
(kWh)30,895 825 305
Average annual revenue per customer 732 669 638
Revenue per kWh 5.4~
During the year ended March 31, 2006, no single retail customer accounted for more than 2.0% of PacifiCorp' s retail electric
revenues, and the 20 largest retail customers accounted for 13.0% of PacifiCorp s retail electric revenues.
PacifiCorp is estimating average growth in retail megawatt-hour (UMWh") sales in PacifiCorp s franchise service territories
to average between 2.0% and 3.0% annually over the five years to December 2010, depending on factors such as economic
conditions, number of customers, weather, consumer trends, conservation efforts and changes in prices.
Seasonality
As a result of the geographically diverse area of operations, PacifiCorp s service territory has historically experienced
complementary seasonal1oad patterns. In the western portion, customer demand peaks in the winter months due to heating
requirements. In the eastern portion, customer demand peaks in tbe summer when irrigation and air-conditioning systems are
heavily used.
For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal
seasonal patterns. Strong Utah residential growth over the last several years and increasing installations of central air
conditioning systems are contributing to faster summer peak growth.
http://www.see.gov!Archives/edgar/datal75594/000007 5 59406000028!p 1 Ok.htm 5/31/06
,....-..-.......-..-...-...-..,'-'.....""-"--".-"-"
Page 16 of 160
http://www.see.goy/ Arehiyes/edgar/datal75 594/000007559406000028/p Ok.htm 5/31/06
Page 17 of 160
RETAIL COMPETITION
During the year cnded March 31 , 2006, PacifiCorp continued to operate its retail business under state regulation, which
generally prohibits retail competition. However, certain ofPacifiCorp s commercial and industrial customers in Oregon bave
the right to choose alternative electricity suppliers. As a result of Direct Access mandated by Oregon s Senate Bill 1149, a
group of customers having a total average load of approximately 11.4 average MW have chosen service from suppliers other
than PacifiCorp. A group of customers having a total average load of approximately 1.6 average MW have taken service
from PacifiCorp at the Daily Market Pricing Option. This service provides a market-based pricing option by linking the
energy charge on a customer s bill to a representative market price index.PacifiCorp does not expect the Direct Access
program and tbe Daily Market Pricing Option to have a material effect on earnings for the 12 months ending March 31 , 2007.
In addition to Oregon s Direct Access program, others in PacifiCorp s service territories are seeking to have a choice of
suppliers, exploring options to build their own generation or co-generation plants, or considering the use of alternative energy
sources such as natural gas. If these customers gain the right to receive electricity from alternative suppliers, they will make
their energy purchasing decisions based upon many factors, including price, service and system reliability. The use of
alternative energy sources is typically based on availability, price and the general demand for electricity.
Any adoption of retail competition by the legislatmes in the states served by PacifiCorp. in addition to the Direct Access
program, and/or the unbundling of transmission, distribution and generation costs in regulated electricity services could have
a significant adverse financial impact on PacifiCorp due to an impairment of assets, a loss of retail customers, lower profit
margins or increased costs of capital and could result in increased pressure to lower the price of electricity. Alt110Ugh
PacifiCorp believes it will continue as a regulated entity and does not expect significant retail competition in the near future
it cannot predict if or to what extent it will be subject to changes in legislation or regulation allowing retail competitors, nor
can PacifiCorp predict the impact of these changes. See "Item lA. Risk Factors - PacifiCoIp is subject to energy regulation,
legislation and political risks, and changes in regulations and rates or legislative developments may adversely affect its
business, financial condition, results of operations and cash flows.
ENVIRONMENTAL MATTERS
PacifiCorp is subject to a number of federal, state and local environmental laws and regulations affecting many aspects of its
present and future operations. These requirements relate to air emissions, water quality, waste management, hazardous
chemical use, noise abatement, land use aesthetics and endangered species.
Environmental laws and regulations currently have, and future modifications may have, the effect of (i) increasing the lead
time for the construction of new facilities, (ii) significantly increasing the total cost of new facilities, (iii) requiring
modification ofPaciftCorp s existing facilities, (iv) increasing the risk of delay on constmction projects, (v) increasing
PacifiCorp s cost of waste disposal, and (vi) reducing the amount of energy available from PacifiCorp s facilities. Any of
these items could have a substantial impact on amounts required to be expended by PacifiCorp in the future.
In lhe year ended March 31 , 2006, PacifiCorp spent approximately $62.3 million on environmental capital projects.
PacifiCorp currently estimates expenditures for environmental~reJated capital projects wiu total approximately $129.2 million
in the 12 months ending March 31 , 2007.
Air Quality
PacifiCorp s fossil fuel-fired electricity generation plants are subject to applicable provisions of the Clean Air Act and related
air quality standards promulgated by the United States Environmental Protection Agency ("EPA") and state air quality laws.
The Clean Air Act provides the framework for regulation of certain air emissions and permitting and monitoring associated
with those emissions. PacifiCorp owns or has interests in 11 coal-fired generating plants, which represent 72.1 % of
PacifiCoIp s generating capability. PacifiCorp believes it has aU required pennits and other approvals to operate its plants
and t1mt the plants are in material compliance wilh applicable requirements.
The acquisition ofPacifiCorp by MEHC includes a regulatory commitment to spend approximately $812.0 million over
several years to reduce emissions at PacifiCorp s genemting facilities to address existing and future air quality requirements.
These costs and any additional expenditures necessitated by air quality regulations are expected to be included in rates and, as
such, would not have a material adverse impact on PacifiCorp s consolidated results of operations.
http://www .see.goy/ Archiyes/edgar/datal75594/000007559406000028/p 1 Ok.htm 5/31/06
.....--,......-..-...,-----.........--.""""'-'"......-.-...----
Page 18 of160
The EPA has in recent years implemented more stringent national ambient air quality standards for ozone and new standards
for fine particulate matter. These standards set the minimum level of air quality that must be met throughout the United
States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in
attainment of lhe standard. Areas that fait to meet the standard are designated as being non-attainment areas. Generally, once
an area has been designated as a non-attairunent area, sources of emissions that contribute to the failure to achieve the
ambient air quality standards are required to make emissions reductions. The EP A has concluded that Utah and Wyoming,
where PacifiCorp s major emission sources are located, are in attainment of the ozone standards and the fine particulate
matter standards.
In December 2005, the EPA proposed a revision of the ambient air quality standards for fine particles that would maintain the
current annual standard and set a new, more stringent 24-hour standard for concentration offine particulate. The EPA is
scheduled to issue final rules in September 2006. Until the EPA takes final action on the proposal, the impact of the proposed
rules on PacifiCorp cannot be detcnnined.
In March 2005, the EPA released the final Clean Air Mercury Rule. The Clean Air Mercury Rule utilizes a market-based cap
and trade mechanism to reduce mercury emissions from coal-burning power plants from the current nationwide level of 48
tons to 15 tons at full implementation. The Clean Air Mercury Rule s two-phase reduction program requires initial reductions
of mercury emissions in 2010 and an overall reduction in mercury emissions from coal-burning power plants of70.0% by
2018. Individual states are required to implement the Clean Air Mercury Rule through their state implementation plans.
Depending on the outcome of the respective states' implementation rules, the Clean Air Mercury Rule may require
PacifiCorp to reduce emissions of mercury from some or all of its coal-fired facilities through the installation of emission
controls, the purchase of emission allowances, or some combination thereof.
The Clean Air Mercury Rule could, in whole or in part, be superseded or made more stringent by one of a number of multi.
pollutant emission reduction proposals currently under consideration at the federal level, including pending legislative
proposals that contemplate 70.0% to 90.0% reductions of sulfur dioxide, nitrogen oxides and mercury, as well as possible
new federal regulation of carbon dioxide and otber gases that may affect global climate change. In addition to any federal
legislation that could be enacted by the United States Congress to supersede the Clean Air Mercury Rule, the rules could be
changed or overturned as n result of litigation. The sufficiency of the standards established by the Clean Air Mercury Rule
has been legally challenged in the United States District Court for the District of Columbia. Untit final resolution of litigation
challenging the Clean Air Mercury Rule, the full impact of the rules on PacifiCorpcannot be determined.
The EPA has initiated a regional haze program intended to improve visibility at specific federally protected areas. PacifiCorp
and other stakeholders are participating in the Western Regional Air Partnership to help develop the technical and policy
tools needed to comply with this program.
Under existing New Source Review provisions of the Clean Air Act, any facility that emits regulated polJutants is required to
obtain a permit from the EP A or a state regulatory agency prior to (i) beginning construction of a new stationary source of a
New Source Review -regulated pollutant, or (ii) making a physical or operational change to an existing stationary source of
such pollutants. Pending or proposed air regulations will require PacifiCorp to reduce its electricity plant emissions of sulfur
dioxide, nitrogen oxides and other pollutants below current levels. These reductions wilt be required to address regional haze
programs, mercury emissions regulations and possible fe-interpretations and changes to the federal Clean Air Act. In the
future PacifiCorp expects to incur significant costs to comply with various stricter air emissions requirements. "nlcse
potential costs are expected to consist primarily of capital expenditures. PacifiCorp expects these costs would be included in
rates and, as such, would not have a material adverse impact on PacifiCorp s consolidated results of operations. See also
Item 8. Financial Statements and Supplementary Data - Note 6 - Asset Retirement Obligations and Accrued Environmental
Costs.
TIle EPA has requested from several utilities information and supporting documentation regarding their capital projects for
various generating plants. The requests were issued as part of an industry-wide investigation to assess compliance with the
New Source Review and the New Source Performance Standards of the Clean Air Act. In 2001 and 2003, PacifiCorp
received requests for information from the EP A relating to PacifiCorp s capital projects at seven of its generating plants.
PacifiCorp submitted infom1ation responsive to the requests and there are currently no outstanding data requests pending
from the EPA. PacifiCorp cannot predict the outcome of these requests at this time.
http://www.see.gov/Archives/edgar/datal7 5594/0000075 59406000028/p 1 Ok.htm 5/31/06
Page 19 of 160
(n 2002 and 2t)03, the EPA proposed variouschnnges to its New Source Review mles tbat clarify what constitutes routine
repair, maintenance and replacement for purposes of triggering New Source Review requirements. These changes have been
subject to legal challenge and, until such time as the legal challenges are resolved and the rules are effective, PacifiCorp will
continue to manage projects at its generating plants in accordance with the rules in effect prior to 2002. In October 2005, the
EP A proposed a rule that would change or clarify how emission increases are to be calculated for purposes of determining the
applicability of the New Source Review pennitting progrum far existing power plants. The impact of these praposed changes
on PacifiCorp cannot be determined until after the rule is fmalized and implemented.
In February 2005, the Kyoto Protocol became effective, requiring 35 develaped countries te reduce greenhouse gas emissians
by approximately 5.0% between 2008 and 2012. White the United States did nat ratify tbe pratacol, the ratification and
implementation of its requirements in other countries has resulted in increased attention te climate change in the United
States. In 2005, the United States Senate adopted a "sense of the Senate" resolution that puts the United States Senate on
record that the United States Congress should enact a comprehensive and effective national program of mandatory, market-
based limits and incentives on emissions of greenhouse gases that slow, stop, and reverse the growth of such emissions at a
rate and in a manner that wilt not significantly harm the United States economy; and will encourage comparable action by
other nations 111at are major trading partners and key contributors to global emissions. While debate continues at the national
level over tbe direction of domestic climate policy, several states are developing state-specific or regional legislative
initiatives to reduce greenhouse gas emissions. (n December 2005, the states ofCoWlecticut, Delaware, Maine, New
Hampshire, New Jersey, New York and Vermont signed a mandatory regional pact to reduce green110use gas emissions Ulat
would become effective in 2009 and ultimately would require a reduction in greenhouse gas emissions of 10.0% from 1990
levels. An executive order signed by California s governor in June 2005 would reduce greenhouse gas emissions in that state
to 2000 levels by 2010, to 1990 levels by 202-0 and 80.0% below 1990 levels by 2050. In addition, California is seeking to
apply a greenhouse gas emission performance standard to all electricity generated within the state or delivered from outside
the state that is no higher than the greenhouse gas emission levels of a state-of-the-art combined-cycle natural gas generation
facility.
Litigation was filed in the federal district court for the southern district of New York seeking to require reductions of carbon
dioxide emissions from generating facilities of five large electric utilities. The court dismissed the public nuisance suit,
holding that such critical issues affecting the United States such as greenhouse gas emissions reductions are not the domain
of the court and should be resolved by the Executive Branel1 and the United States Congress. TI1is ruling 11as been appealed to
the Second Circuit Court of Appeals. The outcome of climate change litigation and federal and state initiatives cannot be
determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly impact
PacifiCorp s fossil-fueled facilities and, therefore, its results of operations and cash flows. PacifiCorp includes a projected
additional cost for carbon dioxide emissions in its Integrated Resource Plans when evaluating proposed new resources.
The EPA's regulation of certain pollutants under the Clean Air Act, and its failure to regulate other pol1utants, is being
challenged by various lawsuits brought by both individual state attorney generals and environmental groups. To the extent
that 111ese actions may be successful in imposing additional and/or more stringent regulation of emissions on fossil-iheled
facilities in general and PacifiCorp s facilities in particular, such actions could significantly impact PacifiCorp s fossil-fueled
facilities and, therefore, its results of operations and cash flows.
Water Quality
The federal Clean Water Act and individual state clean-water regulations require a permit for the discharge of wastewater
including storm water mnoff frem electricity plants and coal storage areas, into surface water and groundwater. Additionally,
PacifiCorp believes that it currently has, or has initiated the process to receive, all required water quality permits.
Endangered Species
The federal Endangered Species Act of 1973 and similar state statutes protect species threatened with possible extinction.
Protection of the habitat of endangered and threatened species makes it difficult and more costly to perform some of
PacifiCorp s ~ore activities, including the siting, construction and operation of new and existing transmission and distribution
facilities, as well as thermal, hydroelectric and wind generation plants. In addition. issues affecting endangered species can
impact the reticensing of existing hydroelectric generating projects. This can generally reduce the generating output and
operational flexibility, and potentially increase the costs of operation, ofPacifiCorp s own hydroelectric resources, as well as
raise the price PacifiCorp pays to purchase wholesale electricity from hydroelectric facilities owned by others.
http://www.see.gov/Archives/edgar/data/7 5594/000007 559406000028/p 1 Ok.htm 5/31/06
.,.-.--.----..-..."'-'"
Page 20 of 160
Environmental Cleanups
Under the Comprehensive Environmental Response, Compensation and Liability Act, the Resource Conservation and
Recovery Act and simi1ar state statutes, entities that dispose of, or arrange for the disposal of, hazardous materials may be
liable for cleanup of the contaminated property. In addition, the current or former owners or operators of affected sites may
be liable. PacifiCorp has been identified as a potentially responsible party in connection with a number ofc1eanup sites
because of its current or past ownership or operation of certain properties or because PacifiCorp sent materials deemed to be
hazardous to the property in the past. PacifiCorp has completed several c1eanup actions and is actively participating in
investigations and remediation actions at other sites. Sce "Item 8. Financial Statements and Supplementary Data - Note 6
Asset Retirement Obligations and Accrued Environmental Costs" for further discussion.
Mine Reclamation
The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation
and closure standards that must be met during and upon completion of mining activities. These obligations mandate that mine
property be restored consistent with specific standards and the approved reclamation plan. PacifiCorp s mining operations are
subject to these reclamation and closure requirements. Significant expenditures are being incurred for both ongoing and final
reclamation. For further discussion, see "Item 2. Properties" and "itemS. Financial Statements and Supplementary Data -
Note 6 - Asset Retirement Obligations and Accrued Environmental Costs.
REGULATION
PacifiCorp conducts its business in conformance with a multitude of federal and state laws. PacifiCorp is also subject to the
jurisdiction of public utility regulatory authorities in each of the states in which it conducts retail electric operations. These
authorities regulate various matters, including customer rates, services, accounting policies and practices, allocation of costs
by state, issuances of securities and other matters. In addition, PacifiCorp is a "licensee" and a "public utility" as those tenns
are used in the Federal Power Act and is therefore subject \0 regulation by the FERC as to accounting policies and practices,
certain prices and other matters, including the terms and conditions of transmission service. Most ofPacifiCorp
hydroelectric plants are licensed by the FERC as major projects under the Federal Power Act, and certain of these projects
are licensed under the Oregon Hydroelectric Act.
Federal Regulatory Matters
After several years of active consideration, in July 2005 the United States Congress approved legislation making significant
changes in federal energy policy. TIle Energy Policy Act of 2005, enacted in August 2005, repealed the Public Utility
Holding Company Act of 1935 and transferred regulatory oversight of public utility holding companies from the SEC to the
FERC. The Energy Policy Act of 2005 also contains provisions to encourag-e investment in renewable and lower-emission
coal generation, provides financial incentives and removes regulatory barriers for developers of new electric transmission
facilities, establishes a process for the creation and enforcement of mandatory electric reliability standards, and authorizes
license applicants and other parties to seek less costly and more efficient conditions imposed on federal hydroelectric power
licenses.
See "Item 8. Financial Statements - Note 10- Commitments and Contingencies" which is incorporated by reference into this
Item 1.
Several ofPacifiCorp s hydroelectric plants are in some stage of the relicensing process wjth the FERC. PacifiCorp also has
requested the FERC to allow decommissioning of four hydroelectric plants. TIle following summarizes the status of certain of
these projects.
Hydroelectric Relicensing
fClamatlJ 'lI'droelectric project - (Klamath River, Oregon and California)
In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 161.4-MW Klamath
hydroelectric project. The FERC is scheduled to complete its required analysis by January 2007. TIle United States
Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006;
PacifiCorp filed alternatives to the federal agencies' proposal and challenges to its factual assumptions in April 2006.
http://www.sec.gov/Archives/edgar/datal7 5 594/000007 559406000028/p 1 Ok.htm 5/31/06
"....-...-..-..,..".,--
Page 21 of 160
PacifiCorp continues to participate in the mediated settlement discussions with state and federal agencies, Native American
tribes and other stakeholders in an effort to reach a comprehensive agreement on project reHcensing.
ewis River Itvdroelectric projects - (Lewis River, Washington)
PacifiCorp filed new license applications for the 136.MW Merwin and 240.MW Swift No.1 hydroelectric projects in
April 2004. An application for a new license for the 134.MW Yale hydroelectric project was filed with the FERC in April
1999. However, consideration of the Yale application was delayed pending filing of the Merwin and Swift No. 1 applications
so that the FERC could complete a comprehensive environmental analysis.
In November 2004, PacifiCorp executed a comprehensive settlement agreement with 25 other parties including state and
federal agencies, Native American tribes, conservation groups, and local government and citizen groups to resolve, among
the parties, issues related to the pending applications for new licenses for PacifiCorp s Merwin, Swift No.1 and Yale
hydroelectric projects. As part of this settlement agreement, PacifiCorp has agreed to implement certain protection,
mitigation and enhancement measures prior to and during a proposed 50-year license period. However, these commitments
are contingent on ultimately receiving a license from the FERC that is consistent with the settlement agreement and other
required pennits. Other required pennits include biological opinions and a water quality certification. At the earliest, the
FERC is expected to make a final decision in August 2006.
Nort" U"fJl.qlla J,vdroelectric p-'roJect - (North Umpqua River, Oregon)
In October 2005, tile new FERC license for the 136.MW North Umpqua hydroelectric project became final under the tem1S
of the North Umpqua Settlement Agreement. Prior to this date, the license had been effective, but not final, because
environmentnl groups had challenged its legality before the FERC and in federal court. In September 2005, the Ninth Circuit
Court of Appeals issued an order upholding the new license. Since the Ninth Circuit Court's order was not appealed within
the allowed time, aU legal challenges of the FERC license order have been exhausted and the license is final for purposes of
recording liabilities. PacifiCorp is committed, over the 3S-year life of the license, to fund approximately $48.4 mi1lion for
environmental mitigation and enhancement projects. As a result of the license becoming final, PacifiCorp recorded additional
liabiHties and intangible assets in October 2005 amounting to a present value of$11.2 mimon. At March 31, 2006, the
liability recorded for all North Umpqua obligations amounted to a present value of$21.8 million.
Prospect ltvdroelectric;.p-roiect - (Rogue River, Oregon)
In June 2003, PacifiCorp submitted a final license application to the FERC for the Prospect Nos. 1 , 2 and 4 hydroelectric
projects, which total 36.8 MW. The FERC is expected to complete its required analysis and issue a new license before the
end of October 2006.
Jl~'droelectric DecommIssioning
Condit ltVllroelectric IlroJect - (White Salmon River, Washington)
In September 1999, a settlement agreement to remove tbe 9.MW Condit hydroelectric project was signed by PacifiCorp,
state and federal agencies and non-governmental agencies. Under the original settlement agreement, removal was expected to
begin in October 2006, for a total cost to decommission not to exceed $17.2 million, excluding inflation. In early February
2005, the parties agreed to modify the settlement agreement so that removal will not begin until October 2008 for a total cost
to decommission not to exceed $20.5 million, exc1uding inflation. 'The settlement agreement is contingent upon receiving an
amended FERC license and removal order that is not materially inconsistent with the amended settlement agreement and
other regulatory approvals. PacifiCorp is in the process of acquiring all necessary pennits, within the terms and conditions of
the amended settlement agreement.
State Regulatory Actions
PacifiCorp is currently pursuing a regulatory program in an states, with the objective of keeping rates closely aligned to
ongoing costs. A component of the regulatory program is the filing of Power Cost Adjustment Mechanisms ("PCAM"
PCAMs deal with changes in power costs occurring between rate cases. Power costs above or below the amounts built into
rates are recovered from or returned to customers according to the provisiOl1S in tIle specific PCAM. The following
discussion provides a state-by-state update.
Utah
In March 2006, PacifiCorp filed a general rate case with the UPSC related to increased investments in Utah due to growing
demand for electricity. PacifiCorp is seeking an increase of$197.2 million annually, or 17.1%, If approved by the UPSC, the
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
".."-...."....".....
Page 22 of 160
http://www .see.goy/ Arehives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
..,..,-,-.....--........
Page 23 of 160
increase would take effect in December 2006. In April 2006, PacifiCorp filed a revised case reflecting the effects of
PacifiCorp s sale to MEHC. The revised case reduced the original increase requested from $197.2 million to $194.1 million.
The active parties in the case have stipulated to a new schedule in the rate case which allows completion ofpreliminnry
audits and an opportunity for settlement discussions prior to the hearings set in July 2006 to determine the proper test year. In
November 2005, PacifiCorp filed a PCAM application. The Utah Industrial Energy Consumer Group has filed a motion to
dismiss the PCAM IIpptication based on lack of delegated legislative authority.PacifiCorp does not believe die motion has
merit and wilt oppose the motion in its reply due June 9, 2006. The PCAM proceeding is running concurrently with the
March 2006 general rate case.
Oregon
In April 2006, long-term special contracts for PacifiCorp s Klamath basin irrigation customers expired. Under the contracts,
customers received power at rates less than PacifiCorp s average retail rates charged to other customers on general irrigation
tariffs. Following expiration of these contracts, the OPUC issued an order authorizing the transition of Klamath
basin irrigators to generally applicable cost-based rates.
In February 2006, PacifiCorp filed a general rate case request with the OPUC for approximately $112.0 million, which
represents a 13.2% overall increase. The request is related to investments in generation, transmission and distribution
infrastructure and increases in fuel and general operating expenses, including the maintenance of low-cost but aging power
plants. A procedural schedule has been established with a decision from the OPUC expected by December 2006.
In September 2005, Oregon s governor signed into law Senate Bill 408. This legislation is intended to address differences
between income taxes collected by Oregon public utilities in retail rates and actual taxes paid by the utilities or consolidated
groups in which utilities are included for income tax reporting purposes. This legislation authorizes an automatic adjuSbnent
to rates based on the taxes paid to governmental entities on or after January 1 2006. The OPUC adopted a temporary rule in
September 2005 to establish filing requirements for an annual tax report mandated by Senate Bill 408. The definitions
adopted in the temporary rule would allocate a share of individual taxable losses of affiliate companies to the utility even
when the consolidated tax group pays more taxes than the utility collects in retail rates. The temporary rule expired in March
2006. PacifiCorp is actively participating in the rulemaking process for adopting permanent nales required by Senate Bill 408.
In September 2005, the OPUC issued aD order granting a general rate increase of$25.9 million, or an average increase of
2%, effective October 2005. PacifiCorp filed its general rate case in November 2004, and following four partial stipulations
with participating parties, PacifiCorp s requested revenue requirement increase was $52.5 million. The OPUC's order
reduced PacifiCorp 's revenue requirement by $26.6 million based on the OPUC's interpretation of Senate Bill 408. In
October 2005, PacifiCorp filed with tIle OPUC a motion for reconsideration and rehearing of the rate order generally on the
basis that the tax adjustment was not made in compliance with applicable law. With the motion, PacifiCorp also filed a
deferred accounting application with the OPUC to track revenues related to the disallowed tax expenses. The OPUC granted
PacifiCorp s motion for reconsideration and rehearing in December 2005 and is reconsidering whether Oregon Senate
Bil1408 applies to the general rate case and, if it does, whether the tax adjuSbnent ordered by the OPUC results in rates that
are unconstitutional. A hearing and submissions of written briefs are scheduled to occur through May 2006. A decision is
expected by summer 2006.
PacifiCorp filed an application in February 2005 for deferral of higher power costs incurred in calendar 2005 due to
continuing poor hydroelectric conditions. PllcifiCorp sought deferral of these costs to track for future recovery in rates. In
May 2005, this deferral application was suspended to allow parties to focus on a PC AM application filed by PacifiCorp in
April 2005. Briefing in the PCAM proceeding was completed in January 2006 and a commission order is pending. In May
2006, the PCAM proceeding was stayed for 60 days at PacifiCorp s request.
Wyoming
In March 2006, the WPSC approved an agreement that settled the general rate case filed by PacifiCorp in October 2005 and a
separate request filed by PacifiCorp in December 2005 to recover increased costs of net wholesale purchased power used to
serve Wyoming customers. The agreement provides for an annual rate increase of$15.0 miUion effective March 1, 2006, an
additional annual rate increase of $10.0 million effective July t, 2006. a PCAM and an agreement by the parties to support a
forecast test year in the next general rate case application.
http://www.see.goy/ Archiyes/edgar/datal7 5594/000007559406000028/p 1 Ok.htm 5/31/06
.-'--""-----...--"'-.---"----.'-------'- ....._._--,.,_.
Page 24 of 160
Washingtt)n
In May 2005, PacifiCorp filed a general rate case request with the WUTC for approximately $39.2 million 'IImually.
Hearings took place in January and February 2006 and this amount was reduced to approximately $30.0 million. As part of
the general rate case, PacitiCorp was also seeking to recover $8.3 million in hydroelectric costs and was proposing that future
hydroelectric and power cost volatility be recovered through a PCAM that was proposed as part of the general rate case. In
April 2006, the WUTC issued an order denying PacifiCorp s request to increase retail rates. TIle WUTC determined that
application ofPacifiCorp s cost allocation methodology failed to satisfy the statutory requirements that resources must
benefit Washington ratepayers.
(n April 2006, PacifiCorp filed a petition for reconsideration of the order and requested an increase of not less than $11.
million. PacifiCorp also filed a limited rate request seeking a rate increase of approximately $7.0 million, which represents a
99% increase in rates. PacifiCorp has requested that these dockets be consolidated so that the requested increase of not less
than $11.0 million can be achieved.
Idaho
In February 2006, PacifiCorp filed a notice of intent to file a general rate case with the IPUC. A general rate case may be
filed between 60 and 120 days after filing such a notice. Negotiations with certain Idaho customers are ongoing and the
successful conclusion of such negotiations may preclude the need for a rate case filing. If filed, the rate case witl seek a rate
increase in Idaho to be effective beginning January 2007.
In July 2005, the IPUC issued an order approving a settlement ofPacifiCorp s general rate case filed in January 2005 and
granting a stipulated rate increase of $5.8 million, or an average increase of 4.8%, effective September 16,2005. On that
date, unrelated pre-existing surcharges expired, so the net effect to customers oftlle $5.8 million base increase was an
increase in rates of$2.1 million annually, or an average increase of 1.7%.
Califarniu
In April 2006, long-term special contracts for PacifiCorp s Klamath basin irrigation customers expired. Under the conttacts,
customers received power at rates less than PacifiCorp s average retail rates charged to other customers on general irrigation
tariffs. Following expiration of these contracts, the CPUC approved ajoint proposal for a transition to standard tariff pricing.
In November 2005, PacifiCorp filed a general rate case with the CPUC for an increase of $11.0 million annually, or an
average increase of 15.6% related to increasing costs, including power costs and operating expenses, as well as significant
needed capital investments. PacifiCorp s application also requests the implementation of an Energy Cost Adjustment Clause
ECAC"), which like a PCAM allows for annual rate adjustments for changes in the level of net power costs, and a Post
Test- Year Adjustment Mechanism ("PT AM"), which would allow annual rate adjustments for changes in operating costs and
plant additions. These proposed adjustment mechanisms would operate outside the context of traditional general rate cases. In
May 2006, PacifiCorp filed an update to this general rate case to account for the Klamath basin irrigation customers
transition plan and to update the filing for the expected -cost savings as a result of the acquisition ofPacifiCorp by MEHC.
This updated filing resulted in a net requested average increase of$12.8 million annually, or 18.9% for California customers.
ITEM lA. RISK FACTORS
The following are certain risks and other factors to be considered when evaluating PacifiCorp. See "Item 7 A. Quantitative
and Qualitative Disclosures About Market Risk" for a discussion of additional important risks and other factors.
PacifiCorp is ellgaged ill several/arge colIStrllction or e.~pansioll projects, t/Je comp/etioll and expected cost of If!llic/J
subject to sigllifieallt risk, alld PacifiCorp /Jas signifieallt /llIIllillg lIeeds related to its piau lied capital expellditllres.
PacifiCorp is engaged in several large construction or expansion projects, including construction of a new generating facility,
the Lake Side Power Plant, in Utah and various capital projects related to transmission and distribution. In addition, in
connection with PacifiCorp s acquisition by MEHC, MEHC and PacifiCorp have committed to undertake several other
capital expenditure projects, principally relating to environmental controls, transmission and distribution, renewable
generating and other facilities. PacifiCorp expects to incur substantial construction, expansion and other capital expenditure
http://www.sec.gov!Archives/edgar/datal? 5594/000007 559406000028/p 1 Ok.htm 5/31/06
,.......-,-'-"'---.-'"...-.-.-..-,-"--.-'......-..--.
Page 25 of 160
costs over the ncxt several years, including the recent regulatory conunitments previously discussed. PacifiCorp depends
upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. 1 f these
funds are not available amI/or if MEHC does not elect to provide any needed funding to PacifiCorp, PacifiCorp may need to
postpone or cancel planned capital expenditures.
The completion of any or all of PacifiCorp s pending, proposed or future construction or expansion projects is subject to
substantial risk and may expose PacifiCorp to significant costs. PacifiCorp s development or construction efforts on any
particular project, or its capital expenditure program generally, may not be successful. IfPacifiCorp is unable to complete the
development or construction of any capital project, or if it decides to delay or cancel a project, it may not be able to recover
its investment in that project.
Also, a proposed expansion or new project may cost more tItan planned to complete, and any excess costs, if related to a
regulated asset and found to be imprudent, may not be recoverable in rates. The inability to successfully and timely complete
a project or avoid unexpected costs may require PacifiCorp to perform under guarantees, and the inability to avoid
unsuccessful projects or to recover any excess costs may materially affect PacifiCorp s cash flows and results of operations.
PacifiCorp is subject to ceriaill operatillg Imeertaillties wllie" may adversely affect itsfillnllcial positioll, reslllts of
operations al/d casllflolVs.
The operation of complex electric utility systems (including transmission and distribution) and power generating facilities
that are sprcad over a large geographic area involves many risks associated with operating uncertainties and events beyond
PacifiCorp s control. These risks include the breakdown or failure of power generation equipment, transmission and
distribution tines or other equipment or processes, unscheduled plant outages, work stoppages, transmission and distribution
system constraints or outages, fuel shortages or interruptions, perfonnance below expected levels of output, capacity or
efficiency, the effects of cbanging government regulation, operator error and catastrophic events such as severe storms, fires
earthquakes, explosions or mining accidents. A casualty occurrence might result in injury or loss of life, extensive property
damage or environmental damage. The realization of any of these risks could significantly reduce PacifiCorp s revenues or
significantly increase its expenses, thereby adversely affecting results of operations. For example, if PacifiCorp cannot
operate generation facilities at fun capacity dlle to restrictions imposed by environmental regulations, its revenues could
decrease due to decreased wholesale sales and its expenses could increase due to the need to obtain energy from higher-cost
sources. Any reduction of revenues or increase in expenses resulting from the risks described above could decrease
PacifiCorp s cash flows and weaken its financial position.
Furthennore, PacifiCorp s current and future insurance coverage may not be sufficient to replace lost revenues or cover
repair and replacement costs, especially in light of recent catastrophic events affecting the insurance markets that make it
more difficult or costly to obtain certain types of insurance.
Acts of sabotage ",Id terrorism aimed at PacifiCrJrp 's facilities, ti,e faciliJies of its filet suppliers or customers, or at
regiOllal tratlsmiss;OII facilities could arlversely affect PacifiCorp s busilless.
Since the September 11 2001 terrorist attacks, the United States government has issued warnings that energy assets
specifical1y the nation s pipeline and electric utility infrastructure, may be the future targets of terrorist organizations. These
developments have subjected PacifiCorp s operations to increased risks. Damage to PacifiCorp s assets, the assets of
PacifiCorp s fuel suppliers or customers, or to regional transmission facilities inflicted by terrorist groups or saboteurs could
result in a significant decrease in revenues and significant repair costs, force PacifiCorp to increase security measures, cause
changes in the insurance markets and cause disruptions of fuel supplies, energy consumption and markets, particularly with
respect to natural gas and electric energy. Any of these consequences of acts of terrorism could materially affect PacifiCorp
results of operations and cash flows. Instability in the financial markets as a result of terrorism or war could also materially
adversely affectPacifiCorp s ability to raise capital.
Recovery of costs by PacifiCorp ;s subject to reglllatory reviell' alld approval, alld tile iI/ability to recover costs may
adversely affect PacifiCorp s revelllles alld cas/rflolVs.
. PacifiCorp is subject to the jurisdiction of federal and state regulatory authorities. 111e FERC establishes tariffs under which
PacifiCorp provides transmission service to the wholesale market and the retail market (in states allowing retail competition).
The FERC also establishes both cost.based and market-based tariffs under which PacifiCorp sells electricity at wholesale and
has licensing authority over most ofPacifiCorp s hydroelectric generation facilities. In addition, the utility regulatory
http://www .see.goy/ Archivesledgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
,.--...,---..---.--'"'".."..""-"".'.'."""""----'...-....,.......,.....,.........-.----..-.-....' ,.....-....-....----
Page 26 of 160
commissions in each state served by PacifiCorp independently determine the rates that PacifiCorp may charge its retail
customers in those states.
Each state s rate-setting process is based upon the state utility commission s acceptance of an allocated share of PacifiCorp '
total utility costs for its entire retail service territory. When different states adopt different methods to address this cost
allocation issue, some costs may not be incorporated into rates in any state. Rate-making is also generally done on the basis
of estimates of normalized costs, so if in a specific year realized costs are higher than normal, rates wilt not be sufficient to
cover those costs. Each state utility commission generally sets rates based on a test year established according to that
commission s policies. Certain states use a future test year or allow for escalation of historical costs. In the states in which
PacifiCorp operates that use a historical test year, rate adjustments could lag cost increases, or decreases, by up to two years.
Il1is regulatory lag causes PacifiCorp to incur costs, including significant new investments, for which recovery through rates
is delayed. In addition, each state commission decides what percentage return a utility wiH be permitted to earn on its equity.
Each commission also decides what level of expense and investment is necessary, reasonable and prudent in providing
service and may disallow and deny recovery in rates for any costs that do not meet this standard. For these reasons, as well as
others (such as recently enacted legislation and the outcome of the recent rate order in Oregon limiting or denying the ability
of a utility to recover tax expenses in rates), the rates authorized by the state regulators may not be sufficient to cover costs
incurred to provide electrical services in any given period.
PacifiCorp is subject to ellergy regll/atioll, Icgislatioll alld political risks, alld challges in regilialiolls alld rates or
legislative developllleltts may ad~lersely affect its bllSillCSS, flllallcial cOlrditioll, results of operatiolls alld cas', flows.
PacifiCorp is subject to comprehensive governmental regulation, including regulation by various federal, state and local
regulatory agencies, which significantly influences PacifiCorp s operating environment, the prices it is allowed to charge
customers, its capital structure, its costs and its ability to recover costs from customers. These regulatory agencies include tIle
FERC, the EPA, and the public utility commissions in Utah, Oregon, Wyoming, Washington, Idaho and California.
PacifiCorp also conducts its businesses in conformance with a multitude of federal, state and local laws, which are subject to
significant changes at any time. Changes in regulations or the imposition of additional regulations by any of these regulatory
entities, as well as new legislation, could have a material adverse impact on PacifiCorp s results of operations. For example
such changes could result in increased retail competition in PacifiCorp s service territory, changes to the hydroelectric
relicensing process under the Federal Power Act, encouragement of investments in renewable or lower-emission generation,
the acquisition by a municipality or other quasi-governmental body ofPacifiCorp s distnDution facilities (by negotiation
legislation or condemnation or by a vote in favor of a Public Utility District under Oregon law), or a negative impact on
PacifiCorp s current cost recovery arrangements. As another example, PacifiCorp could be adversely affected by Senate Bill
408, which was recently enacted in Oregon. That legislation, and the outcome of a recent rate case, which is currently under
formal reconsideration, resulted in a reduction by the OPUC in the rates that PacifiCorp is currently permitted to charge to its
Oregon customers, and in the future may limit the ability ofPacifiCorp and other public utilities to recover future federal and
state income tax expenses in Oregon retail rates. Unless Senate BiU 408 is amended, modified or repealed, or the pending
rehearing of the rate case is resolved, in a manner satisfactory to PacifiCorp, such legislation and rules could have a material
adverse effect upon PacifiCorp s results of operations and cash flows.
Several ofPacifiCorp s hydroelectric projects are in some stage of the FERC relicensing process under the Federal Power
Act, as several ofPacifiCorp s long-term operating licenses have expired or will expire in the next few years. The relicensing
process is a political and public regulatory process that involves sensitive resource issues and uncertainties. PacifiCorp
cannot predict with certainty the requirements that may be imposed during the relicensing process, the economic impact of
those requirements, whether new licenses will ultimately be issued or whether PacifiCorp wilt be willing to meet the
relicensing requirements to continue operating its hydroelectric projects. Loss of hydroelectric resources or additional
commitments arising from the relicensing process could increase PacifiCorp s operating costs or result in large capital
expenditures that reduce earnings and cash flows.
In August 2005, the Energy Policy Act of2005 was signed into law. That Jaw potentially impacts many segments of the
energy industry. Tl1e law directed the FERC to issue new regulations and regulatory decisions in areas such as electric system
reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority.
White the FERC has now issued rules and decisions on multiple aspects of the Energy Policy Act of200S, the full impact of
those decisions remains uncertain. As a result of past events affecting electric reliabitity, the Energy Policy Act of 2005
requires federal agencies, working together with non-governmental organizations charged with electric reliability
responsibilities, to adopt and implement measures designed to ensure the reliability of electric transmission and distribution
http://www.see.goY/Archives/edgar/datal7 5594/000007 559406000028/p 1 Ok.htm 5/31/06
.....---------.....,".""-."-."--'-'.-,..--".-.-......--...-..,,..,-........-..-
Page 27 of 160
systems. The implementation of such measures could result in the imposition of more comprehensive or stringent
requirements on PacifiCorp or other industry participants, which would result in increased compliance costs and could have a
material adverse effect on PacifiCorp s business, financial position, results of operations and cash flows.
PacijiCorp o; subject to market risk, collnterparty performallce ri.vk allil otlter risks associated witlt wllolesale ellergy
markets.
In general, market risk is the risk of adverse fluctuations in the market price of wholesale electricity and fuel, including
natural gas and coal, which is compounded by energy volume changes affecting the availability of and/or demand for
electricity and fuel. PacifiCorp purchases electricity and fuel in the open market or pursuant to short-term or variable-priced
contracts as part of its normal operating business. If market prices rise, especially in a time when PacifiCorp requires larger
than expected volumes that must be purchased at market or short-term prices, PacifiCorp may have significantly greater costs
than anticipated. In addition, it may not be able to timely recover all, if any, of those increased costs through rate-making, due
to retroactive rate-making prohibitions, unless deferred accounting or power cost recovery mechanisms have been previously
authorized. Likewise, if electricity market prices drop in a period when PacifiCorp is a net seller of electricity in the
wholesale market, PacifiCorp will eam less revenue, possibly to the extent of not recovering the cost of generating the
electricity. Wholesale electricity prices are influenced primarily by factors throughout the western United States relating to
supply and demand. lllOse factors include the adequacy of generating capacity, scheduled and unscheduled outages of
generating facilities, hydroelectric generation levels, prices and availability of fuel sources for generation, dismptions or
constraints to transmission facilities, weather conditions, economic growth, and changes in tec1mology. Energy volume
changes are cnused by unanticipated cbanges in generation availability and/or chnnges in customer demand for power due to
the weather, the economy and customer behavior. Although PacifiCorp plans for resources to meet its current and expected
power delivery obligations, its power costs may be adversely impacted by market risk.
PacifiCorp is also exposed to risk related to performance of contractual obligations by its wholesale suppliers and customers.
PacifiCorp relies on suppliers to deliver natural gas, coal and electricity in accordance with short- and long-term contracts.
Failure or delay by suppliers to provide natural gas, coal or electricity pursuant to existing contracts could dismpt
PacifiCorp s ability to deliver electxicity and require it to incur additional expenses to meet the needs of its customers. In
addition, as these contractual agreements end, PacifiCorp may not be able to continue to purchase natura) gas, coal or
electricity on terms equivalent to the terms of current contractual agreements. PacifiCorp relies on wholesale customers to
take delivery of the energy they have committed to purchase and to pay for the energy on a timely basis. Failure of customers
to take delivery may require PacifiCorp to fmd other customers to take the energy at lower prices than the original customers
committed to pay. At certain times of year, prices paid by PacifiCorp for energy needed to satisfy its customers' demand for
power may exceed the amounts PacifiCorp receives through retail rates from these customers. If the strategy PacifiCorp uses
to economically hedge the exposure to these risks is ineffective, it could incur significant losses.
Weather colllfitiolts Catr adver.o;elJ' affect PllcijiCorp s operatiug resllits.
Although PacifiCorp s service territory has historically experienced complementary seasonal customer power demand
patterns as a result of the geographical1y diverse area of its operations. weather conditions can significantly affect operating
results. For residential customers, within a given year, weather conditions are the dominant cause of usage variations from
normal seasonal patterns. For example, in periods ofunusualty hot summer weather, residential customers tend to use
significantly greater amounts of electricity to run air conditioners, which may substantially increase summer peak power
demand. Changes in weather conditions and other natural events also impact customer behavior and power demand.
Additionally, a portion ofPacifiCorp s supply of electricity comes from hydroelectric projects that are dependent upon
rainfall and sl1owpack. During or following periods of low rainfall or snowpack, PacifiCorp may obtain substantially less
electricity from 11ydroelectric projects and must purchase greater amounts ofelectricity from the wholesale market or from
other sources at market prices. Accordingly, variations in weather conditions can adversely affect PacifiCorp s results of
operations through lower revenues and/or increased energy costs.
PacijiCorp is subject to eltviroltmelltal, health, safety alld otller laws and reglllatiOlrs tltat may adversely impact its
brrsiness.
PacifiCorp is subject to a number of environmental, heallh, safety and other laws and regulations affecting many aspects of
its present and future operations, including air emissions, water quality, endangered species, wastewater discharges, solid
wastes, hazardous substances and safety matters. PacifiCorp may incur substantial costs and liabilities in connection with its
operations as a result of these laws and regulations. In particular, the cost of future compliance with federal, state and local
http://www .see.gov/ Archives/edgar/datal75594/000007559406000028/p 1 Ok.htm 5/31/06
"-"-.-,,,--,,,,-"'----.',._-,-~...---_....._-,_.'.....-..---------,""'-
Page 28 of 160
clean air laws, such as those that relate to addressing regional haze issues and those that require certain generators, including
some of PacitiCorp' s electric generating facilities, to limit emissions of nitrogen oxide, sulfur dioxide, carbon dioxide,
mercury and other potential pollutants or emissions, may require PacifiCorp to make significant capital expenditures that may
not be recoverable through future rates. In addition these costs and liabilities may include those relating to claims for
damages to property and persons resulting from PacifiCorp s operations. Regulatory changes, including new interpretations
of existing h\ws and regulations, imposing more comprehensive or stringent requirements on PacifiCorp, to the extent such
changes would result in increased compliance costs or additional operating restrictions, could have a material adverse effect
on PacifiCorp s business, financial position, results of operations and cash nows.
Furthermore, regulatory compliance for existing facilities and the construction of new facilitics is a costly and time-
consuming process, and intricate and rapidly changing environmental regulations may require major expenditures for
permitting and create the risk of expensive delays or material impairment of value if projects cannot function as planned due
to changing regulatory requirements or local opposition.
In addition to operational standards, environmental laws also impose obligations \0 clean up or remediate contaminated
properties or to pay for the cost of such remediation, often upon parties that did not actuaUy cause the contamination.
Accordingly, PacifiCorp may become liable, either contractually or by operation of Jaw, for remediation costs even if the
contaminated property is not presently owned or operated by it, or if the contamination was caused by third parties during or
prior to its ownership or operation of the property. Given the nature .of the past industrial operations conducted by PacifiCorp
and others at its properties, aU potential instances of soil or groundwater contamination may not have been identified, even
for those properties where an environmental site assessment or other investigation has been conducted. Although PacifiCorp
has accrued reserves for its known remediation liabilities, future events, such as changes in existing laws or policies or their
enforcement, or the discovery of currently unknown contamination, may give rise to additional remediation liabilities which
may be material. Any failure to recover increased environmental, health or safety costs incurred by PacifiCorp may have a
material adverse effect on its business, financial position, results of operations and cash flows.
Poor performarrce ofpells;oll pia" i/,vestmellts alrd otller factors ;mpactillg pellsion plarr costs collid "'ifa~'orably impact
PacifiCorp 'i liq"itlity alld resl/lts of operatiolls.
PacifiCorp s costs of providing non-contributory defined benefit pension plans depend upon a number of factors, including
the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding
levels of the plans, future government regulation and PacifiCorp s required or voluntary contributions made to the plans.
While PacifiCorp complies with the minimum funding requirements under federal law, as of March 31 , 2006 its projected
benefit obligations, which include the impact of expected future c.ompensation increases, exceeded the value of plan assets by
approximately $513.6 million, including contributions made between the December 31, 2005 measurement date and March
3 I, 2006. Without sustained growth in the pension investments over time to increase the value of its pension plan assets, and
depending upon the other factors described above, PacifiCorp could be required to fund its pension plans with significant
amounts of cash. Such cash funding obligations, as well as the impact of the other factors described above, could have a
material impact on PacifiCorp s liquidity by reducing its cash flows and could negatively affect its results of operations.
A dowIIgrutle ;1/ PacifiCorp s credit ,alillgs co"ld tregatively affect its ability to access capital alld its ability to
ecollomically "edge ill wllO/esale markets.
Changes in PacifiCorp s financial performance, capital structure, the regulatory environment in which it operates and other
factors expose it to the risk of a credit ratings downgrade by Standard and Poor s or Moody s Investor Services, the principal
ratings agencies that evaluate PacifiCorp s creditworthiness and that of its debt securities and preferred stock. Although
PacifiCorp has no rating-downgrade triggers that would accelerate the maturity dates of its outstanding debt. A downgrade in
its credit ratings could directly increase the interest rates and commitment fees on its revolving credit agreement. A ratings
downgrade also may reduce the accessibility and increase the cost ofPacifiCorp s commercial paper program, its principal
source of short-term borrowing, and may result in the requirement that PacifiCorp post coUateral under certain of its power
purchase and other agreements. In addition, a credit ratings downgrade could allow counterparties in the wholesale electric,
wholesale natural gas and energy derivatives markets to require PacifiCorp to post a letter oCcredit or other coltateral, make
cash prepayments, obtain a guarantee agreement or provide ot11er mutually agreeable security. These consequences of a credit
ratings downgrade could increase PacifiCorp s borrowing and operating costs.
http://www .see.gov/ Archives/edgar/datal75594/000007559406000028/p 1 Ok.htm 5/31/06
...,-.-..--..-.......,....-.....",,---.
Page 29 of 160
PacijiCorp /ms a substa"tial al1l0ullt o/Ilebt, w/licll COllIl1 adversel)' affect its ability to ubtaillflllureflnRllCi"g "lid limit
its expcllditllres.
As of March 31, 2006,PacitiCorp had $4.1 billion in total debt securities outstanding. Its principal financing agreements
contain restrictive covenants that limit its ability to borrow funds, and any issuance of debt securities requires prior
authorization from multiple state regulatory commissions. PacifiCorp expects that it will need to supplement cash generated
from operations and availability under committed credit facilities with new issuances of long-term debt. However, if market
conditions are not favorable for the issuance of long-term debt, or if an issuance of long-term debt would exceed contractual
or regulatory limits, PacifiCorp may postpone planned capital expenditures, or take other actions, to the extent those
expenditures are not fully covered by cash from operations or equity contributions from MEHC and not available under
committed credit facilities.
MERC may exercise its .~igllijicallt illf/llence over PaciflCorp in a manlIer tltat would b(mefit MERC to tlte detrimellt 0/
PaciflCorp s crellitors ami preferred stock/wlders.
MEHC, through its subsidiary, owns all ofPacifiCorp s common stock and therefore has significant influence over its
business and any matters submitted for shareholder approval. In circumstances involving a conflict of interest between
MEHC and PacifiCorp s creditors and preferred stockholders, MEHC could exercise its influence in a manner that would
benefit MEHC to the detriment ofPacifiCorp screditors and preferred stockholders.
ITEM lB. UNRESOLVED STAFF COMMENTS
No information is required to be reported pursuant to this item.
ITEM 2. PROPERTIES
PacifiCorp owns its principal properties in fee (except as indicated below), subject to defects and encumbrances that do not
interfere materially with their use. Substantially all ofPacifiCorp s electric utility properties are subject to the lieD of
PacifiCorp s Mortgage and Deed of-Trust. See "Item 15. Exhibits, Financial Statement Schedules - Exhibit 4.1." PacifiCorp
considers all of its properties to be well maintained, in good operating condition, and suitable for their intended purposes.
Headquarters/Offices
PacifiCorp s corporate offices consist of approximately 900 000 square feet of owned and leased office space located in
several buildings in Portland, Oregon, and Salt Lake City, Utah. PacifiCorp s corporate headquarters are in Portland, but
there are several executives and departments located in Salt Lake City. In addition to the corporate headquarters,PacifiCorp
owns and leases approximately 1.2 million square feet of field office and warehouse space in various other locations in Utah
Oregon, Wyoming, Washington, Idaho and California. TIle field location square footage does not include offices located at
PacifiCorp s generating plants.
Generation
PacifiCorp owns, or has an interest in, various hydroelectric, thennal and wind generating plants. A generator s nameplate
rating is its full.load capacity (in megawatts) under normal operating conditions as defined by the manufacturer. TIle net
capability is the maximum level a generator can operate at under specified conditions. l1le following table summarizes
PacifiCorp s existing generating plants;
http://www sec.gov/ Archives/edgar/datal75594/000007559406000028/p 1 Ok.htm 5/31/06
---.-"..----"---'...........-.-.,-.............---
Page 30 of 160
Vnlt
Illstullulion Nunleplale I'lallt Nel
Locallon Energy Source Dalc(s)Rallng (I\IW)Capubllily (MW)
HYDROELECTRIC PLANTS (a)
Swift No.1 (b)Cougar, W A Lewis River 1958 240.264.
Merwin Ariel, W A Lewis River 1931-1958 136.144.
Yale Amhoy, WA Lewis River 1953 134.165.
Five North Umpqua Plants Toketee Faits, OR N. Umpqua River 1950-1956 136.138.
101m C. Boyle Keno, OR Klamath River 1958 90.4 94.
Copco Nos. 1 and 2 Plants Hombrook, CA Klamat11 River 1918-1925 47.54.
Clearwater Nos. 1 and 2 Plants Toketee Falls, OR Clearwater River 1953 41.0 41.0
Grace Grace, ID Bear River 1908-1923 33.33.
Prospect No.Prospect, OR Rogue River 1928 32.36.
Cutler Cotlingston, UT Bear River 1927 30.29.
Oneida Preston, ID Bear River 1915-1920 30.28.
Iron Gate Hornbrook, CA Klamath River 1962 18.20.
Soda Soda Springs, ID Bear River 1924 14.14.
Fish Creek Toketee FaUs, OR Fish Creek 1952 11.0 12.
31 Minor Hydroelectric Plants (c)Various Various 1895-1990 90.86.
Subtotal (51 Hydroelectric Plants)083.159.4
TIIERMAL PLANTS
Jim Bridger Rock Springs, WY Coal-Fired 1974-1979 541.1*413.4*
Huntington Huntington, VT Coal-Fired 1974-1977 996.895.
Dave Johnston Glenrock, WY Coal';Fired 1959-1972 816.762.
Naughton Kemmerer, WY Coal-Fired 1963-1971 707.700.
Hunter Nos. 1 and 2 Castie Dale, UT Coal-Fired 1978-1980 727.662.
Hunter No.Castle Dale, VT Coal-Fired 1983 495.460.
Chona No.Joseph City, AZ Coal-Fired 1981 414.380.
Wyodak Gillette, WY Coal-Fired 1978 289.268.
Carbon Castle Gate, VT Coal-Fired 1954-1957 188.172.
Craig Nos. 1 and 2 Craig, CO Coal-Fired 1979-1980 172.165.
Colstrip Nos. 3 and 4 Colstrip, MT Coal-Fired 1984-1986 155.149.
Hayden Nos. 1 and 2 Hayden, CO Coal-Fired 1965-1976 81.3*78.
Currant Creek Mona, UT Natural Gas-Fired 2005-2006 566.523.
Hermiston Herrniston, OR Natural Gas-Fired 1996 279.237.
Gadsby Steam Salt Lake City, VT Natural Gas-Fired 1951-1952 257.235.
Gadsby Peakers Salt Lake City, VT Natural Gas-Fired 2002 141.0 120.
Little Mountain Ogden, UT Natural Gas-Fired 1912 16.14.
Camas Co-Gen Camas, W A Black Liquor 1996 61.5 22.
Blundell (d)Milford, UT Geothermal 1984 26.23.
Subtotal (17 Thermal Electric Plants)934.278.4
WIND PLANT
Foole Creek Arlington, WY Wind Turbines 1998 32.32.
Sublotal (I Other Plant)32.32.
Total Generating Plants (69)050.8,470.4
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
.......-.-.....--....,-,""'-'..'-----'--.'-----'-..'-.-.'-"".---'-......-..'---.
Page 31 of160
Jointly owned plants; amount shown represents PacifiCorp s share only.
Hydroelectric project locations are stated by locality and river watershed.
On April 21 , 2002, the Cowlitz County Public Utility District-owned Swift No.2 power canal failed, impacting the
operations of the PacifiCorp-owned 240.0 MW Swift No.1 hydroelectric facility. In June 2004, PacifiCorp and
Cowlitz County Public Utility District, through an amendment to an existing power purchase agreement, agreed to a
(a)
(b)
http://www .see.gov/ Arehives/edgar/dataJ75594/000007559406000028/p 10k.htm 5/31/06
..,-..,--..----,..-
Page 32 of 160
(d)
mechanism for settling aU claims and terms of rebuilding. Reconstnaction of the canal is nearing completion and the
project began operating on an interim basis in the three months ended Murch 31, 2006.
PacifiCorp hus negotiated settlement agreements with resource agencies and other interested parties to decommission
the American Fork, Condit, Cove Development and Powerdale hydroelectric plants, which have a combined net
capability of 16.6 MW. These settlement agreements have been filed with the FERC and are pending further regulatory
action.
As a result of the settlement agreement between MEHC, the Utah Committee of Consumer Services ("CCS"), a state
utility consumer advocate, and Utah Industrial Energy Consumers, MEHC contributed to PacifiCorp, at no cost,
MEHC's indirect 100.0% ownership interest in IntermOlmtain Geothermal Company, which controls 69.3% of the
steam rights associated with the geothermal field serving PacifiCorp s Blundell Geothermal Plant in Utah. Therefore,
Intermountain Geothermal Company became a wholly owned subsidiary ofPacifiCorp in March 2006, subsequent to
the sale ofPacifiCorp to MEttC.
In May 2002, PacifiCorp entered into a IS-year operating lease for an electric generation facility with West Valley Leasing
Company, LtC, an indirect subsidiary of ScottishPower. The Utah facility consists of five generation units with an aggregate
nameplate rating of 217.0 MW and a net plant capability of 202.0 MW. PacifiCorp, at its sole option, may terminate the
lease, or purchase the facility, if written notice is provided to West VaHey on or before December 1,2006. If the termination
option is exercised, the lease would end in May 2008.
(c)
Transmission nnd Distribution
PacifiCorp s generating facilities are interconnected through Pa-eifiCorp s own transmission Jines or by contract through the
transmission lines of other transmission owners. Substantially all ofPacifiCorp s generating plants and reservoirs are
managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions ofPacifiCorp
transmission and distribution systems are located:
. On property owned or leased by PacifiCorp;
Under or over streets, alleys, highways and other public places, the public domain and national forests and state lands
under franchises, easements or other rights that are generally subject to tennination;
Under or over private property as a result of easements obtained primarily from the record bolder of title; or
Under or over Native American reservations under grant of easement by the Secretary of Interior or lease by Native
American tribes.
It is possible that some of the easements, and the property over which the easements were granted, may have title defects or
may be subject 10 mortgages or liens existing at the time the easements were acquired.
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
.....--.-....-..--,-........ ...--...."..-......,.-...,-..,-....-......-.-.,-..-.-....-...."
Page 33 of 160
At March 3 1, 2006, PacifiCorp owned, or participated in, an electric transmission and distribution system consisting of:
Nominal
Voltage
(In kilovolts)
Transmission Lines
500
345
230
161
138
115
Distribution Lines Less than 46
Total
Miles
720
900
360
280
050
540
970
110
650
580
59,510
75,090
At March 31, 2006, PacifiCorp owned 908 substations.
Mining
PacifiCorp believes that the respective coal reserves available to the Craig, Huntington, Hunter and Jim Bridger Plants,
together with coal available under both long-term and short-term contracts with external suppliers, will be substantially
sufficient to provide these plants with fuel that meets the Clean Air Act standards for their current economically useful lives.
Blending ofPacifiCorp-owned and contracted coal, together with electricity plant technologies for controlling sulfur and
other emissions, are utilized to meet the applicable standards. PacifiCorp-owned plants held sufficient sulfur dioxide
emission aUowanccs to comply with tIle EPA Title IV requirements during the compliance year. The sulfur content of tIle
coal reserves ranges from 0.30% to 0.94%, and the British Thermal Units value per pound ofthe reserves ranges from 8,600
to 12 400.
Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data
new mining technology and changes in regulation and economic factors affecting the utilization of such reserves.
Recoverable coal reserves at March 31 , 2006, based on PacifiCorp s most recent engineering studies, were as follows:
location I'lant Served !\lIning Melilod
Recoverable Toos
(in MIllions)
Craig, CO
Huntington & Castle Dale, UT
Rock Springs, WY
Craig
Huntington and Hunter
Jim Bridger
Surface
Underground
SurfacelUnderground
48.0 (a)
61.1 (b)
139.2 (c)
(a) ll1ese coal reserves are leased and mined by Trapper Mining, Inc., a Dclaware non-stock corporation operated on a
cooperative basis, in which PacifiCorp has an ownership interest of2) .4%.
(b) ll1ese coal reserves are leased by PacifiCorp and mined by a wholly owned subsidiary of PacifiCorp.
(c) These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc.
PMI") and a subsidiary of Idaho Power Company. PMI, a subsidiary of PacifiCorp, has a two-thirds interest in the joint
venture. The Bridger mine is in the process of conversion from surface operation to primarily underground operation,
while currently continuing production at its surface operations.
Recoverability by surface mining methods typically ranges from 90.0% to 95.0%. Recoverability by underground mining
techniques ranges from 50.0% to 70.0%. Most of PacifiCorp s coal reserves are held pursuant to leases from the federal
government through the Bureau of Land Management and from certain states and private parties. The leases generally have
http;//www .see.gov! Archives/edgar/data/75594!00OOO7559406000028/p 1 Ok.htm 5/31/06
Page 34 of 160
multi-year terms that may be renewed or extended and require payment ofrenls and royalties. In addition, federal and state
regulations require that comprehensive
http://www.sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
Page 35 of160
environmental protection and reclamation standards be met during the course of mining operations and upon completion of
mining activities. See "Item 8. Financial Statements and Supplementary Data - Note 6 - Asset Retirement Obligations and
Accrued Environmental Costs.
ITEM 3. LEGAL PROCEEDINGS
In October 2005, PacifiCorp was added as II defendant to a lawsuit originally filed in February 2005 in state district court in
Salt Lake City, Utah by USA Power, LLC and its affiliated companies, USA Power Partners, LLC and Spring Canyon, LLC
(collectively, "USA Power ), against Utah attorney lody L. Williams and the law firm Holme, Roberts & Owen, LLP, who
represent PacifiCorp on various matters from time to time. USA Power is the developer of n planned generation project in
Mona, Utah caIled Spring Canyon, which PacifiCorp, as part of its resource procurement process, at one time considered as
an alternative to the Currant Creek Power Plant. USA Power s complaint alleges thatPacifiCorp misappropriated confidential
proprietary information in violation ofUtab's Uniform Trade Secrets Act and accuses PacifiCo." of breach of contract and
related claims. USA Power seeks $250.0 million in damages, statutory doubling of damages for its trade secrets violation
claim, punitive damages, costs and attorneys' fees. PacifiCorp believes it has a number of defenses and intends to vigorously
oppose any claim of liability for the matters alleged by USA Power. Furthermore, PacifiCorp expect,; that the outcome of this
proceeding will not have a material impact on its consolidated financial position, results of operations or liquidity.
In October 2005, CCS filed a request for agency action with the UPSC. The request sought an order requiring PacifiCorp to
retum to Utah ratepayers certain monies collected in Utah rates for taxes, which the CCS alleges were improperly retained by
PacifiCorp s parent company, PHI. The CCS has publicly announced it is seeking a refund of at least $50.0 miUion to Utah
ratepayers. Following PacifiCorp s sale to MEHC in March 2006, the CCS, MEHC and intervening party Utah Industrial
Energy Consumers filed with the UPSC an agreement settling the claims made by the CCS. In exchange for dismissal of the
claims, MEHC agreed to contribute to PacifiCorp, at no cost, MEHC's 100.0% ownership interest in Intermountain
Geothermal Company, which controls 69.3% of the steam rights associated with the geothermal field serving PacifiCorp
Blundell Geothermal Plant in Utah. The settlement agreement has been approved by the UPSC, which dismissed the CCS
request.
In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by
the Klamath Tribes of Oregon, individual Klamath Tribal members and tbe Klamath Claims Committee. The complaint
generally alleges that PacifiCorp and its predecessors affected the Klamath Tribes' federal treaty rights to fish for salmon in
the headwaters of the Klamath River in southern Oregon by building dams that blocked the passage of salmon upstream to
the headwaters beginning in 1911. In September 2004, the Klamath Tribes filed their first amended complaint adding claims
of damage to their treaty rights to fish for sucker and steelhead in the headwaters of the Klamath River. TI1ecompiaint seeks
in excess of $1.0 billion in compensatory and punitive damages. In July 2005, the District Court dismissed the case and in
September 2005 denied the Klamath Tribes' request to reconsider the dismissal. In October 2005 , the Klamath Tribes
appealed the District Court's decision to the Ninth Circuit Court of Appeals and briefing was completed in March 2006. Any
final order wilt be subject to appeal. PacifiCorp believes the outcome of this proceeding will not have a material impact on its
consolidated financial position, results of operations or cash flow.
In April 2004, PacifiCorp filed a complaint with the federal district court in Wyoming challenging the WPSC decision made
in March 2003 to deny recovery of the Hunter No.1 replacement power costs and certain deferred excess net power costs.
The complaint was filed on the grounds that the decision violates federal law by denying PaciliCorp recovery in retail rates of
its wholesale electricity and transmission costs incurred to serve Wyoming customers. In February 2006, PacifiCorp and
certain parties intervening in its tben-pending Wyoming general rate case reached a settlement of the terms ofPacifiCorp
general rate case request. PacifiCorp also agreed to dismiss its federal lawsuit challenging the WPSC decision. TI1e case was
dismissed in May 2006.
In December 2004, a group of Utah customers filed a petition with the UPSC on behalf of themselves and other similarly
situated customers seeking monetary compensation from PacifiCorp as a result of a severe winter storm in December 2003.
TI1is petition was substantially similar to an April 2004 petition that the UPSC resolved by consolidating customer requests
with an ongoing regulatory winter storm inquiry. In May 2006, PucifiCorp reached a stipulation with the petitioners that
resolved an claims in consideration of system maintenance and vegetation management commitments and additional credits
for customers. The stipulation was approved by the UPSC on May 22, 2006.
http://www.sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.hoo 5/31/06
....-....-,............-...,
Page 36 of 160
ITEM 4.SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No information is required to be reported pursuant to this item.
PART II
ITEM 5.MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
PacifiCorp is an indirect subsidiary ofMEHC, which owns aU shares ofPacifiCorp s outstanding common stock. TI1erefore
there is no public market for PacifiCorp s common stock. Dividend information required by this item is included in "Item 8.
Financial Statements and Supplementary Data - Quarterly Financial Data.
The state regulatory orders that authorized the acquisition by MEHC contain restrictions on PacifiCorp s ability to pay
dividends to the extent t1mt they would reduce PacifiCorp s common stock equity below specified percentages of defined
capitalization.
As of March 3 I, 2006, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to PPW
Holdings LLC or MEHC without prior state regulatory approval to the extent that it would reduce PacifiCorp s common
stock equity below 48.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt.
After December 31 , 2008, this minimum level of common equity declines annually to 44.0% after December 31, 2011. TIle
terms of this commitment treat 50.0% ofPacifiCorp s preferred stock outstanding prior to the acquisition ofPacifiCorp by
MEHC as common equity. As of March 31, 2006, PacifiCorp s actual common stock equity percentage, as calculated under
this measure, exceeded the minimum threshold.
In addition, PacifiCorp is restricted from making any distributions to PPW Holdings LLC or MEHC ifPacifiCorp
unsecured debt rating is BBB- or lower by Standard & Poor s Rating Services or Fitch Ratings or Baa3 or lower by Moody
Investor Service, as indicated by two of the three rating services. As of March 31, 2006,PacifiCorp s unsecured debt rating
was BBB+ by Standard & Poor s Rating Services and Fitch Ratings and Baal by Moody s Investor Service.
PacifiCorp does not presently anticipate that it will declare dividends on common stock during the 12 months ending March
31,2007.
PacifiCorp is also subject to maximum debt-to-total capitalization ratios under various debt agreements. For further
discussion, see "Item 7. Management's Discussion and Analysis ofFinanciat Condition and Results of Operations - Liquidity
and Capital Resources,
http://www.see.gov/ Arehives/edgar/data/75594/000007 559406000028/p 1 Ok.htm 5/31/06
Page 37 of 160
ITEM 6.SELECTED FINANCIAL DATA (Unaudited)
Total
Years Ent!et! Mardi JI.
2006 2005 2004 2003 2002
$3,896.$3,048.$3,194.5 $3,082.4 $3,341.1
12.
896.$3,048.$3,194.$3,082.4 $3,353.
$ 792.$ 656.$ 617.$ 488.$ 598.
27.4
15.
$ 792.656.4 $ 617.$ 488.641.0
$ 360.251.7 $ 248.140.$ 327.
(Millions or t!ullan, euept per
share lint! employee amOIlIlII)
Revenues:
Electric Operations
Australian Operations
Other Operations (a)
Total
Income (loss) from operations:
Electric Operations
Australian Operations
Other Operations (a)
Net income
Earnings on common stock:
Continuing operations
Electric Operations
Australian Operations
Other Operations (a)
Total
Discontinued operations (b)
Cumulative effect of accounting change (c) (d) (e)
$ 358.$ 249.245.134.$ 232.
27.4
20.
358.249.245.134.280.
146.
(0.(1.9)(112.
358.$ 249.244.132.314.
1.00
At M:lreh 31.
2006 ZO05 2004 2003 2002
Total earnings on common stock
Common dividends declared per share
Common dividends paid per share
Capitalization:
Short-term debt
Long-term debt. including current maturities
Preferred Securities of Trusts
Preferred stock subject to mandatory redemption
Preferred stock
Common equity
184.4 $ 468.8 $ 124.9 $ 25.0 $ 177.
937.9 3 898.9 3 760.2 3,554.3 3,698.341.8 341.5
66.7 74.41.3 41.3
194.4 2,891.9
45.
41.3
010.
52.
41.3
335.
60.
41.3
278.
Total Capitalization $ 8,219.1 $ 7 797.3 $ 7 265.1 $ 7 223.5 $ 7 224.
Total assets $12 731.3 $12 520.9 $11,677.1 $11,695.8 $10,234.
Total employees 750 654 507 140 287
http://www.sec.gov/Archives/edgar/data/75 594/0000075 59406000028/p 1 Ok.htm 5/31/06
'-'-"-.."'--'.-"."."-'..-.-..--..-..-..................-...--------.-
Page 38 of 160
(c)
Other Operations includes the activities ofPacifiCorp Financial Services, Inc. and PacifiCorp Group Holdings
Company, until their transfer in February 2002 to PacifiCorp s former parent company, PHI.
The year ended March 31, 2002 includes the collection of a contingent note receivable relating to the discontinued
operations of a fonner mining and resource development business, NERCO, Inc.
The year ended March 31, 2004 reflects the effect of implementation of Statement of Financial Accounting Standards
SFAS") No. 143 Asset Retirement Obligatiolls SFAS No. 143"
The year ended March 3 I, 2003 reflects the effect of the implementation of the Derivatives Implementation Group (the
(a)
(b)
(d)
http://www.sec.gov/Archives/edgar/datal7 5594/000007 559406000028/p 1 Ok.htm 5/31/06
, --,.-..-..-..-..-....-."""-"'.'-"'....-......"'-'........-,-..,..........,'.,.....,.----..........--..'.,......--......----,--.,....".,-.....,...,...,-.."......,.....--
Page 39 of 160
(e)
DIG") Revised Issue C15. Normal Purchases and Nornw/ Sales Exceptiolllor Certain Optioll-Type Cot/tmcts and
Forward Contracts ill Electricity Issue CIS"), and Issue C 16 Applying the Normal Purchases alld No17nal Sales
Exception to COTltracts that Combine a Forward Collfract al/(i a Purchased Option Call tract Issue C 16"
The year ended March 31 , 2002, reflects the effect of the implementation of SF AS No. 133, AccOImfillgjor Derivative
Instl"lll1lellts and Hedging ActMties, as amended
, ("
SFAS No. 133"). Upon receiving regulatory approval, PacifiCorp
has subsequenUy recorded the effects of unrealized gains or losses on certain long.tenn contracts as regulatory assets
and liabilities.
http://www .sec.govl Archives/edgar/data/75594/000007559406000028/p lOk.htm 5/31/06
.........-.......-.,--.......,..-,.......,.....,..,--.......-..-...""'--......,....,--.--...-.......,.......,.... ...-.....-----.,.
Page 40 of 160
ITEM 7.MAJ'IAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
OVERVIEW
l11e Management s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements.
PacifiCorp is a regulated electricity company serving approximately 1.6 million retail customers in service territories
aggregating approximately 136,000 square miles in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and
California. The regulatory commissions in each state approve rates for retail electric sales within their respective states.
PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and to
incorporated municipalities. Wholesale activities are regulated by the FERC. PacifiCorp owns, or has interests in, 69 thermal
hydroelectric and wind generating plants, with an aggregate nameplate rating of 9 050.8 MW and plant net capability of
470.4 MW. The FERC and the six state regulatory commissions also have authority over the construction and operation of
PacifiCorp s electric generation facilities. PacifiCorp delivers electricity through approximately 59,510 miles of distribution
lines and approximately 15,580 miles of transmission lines.
Sale or PacifiCorp
As described in "Item 1. Business - Overview - Ownership by MEHC; Sale ofPacifiCorp," MEHC completed its acquisition
ofPacifiCorp from ScottishPower and PHI on March 21, 2006. MEHC purchased all PacifiCorp common stock for
approximately $5. I billion in cash.
In January through March 2006, the state commissions in all six states where PacifiCorp has retail customers approved
PacifiCorp s sale to MEHC. The approvals were conditioned on a number of regulatory commitments, including expected
financial benel1ts in the form of reduced corporate overhead and financing costs, certain mid- to long-term capital and other
expenditures of significant amounts and a commitment not to seek utility rate increases attributable solely to the change in
ownership. The capital and other expenditures proposed by MEHC and PacifiCorp include:
Approximately $812.0 mi11ion in investments (generally to be made over several years following the sale and subject
to subsequent regulatory review and approval) in emissions reduction technology for PllcifiCorp s existing coal plants
which, when coupled with the use of reduced emissions technology for anticipated new coal-fueled generation, is
expected to result in signil1cant reductions in emissions rates of sulfur dioxide, nitrogen oxide and mercury and to
avoid an increase in the carbon dioxide emissions rate;
Approximately $519.5 million in investments (to be made over several years following the sale and subject to
subsequent regulatory review and approval) in PacifiCorp s transmission and distribution system that would enhance
reliability, facilitate the receipt of renewable resources and enable further system optimization; and
TIle addition of 400.0 MW of cost-effective renewable resources to PacifiCorp s generation portfolio by December 31,
2007, including 100.0 MW of cost-effective wind resources by March 21 , 2007.
The commitments approved by the state commissions also include credits that wiIl reduce retail rates generally through 2010
to the extent that PacifiCorp does not achieve identified cost reductions or demonstrate mitigation of certain risks to
customers. The maxinmm potential value of these rate credits to customers in aU six states is $142.5 million. PacifiCorp and
MEHC have made additional commitments to the state commissions that limits the dividends PacifiCorp can make
to MEHC or its afliliates. As of March 31, 2006, the most restrictive of these commitments prohibits PacifiCorp from making
any distribution to PPW Holdings LLC or MEHC without prior state regulatory approval to the extent that it would reduce
PacifiCorp s common stock equity below 48.25% of its total capitalization, excluding short-term debt and current maturities
of long-term debt. After December 31, 2008, this minimum level of common equity declines annually to 44.0% after
December 31, 2011. 111e terms of this commitment treat 50.0% ofPacifiCorp s preferred stock outstanding prior to the
acquisition ofPacifiCorp by MEHC as common equity. As of March 31,2006, PacifiCorp s actual common stock equity
percentage, as calculated under this measure, exceeded the minimum threshold.
http://www.see.gov/Archives/edgar/datal? 5594/000007 559406000028/p 1 Ok.htm 5/31/06
, ,...,.....,-........-.......--,.-"-,.--....".,,.._,..-"........._,.,_.,..,........,......-.-
Page 41 of 160
Forward-Looldng Statements
This report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical fact, made in this report are forward.looking. When used in this
Management s Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this report, the
words "will,
" "
may,
" "
could," "believes,
" "
estimates,
" "
expects,
" "
anticipates,
" "
forecasts,
" "
plans," "intends,
" "
projec,ted,
potential" and variations of such words and similar expressions are intended to identify forward-looking statements.
Forward-looking statements included in this report relate to, among other matters, the effect on PacifiCorp of the following:
regulatory commitments related to PacifiCorp s sale to MEHC; recently enacted Oregon Senate Bill 408; potential
adjustment of regulatory rates to cover costs; growth of retail customers and demand; the impact of new accounting standards
or accounting policy changes; the outcome of litigation or regulatory proceedings; the timing of future regulatory filings;
environmental laws; federal energy policy and legislation; capital expenditure levels; results from, and the timing of, the
construction or repair of generating facilities; hydroelectric relicensing and decommissioning activities; electricity outages;
pension and other postretirement contributions; outcome of tax proceedings; growth in customers and usage; levels of
hydroelectric and thermal generation; sufficiency ofPacifiCorp s available funds to meet its liquidity needs and future
financing; off-balance sheet arrangements; the effect of risk management measures, including use of financial derivatives to
manage and mitigate interest rate exposure; fluctuations in forward prices for electricity and natural gas; and the efficiency
and effectiveness of PacifiCorp s resource and fuel procurement. Forward-looking statements reflect management's current
expectations, plans or projections and are inherently uncertain. There can be no assurance the results predicted will be
realized. Actual results may vary from those represented by the forecasts, and those variations may be material. The
following are among the factors, in addition to those set forth under "Item IA. Risk Factors," that could cause actual results
to differ materially from the forward-looking statements:
TIle outcome of general rate cases and other proceedings conducted by regulatory commissions or other governmental
and legal bodies;
Changes in prices and availability (for both purchases and sales) of wholesale electricity, natural gas and other fuel
sources and other changes in operating costs that could affect PacifiCorp s cost recovery;
Changes in regulatory requirements or other legislation, including the recently enacted federal Energy Policy Act of
2005, legislation or regulatory outcomes limiting the ability of public utilities to recover income tax expense in retail
rates such as Senate Bill 408, industry restructuring and deregulation initiatives;
Industrial, commercial and residential customer growth and demographic patterns in PacifiCorp s service territories;
Economic trends that could impact electricity usage;
Changes in weather conditions and other natural events that could affect customer dcmand or electricity supply;
A high degree of variance between actual and forecasted load and prices that could impact the hedging strategy and
costs to balance electricity load and supply;
Hydroelectric conditions, as welt as natural gas and coal production and price levels, that could have a significant
impact 011 electric capacity and cost and on PacifiCorp s ability to generate electricity;
Performance ofPacifiCorp s generation facilities, including the level of planned and unplanned outages;
The cost, feasibility and eventual outcome of hydroelectric facility relicensing proceedings;
Changes in, and compliance with, environmental and endangered species laws, regulations, decisions and policies that
could increase operating and capital improvement costs, reduce plant output and/or delay plant construction;
Changes resulting from MEHC ownership;
The impact of new accounting pronouncements or changes in current accounting estimates and assumptions on
financial position and results of operations;
http://www .see.gov! Archives!edgar/data/755941000007559406000028Ip 1 Ok.htm 5/31/06
Page 42 of 160
The impact of interest rates, investment performance and increases in health care costs on pension and post-retirement
expense;
Continued availability of funds to meet liquidity requirements;
The impact of any required performance under off-balance sheet arrangements;
Financial condition and creditworthiness of significant customers and suppliers;
The impact of financial derivatives used to mitigate or manage interest rate risk and volume and price risk due to
weather extremes;
Changes in PacifiCorp s credit ratings;
Timely and appropriate completion ofPacifiCorp s resource procurement process, unanticipated construction delays
changes in costs, receipt of required permits and authorizations, ability to fund resource projects and other factors that
could affect future generation plants and infrastructure additions;
Other risks or unforeseen events, including wars, the effects of terrorism, embargos and other catastrophic events; and
Other business or investment considerations that may be disclosed from time to time in SEC filings or in other publicly
disseminated written documents.
Any forward-looking statements issued by PacifiCorp should be considered in light of lhese factors. PacifiCorp does not
intend to update or revise any forward-looking statements to reflect actual results, changes in assumptions or changes in other
factors affecting such forward-looking statements or ifPacifiCorp later becomes aware lhat these assumptions are not likely
to be achieved.
Accounting Matters
Critical Accounting Estimates and Related Policies
The preparation of consolidated financial statements in confonnity with accounting principles generally accepted in the
United States requires management to make estimates and assumptions that affect the results of operations and the reported
amounts of assets and liabilities in the Consolidated Financial Statements. The estimates and assumptions may change as
time passes and accounting guidance evolves. Management bases its estimates and assumptions on historical experience and
on other various judgments that it believes are reasonable at the time of application. Changes in these estimates and
assumptions could have a material impact on the Consolidated Financial Statements. Ifestimates and assumptions are
different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new
information. Critical accounting estimates, in addition to certain less significant accounting estimates, are discussed with
senior members of management and PacifiCorp s Board of Directors, as appropriate, and were previously disclosed to the
ScottishPower Audit CommiUee and from March 21 , 2006 are disclosed to the MEHC Audit Committee. Those estimates
that management considers critical are described below.
;Derivatives
On April 1,2001, PacifiCorp adopted SFAS No. 133, as amended. PacifiCorp uses derivative instruments (primarily forward
purchases and sales) to manage the commodity price risk inherent in its fuel and electricity obligations, as well as to optimize
the value of power generation assets and related contracts. PacifiCorp also enters into short-term energy derivatives on n
limited basis for arbitrage purposes to take advantage of opportunities arising from market inefficiencies.
SFAS No. 133 requires that derivative instruments be recorded on the balance sheet at fair value. The fair values of derivative
instruments are determined using forward price curves. Forward price curves represent PacifiCorp s estimates of the prices at
which a buyer or seHer could contracttoclay for delivery or settlement of a commodity at future dates. PacifiCorp bases its
forward price curves upon market price quotations when available and uses internally developed, modeled prices when
market quotations are unavailable. In general, PacifiCorp estimates the fair value of a contract by calculating the present
value of the difference between the contract and lIte applicable forward price curve.
http://www.see.gov/ Archives/edgar/data/75594/000007 559406000028/p 1 Ok.htm 5/31/06
""".......-.".'..
m......
,.,...,...,.._.._._.........._...._-~..-
Page 43 of 160
Price quotations for certain major electricity trading hubs are generally readily obtainable for the first six years and, therefore
PacifiCorp s forward price curves for those locations and periods reflect observable market quotes. However, in the later
years or for locations that are not actively traded, forward price curves must be estimated in otIter ways. For short-term
contracts at less actively traded locations, prices are modeled based on observed historical price relationships with actively
traded locations. For long-term contracts extending beyond six years, the forward price curve is based upon the use of a
fundamentals model (cost-to-build approach), due to the limited information available. Factors used in the fundamentals
model include the forward prices for the commodities used as fuel to generate electricity, tbe expected system heat rate
(which measures the efficiency of power plants in converting fuel to electricity) in the region where the purchase or sale takes
place and a fundamentals forecast of expected spot prices for a commodity in a region based on modeled supply of and
demand for the commodity in the region. The assumptions in these models are critical, since any changes in assumptions
could have a significant impact on the fair value of the contract.
Despite the large volume of implementation guidance, SF AS No. 133 and the supplemental guidance do not provide specific
guidance on all contract issues. As a result, significant judgment must be used in applying SF AS No. 133 and its
interpretations.
Pensions and Other Postn~pt Bene~
PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees. In addition, certain bargaining
unit employees participate in a joint tmst plan to which PacifiCorp contributes. PacifiCorp accounts for these plans in
accordance with SF AS No. 87, Employers ' AccOI/IIlillgfor Pensions SFAS No. 87"). PacifiCorp accounts for its other
postretirement benefit plan in accordance with SF AS No.1 06, Employers ' Accol/lIting for Postretirement Benefits Other tltall
Pellsions SF AS No. 106"). TIle expense and benefit obligations relating to PacifiCorp s pension and other postretirement
benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates,
expected returns on plan assets, compensation increases, PacifiCorp contributions and health care cost trend rates. These
actuarial assumptions are reviewed annually and modified as appropriate. The effect of modifications is generally amortized
over future periods. PacifiCorp believes that the assumptions utilized in recording obligations under the plans are reasonable
based on prior experience, market conditions and the advice of plan actuaries. However, actual results may differ from such
assumptions.
The PacifiCorp Retirement Plan (the "Retirement Plan ) currently has assets with a fair value that is less than the
accumulated benefit obligation, primarily due to declines in the equity markets during calendar years 2000 through 2002 and
lower discount rates. PacifiCorp recognized a minimum pension liability in the three months ended March 31, 2003, and
continues to recognize this liability at March 31 , 2006. The liability adjustment did not affect tIte consolidated results of
operations. PacifiCorp requested and received accounting orders from the regulatory commissions in Utah, Oregon,
Wyoming and Washington to classify most of this charge as a Regulatory asset instead of a charge to Other comprehensive
income. This increase to Regulatory assets was adjusted as of March 31, 2006 and 2005 and wilt be adjusted in future periods
as the difference between the fair value of the tnast assets and the accumulated benefit obligation changes. PacifiCorp has
determined that costs related to SF AS No. 87 for the Retirement Plan are currently recoverable in rates.
PacifiCorp s contributions to the Retirement Plan have exceeded the minimum funding requirements of the Employee
Retirement Income Security Act ("ERISA"). PacifiCorp made $63.7 million in cash contributions to the Retirement Plan
during the year ended March 3 I , 2006, including those contributions made between the December 31 , 2005 measurement
date and March 31 , 2006, and made $61.6 million in cash contributions to the Retirement Plan during the year ended
March 31, 2005. In April 2006, PacifiCorp contributed $72.7 million to its Retirement Plan and expects to contribute another
$11.0 million to its pension plans in the 12 months ending March 31, 2007. PacifiCorp is funding the Retirement Plan at what
it believes to be an adequate leve1, but it currently expects to make larger cash contributions in the future due to its
underfunded pension obligation and ERISA requirements. Such cash requirements could be material to PacifiCorp s cash
flows. PacifiCorp believes it has adequate access to capital resources to support these contributions. As of March 31, 2006,
PacifiCorp s underfunded status of the pension plans was $513.6 million, including contributions made between the
December 31, 2005 measurement date and March 31 , 2006. For further details. see "Item 8. Financial Statements - Note 17 -
Employee Benefits," which are incorporated by reference into this Item 7.
http://www.sec.gov/ Archives/edgar/dataJ75594/000007559406000028/p 10k.htm 5/31/06
Page 44 of 160
PacifiCorp discounted its future pension and other postretirement plan obligations using a rate of 5.75% at March 31, 2006
and 2005. Thus, the discount rate used for PacifiCorp s expense during the 12 months ended March 3 1,2006 was 5.75% and
the discount rate that will be used for PacifiCorp s expense during the 12 months ending March 31 2007 witt also be 5.75%.
PacifiCorp chooses a discount rate based upon high quality fIxed-income investment yields. The pension and other
postretirement benefit liabilities, as well as expenses, increase as the discount rate is reduced.
At March 31, 2006, PacifiCorp assumed that the pension and other postretirement assets would generate n long-term rate of
return of 8.50% for the 12 months ending March 31, 2007 compared to au assumed rate of return of 8.75% for the year ended
March 31, 2006. In establishing its assumption as to the expected return on assets, PacifiCorp reviews the expected asset
atlocation and develops return assumptions for each asset class based on historical performance and independent advisors
forward-looking views of the fInancial markets. Pension and otl1er postretirement benefit expenses increase as the expected
rate ofretum on Retirement Plan and other postretirement benefit plan assets decreases.
Based on the above assumptions PacifiCorp expects to record pension expense of$71.0 million for the 12 months ending
March 31, 2007, compared to $63.8 million for the year ended March 31, 2006.
The following table reflects the sensitivities of the March 31, 2006 disclosures and the projected pension expense for the 12
months ending March 31, 2007 associated with a change in certain actuarial assumptions by the indicated percentage:
Aetu3rlal Assumption
Change In
Ass um p lion
ImpaClon
Projected
Denent Obligation
Increase
(DecrcQSc)
Impacl on
Minimum
Pension LIability
Increase
(Decrease)
hnpacl on Annual
Pension CoJl
Inere:ue
(Decrease)
(Mllllolls of dollan)
Expected long-term return on plan assets
Expected long-term return on plan assets
Discount rate
Discount rate
(0.5)% $
(4.
(0.89.77.
(83.(73.(8.
PaciftCorp expects to record other postretirement benefit expense of $36.6 million for the 12 months ending March 31 , 2007,
compared to $29.9 million for the year ended March 31, 2006. PacifiCorp has determined that costs related to SF AS No.1 06
for other postretirement benefits are currently recoverable in rates. PacifiCorp contributed $29.7 million for the year ended
March 31 , 2006 and $24.9 million for the year ended March 31 , 2005 to the funding vehicles for its postretirement benefit
plan. PacifiCorp expects to contribute $36.6 million to its other postretirement benefIt plans for the 12 months ending March
31,2007. As of March 31, 2006, PacifiCorp s tUlderfunded status of the other postretirement benefit plans was $260.
million, including contributions made between the December 31 , 2005 measurement date and March 31, 2006. For further
details, see "Item 8. Financial Statements - Note 17 - Employee Benefits," which are incorporated by reference into this Hem
In valuing its accumulated postretirement benefit obligation, PacifiCorp must make an assumption regarding future changes
in health ca-re costs. Assmned changes impact the obligation and expense as fottows:
Assumed health earc cllsllrend rates
Impaelon
Accumulated
Poslrellrement
nenelll Obllgallon
Increase (Decrease)
Impact IIn Annual
Other I'osirelirelllent
Renefll CDS!
Increase (Decrease)
(1\1l1l1ons of dollars)
One percentage point increase
One percentage point decrease
43.7 $
(35.(5.1 )
Rcgtl.l!ltim!
PacifiCorp prepares its Consolidated Financial Statements in accordance with SF AS No. 71 AccountillgJor the Effects of
Cerlai" Types of Reglliation SF AS No. 71 "). SF AS No. 71 requires PacifiCorp to reflect the impact of regulatory decisions
in its Consolidated Financial Statements and requires that certain costs be deferred on the balance sheet until matching
revenues can be recognized. Similarly, certain items may be deferred as regulatory liabilities and are amortized to the
Consolidated Statements of Income as rates to customers are reduced or costs
http://www.see.gov/Archives/edgar/datal?5594/00000? 5 59406000028/p 1 Ok.htm 5/31/06
Page 45 of 160
http://www .sec.govl Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
...."'--.....-.---...""'."..-......-...-".....,.."...--......" .............._-,-,................---_....
,......._....._m.__~
Page 46 of 160
previously recovered in rates are actual1y incurred. SF AS No. 71 provides that regulatory assets may be capitalized if it is
probable that future revenue in an amount at least equal to the capitalized costs will result from their treatment as al\owable
costs for rate-making purposes. In addition, the rate action should permit recovery of the specific previously incurred cost
rather than provide for expected levels of similar future costs.
PacifiCorp is subject to state and federal regulation. In the event of deregulation, PacifiCorp would seek recovery of its net
regulatory assets and any additional stranded costs. Ifunsuccessful, the unrecoverable portion of its net regulatory assets
would be written-off and PacifiCorp would evaluate the remaining assets on its balance sheet for impairment in accordance
with SFAS No. 144 AccOImtil/gfor tIre Impairment or Dispo.wl afLolIg-Lived Assets. PacifiCorp is unable to predict the
likelihood of deregulation and its future impacts.
At I..-Iarch 31, 2006, PacifiCorp had recorded specifically identified regulatory assets, net of regulatory liabilities, totaling
$174.3 million. In the event PacifiCorp stopped applying SF AS No. 71 at March 31, 2006, an after-tax loss of approximately
$108.2 million would be recognized.
U II b.llw_tv C II
Electricity sales to retail customers are determined based on meter readings taken throughout the month. PacifiCorp accmes
an estimate of unbilled revenues, net of estimated line losses, each month for electric service provided after the meter reading
date to the end of the month. The unbilled revenue estimate is based on three components: PacifiCorp s total electricity
delivered during the month, assignment of un billed revenues to customer type and valuation of the unbiUed energy. Factors
involved in the estimation of consumption and line losses relate to weather conditions. amount of natural light, historical
trends, economic impacts and customer type. Valuation of un billed energy is based on estimating the average price for the
month for each customer type. These estimates can vary significantly from period to period depending on monthly weather
patterns, customers' space heating and cooling, production levels due to economic activity or changing irrigation patterns due
to precipitation conditions.
Differences between estimated unbilled revenue and the subsequently billed revenue would most likely occur due to the
variation in assignments of customer usage by revenue class and jurisdiction or variations from estimates of line losses due to
changes related to line capacity utilization and weather conditions. At March 31,2006, the amount accrued for unbilted
revenues was $148.2 million.
ContingILncies
PacifiCorp fotIows SPAS No. Accorll/ti/Jgfor Camillgellcies SFAS No.), to determine accounting and disclosure
requirements for contingencies. According to SFAS No., an estimated loss from a contingency shan be charged to income
if (i) it is probable that an asset has been impaired or a liability has been incurred at the date of the financial statements, and
(ii) the amount of the loss can be reasonably estimated. Disclosure in the notes to the financial statements is required for loss
contingencies not meeting both of these conditions if there is a reasonable possibility that a loss may have been incurred.
Gain contingencies are not recorded untit realized.
PacifiCorp operates in a highly regulated environment. Governmental bodies such as the FERC, state regulatory
commissions, the SEC, Internal Revenue Service, Department of Labor, the EP A and others have authority over various
D.spects ofPacifiCorp s business operations and public reporting. Reserves are established when required based upon
management's best judgment. Appropriate disclosures are made regarding litigation , tax matters, environmental issues,
assessments and creditworthiness of customers orcounterparties, among others. The evaluation of tl1ese contingencies is
performed by various specialists inside and outside of PacifiCorp. Accounting for contingencies requires significant
judgment by management regarding the estimated probabilities and ranges of exposure to potential loss. Management's
assessment of PacifiCorp s exposure to contingencies could change as new developments occur or more information
becomes available. 111e outcome of the contingencies could vary significantly and could materially impact PacifiCorp
consolidated financial position, results of operations and cash flows. Management has used its best judgment in applying
SF AS No.5 to these matters.
Ncw A(:counting Standards
For new accounting standards, see "Item S. Financial Statements - Note I - Summary of Significant Accounting Policies,
which are incorporated by reference into this Item 7.
http://www.sec.gov/Archives/edgar/datal?5594/000007 5 59406000028/p 1 Ok.htm 5/31/06
"'..-.--.....-"'."
Page 47 of 160
http://www.see.gov! Archives/edgar/datal7 5594!000007559406000028!p 1 Ok.htm 5/31/06
Page 48 of 160
RESULTS OF OPERATIONS
Overview
PacifiCorp s net income was $360.7 million for the year ended March 31 , 2006 compared to $251.7 million for the year
ended March 31 , 2005. Significant factors affecting results for the year ended March 3 I. 2006 included higher retail prices
approved by regulators, customer growth and a net increase in customer usage, as well as increased generation output
partially offset by higher operations and maintenance expense, including employee-related expenses, and the impact of
increased fuel prices. TIte increase in net income was also significantly affected by a $78.4 million increase in net unrealized
gains on wholesale sales, wholesale purchase and fuel contracts primarily due to movements in forward prices.
Retail energy sales volumes grew by 2.4% in the year ended March 31, 2006 compared to the year ended March 31 , 2005.
PacifiCorp s number of retail customers has been increasing by approximately 2.0% annually over the past four years. This
trend is expected to continue for the foreseeable future. Increased customer usage, which also contributed to the higher
volumes, is generally affected by economic and weather conditions, consumer trends and energy savings programs.
In recent years, PacifiCorp has filed general rate cases in all six states where it has retail customers, with the objective of
keeping customer rates closely aligned to ongoing operating costs and to recover costs of capital investments. PacifiCorp may
make additional general rate case filings in certain states over the coming year. PacifiCorp s regulatory program has also
included various other filings such as proposed power cost adjustment mechanisms. See "Item L Business - Regulation" for
developments regarding state regulatory issues and pending rate case filings.
PacifiCorp relies on electricity generated by its thermal facilities to meet a substantial portion of its customer load.
PacifiCorp s maintenance and overhaul programs are utilized to facilitate reliable generation availability at its thermal
facilities through planned outages, but PacifiCorp still may experience unplanned outages. During these outage periods, other
owned generation or wholesale market purchases are utilized to balance system requirements. PacifiCorp s hydroelectric
facilities are utilized as lower-cost sources of electricity generation but are dependent upon precipitation, temperatures and
other variables. Wholesale energy sales and purchase contracts are utilized to balance PacifiCorp s physical excess or
shortage of net electricity and are impacted by the movements in the market prices of both natural gas and electricity. While
increased thermal generation output reduces the need for wholesale market purchases, its financial impact can be
significantly affected by market prices for coal and natural gas.
Output from PacifiCorp s them1al plants increased by 1,055,579 megawatt-hours ("MWh"), or 2., during the year ended
March 31, 2006 compared to the year ended March 31, 2005. The Currant Creek Power Plant commenced full combined-
cycle operation in March 2006, adding 523.0 MW of capability to PacifiCorp s generation portfolio. Construction of the Lake
Side Power Plant is progressing and is expected to begin operations in May 2007. Once in full commercial operation, the
Lake Side Power Plant wilt add an estimated capability of 550.0 MW to meet expected future energy needs.
Output from PacifiCorp-owned hydroelectric facilities fQf the year ended March 31 2006 increased by 1,074,640 MWh, or
35.0%, as compared to the year ended March 31 , 2005. This increase was primarily attributable to current-year water
conditions that, although slightly lower than normal, improved relative to the prior-year period. PacifiCorp s hydroelectric
generation was 98.2% of normal for the year ended March 31 , 2006, based on a 30-year average. Hydroelectric generation
has been below normal for the past six years. PacifiCorp cannot predict if this trend will continue in future years.
PacifiCorp continues to experience increasing employee costs primarily due to rising healthcare and pension costs, additional
employees and normal annual salary and wage increases. Pension costs continue to increase as a result of previous years
decreases in discount rates, which result in increases in PacifiCorp s projected benefit obligation, as well as the recognition of
deferred losses from previous years' lower-than-expected plan asset returns.
http://www .see.goy/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31106
........-,-.....,-...-.--...,
.....on.._
......""""""'-
Page 49 of 160
Wholesale energy sales and purchase contracts that meet the definition of a derivative are recorded at fair value. For
derivative contracts, when forward prices arc higher than contract prices, wholesale energy sales contracts will have
unrealized losses and wholesale purchase contracts will have unrealized gains. TI1e opposite is true when forward prices are
lower than contract prices. Unrealized gains and losses will reverse in future periods when the contracts settle at contract
prices. They do not result in cash collections or payments other than in obtaining or providing cash collateral required in
support of certain contracts. See "Item 8. Financial Statements - Note 3 - Derivative Insbllments" for a summary of
unrealized gains and losses on wholesale energy sales and purchase contracts.
Year Ended March 31,2006 Compared to Year Ended March 31, 200S
Revcnues
Retail
Wholesale sales and other
Year Ended March 31,Favora blet( U nravorable)
2006 200S S Change I. Change
808.648.159.
088.400.688.1 172.
896.048.847.27.
112 48,919 193 2.4
640 605
(Millions or dollars)
Total revenues
Retail energy sales (thousands ofMWh)
Total retail customers (in thousands)
Retail revetlues increased $159.8 million, or 6.0%, primarily due to:
. $74.1 million of increases from higher prices approved by regulators;
$43.2 million of increases relnted to growth in the number of residential and commercial customers;
$28.7 million ofincreases due to higher average residential and industrial customer usage, net of decreases in
commercial and other customer usage; and
$13.8 mil1ion of increases due to changes in price mix, resulting from the levels of customer usage at different
customer tariffs in the various states that PacifiCorp serves.
Wholesale sales ami other revelUlI!s increased $688.1 million, or 172., primarily due to:
$554.4 mi11iol1 of increases from higher unrealized gains on short- and long-term energy sales contracts recorded at fair
value, primarily due to changes in forward prices;
$108.7 million of increases in wholesale electric sales, primarily due to higher prices;
$29.2 million of increases resulting from sales of sulfur dioxide emission allowances;
$11.0 million of increases in wholesale natural gas sales: and
$8.2 million of increases in revenues from the settlement of amounts previously disputed with third parties; partially
offset by,
$28.2 million of decreases related to non-physically settled system balancing transactions.
Operating Expenscs
(!\IllIIons or dollars)Year Ended March 31.Fa\'orab 1et( Un fa \'orable)
2006 200S S ClulIlge
Energy costs 545.948.(597.
Operations and maintenance 014.913.1 (101.4)
Depreciation and amortization 448.436.(11.4)
Taxes, other than income laxes 96.94.4 (2.4)
OJ. Change
(63.0)%
(11.1)
(2.
(2.
http://www.sec.gov/ Archives/edgar/datal7 SS94/000007S59406000028/p 1 Ok.htm 5/31/06
Page 50 of 160
Total operating expenses $ 3,104.7 $ 2 392.4 $(712.3)(29.
E/lergy costs increased $597.1 million, or 63., primarily due to:
. $469.5 million of increases from higher unrealized losses on short- and long-term energy purchase contracts recorded
at fair value, primarily due to changes in forward prices;
$43.5 million of increases related to unfavorable changes in the fair value of streamflow weather derivative contracts
resulting primarily from improved streamflow conditions in the current year compared to prior forecasts;
http://www.see.gov/Archives/edgar/datal7 5594/000007 559406000028/p 1 Ok.htm 5/31/06
Page 51 of 160
$40.7 million of increases in purchased electricity due to higher prices and volumes;
$14.8 million of increases related to higher volumes of coal consumed due primarily to an increase in thermal
generation;
$13.9 mi11ion of increases related to higher prices for coal consumed; and
$11.2 million of increases related to higher wheeling expenses.
Operations mId maintenallce expense increased $101.4 million, or 11.1 %, primarily due to:
. $43.7 million of increases in employee expenses, primarily due to an increase in beadcount and higher benefit and
pension costs;
$17.0 million in employee severance expense incurred during the current year;
$11.3 million of increases in materials and supplies utilized in plant overhaul activities;
$9.7 million of increases in third-party contract and service fees; and
$7.2 million of increases from services rendered by Scottish Power UK pic prior to the sale of PncifiCorp to MEHC.
and charged to PacifiCorp pursuant to the affiliated interest cross-charge policy.
DepreciatiOll and amortizatioll expellse increased $11.4 million, or 2.6%, primarily due to:
. $13.9 million of increases in depreciation expense due to additions to plant in service; partially offset by,
$3.0 million of decreases in amortization expense predominantly due to certain capitalized software becoming fully
amortized.
Interest and Other (Income) Expense
(Millions of dollars)Year Ended !\larch 31,FavorableJ(Unfnvof:.ble)
2006 200S S Change % Change
279.267.4 (12.(4.7)%
(9.5)(9.0.4 4.4
(32.4)(14.17.118.
(6.(7.3)(1.2)(16.4)
231.9 236.1.8
Interest expense
Interest income
Interest capitalized
Minority interest and other
Total
Illterest expellse increased $12.5 million, or 4.7%, primarily due to:
Higher average debt outstanding and higher variable rates during the year ended March 31 , 2006; partial1y offset by,
Lower average fIXed rates on long-term debt during the year ended March 3 I , 2006.
Iltterest capitalized increased $17.6 million, or 118., primarily due to higher average construction work-in-progress
balances that qualify for capitalized interest and higher capitalization rates during the year ended March 31,2006.
Millori!)' illterest alld otlrer e..~pellse changed $1.2 mil1ion, primarily due to lower gains on net investments for the year
ended March 31, 2006 compared to the year ended March 31, 2005.
Income Tax Expense
Income tax expense increased $30.9 million, or 18.3%, primarily due to:
. $49.0 million of increases due to higher levels of income from continuing operations before income taxes for the year
ended March 31 , 2006; and
$9.7 million ofincreases in the income tax contingency reserve; partial1y offset by,
$9.2 million of decreases from the tax effect ofthe regulatory treatment of book and tax depreciation differences of
http://www.see.gov/ Archives/edgar/data/7 5594/000007559406000028/p 1 Ok.htm 5/31/06
Page 52 of 160
$3.1 million and of the regulatory treatment of other differences of$6.1 million;
$5.4 million of decreases due to permanent book and tax differences of Internal Revenue Service settlements in the
prior year;
$5.0 million of decreases from the tax effect of increases in depletion expense; and
$4.3 million of decreases from the tax effect of certain state income tax credits.
http://www.sec.gov/Archives/edgar/datal7 5594/000007 559406000028/p 1 Ok.htm 5/31/06
Page 53 of 160
Year Ended March 31, 2005 Compared to Year Ended Marcia 31, 2t104
Revenues
Retail
Wholesale sales and other
Year Ended March 31,FII\'orableJ(Unra~orable)
2005 2004 S Change ~. Change
648.547.101.8
400.647.(247.5)(38.
048.194.(145.(4.
919 679 240
605 570
(Mllllolls of dollan)
Total revenues
Retail energy sales (thousands ofMWh)
Total retail customers (in thousands)
Retnil revelUles increased $101.8 million, or 4., primarily due to:
. $108.9 million of increases from higher prices approved by regulators; and
. $49.0 million of increases relating to growth in the number of residential, commercial and industrial customers; partially
offset by,
. $39.8 million of decreases from lower average residential customer usage, net of increases in commerciailisage; and
. $7.3 million of decreases due to'a change in price mix, which resulted from the levels of customer usage at different
customer tariffs in the various states that PacifiCorp serves.
Wholesale .mles allli otller reI/elUteS decreased $247.5 million, or 38.2%, primarily due to:
. $300.6 million of decreases from higher unrealized losses on short- and long-term energy sales contracts recorded at fair
value, primarily due to changes in forward prices; and
. $48.1 million of decreases related to non-physically settled system balancing transactions; partially offset by,
. $47.2 million of increases due to higher revenues related to regulatory asset recovery, including $27.9 million due to a
new tariff in Utah;
$45.9 million of increases in wholesale electric sales due to higher volumes and prices; and
. $2.8 million of increases due to higher wheeling revenue.
Operating Expenses
Energy Cosls
Operations and maintenance
Depreciation and amortization
Taxes, other than income taxes
Year Ended Murch 31,Fa~orablel(U nravorable)
2005 2004 S Change ~. Change
948.156.208.18.
913.895.(17.3)(1.9)
436.428.(8.(1.9)
94.4 95.
392.4 576.184.
(Millions ordollan)
Total operating expenses
Ellergy costs decreased $208.7 million, or 18~O%, primarily due 10:
. $302,9 million of decreases from higher unrealized gains on short- and long-term energy purchase contracts recorded at
fair value, primarily due 10 changes in forward prices;
http://www.see.goy/ Archives/edgar/datal? 5594/000007559406000028/p 1 Ok.htm 5/31/06
Page 54 of 160
. $27.5 million of decreases due to favorable changes in fair value on streamflow weather derivative contracts; and
. $9.9 million of decreases due to lower volumes of coal consumed due mainly to a reduction in thermal plant generation;
partially offset by,
$98.4 million of increases in purchased electricity due to higher volumes and prict.'s; and
. $30.0 million of increases due to higher prices for coal consumed.
http://www.sec.gov/Archives/edgar/datal? 5594/000007 559406000028/p 10k.htm 5/31/06
Page 55 of 160
Operat;olls ami ma;lItellal/Ce expell.'ie increased $17.3 million, or 1.9%, primarily due to:
. $44.3 million of increases in employee salary expense and other direct employee expenses, primarily due to an increase in
headcount and higher benefit and pension costs;
. $14.9 million of increases from services rendered by Scottish Power UK pic and charged to PacifiCorp pursuant to
ScottishPower s affiliated interest cross-charge policy, which became effective April 1 , 2004; and
$12.1 million of net increases due to changes in regulatory assets and liabilities, including $27.0 million of increased
Utah demand-side management amortization; partially offset by,
. $26.9 million of decreases in third-party contract and service fees, including a reduction in the use of contractors for
certain activities, including information tec1mology, planned outages and field operations;
$5.5 million of a decrease due to the recognition of claims in the prior year due to the bankruptcy of an insurance carrier;
and
. $5.5 million of decreases in insurance costs.
Depreciat;oIJ ami amort;zat;oll expense increased $8.1 million, or 1.9%, primarily due to:
. $15.8 million of increases in depreciation and amortization expense due to an increase in plant in service; and
$4.6 million of increases in amortization expense due to higher capitalized software balances; partially offset by,
. $12.9 million of decreases in capitalized software amortization following II change in the estimated useful lives of certain
computer software systems.
Interest and Other (Income) Expense
Total
Year Ended March 31,FII\'orablel(Unfavorlible)
2005 2004 S Change % Change
267.4 256.5 (10.(4.2)%
(9.1)(13.(4.(34. I)
(14.(19.(5.(25.
(7.1.6 556.
236.224.(11.8)(5.
(Millions of dollars)
Interest expense
Interest income
Interest capitalized
Minority interest and other
Illterest e.\:pense increased $10.9 mi\lion, or 4.2%, primarily due to $8.9 million of increases resulting from an increase in
average amount of debt outstanding, due in part to the refinancing of$352.0 million of Preferred securities redeemed in
August 2003 with long-term debt, partially offset by a decrease in average interest rates.
I"terest ;Ircome decreased $4.7 million, or 34.1%, primarily due to decreases in interest income on regulatory assets.
IIrterest capitalized decreased $5.1 million, or 25., primarily due to lower average capitalization rates applied to higher
qualifying construction work-in-progress balances during the year ended March 3 1,2005.
Millor;t)' ;lIterest ami otller e.v:pellse changed $8.9 million, primarily due to:
$11.7 million ofa decrease in expense relating to distributions on Preferred securities, which were redeemed in August
2003;
. $2.3 million of a decrease in charitable donations; partially offset by,
$4.3 million of an increase in income relating to proceeds from company-owned life insurance.
Income Tax Expense
Income tax expense increased $24.0 million, or 16.6%, primarily due to:
http://www .see.govl Arehives/edgar/data/75594/000007559406000028/p 10k.htm 5/31/06
Page 56 of 160
. $14.2 million of increases in the federal tax contingency reserve due to $8.5 million of additional accruals in the current
year related to new activities/development of tax examinations, compared to $5.7 million of contingency reserve releases
in the prior year due to the resolution of certain tax examinations;
. $9.5 million of increases due to higher levels of income from continuing operations before income taxes and cumulative
effect of accounting change for 111e year ended March 31, 2005; and
$5.4 million of increases due to permanent book and tax differences ofIntemal Revenue Service settlements; partially
offset by,
. $3.9 million of decreases from the tax. effect of regulatory treatment of book and tax differences; and
. $3.7 million of decreases in state income lax effect.
http://www .see.gov/ Arehives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
,.-..--.....-...-.....-...-...........-.-.......-....."..,-.-......-....--
Page 57 of 160
LIQUIDITY AND CAPITAL RESOURCES
Sources and Uses of Cas"
PacifiCorp depends on both internal and external sources of liquidity to provide working capital and to fund capital
requirements. Short-term cash requirements not met by cash provided by operating activities are generally satisfied with
proceeds from short-term borrowings. Long-term cash needs arc met through sales of securities, il1c1uding additional long-
term debt issuances, and, in the past, also by issuance of common stock to PacifiCorp s former parent company, PHI.
PacifiCorp expects it will need additional periodic equity contributions from its e"isting parent over the next five years.
Issuance of longer-term securities is influenced by levels of short-term debt, cash from operations, capital expenditures,
market conditions, regulatory approvals and other considerations.
Operating Activities
Net cash flows provided by operating activities increased $183.5 million to $894.6 mi11ion for the year ended March 31 2006
compared to $7 11.1 million for the year ended March 31,2005, primarily due to higher retail revenues, increased generation
output, reduced net cash collateral requirements and the net impact of the timing of cash collection and payments, partially
offset by increases in income tax payments and higher fucl inventory levels.
Net cash provided by operating activities decreased $120.8 million to $71 1.1 million for the year ended March 31, 2005
compared to $831.9 million for the year ended March 31, 2004, due primarily to increases in net cash collateral requirements;
increases in the level of funding for pension and other postretirement benefit p1ans; higher inventory levels; and the net
impact of the timing of cash collection and payments.
Investing Activities
Net cash used in investing activities. increased $177.4 million to $1 024.1 million for tIle year ended March 31, 2006
primarily due to higher capital expenditures during the year ended March 31, 2006 compared to the prior year. Capital
expenditures totaled $1 049.0 miUion for the year ended March 31 2006, compared to $851.6 million for the year ended
March 31, 2005. The increase was primarily due to $109.7 million of increased expenditures on tl1e construction of the Lake
Side Power Plant, increases in various capital projects related to transmission and distribution and other themal and
hydroelectric facilities and $58.5 million for the installation of emission control equipment at the Huntington Power Plant
partially offset by $113.9 miUion of decreases in expenditures for the Currant Creek Plant. Expenditures for the Lake Side
Power Plant will continue to be capitalized as construction work-in-progress until the plant is placed into service, which is
expected to occur by May 2007 . The Currant Creek Power Plant was completed in simple and combined-cycle phases. "TIle
simple-cycle phase was placed into service during May and June 2005 and combined-cycle phase was placed into service
during March 2006.
Net cash used in investing activities increased $143.2 million to $846.7 million for the year ended March 31, 2005, primarily
due to higher capital expenditures during the year ended March 31 , 2005 compared to the prior year. Capital expenditures
totaled $851.6 million for the year ended March 31, 2005, compared to $690.4 million for the year ended March 31 2004.
The increase was primarily due to $158.9 million of increased e"penditures on the construction of the Currant Creek Power
Plant and $49.6 million for construction of the Lake Side Power Plant, partially offset by lower e"penditures on the
distribution and transmission upgrades along the Wasatch Front in Utah, as well as reductions in other capital expenditures.
Financing Activities
hort- Term Debt
PacifiCorp s short-term debt decreased by $284.4 million during the year ended March 31 2006 to $184.4 million, primarily
due to proceeds from long-term debt and common stock financing during the period, partially offset by capital expenditures
in excess of net cash from operations. Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which
$ 184.4 million was outstanding at March 31, 2006, with a weighted-average interest rate of 4.8%.
http://www .see.gov/ Arehives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
, .-..........-..-..,.,.......----..,......-.-.
Page 58 of 160
PacifiCorp s short.term debt increased by $343.9 million during the year ended March 31 2005 to $468.8 million, primarily
due to capital expenditures in excess of net cash from operations and pre-funding of maturing long-term debt, partially offset
by the proceeds from the long-term debt fmancing during the period, Short-term debt increased by $99.9 million during the
year cnded March 31, 2004, primarily due to changes in working capital, maturing long-term debt, increased capital
expenditures and the resumption of paying dividends on common shares.
Rcvolvil g Credit Agreeme
PacifiCorp s short-term borrowings and certain other financing arrangements are supported by an $800.0 million committed
bank revolving credit agreement, which was amended during August 2005. Changes included an increase to 65.0% in the
covenant not to exceed a specified debt-to-capitalization percentage, extension of the termination date to August 2010 and
exclusion of the acquisition ofPacifiCorp by MEHC as an event of default under tbe agreement. The interest rate on
advances under this facility is generally based on the London Interbank Offered Rate (LIBOR) plus a margin that varies
based on PacifiCorp s credit ratings. As of March 31,2006, this facility was fully available and there were no borrowings
outstanding. In addition to this committed credit facility, at March 31, 2006, PacifiCorp had $79.6 million in money market
accounts included in Cash and casllequivalents available to meet its liquidity needs.
PacifiCorp s revolving credit agreement contains customary covemmts and default provisions, which PacifiCorp monitors on
a regular basis. As of March 31, 2006, PacifiCorp was in compliance with the covenants of its revolving credit agreement,
which also apply to its letters of credit. See "Future Uses of Cash - Contractual Obligations and Commercial Commitments -
Commercial Commitments" below for information regarding PacifiCorp s letters of credit.
J,..ong- Term Debt
During the year ended March 31, 2006, PacifiCorp made scheduled long-term debt repayments of $269.7 million.
In June 2005, PacifiCorp issued $300.0 million of its 5.25% Series of First Mortgage Bonds due June 15, 2035. PacifiCorp
used the proceeds for the reduction of short-term debt, including the short-tern1 debt used in December 2004 to redeem its
625% Series of First Mortgage Bonds due December 13, 2024 totaling $20.0 million.
During the year ended March 31, 2005, PacifiCorp made scheduled long-tenn debt repayments of $239.8 million.
Additionally, during December 2004, PacifiCorp redeemed, prior to maturity, all of the 8.625% First Mortgage Bonds due
December 13, 2024 totaling $20.0 million.
In March 2005, the maturity dates for three series of variable-rate pollution-control revenue bonds totaling $38.1 million
were extended to December I, 2020.
In August 2004, PacifiCorp issued $200.0 million of its 4.95% Series of First Mortgage Bonds due August 15 2014 and
$200.0 million of its 5.90% Series of First Mortgage Bonds due August 15 2034. PacifiCorp used the proceeds for general
corporate purposes, including the reduction of short-tenn debt.
For the year ended March 31, 2004, PacifiCorp made scheduled long-tem1 debt repayments of $136.6 million. Additionally,
during July and August 2003, PacifiCorp redeemed, prior to maturity, First Mortgage Bonds totaling $57.5 million and
Preferred Securities totaling $352.0 million. These retirements were funded initially with short-term debt. In September 2003,
PacifiCorp issued $200.0 million of its 4.30% First Mortgage Bonds due September 15, 2008 and $200.0 million of its 5.45%
First Mortgage Bonds due September i5, 2013.
PacifiCorp s Mortgage and Deed of Trust creates a lien on most of PacifiCorp s electric utility property, allowing the
issuance of bonds based on:
. A percentage of utility property additions;
Bond credits arising from retirement of previously outstanding bonds; and/or
Deposits of cash.
http://www.see.gov/ Archives/edgar/data/75594/000007 559406000028/p 1 Ok.htm 5/31/06
..-..-......,-..-.....-..-...-
Page 59 of 160
TIle amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of March 31 , 2006
PacifiCorp estimated it would be able to issue up to $4.7 billion of new First Mortgage Bonds under the most restrictive
issuance test in the mortgage. Any issuances would be subject to market conditions and amounts may be further limited by
regulatory authorizations or commitments or by covenants and tests contained in other financing agreements. PacifiCorp also
has the ability to release property from the lien of the Mortgage on the basis of property additions, bond credits and/or
deposits of cash. See also "Limitations" below.
During September 2005, the SEC declared effective PacifiCorp s shelf registration statement covering $700.0 million of
future first mortgage bond and unsecured debt issuances. PacifiCorp has not yet issued any of the securities covered by this
registration statement.
PacifiCorp has state regulatory authority to issue up to an additional $700.0 million of long-term debt from the UPSC, OPUC
and IPUC and up to $100.0 million of first mortgage bonds from the WUTC. An additional filing will be made with the
WUTC prior to any future issuances.
Common Stock
During the year ended March 31, 2006, PacifiCorp issued 44 884 826 shares of its common stock to PHI, its former parent
company, at a total price of $484.7 million. PacifiCorp used the proceeds from the sale of these shares for the reduction of
short-term debt.
PacifiCorp expects to seek amendments to existing state regulatory aul1lOrity or new authorizations that would permit the
issuance of its common stock to PPW Holdings LLC.
Preferred Stock Redemptions
PacifiCorp redeemed $7.5 million of Preferred stock subject to mandatory and optional redemption during each of the years
ended March 31, 2006,2005 and 2004.
Dividends
During the year ended March 31, 2006, PacifiCorp had the following dividend activity:
. $175.0 million declared and paid on common stock;
. $5.6 million declared on preferred stock and preferred stock subject to mandatory redemption, of which $3.5 million was
recorded as interest expense; and
. $5.8 million paid on preferred stock and preferred stock subject to mandatory redemption.
On March 20, 2006. immediately prior to the closing ofPacifiCorp s sale to MEI-IC, PacifiCorp paid a dividend on conunon
stock, at that lime held by PHI, in the aggregate amount of$16.8 million. 'nle dividend was reduced pursuant to Amendment
No.1 to the Stock Purchase Agreement among l'vIEHC, ScottishPower and PHI executed on the date of the transaction' s
closing from the $56.6 million aggregate amount originally declared by the PacifiCorp Board of Directors on January 27
2006.
During the year ended March 3 1,2005. PacifiCorp had the following dividend activity:
. $193.3 million declared and paid on common stock;
. $6.1 million declared on preferred stock and preferred stock subject to mandatory redemption, of which $4.0 million was
recorded as interest expense; and
. $6.2 million paid on preferred stock and preferred stock subject to mandatory redemption.
During the year ended March 31, 2004, PacifiCorp had the following dividend activity:
. $160.6 million declared and paid on common stock;
. $6.7 million declared on preferred stock and preferred stock subject to mandatory redemption, of which $3.4 million was
recorded as interest expense; and
. $6.8 million paid on preferred stock and preferred stock subjeclto mandatory redemption.
http://www .see.goy/ Arehives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
Page 60 of 160
http://www .see.gov/ Arehivesledgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
"".."."."_.".."....""."."._-,,,, ..--,--...."..,...----..-..-"-"."... " .." "-",-,---,.,-""-",,,-,,,.-,-""""""-"'-""""""""'-"""'."'-""."""""" .
",w..
,,-...-..""""-"."'.----
Page 61 of160
Cipll!ili1JtljJrn
Total capitalization
March 31.
2006 2005
184.4 468.
937.47.898.50.
45.52.
41.3 41.3 0.5
010.48.335.42.
219.100.797.100.
(Millions ordollars)
Short-tenD debt
Long-tenn debt, including current maturities
Preferred stock subject to mandatory redemption
Preferred stock
Common equity
PacifiCorp manages its capitalization and liquidity position with a key objective of retaining existing credit ratings, which is
expected to facilitate continuing access to flexible borrowing arrangements at favorable costs and rates. l1\is objective,
subject to periodic review and revision, attempts to balance the interests of alt shareholders, ratepayers and creditors and to
provide a competitive cost of capital and predictable capital market access.
As a result of recent changes in accounting standards, such as FIN 46R Conso/idatiorr of Variab/e-lnlere~.t Errtities. arr
interpretatioll of ACCOlll11illg Research BlIlletill No. 5/. and ElTF No. 01-08, Deteml;llillg Wlletller all Arrllllgelllellt Is a
Lease it is possible that new purchase power and gas agreements, transmission arrangements or amendments to existing
arrangements may be accounted foras capital lease obligations or debt on PacifiCorp s fmancial statements. While
PacifiCorp has successfully amended covenants in financing arrangements that may be impacted by these changes, it may be
more difficult for PacifiCorp to comply with its capitalization targets or regulatory commitments conceming minimum levels
of common equity as a percentage of capitalization. 111is may lead PacifiCorp to seek amendments or waivers from
regulators, delay or reduce dividends or spending programs, seek additional new common equity contributions from its
immediate parent, PPW Holdings LLC, or take other actions.
Limit~tionli
In addition to PacifiCorp s capital structure objectives, its debt capacity is also governed by its contractual and regulatory
commitments.
PacifiCorp s credit agreement contains customary covenants and default provisions, including a covenant not to exceed a
specified debt-to-capitalization ratio of 65.0%. As of March 31, 2006, management believes that PacifiCorp could have
borrowed an additional $3.3 biIlion without exceeding this threshold. Any additional borrowings would be subject to market
conditions, and amounts may be further limited by regulatory authorizations or by covenants and tests contained in other
financing agreements.
fl\e state regulatory orders that authorized the acquisition by MEHC contain restrictions on PacifiCorp s ability to pay
common dividends to the extent that they would reduce PacifiCorp s common stock equity below specified percentages of
defined capitalization.
As of March 31, 2006, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to PPW
Holdings LiC or MEHC without prior state regulatory approval to the extent that it would reduce PacifiCorp s common
stock equity below 48.25% of its total capitalization, excluding short-term debt and current maturities oftong-term debt.
After December 31, 2008, this minimum level of common equity declines annually to 44.0% after December 31, 2011. The
terms of this commitment treat 50.0% ofPacifiCorp s preferred stock outstanding prior to the acquisition ofPacifiCorp by
MEHC as common equity. As of March 31, 2006, PacifiCorp s actual common stock equity percentage, as calculated under
this measure, exceeded the minimum threshold.
http://www ,see.goy/ Archiyes/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
Page 62 of 160
http://www.sec.gov/ Archives/edgar/data/75594/000007 559406000028/p Ok.htm 5/31/06
., .-....-.--.......-..--.....---,-,....
Page 63 of 160
FUTURE USES OF CASH
Dividends
PacifiCorp does not presently anticipate that it will declare dividends on common stock during the 12 months ending March
2007.
Capital Expenditure Program
Actual capital expenditures were $1,049.0 rnittion for the year ended March 31 , 2006 and $851.6 million for the year ended
March 31, 200S. Estimated capital expenditures for the 12 months ending Marel) 31, 2007 are expected to be approximately
$1.1 biIlion, which include $129.2 million for emissions control equipment to address current and anticipated air quality
regulations, $137.9 million for generation development projects, and $875.1 million for ongoing operational projects.
In conjunction with state regulatory approvals of the PacifiCorp acquisition, :MEHC and PacifiCorp committed to invest
$812.0 million in capital spending for emission control equipment to address current and future air quality
initiatives implemented by the EP A or by the states in which PacifiCorp operates facilities. Additional capital
expenditures for emission reduction projects may be required, depending on the outcome of pending or new air
quality regulations. TIle actual and estimated expenditures for emissions control equipment include amounts for installation
of equipment at the Huntington Power Plant. The actual expenditures for the Huntington Power Plant were $59.6 miltion for
the year ended March 31, 2006. The estimated expenditures for the 12 months ending March 31, 2007 are $68.7 million.
In March 2006, PacifiCorp completed construction of the Currant Creek Power Plant, a 523.MW combined-cycle plant in
Utah. Total project costs incurred through March 31, 2006 were approximately $338.0 million. The estimates provided above
for generation development projects include the remaining costs to have the Lake Side Power Plant constructed, as well as
upgrades of other generation plant equipment. As of March 31, 2006, $208.9 million of the $347.0 million expected total cost
for the Lake Side Power Plant had been incurred.
PacifiCorp is focused on infrastmcture improvement projects in targeted areas to improve customer service and network
safety and enhance system reliability and performance. PacifiCorp and MEHC have committed to a number oftransmissi()I1
and distribution system investments in connection with regulatory approval ofPacifiCorp s sale to MEHC. Approximately
$519.5 mi11ion in investments in PacifiCorp s transmission and distribution system are expected over the next several years
of which $13.9 mi1lion are currently estimated to be incurred during the 12 months ending March 31,2007.
AII of these expenditures are subject to continuing review and revision by PacifiCorp, and actual costs could vary from
estimates due to various factors, such as changes in business conditions, revised load-growth estimates, future legislative and
regulatory developments, increasing costs in labor, equipment and materials, competition in the industry for similar
technology and management's strategies for achieving compliance with regulations. The estimates of capital expenditures for
the 12 months ending March 31, 2007 generalIy excludes the potential impact on generation and transmission capacity of
future decisions arising from further stages ofPacifiCorp s various Integrated Resource Plans. Additional expenditures may
be significant but are spread over a number of years and cannot be accurately estimated at this time. Based on future
decisions arising from the Integrated Resource Plan process, including wind generation projects, the estimate of capital
expenditures may be revised.
In funding its capital expenditure program, PacifiCorp expects to obtain funds required for construction and tither purposes
from sources similar to those used in the past, including operating cash flows, the issuance of new long-term and short-term
debt and equity contributions from MEHC.
http;//www .see.gov/ Arehives/edgar/data/75594/000007559406000028/p 10k.htm 5/31/06
-.....--....,.-.-.....,........-.....---.-..........-.......-...-...-..-,-..,--..-..,--.-..-.-.....".-..---
Page 64 of 160
Contraclual Obligations and Commercial Commitments
Co.!ltr!ltll1J11 Obli ations
TIlc table below shows PacifiCorp s contractual obligations as of March 31 , 2006.
(MIllions Clf dollars)aymenls due during the 12 munlhs endll1gMarth 31,
2007 2008.2009 Thereafter Total2010-2011
Long-term debt, including interest:
Fixed-rate obligations 429.911.479.223.044.
Variable-rate obligations (3)17.4 34.34.690.777.
Short-term debt, including interest 185.185.
Preferred stock subject to mandatory redemption 41.3 45.
Capilalleases, including interest 63.88.
Operating leases (b)15.18.46.
Asset retirement obligations (c)34.35.356.433.
Power purchase agreements: (d)
Electricity commodity contracts 603.380.211.4 667.862.
Electricity capacity contracts 136.299.310.4 301.1 048.
Electricity mixed contracts 16.30.26.178.252.1
Transmission 45.77.72.503.698.
Fuel purchase agreements: (d)
Natural gas supply and transporation 317.4 678.433.869.299.
Coal supply and transportation 199.4 444.358.062.064.5
Purchase obligations (e)123.42.170.5
Owned hydroelectric commitments (0 28.71.7 66.469.637.
Other long-term liabilities (g)20.
Total contractual cash obligations 138.080.049.$ 10 405.$ 17,672.
(a)Consists of principal and interest for pollution-control revenue bond obligations with interest rates scheduled to reset
within the next 12 months. Future variable interest rates are set at March 31, 2006 rates. See "Item 7A. Interest Rate
Risk" for additional discussion related to variable-rate liabilities.
Excludcd from these amounts are power purchase agreements that meet the definition of an operating lease. Such
amounts are included with power purchase agreements.
Represents expected cash payments adjusted for inflation for estimated costs 10 perform legally required asset
retirement activities.
Commodity contracts are agreements for the delivery of energy. Cilpacity contracts are agreements that provide rights
to the energy output ofa specified facility. Forecasted or other applicable estimated prices were used to determine total
dollar value of the commitments for purposes of the table. Amounts included in power purchase agreements include
those agreements that meet the definition of an operating lease.
(ncludes minimum commitments for maintenance, outsourcing of certain services, contracts for software. telephone
data and consulting or advisory services. Also includes contractual obligations for engineering, procurement and
construction costs on the Lake Side Power Plant and Huntington Power Plant emission control equipment.
n1C purchase obligation amounts consist of items for which PacifiCorp is contractually obligated to purchase from a
third party as of March 31, 2006. These amounts only constitute the known portion ofPacifiCorp sexpected future
expenses; therefore, the amounts presented in the table will not provide a reliable indicator ofPacifiCorp s expected
future cash outflows on a stand-alone basis. For purposes of identifying and accumulating purchase obligations
PacifiCorp has included all contracts meeting the definition of a purchase obligation (e., legally binding and
specifying all significant terms, including fixed or minimum amount or quantity to be purchased and the approximate
timing of the transaction). For those contracts involving a fixed or minimum quantity but variable pricing, PacifiCorp
has estimated the contractual obligation based on its best estimate of pricing that will be in effect at the time the
(b)
(c)
(d)
(e)
http://www.see.goY/ArchiYes/edgar/datal75 594/000007 559406000028/p 1 Ok.htm 5/31/06
obligation is incurred.
Page 65 of 160
http://www .see.goy/ Arehives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
.-..-....-..-.--.,.-......,.-..-.....-....--..-..-..-.
Page 66 of 160
(g)
PacifiCorp has entered into settlement agreements with various interested parties to resolve issues necessary to obtain
new hydroelectric licenses from the FERC. 111ese settlement agreements generally include clauses that allow for
termination of certain ofPacifiCorp s obligations if the FERC license order is not consistent with the settlement
agreement. The table only indudes contractual obligations made in settlement agreements tbat arc not contingent upon
the FERC license being consistent with the settlement agreement and obligations that are required by the FERC
licenses. Hydroelectric licenses have varying expiration dates, and several expire within the next five years. The
contractual obligations included in the table expire with the license expiration dates. However. PacifiCorp plans to
acquire new licenses that wilt al1ow for continued operation for more than 30 years and expects contractual obligations
to continue or increase.
Includes environmental commitments recorded on the balance sheet that are contractually or legally binding. Excludes
regulatory liabilities and employee benefit plan obligations that are not legally or contractually fixed as to timing and
amount. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each
discrete year.
(f)
~rn.mlli!nLC!ll1J. m It !I " t s
At March 3 J , 2006, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements
available to provide credit enhancement and liquidity support for variable.rate poIJution-control revenue bond obligations. In
addition, PacifiCorp had approximately $40.5 million of standby letters of credit to provide credit support for certain
transactions as requested by third parties. These committed bank arrangements were all fully available as of March 31 2006
and expire periodicalty through the 12 months ending March 31. 2011.
PacifiCorp s standby letters of credit and standby bond purchase agreements generally contain similar covenants to those
contained in PacifiCorp s revolving credit agreement. See "Financing Activities - Revolving Credit Agreement" for further
information. However, the maximum debt-to-capitatization ratio for one of these arrangements was 60.0% as of March 31,
2006 and was amended in May 2006 to now permit a maximum ratio of 65.0%. PacifiCorp monitors these covenants on a
regular basis and at March 31 , 2006, was in compliance with the covenants of these agreements.
PacifiCorp s commercial commitments include surety bonds that provide indemnities for PacifiCorp in relation to various
commitments it has to tllird parties for obligations in the event of default on behalf of PacifiCorp. TIle majority of these
bonds are continuous in nature and renew annually. Based on current contractual commitments, PacifiCorp s level of surety
bonding beyond the year ended March 31, 2006, is estimated to be approximately $27.3 mHlion. TIlis estimate is based on
current information and actual amounts may vary due to rate changes or changes to the general operations of PacifiCorp.
CREDIT RATINGS
PacifiCorp s credit ratings at March 31 , 2006, were as follows:
Moody Sllindard & Poor
Issuer/Corporate
Senior secured debt
Senior unsecured debt
Preferred stock
Commercial paper
Outlook
Baal
Baal
Baa3
Stable
BBB+
BBB
Stable
In February 2006, Moody s Investors Service affirmed the issuer and securities ratings of PacifiCorp and changed the ratings
outlook to stable from developing. In March 2006, Standard & Poor s Rating Services affirmed the corporate credit ratings
and securities ratings ofPacifiCorp and changed the ratings outlook to stable from CreditWatch with negative implications.
Also in March 2006, Standard & Poor s Rating Services raised the short-term rating for PacifiCorp to A-I from A.
PncifiCorp has no rating-downgrade triggers that would accelerate tile maturity dates of its debt. A change in ratings is not an
event of default, nor is the maintenance ora specific minimum level of credit rating a condition to drawing upon PacifiCorp
credit agreement. However, interest rates on loans under the revolving credit agreement and
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
.......--,........-..."--..-.....-_........._"".,......~.....".......,......,..,,_.........., ....,--",-,.,...,.,..,...,......,.,...
,..""....._...........m..
.""",,"_."""'.. " ... .......
Page 67 of 160
http://www .sec.gov/ Archives/edgar/datal7 5594/000007 559406000028/p 1 Ok.htm 5/31/06
...-..-....-.....---..--....". ......................,...--.....-......,...-........-.-..........
Page 68 of 160
commitment fees are tied to credit ratings and would increase or decrease when ratings are changed. A ratings downgrade
may reduce the accessibility and increase the cost of PacifiCorp s commercial paper program, its principal source of short-
tenn borrowing, and may result in the requirement that PacifiCorp post collateral under certain ofPacifiCorp s power
purchase and other agreements. Certain authorizations or exemptions by regulatory commissions for the issuance of securities
are valid as long as PacifiCorp maintains investment-grade ratings on senior secured debt. A downgrade below that level
would necessitate new regulatory applications and approvals.
In conjunction with its risk management activities, PacifiCorp must meet credit quality standards as required by
counterparties. In accordance with industry practice, contractual agreements that govern PacifiCorp s energy management
activities either specifically providc bilateral rights to demand cash or other security if credit exposures on a net basis exceed
certain ratings-dependent threshold levels or provide the right for collnterparties to demand "adequate assurances" in the
event of a material adverse change in PacifiCorp s creditworthiness. If one or more ofPacifiCorp s credit ratings decline
below investment gradc, PacifiCorp would be required to post cash collateral, letters of credit or other similar credit
support to facilitate ongoing wholesale energy management activities. As of March 31 2006, PacifiCorp s credit ratings from
Standard & Poor s and Moody s were investment grade; however, if the ratings fen more than one rating below investment
grade, PacifiCorp s estimated potential collateral requirements totaled approximately $334.0 million. ,PacifiCorp s potential
collateral requirements could fluctuate considerably due to seasonality, market prices and their volatility, a loss of
key PacifiCorp generating facilities or other related factors.
OFF-BALANCE SHEET ARRANGEMENTS
PacifiCorp from time to time enters into arrangements in the normal course of business to facilitate commercial transactions
with third parties that involve guarantee, indemnification or similar arrangements. PacifiCorp currently has indemnification
obligations for breaches of warranties or covenants in connection with the sale of certain assets. In addition, PacifiCorp
evaluates potential obligations that arise out of variable interests in unconsolidated entities, determined in accordance with
the F ASB Interpretation No. 46, Consolidation of Variable-Interest Emities. all interpretation of Accolmthlg Research
BlIlIetin No.5 J . PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant
losses associated with any of these obligations is remote. See "Item 8. Financial Statements and Supplementary Data - Note
11 - Guarantees and Other Commitments" and "Note 13 - Consolidation of Variable-Interest Entities" for more information
on these obligations and arrangements.
INFLATION
PacifiCorp is subject to rate-or-return regulation and the impact of inflation on the level of cost recovery under regulation
varies by state depending upon the type of test-period convention used in the slate. In PacifiCorp s state jurisdictions, a 12-
month period of historical costs is typically used as the basis for developing a "test year " which may also include various
adjustments to eliminate abnormal or one time events, normalize cost levels, or escalate the historical costs to a future level
when the new rates wilt actually be in effect. To the extent that the levels of costs beyond the historical 12-month period can
be established either through known adjustments or through the escalation of cost levels in establishing prices, PacifiCorp can
mitigate the impacts of inflationary pressures. The majority ofPacifiCorp s retail customer prices are established using
forecasts. These forecasts may include, but are not limited 10, projected rate base levels and expenses, which are adjusted for
both inflation and known and measurable changes. They may also include projected revenue and power cost changes related
to load growth.
ITEM 7A. QUANTITATIVE AND QUALlT A TIVE DISCLOSURES ABOUT MARKET RISK
PacifiCorp participates in a wholesale energy market that includes public utility companies. electricity and natural gas
marketers, financial institutions, industrial companies and govenunent entities. A variety of products exist in this market
ranging from electricity and natural gas purchases and sales for physical delivery to financial instruments such as futures,
swaps, options and other complex derivatives. Transactions may be conducted directly with customers and suppliers, through
brokers, or with an exchange that selVes as a central clearing mechanism.
http://www.sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
,-...-,....,.....-.---....-..-...,... ".,.,.,-.""",,..,".-".'-'.""'-.'... ,. ...----..-.., ...-, ...",... ..' ,..., .._, -,.... -.. . ,....,.. -........... ,.. -.., ..........- ,...-..... ,- .-- ,. ,-.-... ....... -.., -, .-,....... ,'" ....... -. - - --.-..,.. ...- -- ,., '.. ," -. .-,--..-...... ---..--
Page 69 of 160
PacifiCorp is subject to the various risks inherent in the energy business, including credit risk, interest rate risk and
commodity price risk.
Risk Management
PacifiCorp has a risk management committee that is responsible for the oversight of market and credit risk relating to the
commodity transactions ofPacifiCorp. To limit PacifiCorp s exposure to market and credit risk, the risk management
committee sets policies and limits and approves commodity stmtegies, which are reviewed frequently to respond to changing
market conditions.
Risk is an inherent part of PacifiCorp s business and activities. The risk management process established by PacifiCorp is
designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business
and activities and to measure quantitative market risk exposure and identify qualitative market risk exposure in its businesses.
To assist in managing the volatility relating to these exposures, PacifiCorp enters into various transactions, including
derivative transactions, consistent with PacifiCorp s risk management policy and procedures. The risk management policy
goven1S energy transactions and is designed for hedging PacifiCorp s existing energy and asset exposures, and to a limited
extent, the policy permits arbitrage activities to take advantage of market inefficiencies. TIle policy and procedures also
govern PacifiCorp s use of derivative instruments for commodity derivative transactions, as well as its energy purchase and
sales pmctices, and describe PacifiCorp s credit policy and management information systems required to effectively monitor
such derivative use. PacifiCorp s risk management policy provides for t11e use of only those instruments that have a similar
volume or price relationship to its portfolio of assets, liabilities or anticipated transactions, thereby ensuring that such
instruments witt be primarily used for hedging. PacifiCorp s portfolio of energy derivatives is substantially used for non.
trading purposes.
PacifiCorp continues to actively manage its exposure to conunodity price volatility. TIlese activities may include adding to
the generation portfolio and entering into transactions that help to shape PacifiCorp s system resource portfolio, including
wholesale contracts and financially settled temperature-related derivative instruments that reduce volume and price risk dueto weather extremes.
Credit Risk
Credit risk relates to the risk of loss that might occur as a result of non-performance by counterparties of their contractual
obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of
these obligations. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar
economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly
affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a collnterparty may
default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances
involving other market participants that have a direct or indirect relationship with such counterparty.
PacifiCorp seeks to mitigate credit risk (and concentmtions of credit risk) by applying specific eligibility criteria to
prospective counterparties. However, despite mitigation efforts, defaults by counterparties occur from time to time.
PacifiCorp continues to actively monitor the creditworthiness of counterparties with whom it transacts and uses a variety of
risk mitigation techniques to limit its exposure as it believes appropriate. When PacifiCorp considers a new asset purchase
transaction or contractual arrangement, market liquidity and the ability to optimize the investment are main considerations.
To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp has entered into netting and collateral
arrangements that include margining and cross-product netting agreements and obtaining third-party guamntees, letters of
credit and cash deposits. Counterparties may be assessed interest fees for delayed receipts. If required, PacifiCorp exercises
rights under these arrangements, including calling on the counterparty s credit support arrangement.
http :lIwww sec.gov/ Archives/edgar/datal7 5594/000007559406000028/p 1 Ok.htm 5/31/06
Page 70 of 160
The following table represents PacifiCorp s March 31 , 2006 distribution of unsecured credit exposure, net of collateral
within its electricity and natural gas portfolio of purchase and sale contracts and takes into account contractual netting rights.
f)lslrlbulion nfCredlt E:r;pnsure % urTolal
Investment grade - Externally rated
Non-investment grade - Externally rated
Investment grade - InternaUy rated
Non-investment grade - Internally rated
81.6%
18.
1O0.0'Yu
Externally rated" represents enterprise relationships that have published ratings from at least one major credit rating agency.
Internally rated" represents those relationships that have no rating by a major credit rating agency. For those relationships
PacifiCorp utilizes internally developed, commercially appropriate rating methodologies and credit scoring models to
develop a public rating equivalent.
TIle "Non-investment grade - Internally rated" component of PacifiCorp s overall credit exposure reflects the market value
of a small number of contracts that support PacifiCorp s Integrated Resource Plan and Oregon s electric energy restructuring
legislation as it relates to renewable energy projects, as well as compliance with FERC regulations requiring utilities to
purchase power from qualifying facilities.
Interest Rate Risk
PacifiCorp is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and
commercial paper. PacifiCorp manages its interest rate exposure by maintaining a blend of fixed-rate and variable-rate debt
and by monitoring the effects of market changes in interest rates. Changing interest rates will affect interest paid on variable-
rate debt and interest earned by PacifiCorp s pension plan assets, mining reclamation trust funds and cash balances.
PacifiCorp s principal sources of variable-rate debt are commercial paper and pollution-control revenue bonds remarketed on
a periodic basis. Commercial paper is periodically refinanced with fixed-rate debt when needed and when interest rates are
considered favorable. PacifiCorp may also enter into financial derivative instruments, including interest rate swaps,
swaptions and United States Treasury lock agreements, to manage and mitigate interest rate exposure. PacifiCorp does not
anticipate using financial derivatives as the principal means of managing interest rate exposure. PacifiCorp s weighted-
average cost of debt is recoverable in rates. Increases or decreases in interest rates are reflected in PacifiCorp s cost of debt
calculation as rate cases are filed. Any adverse change to PacifiCorp s credit rating could negatively impact PacifiCorp
ability to borrow and the interest rates that are charged.
As of March 31, 2006, PacifiCorp had fixed-rate long-term liabilities of$3,405.4 million in ag1.rregate principal amount and
having a fair value of $3,597.1 million. These instruments have fixed interest rates and therefore do not expose PacifiCorp to
the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would decrease
by approximately $114.3 million if interest rates were to increase by 10.0% from their levels at March 31 , 2006. In general
such a decrease in fair value would impact earnings and cash flows only if PacifiCorp were to reacquire all or a portion of
these instruments prior to their maturity.
As of March 31, 2006, PacifiCorp had $726.1 million of variable-rate liabilities and $113.6 million of temporary cash
investments compared to $1 010.5 million ofvariablc-rate liabilities and $182.2 million of temporary cash investments at
March 31, 2005. At March 31 , 2006 and 2005, PacifiCorp had no financial derivatives in effect relating to interest rate
exposure.
Based on a sensitivity analysis as of March 31, 2006, for a one-year horizon, PacifiCorp estimates t11at if market interest rates
average 1.0% higher (tower) during the 12 months ending March 31 , 2007 than during the year ended March 31, 2006,
interest expense, net of offsetting impacts on interest income, would increase (decrease) by $6.1 million. Comparatively,
based on a sensitivity analysis as of March 31 , 2005, for a one-year horizon, had interest rates averaged 1.0% higher (lower)
during the year ended March 31 , 2006 than during the year ended March 31, 2005, PacifiCorp estimated that interest
expense, net of offsetting impacts in interest income, would have increased (decreased) by $8.3 million. These amounts
include the effect of invested cash and were determined by considering the impact of the hypothetical interest rates on the
variable-rate securities outstanding as of March 31 2006 and 2005. The decrease in interest rate sensitivity is primarily due
to the decrease in outstanding variable-rate
http://www.sec.gov/ Archives/edgar/datal75594/000007 559406000028/p 1 Ok.htm 5/31/06
....-....,.---..-........,.--..-..,-.---.--..........".,
Page 71 of160
http;//www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
,.----.,---...' ,...' ,-,"'-"'.'..-."-..'..".-."",.. ,..,........-..-..,-...,.,-..,---.
..._c.......
,............-....,....,..,.".,.-,--."",-"","'."'--"""-""."--'."'.""""""""'-"'.""""'.-"""'."""".""""""-""."'-"""".."."-""""."'-"""',---
Page 72 of 160
commercial paper, partially offset by the decrease in invested cash. If interest rates change significantly, PacifiCorp might
take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that migbt be taken
and their possible effects, the sensitivity analysis assumes no changes in PacifiCorp' s financial structure.
Commodity Price Risk
PacifiCorp s exposure to market risk due to commodity price change is primarily related to its fuel and electricity
commodities, which are subject to fluctuations due to unpredictable factors, such as weather, electricity demand and plant
performance, that affect energy supply and demand. PacifiCorp s energy purchase and sales activities are governed by
PacifiCorp s risk management policy and tbe risk levels established as part ofiliat policy.
PacifiCorp s energy commodity price exposure arises primarily from its electric supply obligation in the western United
States. PacifiCorp manages this risk principally through the operation of its generation plants with a net capability of 8,470.4
, as well as transmission rights 11eld both on some ofits own 15,580-mile transmission system and on third-party
transmission systems, and through its wbolesale energy purchase and sales activities. Wholesale contracts are utilized
primarily to balance PacifiCorp s physical excess or shortage of net electricity for future time periods. Financially settled
contracts are utilized to further mitigate commodity price risk. PacifiCorp may from time to time enter into other financially
settled, temperaturc.related derivative instruments that reduce volume and price risk on days with weather extremes. 1n
addition, a financially settled hydroelectric streamflow hedge is in place through September 2006 to reduce volume and price
risks associated with PacifiCorp s hydroelectric generation resources.
PacifiCorp measures the market risk in its electricity and natural gas portfolio daily, utilizing a historical Value-at-Risk
VaR") approach and other measurements of net position. PacifiCorp also monitors its portfolio exposure to market risk in
comparison to established thresholds and measures its open positions subject to price risk in terms of quantity at each
delivery location for each forward time period.
VaR computations for the electricity and natural gas commodity portfolio are based on a historical simulation technique,
utilizing historical price changes over a specified (holding) period to simulate potential forward energy market price curve
movements to estimate the potential unfavorable impact of such price changes on the portfolio positions scheduled to settle
within the following 24 months. The quantification of market risk using VaR provides a consistent measure of risk across
PacifiCorp s continually changing portfolio. VaR represents an estimate of possible changes at a given level of confidence in
fair value that would be measured on its portfolio assuming hypothetical movements in future market rates and is not
necessarily indicative of actual results that may occur.
PacifiCorp s VaR computations for its electricity and natural gas commodity portfolio utilize several key assumptions
including a 99.0% confidence level for the resultant price changes and a holding period of five business days. The calculation
includes short-term derivative commodity instruments held for risk mitigation and balancing purposes, the expected resource
and demand obligations from PacifiCorp s long-term contracts, the expected generation levels from PacifiCorp s generation
assets and tlte expected retail and wholesale load levels. The portfolio reflects flexibility contained in contracts and assets,
which accommodate the normal variability in PacifiCorp s demand obligations and generation availability. These contracts
and assets are valued to reflect the variability PacifiCorp experiences as a load-serving entity. Contracts or assets that contain
flexible elements are often referred to as having embedded options or option characteristics. These options provide for energy
volume changes that are sensitive to market price changes. Therefore, changes in the option values affect the energy position
of the portfolio with respect to market prices, and this effect is calculated daily. When measuring portfolio exposure through
VaR, these position changes that result from the option sensitivity are held constant through the historical simulation to avoid
understating VaR.
http://www .see.goy/ Arehiyes/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
- ----....---..-.,...-...---"-"-- ."-_."_._--_._"'~""'.'-----"----"'" ".-----"-.---."'..""'.""'.'---.-.--"".'---."'.'.-"-"""",.-""".--,,-----..'-"""" ,--......,....-..---.--""..--- -.. -. '.' "....,~",,~_._------.--....-,,=
Page 73 of 160
As of March 31,2006, PacitiCorp s estimated potential five-day unfavorable impact on fair value ofthe electricity and
natural gas commodity portfolio over the next 24 months was $22.4 million, as measured by the VaR computations described
above, compared to $15.5 million as of March 31,2005. -DIe minimum, average and maximum daily VaR (five-day holding
periods) for the years ended March 31, 2006 and 2005 are as follows:
Minimum VaR (measured)
Average VaR (calculated)
Maximum VaR (measured)
PacifiCorp maintained compliance with its VaR limit procedures during the year ended March 31, 2006. Changes in markets
inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.
2006 2005
10.
16.16.
46.26.
(Millions of dollars)
Fair Value of Derivatives
The following table shows the changes in the fair value of energy-related contracts subject to the requirements of SF AS No.
133 from April I, 2005, to March 31, 2006 and quantifies tIle reasons for the changes.
Net Asset (Liability)
TradIng Non-trading
Regulatory
Net ,\sse I
(I. lability) (b)
(MillIons or dollars)
Fair value of contracts outstanding at March 3 I, 2005
Contracts realized or otherwise settled during the period
Other changes in fair values (a)
2 $
(0.
(154.4) $
(115.
277.
170.
128.3
(203.
Fair value of contracts outstanding at March 31, 2006 2 $7 $94.
(a) Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates, including
those based on models, on new and existing contracts.
(b) Net unrealized losses (gains) related to derivative contracts included in rates are recorded as a regulatory net asset
(liability).
The fair value of derivative instmments is determined using forward price curves. Forward price curves represent
PacifiCorp 'sestimates of the prices at which a buyer or seller could contract today for delivery or settlement of a commodity
at nlture dales. PacifiCorp bases its forward price curves upon market price quotations when available and internalIy
developed and commercial models with internal and external fundamental data inputs when market quotations are
unavailable. In general, PacifiCorp estimates the fair value of a contract by calculating the present value of the difference
between the prices in the contract and the applicable forward price curve. Price quotations for certain major electricity trading
hubs are generally rendily obtainable for the first six years, and thereforePacifiCorp s fo1"\vard price curves for those
locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively
traded, PacifiCorp must develop fo1"\vard price curves. For short-term contracts at less actively traded locations, prices are
modeled based on observed historical price relationships with actively traded locations. For long-term contracts extending
beyond six years, the fo1"\vard price curve is based upon the use ofa fundamentals model (cost-to-build approach) due to the
limited information available. Factors used in the fundamentals model include the fo1"\vard prices for the commodities used as
fuel to generate electricity, the expected system heat rate (which measures the efficiency of electricity plants in converting
fuel to electricity) in the region where the purchase or sale takes place and a fundamental forecast of expected spot prices
based on modeled supply and demand in the region. The assumptions in these models are critical since any changes to the
assumptions could have a significant impact on the fair value of the contract. Contracts with explicit or embedded optionality
are valued by separating each contract into its physical and financial forward and option components. Fo1"\vard components
are valued against the appropriate fo1"\vard price curve. The optionality is valued using a modified Black-Scholes model or a
stochastic simulation (Monte Carlo) approach. Each option component is modeled and valucd separately using the
appropriate fo1"\vard price curve.
PacifiCorp s valuation models and assumptions are continuously updated to reflect current market information, and
evaluations and refinements of model assumptions are performed on a periodic basis.
http://www.see.goy/ Archiyes/edgar/data/75594/000007 559406000028fp 1 Ok.htm 5/31/06
,....-,..-----.....-..-..--...--.......--,..-.-..---.......-..--..,..,-
Page 74 of 160
http://www.sec.gov/ Archives/edgar/data175594/000007S59406000028/p lOk.htm 5/31/06
..-.....---....,-......-....--.".....-..-,..-....,",...",...-..-.--..--..-,--.--...,-""",.---...,.......,.,,-,....-.,...-,.-..-..--"".'-.'..'-"-.
' w
'-_._---'._--""".' ,..",.-..,--"",,,.., , "",,~-_._,._--"'-"'_."'..-"'.
Page 75 of 160
The following table shows summarized infonnation with respect to valuation techniques and contractual maturities of
PacifiCorp s energy-related contracts qualifying as derivatives under SFAS No. 133 as of March 31 2006.
(Mllllolls urllullars)Fair "alue or Contracts al rcrlotl-Etld
Maturity
css Than
t Year
Maturity
1-3 Ycars
l\Iaturlly
5 Ycars
Maturity In
EucSlur
5 Years
Total
Fair
Valuc
Trading:
Values based on quoted market prices from third-party sources $2 $
Non-trading:
Values based on quoted market prices from third-party sources $
Values based on models and other valuation methods
58.7 $
64.
49.7 $
82.
0 $ 1.2 $ 115.
9 (260.6) (107.
Total non-trading 123.6 $132.6 $10.9 $ (259.4) $
Regulatory net asset (liability)(76.2) $(83.4) $(5.5) $ 259.8 $94.
Standardized derivative contracts that are valued using market quotations are classified as "values based on quoted market
prices from third-party sources." All remaining contracts, which include non-standard contracts and contracts for which
market prices are not routinely quoted, are classified as "values based on models and other valuation methods." Both
classifications utilize market curves as appropriate for the first six years.
PacifiCorp currently has II non-exchange traded streamflow weather derivative contract to reduce PacifiCorp s exposure to
variability in weather conditions that affect hydroelectric generation. Under the agreement, PacifiCorp pays an annual
premium in return for the right to make or receive payments if streamflow levels are above or below certain thresholds.
PacifiCorp estimates and records an asset or liability corresponding to the total expected future cash flow under the contract
in accordance with EITF No. 99-2, Accoutltingfor Weather Derivative.~. The net asset (liability) recorded for this contract
was $(2.1) million at March 31, 2006 and $20.3 million at March 31, 2005. PacifiCorp recognized n loss of $15.6 million for
the year ended March 31, 2006; a gain of $27.9 million for the year ended March 31, 2005; and a gain of $0.4 million for the
year ended March 31, 2004.
http://www .sec.gov/ Archives/edgar/datal75594/000007559406000028/p 1 Ok.htm 5/31/06
Page 76 of 160
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements:
R~ )2QI U!fl!!~kp c: n dJ;JllR..~i~ ~ red P~!pli~.1\~ ~_Qlli!lhK Eiull
(m.lli.Q!i~!atc;~!.s.Jill..~!l:L~l1t~Qfl.m:,o\'Q lt.the Y~m:~-I!!l JYlm~h,lJ, ,WQ!i,_~Jm.l\mll004
C !-!n$;9JJrJ.nl~dJl;Jl\ln~~,_SJt~-tj~J!.:'L 0 f M_!lr~!Lll..._906 a d...2,Q.Q~.
c.llil~Q.lida ted S la 1t;'...1J1!;nl,C; O~i!~l.fl ~y'~!j~xJ!1~_Y~.!lJ:~_fu!gj;Arv.lm:!i!,
!...
';!.!10J!,-.f(1Q~_!!.mL~ OOA
C:;Q n ~p Udutc.rl_a Ie mc;.ms oLG!!.\mg~U!!..c.Q.-'1m1Q.I..'L:i!mr~hQ!~1~r:~-
",
Eq I~ i!y.- f9J.lt~,_Y..l2I!!~..lliJ1\..!;.~..:t;:uc h 3J 2 OOJ
!..
J.f!Q5.
!W4
N Q I
- ~.
!iJQJJ 1 LCQ.H 1ill.!l gftt~J!..Eh Hll1~iru j)J;:j.t~m\~nl~
"age
http://www .see.gov/ Archives/edgar/datal7 5594/000007559406000028/p 1 Ok.htm 5/31106
,...-.-..-...--,--..----.......----..--..-......---.-..,..-..-".....,.--.....",..,...,-.-'-."-'-" ,---.-."--,.,,.'-..-".'.'.".------"."--"--,-..-...--,-....-.------..'
Page 77 of 160
REPORT OJ" INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of PacifiCorp:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, common
shareholder s equity and cash flows present fairly, in all material respects, the financial position ofPacifiCorp and its
subsidiaries at March 3 I , 2006 and 2005, and the results of their operations and their cash flows for each of the three years in
the period ended March 31, 2006, in conformity with accounting principles generally accepted in the United States of
America. These financial statements are the responsibility of the Company s management. Our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with
the standards of the Public Company Accounting Oversight Board (United States). TIlose standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 3 to the consolidated fInancial statements, PacifiCorp and its subsidiaries changed tile manner in which
they apply the normal purchases and normal sales exception to derivative contracts entered into or modified after June 30
2003, upon their adoption of SFAS No. 149 Amendmellt ofSlatemel/I/33 01/ De,'ivative lns/11/l1Ients and Hedging Activities,
as of July 1 , 2003.
As discussed in Note 6 to the consolidated financial statements, PacifiCorp and its subsidiaries changed the manner in which
they account for asset retirement obligations upon adoption of SF AS No. 143 AccOIlI/lil/gfor Asset Retirement Obligations
as of Aprilt, 2003.
PricewaterhouseCoopers LLP
Portland, Oregon
May 26, 2006
http://www.see.goY/Archivesledgar/data/75 594/000007 559406000028/p 1 Ok.htrn 5/31/06
..........-.-"........-.--..--.. .... .,....--...-...........--.............,..,..-.... ,.. .......,...,...-.............-_............,...-, --..,."........-.."..-....-....__
.'_n" ----.."-.-._0.._0""'.."""""'-
-"."..---.-"- ,.....--""-,........""",........,,........,..--..- - ,---.......,.-...,........-...-"""""..,.,,-,-,,--
Page 78 ofl60
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Millions oftlollars)
Revenues
Operating expenses:
Energy costs
Operations and maintenance
Depreciation and amortization
Taxes, other than income laxes
Total
Income from operations
Interest expense and other (income) expense:
Interest expense
Interest income
Interest capitalized
Minority interest and other
Total
Income from operations before income tax expense and cumulative effect of accounting
change
Income tax expense
Income before cumulative effect of accounting change
Cumulative effect of accounting change (less applicable income tax benefit of
$(0.6)/2004
Net income
Preferred dividend requirement
Earnings on common stock
Years Ended March 31.
2006 2005 2004
$3,896.$3,048.$3,194.5
545.948.156.
014.5 913.1 895.
448.436.428.
96.94.4 95.
104.392.4 576.
792.656.4 617.
279.267.256.
(9.(9.(13.
(32.4)(14.(19.
(6.(7.1.6
231.9 236.224.4
560.1 420.393.
199.4 168.5 144.
360.251.7 249.
(0.
360.251.7 248.
(2.(2.(3.
$ 358.$ 249.$ 244.
OIC accompanying notes are an integral part of these consolidated financial statements.
http://www .see.gOY/ Arehives/edgar/dataJ75594/000007559406000028/p 1 Ok.htm 5/31/06
- --.--.--,.............,...,-"".".---.-"""""""."""-"'-.---".-..--....-......-..,.,,--,--,-.--..--............,--,....,.'. .. ,---"--,,,""."'--- ----"-.,-",-""".,,,--'-.-"-"--""'.'.'-'."""--"'-"""--'--,..,...,......" .'.'..
Page 79 of 160
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(MUlions IIf iJllllars)
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable less allowance for doubtftll accounts of $ I 1.4/2006 and $11.6/2005
UnbiUed revenue
Amounts due from affiliates - ScottishPower
Inventories at average costs:
Materials and supplies
Fuel
Current derivative contract asset
Other
Total current assets
Property, plant and equipment:
Generation
Transmission
Distribution
Intangible plant
Other
Total operating assets
Accumulated depreciation and amortization
Net operating assets
Construction work-in-progress
Total property, plant and equipment, net
Other assets:
Regulatory assets
Derivative contract regulatory asset
Non-current derivative contract asset
Deferred charges and other
Total other assets
Total assets
March 31,
2006 2005
119.6 $199.
266.293.
148.143.
36.
131.2 114.
80.58.
221.7 252.
46.115.
015.214.
686.238.
591.8 507.
502.308.
659.607.
662.596.
15,102.4 14,259.
611.5)(5,361.8)
490.897.
618.593.4
10,109.490.
884.3 972.
94.170.
345.360.
282.312.
606.816.
$12,731.3 $12,520.
TIIC accompanying notes are an integral part of these consolidated financial statements.
http://www .see.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
......,...-.....,...--.....-..,.,.-----"------""'-"'-."..-""""""""-""'---""".-""..'..-------~,,..,,' '-"'--"""..,....",".--'~,,,~-..;"::",:.'" .""
:;c""""","",-~""",.',"",,,
'."'--."-"-
::C::="""
"~"'-;""""""
'""O::::-...C::..::;:~;.
Page 80 of 160
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS, continued
IMllllons orllollars)
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable
ArnOUDls due to affiliates - MidAmerican
Amounts due to affiliates - ScoltishPower
Accrued employee expenses
Taxes payable
Interest payable
Current derivative contract liability
Current defelTed tax liability
Long-term debt and capital lease obligations, currently maturing
Preferred stock subject to mandatory redemption, currently maturing
Notes payable and commercial paper
Other
Total current liabilities
Deferred credits:
Deferred income taxes
Investment tax credits
Regulatory liabilities
Non-current derivative contract liability
Pension and other post employment liabilities
Other
Total deferred credits
Long-tenn debt and capilallease obligations, net of current maturities
Preferred stock subject to mandatory redemption, net of current maturities
Total liabilities
Conunitments, contingencies and guarantees (Sce Notes 10 and 11)
Shareholders' equity:
Preferred stock
Common equity:
Common shareholder s capital
Retaincd ea111ings
Accumulated other comprehensive income (loss):
Unrealized gain on available.for-sale
securities, net of tax of$1.7/2006 and $2.6/2005
Minimum pension liability, net of tax of $(2.5)/2006 and $(5.5)/2005
Total common equity
http://www.sec.gov/ Archives/edgar/dataJ75594/000007559406000028/p 1 Ok.htm
March 31,
2006 2005
361.3 $350.4
118.134.
47.39.
63.64.
97.136.
16.
216.269.
184.4 468.
103.123.4
216.597.
621.2 629.
67.75.
804.806.
461.2 630.5
385.422.4
361.4 304.
701.1 868.
721.0 629.
41.3 48.
679.5 143.
41.3 41.3
381.9 894.
630.446.4
(4.(9.
010.335.
5/31106
. .-...-...-........-.....-..-...-........-......-....-..-..-..."..-...-..--..,........,.",---..-...-....--..,..-...----.-.-.",........,.--....-.-----"-.-,----.." ,._-,_....,..,.._----"'--".'--""-_.'-----"'-'----.-
Page 81 of160
Total shareholders' equity 051.8 377.
Total liabilities and shareholders' equity $12 731.3 $12,520.
The accompanying notes are an integral part of these consolidated financial statements.
hUp:!/www .sec.gov! Archives/edgar/datal7 5594/000007 559406000028/p Okhtm 5/31/06
"..-..",.......-.
,..-....,.--_......_.m..___-
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(MIIliORS of dollars)
Cash flows from operating activities:
Net income
Adjustments to reconcile net income to net cash provided by,operating activities:
Cumulative effect of accounting change, net of tax
Unrealized gain on derivative contracts, net
Depreciation and amortization
Deferred income taxes and investment tax credits, net
Regulatory asset/liability establishment and amortization
Other
Changes in:
Accounts receivable, prepayments and other cunent assets
Inventories
Amounts due to/from affiliates - MidAmerican, net
Amounts due to/from affiliates - ScottishPower, net
Accounts payable and accrued liabilities
Other
Net cash provided by operating activities
Cash flows from investing activities:
Capital expenditures
Proceeds from sales of assets
Proceeds from available-for-sale securities
Purchases of available. for-sale securities
Other
Net cash used in investing activities
Cash flows from financing activities:
Changes in short-term debt
Proceeds from long-term debt. net of issuance costs
Proceeds from issuance of common stock to PHI
Dividends paid
Repayments and redemptions oflong-terrn debt
Repayment of preferred securities
Redemptions of preferred stock
Other
Net cash provided by (used in) financing activities
Change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
-.....m_..._..",..._.~-
'."_"""'-,..-.---..---...--
Page 82 of 160
Years Ended March 31,
2006 2005 2004
360.$ 251.7 $ 248.1
(86.(8.4)(6.1)
448.436.428.
13.120.80.
51.6 66.111.1
50.(27.(6.5)
71.1 (137.(1.7)
(38.(16.14.
32.(32.(36.
(13.4)84.1 (3.
1.9 (26.
894.711.1 831.9
049.(851.6)(690.4)
1.3 3.3
123.4 49.95.
(84.(44.(89.4)
(14.(6.(22.
024.1)(846.(703.
(284.343.99.
296.395.396.
484.
(177.1)(195.4)(165.1)
(269.(259.(194.
(352.
(7.5)(7.5)(7.
(0.
49.276.4 (222.4)
(79.140.(94.
199.58.152.
119.199.58.
http://www .see.goy/ Archiyes/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
....-.-...-.--.........--...-..,.....--....-......-..---..----..,.. ,.,,"-"..---.""'-.'
The accompanying notes are an integral part of these consolidated financial statements.
................---...--.--.--.....
Page 83 of 160
http://www.see.gov/Archives/edgar/datal? 5 594/000007559406000028/p lOk.htm 5/3 1/06
...-."..."....--"..-,---".-..-....--..- """"-'----'."'.'-'--------""-- "--.-""""'-----"".-'-."-..-.-.
,..---.--.___..m_
_'_
--.........._.m
.""""-----
Page 84 of 160
PACIFICORI) AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY
Common Shllreholder
(Millions Dr tlOUIlr!, thousllnds ohhllres)Cllpll1l1 Accumuillted
Olher Tollil
Iletalned Comprehensh'Comprehensh-e
Shares Amounts f:arnlngl Income (1.05S)Income (Los5)
Balance at March 31 2003 312,176 892.305.(3.
Comprehensive income
Net income 248.248.1
Other comprehensive income (loss):
Unrealized gain on available-for-sale securilies
net of tax of$3.
Minimum pension liability, net of tax of$(3.(6.(6.
Cash dividends declared:
Preferred slock (3.
Common slock ($0.5! per share)(160.
Balance at March 31,2004 312,176 892.390.1 (3.5) $248.
Comprehensive income
Net income 251.7 251.7
Other comprehensive loss:
Unrealized loss on available-for-sale securities,
net of tax of $(0.(0.(0.
Minimum pension liability, net of tax of $(0.6) (1.0)(1.0)
Stock-based compensation expense
Cash dividends declared:
Preferred stock (2.1)
Common stock ($0.62 per share)(193.
Balance at March 31, 2005 312,176 894.446.4 (4.7) $250.
Comprehensive Income
Net income 360.360.
Other comprehensive income (loss):
Unrealized loss on available. for-sale securities
net of tax of$(O.(1.6)(1.6)
Minimum pension liability, nct of tax of $3.
Common siock issuance 44,885 484.
Tax benefit from stock option exercises
Separation of employee benefit plans (3.5)
Other (0.
Cash dividends declared:
Preferred stock (2.
Common stock ($0.53 per share)(175.
Balance at March 31, 2006 357,061 381.9 630.(1.4) $364.
TIlc accompanying notes are an intcgml part of these consolidated financial statements.
http://www .see.goy/ Arehiyes/edgar/data/75594/000007559406000028/p Ok.htm 5/31/06
., .,--.--...-----...... "--..,-.....-..--,-.......--...-..-.....--..,-..-....-......,,......,".,-,,-.-----"-""""""'.--.""'.-""""'" """"".."-,._""---"""",,,,-,-_.,,-,,,--,.,,"'-""-~"".""-"-...--...-.--..-.. .-- -....--...-..-.......",-"-".-"".-,,,.-,
Page 85 of 160
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
"-..
--."....-..,...-....,,--......,",.,-,---------",.."_.
"""M'~----"'.""
"""",.... ..".",..-
",..,w_"",-,~"".
."-"-",,,,,,,--'""""''"".-"""-~'""'-""-""""-'"-=:_
Page 86 of 160
PACIFICORP AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summar)' of Significant Accounting Policies
On March 21, 2006, MidAmerican Energy Holdings Company ("MEHC") completed its purchase of all of PacifiCorp
outstanding common stock from PacifiCorp Holdings, Inc. ("PHI"), It subsidiary of Scottish Power pic ("ScottishPower
pursuant to the Stock Purchase Agreement among MEHC, ScottishPower and PHI dated May 23, 2005, as amended on
March 21, 2006. The cash purchase price was $5.1 billion. PacifiCorp s common stock was directly acquired by a subsidiary
ofMEHC, PPW Holdings LLC. As a result oftbis transaction, MEHC controls the significant majority ofPacifiCorp
voting securities, which includes both common and preferred stock. MEHC, a global energy company based in Des Moines
Iowa, is a majority-owned subsidiary of Berkshire Hathaway Inc.
Nature of on.erntiolls - PacifiCorp (which includes PacifiCorp and its subsidiaries) is a United States electricity company
serving retail customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp
generates electricity and also engages ine lectricity sales and purchases on a wholesale basis. The subsidiaries of PacifiCorp
support its electric utility operations by providing coal mining and other fuel-related services, as well as environmental
remediation.
As a result of a settlement agreement between MEI-IC, the Utah Committee of Consumer Services and Utah Industrial Energy
Consumers, MEHC contributed to PacifiCorp, at no cost, MEHC's indirect 100.0% ownership interest in Intermountain
Geothermal Company, which controls 69.3% of the steam rights associated with the geothermal field serving PacifiCorp
Blundell Geothermal Plant in Utah. Intennountain Geothermal Company therefore became II wholly owned subsidiary of
PacifiCorp in March 2006, subsequent to the sale ofPacifiCorp to MEHC.
Basis oJp.reselltatiof'. The Consolidated Financial Statements ofPacifiCorp include its integrated electric utility operations
and its wholly owned and majority-owned subsidiaries. Intercompany transactions and balances have been eliminated upon
consolidation.
lf/atioll - Accounting for the electric utility business conforms to accounting principles generally accepted in the United
States as applied to regulated public utilities and as prescribed by agencies and the commissions of 111e various locations in
which the electric utility business operates. PacifiCorp prepares its financial statements in accordance with Statement of
Financial Accounting Standards ("SF AS") No. 71 ACCOll/llil/gJor the Effects oj Certai" Types oj Regulatiol/ SF AS No.
11") as further discussed in Note 2 - Accounting for the Effects of Regulation.
Use of e.~timates - The preparation of financial statements in conformity with accounting principles generally accepted in the
United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities
revenues, expenses and disclosure of contingent assets and liabilities at the date of the financial statements. These estimates
involve judgments with respect to numerous factors that are difficult to predict and are beyond management's control. As a
result, actual results could differ materially from these estimates.
Re..clnss~atiolls - Certain reclassifications of prior years' amounts have been made to conform to the fiscal 2006 method of
presentation. These reclassifications had no effect on previously reported consolidated net income.
ens!, alldJ;M1l eqllivalellts - For the purposes of these financial statements, PacifiCorp considers all liquid investments with
maturities of three months or less, at the time of acquisition, to be cash equivalents.
ds..t;lllwts receivable alld allmvollce (or lJmlllifHLffffOllllt.- Accounts receivable includes billed retail and wholesale
services plus any accrued and unpaid interest. Credit is granted to customers, which include retail and wholesale customers
govemment agencies and other utilities. Management performs continuing credit evaluations of customers , financial
conditions, and although PacifiCorp does not require collateral, deposits may be required from customers in certain
circumstances. Accounts receivable are considered delinquent based on regulations provided by each state, which is generaUy
if payment is not received by the date due, typicaUy 30 days after the invoice date. PacifiCorp charges interest on delinquent
customer accounts or past due balances in the states where PacifiCorp does business based on the respective regulation of
each state, and this interest varies between 1.0% to 1.7% per month.
http://www.see.gov/ Archives/edgar/data/75594/000007 559406000028/p 1 Ok.htm 5/31/06
-- .__._-~~-,_._.",, "-~"--""""'"._""'_'---~'-'~."""",".-,,-;:,,,,..::..;::~:..'~"-_"'=',,"-
.c:-
";:"':-".
7"-"-.--
:"'-"~-
,,o""
-""~"""'""';::::=.-:::
Page 87 ofl60
Management reviews accounts receivable on a monthly basis to determine if any receivable will potentially be uncollectible.
TIle allowance for doubtful accounts includes amounts estimated through an evaluation of specific accounts, primarily for
wholesale accounts receivable, and a reserve for retail accounts receivable based on historical experience. After all attempts
to collect a receivable have failed or, if later, by six months from when a customer becomes inactive, the receivable is
written-off against the allowance. Management believes that the aUowance for doubtful accounts as of March 31, 2006 was
adequate. However, acnlal write-orrs could exceed the recorded allowance. TIle allowance activity was as follows:
Ending balance
Years Ended March 3t,
:2006 200S 2004
11.23.31.1
(9.4)(16.(13.
It.4 11.6 23.
(Millions of doLlars)
Beginning balance
Charged to costs and expenses, net (a)
Write-orrs, net (b)
(a)Includes amounts charged to expense for adjustments to the allowance for doubtful accounts, net of recoveries of
wholesale accounts receivable.
Includes write-offs of retail and wholesale accounts receivable, net ofrecoveries of retail accounts receivable.(b)
l"veillorie.- Inventories are valued at -the lower of average cost or market.
Property. p-Inllt mId eqllimnelll - Property, plant and equipment are originally recorded at the cost of contracted services
direct labor and materials, interest capitalized during construction and indirect charges for engineering, supervision and
similar overhead items. The cost of depreciable electric utility properties retired, less salvage value, is charged to
accumulated depreciation. The cost of removal is charged against the regulatory liability estab1ished through depreciation
rates. Annual overhaul costs for the replacement of defined retirement units are capitalized. Generally other costs of overhaul
activities and ot11er repairs and maintenance are expensed as they are incurred.
Intangible plant consists primarily of computer software costs that are originally recorded at cost. Accumulated amortization
on Intangible plant was $329.8 million at March 31, 2006 and $307.6 mi1lion at March 31, 2005. Amortization expense on
Intangible plant was $45.5 million for the year ended March 31, 2006 and $48.5 million for the year ended March 31 , 2005.
The estimated aggregate amortization on Intangible plant for the next five succeeding 12 month periods ending from March
31,2007 to March 31 , 201 1 is $45.4 million, $38.9 million, $31.0 million, $24.7 million and $21.8 million. Unamortized
computer software costs were $186.7 million at March 31 2006 and $185.1 million at March 31, 2005.
Dep-reciat;oll ami amortkat;Oll - TIle average depreciable lives of Property, plant and equipment currently in use by category
are as follows:
Generation
Steam plant
Hydroelectric plant
Other plant
Transmission
Distribution
Intangible plant
Other
20 - 43 years
14 - 85 years
15 - 35 years
20 - 70 years
44 - SO years
5 - 50 years
5 - 30 years
Computer software costs included in Intangible plant are initially assigned a depreciable tife of 5 to 10 years.
During the year ended March 31, 2005, PacifiCorp changed the estimated average lives of certain computer software systems
to reflect operational plans. This change reduced amortization expense by $12.9 million annually on existing computer
software systems, with an annual impact to net income of approximately $8.0 million.
Depreciation and amortization are computed by the straight-line method either over the life prescribed by PacifiCorp
various regulatory jurisdictions for regulated assets or over the assets' estimated useful lives.
http://www.see.gov/ Archives/edgar/datal7 5594/000007559406000028/p 1 Ok.htm 5/31/06
----"""""".-""""'-""---............--,--,..,-.,.--,.---"-.-"---..--.--.----.-,.........-....---..-..----."'..
Page 88 of 160
http://www .see.goy/ Arehiyes/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
..,-..--...-.--..---.--.."...-...-..-....",......".."".."""-"""-",.,.---",."",."""-'--""'-"".----".-""--.."'" -,."",-"--",,,,----,,""-"'-"""."".-"-----".""'-"'-"'-"..........,_.
Page 89 of 160
Composite depreciation rates of average depreciable assets on utility Property, plant and equipment (excluding amortization
of capital leases) were 3.0% for each oft11e years ended March 31, 2006, 2005 and 2004.
Asset imnnirmlillM.- Long-lived assets to be held and used by PacifiCorp are reviewed for impainnent when events or
circumstances indicate costs may not be recoverable. Such reviews are performed in accordance with SFAS No. 144
AccOIl//til/gfor the Impairme1lt or Disposal ofLollg-Lived Assets SFAS No. 144"). The impacts of regulation on cash flows
are considered when determining impairment. Impairment losses on long-lived assets are recognized when book values
exceed expected undiscounted future cash flows with the impairment measured on a discounted future cash flows basis.
Allolllallce ffJ.l..ljlllds 1I.~ed during clmstrllctioll - The allowance for funds used during constmction (the "AFUDC"
represents the cost of debt and may also include equity funds used to finance utility property additions during construction.
As prescribed by regulatory authorities, the AFUDC is capitalized as a part of the cost of utility property and is recorded in
the Consolidated Statements of Income as Interest capitalized. Under regulatory rate practices, PacifiCorp is generally
permitted to recover the AFUDC, and a fair return thereon, through its rate base after the related utility property is placed in
service.
The composite capitalization rates were 6.5% for the year ended March 31, 2006; 4.5% for the year ended March 31, 2005;
and 7.9% for the year ended March 31, 2004. PacifiCorp s AFUDC rates do not exceed the maximum allowable rates
determined by regulatory authorities.
Deri.'ati"es - In accordance with SFAS No. 133, Accor/lltil/gfor Derivath'e Instrume1lts and Hedging Activities, SPAS No.
133"), as amended by SF AS No. 138 Accollt1tingfor Certain Derivative Inst11lments and Certai" Hedging Activities, and
SPAS No. 149, Alllel/c!metll ofStatemettt /33 Ofl Derivati\le Instnl1lwllts a/l(( Hedgillg Activities SF AS No. 149"
(collectively "SPAS No. 133"), derivative instruments are measured at fair value and recognized as either assets or liabilities
on the Consolidated Balance Sheets, unless they qualify for the exemptions afforded by the standard. Changes in the fair
value of derivatives are recognized in earnings during the period of change. Certain long-term derivative contracts have been
approved by regulatory authorities for recovery through retail rates. Accordingly, changes in fair value of these contracts are
deferred as regulatory assets or liabilities pursuant to SF AS No.7 I. Derivative contracts for commodities used in
PacifiCorp s normal business operatIon and that settle by physical delivery, among other criteria, are eligible for the normal
purchases and normal sales exemption afforded by SF AS No. 133. These contracts are accounted for under accmal
accounting and recorded in Revenues or Energy costs in the Consolidated Statements of Income when the contracts settle.
Marketable secllrities - PacifiCorp accounts for marketable securities, included in Deferred charges and other on
PacifiCorp s Consolidated Balance Sheets, in accordance with SPAS No.1 15 Accoullti"gfor Certail/illvestments ill Debt
allc! Equity Secllrities. PacifiCorp determines the appropriate classification of an marketable securities as held-to-maturity,
available-for-sale or trading at the time of purchase and re-evaluates such classification as of each balance sheet date. As
shown in Note 5 - Marketable Securities, at March 31 , 2006 and 2005, all ofPacifiCorp s investments in marketable
securities were classified as available-for-sale and were reported at fair value. PacifiCorp uses the specific identification
method in computing realized gains and losses on 111e sale ofits available-for-sale securities. Realized gains and losses are
included in Other (income) expense. Unrealized gains and losses are reported as a component of Accumulated other
comprehensive income (loss). Investments that are in loss positions as of the end of each reporting period are analyzed to
determine whether they have experienced a decline in market value that is considered other-than-temporary. An investment
wilt generally be written down to market value if it has a significant unrealized loss for more titan nine months. If additional
infonnation is available that indicates an investment is other-than-temporarily impaired, it will be written down prior to the
nine-month time period. If an investment bas been impaired for more than nine months but available information indicates
that the impairment is temporary, the investment will not be written down.
lllOllllts l,eI4J1ur"Ji!. - PacifiCorp holds certain trusts to fund decommissioning and reclamation activities as described in
Note 5 - Marketable Securities and Note 6 - Asset Retirement Obligations and Accmed Environmental Costs. Amounts are
also held in trusts that serve as funding vehicles for certain ofPacifiCorp s employee benefits, including the Supplemental
Executive Retirement Plan (the "SERF") as described in Note 17 - Employee Benefits.
~set retiremellcohljg !.ioJI!umd_m:crned removal costs - Effective April I, 2003, PacifiCorp recognizes the fair value of
legal obligations associated with the retirement or removal orIong-lived assets at the time the obligations
http://www.see.goY/Archives/edgar/datal7 5 S94/000007559406000028/p 1 Ok.htm 5/31/06
, --.._...._.
h"'_'.'--"'.'"",,---,,---"""""--h_'..___,._,.....,
-,...,_....-..."'_--~-"'- -....--..-.-.,-...-..-,......... ,.,....-,-,.-.....,.-....-...-.--.........,--............-...-,.,..-..",,,"--'" ,..,"......--.,.,...-,.-..---....,--..,...,...-",..-,..-,.,-,-,"'. -,_.......,----.-_..-_......._-,,-~
Page 90 of 160
are incurred and can be reasonably estimated in accordance with SF AS No. 143 AccD/llltingfor Asset Retirement Obligatiolls
SFAS No. 143"). The initial recognition of this liability is accompanied by a corresponding increase in Property, plant and
equipment. Subsequent to the initial recognition, the liability is adjusted for any revisions to the expected value of the
retirement obligation (with corresponding adjustments to Property, plant and equipment) and for accretion of the liability due
to the passage of time. Additional depreciation expense is recorded prospectively for any Property, plant and equipment
increases. In general, depreciation and accretion expense generated by SF AS No. 143 accounting is recorded as n regulatory
asset or liability because such amounts are recoverable in rates. As of March 3), 2006, PacifiCorp adopted Financial
Accounting Standards Board (the "FASB") Interpretation No. 47 Accortntingfor Collc/itiollal Asset Retirement Obligations-
(l1IllIterpretation of FASB Statement No. /43 ("FIN 47") as described in Note 6 - Asset Retirement Obligations and Accrued
Environmental Costs.
For those asset retirement removal costs that do not meet the requirements of SF AS No. 143, PacifiCorp recovers through
approved depreciation rates estimated removal costs and accumulates such amounts in Asset retirement removal costs within
Regulatory liabilities as described in Note 2 - Accounting for the Effects of Regulation.
Illcome taxes - PacifiCorp uses the liability method of accounting for deferred income taxes. Deferred tax liabilities and
assets reflect the expected future tax. consequences, based on enacted tax law, of temporary differences between the tax bases
of assets and liabilities and their financial reporting amounts.
Prior to the sale of PacifiCorp to MEHC on March 21, 2006, PacifiCorp was a wholly owned subsidiary of PHI. Therefore, it
was included in the consolidated income tax return for PHI from Aprill, 2003 through March 21, 2006. PacifiCorp currently
is an indirect, majority-owned subsidiary of Berkshire Hathaway Inc. and is included in its consolidated income tax return.
PacifiCorp s provision for income taxes has been complltedon the basis that it files separate consolidated income tax returns
with its subsidiaries.
Historically, PacifiCorp did not recognize deferred taxes on many of the timing differences between book and tax
depreciation. In prior years, these benefits were flowed through to the utility customer as prescribed by PacifiCorp s various
regulatory jurisdictions. DeferTed income tax liabilities and Regulatory assets )lave been established for those flow~through
tax benefits as shown in Note 2 - Accounting for the Effects of Regulation since PacifiCorp is allowed to recover the
increased income tax expense when these differences reverse.
Investment lax credits are deferred and amortized to income over periods prescribed by PacifiCorp s various regulatory
jurisdictions.
PacifiCorp establishes accruals for certain tax contingencies when, despite tIle belief that its tax return positions are
supported, it also believes that certain positions may be challenged and that it is probable those positions may not be fully
sustained. PacifiCorp is under continuous examination by the Internal Revenue Service and other tax authorities and accounts
for potential losses of tax benefits in accordance with SFAS No.5, Accountingfor Contingel/cies SFAS No.). See Note
19 - Income Taxes for further infonnation.
fjfock-h.Jl.~flll1P-~!l$JltiP.l! - As permitted by SFAS No. 123, Accountingfor Stock-Based Compensation SFAS No. 123"
PncifiCorp accounts for its stock-based compensation arrangements, primarily employee slack options, under the intrinsic
value recognition and measurement principles of Accounting Principles Board ("APB") Opinion No. 25 AccO/lIltingfor
Stock Issued to Employees APB No. 25"), and related interpretations in accounting for employee stock options issued to
PacifiCorp employees. Under APB No. 25, because the exercise price of employee stock oplions equals the market price of
the underlying stock on the date of grant, no compensation expense is recorded if the ultimate number of shares to be
awarded is known at the date of Ihe grant. AU options currently accounted for under APB No. 25 were issued in
ScottishPower American Depository Shares, as discussed in Note 18 - Stock-Based Compensation. Had PacifiCorp
determined compensation cost based on the fair value at tIle grant date for all stock options vesting in each period under
SFAS No. 123, PacifiCorp s Net income would have been reduced to the pro forma amounts below:
http://www.see.goY/Arehiyes/edgar/data/7 5594/000007 559406000028/p 1 Ok.htm 5/31/06
.-...........,..-...----. -..-...~--,.,-_..._-..,.__..,-_....__.-...._, - ".....-",~--,----_.._"..-",...,.,-------"".."-~..,,,..,,..,-":-:' -,--.. ::::..
""~,,,--_._'-r-,,""'~:':c"
,,'",.:'.."-
:=--C:"":~""'~"~~".O"""',
~=:'-,,--
Page 91 of160
Pro forma net income
Years Elld~tI !\larch 31,
2006 2005 2004
360.251.7 248.
0.1
(1.4)(4.(1.1)
359.4 250.5 247.
(Million! of dollars)
Net income as reported
Add: stock-based compensation included
in reported net income, net of related tax effects
Less: stock-based compensation expense
using the fair value method, net of related tax effects
Revenue recognition - Revenue is recognized upon delivery for retail and wholesale electricity sales. Electricity sales to
retail customers are determined based on meter readings taken throughout the month. PacifiCorp accmes an estimate of
unbi1led revenues, which are earned but 110t yet billed, net of estimated line losses, each month for electric service provided
after the meter reading date to the end of the month. The process of calculating the Unbilled revenue estimate consists of
three components: quantifying PacifiCorp s tota:1 electricity delivered during the month, assigning UnbiUed revenues to
customer type and valuing the unbiUed energy. Factors involved in the estimation of consumption and line losses relate to
weather conditions, amount of natural light, historical trends, economic impacts and customer type. Valuation of un billed
energy is based on estimating the average price for the month for each customer type. The amount accmed for Unbilled
revenues was $148.2 million at March 31, 2006 and $143.8 million at March 31,2005.
fJpnellt information - PacifiCorp currently has one segment, which includes the regulated retail and wholesale electric
operations.
NeIll accoJllrtillg statrdnrds
SF AS No. 123R
On April 1 , 2006, PacifiCoIp adopted SPAS No. 123R Share-Based Paymetlt SFAS No. 123R"), a revision of the
originally issued SPAS No. 123. SPAS No. 123R establishes standards for the accounting for transactions in which an entity
exchanges its equity instruments for goods or services. SF AS No. 123R requires that the cost resulting from all share-based
payment transactions be recognized in the financial statements using the fair value method. The intrinsic value method of
accounting established by APB No. 25 will no longer be allowed. TI1e adoption of SF AS No. 123R did not have an effect on
PacifiCoIp sfinancial position or results of operations as all requisite service has been rendered by employees and the
outstanding stock awards are fully vested. For further information see Note 18 - Stock-Based Compensation.
EITF No. 04-
On April 1 2006, PacifiCorp adopted Emerging Issues Task Force No. 04-Accol/1rtillg!or Strippillg Costs brclIrred duritlg
Production ill tfle Milling Itldustry EITF No. 04-). ElTF No. 04-6 requires that stripping costs incurred during the
production phase of a mine are variable production costs that should be included in the costs of the inventory produced (that
, extracted) during the period that the stripping costs are incurred. TIle adoption of EITF No. 04-6 did not have a material
impact on PacifiCorp s consolidated financial position or results of operations.
Note 2 - Accounting for the Effects of Regulation
Regulated utilities have historically applied the provisions of SF AS No. 71, which is based on the premise that regulators will
set rates that allow for the recovery of a utility s costs, including cost of capital. AccOlmting under SFAS No. 71 is
appropriate as long as (i) rates are established by or subject to approval by independent, third-party regulators, (ii) rates are
designed to recover the specific enteIprise s cost of service, and (iii) in view of demand for service, it is reasonable to assume
that rates are set at levels that will recover costs and can be collected from customers.
SF AS No. 71 provides that regulatory assets may be capitalized if it is probable that future revenue in an amount at least
equal to the capitalized costs wilt result from t11cir treatment as allowable costs for rate-making puIposcs. In addition, the rate
action should permit recovery of the specific previously incurred costs rather than provide for expected levels of similar
future costs. PacifiCorp records regulatory assets and liabilities based on management'
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
,.........,.,......-,....,..,..,..,.......-."'-"-".........---..,..."..---,....-..,....,,-,...,....,-..-....--...-..-..--....-....,.,..--,.,..""..-..,....-,...,,,-
,.....__.....m
'.-"-.,,'--..-'" ,..,......,---_...,.-.. ."-'--'._"---""""--'-"'."",'
Page 92 of 160
http://www.sec.gov/ Archives/edgar/datal7 5594/000007559406000028/p 1 Ok.htm 5/31/06
""".""'----'"'-._-",-,,",-"--~"-""",,- . - "-
"""""..__w.._"-,,,..
,,......,,.."'-;--" ""'~'~"-~~'"""-;;;-
C" ""
~~".",-,---,~"~-",-",,--""'...,,,,,"'-_."_.'-
Page 93 of 160
assessment t11at it is probable that a cost will be recovered (asset) or that an obligation lIas been incurred (liability). The final
outcome, or additional regulatory actions, could change management's assessment in future periods. A regulator can provide
current rates intended to recover costs that are expected to be incurred in the future, with the understanding that if those costs
are not incurred, future rates win be reduced by corresponding amounts. If current rates are jntended to recover such costs,
PacifiCorp recognizes amounts charged pursuant to such rates as liabilities and takes those amounts to income only when the
associated costs are incurred. In applying SF AS No. 71, PacifiCorp must give consideration to changes in the level of
demand or competition during the cost recovery period. In accordance with SFAS No. 71 , PacifiCorp capitalizes certain costs
as regulatory assets if authorized to recover the costs in future periods.
PacifiCorp continuously evaluates the appropriateness of applying SPAS No. 71 to each ofitsjurisdictions. At March 31
2006, PaciliCorp had recorded specifically identified net regulatory assets of $174.3 mi11ion. In tbe event PacifiCorp stopped
applying SF AS No. 71 at March 31, 2006, an after-tax loss of approximately $108.2 million would be recognized.
PaciliCorp is subject to the jurisdiction of public utility regulatory authorities of each of the states in which it conducts retail
electric operations with respect to prices, services, accounting, issuance of securities and other matters. TIle jurisdictions in
which PacifiCorp operates are in various stages of evaluating deregulation. At present, PacifiCorp is subject to cost-based
rate-making for its business. PacifiCorp is a "licensee" and a "public utility" as those terms are used in the Federal Power Act
and is, therefore, subject to regulation by the Federal Energy Regulatory Commission (the "FERC") as to accounting policies
and practices, certain prices and other matters.
Regulatory assets include the following:
Subtotal
Derivative contracts (d)
March 31,
2006 (a)2005 (a)
480.499.
257.280.
29.34.
13.4 25.5
16.24.
87.107.
884.972.
94.170.
979.142.
(Millions ortlollars)
Deferred income taxes (b)
Minimum pension liability (c)
Unamortized issuance expense on retired debt
Demand-side resource costs
Transition plan - retirement and severance
Various other costs
Total
(a) PacifiCorp had regulatory assets not accruing carrying charges of $952.9 million at March 31, 2006 and $1 095.6 million
at March 31 , 2005.
(b) Represents accelerated income tax benefits previously passed on to ratepayers that will be included in rates concurrently
with recognition of the associated income tax expense.
(c) Represents minimum pension liability offsets proportionate to the amount of pension costs that are recoverable in rates.
Remaining minimwn pension liability offsets are included net of tax in Accumulated other comprehensive income (loss).
(d) Represents net unrealized losses related to derivative contracts included in rates. See Note 3 - Derivative Instruments for
further information.
http://www.sec.gov/ Archives/edgar/datal7 5594/000007559406000028/p 1 Ok.htm 5/31/06
..,.,--....,..~, ..""."'--'-"""
'C..
--"'"-'""'-'~""""'-""--"""..,,,.........-~,,--~,...., ..'~"""""""""";-
,,,,C=""-
;-"''-;- -""."'
:C'::;,
""""""""""'"""""'-.,
"""'O--""""=:J
Page 94 of 160
Regulatory liabilities include the following:
Total
!\I3rth 31,
2006 2005
699.692.1
43.44.
23.12.
37.56.
804.806.
(Millions or dollars)
Asset retirement removal costs (a)
Deferred income taxes
Bonneville Power Administration Regional Exchange Program
Various other costs
(a)Represents removal costs recovered in rates.
PacifiCorp evaluates the recovery of aU regulatory assets periodically and as events occur. The evaluation includes the
probability of recovery, as welt as changes in the regulatory environment. Regulatory and/or legislative action in Utah,
Oregon, Wyoming, Washington, Idaho and California may require PacifiCorp to record regulatory asset write-offs and
charges for impairment oflong-lived assets in future periods. Impairment would be measured in accordance with
PacifiCorp s asset impairment policy, as discussed in Note 1- Summary of Significant Accounting Policies.
Note 3 . Derivative Instruments
In accordance with SF AS No. 133, PacifiCorp records derivative instruments on the Consolidated Balance Sheets as assels or
liabilities measured at estimated fair value, unless they qualify for the exemptions afforded by the standard. PacifiCorp uses
derivative instruments (primarily forward purchases and sales) to manage the commodity price risk inherent in its fuel and
electricity obligations, as welt as to optimize the value of power generation assets and related contracts.
In July 2003, the ElTF issued EITF No. 03-Reporting Realized Gaills and Losse~' 011 Derivative IlIstrll1nell/s That Are
Subject to FASB Sta/emellt No. /33 anci Not "Held for Tradillg Purposes " as llefmell in Issue No. 02-EITF No. 03-11"
which provides guidance on whether to report realized gains or losses on physically settled derivative contracts not held for
trading purposes 011 a gross or net basis and requires realized gains or losses on derivative contracts that do not settle
physically to be reported on a net basis. The adoption of EITF No. 03-11 during the year ended March 31, 2004 resulted in
PacifiCorp netting certain contracts that were previously recorded on a gross basis in Wholesale sales and other revenues and
Energy costs in the Consolidated Statements ofIncome. The adoption ofEITF No. 03-11 had no impact on PacifiCorp
consolidated Net income and aU periods presented are consistent with the requirements ofEITF 03-11.
As the FASB continues to issue interpretations, PacifiCorp may change the conclusions that it has reached and, as a result,
the accounting treatment and financial statement impact could change in the future.
The accounting treatment for the various classifications of derivative financial instruments is as follows:
Normal p-",cllase.~ alld IIorlllal sale.- The contracts that qualify as normal purchases and normal sales are excluded from the
requirements of SF AS No. 133. The realized gains and losses on these contracts are reflected in the Consolidated Statements
of Income at the contract settlement date.
!l!!!l~.1l- Unrealized gains and losses on derivative contracts held for trading purposes are presented on a net basis in
the Consolidated Statements of Income as Revenues. Unrealized gains and losses on derivative contracts not held for trading
purposes are presented in the Consolidated Statements ofIncome as Revenues for sales contracts and as Energy costs and
Operations and maintenance expense for purchase contracts and financial swaps.
PacifiCorp has the following types of commodity transactions:
Wholesale electricitypllrc1ll1se a.ml~ll!!lmf:1S. - PacifiCorp makes continuing projections of future retail and wholesale
loads and future resource availability to meet these loads based on a number of criteria, including
http://wv,,w.sec.gov/Archives/edgar/datal7 5594/000007 559406000028/p 1 Ok.htm 5/31/06
-,-""'".--"""",,,,-
,"""'-------"W""""""--
"'---,"","" .",","",..
:c_
,_.:"-"""",,,,--~-""'~~""",';." ""'":":""""""'---'~"""-
':O'_'
::'.
:C-"::c-
",.,----,-
Page 95 of 160
historical load and forward market and other economic information and experience. Based on these projections, PacifiCorp
purchases and sells electricity on a forward yearly, quarterly, monthly, daily and hourly basis to match actual resources to
actual energy requirements and sells any surplus at the prevailing market price. This process involves hedging transactions,
which include the purchase and sale of firm energy under long-term contracts, forward physical contracts or financial
contracts for the purchase and sale of a specified amount of energy at a specified price over a given period of time.
Nalr/ral g...as ami t'ther fuel purchase colI/TacH . PacifiCorp manages its natural gas supply requirements by entering into
forward commitments for physical delivery of natural gas. PacifiCorp also manages its exposure to increases in natural gas
supply costs through forward commitments for the purchase of physical natural gas at fixed prices and financial swap
contracts that settle in cash based on the difference between a fixed price that PacifiCorp pays and a floating market-based
price that PacifiCorp receives.
Where PacifiCorp s derivative instruments are subject to a master netting agreement and the criteria of FIN 39 Offsetting of
Amounls Related to Certain Contracts- An blterprelatioIJ of APB Opitl;on No. /0 and FASB Statement No. 105, are met
PacifiCorp presents its derivative assets and liabilities, as well as accompanying receivables and payables, on a net basis in
the accompanying Consolidated Balance Sheets.
Unrealized gains and losses on energy sales and purchase contracts are affected by fluctuations in forward prices for
electricity and natural gas. The following table summarizes the amount of the pre-tax unrealized gains and losses included
within the Consolidated Statements ofIncome associated with changes in the fair value ofPacifiCorp s derivative contracts
that are not included in rates.
(Millions uftlullars)Years End~d MardI 31,
2006 2005 2004
Revenues
Operating expenses:
Energy costs
Operations and maintenance
224.4 $(330.0) $(29.
(131.1)
(6.5)
338.4 35.
Total unrealized gain on derivative contracts 86.8 $8.4 $6.1
The following table shows the changes in the fair value of energy-related contracts subject to the requirements of SF AS No.
133, as amended, from April 1, 2005 to March 31, 2006.
Fair value of contracts outstanding at March 31, 2006
Net Asset (LIability)Regulatory
Net Asset
Trading Non-tradIng (LIability) (b)
(154.4) $170.
(0.(115.128.
277.(203.
94.
(MIllions or dollars)
Fair value of contracts outstanding at March 31, 2005
Contracts realized or otherwise settled during the period
Other changes in fair values (a)
(a) Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates, including
those based on models, on new and existing contracts.
(b) Net unrealized losses (gains) related to derivative contracts included in rates are recorded as a regulatory net asset
(liability).
PacifiCorp bases its forward price curves upon market price quotations when available and bases them on internally
developed and commercial models, with internal and external fundamental data inputs, when market quotations are
unavailable. Markel quotes are obtained from independent energy brokers, as well as direct information received from third-
http://www .see.gov! Arehives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
...----,....,..""......-""""""-""'."-' "..--'.--"'-"-"--"----""'-."'-'-"""'-'.-"-"--" ..,-_.,,---.......~,"~,~-""-
,c-,-,,
_.."""',..,-""-'~"...-
party offers and actual transactions executed by PacifiCorp. Price quotations for certain major electricity
' ""
"",~_.,"""c-
",,".."..,~..",",....,"q~",",~"",-..=
Page 96 of 160
http://www.sec.gov/ Archives/edgar/data/7S594/000007559406000028/p 1 Ok.htm 5/31106
Page 97 ofl60
trading hubs are generally readily obtainable for the first six years and therefore PacifiCorp s forward price curves for those
locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively
traded, forward price curves must be developed. For short-term contracts at less actively traded locations, prices are modeled
based on observed historical price relationships with actively traded locations. For long-term contracts extending beyond six
years, the forward price curve (beyond the first six years) is based upon the use of a fundamentals model (cost-to-build
approach) due to lite limited information available. The fundamentals model is updated as warranted, at least quarterly, to
reflect changes in the market such as long-term natural gas prices and expected inflation rates.
Short-term contracts, without explicit or embedded optionatity, are valued based upon the relevant portion of the forward
price curve. Contracts with explicit or embedded optionality are valued by separating each contract into its physical and
financial forward, swap and option components. Forward and swap components are valued against the appropriate forward
price curve. The optionality is valued using a modified Black-Scholes model approach or a stochastic simulation (Monte
Carlo) approach. Each option component is modeled and valued separately using the appropriate forward price curve.
Standardized derivative contracts that are valued using market quotations, as described above, are classified in the table
below as "values based on quoted market prices from third-party sources." All remaining contracts, which include non-
standard contracts and contracts for which market prices are not routinely quoted, are classified as "values based on models
and other valuation methods.
Total non-trading
Fair Value of Contratb at l'erlod-EmJ
Maturity Malurlty In 1'01011
Less Than Malurlty 1\1aturlt)'Excess of Fair
1 Year 3 Yean 5 Years 5 Years Value
2 $
58.7 $49.7 $0 $1.2 $115.
64.82.(260.(107.
123.6 $132.6 $10.9 $(259.4)$
(76.2)$(83.4)$(5.5)$259.8 $94.
(Millions or dollars)
Trading:
Values based on quoted market prices from third-party sources
Non-trading:
Values based on quoted market prices from third-party sources
Values based on models and other valuation methods
Regulatory net asset (liability)
Weather tlerivatives . PacifiCorp currently has a non-exchange traded streamflow weather derivative contract to reduce
PacifiCorp s exposure to variability in weather conditions that affect hydroelectric generation. Under the agreement
PacifiCorp pays an annual premium in return for the right to make or receive payments if streamflow levels are above or
below certain thresholds. PacifiCorp estimates and records an asset or liability corresponding to the total expected fhture cash
(low under the contract in accordance with EITF No. 99-AccO/llltillgfor Weather Derivativc.v. The net asset (liability)
recorded for this contract was $(2.1) million at March 31, 2006 and $20.3 million at March 31 , 2005 and was included in
other current assets (liabilities) in the Consolidated Balance Sheets. PacifiCorp recognized a loss of$15.6 million for the year
ended March 31, 2006; a gain of$27.9 million for the year ended March 31 2005; and a gain of$O.4 million for the year
ended March 31 . 2004.
Note 4 - Related-Party Transactions
IruIf.'iat;tiolls wllile oJlme~MEHC - As discussed in Note 1- Summary of Significant Accounting Policies, PacifiCorp
was acquired by MEHC on March 21, 2006. TIle following describes PacifiCorp s transactions and balances with
unconsolidated related parties while owned by MEHC.
PacifiCorp began participating in a captive insurance program provided by MEHC Insurance Services Ltd. ("MISL"), a
wholly owned subsidiary ofMEHC. MISL covers all or significant portions of the property damage and liability insurance
deductibles in many of PacifiCorp s current policies, as well as overhead distribution and transmission line property damage.
PacifiCorp has no equity interest in MISL and has no obligation to contribute
http://www.see.gov/ Archives/edgar/datal? 5594/000007559406000028/p 1 Ok.htm 5/31/06
..,.,,-.- ,.--,.-,--""-""'"" -. --"""."-",."- . -":,,
C""~'-
"'="-~"-
"":C;-
, :'::' '.:: """"-
"""'."W"'-'-'~'"',"":::":"'
:-.:'.'-
"","~,,-~,-,--,-,,-~w"'~~
Page 98 of 160
http://www .see.gov/ Archives/edgar/datal? 5594/0000075 59406000028/p 1 Ok.htm 5/31/06
-'~-
,.c
-..~" -- '" '..--""-.-'.--"-.. -"--,-,--,,,--,,,-""---_._"-"-----""-."""'."-'--.",..--",-."--,..,.-".,---."-",,--,,.-,,---.-,,-,,-,,-.,,,.'--....---'--.""'-""-"-.---..---".-.--....,-...,.".,..,.,,-----
Page 99 of 160
equity or loan funds to MISL. Premium amounts are established based on a combination of actuarial assessments and market
rates to cover loss claims, administrative expenses and appropriate reserves. Certain costs associated willi the program are
prepaid and amortized over the policy coverage period expiring March 20, 2007. Prepayments to MISL were $7.2 million at
March 3 1, 2006. Premium expenses were $0.2 million for March 2 I, 2006 through March 3 1 , 2006.
As of March 31 , 2006, Amounts due to affiliates - MEHC included $3.8 million of current income taxes payable to PPW
Holdings LLC.
See Note 1 - Summary of Significant Accounting Policies for information related to the transfer of MEHC's 100.
ownership interest in Intermountain Geothermal Company to PacitiCorp.
Tra/lSactiom.. wM/e olVlled bv Sc(JttisJrPoll1er - There were 110 loans or advances between PacifiCorp and ScottishPower or
between PacifiCorp and PHI. Loans from PacifiCorp to ScottishPower or PHI were prohibited under the Public Utility
Holding Company Act of 1935 ("PUHCA"), which was repealed effective February 2006. Loans from ScottishPower or PHI
to PacifiCorp generally required state regulatory and SEC approval. There were intercompany loan agreements that allowed
funds to be lent to PacifiCorp from PacifiCorp Group Holdings Company ("PGHC"), but loans from PacifiCorp to PGHC
were prohibited. There were intercompany toan agreements that allowed f1mds to be lent between PacifiCorp and Pacific
Minerals, Inc., n wholly owned subsidiary ofPacifiCorp. PaciftCorp does not maintain a centralized cash or money pool.
Therefore, funds of each company were not commingled with funds of any otl1er company.
http://www.sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
-,------,. .." "_.,_.."-,...-----".,, '
F-~'-.""'-;'~-'"""":C--" -
':;"
"""".~""-~""'~""'~"",""C
::-,.."""---'.-:;,
:::::":O"',,"O'=~"'""""""""'-;C:::C'
:,---,---'- "",.
:::::;"""o,,o;co,"o"""-
""-"'-""';=,::="""-
7;;:1
Page 1 00 of 160
l11e tables below detail PacifiCorp s transactions nnd balances with unconsolidated related parties while owned by
ScottishPower.
(Millions ofdollnrs)M:1rch 31, 2006"
Marl:h 31,
200S
Amounts due from former affiliated entities:
SPUK (a)
PHI and its subsidiaries (b)36.
36.
Prepayments to former affiliated entities:
PHI and its subsidiaries (c)1.5
Amounts due to former affiliated entities:
SPUK (d)
Deposits received from former affiliated entities:
PHI and its subsidiaries (e)
(MIllions of dollars)Years EndctlMarch 31,
2006 2005 2004
Revenues from former affiliated entities:
PHI and its subsidiaries (e)4.4
Expenses recharged to former affiliated entities:
SPUK (a)
PHI and its subsidiaries (b)7.3 9.4
13.5 12.4
Expenses incurred from former affiliated entities:
SPUK (d)18.18.
PHI and its subsidiaries (c)19.17.3 17.
DIIL (1)
44.35.24.
Interest expense to former affiliated entities:
PHI and its subsidiaries (g)1 $
(a)
Amounts settled at close of sale to MEHC.
For the years ended March 31 , 2006 and 2005, receivables and expenses included amounts allocated to Scottish Power
UK pIc ("SPUK"), an indirect subsidiary of ScottishPower, by PacifiCorp for administrative services provided under
ScottishPower s affiliated interest cross-charge policy. For the year ended March 3l, 2006, expenses also included
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
-...--..---,,'.......-...
Page 101 of160
(c)
costs associated with retention agreements and severance benefits reimbursed by SPUK. (n addition, PacifiCorp
recharged to SPUK payroll costs and related benefits ofPacifiCorp employees working on international assignment in
the United Kingdom for ScottishPower during the years ended March 31, 2006, 2005 and 2004.
Amounts shown pertain to activities ofPacifiCorp with its former parent PHI and its subsidiaries. Expenses recharged
reflect costs for support services to PHI and its subsidiaries. Amounts due from PHI and its subsidiaries included $33.
million as of March 31, 2005 ofincome taxes receivable from PHI. PHI was the tax-paying entity while PacifiCorp
was owned by ScottishPower.
TI1ese expenses primarily related to operating lease payments for the West Valley facility, located in Utah and owned
by West Valley Leasing Company, LLC ("West Valley ). West Valley is a subsidiary ofPPM Energy, Inc. ("PPM"
which is a subsidiary of PHI. The lease is a 15 year operating lease on an electric generation facility. The facility
consists of five generating units each with a nameplate rating of 43.4 MW. Certain costs associated with the West
Valley lease are prepaid on an annual basis. Lease expense was $16.4 million for the year ended March 31, 2006;
$17.1 million for the year ended March 31, 2005; and $17.
(b)
http://www .see.gov/ Archives/edgar/data/75594/000007559406000028/p 10k.l1tm 5/31/06
,..,.. ".' ,....',,-
c,,
:,_:- ,"""""'"""""""""",,,_
...;0:::.._
",..""""-,."_.",,...,,,,..",-~'",....-..,-,.-""-""""-""""_.""-,,,..,..-,,,,-,,...,..",_."."-'."""",",------
Page I 02 of 160
(d)
million for the year ended March 31 , 2004. PacifiCorp has an option to terminate the West Valley lease if written
notice is provided to West Valley on or before December 1,2006. If the option to terminate is exercised, the lease
would terminate in May 2008. PacifiCorp is committed to future minimum lease payments of$IO.O million am1UaUy
for each of the 12 months ending March 31 , 2007 and 2008 and $1.7 million for tJle two months ending May 31 2008.
1llese minimum future lease payments reflect the reduction in monthly payments resulting from a March 2006
amendment to the lease tenns.
These liabilities and expenses primarily represented amollnts al1ocated to PacifiCorp by SPUK for administrative
services received under the cross-charge policy. Cross-charges nom SPUK to PacifiCorp amounted to $16.7 million
for the year ended March 3 1,2006 and $14.9 million for the year ended March 31 , 2005. These costs were recorded in
Operations and maintenance expense. SPUK also recl1arged PacifiCorp for payroll costs and related benefits of SPUK
employees working on international assignment with PacifiCorp in the United States.
lllese revenues and the associated deposits related to wheeling services billed to ,PPM. PacifiCorp provided these
services to PPM pursuant to PacifiCorp s FERC-approved open access transmission tariff, which required PacifiCorp
to make transmission services available on a non-discriminatory basis to all interested parties.
PacifiCorp began participating in a captive insurance program provided by Domoch International Insurance Limited
DIlL"), an indirect wholly owned consolidated subsidiary of Scottish Power, in May 2005. DilL covered all or
significant portions of the property damage and liability insurance dedl1ctibles in many of PacifiCorp' s policies, as
well liS overhead distribution and transmission line property damage. PacifiCorp had no equity interest in DUL and had
no obligation to contribute equity or loan funds to DIlL. Premium amounts were established to cover loss claims,
administrative expenses and appropriate reserves, but otherwise DIlL was not operated to generate profits.
Included interest on short-term demand loans made to PncifiCorp by PGHC, in accordance with regulatory
authorization.
(e)
(g)
Note 5 - Marketable Securities
PacifiCorp, by contract with Idaho Power, the minority owner of Bridger Coal Company (an indirect subsidiary
PacifiCorp), maintains a trust relating to final reclamation of a leased coal mining property. Amounts funded are based on
estimated future reclamation costs and estimated future coal deliveries. Trust fund assets associated with Bridger Coal
Company recorded at fair value included in Deferred c1larges and other were $101.9 million at March 3 I, 2006 and $92.4
million at March 31, 2005, including the Idaho Power minority-interest portion. Minority interest in Bridger Coal Company
was $49.5 million at March 31,2006 and $26.2 million at March 31, 2005. See also Note 6 - Asset Retirement Obligations
and Accrued Envirorunental Costs.
The amortized cost and fair value of reclamation trust securities and other investments included in Deferred charges and other
on PacifiCorp s Consolidated Balance Sheets, which are classified as available-for-sale, were as follows:
(Millions of dollars)
Amortized
Cost
Gron
Unrealized
Gains
Gross
UnreAlized
Losses
EsUmAletJ
Fair Value
March 31. 2006
Debt securities
Equity securities
25.9 $
61.7
2 $(0.6) $
(0.
25.
68.
Total 87.6 $2 $(1.3) $93.
March 31. 200
Mutual fund account (a)
Debt securities
Equity securities
27.(1.0) $26.
25.(0.4)25.
60.13.(1.2)72.
113.13.(2.6) $124.Total
(a) In October 2005, the mutual fund account was transferred to a money market account.
http://www.sec.gov! Archives!edgar/datal75594/000007 559406000028/p 1 Ok.htm 5!3l/06
"'-
~'CC",-
,-,:"."""""",~-
,."",#,,,._".,.",,""w",..."~",~",
,,,':"'. -
""""_"_-'M_"""_
"",-",'.-."",::.~",-"""_-""",,,,.'.'._;""-""'-""-'-"-"'--"-"-'""'~"",':"'-".'':.'"-'-'"
Page 1 03 of 160
http://www .see.gov/ Arehives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
, -"""---""'-..- ..-- "'-'-'""'.'-"..... - ""'..".."........"-",-",-",---,-...._
c.."
..-,,,,,,_..-..,,~-,-"""'~"'-,,-- ,.-'-"-"-"-""""---'_."'-
"C.
"""",'
Page 104 of 160
TIle quoted market price of securities is used to estimate their fair value.
TIle amortized cost and estimated fair value of debt securities at March 31 , 2006 and 2005 by contractual maturities and of
equity securities for the same dates are shown below. Actual maturities may differ from contractual maturities because
borrowers may have the right to call or prepay obligations with or without call or prepayment penalties.
March 31,
2006 200S
tMllllons of dollars)
Amorllzcd
Cusl
Estimated
Fair Value
Amorllud
Cosl
t:sllmaled
Fair Value
Debt securities
Due in one year or less
Due after one year through five years
Due after five years through ten years
Due after ten years
Mutual fund account
Equity securities
6.4
9.5
27.26.
61.7 68.60.72.
87.93.113.124.Total
Proceeds, gross gains and gross losses from realized sales of available-for-sale securities using the specific identification
method were as fol1ows for the years ended March 31, 2006, 2005 and 2004:
Net losses included in Net income
Years Ended March 31.
2006 2005 2004
123.4 49.1 95.
16.
(2.(2.(3.4)
14.4.1 3.1
(16.(5.(3.
(2.3) $(1.5) $(0.
(Millions of dollars)
Proceeds
Gross gains
Gross losses
Net gains
.Less net gains included in Regulatory liabilities (a)
(a)Realized gains and losses on the Bridger Coal Company reclamation trust described above are recorded as a regulatory
liability in accordance with the prescribed regulatory treatment.
Note 6 - Asset Retiremcnt Obligations and Accrued Environmental Costs
5..Sel Relirf!lnellt Obligfl!if!.l!!i. - PacifiCorp records asset retirement obligations for long-lived physical assets that qualify as
legal obligations under SF AS No. 143. PacifiCorp estimates its asset retirement obligation liabilities based upon detailed
engineering calculations of the amount and timing ofthe future cash spending for a third party to perform the required work.
Spending estimates are escalated for intlation and then discounted at a credit-adjusted, risk-free rate. PacifiCorp then records
an asset retirement obligation asset associated with the liability. TIle asset retirement obligation assets are depreciated over
their expected lives and the asset retirement obligation liabilities are accreted to the projected spending date. Changes in
estimates could occur due to plan revisions, changes in estimated costs and changes in timing of the performance of
reclamation activities. In addition, PacifiCorp records removal costs as a part of depreciation expense in accordance with
regulatory accounting requirements described in Note 2 - Accounting for the Effects of Regulation. Since asset retirement
costs are recovered through the ratemaking process, PacifiCorp records a regulatory asset or regulatory liability on the
Consolidated Balance Sheets to account for the difference between asset retirement costs as currently approved in rates and
http://www.see.gov/Archives/edgar/datal75594/000007 5 59406000028/p 1 Ok.htm 5/31/06
........-..--""-' , ,",-",,",-,"'
C"" -
:-.-:,-
"W"~"-""
:..:-.-"-"-----""'-'-",""'-.."-"-"'" ,_.'-'."'~-'-",,""-'-"',..," ."."'--"-"'.""'-'-"""'-'~'
Page 1 05 of 160
costs under SFAS No. 143.
PacifiCorp does not recognize liabilities for asset retirement obligations for which the fair value cannot be reasonably
estimated. PacifiCorp has asset retirement obligations associated with its transmission and distribution
http://www.sec.gov/Archives/edgar/data/75 594/000007 5S9406000028/p 1 Ok.htm 5/31/06
~-"-'-~'.""",-- """,""...---....,,..-'..--""'""-
.....-",~-M",
,,'-~"'-,':_""""""""'-'~'_'-""",,-::. "',"""
""""..CC"'-----'"""""-
"::;,-.-.""-""'_"""'~-","."",-"...::::::'--""::"'..-~",-
"v_'-""""""""'
"""""",
;'::;;:O
Page 1 06 of 160
systems and certain coal mines. However, due to the indeterminate removal date, the fair value of the associated liabilities
currently cannot be estimated and no amounts are recognized in the Consolidated Financial Statements.
In March 2005, the FASB issued FIN 47. FIN 47 clarifies that an entity is required to recognize a liability for the fair value of
a conditional asset retirement obHgation when incurred if the fair value of the liability can be reasonably estimated. Upon
adoption of FIN 47 at March 31, 2006, PacifiCorp recorded an asset retirement obligation liability at a net present value of
$22.7 million. PacifiCorp also increased net depreciable assets by $1.8 million, reclassified $13.5 million of costs accrued for
retirement removals from regulatory liabilities to asset retirement obligation liabilities, increased regulatory liabilities by $0.4
million and increased regulatory assets by $7.8 million for the difference between retirement costs approved by regulators
and obligations under FIN 47.
The pro forma total asset retirement obligation liability balances that would have been reported assuming FIN 47 had been
adopted on April I, 2004, rather than March 31, 2006, are as follows:
(Millions of dollars)
Pro forma asset retirement obligation liability at Aprill , 2004
Pro forma asset retirement obligation liability at March 31, 2005
$215.
$222.
Due to regulatory accounting treatment, the adoption of FIN 47 would have no material impact on net income for the pro
fornla periods listed above and had no impact on PacifiCorp s reported cash flows.
The following table describes the changes to PacifiCorp s asset retirement obligation liability for the years ended March 31,
2006 and 2005:
Long-tenn asset retirement obligation at end of period (e)
March 31,March JI,
1006 200S
199.193.
25.1.4
(10.4)(13.
(11.2)
212.199.
17.
205.181.8
(J\lIIlIons or dollars)
Liability recognized at beginning of period
Liabilities incurred (a)
Liabilities settled (b)
Revisions in cash flow (c)
Accretion expense
Asset retirement obligation
Less current portion (d)
(a) Relates primarily to the adoption of FIN 47 at March 31,2006.
(b) Relates primarily to ongoing reclamation work at the Glenrock coal mine.
(c) Results from changes in the timing and amounts of estimated cash flows for certain plant reclamation.
(d) Amount included in Other current liabilities on the Consolidated Balance Sheets.
(e) Amount included in Deferred credits - other on the Consolidated Balance Sheets.
PacifiCorp had trust fund assets recorded at fair value included in Deferred charges and other of$103.0 million at March 31
2006 and $93.4 million at March 31,2005 relating to mine and plant reclamation, including the minority-interest joint-owner
portions.
Accmed E"v;rolllne"la.1..!;fJ.'i/.- PacifiCorp s policy is to accrue environmental cleanup-related costs of a non-capital nature
when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures
is based on assessments of many factors, including changing laws and regulations, advancements in environmental
tec1mologies, the quality of information available related to specific sites, the assessment stage of each site investigation.
preliminary findings and the length of time involved in remediation or settlement. PacifiCorp hires external consultants from
time to time to conduct studies in order to establish reserves for various site environmental remediation costs. PacifiCorp is
subject to cost-sharing agreements with other potentially responsible parties based on decrees, orders and other legal
http://www.see.gov/ Archives/edgar/datal7 5594/000007559406000028/p 1 Ok.htm 5/31/06
e""--.
:.--
"c:-
,~--~_._-.'-", --",.:,_._~~-".,.=~,..",-::,;-"."-="""-",,.,,,,",,,-,:-"""-,-"""",""-,-,-.....'""",,..,..,,:-
c:_
;..,,----,-
""""M"",-'=W~=-"
Page 1 07 of 160
agreements. In lhese circumstances, PacifiCorp assesses the financial capability of other potentially responsible parties and
the reasonableness of
http://www.sec.gov/ Archives/edgar/data/75594/O00007559406000028/p 10k.htm 5/31/06
Page 108 of 160
PacifiCorp s apportionment. These agreements may affect the range of potential loss. Additionally, PacifiCorp may benefit
from excess insurance policies that may cover some of the cleanup costs if costs incurred exceed certain amounts.
PacifiCorp assesses its potential obligations to perform environmental remediation on an ongoing basis. As n result of studies
performed during the year ended March 31 , 2006, PacifiCorp increased its reserve by $9.7 million to reflect its most likely
estimate for probable liabilities. Remediation costs that are fixed and determinable have been discounted to their present
value using credit-adjusted, risk-free discount rates based on the expected future annual borrowing rates ofPacifiCorp. The
liability recorded was $38.5 million at March 31, 2006 and $33.3 million at March 31 , 2005 and is included as part of
Deferred credits - other. The March 31 , 2006 recorded liability included $18.1 million of discounted liabilities. Had none of
the liabilities included in the $38.5 million balance recorded at March 31, 2006 been discounted, tl1e total would have been
$40.7 million. TI1e expected payments for each of the five 12 month periods ending March 31 and thereafter are as follows;
$5.4 million in 2007, $3.9 million in 2008, $2.4 million in 2009, $1.5 million in 2010, $1.2 million in 2011 and $26.3 million
thereafter.
It is possible that future findings or changes in estimates could require that additional amounts be accrued. Should current
circumstances change, it is possible that PacifiCorp could incur an additional undiscounted obligation of up to approximately
$53.1 million relating to existing sites. However, management believes that completion or resolution of these matters wilt
have no material adverse effect on PacifiCorp s consolidated fmancial position or results of operations.
Note 7 - Notes Payable and Commercial Paper
Amounts outstanding under PacifiCorp s short-term notes payable and commercial paper arrangements were as follows:
(MIllions of tlollars)nalance
\\'crage
Inlerest
Rale
March 31 , 2006
March 31, 2005
184.4
468.
Revolving CrelUt Agrecment
PacifiCorp amended and restated its existing $800.0 million commiued bank revolving credit agreement in August 2005.
Changes included an increase to 65.0% in the covenant not to exceed a specified debt-to-capitalization percentage, extension
of the termination date 10 August 29, 2010 and exclusion ofthe acquisition of Paci fi Corp by MEHC as an event of default
under the agreement. As of March 31, 2006, PacifiCorp s revolving credit agreement was fully available and had no
borrowings outstanding. The interest on advances under this facility is generally based on Ihe London Interbank Offered Rate
(LIBOR) plus a margin thai varies based on PncifiCorp s credit ratings. This facility supports PacifiCorp s commercial paper
program and $38.1 million of variable rate pollution control revenue bonds.
PacifiCorp s revolving credil agreement contains customary covenants and default provisions and PacifiCorp monitors these
covenants on a regular basis. As of March 31 2006, PacifiCorp was in compliance with the covenants of its revolving credit
agreement.
http://www.sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
Note 8 - Long-Term Debt :md Capital Lease Obligations
PacifiCol1"s long-term debt and capital lease obligations were as follows:
(Millions of dollars)
Page 1 09 of 160
March JI,
2006 2005
Amount
wt mQ!1gage bonds
3% to 8., due through 2011
0% to 9., due 2012 to 2016
5% to 8.6%, due 2017 to 2021
7% to 8.5%, due 2022 to 2026
5.3 % to 7., due 2032 to 2036
Unamorlized discount
Guaranty of pollution-control revenue l1ds
Variable rates, due 2014 (a) (b)
Variable rates, due 2014 to 2026 (b)
Variable rates, due 2025 (a) (b)
3.4% to 5.7%, due 2014 to 2026 (a)
2%, due 2031
Unamortized discount
Funds held by trustees
itallease obligations
10.4% to 14., due through 2035
901.7
040.4
424.
800.
(4.
40.
325.
175.
184.
12.
(0.5)
(2.
35.
937.
(216.
721.0
Total
Less current maturities
Total
t\verage
Interest
!tate Amoullt
Average
Interest
Rate
7.4
) 1.9
(a) Secured by pledged first mortgage bonds generally at the same interest rates, maturity dates and redemption provisions as
the pollution-control revenue bonds.
(b) Interest rates fluctuate based on various rates, primarily on certificate of deposit rates, interbank borrowing rates, prime
rates or other short-term market rates.
First mortgage bonds ofPacifiCorp may be issued in amounts limited by PacifiCol1"s property, earnings and other provisions
of the mortgage indenture. Approximately $13.8 billion of the eligible assets (based on original cost) ofPacifiCorp are
subject to the lien ofthe mortgage.
Approximately $2.3 billion of first mortgage bonds were redeemable at PacifiCorp s option at March 31 , 2006 at redemption
prices dependent upon United States Treasury yields. Approximately $54 1.7 million of variable-rate pollution-control
revenue bonds were redeemable at PacifiCorp s option at par at March 31, 2006. Approximately $7).2 million of fixed-ratc
poJlution-control revenue bonds were redeemable at PacifiCorp s option at par at March 31 , 2006. TI1C remaining long-term
debt was not redeemable at March 31,2006.
0%$171.4
040.4
8.5
7.4 424.
500.
(4.
40.
325.
175.
184.
12.
(0.5)
(2.
11.7 26.
In September 2005, the SEC declared effective PacifiCorp s shelf registration statement covering $700.0 mi1lion of future
first mortgage bond and unsecured debt issuances. PacifiCorp has not yet issued any of the securities covered by this
registration statement.
898.
(269.
$ 3,629.
http://www .see.gov/ Archives/edgar/datal7 5594/0000075 59406000028/p 1 Ok.htm 5/31/06
Page 11 0 of 160
In June 2005, PacifiCorp issued $300.0 million of its 5.25% Series of First Mortgage Bonds due June 15, 2035. PacifiCorp
used tbe proceeds for the reduction of short-term debt, including the short-term debt used in December 2004 to redeem its
625% Series of First Mortgage Bonds due December 13 2024 totaling $20.0 million.
http://www.sec.gov/Archives/edgar/datal75 594/00000755940600002 8/p 1 Ok.htm 5/31/06
Page 111 of 160
In March 2005, tIte maturity dates were extended to December 1 2020 for tluee series of variable-rate pollution-control
revenue bonds totaling $38.1 million.
PacifiCorp leases equipment and real estate in various states in which it docs business under long-term agreements, extending
through March 2035, which are classified as capital leases. These capital leases are payable in monthly installments allocated
between principal and imputed interest rates ranging from 10.4% to 14.8%.
In April 2005, PacifiCorp entered into a 30-year transportation service agreement with Questar Pipeline Company for the
right to use a newly constructed pipeline facility with a majority of the output designated to provide natural gas to the Currant
Creek Power Plant. l11is agreement qualifies as a capital lease with an initial net present value lease obligation of$12A
million at an imputed interest rate of 11.3%.
The annual maturities oflong-term debt and capital lease obligations for the 12 months ending March 31 are:
(Millions or dollars)
Long-term
Debt
2007
2008
2009
2010
2011
111ereafier
216.3 $
119.
412.4
138.
14.
007.
Unamortized discount
Funds held by trustee
Amounts representing interest
909.
(5.
(2.
$ 3,902.
Capital Lease
Obligations
8 $
63.
88.
(52.3)
Tllt31
221.1
124.
417.
143.5
19.5
071.6
997.
(5.
(2.
(52.
35.8 $ 3 937.
PacifiCorp made interest payments, net of capitalized interest, of $240.3 million for the year ended March 31, 2006; $220.4
million for the year ended March 31 , 2005; and $236.7 million for the year ended March 31, 2004.
At March 31, 2006, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements
available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. In
addition, PacifiCorp had approximately $40.5 million of standby letters of credit to provide credit support for certain
transactions as requested by third parties. These committed bank arrangements were all fully available as of March 31 , 2006
and expire periodically through the 12 months ending March 3 I , 2011.
PacifiCorp s standby letters of credit and standby bond purchase agreements generally contain similar covenants to those
contained in PacifiCorp s revolving credit agreement, although the maximum permitted debt-to-capitalization ratio for one of
the standby bond purchase agreements was 60.0% as of March 31 2006 and was amended in May 2006 to now permit a
maximum ratio of 65.0%. See Note 7 - Notes Payable and Commercial Paper for further information. PacifiCorp monitors
these covenants on a regular basis in order to ensure that events of default will not occur and as of March 31 , 2006,
PacifiCorp was in compliance with the covenants of these agreements.
Note 9 - Preferred Stock Subject to Mnndntory Redemption
March 31, 2006 March 31, 2005
Shares Amollnt Shares Amonnt
450 45.525 52.
PacifiCorp s Preferred stock subject to mandatory redemption was as follows:
(Thollsands of shares, millions of dona")
Series
Preferred stock subject to mandatory redemption $7.48 No Par Serial
Preferred, $100 stated value, 16 000 shares authorized
http://www.sec.gov/Archives/edgar/datal75594/000007 5 59406000028/p 1 Ok.htm 5/31/06
Page 112 of 160
http://www .see.gov/ Arehives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
Page 113 of 160
PacifiCorp has mandatory redemption requirements on 37 500 shares of the $7.48 series Preferred stock on June 15 2006
with a non-cumulative option to redeem an additional 37,500 shares on June 15,2006, at $100.0 per share, plus accrued and
unpaid dividends to the date of such redemption. AU outstanding shares on June 15,2007 are subject to mandatory
redemption. Holders of Preferred stock subject to mandatory redemption are entitled to certain voting rights and may have
the right to elect members to the PacifiCorp Board of Directors in the event dividends payable are in default in an amount
equal to four full quarterly payments. PacifiCorp redeemed $7.5 million of Preferred stock subject to mandatory and optional
redemption during each of the years ended March 31,2006,2005 and 2004.
PacifiCorp had $0.8 million at March 31,2006 and $1.0 million at March 3l , 2005 in dividends declared but unpaid on
Preferred stock subject 10 mandatory redemption that were included in Interest payable.
Note 10 - Commitments and Contlngendcs
PacifiCorp follows SF AS No., to determine accounting and disclosure requirements for contingencies. PacifiCorp operates
in a highly regulated environment. Governmental bodies such as the FERC, state regulatory commissions, the SEC, the
Internal Revenue Service, the Department of Labor, the United States Environmental Protection Agency (the "EPA") and
others have autllority over various aspects ofPacifiCorp s business operations and public reporting. Reserves are established
when required in management's judgment, and disclosures regarding litigation, assessments and creditworthiness of
customers or counterparties, among others, are made when appropriate. The evaluation of these contingencies is performed
by various specialists inside and outside ofPacifiCorp.
From time to time, PacifiCorp is also a party to various legal claims, actions, complaints and disputes, certain of which
involve material amounts. PacifiCorp has recorded $6.7 million in reserves as of March 31, 2006 related to various
outstanding legal actions and disputes, excluding those discussed below. This amount represents PacifiCorp s best estimate
of probable losses related to these matters. PacifiCorp currently believes that disposition of these matters witt not have a
material adverse effect on PacifiCorp s consolidated financial position, results of operations or liquidity.
Ellv;rollmelltal matters - PacifiCorp is subject to numerous environmental laws, including the federal Clean Air Act and
various state air quality laws; the Endangered Species Act, particularly as it relates to certain endangered species offish; the
Comprehensive Environmental Response, Compensation and Liability Act, and similar state laws relating to environmental
cleanups; the Resource Conservation and Recovery Act and similar state laws relating to the storage and handling of
hazardous materials; and the Clean Water Act, and similar state laws relating to water quality. These laws could potentially
impact future operations. Environmental contingencies identified at March 31, 2006 principally consist of air quality matters.
Pending or proposed air regulations will require PncifiCorp to reduce its electricity plant emissions of sulfur dioxide, nitrogen
oxides and other pollutants below current levels. These reductions will be required to address regional haze programs,
mercury emissions regulations and possible re-interpretations and changes to tbe federal Clean Air Act. In the future
PacifiCorp expects to incur significant costs to comply with various stricter air emissions requirements. These potential costs
are expected to consist primarily of capital expenditures. PacifiCorp expects these costs would be included in rates and, as
such, would not have a material adverse impact on PacifiCorp s consolidated results of operations. See also Note 6 - Asset
Retirement Obligations and Accrued Environmental Costs.
Hy.llroelectric relicellsillg - PacifiCorp s hydroelectric portfolio consists of 51 plants with an aggregate plant net capability of
159.4 MW. The FERC regulates 93.9% of the installed capacity of this portfolio through 18 individual licenses. Several of
PacifiCorp s hydroelectric projects are in some stage of relic en sing under the Federal Power Act. Hydroelectric relicensing
and the related environmental compliance requirements arc subject to uncertainties. PacifiCorp expects that future costs
relating to these matters may be significant and will consist primarily of additional relicensing costs, operations and
maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional
environmental requirements. PacifiCorp had incurred $70.3 million in costs as of March 31, 2006 for ongoing hydroelectric
relicensing, which are reflected in Construction work-ill-progress on the Consolidated Balance Sheet. PacifiCorp expects that
these and future costs will be included in rates and, as such, will not have a material adverse impact 00 PacifiCorp
consolidated finaociai position or results of operations.
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
Page 114 of 160
In October 2005, the new FERC license for the North Umpqua hydroelectric project became final under the terms of tbe
North Umpqua Settlement Agreemenl.Prior to this date, the license had been effective, but not final, because environmental
groups had challenged its legality before the FERC and in federal court. In September 2005, the Ninth Circuit Court of
Appeals issued an order upholding the new license. Since the Court's order was not appealed within the allowed time, aU
legal challenges of the FERC license order have been exhausted and the license is final for purposes of recording liabilities.
PacifiCorp is committed, over the 35-year life of the license, to fund approximately $48.4 million for environmental
mitigation and enhancement project!;. As a result of the license becoming final, PacifiCorp recorded additional liabilities and
intangible assets in October 2005 amounting to a present value of $11.2 million. At March 31, 2006, the liability recorded for
all North Umpqua obligations amounted to a present value oU21.S million.
FERC Issue.!
Cali/om;" Refilm! Case - PacifiCorp is a party to aFERC proceeding that is investigating potential refunds for energy
transactions in the California Independent System Operator and the California Power Exchange markets during past periods
ofhigb energy prices. PacifiCorp has a reserve of$17.7 million for these potential refunds. PacifiCorp s ultimate exposure to
refunds is dependent upon any order issued by the FERC in this proceeding. In addition, beginning in summer 2000
California market conditions resulted in defaults of amounts due to PacifiCorp from certain counterparties resulting from
transactions with the California Independent System Operator and California Power Exchange. PacifiCorp has reserved $5.
million for these receivables.
FERC Mar/fet Po Iller AmtlJ'.Sis - Pursuant to the FERC's orders granting PacifiCorp authority to sell capacity and energy at
market-based rates, PacifiCorp and certain of its former affiliates had been required to submit a joint market power analysis
every three years. Under the FERC's current policy, applicants must demonstrnte that they do not possess market power in
order to charge market-based rates for sales of wholesale energy and capacity in the applicants' control areas. An analysis
demonstrating an applicant's passage of certain threshold screens for assessing generation market powcr establishes a
rebuttable presumption that the applicant does not possess generation market power, white failure to pass any screen creates a
rebuttable presumption that the applicant has generation market power. (n February 2005, PacifiCorp submitted ajoint
triennial market power analysis in c~mpliance with the FERC's requirements. TIle analysis indicated thatPacifiCorp failed to
pass one ofthe generation market power screens in PacifiCorp s eastern control area and in Idaho Power Company s control
area. In May 2005, the FERC issued an order instituting a proceeding pursuant to section 206 of the Federal Power Act to
determine whether PacifiCorp may continue to charge market-based rates for sales of wholesale energy and capacity. Under
Ole tem1S of the order, PacifiCorp and its formerly affiliated co.applicants were required to submit additional information and
analysis to the FERC within 60 days 10 rebut the presumption that PacifiCorp has generation market power. In June and July
2005, PacifiCorp filed additional analysis in response to the FERC's May 2005 order. In January 2006, the FERC requested
PaciliCorp to amend its previous filings with additional analysis, which was filed in March 2006. If the FERC ultimately
finds that PacifiCorp bas market power, PacifiCorp will be required to implement measures to mitigate any exercise of
market power, which may result in decreased revenues and/or increased operating expenses. PacifiCorp believes the outcome
of this proceeding wilt not have a material impact on its consolidated financial position or results of operations.
Note 11 - Guarantees and Other Commitments
Guarantees
PacifiCorp is generally required to obtain state regulatory commission approval prior to guaranteeing debt or obligations of
other parties. In November 2002, the FASB issued Interpretation No. 45 Guarantor s Accou/lti/lg and Di.c/osure
Requiremellts for Gllal'llllCeeS, III eluding III direct Guarantees of Indebtedness of Others FIN 45"). FIN 45 requires
disclosure of certain direct and indirect guarantees.
The following represent the indemnification obligations ofPacifiCorp as of March 31, 2006 and 2005.
PacifiCorp has made certain commitments related to the decommissioning or reclamation of certain jointly owned facilities
and mine sites. The decommissioning guarantees require PacifiCorp to pay a proportionate share of the decommissioning
costs based upon percentage of ownership. TIle mine reclamation obligations requirePacifiCorp to pay the mining entity a
proportionate share of the mine s reclamation costs based on the amount of coal purchased by PacifiCorp.ln the event of
default by any of the other joint participants, PacifiCorp potentially may be obligated to absorb, directly or by paying
additional sums to the entity, a proportionate share of the defaulting party's liability.
http://www.see.gov/Arehives/edgar/datal7 5 594/000007559406000028/p 1 Ok.hun 5/31/06
-,---..--..--........--..---..--,.-.......--..--..-....-.
Page 115 ofl60
PacifiCorp has recorded its estimated share of the decommissioning and reclamation obligations as either an asset retirement
obligation, regulatory liability or other liability.
In connection with tJ1e sale ofPacifiCorp s Montana service territory, PacifiCorp entered into a purchase and sale agreement
with Flathead Electric Cooperative in October 1998. Under the agreement, PacifiCorp indemnified Flathead Electric
Cooperative for losses, if any, occurring after the closing date and arising as a result of certain breaches of warranty or
covenants. The indemnification has a cap of $1 0.1 million until October 2008 and a cap of $5.1 ,million thereafter (less
expended costs to date). Two indemnity claims relating to environmental issues have been tendered, but remediation costs for
these claims, if any, are not expected to be material.
From time to time, PacifiCorp executes contracts that include indemnities typical for the underlying transactions, which are
related to sales of businesses, property, plant and equipment, and service territories. These indemnities might include any of
the following matters: privacy rights; governmental regulations and employment-related issues; commercial contractual
relationships; financial reports; tax-related issues; securities laws; and environmental-related issues. Perfonnance under these
indemnities generally would be triggered by breach of representations and warranties in the contract. PacifiCorp regularly
evaluates the probability of having to incur costs under the indemnities and appropriately accrues for expected losses that are
probable and estimable. Some of these indemnities may not limit potential liability; therefore, PacifiCorp is unable to
estimate a maximum potential amount of future payments that could result from claims made under these indemnities.
PacifiCorp believes that the likelihood that it would be required to perform or otherwise incur any significant losses
associated with any oftbese obligations is remote.
Unconditional Purchase Obligations
Construction
Operating leases
Purchased electricity
Transmission
Fuel
Other
rayments due during the 12 months ending Mareh 31.
2007 2008 2009 2010 2011 fhereafter Tolal
111.4 $33.2 $144.
15.15.3 2.1 46.
756.3 426.284.1 290.258.146.162.4
45.39.37.35.3 36.503.698.
516.600.5 522.5 452.339.931.5 363.
52.61.0 59.53.53.4 837.117.
$1,497.8 $1 176.2 $906.7 $834.3 $690.1 $5,427.3 $10,532.4
(Millions of dollars)
Total commitments
Constr.uctio"- PacifiCorp has an ongoing construction program to meet increased electricity usage, customer growth and
system reliability objectives. At March 31, 2006, PacifiCorp had estimated long-term unconditional purchase obligations for
constmction of the new Lake Side Power Plant.
Qp..eratittg leases - PacifiCorp leases offices, certain operating facilities, land and equipment under operating leases that
expire at various dates through the 12 months ended March 31 2093. Certain leases contain renewal options for varying
periods and escalation clauses for adjusting rent to reflect changes in price indices. These leases generally require PacifiCorp
to pay for insurance, taxes and maintenance applicable to the leased property. Excluded from the operating lease payments
above are any power purchase agreements that meet the definition of an operating lease.
Net rent expense was $28.8 million for the year ended March 31 , 2006; $26.1 million for the year ended March 3 I, 2005; and
$29.4 million for the year ended March 31 , 2004.
Minimum non-cancelable sublease rent payments expected to be received through the 12 months ended March 31, 2013 total
$6.8 million.
Pure/lased electricity.- As part of its energy resource portfolio, PacifiCorp acquires a portion of its electricity through long-
tem1 purchases amVor exchange agreements. Included in the purchased electricity payments above are any power purchase
agreements that meet the definition of an operating lease.
http://www.see.gov/ Archives/edgar/datal? 5594/00000?559406000028/p 1 Ok.htm 5/31/06
Page 116 ofl60
http://www .see.goyl Arehiyes/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31106
Page 117 ofl60
Included in the minimum fixed annual payments for purchased electricity above are commitments to purchase electricity
from several hydroelectric projects under long-term arrangements with public utility districts. These purchases are made on a
cost-of-service" basis for II stated percentage of project output and for a like percentage of project operating expenses and
debt service. 111ese costs are included in Energy costs in the Consolidated Statements ofIncome. PacifiCorp is required to
pay its portion of operating costs and its portion of the debt service, whether or not any electricity is produced.
At March 3 J , 2006, PacifiCorp s share oflong-teml arrangements with public utility districts was as follows:
(MIllions or dollars)
Wanapum
Rocky Reach
Priest Rapids
Wells
YearCunluti Capacity I'errentagc Annual
Elplres (I\IW)orOutpul Costs (0)
2009 194.1 18.7%$
20J)67.
2045 61.0
2018 58.3
381.2 14.
Generallng Jo'aellll)'
Total
(a)Includcs debt service totaling $7.0 million,
PacifiCorp s minimum debt service and estimated operating obligations included in purchased electricity above for the 12
months ending March 31 are as follows:
2007
2008
2009
2010
2011
ll1ereafter
Minimum
Debt Operating
Servin Obligations
8.3
8.4
55.84.
92.JI9.
(1\1l11lons or dollars)
PacifiCorp has II 4.0% entitlement to the generation of the Intem1Ountain Power Project, located in central Utah, through a
power purchase agreement. PacifiCorp and the City of Los Angeles have agreed that the City of Los Angeles witt purchase
capacity and energy from PacifiCorp s 4.0% entitlement of the Intermountain Power Project at a price equivalent to 4.0% of
the expenses and debt service of the project.
Flffll PacifiCorp has "take or pay" coal and natural gas contracts that require minimum payments.
Q1JY!.! - Unconditional purchase obligations, as defined by accounting standards, are those long-term commitments that are
non-cancelable or cancelable only under certain conditions. PacifiCorp has such commitments related to legal or contractual
asset retirement obligations, environmental obligations, hydroelectric obligations, equipment maintenance and various other
service and maintenance agreements.
ncsollrcc Managcmc!1
PacifiCorp, as a public utility and It franchise supplier, has an obligation to manage resources to supply its customers. Rates
charged to most customers are tariff rates authorized by regulatory agencies as discussed in Note 2 - Accounting for the
Effects of Regulation.
http://www.see.goY/Archives/edgar/data/75594/000007 5 59406000028/p 1 Ok.htrn 5/31/06
Page 118 of 160
http://www .see.gov/ Arehives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
Page 119 of 160
Note 12 - Jointly Owned Facilities
At March 31, 2006, PacifiCorp s share in jointly owned facilities was as follows:
Total
Plant A~~un1Ulaled Cnnstru~lIon
PatiOCorp Del're~latillnl Work-In-
Share Senlce Amortization rugress
66.7%$922.467.18.
80.308.165.14.
93.307.142.5 1.8
10.239.116.1.5
60.212.99.4
50.167.38.1.6
19.165.71.3
24.41.1 18.1.0
78.36.10.4
12.26.4 12.
Various 78.21.2
157.75.
662.240.48.
(Millions of dollars)
Jim Bridger Nos. 1-4 (a)
Wyodak
Hunter No. I
Colstrip Nos. 3 and 4 (a)
Hunter No.
Henniston (b)
Craig Station Nos. I and 2
Hayden Station No. I
Foote Creek
l'Iayden Station No.
Trojan (c)
Other transmission and distribution plants
Unallocated acquisition adjustments (d)
(c)
Includes kilovolt lines and substations.
Additionally, PacifiCorp has contracted to purchase the remaining 50.0% of the output of the Hermiston Plant. See
Note 13 - Consolidation of Variable-Interest Entities.
The Trojan Plant was closed in 1993 and PacifiCorp is allowed recovery of costs associated with tl1e plant over the
remaining life of the original license. Plant, inventory, fuel and deconunissioning costs totaling $8.1 million relating to
the Trojan Plant were included in regulatory assets at March 31, 2006.
Represents the excess of the costs of the acquired interests in purchased facilities over their original net book values.
(a)
(b)
(d)
Under the joint ownership agreements, each participating utility is responsible for financing its share of construction
operating and lensing costs. PacifiCorp s portion is recorded in its applicable construction work-in-progress, operations,
maintenance and tax accounts, which is consistent with wholly owned plants.
Note 13 - Consolidntion of Variable-Interest Entities
In December 2003, the F ASB issued revised FIN 46 Consolidclliml of Variable-Interest Emities, an illterpretatioll of
ACCOIl1Itillg Research Bulletill No. 5/ ("FIN 46R"), which requires existing unconsolidated variable-interest entities ("VIEs
to be consolidated by their primary beneficiaries if the entities do not effectively disperse risks among parties involved. FIN
46R was adopted as of January I, 2004 and resulted in disclosures describing identifiable variable interests.
VIE's Required to be Consolidated
PacifiCorp holds an undivided interest in 50.0% of the 474-MW Hermiston Plant (see Note 12 - Jointly Owned Facilities),
procures 100.0% of the fuel input into the plant and subsequently receives 100.0% of the generated electricity, 50.0% of
which is acquired through a long-tenD purchase power agreement. As a result PacifiCorp holds a variable interest in the joint
owner of the remaining 50.0% of the plant and is the primary beneficiary. However, upon adoption of FIN 46R, PacifiCorp
was unable to obtain the information necessary to consolidate the entity, because the entity did not agree to supply the
infom1ation due to the lack of a contractual obligation to do so. PacifiCorp continues to request from the entity the
information necessary to perform the consolidation; however, no information has yet been provided by the entity. Electricity
purcbased from the joint owner was $35.2 million during tlte year ended March 31, 2006; $34.8 million during the year
ended March
http://www.sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
....----.-....-....-....-....-..
Page 120 of 160
http://www.see.goy/ Archiyes/edgar/data/75594/000007 559406000028/p 10khtm 5/31/06
......,.."'....--.----..--....----... .........--.---..""-'-'.'--"."'--.-'"
Page 121 of 160
2005; and $33.7 million during the year ended March 31 2004. TI1e entity is operated by the equity owners, and
PacifiCorp has no risk of loss in relation to the entity in the event of a disaster.
Significant Variable-Interests in VIE's not Required to be Consolidated
As discussed in Note 4 - Related-Party Transactions, PacifiCorp leases the West VaHey facility from a fom1er affiliate under
an operating lease that contains purchase options at specified prices. Although the purchase options are variable-interests in
West Valley, PacifiCorp is not the primary beneficiary of the entity. PacifiCorp s exposure to loss under the operating lease
is negligible.
PacifiCorp is a party to certain operating and coal purchase agreements with Trapper Mining, Inc. that create a variable
interest under the provisions of FIN 46R. Trapper Mining, Inc. owns and operates the Trapper Mine near Craig, Colorado
and produces 100.0% of its output for tl1e benefit of the Craig Power Plant. PacifiCorp has a 21.4% equity interest in Trapper
Mining, Inc. and also holds a 19.3% undivided interest in the Craig Power Plant as disclosed in Note 12 - Jointly Owned
Facilities. Since each equity investor in Trapper Mining, Inc. also holds a similar interest in the Craig Power Plant, and since
none of the joint owners have more than a 50.0% interest in the Craig Power Plant or Trapper Mining, Inc., none of the joint
owners are required to consolidate Trupper Mining, Inc. Accordingly, PacifiCorp will continue to account for its interest in
Trapper Mining, Inc. via the equity method under APB No. 18, The Equity Metlw(1 of Accolllltblgfor Investments ill Commo"
Stock as in prior periods.
Note 14 - Preferred Stock
PacifiCorp s Preferred stock was as follows:
(Thousands of shares, millions of dollars, excepl per share
amounts)
Series
Redempllon
Price
er Share
Mareh 31,2006 March 31, 1005
Shares ,\mollnt Shares "mounl
Preferred stock not subject to mandatory
redemption Serial Preferred, $100 staled
value, 3,500 shares authorized
52%
4.56
5.40
103.5
102.8.4 8.4
103.
100.
101.
Non-
redeemable
Non -
redeemable 1.8 1.8
110.126 12.126 12.
415 41.3 415 41.3
5% Preferred, $100 stated value, 127 shares
authorized
Generally, Preferred stock is redeemable at slipulated prices plus accrued dividends, subject to certain restrictions. Upon
voluntary liquidation, all Preferred stock is entitled to stated value or a specified preference amount per share plus accrued
dividends. Upon involuntary liquidation, an Preferred stock is entitled to stated value plus accrued dividends. Any premium
paid on redemptions of Preferred stock is capitalized, and recovery is sought through future rates. Dividends on all Preferred
stock are cumulative. Holders also have tIle right to elect members to the PacifiCorp Board of Directors in the event
dividends payable are in default in an amount equal to four fun quarterly payments.
PacifiCorp had $0.5 million at both March 31, 2006 and March 31, 2005 in dividends declared but unpaid on Preferred stock.
The shares and amounts outstanding for each series of Preferred stock not subject to mandatory redemption were unchanged
from March 31 2004 through March 31 , 2006.
http://www.sec.gov/Archives/edgar/datal? 5594/000007 559406000028/p 1 Ok.htm 5/31/06
........-..-..-...,...-
Page 122 of 160
http://www .see.gov! Arehives/edgar/data/75594/000007559406000028/p Okhtm 5/31/06
Page 123 of 160
Note 15 - Common Shareholder s Equity
(:(11"'11(111 S/mrellOltJe.J:iE.!JAfilJ!. - PacifiCorp has one class of common stock with no par value. A total of 750 000,000 shares
were authorized and 357 060 915 sl1ares were issued and outstanding at March 31, 2006 and 312 176,089 shares were issued
and outstanding at March 31, 2005. During the year ended March 31, 2006, PacifiCorp issued 44 884 826 shares of its
common stock to PHI, its former parent company, at a total price of$484.7 million; The proceeds from the sale oftbe shares
were used to repay short-term debt.
On March 20, 2006, immediately prior to the closing ofPacifiCorp s sale to MEHC, PacifiCorp paid a dividend on common
stock, at that time held by PHI, in tlle aggregate amount of $16.8 million. The dividend was reduced pursuant to Amendment
No. lto the Stock Purchase Agreement among MEHC, ScottishPower and PHI executed on the date of the transaction
closing from the $56.6 miUion aggregate amount originally declared by the PacifiCorp Board of Directors on January 27,
2006.
In the past, to the extent PacifiCorp did 110t reimburse ScouishPower for stock-based compensation awarded under
ScottishPower plans, such amounts increased the value of PacifiCorp s common shareholder s capital.
h!lll1111fJII Dividelld Restrict;OIIs - MEHC is the sole indirect shareholder ofPacifiCorp s common stock. The state regulatory
orders that authorized the acquisition ofl)acifiCorp by MEHC contain restrictions on PacifiCorp s ability to pay dividends to
the extent that they would reduce PacifiCorp s common stock equity below specified percentages of defined capitalization.
As of March 31, 2006, the most restrictive ofthesecOl11mitments prohibits PacifiCorp from making any distribution to PPW
Holdings LLC or MEHC without prior state regulatory approval to the extent that it would reduce PacifiCorp s common
stock equity below 48.25% of its total capitalization, excluding short-term debt and current maturities oflong-term debt.
After December 31 2008, this minimum level of common equity declines annually to 44.0% after December 3 1 2011. The
tenns oflhis commitment treat 50.0% ofPacifiCorp s preferred stock outstanding prior to the acquisition ofPacifiCorp by
MEHC as common equity. As of March 31, 2006, PacifiCorp s actual common stock equity percentage, as calculated under
this measure, exceeded the minimum tlueshold.
In addition, PacifiCorp is restricted from making any distributions toPPW Holdings LLC or MEHC ifPacifiCorp
unsecured debt rating is BBB- or lower by Standard & Poor s Rating Services or Fitch Ratings or Baa3 or lower by Moody
Investor Service, as indicated by two of the three rating services. As of March 31 , 2006, PacifiCorp s unsecured debt rating
was BBB+ by Standard & Poor s Rating Services and Fitch Ratings and Baal by Moody s Investor Service.
PacifiCorp is also subject to maximum debt-ta-total capitalization levels under various debt agreements.
Note 16 - Fair Value of Financial Instruments
(Millions of dollars)March 31, 2006 March 31, 2005
Carrying
Amount
Fair
Value
Carrying
Amount
alr
Value
Long-term debt (a) $ 3,902.1 $ 4 091.4 $ 3 872.3 $ 4 209.
Preferred stock subject to mandatory redemption 45.0 46.3 52.5 56.
(a) Includes long-tenn debt classified as currently maturing, less capilallease obligations.
The carrying value of cash and cash equivalents, receivables, payables, accrued liabilities and short-term borrowings
approximates fair value because of the short-term maturity of these instruments.
me fair value ofPacifiCorp s long-term debt, current maturities Delong-tenD debt and redeemable preferred stock has been
estimated by discounting projected future cash flows, using the current rate at which similar loans would be made to
borrowers with similar credit ratings and for the same maturities.
http://www.sec.gov/Archives/edgar/datal75594/0000075 5 9406000028/p 1 Ok.htm 5/31/06
Page 124 of 160
Note 17 - Employee Benefits
PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees and also provides health care and
life insurance benefits through various plans for eligible retirees. TIle measurement date for plan assets and obligations is
December 31 of each year.
As a result of the sale of PacifiCorp to MEHC, plan participants that were employees or retirees of certain ScottishPower
affiliates and a former PacifiCorp mining subsidiary ceased to participate in PacifiCorp s plans. This separation resulted in a
net $3.5 million reduction in Common shareholder s capital.
pensif!..l!.Xlans
PacifiCorp s pension plans include the PacifiCorp Retirement Plan (the "Retirement Plan ), the SERF and ajoint trust plan to
which PacifiCorp contributes on behalf of certain bargaining unit employees of JBEW Local 57. Benefits under the
Retirement Plan are based on the employee s years of service and average monthly pay in the 60 consecutive months of
highest payout of the last 120 months, with adjustments to reneet benefits estimated to be received from social security.
Pension costs are funded annually by no more than 11le maximum amount that can be deducted for federal income tax
purposes.
Components of the net periodic pension benefit cost (income) are summarized as follows:
2006
Years Ended March 31,
:1004
(Millions of dnllQ.rsl
Service cost (a)
Interest cost
Expected return on plan assels (b)
Amortization of unrecognized net transition obligation
Amortization of unrecognized prior service cost
Amortization of unrecognized loss
Cost oftcrmination benefits
32.2 $
74.4
(76.
1.2
21.5
Net periodic pension benefit cost 63.8 $
2005
25.9 $
73.
(77.
8.4
1.4
8.5
25.
73.
(80.
8.4
1.5
40.3 $28.
(n) Includes contributions to the PacifiCorp/LBEW Local 57 Retirement Trust Flmd of$1.4 million for the year ended March
, 2006; no contributions for the year ended March 31, 2005; and contributions of $5.6 million for the year ended March
31,2004.
(b) TIle market-related value of plan assets, among other factors, is used to detennine expected return on plan assets and is
calculated by spreading !lIe difference between expected and actual investment retums over a five-year period beginning
in the first year in which they occur.
The weighted-average rates assumed in the actuarial calculations used to detcnnine the net periodic bel1cfit costs for the
pension and postretirement benefit plans were as follows:
Years Ended March 31.
:1006 1005 2004
75%25%75%Discount rate
Expected long-tenn rate of return on assets
Rate of increase in compensation levels
PacifiCorp determined the long-term rate of return based on historical asset class returns and current market conditions
taking into account the diversification benefits of investing in multiple asset classes.
http://www .see.gov/ Archivesledgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
Page 125 of 160
http://www .see.goy! Archiyes!edgar!data/75594!000O07559406000028/p 1 Ok.htm 5/31/06
..,....,.-......--......-............'-.-"".."----'-"""'.--""..,.,-...--...--.----,..---.....,
Page 126 of 160
The weighted-average rates assumed in the acnlarinl calculations used to determine benefit obligations for the pension and
postretirement benefit plans were as follows:
March 31,
2006 2005 2004
75%75%25%Discount rate
Rate of increase in compensation levels
The change in tl1t~ projected benefit obligation, change in plan assets and funded status ofthe pension plans are as follows:
(Millions ordnllan)Mllrch 31,
2006 2005
rojectcd benefit obligatioll
Projected benefit obligation - beginning of year
Service cost
Interest cost
Plan amendments
Cost of termination benefits
Separation of former participants
Actuarial loss
Benefits paid
Transfers
Projected benefit obligation - end of year
338.1 229.
30.25.
74.4 73.
1.0
(44.
22.86.
(84.(79.1)
(1.(0.
342.338.1
Change in plan assets
Plan assets at fair value - beginning of year
Actual return on plan assets
Separation of former participants
Company contributions
Benefits paid
Transfers
806.733.
72.87.
(32.
63.65.
(84.(79.
(1.(0.
824.806.Plan assets at fair value - end of year
Reconciliation of accrued pens pn \;...Q.st and total amount recognized
Funded status of the plan
Unrecognized net loss
Unrecognized prior service cost
Unrecognized net transition obligation
(517.3) $
435.
10.
(531.6)
443.
15.
Accmed postretirement benefit before final contribution
Contribution made after measurement date but before March 31
(64.4)(63.
Accrued pension cost (60.7) $(63.
http://www .see.goYI Archiyes/edgar/data175594/000007559406000028/p 1 Ok.htm 5/31/06
,...._",-,-,...,--._-_."",.,--""""'-"-..,--,,,....-.._-_.._--...-,----....-----
Page 127 of 160
Accrued pension cost
(342.3) $(383.
17.25.
14.5
257.280.
(60.7) $(63.
Accrued benefit liability
Intangible asset
Accumulated other comprehensive income, pre-tax
Regulatory assets
http://www .see.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
"....-"....--.-....-.-..---,--..--.-..,.-.--,"..--"..--..--....-.,-"",---,-,._,."",-"",,"."'--".'-'-"'- --....---..-"..--.....--..,-."...........-.."-..-----
Page 128 of 160
The aggregated accumulated benefit obligation was $1, I 70.9 million and the fair value of assets was $828.6 million,
measured as of December 3 1,2005, and including contributions prior to March 31,2006.
The Retirement Plan and the SERP currently have assets with a fair value that is less than the accumulated benefit obligation
under the Retirement Plan and the SERP, primarily due to prior declines in the equity markets and historically low interest
rate levels. As a result, PacifiCorp recognized minimum pension liabilities in the fourth quarters of the years ended March 31
2006 and 2005. The minimum pension liability adjustment impacted Regulatory assets, Intangible assets and Accumulated
other comprehensive income. These adjustments are reflected in the table above and did not materially affect the consolidated
results of operations. PacifiCorp requested and received accounting orders from tile regulatory commissions in Utah, Oregon,
Wyoming and Washington to classify most of the minimum pension liability adjustment as a Regulatory asset instead of a
charge to Other compre1lensive income. This increase to Regulatory assets will be adjusted in future periods as the difference
between the fair value of the trust assets and the accumulated benefit obligation changes. PacifiCorp has determined that
costs related to SFAS No. 87, Employers ' Acco/Illtingfor Pensiolls SFAS No. 87") for the Retirement Plan are currently
recoverable in rates.
Retirement Plan assets are managed and invested in accordance with all applicable requirements, including the Employee
Retirement Income Security Act and the Internal Revenue Code. PacifiCorp employs an investment approach that uses a mix
of equities and fixed-income investments to maximize the long-term return of plan assets at a prudent level of risk. Risk
tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition.
The investment portfolio contains a diversified blend of equity and fixed-income investments as shown in the table below.
Equity investments are diversified across United States and non-United States stocks, as well as growth and value companies
and small and large market capitalizations. Fixed-income investments are diversified across United States and non-United
States bonds. Other assets, such as private equity investments, are used to enhance long-term returns while improving
portfolio diversification. PacifiCorp primarily minimizes the risk of1arge losses through diversification but also monitors and
manages other aspects of risk through quarterly investment portfolio reviews, annual liability measurements and periodic
asset/liability studies.
Details of the Retirement Plan asset~ by investment category based on market values are as follows:
Equity securities
Debt securities
Private equity
Although the SERF had no qualified assets as of March 31, 2006, PacifiCorp has a Rabbi trust that holds corporate-owned
life insurance and other investments to provide funding for the future cash requirements of the SERP. Because this plan is
nonqualified, the assets in the Rabbi trust are not considered plan assets. The cash surrender value of all of the policies
included in the Rabbi trust plus the fair market value of other Rabbi trust investments was $36.4 million at March 31, 2006
and $34.7 million at March 31 2005, net of amounts borrowed against the cash surrender value.
March 31
Target 2006 200S
55.58.56.
35.34.33.
10.10.
Other Postretirement Benefits
The cost of other postretirement benefits, including health care and tife insurance benefits for eligible retirees, is accrued over
the active service period of employees. The transition obligation represents the unrecognized prior service cost and is being
amortized over a period of20 years. PacifiCorp funds other postretirement benefits through a combination of funding
vehicles. PacifiCorp contributed $29.7 million for the year ended March 31, 2006; $24.9 million for the year ended March
2005; and $25.3 million for the year ended March 3 1 2004. TIle measurement date for plan assets and obligations is
December 31 of each year.
For the postretirement benefit plan assets,PacifiCorp employs an investment approach that uses a mix of equities and fixed.
income investments to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established
through careful consideration of plan liabilities, plan funded status and corporate financial condition. TIle investment
portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across
United Slates and non-United States stocks, as wetl as growth and value companies, and small and large market
capitalizations. Fixed-income investments are diversified across United States and non-United States bonds. Other assets,
such as private equity investments, are used to enhance long-term returns while improving portfolio diversification.
acifiCorp primarily minimizes the risk oflarge losses through diversification, but also monitors and manages other aspects
of risk through quarterly investment portfolio reviews, annual liability measurements and periodic asset/liability studies.
http://www.sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
,.....-.......----..---..---
Page 129 of 160
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
,.-...-......--....-..-..-,-"-...,.....---,.--.--..-..-....-..,.."'-,----......-.....-,
Page 130 of 160
TIle assets for other postretirement benefits are composed of three different trust accounts. The 401 (h) account is invested in
the same manner as the pension account Each of the two Voluntary Employees' Beneficiaries Association Trusts has its own
investment allocation strategies. Details of the Voluntary Employees' Beneficiaries Association Trusts ' assets by investment
category based on market values are as fol1ows:
Equity securities
Debt securities
Components oftbe net periodic postretirement benefit cost are summarized as follows:
Mareb 31,
Target 2006 2005
65.66.66.4%
35.34.33.
Net periodic postretirement benefit cost
Years Ended March 31,
2006 2005 2004
7.4
30.31.0 34.
(26.(26.4)(26.
12.12.12.
0.1
29.26.27.
(Mlillol1s of dollars)
Service cost
lnterest cost
Expected return on plan assets (a)
Amortization of unrecognized net transition obligation
Amortization of unrecognized loss
Amortization of prior service cost
(a) TIle market-related vallie of plan assets, among other factors, is used to detennine expected return on plan assets and is
calculated by spreading the difference between expected and actual investment returns over a five-year period beginning
in tbe first year in which they occur.
http://www .see.goy/ Arehives/edgar/datal75594/000007559406000028/p 1 Ok.htm 5/31/06
,,-""_
'_.n___
-.--- ...........,.,-,-,-....--...--.",...---,...---.--,---.,-...-..-----"""--"-'-
Page 131 of160
The change in the accumulated postretirement benefit obligatiQn, change in plan assets and funded status of the
postretirement plan is as follows:
Accmed postretirement cost
March 31,
2006 2005
528.555.
8.5
30.4 31.0
22.
(8.
34.(34.4)
(41.6)(40.1)
582.4 528.
286.261.
20.28.
22.5 29.
(4.1)
(41.6)(40.1)
292.286.
(290.3) $(241.7)
81.1 94.
22.1 1.4
138.100.
(49.(45.
29.24.
(19.3) $(20.
(Millions Gf doll:lrs)
ange in accumulg!~cip-ostretirement benefit obligation
Accumulated postretirement benefit obligation - beginning of year
Service cost
Interest cost
Plan participant contributions
Plan amendments
Separation of former participants
Actuarial loss (gain)
Benefits paid
Accumulated postretirement benefit obligation - end of year
Change in p'lan assets
Plan assets at fair value - beginning of year
Actual return on plan assets
Company contributions
Plan participant contributions
Separation of former participants
Net benefits paid
Plan assets at fair value - end of year
Reconciliation of accrued p'ostretircment costs and total amount recognized
Funded status of the plan
Unrecognized net transition obligation
Unrecognized prior service cost
Unrecognized loss
Accrued postretirement benefit cost, before final contribution
Contribution made after measurement date but before March J 1
The assumed health care cost trend rates arc as follows:
"'hlrch 31,
2006 2005 2004
10.8.5%
10.10.5
2011 2007 2007
2011 2009 2009
Initial health care cost trend - under 65
Initial health care cost trend - over 65
Ultimate health care cost trend rate
Year that rate reaches ultimate - under 65
Year that rate reaches ultimate - over 65
http://www.sec.gov/Archives/edgar/datal? 5594/0000075 59406000028/p 1 Ok.htm 5/31/06
Page 132 of 160
http://www.sec.gov/ Archives/edgar/data/75594/000007559406000028/p 10k.htm 5/3 1/06
- -----,-..,........"..-..-..-......-.-...-,.--..-..-..-,..-,-......,."..-,.....---,-..--
.....,.,...-......,..,...."........._.m___......-..---
..-'"....-.....-
Page 133 ofl60
The health care cost trend rate assumption has a significant effect on the amounts reported. An annual increase or decrease in
the assumed medical care cost trend rate of 1.0% would affect the accumulated postretirement benefit obligation and the
service and interest cost components as follows:
(Millions of dollars)One I'ercent
Increase Decrease
Accumulated postretirement benefit obligation
Service and interest cost components
$ 43.7 $ (35.5)8 (2.
Future Contrib~jjons and Bene(iJ..f;n.lI)ents
In April 2006, PacifiCorp contributed $72.7 million to its Retirement Plan. In addition, PacifiCorp expects to contribute
another $11.0 million to its pension plans, as well as $36.6 million to its postretirement benefit plan, during the 12 months
ending March 31, 2007. The benefit payments expected to be paid, which reflect expected future service and the Medicare
Part D subsidy expected to be received, are as follows:
(Millions of dollars)
11 months eodlo!; March 31,
Retirement
Plans
J\IedlureOcher I'art D
Postretirement SubsidyDenen.s ltecelplS
2007
2008
2009
2010
2011
2012 to 2016 (inclusive)
92.5 $
92.4
93.
94.
97.
541.
35.8 $ (3.
37.(3.4)
40.0 (3.
42.1 (4.
44.4 (4.
248.2 (29.
ployee Sav.ings Plan
PacifiCorp has an employee savings plan (the "Savings Plan ) that qualifies as a tax-deferred arrangement under the Internal
Revenue Code. Eligible employees of adopting affiliates are those who are not temporary, casual, leased or covered by it
collective bargaining agreement that does not provide for participation. Employees of any company within the PacifiCorp
controlled group of companies that has not adopted the Savings Plan are not eligible. Participating United States employees
may defer up to 50.0% of their compensation, subject to certain statutory limitations. Compensation includes base pay,
overtime and annual incentive, but is limited to the maximum allowable under the Internal Revenue Code. Employees can
select a variety of investment options. PacifiCorp matches 50.0% of employee contributions on amounts deferred up to 6.
of total compensation, with that portion vesting over the initial five years of an employee s qualifying service. 1l1ereafter
PacifiCorp s contributions vest immediately. PacifiCorp s matching contribution is allocated based on the employee
investment selections. PacifiCorp may also make an additional contribution equal to a percentage of the employee s eligible
eami11gs. lltis additional contribution is allocated based on the employee s investment selections or to the money market
fund if the employee has made no selections. These contributions are immediately vested. PacifiCorp s contributions to the
Sav,ings Plan were $22.5 million for the year ended March 31, 2006; $20.2 million for the year ended March 31, 2005; and
$19.3 mitIion for the year ended March 31,2004; and represent amounts expensed for such periods.
everance
As a result of general workforce reductions and ScouishPower s corporate restructuring during the year ended March 31,
2006, PacifiCorp incurred severance expense of $4.1 million under its severance and other benefit plans related to the
involuntary termination of approximately 62 employees. Services provided by these employees are expected to be complete
by March 31 , 2007,
As a result of the MEHC acquisition, PacifiCorp has experienced organizational changes and additional workforce reductions
resulting in severance expense of $12.9 million during the year ended March 31, 2006 under its severance and other benefit
plans, primarily related to the involuntary tennination of 29 employees. Additional severance expense is expected to be
incurred in the future as additional organizational changes occur.
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 10k.htm 5/31/06
....--,..-......---....---..-..-.--.--..--...-......-
Page 134 of 160
http://www.see.gov/ Arehives/edgar/data/75594/000007 559406000028/p lOk.htm 5/31/06
".....-....--..---..-, ..--........",-,-,-....-..........,---..---,,-..-
Page 135 of 160
Note 18 - Stock-Based Compensation
?m;i LCorp Stock IlIce"l;ve Pia" ("PSIP"- During 1997, PacifiCorp adopted the PSIP. The exercise price of options
granted under the PSIP was equal to the market value of the common stock on the date of the gmnt. ScottishPower took
control of the plan upon completion of its merger and all stock options were converted into options to purchase
ScottishPower American Depository Shares. The PSIP expired on November 29,2001 and all outstanding options under the
plan were fully vested as ofMarcb 31 , 2005.
As a result of the sale of PacifiCorp to MEHC and in accordance with the PSIP provisions regarding a change in control, all
outstanding options mllst be exercised no later than 12 months after the date of tile sale ofPacifiCorp; otherwise they will be
forfeited.
J11Ji.'.flPmver E.-ceClllhle Share Opt;OIl Pia" ("ExSOP"In prior years, a select group ofPacifiCorp employees received
grants of stock -options under the ScottishPower ExSOP. Certain grants awarded in May 2001 were performance-based
awards which resulted in $2.0 million of compensation expense included in Operations and maintenance expense for the year
ended March 31,2005.
As a result of the sale of PacifiCorp to MERC on March 2 I , 2006, aU ExSOP options held by PacifiCorp employees became
fully vested in accordance with the change-in-control provisions of the ExSOP. The change-in-control provisions also
provide that all outstanding options are exercisable up to the later of 12 months after the date ofthe sale ofPacifiCotp or 42
months after the date of original option grant. Options that are not exercised within this time period will be forfeited. As of
the date of the sale, PacifiCorp ceased to participate in the plan but as of March 31, 2006, there are still options outstanding
and exercisable by PacifiCorp employees.
TIle table below summarizes the stock option activity under the PSII' and the ExSOP.
PSII'EsSOI'
Weighted WeIghted
Number of Average Number of Anrage
SeollhllPower Amerlean Deposllory ShareJ Shares PrIce Stlllr"Price
Outstanding options at March 31 , 2003 403,251 $ 31.67 935 054 $ 23.
Granted 780 901 24.40
Exercised (147 496)25.55 (25,508)23.
Forfeiled (331 706)34.(41 991)23.
Outstanding options at March 31, 2004 924 049 31.64 648,456 23.
Granted 763,843 28.
Exercised (750,126)26.1 0 (483 667)23.
Forfeited (40,310)35.(30 136)26.
Outstanding options at March 31 , 2005 133,613 33.898 496 25.
Exercised (1,325,284)3132 404,637)25.58
Forfeited (30 578)35.(16 096)27.
Transfers due to separation (68,710)37.(164 677)25.
Outstanding options at March 3 1,2006 709 041 37.313,086 27.
http://www .see.gov/ Archives/edgar/datal75594/000007559406000028/p 1 Ok.htm 5/31/06
Page 136 of 160
Information with respect to options outstanding and options exercisable under the PSIP and the ExSOP as of March 31,2006
and 2005 were as follows:
Options Outstanding Opllons Exercisable
Itange Dr E~erclse Prices
Number
orSburn
Wel~hted
A\'era~e
E~erclse
rlee
Wel~htetl
Anrage
Remaining
LIre (In years)
Number
or Shares
Welglllet!
Average
Exercise
rlce
Year ended March 31 2006
PSIP
$25.70 - $36.
$39.99 - $41.38
Total
268 205 31.1.0 268,205 31.25
440 836 40.1.0 440 836 40.
709,041 37.1.0 709,041 37.
313,086 27.15 1.4 313,086 27.
589 323 31.589,323 31.
544 290 40.544 290 40.
133 613 33.133,613 33.
898,496 25.182 134 23.
Tolal
ExSOP
$23.55 - $28.
Year ended March 31, 2005
PSIP
$25.70 - $36.
$39.994 $43.
ExSOP
$23.55 - $28.
ScottisilPower Long-Term lucel/live PIal'- In prior years, a select group ofPacitiCorp employees received grants of
performance share awards under ScottishPower s Long-Term Incentive Plan. The number of shares that actually vest is
dependent upon the outcome of certain performance measures over a three-year period. The plan s change-in-control
provisions resulted in removal of the employees' future service requirement as of the date of the acquisition but retained the
three-year performance requirements. As a result, the number of shares that ultimately vest at the end of the performance
period, if any, will be prorated to reflect only tbe portion of the three-year period which had elapsed between tile date of
original grant and tile date of the sale ofPacifiCorp to MEHC. During the year ended March 31 2006, no stock-based
compensation expense was recorded because the performance measures were not yet reached.
Deferred Share Pr1!Cralll - In May 2004, ScottishPower implemented a deferred share program under wllich certain
PacifiCorp employees were granted an annual stock bonus award based on a .fixed dollar amount but distributable in
ScottishPower American Depository Shares with the number of shares to be determined by the quoted market price of the
shares at the date of issuance. Historically, compensation expense was accrued throughout the year in which the employee
services were rendered and awards earned. During the year ended March 31, 2005, $3.1 million of compensation costs were
accrued. However, as a result of the sale ofPacifiCorp to MEHC, the progmm was modified during the year ended March 31
2006 to provide for a cash payment mther than a share-based payment. The plan was discontinued as of April I, 2006.
http://www.see.gov/Archives/edgar/datal7 5594/0000075 59406000028/p 1 Ok.htm 5/31/06
_..---,........-,-_.....
Page 137 of160
Note 19 - Income Taxes
The difference between the United States federal statutory tax rate and the effective income tax rate attributed to income from
continuing operations is as follows:
Years Ended Mareh 31,
2006 2005 2004
35.35.35.
4.1
1.1 (0.(3.1)
(2.(2.3)(2.5)
(3.3)0.4 (0.
35.40.1%36.
Federal statutory rate
State taxes, net of federal benefit
Effect of regulatory treatment of depreciation differences
Tax reserves
Tax credits
Other
Effective income tax rate
ll1e provision for income taxes is summarized as follows:
Years Ended March 31,
(Millions of duIl3r5)2006 2005 2004
Current
Fcderal 167.3 58.63.
Stale 18.(10.1.0
Total 185.5 48.5 64.
Deferred
Federal 19.112.77.
State 2.1 15.10.
Total 21.8 127.88.4
Investment tax credits (7.(7.(7.
Total income tax expense 199.4 168.144.5
The tax effect of temporary differences giving rise to significant portions ofPacifiCorp s deferred tax liabilities and deferred
tax assets were as follows:
(Mllllolls of dollars)March 31,
2006 2005
Deferred tax liabilities:
Property, plant and equipment
Regulatory assets
Derivative contract regulatory assets
Other deferred tax liabilities
$ 1 531.2 $ 1,512.
623.0 667.
35.9 64.
114.126.3
http://www.sec.gov/ Archives/edgar/data/75594/000007 559406000028/p 1 Ok.l1tm 5/31/06
.. .... .--..-----.......,.....-..-..-----
Page 138 of160
Net deferred tax liability
304.4 371.0
(316.(325.
(170.(185.
(44.(102.
(134.(126.
(666.(740.
638.631.
Deferred tax assets:
Regulatory liabilities
Employee benefits
Derivative contracts
Other deferred tax assets
PacifiCorp made net ,income tax payments of $140.0 million for the year ended March 31, 2006; $92.0 million for the year
ended March 31 , 2005; and $114.1 miltion for the year ended March 31,2004. The income tax payments include payments
for current federal and state income taxes, as welt as amounts paid in settlement of prior years' liabilities as a result of
income tax proceedings.
http://www see.govl Archives/edgar/data/75594/000007559406000028/p 10k.htm 5/31106
".-.'."..-..".".-"---"-""-.-"---------..-.........,...--...-.,--....,-.-""-""""-'..--
Page 139 of 160
PacifiCorp has established, and periodically reviews, an estimated contingent tax reserve on its Consolidated Balance Sheets
to provide for the possibility of adverse outcomes in tax proceedings. The net federal and state contingency reserve increased
$6.1 million during the year ended March 31 , 2006 primarily due to new issues identified for tax years ended after March 31,
2000. 111e Internal Revenue Service started its examination of the 2001. 2002 and 2003 tax years in October 2004. PacifiCorp
anticipates that final settlement and payment on settled issues and other unresolved issues will not have a material adverse
impact on its consolidated financial position or results of operations.
The sale of PacifiCorp to MEHCon March 21, 2006 triggered tIle recognition of a deferred intercompany gain or loss for tax
purposes. The recognition oftbe tax effects of this item is considered to have been recognized immediately prior to the
closing of the sale of PacifiCorp white it was part of the PHI consolidated group. PacifiCo,rp is currently unable to estimate
the amount of the tax effect, if any, or determine a range of the potential tax effect. Due to the uncertainty of the amount of
the deferred intercompany gain or loss, no adjustments have been recorded as of March 31, 2006.
Pursuant to a formal agreement with PHI and ScottishPower, any tax liabilities generated as a result of a deferred
intercompany gain would be recorded as an equity contribution to PacifiCorp. Additionally, as tIlis transaction is deemed to
be with shareholders, the net tax expense would be recorded as a reduction in Conunon shareholder s capital similar to a
return of capital distribution. As a result, there would be no net impact to PacifiCorp s Common shareholder s capital
statement of fmancial position or results of operations.
If a deferred intercompany loss is detemlined to exist, PacifiCorp would be required to recognize the tax benefit of the
deferred intercompany loss as an increase in Common shareholder s capital and establish a corresponding tax receivable or
deferred tax asset, depending on whether PacifiCorp would be able to currently utilize tbe capital loss. In the event a deferred
tax asset is created with respect to the capital loss, it will be necessary to determine whether a valuation allowance should be
established against the deferred tax asset.
At March 31,2006, PacifiCorp had no federal or state net operating loss carry forwards. At March 3 I, 2005 PacifiCorp had
total available federal net operating loss carryforwards of approximately $2.7 million and no state net operating loss
carryforwards. PacifiCorp has Oregan business energy tax credits of approximately $0.6 million at March 31, 2006 available
to reduce future income tax liabilities. These credits begin to expire in 2012. PacifiCorp has Idaho investment tax credits of
approximately $1.9 million at March 31 , 2006 that are available to reduce future income tax. liabilities. These credits begin to
expire in 2017. PacifiCorp anticipates utilizing the tax credits prior to the expiration dates.
Note 20 - Concentration of Customers
During the year ended March 31 2006, no single retail customer accounted for more than 2.0% of PacifiCorp s retail electric
revenues, and the 20 largest retail customers accounted for 13.0% of total retail electric revenues. The geographical
distribution ofPacifiCorp s retail operating revenues for the year ended March 31, 2006 was: Utah, 40.9%; Oregon, 29.3%;
Wyoming, 13.3%; Washington, 8.4%; Idaho, 5.7%; and California, 2.4%.
Note 21 - Subsequent Events
On May 10 2006, the PacifiCorp Board of Directors determined to change PacifiCorp s fiscal year-end from March 31 to
December 31. PacifiCorp s report covering the transition period beginning April 1, 2006 and ending December 31 2006 will
be filed on Fom1 lO-
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
-..-....-..---,..-.-.--"--___..
.._n.-...__n.._--._
Page 140 of 160
SUPPLEMENTAL lNFORl\1A nON
QUARTERL Y FINANCIAL DATA (UNAUDITED)
2005
Revenues
Income from operations
Net income
Earnings on common stock
Common dividends declared per share
Common dividends paid per share
Quarters Ended
June 3D September 30 December 31 March 31
$ 881.4 620.165.$1,229.
135.129.256.270.
46.4 39.4 127.147.
45.38.127.146.
16.16.16.3st
16.16.16.3i
$ 747.828.849.$ 622.
129.165.155.206.
50.61.9 51.3 87.
50.4 61.4 50.87.1
15.5st 15.5st 15.15.
t5.5st t5.lS.15.
(MIllions or dollars, execpl per share amounl5)
tOO6
Revenues
Income from operations
Net income
Earnings on common stock
Common dividends declared per share
Common dividends paid per share
On March 31 , 2006, MEHC was the only common shareholder of record.
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNT ANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No information is required to be reported pursuant to this item.
ITEM 9A. CONTROLS AND PROCEDURES
PacifiCorp maintains disclosure controls and procedures designed to provide reasonable assurance that material information
required to be disclosed by it in the reports it files or submits under the Securities Exchange Act of 1934 is recorded
processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that the information
is accumulated and communicated to PacifiCorp s management, including its Chief Executive Officer and Chief Financial
Officer, as appropriate to allow timely decisions regarding required disclosure. PacifiCorp performed an evaluation, under the
supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer,
of the effectiveness of the design and operation ofPacifiCorp s disclosure controls and procedures as of the end of the period
covered by this report. Based on this evaluation, PacifiCorp s management, including its Chief Executive Officer and Chief
Financial Officer, concluded that the disclosure controls and procedures were effective as of the end of the period covered by
this report.
On March 21, 2006,MEHC completed its purchase ofPadfiCorp, at which time PacifiCorp became a subsidiary ofMEHc.
Although PacifiCorp has maintained its disclosure controls and procedures that were in effect prior to the acquisition,
subsequent to the acquisition there have been material changes in PaciliCorp s internal control over financial reporting. The
material changes are due to the effect of the acquisition on PacifiCorp s control environment, which includes changes in the
composition of the board of directors, PacifiCorp s organizational structure, audit conunittee oversight and its corporate
governance framework. PacifiCorp believes these changes have not negatively affected its internal control over financial
reporting.
http://www.sec.gov/ Archives/edgar/data/75594/000007559406000028/p 10k.htm 5/31/06
_._._.......-.._-_....._--_.._,-,.........---,.."-"-.-"".---""'-".-,...-..-...---,.."..."'---"."""--"."-
Page 141 of 160
During the three months ended March 31 2006, there was no other change in PacifiCorp s intemal control over financial
reporting identified in connection wit11 the evaluation required by paragraph (d) of Securities Exchange Act of 1934 Rules
13a-15 or lSd-IS that occurred that has materially affected, or is reasonably likely to materially affect, PacifiCorp s internal
control over fmancial reporting.
ITEM 98. OTHER INFORMATION
No information is required to be reported pursuant to this item.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of directors and executive officers of PacifiCorp. ll1ere are no family relationships among the
executive officers ofPacifiCorp. Officers ofPacifiCorp are normally elected annually.
ri!!mu.I1!!..A1t~usln~n Ex ~u Five Ye
Gregory E. Abel (43)Chief Executive Officer and Chairman. Director since March 2006.
Mr. Abel was elected Chief Executive Officer and Chairman ofPacifiCorp s Board of Directors
in March 2006. Mr. Abel is also the President and Chief Operating Officer and a director of
MEHC. Mr. Abel joined MEHC in 1992.
Douglas L. Anderson (48) Director since March 2006.
Mr. Anderson is the Senior Vice President, General Counsel and Corporate Secretary ofMEHC.
Mr. Anderson joined MEHC in February 1993 and has served in various legnl positions,
including General Counsel ofMEHC's independent power affiliates. Prior to that, Mr. Anderson
was a corporate attorney in private practice.
William J. Fehrman (45) President, PacifiCorp Energy. Director since March 2006.
Mr. Fehrman was elected President, PacifiCorp Energy in March 2006 and has responsibility for
PacifiCorp s electric generation, commercial and energy trading and coal-mining operations. He
joined MEHC in March 2006 to oversee integration activities ofMEHC's acquisition of
PacifiCorp. Prior to joining MEHC, Mr. Fehrman was President and Chief Executive Officer of
Nebraska Public Power District in Columbus, Nebraska. He joined Nebraska Public Power in
1981, serving as its President and Chief Executive Officer since January 2003 and before that as
Vice President of Energy Supply.
Brent E. Gale (54)Director since March 2006.
Mr. Gale was appointed Senior Vice President of Regulation and Legislation ofMEHC in
March 2006. Previously he had been Senior Vice President of MidAmerican Energy Company, a
MEHC subsidiary, since July 2004. Mr. Gale has served in various legal, regulatory and
strategic positions with MidAmerican Energy Company and its predecessors for more than five
years prior to that.
Patrick J. Goodman (39) Director since March 2006.
http://www.sec.gov/Archives/edgar/datal75594/000007 5 59406000028/p 10k.htm 5/31/06
Andrew ,P. Haller (54)
Nolan E. ,Karras (61)
A. Robert Laslch (46)
Mark C. Moench (50)
Richard D. Peach (42)
- ..-..--.-...-----.,_____
n.._-.-
-- .....,-..-,-,..,---.,.-.--,,--.........".......__.........-._~
Page 142 of 160
Mr. Goodman is Senior Vice President and Chief Financial Officer of MEHC. Mr. Goodman
joined MEHC in 1995 and has served in various financial positions, including Chief Accounting
Officer.
Senior Vice President, General Counsel and Corporate Secretary. Director since May 2003.
Mr. Haller joined PacifiCorp as its Senior Vice President, General Counsel and Corporate
Secretary in December 2000 and was also named General Counsel for Pacific Power in March
2006. Prior to joining PacifiCorp, he was chief executive for the United States operations of
Kvaerner Process, a position he assumed in 1999. Mr. Haller began his career with Kvaemer in
1987, and held various senior counsel and management positions, including Senior Vice President
and General Counsel-Americas. From 1998 to 1999, he served as the Associate General Counsel
for the parent company, Kvaemer ASA, in its United States corporate headquarters.
Director since February 1993.
Mr. Karras is President of TIle Karras Company, Inc., an investment adviser, and has se,rved in
that capacity since 1983. He is Chief Executive Officer of West em Hay Company, Inc., a non-
executive director of Scottish Power pIc and Beneficial Life Insurance Company and is a
Registered Principal for Raymond James Financial Services.
Vice President and General Counsel, PacifiCorp Energy. Director since March 2006.
Mr. Lasichjoined PacifiCorp and was elected to his current positions in March 2006. Previously
he served as Vice President ofMEHC with responsibility for integration and transition matters
related to the acquisition ofPacifiCorp since July 2005. Prior to that, Mr. wich was Vice
President of Gas Supply and Trading for MidAmerican Energy Company since August 2004. He
joined MidAmerican Energy Company in October 1997 and has also served as a senior attorney
in its legal department.
Senior Vice President and General Counsel, Rocky Mountain Power. Director since March 2006.
Mr. Moench joined PacifiCorp and was elected to his current positions in March 2006. Previously
he served as Senior Vice President, Law, ofMEHC with responsibility for regulatory approvals
of the PacifiCorp acquisition since June 2005. Prior to that, Mr. Moench was Vice President and
General Counsel of Kern River Gas Transmission Company since 2002, when Kern River was
acquired by MEHC from the Williams Companies, Inc., which he joined in 1987. Mr. Moench
served the Williams Companies in various senior legal positions, including as General Counsel of
Kern River.
Senior Vice President and Chief Financial Officer. Director since May 2003.
Mr. Peach was e1ected PacifiCorp s Chief Financial Officer effective January 2003 and elected
Senior Vice President in March 2006. Mr. Peach had served previously as Senior Vice President
of Fil1ance since March 2002. Prior to his appointment as Chief Financial Officer, he also served
as Group Controller for Scottish Power pic from March 2000 to December 2002, Head of
Customer Services, Energy Supply for ScottishPower from April 1999 to March 2000 and in
various other management positions with ScottishPower since 1995.
http://www .see.goy/ Arehiyes/edgar/data/75594/000007559406000028/p 10k.htm 5/31/06
Page 143 of 160
A. Richard Walje (54)President, Rocky Mountain Power. Director since July 2001.
Mr. Walje was elected President, Rocky Mountain Power in March 2006 and has responsibility
for the electric distribution opemtions ofPacifiCorp in Utah, Idaho and Wyoming. Mr. Walje
previously served as PacifiCorp s Executive Vice President since April 2004 and as Chief
Information Officer since May 2000. Previously he served as PacifiCorp s Senior Vice President
of Corporate Business Services from May 2001 to April 2004 and as PacifiCorp s Vice President
for Tmnsmission and Distribution Opemtions and Customer Service from 1998 to 2000.
Mr. Walje has been with PacifiCorp since 1986.
St:mley K. Watters (47) President, Pacific Power. Director since March 2006.
Mr. Watters was elected President, Pacific Power in March 2006 and has responsibility for the
electric distribution operations ofPacifiCorp in Oregon, Washington and California. Mr. Watters
was elected Senior Vice President of Commercial and Trading in June 2003. Mr. Watters served
as Vice President of Trading and Origination from July 2001 to June 2003 and as Managing
Director of Wholesale Energy Services since 1998. Mr. Watters has been with PacifiCorp since
1982.
Bruce N. WIlIlams(47)Treasurer.
Mr. Williams has served as PacifiCorp s Treasurer since February 2000. Prior to being elected
Treasurer, be served as Assistant Treasurer of PacifiCorp and has been with PacifiCorp since
1985.
In addition to following MEHC's Code of Business Conduct and Berkshire Hathaway s Code of Business Conduct and
Ethics Policy, which provide a basis for employee ethical standards and conduct for all employees, the PacifiCorp Board of
Directors previously approved and implemented a "Code of Ethics for Principal Officers" designed to promote the integrity
ofPacifiCorp s financial reporting and legal compliance. The Code of Ethics for Principal Officers applies to PacifiCorp
Chief Executive Officer and its financial and accounting officers. The Guide to Business Conduct and Code of Ethics for
Principal Officers are available in the "About Us - Company Overview" section ofPacifiCorp s website at
www.pacificorp.com. PacifiCorp intends to make available on its website any amendment to, or waiver from, tbe Code of
Ethics for Principal Officers as the Code applies to PacifiCorp s Chief Executive Officer and its financial and accounting
officers.
Through its affiliation with Berkshire Hathaway, PacifiCorp participates in The Network, an independent company dlat
employees and vendors can call to report business conduct issues confidentially and anonymously involving fraud, financial
reporting irregularities, misrepresentation of financial reports, non-compliance with internal controls, or suspected illegal or
unethical activity.
Because PacifiCorp s common stock is indirectly, wholly owned by MEHC, its Board of Directors consists primarily of
internal executives and it is not required -to have an audit committee. However, the audit committee ofMEHC acts as the
audit committee for PacifiCorp.
ITEM 11. EXECUTIVE COMPENSATION
PACIFICORP BOARD OF DIRECTORS REPORT ON EXECUTIVE COMPENSATION
Introduction
111e PacifiCorp Board of Directors submits this report on executive compensation, which outlines the compensation provided
to PacifiCorp s executive officers. For most of the year ended March 31 2006, PacifiCorp was owned by ScottishPower, and
this report generally reflects the executive compensation philosophy, practices and programs
http://www.see.goy/ Archiyes/edgar/datal75594/000007 559406000028/p 1 Ok. htm 5/31/06
Page 144 of 160
maintained under ScottishPower ownership. PacifiCorp s acquisition by MEHC on March 21 , 2006 generally did not result in
material changes to PacifiCorp executive compensation practices, but any such changes are described in this Item 11.
Compensation Committee Interlocks and Insider Participation
Under ScottishPower ownership, the Remuneration Committee of the ScottishPower Board of Directors, assisted by its
outside advisors, had Ihe responsibility to approve compensation levels and executive compensation plans for the PacifiCorp
Chief Executive Officer, as well as any ScottisltPower executive officers serving as PacifiCorp executive officers in a dual
capacity, and to review compensation for other executive officers and senior management of PacifiCorp. During the year
ended March 31, 2006, the Remuneration Committee was composed entirely of independent, non-executive directors. With
the exception of any compensation requiring review by the Remuneration Committee, the Compensation Committee of the
PacifiCorp Board of Directors, which under ScottishPower ownership consisted of the PacifiCorp Chief Executive Officer
and, at various times during the year ended March 31, 2006, the ScottisltPowerChiefExecutive Officer, the ScottishPower
Human Resources Director and PacifiCorp s General Counsel, had responsibility for approving compensation levels and
executive compensation plans for executive officers ofPacifiCorp. The Remuneration Committee also approved any stock-
based compensation to PacifiCorp executive officers, all of which was in the form ofScottishPower equity.
Effective upon MEHC's acquisition ofPacifiCorp, PacifiCorp s Board of Directors eliminated its Compensation Committee
and delegated its duties to the Chairman of the Board of Directors, Gregory E. Abel. Mr. Abel also serves as PacifiCorp
Chief Executive Officer and as MEHC's President and Chief Operating Officer. He is employed by MEHC and receives no
compensation from PacifiCorp or specific compensation from MEHC for his PacifiCorp service; accordingly, references to
executive officers in this Hem 11 exclude Mr. Abel unless otherwise indicated. The following describes the components of
PaciliCorp s executive compensation program and the basis upon which recommendations and determinations were made for
the year ended March 31, 2006.
Compensation Philosophy
PacifiCorp s philosophy is that executive compensation should be linked closely to corporate and operational performance
customer service and increases in shareholder value. PacifiCorp s executive compensation program has the following
objectives:
(i) provide competitive total compensation that enables PacifiCorp to attract and retain key executives;
(ii) provide variable compensation opportunities that are linked to PacifiCorp, operational area, and individual
performance; and
(Hi) establish an appropriate balance between incentives focused on short-term objectives and those encouraging sustained
performance improvements.
Qualifying compensation for deductibility under Internal Revenue Code Section 162(m) is one of the factors that PacifiCorp
considers in designing PacifiCorp s incentive compensation arrangements for executive officers. Internal Revenue Code
Section 162(m) limits to $1.0 million the annual deduction by a publicly held corporation of compensation paid to any
executive officer, except with respect to certain forms of incentive compensation that qualify for exclusion. Although it is the
intent to design and administer compensation programs that maximize deductibility, PacifiCorp views the objectives outlined
above as more important titan compliance with the teclmical requirements necessary to exclude compensation from the
deductibility limit ofintemal Revenue Code Section 162(m). Nevertheless, witlt the exception of severance payments made
to PacifiCorp s former President and Chief Executive Officer, Judith A. Johansen, PacifiCorp believes that nearly all
compensation paid to the executive officers for services rendered in the year ended March 31 , 2006, is fully deductible.
Compensation Program Components
During the year ended March 31 , 2006, the compensation programs were focused on market-based comparisons on the
relevant industry for each executive officer. The electric utility industry was utilized as the exclusive basis for market
comparison for positions with a principal focus on electric operations. For positions with a corporate-wide focus, the general
industry and electric utility industry were used for market comparison. In all cases, compensation
http://www .see.goy/ Archiyes/edgar/data/75594/000007559406000028/p 10k.htm 5/31/06
....,...-.-.-....---"'-""'-----""."-'.-"""-"'."'-.-"----..-.."....,---..,..-.--............,.--.--
Page 145 of160
is targeted at market median levels, with an assumption that total compensation greater than market median, in any specific
time period, anticipates that PacifiCorp and industry perfonnance exceeds the median performance of peer companies.
PacifiCorp s executive compensation programs have three principal elements: base salaries, annual incentive compensation
and long-term incentive compensation. as described below.
Base Salaries
Base salaries and target incentive amounts are reviewed for adjustment at least annually based upon competitive pay levels
individual performance and potential, and changes in duties and responsibilities. Base salary and the target incentive are set at
a level such that total annual compensation for satisfactory performance would approximate the median of pay levels in the
comparison group used to develop competitive data. In the year ended March 31, 2006, the base salary of each executive
officer was increased, based on market analysis, to reflect competitive market changes, individual performance and changes
in the responsibilities of some officers.
Annual Incentive Compensation
All PncifiCorp executive officers, including those listed in the Summary Compensation Table other than Mr. Abel
participate in PacifiCorp s Annual Incentive Plan (the "AlP"). In May 2006, PacifiCorp determined that named executive
officers are eligible under certain conditions for payments under the AlP in June 2006 as follows: Judith A. Johansen,
$393,751; AndrewP. HaUer, $185 980; A. Richard Walje, $158,789; RichardD. Peach, $184 356; StanleyK. Watters,
$131 016; and Matthew Wright, $142,916.
Long-Term Incentive Compensation
In May 2005, the ScottishPower Remuneration Committee approved grants ofperfonnance share awards under
ScottishPower s Long-Term Incentive Plan (the "L TIP") for II select group of PacifiCorp executive officers and other senior
managers. LTIP awards were also made in April 2004 to certain executive officers and senior managers. The L TIP provides
for awards of performance shares that link the rewards closely between management and shareholders and focus on long-
term corporate performance. The awards will vest only if the Remuneration Committee is satisfied that certain threshold
customer service and financial perfornlance measures are achieved. The number of shares that actually vest depends upon
ScottishPower s comparative Total Shareholder Return performance over a three-year performance period. Vested shares are
released to participants only after the conclusion of the performance period. In addition to the criteria described above, the
vesting of L TIP awards held by PacifiCorp executive officers and senior managers will be prorated to reflect only the portion
of the tlU'ee-year perfonnance period in which PacifiCorp was owned by ScottishPower.
In April 2004, the ScottishPower Remuneration Committee also approved grants of stock options under the ExSOP for
certain executive officers and other senior managers, which were awarded in May 2004. These grants were the last stock
options awarded under the ExSOP. Upon the closing ofPacifiCorp s sale to MEHC, all outstanding ExSOP options vested in
full. A number of restricted stock and stock option awards originally made under the PSlP, which was assumed by
ScottishPower in connection with its acquisition ofPacifiCorp in 1999 and expired in 2001, remain outstanding but are fully
vested. Except for the ExSOP grants awarded in May 2004, ExSOP and PSIP awards relate to ScottishPower American
Depository Shares or Ordinary Shares and will remain outstanding untit March 21, 2007. The ExSOP awards granted in May
2004, will remain outstanding until November 2007.
In May 2004, the ScottishPower Remuneration Committee approved a new program to replace the ExSOP, called the
Deferred Share Program, which was part of the AlP for executive officers and senior management. Eligible employees
received an increase to their AlP maximum target incentive payment, with the increase paid in ScottishPower American
Depository Shares, for the year ended March 31 , 2005. For the year ended March 31, 2006, the Deferred Share Program was
modified and potential payments for eligible employees under the program were added to cash payments under the AlP. TIlis
program was discontinued as of Aprill, 2006.
William Fehrman, President ofPacificorp Energy, currently participates in MEHC's Long~Term Incentive Partnership Plan.
TIle participation of the other named executive officers (excluding Mr. Abel, who is not a participant) in the plan will be
evaluated for PacifiCorp s fiscal year ending December 31,2007. A copy of the plan is attached as Exhibit 10.71 to the
MEHC Annual Report on Form IO-K for the year ended December 31, 2004.
http://www.sec.gov/ Archives/edgar/data/75594/0000075 59406000028/p 1 Ok.htm 5/31/06
..,-....-----..-..-,-,-..--'----"'---'.'-----'---'--'"'-----".""_."".. -."----"---""'-.-'
Page 146 of 160
Compensation of Directors
Directors are not paid any fees for serving as directors. AU directors are reimbursed for their expenses incurred in attending
Board meetings.
Executive Compensation
The following table sets forth information concerning compensation for services in aU capacities to PacifiCorp for the years
ended March 31 , 2006, 2005 and 2004 of the Chief Executive Officer of PacifiCorp, the next four other most highly
compensated executive officers ofPacifiCorp who were serving as executive officers at the end of the last completed fiscal
year and two former PacifiCorpexecutive officers, either of whom would have been among the four other most highly
compensated executive officers if they had been serving in such capacity as of March 31 , 2006.
Summary Compensation Table
LolIg-Term Compensation
Annulil CompenSQllon (b)
Name lind Principal Position Year Salary (e)Bonus (d)
All Other
Compensallon
(e)
Reslrlcled
Slack
,\wards
Securities
Ullderl)'IIIG
aptlnn!
LTJP
"ayoul
ScoUlshPnlnr
erforlllance
Shlire! (II)
Gregory E. Abel (a)
Chainnan and
ChiefExeculive Officer
Michael J, PiLlman (j)
Fonncr Senior
Vice I'residenl
2006 $808,042 S 393,751 $115,523
2005 743.750 437,500 23,311
2004 589,394 337 500 22.883
2006 361.349 185,980 108,955
2005 334,480 167,137 515
2004 327,996 190,109 20,165
2006 343.004 158,789 104,409
2005 317 307 158,108 270
2004 299.544 127 557 83,173
2006 380,45&209.088 248,494
2005 210,654 153,987 100,368
2004 200.291 136.150 1\5,899
2006 277,671 131 ()l6 88,326
2005 256,875 123.550 20,100
2004 243,(,93 130.728 22,544
2006 3\6.545 142.9\6 028,82 I
2005 21)2,48\141,945 151,425
2004 253,(,12 127.527 62,766
2006 190,909 2611,125 839,328
2005 323.750 189.000 329
2004 313,125 187 500 097
- S
52,228
6\,475
15.839
19.916
12,458
Judilh A. Johansen (h)
Fonner President and
ChiefEKcculivc Officer
Andrew P. Holler
Senior Vice Pn:sident.
General Counsel and
Corporate Secretary
11,6&7
13,530
774
74(1
5,484
Mauhew Wrighl (i)
Fonner EKcclitive
Vice PresidclIl
16,613
751
11,406
10.977
58,102
965
865
15,331
502
33,948
38,729
374
757
195
A. Richard Walje
resident, Rocky
Mountain Power
Richard D. !'ench
Senior Vice I'resident and
Chief Financial Officer
704
844
6.586
Siantey K. Walters
residenl,l'acific Power
900
3.593
959
236
301
490
904
849
http://www .see.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
..........-.....-.....--,......."..,-....--------_",--""",."."""."""""""""-".--"".,-..".".-.,,-,,,,-,,-"-"'---"---..--"""-'-.'-."-
Page 147 of 160
(a) Mr. Abel receives no compensation from PacifiCorp or specific compensation from MEHC for his PacifiCorp service.
Please refer to MEHC's Annual Report on Form lO-K for the year ended December 31 2005 (File No. 001-14881) for
executive compensation information for Mr. Abel.
(b) May include amounts deferred pursuant to the Compensation Reduction Plan, under which key executives and directors
may defer receipt of cash compensation until retirement or a preset future date. Amounts deferred are invested in
ScottishPower American Depository Shares or a cash account on which interest is paid at a rate equal to the Moody
Intermediate Corporate Bond Yield for AA-rated Public Utility Bonds.
(c) Salary includes foreign housing benefits paid to Mr. Peach and Mr. Wright. The amounts for Mr. Peach were $8,638 for
the year ended March 31, 2006, $64,944 for the year ended March 3 I, 2005 and $68,513 for the year ended March 31
2004. The amount for Mr. Wright was $39,380 for the year ended March 31,2004.
(d) Bonus includes the value of Scottish Power American Depository Shares awarded under the AlP Deferred Share Program
for the fiscal year ended March 31 2005.
(e) Amounts shown for the year ended March 31, 2006, include:
(i) Company contributions to the PacifiCorp Employee Savings and Stock Ownership Plan (the "Savings Plan ) of
$12 850 for Ms. Johansen, $11 366 for Mr. Haller, $11 259 for Mr. Walje, $7 531 for Mr. Peach, $11,165 for
Mr. Watters, $1 1 258 for Mr. Wright, and $7 240 for Mr. Pittman.
(ii) Portions of premiums on term life insurance policies that PacifiCorp paid in the amounts of $2,344 for
Ms. Johansen, $1 088 for Mr. Haller, $1,072 for Mr. Walje, $1 179 for Mr. Peach, $836 for Mr. Watters, $953 for
Mr. Wright, and $513 for Mr. Pitbnan.These benefits are available to all employees.
(iii) Annual vehicle allowances of$9 263 paid to Ms. Johansen, $9,375 paid to each of Messrs. I-Jailer, Walje, Watters
and Wright, $4,800 paid to Mr. Peach and $4,875 paid to Mr. Pittman.
(iv) Retention payments in the amounts of$87 126 to Mr. Hatler, $82,703 to Mr. Walje, $62,500 to Mr. Peach, $66 950
to Mr. Watters and $76,323 to Mr. Wright.
(v) Additional international assignment payments of$42 195 to Mr. Peach and $37 868 to Mr. Wright for the year
ended March 31, 2006. Also includes international assignee localization payments of $130 289 to Mr. Peach and
$12,611 to Mr. Wright for the year ended March 31 , 2006.
(vi) Severance benefits, including enhancements related to PacifiCorp s change in control, paid during the year ended,
or payable or accrued as of, March 31, 2006, in the amounts of $4,091 ,066 to Ms. Johansen, $1 880,433 to
Mr. Wright and $1 826,700 to Mr. Pittman. Ms- Johansen s and Mr. Wright's amounts include the value of excise
tax gross-up payments to be made by PacifiCorp to the Internal Revenue Service on their behalf. ScottishPowcr
reimbursed PacifiCorp for $1,389,937 of Mr. Pitbnan s benefits.
(0 Represents the dollar value of awards under the ScottishPower L TIP that vested and were distributed to the named officer
in the form of ScottishPower American Depository Shares.
(g) Represents the number of ScottishPower American Depository Shares contingently granted in 2006, 2005 and 2004 that
can be earned under the terms of the LTIP.
(11) Ms. Johansen resigned as a PacifiCorp executive officer effective March 21, 2006.
(I) Mr. Wright resigned as a PacifiCorp executive officer effective March 21, 2006.
(j) Mr. Pittman resigned as a PacifiCorp executive officer effective September 5, 2005.
Aggregated Option Exercises at March 31, 2006 and Year-End Option Values
TIle following table sets forth information regarding the aggregate options exercised during the past fiscal year and the option
values at March 31, 2006 for each of the named executive officers. All options are for ScottishPower American Depository
Shares and include options granted under the PSJP and the ExSOP.
100
http://www .see.gov/ Arehives/edgar/data/75594/000007559406000028/p 10k.htm 5/31/06
....---...-..---"-"."-,-....--.--.....
Page 148 of 160
.. .-....-...-.........---......--..--..-
Number or Securilies
Underlying Unnerclsed
Oplioni
at Mardi 31. 2006
Value or Unexercised
In-tile-Money Opllolls
at Marcil 31, 1006
Name
Shares
Acquired
.:nrclse Exercisable
Value
Realized Exercisable Uneurelsahle
Gregory E. Abet
Judith A. Johansen
Andrew P. Haller
A. Richard Walje
Richard D. Peach (a)
Stanley K. Watters
Matthew Wright (a)
Michael 1. Pittman
124,125 1 561 008
046 196 042
957 282 561
192 487 765
33,262 364 366
288
151 359
161,655
274 096
350
865
520
493,979
217 813 933,991
(a) Certain options of Mr. Peach and Mr. Wright are for ScottishPower Ordinary Shares, but are presented as American
Depository Shares.
Unexerclsable
Long-Term Incentive Plan Awards in the Last Fiscal Year
The following table sets forth information regarding awards made in the year ended March 31 , 2006 to each named executive
officer under the L TIP. Each L TIP award entitles the executive officer to acquire, at no cost, the number of ScottishPower
American Depository Shares listed in the table, less any withholding for applicable taxes. An award will only vest if the
ScottishPower Remuneration Committee is satisfied that certain performance measures related to the sustained underlying
financial performance of the ScottishPower group and improvements in customer service standards are achieved over a
period of three years commencing with the fiscal year preceding the date an award is made. The number of shares that
vest depend upon ScottishPower s comparative Total Shareholder Return performance over the three-year performance
period. Total Shareholder Return perfonnance is measured against a peer group of major international energy companies. No
shares vest unless ScottishPower s Total Shareholder Return performance is at least equal to the median performance of
the peer group. at which point 40% of the initial award vests. IfScottishPower s performance is equal to or exceeds the top
quartile, 100% of the shares vest. The number of shares that vest for performance between these two points is determined on
a straight-line basis. Furthermore, the number of vested shares for each award will be prorated to reflect only the portion of
the three-year performance period in which PncifiCorp was owned by ScottishPower. Participants may acquire
the vested shares at any time after the third anniversary of grant.
Esllmated Fulure I'ayouls
Under Non-Sloek l'rlee.Dllsedl'.nns
Name
Number ur
Shares,
Unlls
or Other
RIghts
Target
Shares (a)
errormance
or Olher
PcrlndlJntll
r.-Ialurallon
or I'ayoul
Exercise or
Threshold
Shares
Gregory E. AbelJudith A. Johansen 15,839 3 yearsAndrew P. Haller 3 774 3 yearsA. Richard Walje 5 374 3 yearsRichard D. Peach 5 704 3 yearsStanley K. Watters 2 900 3 yearsMatthew Wright 4 959 3 yearsMichael t Pittman 5,490 3 years
(n) Amount to vest if threshold measures and median Total Shareholder RetUrn performance are achieved.
990
474
676
717
364
623
690
http://www.see.gov/Archives/edgar/datal75594/000007 5 59406000028/p 10k.htm
Maslmum
Shares (bl
977
186
689
792
911
558
725
5/31/06
- -..-.......-..--,-...,.....,-,-,---..,-....-,..,---.....--..--- ..-...-..-.-..--...."""'---""--' -.'..'----....---
Page 149 of 160
(b) Maximum number of shares exercisable reflects prorating related to acquisition by MEHC as described above.
101
http://www.see.goy/Archiyes/edgar/data/75 594/000007 559406000028/p 1 Ok.htm 5/31/06
.. -."...--.---....--".-.....-"-."""--"-."-.""""""""",-""",-,,,,...,,.,,,-""'--'.-.....-...--.,-........-,...............-.-.'-.-..' ,'.'-"-"."-""--'
Page 150 of 160
Employment Agreements
In September 2003, Ms. Johansen and PacifiCorp executed an employment agreement providing for a base salary of
$700 000 and a maximum annual incentive award of 75.0% of base salary. Under the agreement, she was eligible for
participation in the L TIP, the ExSOP and the Retirement Plan referred to below, in addition to other benefit plans available
for senior-level executives ofPacitiCorp. Additionally, Ms. Johansen agreed to standard confidentiality, non-competition and
non-solicitation terms. (n December 2005, Ms. Johansen signed an amendment to her employment agreement with
PacifiCorp and ScottishPower. The amendment:
Provided for the termination of Ms. Johansen s employment with PacifiCorp and her resignation as an officer and director
ofPacifiCorp and all affiliates, including ScottishPower, effective immediately following the closing of the sale of
PacifiCorp to MEHC;
Restated her waiver of participation in the PacifiCorp Executive Severance Plan;
Provided for the cash retention award associnted with PacifiCorp s sale to MEHC previously approved by
ScottishPower s Remuneration Committee, equal to one times base salary, which was contingent on the closing of
PacifiCorp s sale to MEHC and also on Ms. Johansen s continued employment and her satisfactory performance of duties
in the period tluough the sale s closing; Ms. Johansen wiU receive 80.0% of the retention award within 90 days of the
closing of the sale and will receive the remaining 20.0% of the award 365 days from the date of the closing, provided
there are no claims by MEHC against ScottisbPower related to the sale;
Modified her AlP terms to reflect a single measurement, PacifiCorp s perfonnance against its budget, and to eliminate
pro rata payout, as described above;
Clarified the respective obligations ofPacifiCorp and ScottishPower to her after the termination of her employment;
Provided that upon termination and assuming compliance by her with the terms of her employment agreement, she would
receive severance benefits equal.to 12 months of salary, bonus and vehicle allowance, plus enhanced change-in-control
benefits under the PacifiCorp Supplemental Executive Retirement Plan;
Provided for a gross-up payment by PacifiCorp to Ms. Johansen to cover any excise tax payable in connection with
separation payments, as well as certain health insurance and other benefits following her employment termination; and
Added certain customary obligations relating to non-disparagement and conflicts of interest.
In December 2004, Mr. Pittman and PacifiCorp executed an employment agreement providing for a base salary of $325 000
and a maximum annual incentive award of 100.0% of base salary (unless otherwise modified by the Remuneration
Committee). Under the agreement, he was eligible for participation in the LTIP, the Ex-SOP and the Retirement Plan, in
addition to other benefit plans available for senior level executives of PacifiCorp. Additionally, Mr. Pittman agreed to
standard confidentiality, non-competition and non-solicitation terms.
In October 2005, PacifiCorp entered into a compromise agreement with PHI and Mr. Pittman that superseded Mr. Pittman'
employment agreement with PacifiCorp and ScottishPower and documented the terms of his separation from the companies
following a ScottishPower corporate restructuring that eliminated his position. Under his employment agreement,
Mr. Pittman was entitled to severance benefits equal to 12 months of salary, bonus and vehicle a!lowance and 6 months of
continued health insurance coverage. The Compromise Agreement supplemented those benefits with enhancements generally
comparable to those payable under the PacifiCorp Executive Severance Plan for a termination following a change in control
ofPacifiCorp, including an additional 12 months of salary, bonus and vehicle allowance and health insurance coverage for an
additional 18 months. ScottishPower reimbursed PacifiCorp for the cost of tile supplemental benefits provided by the
compromise agreement.
Mr. Abet's employment agreement with MEHC is described in MEHC's Annual Report on Form lOoK for the year ended
December 3 1 2005 (File No. 001-14881).
102
http://www.see.gov/Arehives/edgar/data/75594/000007 5 59406000028/p 1 Ok.htm 5/31/06
-----."--".--."".'--"'.'--"-"", --.".."..",..,--....-,.,-,...,-".."".,.-.-.- --- -"".".----",.-",."-,---.",,.-,-.---.-.""""---.".,,---
Page 151 of160
Retention Agreements
In May 2005, PacifiCorp and its Senior Vice President and Chief Financial Officer, Richard D. Peach entered into a retention
agreement entitling Mr. Peach to an $80 000 retention bonns on June 1,2006 ifhe remains employed at an tlcceptable level
of performance in PacifiCorp s corporate finance department through May 30, 2006 and has developed a succession and risk
mitigation plan for his department. If Mr. Peach's employment is terminated involuntarily due to a workforce reduction
during the term of the retention agreement, he will receive the full amount of any unpaid retention bonuses.
In August 2005, PacifiCorp s named executive officers (other than Mr. Abel, Ms. Johansen and Mr. Pittman) entered into
agreements with ScottishPower for awards under the Transaction Incentive Program, which is a $6.0 million pool created by
ScottishPower for retention incentives during the period of completion of Scottish Power s sale ofPacifiCorp to MEHC. The
agreement signed by each named executive officer provided for a transaction incentive award in an amount equal to the
executive officer s base salary (in Mr. Peach's case, this amount was adjusted for his existing retention agreement), payable
as follows:
25.0% of the award was paid within one month of execution and delivery of the award agreement;
50.0% of the award is payable three months after the closing ofPacifiCorp s sale to MEHC, provided there are no claims
by MEHC against ScottishPower; and
25.0% ofthe award is payable 12 months after the closing, again as long as there are no claims by MEHC against
ScottisbPower.
Continued employment by PacifiCorp, observance of confidentiality obligations and satisfactory performance in support of
the transaction un tit the sale s completion are conditions to the executive officer s receipt oftbese payments. Award
payments are the obligation of ScottishPower. Ultimate determinations of award eligibility witt be made by ScottishPower
Chief Executive Officer, subject to review by its Remuneration Committee.
On May 24, 2006, PacifiCorp entered into certain retention agreements with each of Messrs. Halter and Peach. Under each
retention agreement, provided that the executive has not voluntarily resigned or had his employment with PacifiCorp
terminated for cause prior to December 31 2006 for Mr. HaUer and November 22 2006 for Mr. Peach, the executive (i) will
be entitled to the same benefits the executive would have been entitled to under PacifiCorp s Supplemental Executive
Retirement Plan ("SERF") had the executive terminated his employment during the two.month window period following the
first anniversary of a change in control, and (ii) will be entitled, upon any termination on or following the applicable retention
date, to the same benefits the executive would have been entitled to under PacifiCorp s Executive Severance Plan had such
tennination occurred in connection with a material alteration in position or compensation within the 24-month period
following a change in control.
Severance Arrangements
PacifiCorp s Executive Severance Plan provides severance benefits to certain executive-level employees who in the past
were designated by the PacifiCorp Compensation Committee, but who in the future will be designated by the Chairman of the
Board of Directors. TIle executive officers named in the Summary Compensation Table (other than Mr. Abel and
Ms. Johansen) participate in this plan.
Severance benefits are payable by PacifiCorp for voluntary terminations as a result of a certain material alterations in position
or compensation that have a detrimental impact on the executive s employment or involuntary terminations (including a
PacifiCorp-initiated resignation) for reasons other than cause. Severance payments generally equal one or two times the
executive s annual cash compensation, three months of health insurance benefits and outplacement services.
The Executive Severance Plan also provides enhanced severance benefits in the event of certain terminations during the 24-
month period following a qualifying change-in-control transaction; with respect to MEHC's acquisition ofPacifiCorp, this
qualifying period commenced on May 23, 2005. Executives designated by the PacifiCorp Compensation Committee or
Chairman, as applicable, are eligible for change-in-control benefits resulting from either a PacifiCorp-initiatcd termination
without cause or a resignation generally within two months after certain material alterations in position or compensation. If
qualified for the enhanced severance benefits, an executive would receive severance pay in an amount equal to either two
two and one-half or three times the annual cash compensation of the executive, depending on the level set by the PacifiCorp
Compensation Committee or Chairman, as applicable. PacifiCorp is required to make an additional payment to compensate
the executive for the effect of any excise tax. "TIle executive would also receive continuation of subsidized health insurance
from six to 24 months, depending on length of service, and outplacement services.
103
http://www .see.goy/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06
......-....,......-...-..---.-.",...-,.--,,-........---...-.".....,..,.,...........-.--.-...-..-......---...----.-
Page 152 ofl60
http://www.see.gov/Arehives!edgar/data/75594/000007 5 59406000028/p 1 Ok.htm 5/31/06
,-..--..,----..-..-.,-,.--........--
,.,._.m.._.-
Page 153 of 160
Retirement Itlans
PacifiCorp has adopted non-contributory defined benefit retirement plans for its employees, other t11an employees subject to
collective bargaining agreements that do not provide for coverage. Certain executive officers, including the executive officers
named in dle Summary Compensation Table other than Mr. Abel, are also eligible to participate in PacifiCorp s non-qualified
SERF. TIle following description assumes participation in both the Retirement Plan and the SERP. Participants receive
benefits at retirement payable for life based on length of service with PacifiCorp and average pay in the 60 consecutive
months of highest payout oftbe last 120 mondls, and pay for this purpose would include salary and AlP payments reflected
in the Summary Compensation Table above. Benefits arc based on 50.0% of final average pay plus 1.0% of final average pay
for each year that PacifiCorp meets certain performance goals set for each fiscal year by, in the past, the PacifiCorp
Compensation Committee, and now the Chairman of the Board of Directors. TIle maximum benefit is 65.0% of final average
pay. Participants may also elect actuarially equivalent alternative fonDs of benefits. Retirement benefits are adjusted to retlcct
social security benefits as welt as certain prior employer retirement benefits. Participants are entitled to receive flill benefits
upon retirement after age 60 with at least 15 years of service. Participants are also entitled to receive reduced benefits upon
early retirement after age 55 or after age 50 with at least 15 years of service and five years of participation in the SERP.
TIle following table shows the estimated annual retirement benefit payable upon retirement at age 60 as of March 31, 2006.
Amounts in the table reflect payments from the Retirement Plan and the SERP combined, prior to any offset of projected
social security benefits and benefits paid from any prior employer plan.
Estimated Annunl Pension at Retirement (n)
Final Average ray al Retirement Dale
Yea" of Senlee (b)
43,333 130 000 130 000 130 000
667 260 000 260 000 260,000
130,000 390,000 390,000 390 000
173 333 520 000 520 000 520 000
216 667 650,000 650,000 650 000
$200,000
400 000
600 000
800 000
000 000
(b)
TIle benefits shown in this table assume tlmt the individual will remain in the employ ofPacifiCorp until retirement at
age 60, that the Retirement Plan and the SERF will continue in their present form and that PacifiCorp achieves its
performance goals under the SERF in all years.
111e number of credited years of service used to compute aggregate benefits under the Retirement Plan and the SERF
are five for Ms. Johansen, five for Mr. Hatler, 20 for Mr. Walje, 11 for Mr. Peach, 24 for Mr. Watters, 19 for
Mr. Wright and 26 for Mr. Pittrmm.
(a)
ITEM 12. SECURITY OWNERSIDr OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
All outstanding shares of common stock of PacifiCorp are indirectly owned by MEHC, 666 Grand A venue, Des Moines,
Iowa 50309. MEHC is a consolidated subsidiary of Berkshire Hathaway, which owns approximately 88.2% ofMEHC'
common stock (86.6% on a diluted basis). The balance of MEHC's common stock is owned by a private investor group
comprised of Walter Scott, Jr. (including family members and related entities), David L. Sokol and Gregory E. Abel,
PacifiCorp s Chairman and Chief Executive Officer.
Based on a Schedule 13G filed with the SEC on February 15, 2006, CAM North America, LLC, 399 Park Avenue, New
York, NY 10022, is the beneficial owner of 38,910 shares, or 5.19%, ofPacifiCorp s outstanding 7.48% Series Preferred
Stock.
104
http://www.see.goy/ Arehiyes/edgar/data/75S94/0000075 59406000028/p 1 Ok.htm 5/31/06
Page 154 of 160
No PacifiCorp executive officers or directors own shares ofPacifiCorp s preferred stock or shares of the Class B common
stock of Berkshire Hathaway. The following table sets forth certain information as of March 31, 2006 regarding the
beneficial ownership of common stock ofMEHC and the Class A common stock of Berkshire Hathaway by (i) each oftbc
executive officers named in the Summary Compensation Table under Item 11. Executive Compensation above, (ii) each
director ofPacifiCorp as detailed under "Item 10. Directors and Executive Officers of tile Registrant," and (iii) all executive
officers and directors of PacifiCorp as a group.
l\-IId'\merlcan Common Stock Berkshire lIathawllY Clllss A Common Slack
Beneflcllll Owner
Nllmber of shares
Beneficially Owned (a)
ereenlage of
Clan (a)
Number of shares
lIenenelllll)' Owned (a)
Percentage of
Class (a)(c)
Gregory E. Abet (b)
Douglas L. Anderson
William J. Fehrman
Brent E. Gale
Patrick J. Goodman
Andrew p, Haller
Nolan E. Karras
A. Robert Lasicll
Mark C. Moench
Richard D. Peach
A. Richard Walje
Stanley K. Watters
Bruce N. Williams
All executive officers and directors
as a group (13 persons)
749,992 1.01%
749 992 1.01 %
(b)
Includes shares as to which the listed beneficial owner is deemed to have the right to acquire beneficial ownership
under Rule) 3d-3( d) under the Securities Exchange Act, including, among other things, shares which the listed
beneficial owner bas the right to acquire within 60 days.
Includes options to purchase 649,052 shares of common stock which are exercisable within 60 days. Excludes 10 041
shares reserved for issuance pursuant to a deferred compensation plan.
* Indicates beneficial ownership of less than one percent of all outstanding shares.
(a)
(c)
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS RELATED TRANSACTIONS
According to the terms of Andrew P. HaUer s offer letter, PacifiCorp made a $200 000.00 loan to Mr. Haller on May 21,
200 I for the repayment of obligations to his former employer. The loan accrues interest at the annual rate of 4.74%.
Mr. Haller has repaid $146 793.50 of the loan amount. TIlC largest outstanding loan balance, including accrued interest, at
any time during the year ended March 31,2006 was $86 206.50 at July 11,2005. As of March 31, 2006, the outstanding loan
balance was $55,016.83, including accrued interest. The remaining balance and interest is payable in one payment of
$32 988,56 on June 30, 2006 and one payment of $23 730.98 on June 30, 2007.
See "Item 8, Financial Statements and Supplementary Data - Note 4 - Related-Party Transactions" for other information on
related-party transactions.
105
http://www .see.gov/ Arehives/edgar/data/75594/000007559406000028/p 10k.htm 5/31/06
Page 155 of 160
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
111e ScottishPower Audit Committee retained PricewaterhouseCoopers LLP, independent certified public accountants, as
PacifiCorp s independent registered public accounting firm for the year ended March 3 1 2006, which was affirmed by the
MEHC Audit Committee.
Fees and Pre-Approval Policy
MEHC's Audit Committee has an Audit and Non-Audit Services Pre-Approval Policy (the "Policy ) which sets forth the
procedures and the conditions pursuant to which services to be performed by the independent registered public accountant are
to be pre-approved. Pursuant to the Policy, certain services described in detail in the Policy may be pre-approved on an
annual basis together with pre-approved maximum fee levels for such services. The services eligible for annual pre-approval
consist of services that would be included under the categories of Audit fees, Audit-related fees and Tax fees below. Ifnot
pre-approved on an annual basis, proposed services must otherwise be separately approved prior to being performed by the
independent registered public accountant. In addition, any services that receive annual pre-approval but exceed the pre-
approved maximum fee level also will require separate approval by the Audit Committee prior to being performed. 111e
PacitiCorp Board of Directors has not adopted any pre-approval policy that is in addition to or different than the MEHC
Audit Committee s pre-approval policy.
ScottishPower s Audit Committee used a pre-approval policy for PricewaterhouseCoopers' services and fees. 111is policy
detailed the services that could be provided by the independent registered public accounting firm, and required that where the
initial fee value for any services permitted in accordance with the policy exceeded (100 000 (or its United States doUar
equivalent), the assignment had to be reviewed and authorized by the Chairman oftlte ScottishPower Audit Committee with
the concurrence of the ScottisbPower Finance Director. Any services authorized by the Chairman were reported to the
ScottishPower Audit Committee at its next scheduled meeting, and fees paid to the independent registered public accounting
finn were reported regularly to the ScottishPower Audit Committee.
The following table presents fees bi~led by PricewaterhouseCoopers for the years ended March 31 , 2006 and 2005.
Total
Ycar Elided Mardi 31,
2006 2005
1.4 42.4%$ 1.4 30.4%
0.4 12.1.1 23.
1.4 42.4 43.
100.0% $ 4.LOO.
(('I-IllIIon5 of dollars)
Audit fees
Audit-related fees
Tax fees
Other fees
Allditfees are for the audit and review ofPacifiCorp s financial statements in accordance with the standards of the ,Public
Company Accounting Oversight Board (tJnited States), including comfort letters, statutory and regulatory audits, consents
and services related to SEC matters.
Alldit-relatedfees are for assurance and related services that are related to the audit or reviewofPacifiCorp s financial
statements, including employee benefit plan audits, due diligence services and financial accounting and reporting
consultation.
Taxfees are fees for tax compliance services and related costs.
Otller fees are mainly for services rendered in connection with requests from state regulatory commissions and for regulatory
matters.
106
http://www.sec.gov/ Archives/edgar/datal7 5594/000007559406000028/p 1 Ok.l1tm 5/31/06
-...........-.....--.....-.-......-"-.-
Page 156 of 160
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
The list of all financial statements filed as a part of this report is included in Item 8. Financial Statements and
Supplementary Data.
Schedules:
All schedules have been omitted because of the absence of the conditions under which they are required
or because the required information is included elsewhere in the financial statements included under
Item 8. Financial Statements and Supplementary Data.
Exhibits:
(a)
EJlhlbl1
IDmlltt
I(a)*
2.1 (b) *
f.xhlhlJ.1.l1k
Agreement and Plan of Merger, dated as of December 6, 1998, by and among Scottish Power pic, NA
Gcncral Partnership, Scottish Power NA 1 Limited and Scottish Power NA 2 Limited. (Exhibit 1 to the
Form 6-K, dated December 11, 1998. filed by Scottish Power pic, File No. 1-14676).
Amended and Restated Agreement and Plan of Merger, dated as of December 6, 1998, as amended as of
January 29, 1999 and February 9, 1999. and amended and restated as of February 23, 1999, by and
among New Scottish Power PLC, Scottish Power pIc, NA General Partnership and PacifiCorp (Exhibit
(2)b, Form 10-K for year ended December 31, 1998. File No. 1-5152).
1l1ird Restated Articles of(ncorporation ofPacifiCorp (Exhibit (3)b, Form lO-K for the year ended
December 31 1996, File No. 1-5152).
Bylaws ofPacifiCorp, as amended May 23, 2005.
Mortgage and Deed of Trust dated as of January 9, 1989, between PacifiCorp and jp Morgan Chase
Bank (formerly known as The Chase Manhattan Bank), Trustee, Ex. 4-E, Fonn 8-, File No. 1-5152, as
supplemented and modified by 18 Supplemental Indentures as follows:
Edllbll
Number lIe 'f)'
(4)(b)
(4)(a)
4(a)
4(a)
4(a)
4(a)lO-Q
4(a)lO-
4(a)
(4)b JO-
(4)b IO-Q
(4)b lOo
(4)b 10-
4(b)10-
99(a)10-
4.1 10-Q
File Dale
File
Number
January 9, 1990
September 11, 1991
January 7, 1992
Quarter ended March 31, \992
Quarter ended September 30, 1992
April \, \993
Quarter ended September 30, 1993
Quarter ended June 30, 1994
Year ended December 3\, 1994
Year ended December 31, 1995
Year ended December 31 , 1996
Year ended December 3 I, 1998
November 21,2001
Quarter ended June 30, 2003
September 8, 2003
August 24, 2004
June 13, 2005
33-3\861
5152
5152
5152
5152
5152
5152
5152
5\52
5152
5152
5152
5152
5152
5152
5152
5152
5\52
107
http://www.see.gov/ Arehives/edgar/data/75594/0000075 59406000028/p 1 Ok.htm 5/31/06
.. -.".--""--'--".-"-""".-".-.-..-,..-----..-...,.---,
Page 157 of 160
Third Restated Articles ofIncorporation and Bylaws. See 3.1 and 3.2 above.
In reliance upon item 601(4)(iii) of Regulation S-K, various instruments defining the rights of holders oflong-terrn
debt of the Registrant and its subsidiaries are not being filed because the total amount authorized under each such
instrument does not exceed 10.0% of the total assets of the Registrant and its subsidiaries on a consolidated basis. The
Registrant hereby agrees to furnish a copy of any such instrument to the Commission upon request.
IO.l '"
10.
10.
10.4*
to.
10.
to.
10.
10.9'"
10.10*
10.11*
10.12*
10.13*
10.
10.
Judith Johansen Employment Agreement (Exhibit 10., Annual Report on Fornl 10-, filed May 27, 2005
File No. 1-5152).
Amendment No.1 to Employment Agreement among PacifiCorp, Scottish Power pic and Judith Johansen
dated as of December 20 2005 (Exhibit 10, Current Report on Form 8-, filed December 23,2005, File
No. 1-5152).
Compensation Reduction Plan (Exhibit 10., Annual Report on Form IO-K, filed May 27, 2005, File No.
5152).
Amendment No.1 to PacifiCorp Compensation Reduction Plan, dated effective July 1,2003 (Exhibit 10.
Quarterly Report on Form 10-Q, filed November 10, 2005, File No. 1-5152).
Amendment No.2 to PacifiCorp Compensation Reduction Plan, dated effective September 20, 2005
(Exhibit 10., Quarterly Report on Form IO-Q, filed November 10 2005, File No. 1-5152).
Executive Severance Plan (Exhibit 10.3, Current Report on Form 8-K, filed May 6, 2005, File No. 1-
5152).
Amendment to PacifiCorp Executive Severance Plan, dated effective October 31, 2005. (Exhibit 10.
Quarterly Report on Form IO-Q, filed February 14 2006, File No. 1-5152).
Supplemental Executive Retirement Plan (Exhibit 10.7, Annual Report on Form IO-, filed May 27 2005,
File No. 1-5152).
Richard Peach Retention Agreement (Exhibit lOA, Current Report on Form 8-K, filed May 6, 2005, File
No. 1-5152).
Andrew HaUer Promissory Note (Exhibit 10., Annual Report on Form 10-, filed May 27 2005, File
No. 1-5152).
Form of Transaction Incentive Program A ward Agreement for Named Executive Officers (Exhibit 10
Current Report on Form 8-, filed September 1 2005, FileNo. 1-5152).
Michael Pittman Employment Agreement (Exhibit lOA, Annual Report on Form 10-K, filed May 27
2005,FileNo.5152).
Compromise Agreement among PacifiCorp, PacifiCorp Holdings, Inc. and Michael J. Pittman, dated
October 4, 2005 (Exhibit lOA, Quarterly Report on Form lO-Q, filed November 10, 2005, File No. 1-
5152).
Andrew Haller Retention Agreement.
Richard Peach Retention Agreement.
108
http://www.sec.gov/ Archives/edgar/data/75594/000007 559406000028/p 1 Ok.htm 5/31/06
12.
12.
31.1
31.2
32.1
32.
Page 158 ofl60
Statements of Computation of Ratio of Earnings to Fixed Charges.
Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock
Dividends.
Consent of Price waterhouse Coopers LLP.
Power of Attorney.
Section 302 Certification of Principal Executive Officer Pursuant to Rule 13a- 14(a)115d-14(a).
Section 302 Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a).
Section 906 Certification of Principal Executive Officer Pursuant to 18 V.C. Section 1350.
Section 906 Certification of Principal Financial Officer Pursuant to 18 V.C. Section 1350.
Stock Purchase Agreement among Scottish Power pic, PacifiCorp Holdings, Inc. and MidAmerican
Energy Holdings Company ~Exhibit 99., Current Report on Fonn 8-K, filed May 24, 2005, by
MidAmerican Energy Holdings CompaJ1Y, File No. 001-14881).
Amendment No.1 to Stock Purchase Agreement, dated as of March 21, 2006, by and among Scottish
Power pIc, PacifiCorp Holdings, Inc. and PPW Holdings LLC (as successor-in-interest to MidAmerican
Energy Holdings Company) (Exhibit 10., Current Report on Fonn 8-K, filed March 21, 2006, by
MidAmerican Energy Holdings Company, File No. 001-14881).
Incorporated herein by reference.
99.1*
99.
(b) See (8) 3. above.
(c) See (a) 2. above.
109
http://www.sec.goY/Archives/edgar/datal75 594/000007 559406000028/p 1 Ok. him 5/31106
Page 159 ofl60
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(0) OF THE SECURITIES EXCHANGE ACT OF 1934
THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED
llIEREUNTO DULY AUTHORIZED,
PacifiCorp
By: Isl GREGORY E. ABEL
Gregory E. Abel
(CHIEF EXECUTIVE OFFICER)
Date: May 26, 2006
PURSUANT TO THE REQUIREMENTS OF TI-IE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN
SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN TILE CAP AClTlES
AND ON THE DATES INDICATED.
SIGNA'ruRF.TIJJ..E
Chairman of the Board of Directors
And Chief Executive Officer
P,\Tf.
Is! GREGORY E. ABEL May 26, 2006
Gregory E. Abet
Is! RICHARD D. PEACH Senior Vice President, Chief
Financial Officer and Director
May 26, 2006
Richard D. Peach
WilliamJ. Fehrman
)Director May 26, 2006
* DOUGLAS L. ANDERSON
Douglas L. Anderson
* WILLIAM J. FEHRMAN
* BRENT E. GALE
Brent E. Gale
* PATRICK J. GOODMAN
Andrew P. Haller
Patrick 1. Goodman
Is! ANDREW P. HALLER
110
http://www.see.goY/ Archives/edgar/data/75594/000007 559406000028/p 1 Ok.htm 5/31/06
, ,.....-.-.-....-.-,--..--.-.......-...-.-.----.
Page 160 of 160
'" NOLAN E. KARRAS
Nolan E. Karrns
)Director May 26, 2006
'" A. ROBERT LASICH
A. Robert Lasich
'" MARK C. MOENCH
Mark C. Moench
'" A. RICHARD W ALJE
A. Richard Watje
'" STANLEY K. W A TIERS
Stanley K. Watters
*By: Is! RICHARD D. PEACH
Richard D. Peach, as
Attorney-in-Fact
III
http://www .sec.gov/ Archives/edgar/data/75594/000007559406000028/p 1 Ok.htm 5/31/06