10-K 1 pacificorp123110form10k.htm PACIFICORP FORM 10-K 12-31-2010 WebFilings | EDGAR view
 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the fiscal year ended December 31, 2010
or
 
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the transition period from _____ to _____
 
Commission
 
Exact name of registrant as specified in its charter;
 
IRS Employer
File Number
 
State or other jurisdiction of incorporation or organization
 
Identification No.
1-5152
 
PACIFICORP
 
93-0246090
 
 
(An Oregon Corporation)
 
 
 
 
825 N.E. Multnomah Street
 
 
 
 
Portland, Oregon 97232
 
 
 
 
503-813-5608
 
 
 
Securities registered pursuant to Section 12(b) of the Act: None
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 Securities Act.
Yes x No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o No x
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the 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 x No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  o No  o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o
Accelerated filer o
Non-accelerated filer x
Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No x
 
All shares of outstanding common stock of PacifiCorp are indirectly owned by MidAmerican Energy Holdings Company, 666 Grand Avenue, Des Moines, Iowa 50309. As of January 31, 2011, 357,060,915 shares of common stock were outstanding.
 

 

 
TABLE OF CONTENTS
 
 
 
 
 
 
 
PART I
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART III
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART IV
 
 
 
 
 
 
 
 
 
 
 
 

2

 

Forward-Looking Statements
 
This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon PacifiCorp's current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside PacifiCorp's control and could cause actual results to differ materially from those expressed or implied by PacifiCorp's forward-looking statements. These factors include, among others:
 
•    
general economic, political and business conditions, as well as changes in laws and regulations affecting PacifiCorp's operations or related industries;
 
•    
changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce generating facility output, accelerate generating facility retirements or delay generating facility construction or acquisition;
 
•    
the outcome of general rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies;
 
•    
changes in economic, industry or weather conditions, as well as demographic trends, that could affect customer growth and usage or electricity supply or PacifiCorp's ability to obtain long-term contracts with wholesale customers and suppliers;
 
•    
a high degree of variance between actual and forecasted load that could impact PacifiCorp's hedging strategy and the cost of balancing its generation resources and wholesale activities with its retail load obligations;
 
•    
performance and availability of PacifiCorp's generating facilities, including the impacts of outages or repairs, transmission constraints, weather and operating conditions;
 
•    
hydroelectric conditions, as well as the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings, that could have a significant impact on electricity capacity and cost and PacifiCorp's ability to generate electricity;
 
•    
changes in prices, availability and demand for both purchases and sales of wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;
 
•    
the financial condition and creditworthiness of PacifiCorp's significant customers and suppliers;
 
•    
changes in business strategy or development plans;
 
•    
availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in the London Interbank Offered Rate, the base interest rate for PacifiCorp's credit facilities;
 
•    
changes in PacifiCorp's credit ratings;
 
•    
the impact of derivative contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of derivative contracts;
 
•    
the impact of inflation on costs and our ability to recover such costs in rates;
 
•    
increases in employee healthcare costs;
 
•    
the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on expense and funding requirements associated with PacifiCorp's pension and other postretirement benefits plans and the joint trust plans to which PacifiCorp contributes;

3

 

 
•    
unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future generating facilities and infrastructure additions;
 
•    
the impact of new accounting guidance or changes in current accounting estimates and assumptions on consolidated financial results;
 
•    
other risks or unforeseen events, including the effects of storms, floods, litigation, wars, terrorism, embargoes and other catastrophic events; and
 
•    
other business or investment considerations that may be disclosed from time to time in PacifiCorp's filings with the United States Securities and Exchange Commission ("SEC") or in other publicly disseminated written documents.
 
Further details of the potential risks and uncertainties affecting PacifiCorp are described in Item 1A and other discussions contained in this Form 10-K. PacifiCorp undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors should not be construed as exclusive.
 
 

4

 

PART I
 
Item 1.      Business
 
General
 
PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric company serving 1.7 million retail customers, including residential, commercial, industrial and other customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, 78 thermal, hydroelectric, wind-powered and geothermal generating facilities, with a net owned capacity of 10,623 megawatts ("MW"). PacifiCorp also owns, or has interests in, electric transmission and distribution assets, and transmits electricity through approximately 16,200 miles of transmission lines. PacifiCorp also buys and sells electricity on the wholesale market with public and private utilities, energy marketing companies and incorporated municipalities as a result of excess electricity generation or other system balancing activities. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining and environmental remediation services. PacifiCorp is an indirect subsidiary of MidAmerican Energy Holdings Company ("MEHC"), a holding company based in Des Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MEHC controls substantially all of PacifiCorp's voting securities, which include both common and preferred stock.
 
PacifiCorp's principal executive offices are located at 825 N.E. Multnomah Street, Portland, Oregon 97232, and its telephone number is (503) 813-5608. PacifiCorp was initially incorporated in 1910 under the laws of the state of Maine under the name Pacific Power & Light Company. In 1984, Pacific Power & Light Company changed its name to PacifiCorp. In 1989, it merged with Utah Power and Light Company, a Utah corporation, in a transaction wherein both corporations merged into a newly-formed Oregon corporation. The resulting Oregon corporation was re-named PacifiCorp, which is the operating entity today.
 
Berkshire Hathaway Equity Commitment
 
In March 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement ("Berkshire Equity Commitment") pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of MEHC's common equity upon any requests authorized from time to time by MEHC's Board of Directors. The proceeds of any such equity contribution shall only be used by MEHC for the purpose of (a) paying when due MEHC's debt obligations and (b) funding the general corporate purposes and capital requirements of MEHC's regulated subsidiaries, including PacifiCorp. Berkshire Hathaway will have up to 180 days to fund any such request in increments of at least $250 million pursuant to one or more drawings authorized by MEHC's Board of Directors. The funding of each drawing will be made by means of a cash equity contribution to MEHC in exchange for additional shares of MEHC's common stock. PacifiCorp has no right to make or to cause MEHC to make any equity contribution requests. In March 2010, MEHC and Berkshire Hathaway amended the Berkshire Equity Commitment extending the term from February 28, 2011 to February 28, 2014 and reducing the $3.5 billion to $2.0 billion effective March 1, 2011.
 
Operations
 
PacifiCorp delivers electricity to customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power and to customers in Oregon, Washington and California under the trade name Pacific Power. PacifiCorp's electric generation, commercial and trading, and coal mining functions are operated under the trade name PacifiCorp Energy. 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 water resources, wind and geothermal to generate electricity at its generating facilities. This electricity, together with electricity purchased on the wholesale market, is then transmitted via a grid of transmission lines throughout PacifiCorp's six-state service area and the Western United States. The electricity is then transformed to lower voltages and delivered to customers through PacifiCorp's distribution system.
 
PacifiCorp's primary goal is to provide safe, reliable electricity to its customers at a reasonable cost. In return, PacifiCorp expects that all prudently incurred costs to provide such service will be included as allowable costs for ratemaking purposes, and PacifiCorp will be allowed an opportunity to earn a reasonable return on its investments.
 

5

 

PacifiCorp seeks to manage growth in its customer demand through the construction and purchase of new cost-effective, environmentally prudent and efficient sources of power supply and through demand response and energy efficiency programs. During 2010, PacifiCorp placed in service its 111-MW Dunlap Ranch I wind-powered generating facility and began purchasing the entire output of a 200-MW wind-powered generating facility to help meet future retail load growth, achieve renewable generation targets and replace expiring wholesale supply contracts.
 
Employees
 
As of December 31, 2010, PacifiCorp, together with its subsidiaries, had approximately 6,300 employees, of which approximately 3,800 were covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Boilermakers and the United Mine Workers of America.
 
Service Territories
 
PacifiCorp's combined service territory covers approximately 136,000 square miles and includes diverse regional economies ranging from rural, agricultural and mining areas to urban, manufacturing and government service centers. No single segment of the economy dominates the service territory, which helps mitigate PacifiCorp's exposure to economic fluctuations. In the eastern portion of the service territory, mainly consisting of Utah, Wyoming and southeastern Idaho, the principal industries are manufacturing, recreation, agriculture and mining or extraction of natural resources. In the western portion of the service territory, mainly consisting of Oregon, southern Washington and northern California, the principal industries are agriculture and manufacturing, with forest products, food processing, technology and primary metals being the largest industrial sectors. In addition to retail sales, PacifiCorp sells electricity to other utilities, municipalities and energy marketing companies on a wholesale basis.
 
PacifiCorp's operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The average term of these agreements is approximately 30 years, although their terms range from five years to indefinite. PacifiCorp generally has an exclusive right to serve electric customers within its service territories and, in turn, has an obligation to provide electric service to those customers. In return, the state utility commissions have established rates on a cost-of-service basis, which are designed to allow PacifiCorp an opportunity to recover its costs of providing services and to earn a reasonable return on its investment.
 
The percentages of electricity sold to retail customers by jurisdiction were as follows for the years ended December 31:
 
 
2010
 
2009
 
2008
 
 
 
 
 
 
 
 
Utah
42
 
%
42
 
%
42
 
%
Oregon
24
 
 
25
 
 
26
 
 
Wyoming
18
 
 
17
 
 
17
 
 
Washington
8
 
 
8
 
 
7
 
 
Idaho
6
 
 
6
 
 
6
 
 
California
2
 
 
2
 
 
2
 
 
 
100
 
%
100
 
%
100
 
%

6

 

 
The following map highlights PacifiCorp's retail service territory, generating facility locations, coal mines in which PacifiCorp has an interest and PacifiCorp's primary transmission lines as of December 31, 2010. PacifiCorp's generating facilities are interconnected through PacifiCorp's own transmission lines or by contract through transmission lines owned by others.
 
 
(a)    
Access to other entities' transmission lines through wheeling arrangements.
 
 

7

 

 
Customers
 
Electricity sold to retail and wholesale customers by class of customer, total gigawatt hours ("GWh") sold and the average number of retail customers for the years ended December 31 were as follows:
 
 
2010
 
2009
 
2008
GWh sold:
 
 
 
 
 
 
 
 
 
 
 
Residential
15,795
 
 
24
%
 
15,999
 
 
24
%
 
16,222
 
 
24
%
Commercial
15,969
 
 
25
 
 
16,194
 
 
25
 
 
16,055
 
 
24
 
Industrial
20,680
 
 
32
 
 
19,934
 
 
31
 
 
21,495
 
 
32
 
Other
572
 
 
1
 
 
583
 
 
1
 
 
590
 
 
1
 
Total retail
53,016
 
 
82
 
 
52,710
 
 
81
 
 
54,362
 
 
81
 
Wholesale
11,415
 
 
18
 
 
12,349
 
 
19
 
 
12,345
 
 
19
 
Total GWh sold
64,431
 
 
100
%
 
65,059
 
 
100
%
 
66,707
 
 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands):
 
 
 
 
 
 
 
 
 
 
 
Residential
1,475
 
 
85
%
 
1,467
 
 
85
%
 
1,458
 
 
86
%
Commercial
220
 
 
13
 
 
214
 
 
13
 
 
210
 
 
12
 
Industrial
34
 
 
2
 
 
34
 
 
2
 
 
34
 
 
2
 
Other
4
 
 
 
 
4
 
 
 
 
4
 
 
 
Total
1,733
 
 
100
%
 
1,719
 
 
100
%
 
1,706
 
 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Retail customers:
 
 
 
 
 
 
 
 
 
 
 
Average usage per customer (kilowatt hours)
30,595
 
 
 
 
30,672
 
 
 
 
31,863
 
 
 
Average revenue per customer
$
2,142
 
 
 
 
$
2,076
 
 
 
 
$
2,043
 
 
 
Revenue per kilowatt hour
7.0¢
 
 
 
 
6.8¢
 
 
 
 
6.4¢
 
 
 
 
Customer Usage and Seasonality
 
In addition to the variations in weather from year to year, fluctuations in economic conditions within PacifiCorp's service territory and elsewhere can impact customer usage, particularly for industrial and wholesale customers. Beginning in the fourth quarter of 2008, certain customer usage levels began to decline due to the effects of the economic conditions in the United States. The declining usage trend continued during 2009, resulting in lower retail demand compared to 2008. The declining usage trend reversed during 2010 in the eastern side of PacifiCorp's service territory although partially offset by unfavorable weather conditions. The declining usage trend continued during 2010 in the western side of PacifiCorp's service territory.
 
Peak customer demand is typically highest in the summer across PacifiCorp's service territory when air conditioning and irrigation systems are heavily used. The service territory also has a winter peak, which is primarily due to heating requirements in the western portion of PacifiCorp's service territory. Peak demand represents the highest demand on a given day and at a given hour. During 2010, PacifiCorp's peak demand was 9,418 MW in the summer and 8,592 MW in the winter.
 
Generating Facilities and Fuel Supply
The percentage of PacifiCorp's energy supplied by energy source varies from year to year and is subject to numerous operational and economic factors such as planned and unplanned outages; fuel commodity prices; fuel transportation costs; weather; environmental considerations; transmission constraints; and wholesale market prices of electricity. When factors for one energy source are less favorable, PacifiCorp must place more reliance on other energy sources. For example, PacifiCorp can generate more electricity using its low cost hydroelectric and wind-powered generating facilities when factors associated with these facilities are favorable. When factors associated with hydroelectric and wind resources are less favorable, PacifiCorp must increase its reliance on more expensive generation or purchased electricity. PacifiCorp manages certain risks relating to its supply of electricity and fuel requirements by entering into various contracts, which may be accounted for as derivatives, including forwards, futures, options, swaps and other agreements. Refer to Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.
 

8

 

PacifiCorp has ownership interest in a diverse portfolio of generating facilities. The following table presents certain information concerning PacifiCorp's owned generating facilities as of December 31, 2010:
 
 
 
Location
 
Energy Source
 
Installed
 
Facility Net Capacity
(MW)(1)
 
 Net Owned Capacity (MW)(1)
COAL:
 
 
 
 
 
 
 
 
 
 
Jim Bridger
 
Rock Springs, WY
 
Coal
 
1974-1979
 
2,118
 
 
1,412
 
Hunter Nos. 1, 2 and 3
 
Castle Dale, UT
 
Coal
 
1978-1983
 
1,336
 
 
1,137
 
Huntington
 
Huntington, UT
 
Coal
 
1974-1977
 
911
 
 
911
 
Dave Johnston
 
Glenrock, WY
 
Coal
 
1959-1972
 
762
 
 
762
 
Naughton
 
Kemmerer, WY
 
Coal
 
1963-1971
 
700
 
 
700
 
Cholla No. 4
 
Joseph City, AZ
 
Coal
 
1981
 
395
 
 
395
 
Wyodak
 
Gillette, WY
 
Coal
 
1978
 
335
 
 
268
 
Carbon
 
Castle Gate, UT
 
Coal
 
1954-1957
 
172
 
 
172
 
Craig Nos. 1 and 2
 
Craig, CO
 
Coal
 
1979-1980
 
856
 
 
165
 
Colstrip Nos. 3 and 4
 
Colstrip, MT
 
Coal
 
1984-1986
 
1,480
 
 
148
 
Hayden Nos. 1 and 2
 
Hayden, CO
 
Coal
 
1965-1976
 
446
 
 
78
 
 
 
 
 
 
 
 
 
9,511
 
 
6,148
 
NATURAL GAS:
 
 
 
 
 
 
 
 
 
 
Lake Side
 
Vineyard, UT
 
Natural gas/steam
 
2007
 
558
 
 
558
 
Currant Creek
 
Mona, UT
 
Natural gas/steam
 
2005-2006
 
550
 
 
550
 
Chehalis
 
Chehalis, WA
 
Natural gas/steam
 
2003
 
520
 
 
520
 
Hermiston
 
Hermiston, OR
 
Natural gas/steam
 
1996
 
474
 
 
237
 
Gadsby Steam
 
Salt Lake City, UT
 
Natural gas
 
1951-1955
 
231
 
 
231
 
Gadsby Peakers
 
Salt Lake City, UT
 
Natural gas
 
2002
 
120
 
 
120
 
Little Mountain
 
Ogden, UT
 
Natural gas
 
1971
 
14
 
 
14
 
 
 
 
 
 
 
 
 
2,467
 
 
2,230
 
HYDROELECTRIC: (2)
 
 
 
 
 
 
 
 
 
 
Lewis River System (3)
 
WA
 
Hydroelectric
 
1931-1958
 
578
 
 
578
 
North Umpqua River System (4)
 
OR
 
Hydroelectric
 
1950-1956
 
200
 
 
200
 
Klamath River System (5)
 
CA, OR
 
Hydroelectric
 
1903-1962
 
170
 
 
170
 
Bear River System (6)
 
ID, UT
 
Hydroelectric
 
1908-1984
 
105
 
 
105
 
Rogue River System (7)
 
OR
 
Hydroelectric
 
1912-1957
 
52
 
 
52
 
Minor hydroelectric facilities
 
Various
 
Hydroelectric
 
1895-1986
 
52
 
 
52
 
 
 
 
 
 
 
 
 
1,157
 
 
1,157
 
WIND: (2)
 
 
 
 
 
 
 
 
 
 
Marengo
 
Dayton, WA
 
Wind
 
2007
 
140
 
 
140
 
Dunlap Ranch I
 
Medicine Bow, WY
 
Wind
 
2010
 
111
 
 
111
 
Leaning Juniper 1
 
Arlington, OR
 
Wind
 
2006
 
101
 
 
101
 
High Plains
 
McFadden, WY
 
Wind
 
2009
 
99
 
 
99
 
Rolling Hills
 
Glenrock, WY
 
Wind
 
2009
 
99
 
 
99
 
Glenrock
 
Glenrock, WY
 
Wind
 
2008
 
99
 
 
99
 
Seven Mile Hill
 
Medicine Bow, WY
 
Wind
 
2008
 
99
 
 
99
 
Goodnoe Hills
 
Goldendale, WA
 
Wind
 
2008
 
94
 
 
94
 
Marengo II
 
Dayton, WA
 
Wind
 
2008
 
70
 
 
70
 
Foote Creek
 
Arlington, WY
 
Wind
 
1999
 
41
 
 
33
 
Glenrock III
 
Glenrock, WY
 
Wind
 
2009
 
39
 
 
39
 
McFadden Ridge I
 
McFadden, WY
 
Wind
 
2009
 
28
 
 
28
 
Seven Mile Hill II
 
Medicine Bow, WY
 
Wind
 
2008
 
20
 
 
20
 
 
 
 
 
 
 
 
 
1,040
 
 
1,032
 
OTHER: (2)
 
 
 
 
 
 
 
 
 
 
Blundell
 
Milford, UT
 
Geothermal
 
1984, 2007
 
34
 
 
34
 
Camas Co-Gen
 
Camas, WA
 
Black liquor
 
1996
 
22
 
 
22
 
 
 
 
 
 
 
 
 
56
 
 
56
 
Total available generating capacity
 
 
 
 
 
 
 
14,231
 
 
10,623
 

9

 

 
(1)    
Facility net capacity represents (except for wind-powered generating facilities, which are nominal ratings) the total capability of a generating unit as demonstrated by actual operating or test experience less power generated and used for auxiliaries and other station uses, and is determined using average annual temperatures. A wind turbine generator's nominal rating is the manufacturer's contractually specified capability (in MW) under specified conditions. Net owned capacity indicates PacifiCorp's ownership of Facility Net Capacity.
(2)    
All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with renewable portfolio standards ("RPS") or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.
(3)    
The license for these facilities is valid through May 2058.
(4)    
The license for these facilities is valid through October 2038.
(5)    
The license for these facilities was valid through February 2006, and they currently operate on annual licenses. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for an update regarding hydroelectric relicensing for the Klamath River system.
(6)    
The license is valid through March 2024 for Cutler and through November 2033 for the Grace, Oneida and Soda hydroelectric generating facilities.
(7)    
The license is valid through December 2018 for Prospect No. 3 and through March 2038 for the Prospect Nos. 1, 2 and 4 hydroelectric generating facilities.
The following table shows the percentages of PacifiCorp's total energy supplied by energy source for the years ended December 31:
 
 
2010
 
2009
 
2008
 
 
 
 
 
 
 
 
Coal
62
 
%
63
 
%
65
 
%
Natural gas
12
 
 
12
 
 
12
 
 
Hydroelectric
5
 
 
5
 
 
5
 
 
Other(1)
5
 
 
4
 
 
2
 
 
Total energy generated
84
 
 
84
 
 
84
 
 
Energy purchased - short-term contracts and other
8
 
 
10
 
 
11
 
 
Energy purchased - long-term contracts
8
 
 
6
 
 
5
 
 
 
100
 
%
100
 
%
100
 
%
 
(1)    
All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.
 
Coal
 
PacifiCorp has interests in coal mines that support its coal-fired generating facilities. These mines supplied 29% of PacifiCorp's total coal requirements during the year ended December 31, 2010 and 31% in each of the years ended December 31, 2009 and 2008. The remaining coal requirements are acquired through long- and short-term third-party contracts. PacifiCorp's mines are located adjacent to certain of its coal-fired generating facilities, which significantly reduces overall transportation costs included in fuel expense. 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 multi-year terms that may be renewed or extended only with the consent of the lessor and require payment of rents and royalties. In addition, federal and state regulations require that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities.

10

 

 
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 as of December 31, 2010, based on PacifiCorp's most recent engineering studies, were as follows (in millions):
 
Coal Mine
 
Location
 
Generating Facility Served
 
Mining Method
 
Recoverable Tons
 
 
 
 
 
 
 
 
 
 
 
Bridger
 
Rock Springs, WY
 
Jim Bridger
 
Surface
 
51
 
(1
)
Bridger
 
Rock Springs, WY
 
Jim Bridger
 
Underground
 
43
 
(1
)
Deer Creek
 
Huntington, UT
 
Huntington, Hunter and Carbon
 
Underground
 
35
 
(2
)
Trapper
 
Craig, CO
 
Craig
 
Surface
 
46
 
(3
)
 
 
 
 
 
 
 
 
175
 
 
 
(1)    
These coal reserves are leased and mined by Bridger Coal Company, ("Bridger Coal") a joint venture between Pacific Minerals, Inc. ("PMI") and a subsidiary of Idaho Power Company. PMI, a wholly owned subsidiary of PacifiCorp, has a two-thirds interest in the joint venture. The amounts included above represent only PacifiCorp's two-thirds interest in the coal reserves.
(2)    
These coal reserves are leased by PacifiCorp and mined by a wholly owned subsidiary of PacifiCorp.
(3)    
These coal reserves are leased and mined by Trapper Mining, Inc., a Delaware non-stock corporation operated on a cooperative basis, in which PacifiCorp has an ownership interest of 21%. The amount included above represents only PacifiCorp's 21% interest in the coal reserves. PacifiCorp does not operate the Trapper Mine.
For surface mine operations, PacifiCorp removes the overburden with heavy earth-moving equipment, such as draglines and power shovels. Once exposed, PacifiCorp drills, fractures and systematically removes the coal using haul trucks or conveyors to transport the coal to the associated generating facility. PacifiCorp reclaims disturbed areas as part of its normal mining activities. After final coal removal, draglines, power shovels, excavators or loaders are used to backfill the remaining pits with the overburden removed at the beginning of the process. Once the overburden and topsoil have been replaced, vegetation and plant life are re-established, and other improvements are made that have local community and environmental benefits. Draglines are used at the Bridger surface mine and draglines with shovels and trucks are used at the Trapper surface mine.
 
For underground mine operations, a longwall is used as a mechanical shearer to extract coal from long rectangular blocks of medium to thick seams. In longwall mining, PacifiCorp also uses continuous miners to develop access to these long rectangular coal blocks. Hydraulically powered supports temporarily hold up the roof of the mine while a rotating drum mechanically advances across the face of the coal seam, cutting the coal from the face. Chain conveyors then move the loosened coal to an underground mine conveyor system for delivery to the surface. Once coal is extracted from an area, the roof is allowed to collapse in a controlled fashion.
 
PacifiCorp operates the Deer Creek, Bridger surface and Bridger underground coal mines, as well as the Cottonwood Preparatory Plant and Wyodak Coal Crushing Facility. Refer to Item 9B of this Form 10-K for further information about the coal mines and coal processing facilities that PacifiCorp operates.
 
Recoverability by surface mining methods typically ranges from 90% to 95%. Recoverability by underground mining techniques ranges from 50% to 70%. To meet applicable standards, PacifiCorp blends coal mined at its owned mines with contracted coal and utilizes emissions reduction technologies for controlling sulfur dioxide and other emissions. For fuel needs at PacifiCorp's coal-fired generating facilities in excess of coal reserves available, PacifiCorp believes it will be able to purchase coal under both long- and short-term contracts to supply its generating facilities with coal over their currently expected remaining useful lives.
 
During the year ended December 31, 2010, PacifiCorp-owned coal-fired generating facilities held sufficient sulfur dioxide emission allowances to comply with the United States Environmental Protection Agency ("EPA") Title IV requirements.
 

11

 

Natural Gas
 
PacifiCorp uses natural gas as fuel for its combined- and simple-cycle natural gas-fired generating facilities. Oil and natural gas are also used for igniter fuel and to fuel generation for transmission support and standby purposes. These sources are presently in adequate supply and available to meet PacifiCorp's needs.
 
PacifiCorp enters into forward natural gas purchases at fixed or floating market prices for physical delivery to fuel its natural gas-fired generating facilities. PacifiCorp utilizes swap contracts to mitigate its price risk and lock in the cost of its forecasted fuel requirements. PacifiCorp also purchases natural gas in the spot market for physical delivery to fulfill any fuel requirements not already satisfied through forward purchases of natural gas and sells natural gas in the spot market for the disposition of any excess supply if the forecasted requirements of its natural gas-fired generating facilities decrease.
 
Hydroelectric
 
The amount of electricity PacifiCorp is able to generate from its hydroelectric facilities depends on a number of factors, including snowpack in the mountains upstream of its hydroelectric facilities, reservoir storage, precipitation in its watersheds, generating unit availability and restrictions imposed by oversight bodies due to competing water management objectives.
 
PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses from the Federal Energy Regulatory Commission ("FERC") with terms of 30 to 50 years, while some are licensed under the Oregon Hydroelectric Act. For further discussion of PacifiCorp's hydroelectric relicensing and decommissioning activities, including updated information regarding the Klamath hydroelectric system, refer to "Hydroelectric Relicensing" and "Hydroelectric Decommissioning" below and Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
 
Wind and Other Renewable Resources
 
PacifiCorp has pursued additional renewable resources as a viable, economical and environmentally prudent means of supplying electricity. Renewable resources have low to no emissions, require little or no fossil fuel and are complemented by PacifiCorp's other generating facilities and wholesale transactions. PacifiCorp's wind-powered generating facilities placed in service by December 31, 2012 are eligible for federal renewable electricity production tax credits for 10 years from the date the facilities were placed in service.
 
Wholesale Activities
 
PacifiCorp purchases and sells electricity in the wholesale markets as needed to balance its generation and long-term purchase commitments with its retail load and long-term wholesale sales obligations. PacifiCorp may also purchase electricity in the wholesale markets when it is more economical than generating electricity from its own facilities. PacifiCorp utilizes both swaps and fixed-price electricity purchase contracts to reduce its exposure to electricity price volatility.
 
Transmission and Distribution
 
PacifiCorp operates one balancing authority area in the western portion of its service territory and one balancing authority area in the eastern portion of its service territory. A balancing authority area is a geographic area with transmission systems that control generation to maintain schedules with other balancing authority areas and ensure reliable operations. In operating the balancing authority areas, PacifiCorp is responsible for continuously balancing electricity supply and demand by dispatching generating resources and interchange transactions so that generation internal to the balancing authority area, plus net imported power, matches customer loads. PacifiCorp also schedules deliveries of energy over its transmission system in accordance with FERC requirements.
 
PacifiCorp's transmission system is part of the Western Interconnection, the regional grid in the western United States. The Western Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico that make up the Western Electricity Coordinating Council ("WECC"). The map under "Service Territories" above shows PacifiCorp's primary transmission system.
 

12

 

As of December 31, 2010, PacifiCorp owned, or participated in, a transmission system consisting of approximately:
 
Nominal Voltage
 
 
(in kilovolts)
 
 
Transmission Lines
 
Miles(1)
500
 
700
 
345
 
2,400
 
230
 
3,300
 
161
 
300
 
138
 
2,200
 
46 to 115
 
7,300
 
 
 
16,200
 
 
(1)    
Includes PacifiCorp's share of jointly owned lines.
 
PacifiCorp's transmission and distribution system included approximately 900 substations as of December 31, 2010. 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.
 
PacifiCorp's Energy Gateway Transmission Expansion Program represents plans to build approximately 2,000 miles of new high-voltage transmission lines, with an estimated cost exceeding $6 billion, primarily in Wyoming, Utah, Idaho and Oregon. The plan includes several transmission line segments that will: (a) address customer load growth; (b) improve system reliability; (c) reduce transmission system constraints; (d) provide access to diverse generation resources, including renewable resources; and (e) improve the flow of electricity throughout PacifiCorp's six-state service area. Proposed transmission line segments are re-evaluated to ensure optimal benefits and timing before committing to move forward with permitting and construction. The Populus to Terminal transmission line, the first major transmission segment associated with this plan, was substantially completed in the fourth quarter of 2010. Other segments are expected to be placed in service through 2019, depending on siting, permitting and construction schedules.
 
Substantially all of PacifiCorp's generating facilities are managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions of PacifiCorp's 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 termination;
•    
Under or over private property as a result of easements obtained primarily from the record holder of title; or
•    
Under or over Native American reservations under grant of easement by the United States 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 to mortgages or liens existing at the time the easements were acquired.
 

13

 

Future Generation and Conservation
 
Integrated Resource Plan
 
As required by certain state regulations, PacifiCorp uses an Integrated Resource Plan ("IRP") 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. The IRP process identifies the amount and timing of PacifiCorp's expected future resource needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts, state energy policies and other factors. The IRP is a coordinated effort with stakeholders in each of the six states where PacifiCorp operates. PacifiCorp files its IRP on a biennial basis and receives a formal notification in four states as to whether the IRP meets the commission's IRP standards and guidelines. In May 2009, PacifiCorp filed its 2008 IRP with each of its state commissions. During 2009, PacifiCorp received orders from the WUTC and the Idaho Public Utilities Commission ("IPUC") acknowledging that the 2008 IRP met their applicable standards and guidelines. During 2010, the Oregon Public Utility Commission ("OPUC") and the Utah Public Service Commission ("UPSC") issued orders acknowledging the 2008 IRP.
 
Requests for Proposals
 
PacifiCorp has issued a series of individual Requests for Proposals ("RFPs"), each of which focuses on a specific category of electric generation resources consistent with the IRP. The IRP and the RFPs provide for the identification and staged procurement of resources in future years to achieve a balance of load requirements and resources. As required by applicable laws and regulations, PacifiCorp files draft RFPs with the UPSC, the OPUC and the Washington Utilities and Transportation Commission ("WUTC") prior to issuance to the market. Approval by the UPSC, the OPUC or the WUTC may be required depending on the nature of the RFPs.
 
In August 2009, under PacifiCorp's 2008R-1 renewable resources RFP (approved by the OPUC in September 2008), PacifiCorp executed a power purchase agreement to purchase the entire output of the 200-MW Top of the World wind-powered generating facility located in Wyoming and the associated renewable energy credits. The generating facility reached commercial operation in October 2010, and the power purchase agreement will continue for a period of 20 years. PacifiCorp's 2009R renewable resources RFP (approved by the OPUC with modification in July 2009) seeks additional cost-effective renewable generation projects with no single resource greater than 300 MW, combined total resources of no more than 400 MW and on-line dates no later than December 31, 2012. As a result of the 2009R renewable resources RFP, PacifiCorp's 111-MW Dunlap Ranch I wind-powered generating facility located in Wyoming was constructed and placed in service in October 2010.
 
In October 2009, PacifiCorp filed a request for approval with the UPSC to re-issue the All Source RFP, which was previously suspended in April 2009. In October 2009 and November 2009, respectively, the UPSC and the OPUC approved resumption of the All Source RFP. The All Source RFP seeks up to 1,500 MW on a system wide basis from projects with in-service dates from 2014 through 2016. In December 2009, the All Source RFP was issued to the market. As a result, PacifiCorp signed an engineer, procure and construct contract, subject to regulatory approval, for the approximately 637-MW Lake Side 2 natural gas-fired combined-cycle generating facility. The Lake Side 2 generating facility will be constructed adjacent to PacifiCorp's Lake Side generating facility, which is located in Vineyard, Utah, about 40 miles south of Salt Lake City. PacifiCorp expects that the UPSC will issue an order approving the construction of Lake Side 2 by May 2011.
 

14

 

Demand-side Management
 
PacifiCorp has provided a comprehensive set of demand-side management ("DSM") programs to its customers since the 1970s. The programs are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, PacifiCorp offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to solicit participation in load management programs by residential, business and agricultural customers through programs, such as PacifiCorp's residential and small commercial air conditioner load control program and irrigation equipment load control programs. Although subject to prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for the DSM programs through state-specific energy efficiency surcharges to retail customers or for recovery of costs through rates. In addition to these DSM programs, PacifiCorp has load curtailment contracts with a number of large industrial customers that deliver up to 305 MW of load reduction when needed. Recovery for the costs associated with the large industrial load management program is determined through PacifiCorp's general rate case process. During 2010, $113 million was expended on PacifiCorp's DSM programs, resulting in an estimated 499,054 megawatt hours ("MWh") of first-year energy savings and an estimated 481 MW of peak load management. Total demand-side load available for control during 2010, including both load management from the large industrial curtailment contracts and DSM programs, was 718 MW.
 
General Regulation
 
PacifiCorp is subject to comprehensive governmental regulation, which significantly influences its operating environment, prices charged to customers, capital structure, costs and ability to recover costs. In addition to the following discussion, refer to "Liquidity and Capital Resources" in Item 7 and Note 5 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
 
State Regulation
 
PacifiCorp pursues a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs. Historically, state regulatory commissions have established rates on a cost-of-service basis, which are designed to allow a utility an opportunity to recover its costs of providing services and to earn a reasonable return on its investments. A utility's cost of service generally reflects its allowed operating expenses, including energy costs, operation and maintenance expense, depreciation expense and income and other tax expense, reduced by wholesale electricity sales and other revenue. The allowed operating expenses are typically based on estimates of normalized costs, which may differ from realized costs in a given year covered by the established rates. State regulatory commissions may adjust rates pursuant to a review of (a) the utility's revenue and expenses during a defined test period and (b) the utility's level of investment. State regulatory commissions typically have the authority to review and change rates on their own initiative; however, they may also initiate reviews at the request of a utility, utility customer, a governmental agency or a representative of a group of customers. The utility and such parties, however, may agree with one another not to request a review of or changes to rates for a specified period of time.
 
PacifiCorp's retail rates are generally based on the cost of providing traditional bundled services, including generation, transmission and distribution services. Historically, the state regulatory framework in PacifiCorp's service areas reflect specified net power costs as part of bundled retail rates or incorporated net power cost adjustment clauses in PacifiCorp's retail rates and tariffs. In states where net power cost adjustment clauses exist, permitted periodic adjustments to cost recovery from customers provide protection to PacifiCorp against exposure to changes in net power costs.
 
Except for Oregon and Washington, PacifiCorp has an exclusive right to serve customers within its service territories, and in turn, has the obligation to provide electric service to those customers within its allocated service territory. Under Oregon law, PacifiCorp has the exclusive right and obligation to provide electric distribution services to all customers within its allocated service territory; however, nonresidential customers have the right to choose alternative electricity service suppliers. The impact of these programs on PacifiCorp's consolidated financial results has not been material. In Washington, state law does not provide for exclusive service territory allocation. PacifiCorp's service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered into service area agreements under the jurisdiction of the WUTC.

15

 

 
In addition to recovery through rates, PacifiCorp also achieves recovery of certain costs through various adjustment mechanisms as summarized below.
 
State Regulator
 
Base Rate Test Period
 
Adjustment Mechanism
 
 
 
 
 
Utah Public Service Commission
 
Forecasted or historical with known and measurable changes (1)
 
PacifiCorp has requested approval of an energy cost adjustment mechanism ("ECAM") to recover the difference between base net power costs set during a general rate case and actual net power costs.
 
A recovery mechanism is available for a single capital investment project that in total exceeds 1% of existing rate base when a general rate case has occurred within the preceding 18 months.
 
Oregon Public Utility Commission
 
Forecasted
 
Annual transition adjustment mechanism ("TAM") based on forecasted net variable power costs; no true-up to actual net variable power costs.
 
 
 
 
Renewable adjustment clause ("RAC") to recover the revenue requirement of new renewable resources and associated transmission that are not reflected in general rates.
 
 
 
 
Annual true-up of taxes authorized to be collected in rates compared to taxes paid by PacifiCorp, as defined by Oregon statute and administrative rules under Oregon Senate Bill 408 ("SB 408").
Wyoming Public Service Commission ("WPSC")
 
Forecasted or historical with known and measurable changes (1)
 
ECAM under which 70% of any difference between actual and forecasted net power costs established in a general rate case would be subject to the ECAM mechanism between general rate cases.
Washington Utilities and Transportation Commission
 
Historical with known and measurable changes
 
Deferral mechanism of costs for up to 24 months of new base load generation resources and eligible renewable resources and related transmission that qualify under the state's emissions performance standard and are not reflected in general rates.
Idaho Public Utilities Commission
 
Historical with known and measurable changes
 
ECAM to recover the difference between base net power costs set during a general rate case and actual net power costs, subject to customer sharing and other adjustments.
California Public Utilities Commission ("CPUC")
 
Forecasted
 
Post test-year adjustment mechanism for major capital additions ("PTAM - capital additions") that allows for rate adjustments outside of the context of a traditional general rate case for the revenue requirement associated with capital additions exceeding $50 million on a total-company basis. Filed as eligible capital additions are placed into service.
 
 
 
 
Energy cost adjustment clause ("ECAC") that allows for an annual update to actual and forecasted net variable power costs.
 
 
 
 
Post test-year adjustment mechanism for attrition ("PTAM - attrition"), a mechanism that allows for an annual adjustment to costs other than net variable power costs.
 
(1)    
PacifiCorp has relied on both historical test periods with known and measurable adjustments, as well as forecasted test periods.
 
PacifiCorp's DSM program costs are collected through separately established rates that are adjusted periodically based on actual and expected costs, as approved by the respective state regulatory commission. As such, recovery of DSM program costs has no impact on net income.
 
Federal Regulation
 
The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Energy Policy Act of 2005 ("Energy Policy Act") and other federal statutes. The FERC regulates rates for wholesale sales of electricity; transmission of electricity, including pricing and regional planning for the expansion of transmission systems; electric system reliability; utility holding companies; accounting; securities issuances; and other matters, including construction and operation of hydroelectric facilities. The FERC also has the enforcement authority to assess civil penalties of up to $1 million per day per violation of rules, regulations and orders issued under the Federal Power Act. PacifiCorp has implemented programs that facilitate compliance with the FERC regulations described below, including having instituted compliance monitoring procedures.
 

16

 

Wholesale Electricity and Capacity
 
The FERC regulates PacifiCorp's rates charged to wholesale customers for electricity and transmission capacity and related services. Most of PacifiCorp's wholesale electricity sales and purchases take place under market-based pricing allowed by the FERC and are therefore subject to market volatility.
 
The FERC conducts triennial reviews of PacifiCorp's market-based pricing authority. PacifiCorp must demonstrate the lack of market power in order to charge market-based rates for sales of wholesale electricity and electric generation capacity in its market areas. PacifiCorp's most recent triennial filing was made in June 2010 and is currently pending before the FERC, while its next triennial filing is due in June 2013. Under the FERC's market-based rules, PacifiCorp must also file a notice of change in status when there is a significant change in the conditions that the FERC relied upon in granting market-based pricing authority. PacifiCorp is currently authorized to sell electricity on the wholesale market at market-based rates.
 
Transmission
 
PacifiCorp's wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp's Open Access Transmission Tariff ("OATT"). In accordance with its OATT, PacifiCorp offers several transmission services to wholesale customers:
 
•    
Network transmission service (service that integrates generating resources to serve retail loads);
 
•    
Long- and short-term firm point-to-point transmission service (service with fixed delivery and receipt points); and
 
•    
Non-firm point-to-point service (service with fixed delivery and receipt points on an as available basis).
 
These services are offered on a non-discriminatory basis, which means that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp's transmission business is managed and operated independently from its commercial and trading business, in accordance with the FERC rules. PacifiCorp has made several required compliance filings in accordance with these rules.
 
FERC Reliability Standards
The FERC has approved an extensive number of reliability standards developed by the North American Electric Reliability Corporation ("NERC") and the WECC, including critical infrastructure protection standards and regional standard variations. PacifiCorp must comply with all applicable standards. Compliance, enforcement and monitoring oversight of these standards is carried out by the FERC, the NERC and the WECC. In 2007, the WECC audited PacifiCorp's compliance with several of the approved reliability standards, and in November 2008, the FERC assumed control of certain aspects of the WECC's audit. In May 2009, PacifiCorp received a notice of alleged violation and proposed sanctions related to the portions of the WECC's 2007 audit that remained with the WECC. In July 2009, PacifiCorp reached a settlement with the WECC. The results of the settlement did not have a material impact on PacifiCorp's consolidated financial results. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding certain aspects of the WECC's 2007 audit currently under the FERC's authority and the FERC's reliability standards review.
 
Hydroelectric Relicensing
 
PacifiCorp's Klamath hydroelectric system is the only significant hydroelectric generating facility for which PacifiCorp is engaged in the relicensing process with the FERC. PacifiCorp also has requested the FERC to allow decommissioning of certain hydroelectric systems. Most of PacifiCorp's hydroelectric generating facilities are licensed by the FERC as major systems under the Federal Power Act, and certain of these systems are licensed under the Oregon Hydroelectric Act. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for an update regarding hydroelectric relicensing for PacifiCorp's Klamath hydroelectric system.

17

 

Hydroelectric Decommissioning
    
Powerdale Hydroelectric Facility - Hood River, Oregon
 
In June 2003, PacifiCorp entered into a settlement agreement to decommission the 6-MW Powerdale hydroelectric facility rather than pursue a new license, based on an analysis of the costs and benefits of relicensing versus decommissioning. In 2007, the FERC authorized PacifiCorp to cease generation at the facility and approved PacifiCorp's proposed accounting entries to defer the remaining net book value and any additional removal costs of the system as a regulatory asset. PacifiCorp received approval from its state regulatory commissions to defer and recover these costs. In April 2010, PacifiCorp initiated removal of the Powerdale dam and associated system features as stipulated in the FERC Surrender Order. As of October 31, 2010, decommissioning activities, including dam removal and site restoration, were completed. PacifiCorp will monitor restored areas until early 2012 when the project land is expected to be transferred to the Columbia Land Trust, Oregon Department of Fish and Wildlife and Hood River County. Removal costs for the Powerdale dam and associated system features were approximately $4 million, and additional monitoring costs are not expected to exceed $1 million.
 
Condit Hydroelectric Facility - White Salmon River, Washington
 
In September 1999, a settlement agreement to remove the 14-MW Condit hydroelectric facility was signed by PacifiCorp, state and federal agencies and non-governmental organizations. In early February 2005, the parties agreed to modify the settlement agreement, establishing a total cost to decommission not to exceed $21 million, excluding inflation. In October 2010, the Washington Department of Ecology issued a Clean Water Act 401 certificate, and in December 2010, the FERC issued a surrender order. In January 2011, PacifiCorp filed a request for clarification and rehearing and motion for stay with the FERC. Remaining permitting includes a Section 404 permit from the United States Army Corps of Engineers. Decommissioning is expected to begin no earlier than October 2011.
 
Northwest Refund Case
 
For a discussion of the Northwest Refund case, refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
 
United States Mine Safety
PacifiCorp's mining operations are regulated by the federal Mine Safety and Health Administration ("MSHA"), which administers federal mine safety and health laws and regulations, and state regulatory agencies. MSHA has the statutory authority to institute a civil action for relief, including a temporary or permanent injunction, restraining order or other appropriate order against a mine operator who fails to pay penalties or fines for violations of federal mine safety standards. Federal law requires PacifiCorp to have a written emergency response plan specific to each underground mine it operates, which is reviewed by MSHA every six months, and to have at least two rescue teams located within one hour of each mine. Refer to Item 9B of this Form 10-K for further information regarding the coal mine and coal processing facilities that PacifiCorp operates.
 
Environmental Laws and Regulations
 
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproducts, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various other state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
 
Refer to "Liquidity and Capital Resources" in Item 7 of this Form 10-K for additional information regarding environmental laws and regulations and PacifiCorp's forecasted environmental-related capital expenditures.
 

18

 

Item 1A.      Risk Factors
 
We are subject to certain risks and uncertainties in our business operations, including, but not limited to, those described below. Careful consideration of these risks, together with all of the other information included in this Form 10-K and the other public information filed by us, should be made before making an investment decision. Additional risks and uncertainties not presently known or that are currently deemed immaterial may also impair our business operations.
 
Our Corporate and Financial Structure Risks
 
We have a substantial amount of debt, which could adversely affect our consolidated financial results.
 
As of December 31, 2010, we had $6.380 billion in total debt securities outstanding. Our principal financing agreements contain restrictive covenants that limit our ability to borrow funds, and any issuance of debt securities requires prior authorization from certain of our state regulatory commissions. We expect that we may 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, we may postpone planned capital expenditures, or take other actions, to the extent those expenditures are not fully covered by cash from operations, borrowings under committed credit facilities or equity contributions from MEHC.
 
A downgrade in our credit ratings could negatively affect our access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.
 
Our long-term debt and preferred stock are rated investment grade by various rating agencies. We cannot assure that our long-term debt and preferred stock will continue to be rated investment grade in the future. Although none of our outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase our borrowing costs and commitment fees on our revolving credit agreements and other financing arrangements, perhaps significantly. In addition, we would likely be required to pay a higher interest rate in future financings, and the potential pool of investors and funding sources would likely decrease. Further, access to the commercial paper market, the principal source of short-term borrowings, could be significantly limited, resulting in higher interest costs.
 
Most of our large wholesale customers, suppliers and counterparties require us to have sufficient creditworthiness in order to enter into transactions with them, particularly in the wholesale energy markets. If our credit ratings were to decline, especially below investment grade, financing costs and borrowings would likely increase because certain counterparties may require collateral in the form of cash, a letter of credit or some other security for existing transactions, as well as a condition to further transact with us. Such amounts may be material and may adversely affect our liquidity and cash flows.
 
MEHC could exercise control over us in a manner that would benefit MEHC to the detriment of our creditors and preferred stockholders.
 
MEHC, through its subsidiary, owns all of our common stock and has control over all decisions requiring shareholder approval, including the election of our directors. In circumstances involving a conflict of interest between MEHC and our creditors and preferred stockholders, MEHC could exercise its control in a manner that would benefit MEHC to the detriment of our creditors and preferred stockholders.
 
Our Business Risks
 
We are subject to extensive federal, state and local legislation and regulation, including numerous environmental, health, safety and other laws and regulations that affect our operations and costs. These laws and regulations are complex, dynamic and subject to new interpretations or change. In addition, new laws and regulations are continually being proposed and enacted that create new or revised requirements or standards on our business.
 
We are required to comply with numerous federal, state and local laws and regulations that have broad application to our business and limit our ability to independently make and implement management decisions regarding, among other items, business combinations; constructing, acquiring or disposing of operating assets; operation of generating facilities and transmission and distribution assets; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; transactions with affiliates; and paying dividends. These laws and regulations are implemented and enforced by federal, state and local regulatory agencies, such as, among others, the FERC, the EPA, MSHA and the OPUC.
 

19

 

Significant examples of laws and regulations and other requirements affecting our present and future operations include, among others, those described below:
 
•    
Under authority granted to it in the Energy Policy Act, the FERC has approved regulations and issued decisions addressing electric system reliability; cyber security; critical infrastructure protection standards developed by the NERC; electric transmission planning, operation, expansion and pricing; regulation of utility holdings companies; and enforcement authority. The FERC has vigorously exercised its enhanced enforcement authority by imposing significant civil penalties for violations of its rules and regulations, which could be up to $1 million per day per violation. These regulations have imposed, or will likely impose, more comprehensive and stringent requirements and increase our compliance costs, which could adversely affect our consolidated financial results.
•    
In July 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Reform Act"). The Dodd-Frank Reform Act reshapes financial regulation in the United States by creating new regulators, regulating new markets and firms and providing new enforcement powers to regulators. Virtually all major areas of the Dodd-Frank Reform Act, including collateral requirements on derivative contracts, will be the subject of regulatory interpretation and implementation rules requiring rulemaking proceedings that may take several years to complete. The outcome of the rulemaking proceedings cannot be predicted at this time; however, the impact of the Dodd-Frank Reform Act could have a material adverse effect on our consolidated financial results.
•    
The EPA's Clean Air Interstate Rule, which established cap-and-trade programs to reduce carbon dioxide and nitrogen oxides emissions starting in 2009 to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards; federal and state renewable portfolio standards; and regulations that establish standards for air and water quality, wastewater discharges, solid waste, hazardous waste and coal combustion byproducts.
•    
Federal laws establishing underground coal mine safety, emergency preparedness and reporting, such as the Mine Improvement and New Emergency Response Act of 2006 ("MINER Act") and those laws administered by MSHA.
•    
Hydroelectric relicensing with the FERC is a public regulatory process involving sensitive resource issues and uncertainties. We cannot predict with certainty whether the outcome of our settlement agreement with relicensing stakeholders for our Klamath hydroelectric system will result in dam transfer and removal by a third party, nor can we predict the requirements (financial, operational or otherwise) that may be imposed by relicensing, the economic impact of those requirements, and whether new licenses will ultimately be issued or whether we will be willing to meet the relicensing requirements to continue operating our hydroelectric generating facilities. Loss of hydroelectric resources or additional commitments arising from relicensing could adversely affect our consolidated financial results.
Compliance with applicable laws and regulations generally requires us to obtain and comply with a wide variety of licenses, permits, inspections and other approvals. Further, compliance with laws and regulations can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, damages arising out of contaminated properties and fines, penalties and injunctive measures affecting operating assets for failure to comply with environmental regulations. Compliance activities pursuant to laws and regulations could be prohibitively expensive. As a result, some facilities may be required to shut down or alter their operations. Further, we may not be able to obtain or maintain all required environmental regulatory approvals for our operating assets or development projects. Delays in or active opposition by third parties to obtaining any required environmental or regulatory permits, failure to comply with the terms and conditions of the permits or increased regulatory or environmental requirements may increase costs or prevent or delay us from operating our facilities, developing new facilities, expanding existing facilities or favorably locating new facilities. If we fail to comply with any environmental requirements, we may be subject to penalties and fines or other sanctions. The costs of complying with laws and regulations could adversely affect our consolidated financial results. Not being able to operate existing facilities or develop new generating facilities to meet customer electricity needs could require us to increase our purchases of electricity on the wholesale market, which could increase market and price risks and adversely affect our consolidated financial results.
 
Existing laws and regulations, while comprehensive, are subject to changes and revisions from ongoing policy initiatives by legislators and regulators and to interpretations that may ultimately be resolved by the courts. For example, changes in law and regulations could result in, but are not limited to, increased retail competition within our service territories; new environmental requirements, including the implementation of renewable portfolio standards and greenhouse gas ("GHG") emissions reduction goals; the issuance of stricter air quality standards and the implementation of energy efficiency mandates; the issuance of regulations over the management and disposal of coal combustion byproducts; the acquisition by a municipality of our distribution facilities; or a negative impact on our cost recovery arrangements.

20

 

 
In addition to changes in existing legislation and regulation, new laws and regulations are likely to be enacted that impose additional or new requirements or standards on our business. For example, the United States Congress and federal policy makers recently considered, but did not adopt, comprehensive climate change legislation. Adoption of new federal and state laws and regulations and changes in existing ones is emerging as one of the more challenging aspects of managing utility operations. We cannot predict the future course of new laws and regulations, changes in existing ones or new interpretations by agency orders or court decisions nor can their impact on us be determined at this time; however, any one of these could adversely affect our consolidated financial results through higher capital expenditures and operating costs and cause an overall change in how we operate our business. To the extent that we are not allowed by regulators to recover or cannot otherwise recover the costs to comply with new laws and regulations or changes in existing ones, the additional requirements could have a material adverse effect on our consolidated financial results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand, this could have a material adverse effect on our consolidated financial results.
 
Recovery of our costs is subject to regulatory review and approval, and the inability to recover costs may adversely affect our consolidated financial results.
 
State Rate Proceedings
 
Rates are established for our regulated retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns, but who generally have the common objective of limiting rate increases. Decisions are subject to appeal, potentially leading to further uncertainty associated with the approval proceedings.
 
Each state sets retail rates based in part upon the state regulatory commission's acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year's realized costs are higher than normalized costs, rates may not be sufficient to cover those costs. Each state regulatory commission generally sets rates based on a test year established in accordance with that commission's policies. The test year data adopted by each state regulatory commission may create a lag between the incurrence of a cost and its recovery in rates. Each state regulatory commission also decides the allowed levels of expense and investment that they deem are just and reasonable in providing the service and may disallow recovery in rates for any costs that do not meet such standard. State regulatory commissions also decide the allowed rate of return we will be given an opportunity to earn on our sources of capital.
 
In certain states, we are not permitted to pass through energy cost increases in our retail rates without a general rate case or are subject to deadbands and sharing mechanisms. Any significant increase in fuel costs for electricity generation or purchased electricity costs could have a negative impact on us, despite efforts to minimize this impact through future general rate cases or the use of hedging contracts. Any of these consequences could adversely affect our consolidated financial results.
 
While rate regulation is premised on providing a fair opportunity to obtain a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that we will be able to realize a reasonable rate of return.
 
FERC Jurisdiction
 
The FERC establishes cost-based rates under which we provide transmission services to wholesale markets and retail markets in states that allow retail competition. Under the Federal Power Act, we may voluntarily file, or may be obligated to file, for changes, including general rate changes, to our system-wide transmission service rates. The FERC also has responsibility for approving both cost- and market-based rates under which we sell electricity at wholesale, has licensing authority over most of our hydroelectric generating facilities and has broad jurisdiction over energy markets. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or revoke or restrict our ability to sell electricity at market-based rates, which could adversely affect our consolidated financial results. The FERC may also impose substantial civil penalties for any non compliance with the Federal Power Act and the FERC's rules and orders.
 

21

 

We are actively pursuing, developing and constructing new or expanded facilities, the completion and expected cost of which are subject to significant risk, and we have significant funding needs related to our planned capital expenditures.
 
We are actively pursuing, developing and constructing new or expanded facilities. We expect that we will incur substantial annual capital expenditures over the next several years. Expenditures could include, among others, amounts for new electric generating facilities, electric transmission or distribution projects, environmental control and compliance systems, as well as the continued maintenance of existing assets.
 
Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, labor and other items over a multi-year construction period, as well as the economic viability of our suppliers. These risks may result in higher than expected costs to complete an asset and place it in service. Such costs may not be recoverable in the rates or market prices we are able to charge our customers. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force reliance on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or to recover any such costs could adversely affect our consolidated financial results.
 
Furthermore, we depend upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If we are unable to obtain funding from internal and external sources, we may need to postpone or cancel planned capital expenditures.
 
Failure to construct our planned projects could limit opportunities for revenue growth, increase operating costs and adversely affect the reliability of electricity service to our customers. For example, if we are not able to expand our existing generating facilities, we may be required to enter into long-term wholesale electricity purchase contracts or purchase wholesale electricity at more volatile and potentially higher prices in the spot markets to support retail loads.
 
A sustained decrease in demand for electricity in the markets served by us would significantly decrease our operating revenue and adversely affect our consolidated financial results.
 
A sustained decrease in demand for electricity in the markets served by us would significantly reduce our operating revenue and adversely affect our consolidated financial results. Factors that could lead to a decrease in market demand include, among others:
 
•    
a depression, recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity, including the significant adverse changes in the economy and credit markets experienced in 2008 and 2009;
•    
an increase in the market price of electricity or a decrease in the price of other competing forms of energy;
•    
efforts by customers, legislators and regulators to reduce the consumption of energy through various conservation and energy efficiency measures and programs;
•    
higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of the fuel source for electricity generation or that limit the use of the generation of electricity from fossil fuels; and
•    
a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise.

22

 

We are subject to market risk associated with the wholesale energy markets, which could adversely affect our consolidated financial results.
 
In general, our primary market risk is the risk of adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas, coal and fuel oil, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. Wholesale electricity may be influenced by several factors, such as the adequacy of generating capacity; scheduled and unscheduled outages of generating facilities; prices and availability of fuel sources for generation; disruptions or constraints to transmission and distribution facilities; weather conditions; economic growth; and changes in technology. Volumetric changes are caused by unanticipated changes in generation availability or changes in customer needs that can be due to the weather, electricity and fuel prices, the economy, regulations or customer behavior. For example, we purchase electricity and fuel in the open market as part of our normal operating business. If market prices rise, especially in a time when larger than expected volumes must be purchased at market or short-term prices, we may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when we are a net seller of electricity in the wholesale market, we will earn less revenue.
 
We are subject to counterparty credit risk, which could adversely affect our consolidated financial results.
 
We are subject to counterparty credit risk related to contractual obligations with wholesale suppliers and customers. Adverse economic conditions or other events affecting counterparties with whom we conduct business could impair the ability of these counterparties to timely pay for services. We depend on these counterparties to remit payments on a timely basis. For example, certain wholesale suppliers and customers experienced deteriorating credit quality in 2008 and 2009, and this trend continued, though on a limited basis, in 2010. If our wholesale customers are unable to pay us for energy, there may be a significant adverse impact on our consolidated financial results.
 
We continue to monitor the creditworthiness of wholesale suppliers and customers in an attempt to reduce the impact of any potential counterparty default. If strategies used to minimize these risk exposures are ineffective or if our wholesale customers' financial condition deteriorates as a result of economic conditions causing them to be unable to pay, significant losses could result.
 
We are subject to counterparty performance risk, which could adversely affect our consolidated financial results.
 
We are subject to counterparty performance risk related to performance of contractual obligations by wholesale suppliers and customers. We rely on wholesale suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require us to incur additional expenses to meet customer needs. In addition, when these contracts terminate, we may be unable to purchase the commodities on terms equivalent to the terms of current contracts.
 
We rely on wholesale customers to take delivery of the energy they have committed to purchase. Failure of customers to take delivery may require us to find other customers to take the energy at lower prices than the original customers committed to pay. At certain times of the year, prices paid by us for energy needed to satisfy our customers' energy needs may exceed the amount we receive through rates. If our wholesale customers are unable to fulfill their obligations, there may be a significant adverse impact on our consolidated financial results.
 
Disruptions in the financial markets could affect our ability to obtain debt financing, draw upon or renew existing credit facilities, and have other adverse effects on us.
 
During 2008 and early 2009, the United States and global credit markets experienced historic dislocations and liquidity disruptions that caused financing to be unavailable in many cases. These circumstances materially impacted liquidity in the bank and debt capital markets during this period, making financing terms less attractive for borrowers that were able to find financing, and in other cases resulted in the unavailability of certain types of debt financing. It is difficult to predict how the financial markets will react to the United States federal government's continued involvement or gradual withdrawal or removal of certain economic stimulus programs. Uncertainty in the credit markets may negatively impact our ability to access funds on favorable terms or at all. If we are unable to access the bank and debt markets to meet liquidity and capital expenditure needs, it may adversely affect the timing and amount of our capital expenditures and our consolidated financial results.
 

23

 

Inflation and changes in commodity prices and fuel transportation costs may adversely affect our consolidated financial results.
 
Inflation may affect our business by increasing both operating and capital costs. As a result of existing rate agreements and competitive price pressures, we may not be able to pass the costs of inflation on to our customers. If we are unable to manage cost increases or pass them on to our customers, our consolidated financial results could be adversely affected.
 
Our consolidated financial results may be adversely affected if we are unable to obtain adequate, reliable and affordable access to electricity transmission service and natural gas transportation.
 
We depend on electricity transmission and natural gas transportation facilities owned and operated by other companies to transport electricity to both wholesale and retail markets and to transport natural gas purchased to supply some of our generating facilities. If adequate transmission and transportation is unavailable, we may be unable to purchase and sell and deliver electricity. A lack of availability could also hinder us from providing adequate or cost-effective electricity to our wholesale and retail customers and could adversely affect our consolidated financial results.
 
The different regional power markets have varying and dynamic regulatory structures, which could affect our growth and performance. In addition, the independent system operators who oversee the transmission systems in certain portions of the regional power markets in which we transact have imposed in the past, and may impose in the future, price limitations and other mechanisms to counter volatility in the power markets. These types of price limitations and other mechanisms may adversely affect our consolidated financial results.
 
Our operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.
 
In the markets in which we operate, demand for electricity peaks during the hot summer months when irrigation and cooling needs are higher. Market prices for electricity also generally peak at that time. In addition, demand for electricity generally peaks during the winter when heating needs are higher. Further, extreme weather conditions, such as heat waves, winter storms or floods could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snowpack may impact electricity generation at our hydroelectric generating facilities, which may result in greater purchases of electricity from the wholesale market or from other sources at market prices. Additionally, we have added substantial wind-powered generation capacity, which is also a climate-dependent resource.
 
As a result, our overall consolidated financial results may fluctuate substantially on a seasonal and quarterly basis. We have historically sold less energy, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect our consolidated financial results through lower revenue or margins. Conversely, unusually extreme weather conditions could increase our costs to provide energy and could adversely affect our consolidated financial results. The extent of fluctuation in our consolidated financial results may change depending on a number of factors related to our regulatory environment and contractual agreements, including our ability to recover energy costs and terms of the wholesale sale contracts.
 
We are subject to operating uncertainties that could adversely affect our consolidated financial results.
 
The operation of complex electric utility (including generation, transmission and distribution) systems that are spread over large geographic areas involves many operating uncertainties and events beyond our control. These potential events include the breakdown or failure of electricity generating equipment, transmission and distribution lines or other equipment or processes; unscheduled generating facility outages; strikes, lockouts or other labor-related actions; shortage of qualified labor; transmission and distribution system constraints or outages; fuel shortages or interruptions; unavailability of critical equipment, materials and supplies; low water flows and other weather-related impacts; performance below expected levels of output, capacity or efficiency; 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. Any of these risks or other operational risks could significantly reduce or eliminate our revenue or significantly increase our expenses. For example, if we cannot operate our generating facilities at full capacity due to damage caused by a catastrophic event, our revenue could decrease and our expenses could increase due to the need to obtain energy from more expensive sources. Further, we self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs and the scope, cost and availability of our insurance coverage may change, including the portion that is self-insured. Any reduction of our revenue or increase in our expenses resulting from the risks described above, could adversely affect our consolidated financial results.
 

24

 

Potential terrorist activities or military or other actions could adversely affect our consolidated financial results.
 
The ongoing threat of terrorism and the impact of military and other actions by the United States and its allies creates increased political, economic and financial market instability, which subjects our operations to increased risks. The United States government has issued warnings that energy assets, specifically including electric utility infrastructure, are potential targets for terrorist organizations. Political, economic or financial market instability or damage to our operating assets or the assets of our customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to electricity and natural gas, increased security, repair or other costs that may materially adversely affect us in ways that cannot be predicted at this time. Any of these risks could materially affect our consolidated financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability to raise capital.
 
Poor performance of plan and fund investments and other factors impacting our pension and other postretirement benefit plans, the joint trust plans to which we contribute and mine reclamation trust funds could unfavorably impact our cash flows and liquidity.
 
Costs of providing our defined benefit pension and other postretirement benefit plans, as well as costs associated with the joint trust plans to which we contribute, depend upon a number of factors, including the rates of return on plan assets, the level and nature of benefits provided, discount rates, the interest rates used to measure required minimum funding levels, changes in benefit design, changes in laws and government regulation and our required or voluntary contributions made to the plans. Our pension and other postretirement benefit plans, as well as certain joint trust plans to which we contribute, are in underfunded positions. Even with sustained growth in the investments over future periods to increase the value of these plans' assets, we will likely be required to make significant cash contributions to fund these plans in the future. Furthermore, the Pension Protection Act of 2006, as amended, may result in more volatility in the amount and timing of future contributions. Similarly, funds dedicated to mine reclamation are invested in equity and fixed-income securities and poor performance of these investments will reduce the amount of funds available for their intended purpose which would require us to make additional cash contributions. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on our liquidity by reducing our cash flows.
 
We are involved in numerous legal proceedings, the outcomes of which are uncertain and could adversely affect our consolidated financial results.
 
We are party to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters. It is possible that the final resolution of some of the matters in which we are involved could result in additional payments in excess of established reserves over an extended period of time and in amounts that could have a material adverse effect on our consolidated financial results. Similarly, it is also possible that the terms of resolution could require that we change business practices and procedures, which could also have a material adverse effect on our consolidated financial results. Further, litigation could result in the imposition of financial penalties or injunctions which could limit our ability to take certain desired actions or the denial of needed permits, licenses or regulatory authority to conduct our business, including the siting or permitting of facilities. Any of these outcomes could adversely affect our consolidated financial results.
 
Potential changes in accounting standards may impact our consolidated financial results and disclosures in the future, which may change the way analysts measure our business or financial performance.
 
The Financial Accounting Standards Board ("FASB") and the SEC continuously make changes to accounting standards and disclosure and other financial reporting requirements. New or revised accounting standards and requirements issued by the FASB or the SEC or new accounting orders issued by the FERC could significantly impact our consolidated financial results and disclosures.
 
Item 1B.      Unresolved Staff Comments
 
None.
 

25

 

Item 2.      Properties
 
PacifiCorp's properties consist of the physical assets necessary to support its electricity business, which include electric generation, transmission and distribution facilities, as well as coal mining assets that support certain of PacifiCorp's electric generating facilities. In addition to these physical assets, PacifiCorp has rights-of-way, mineral rights and water rights that enable PacifiCorp to utilize its facilities. It is the opinion of PacifiCorp's management that the principal depreciable properties owned by PacifiCorp are in good operating condition and are well maintained. Substantially all of PacifiCorp's electric utility properties are subject to the lien of PacifiCorp's Mortgage and Deed of Trust. Refer to Exhibit 4.1 in Item 15 of this Form 10-K. For additional information regarding PacifiCorp's properties, refer to Item 1 of this Form 10-K and Notes 3 and 4 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
 
The right to construct and operate PacifiCorp's electric transmission and distribution facilities across certain property was obtained in most circumstances through negotiations and, where necessary, through the exercise of the power of eminent domain. PacifiCorp continues to have the power of eminent domain in each of the jurisdictions in which it operates, but it does not have the power of eminent domain with respect to Native American tribal lands.
 
With respect to real property, each of the transmission and distribution facilities fall into two basic categories: (a) parcels that are owned in fee, such as certain of PacifiCorp's generating facilities, substations and office sites; and (b) parcels where the interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the transmission and distribution facilities. PacifiCorp believes that it has satisfactory title to all of the real property making up its respective facilities in all material respects.
 
Headquarters/Offices
 
PacifiCorp's corporate offices consist of approximately 800,000 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 million square feet of field office and warehouse space in various other locations in Utah, Oregon, Wyoming, Washington, Idaho and California. The field location square footage does not include offices located at PacifiCorp's generating facilities.
 

26

 

Item 3.      Legal Proceedings
 
PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.
 
In December 2000, Wah Chang, a large industrial customer of PacifiCorp, filed an action before the OPUC asserting that the rates set by a special tariff with PacifiCorp and approved by the OPUC were not just and reasonable due to alleged market manipulation during the energy crisis. In October 2001, the OPUC dismissed Wah Chang's petition and found that Wah Chang assumed the risk of price increases under the special tariff. Wah Chang petitioned the Circuit Court for Marion County, Oregon for review of the OPUC's order. In June 2002, the Circuit Court for Marion County, Oregon, granted Wah Chang's motion for review, and ordered the OPUC to reopen the record to allow Wah Chang the opportunity to present new evidence. In September 2009, the OPUC dismissed Wah Chang's petition and reaffirmed that the rates set by the special tariff were just and reasonable. In October 2009, Wah Chang filed with the Oregon Court of Appeals a petition for judicial review of the OPUC's September 2009 order denying Wah Chang relief. In July 2010, the Oregon Court of Appeals accepted judicial review.
 
In a separate but related proceeding, in December 2000, Wah Chang filed a complaint in the Circuit Court for Linn County, Oregon, asserting that the OPUC-approved special tariff with PacifiCorp is subject to rescission based on theories of mutual mistake of fact, frustration of purpose and impracticability. In August 2002, the Circuit Court for Linn County, Oregon, granted PacifiCorp's motion for summary judgment dismissing Wah Chang's complaint. In February 2004, the Circuit Court for Linn County, Oregon, granted Wah Chang's motion to reopen the case to present additional evidence of alleged market manipulation. In December 2007, Wah Chang filed a second amended complaint seeking recovery of a portion of the costs paid under the special tariff based on various theories of legal relief, including partial rescission, unjust enrichment, and breach of duty of good faith and fair dealing. In August 2009, the Circuit Court for Linn County, Oregon, granted Wah Chang's request to file a third amended complaint containing a claim for punitive damages. The trial date has been set for April 2011. Wah Chang is seeking $37 million (less the amount Wah Chang would have paid for electricity absent the special tariff) in compensatory damages and $200 million in punitive damages. PacifiCorp intends to vigorously defend these claims and believes that the outcome of these proceedings will not have a material impact on its consolidated financial results.
 
In October 2005, PacifiCorp was added as a defendant to a lawsuit originally filed in February 2005 in the Third District Court for Salt Lake County, Utah ("Third District Court") by USA Power, LLC and its affiliated companies, USA Power Partners, LLC and Spring Canyon Energy, LLC (collectively, "USA Power"), against Utah attorney Jody L. Williams and the law firm Holme, Roberts & Owen, LLP, who represent PacifiCorp on various matters from time to time. USA Power was the developer of a planned generation project in Mona, Utah called Spring Canyon, which PacifiCorp, as part of its resource procurement process, at one time considered as an alternative to the Currant Creek generating facility. USA Power's complaint alleged that PacifiCorp misappropriated confidential proprietary information in violation of Utah's Uniform Trade Secrets Act and accused PacifiCorp of breach of contract and related claims. USA Power seeks $250 million in damages, statutory doubling of damages for its trade secrets violation claim, punitive damages, costs and attorneys' fees. The statutory doubling of damages only applies to the plaintiffs' trade secret claim and could increase the total damages sought to $500 million. After considering various motions for summary judgment, the court ruled in October 2007 in favor of PacifiCorp on all counts and dismissed the plaintiffs' claims in their entirety. In February 2008, the plaintiffs filed a petition requesting consideration by the Utah Supreme Court of two of their five claims. The plaintiffs' request was granted and they filed a brief in November 2008 with the Utah Supreme Court. In January 2009, PacifiCorp filed its reply brief. In May 2010, the Utah Supreme Court reversed and remanded the case back to the Third District Court for further consideration. The Third District Court set an eight-week trial for June and July 2011. PacifiCorp cannot predict the outcome of these proceedings, but believes that the outcome will not have a material impact on its consolidated financial results.
 
Item 4.      (Removed and Reserved)
 

27

 

PART II
 
Item 5.      Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
MEHC indirectly owns all of the shares of PacifiCorp's outstanding common stock. Therefore, there is no public market for PacifiCorp's common stock.
 
In January 2011, PacifiCorp declared a dividend of $275 million payable to PPW Holdings LLC, a direct subsidiary of MEHC, on February 28, 2011. PacifiCorp did not declare or pay dividends on common stock during the years ended December 31, 2010 and 2009.
 
During the years ended December 31, 2010 and 2009, PacifiCorp received capital contributions of $100 million and $125 million, respectively, in cash from its indirect parent company, MEHC.
 
For a discussion of regulatory restrictions that limit PacifiCorp's ability to pay dividends on common stock, refer to "Limitations" in Item 7 and Note 15 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
 
Item 6.      Selected Financial Data
 
The following table sets forth PacifiCorp's selected consolidated historical financial data, which should be read in conjunction with Item 7 of this Form 10-K and with PacifiCorp's historical Consolidated Financial Statements and notes thereto in Item 8 of this Form 10-K. The selected consolidated historical financial data has been derived from PacifiCorp's audited historical Consolidated Financial Statements and notes thereto (in millions). In May 2006, the PacifiCorp Board of Directors elected to change PacifiCorp's fiscal year-end from March 31 to December 31.
 
 
Years Ended December 31,
 
Nine-Month Period Ended December 31,
 
2010
 
2009
 
2008
 
2007
 
2006
 
 
 
 
 
 
 
 
 
 
Consolidated Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Operating revenue
$
4,432
 
 
$
4,457
 
 
$
4,498
 
 
$
4,258
 
 
$
2,924
 
Operating income
1,036
 
 
1,060
 
 
954
 
 
894
 
 
421
 
Net income attributable to PacifiCorp
566
 
 
542
 
 
458
 
 
439
 
 
161
 
 
 
As of December 31,
 
2010
 
2009
 
2008
 
2007
 
2006
 
 
 
 
 
 
 
 
 
 
Consolidated Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Total assets
$
20,146
 
 
$
18,966
 
 
$
17,167
 
 
$
14,907
 
 
$
13,852
 
Short-term debt
36
 
 
 
 
85
 
 
 
 
397
 
Current portion of long-term debt and
 
 
 
 
 
 
 
 
 
capital lease obligations
588
 
 
16
 
 
144
 
 
414
 
 
127
 
Long-term debt and capital lease obligations,
 
 
 
 
 
 
 
 
 
excluding current portion
5,813
 
 
6,400
 
 
5,424
 
 
4,753
 
 
3,967
 
Preferred stock
41
 
 
41
 
 
41
 
 
41
 
 
41
 
Total PacifiCorp shareholders' equity
7,311
 
 
6,648
 
 
5,987
 
 
5,080
 
 
4,426
 
 
 

28

 

Item 7.      Management's Discussion and Analysis of Financial Condition and Results of Operations
 
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with Item 6 of this Form 10-K and with PacifiCorp's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. PacifiCorp's actual results in the future could differ significantly from the historical results.
 
Results of Operations
 
Overview
 
Net income attributable to PacifiCorp for the year ended December 31, 2010 was $566 million, an increase of $24 million, or 4%, as compared to 2009. Net income attributable to PacifiCorp increased due to higher prices approved by regulators, higher sales of renewable energy credits, higher benefits associated with deferred net power costs, higher allowances for funds used during construction and a lower effective tax rate, partially offset by lower net wholesale electricity activities, higher depreciation on higher plant placed in service and higher operations and maintenance expense.
 
Net income attributable to PacifiCorp for the year ended December 31, 2009 was $542 million, an increase of $84 million, or 18%, as compared to 2008. Net income attributable to PacifiCorp increased due to higher prices approved by regulators, higher net wholesale electricity activities and higher sales of renewable energy credits, partially offset by lower retail customer usage primarily due to the impacts of the economic conditions on industrial customers across PacifiCorp's service territories and residential customers in Oregon, higher depreciation on higher plant placed in service and higher interest expense due to the issuance of long-term debt to finance the higher plant.
 
Operating revenue and energy costs are the key drivers of PacifiCorp's results of operations as they encompass retail and wholesale electricity sales and the direct costs associated with providing electricity to customers. PacifiCorp believes that a discussion of gross margin, representing operating revenue less energy costs, is therefore useful.
 
As discussed in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K, PacifiCorp adopted authoritative guidance as of January 1, 2010 that required the deconsolidation of its majority owned coal mining joint venture, Bridger Coal. As a result, Bridger Coal is being accounted for under the equity method on a prospective basis. The deconsolidation of Bridger Coal had no impact on net income attributable to PacifiCorp during the year ended December 31, 2010. Prior to the deconsolidation of Bridger Coal, PacifiCorp adopted authoritative guidance on January 1, 2009 that established accounting and reporting standards for the noncontrolling interest in a subsidiary. This guidance impacted PacifiCorp's presentation of both revenue and expense associated with the noncontrolling interest in Bridger Coal and had no impact on net income attributable to PacifiCorp during the years ended December 31, 2009 and 2008.
 
 
 

29

 

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
A comparison of PacifiCorp's key operating results were as follows for the years ended December 31:
 
 
 
 
 
 
Favorable/(Unfavorable)
 
2010
 
2009
 
Change
 
% Change
 
 
 
 
 
 
 
 
Gross margin (in millions):
 
 
 
 
 
 
 
Operating revenue
$
4,432
 
 
$
4,457
 
 
$
(25
)
 
(1
)%
Energy costs
1,618
 
 
1,677
 
 
59
 
 
4
 
Gross margin
$
2,814
 
 
$
2,780
 
 
$
34
 
 
1
 %
 
 
 
 
 
 
 
 
Volumes of electricity sold (in gigawatt hours ("GWh")):
 
 
 
 
 
 
 
Residential
15,795
 
 
15,999
 
 
(204
)
 
(1
)%
Commercial
15,969
 
 
16,194
 
 
(225
)
 
(1
)
Industrial
20,680
 
 
19,934
 
 
746
 
 
4
 
Other
572
 
 
583
 
 
(11
)
 
(2
)
Total retail electricity sales
53,016
 
 
52,710
 
 
306
 
 
1
 
Wholesale electricity sales
11,415
 
 
12,349
 
 
(934
)
 
(8
)
Total electricity sales
64,431
 
 
65,059
 
 
(628
)
 
(1
)%
 
 
 
 
 
 
 
 
Retail electricity sales:
 
 
 
 
 
 
 
Average retail customers (in thousands)
1,733
 
 
1,719
 
 
14
 
 
1
 %
Average revenue per MWh
$
70.01
 
 
$
67.68
 
 
$
2.33
 
 
3
 %
 
 
 
 
 
 
 
 
Wholesale electricity sales:
 
 
 
 
 
 
 
Average revenue per MWh
$
43.02
 
 
$
51.95
 
 
$
(8.93
)
 
(17
)%
 
 
 
 
 
 
 
 
Volumes of electricity generated (in GWh):
 
 
 
 
 
 
 
Coal-fired generation
42,612
 
 
43,854
 
 
(1,242
)
 
(3
)%
Natural gas-fired generation
8,416
 
 
8,576
 
 
(160
)
 
(2
)
Hydroelectric generation
3,744
 
 
3,544
 
 
200
 
 
6
 
Other
2,862
 
 
2,427
 
 
435
 
 
18
 
Total PacifiCorp generated volumes
57,634
 
 
58,401
 
 
(767
)
 
(1
)%
 
 
 
 
 
 
 
 
Volumes of electricity purchased (in GWh):
 
 
 
 
 
 
 
Wholesale electricity purchases
11,329
 
 
10,975
 
 
(354
)
 
(3
)%
 
 
 
 
 
 
 
 
Cost of wholesale electricity purchased:
 
 
 
 
 
 
 
Average cost per MWh
$
38.50
 
 
$
42.95
 
 
$
4.45
 
 
10
 %
 
 
 

30

 

 
Gross margin increased $34 million, or 1%, for 2010 compared to 2009 primarily due to:
 
•    
$138 million of increases from higher retail prices approved by regulators primarily to recover increased costs of assets placed in service and higher energy costs, including $40 million of increases in DSM revenue primarily associated with Utah and Oregon DSM programs and a $10 million decrease in revenue associated with SB 408;
 
•    
$43 million of increases from sales of renewable energy credits;
 
•    
$39 million of increases from higher deferrals of incurred power costs and lower amortization of previous deferrals in accordance with established adjustment mechanisms;
 
•    
$14 million of increases resulting from the elimination of certain regulatory liabilities in the current period resulting from the Utah DSM settlement and the Utah general rate case order; and
 
•    
$6 million of decreases in fuel costs primarily due to lower average prices paid for natural gas and lower volumes of coal and natural gas consumed, substantially offset by increased coal prices.
 
The increase in gross margin was partially offset by:
•    
$115 million of decreases resulting from net wholesale electricity activities due to $102 million of lower average prices on wholesale electricity sales, $49 million of lower volumes of wholesale electricity sales and $15 million of higher volumes of wholesale electricity purchases, partially offset by $51 million lower average prices on wholesale purchases;
 
•    
$66 million of decreases from lower revenue related to the deconsolidation of Bridger Coal;
 
•    
$18 million of decreases resulting from higher transmission expense due to higher contract rates; and
 
•    
$8 million of decreases due to lower customer usage in the western side of PacifiCorp's service territory primarily due to unfavorable weather, partially offset by higher industrial customer usage and higher growth in the average number of customers in the eastern side of PacifiCorp's service territory.
 
Operations and maintenance increased $46 million, or 4%, primarily due to higher Utah and Oregon DSM expenses, the write-off of a portion of the Utah DSM regulatory asset in the current period resulting from the Utah DSM settlement and the Utah general rate case order and higher costs associated with jointly owned generating facilities primarily due to increased overhauls, partially offset by lower costs related to the deconsolidation of Bridger Coal.
 
Depreciation and amortization increased $12 million, or 2%, primarily due to higher plant placed in service, partially offset by revised depreciation rates in California and $10 million of lower depreciation related to the deconsolidation of Bridger Coal.
 
Taxes, other than income taxes were consistent with the prior year, but included $13 million of increased property taxes, substantially offset by decreases related to the deconsolidation of Bridger Coal.
 
Allowances for borrowed and equity funds increased $25 million, or 25%, primarily due to higher qualified construction work-in-progress balances.
 
Interest income decreased $14 million, or 74%, primarily due to interest recognized in the prior year associated with SB 408.
 
Income tax expense decreased $23 million to $211 million for 2010 compared to 2009, primarily due to the effects of ratemaking, higher production tax credits associated with PacifiCorp's wind-powered generating facilities and lower pre-tax income. The effective tax rate was 27% for the year ended December 31, 2010 compared to 30% for 2009.
 

31

 

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
A comparison of PacifiCorp's key operating results were as follows for the years ended December 31:
 
 
 
 
 
 
Favorable/(Unfavorable)
 
2009
 
2008
 
Change
 
% Change
 
 
 
 
 
 
 
 
Gross margin (in millions):
 
 
 
 
 
 
 
Operating revenue
$
4,457
 
 
$
4,498
 
 
$
(41
)
 
(1
)%
Energy costs
1,677
 
 
1,957
 
 
280
 
 
14
 
Gross margin
$
2,780
 
 
$
2,541
 
 
$
239
 
 
9
 %
 
 
 
 
 
 
 
 
Volumes of electricity sold (in GWh):
 
 
 
 
 
 
 
Residential
15,999
 
 
16,222
 
 
(223
)
 
(1
)%
Commercial
16,194
 
 
16,055
 
 
139
 
 
1
 
Industrial
19,934
 
 
21,495
 
 
(1,561
)
 
(7
)
Other
583
 
 
590
 
 
(7
)
 
(1
)
Total retail electricity sales
52,710
 
 
54,362
 
 
(1,652
)
 
(3
)
Wholesale electricity sales
12,349
 
 
12,345
 
 
4
 
 
0
 
Total electricity sales
65,059
 
 
66,707
 
 
(1,648
)
 
(2
)%
 
 
 
 
 
 
 
 
Retail electricity sales:
 
 
 
 
 
 
 
Average retail customers (in thousands)
1,719
 
 
1,706
 
 
13
 
 
1
 %
Average revenue per MWh
$
67.68
 
 
$
64.12
 
 
$
3.56
 
 
6
 %
 
 
 
 
 
 
 
 
Wholesale electricity sales:
 
 
 
 
 
 
 
Average revenue per MWh
$
51.95
 
 
$
68.78
 
 
$
(16.83
)
 
(24
)%
 
 
 
 
 
 
 
 
Volumes of electricity generated (in GWh):
 
 
 
 
 
 
 
Coal-fired generation
43,854
 
 
45,955
 
 
(2,101
)
 
(5
)%
Natural gas-fired generation
8,576
 
 
8,771
 
 
(195
)
 
(2
)
Hydroelectric generation
3,544
 
 
3,766
 
 
(222
)
 
(6
)
Other
2,427
 
 
1,386
 
 
1,041
 
 
75
 
Total PacifiCorp generated volumes
58,401
 
 
59,878
 
 
(1,477
)
 
(2
)%
 
 
 
 
 
 
 
 
Volumes of electricity purchased (in GWh):
 
 
 
 
 
 
 
Wholesale electricity purchases
10,975
 
 
11,448
 
 
473
 
 
4
 %
 
 
 
 
 
 
 
 
Cost of wholesale electricity purchased:
 
 
 
 
 
 
 
Average cost per MWh
$
42.95
 
 
$
66.56
 
 
$
23.61
 
 
35
 %
 

32

 

Gross margin increased $239 million, or 9%, for 2009 compared to 2008 primarily due to:
 
•    
$147 million of increases from higher retail prices approved by regulators primarily to recover increased costs of assets placed in service and higher energy costs, including $13 million of increases in DSM revenue primarily associated with Utah DSM programs;
 
•    
$83 million of increases in net wholesale electricity activities due to $259 million of significantly lower average prices on wholesale electricity purchases and $32 million of lower volumes of wholesale electricity purchases, partially offset by $208 million of lower average prices on wholesale electricity sales;
 
•    
$66 million of increases due to sales to the noncontrolling interest in Bridger Coal;
 
•    
$44 million of increases in sales of renewable energy credits;
 
•    
$27 million of increases due to growth in the average number of commercial and residential customers primarily in Utah; and
 
•    
$13 million of decreases in fuel costs primarily due to lower volumes of coal consumed as a result of increased generating facility overhauls and lower retail demand, partially offset by higher average prices of coal.
 
The increase in gross margin was partially offset by:
•    
$92 million of decreases due to lower average customer usage primarily in Oregon and by industrial customers across PacifiCorp's service territories due to the effects of the current economic conditions; and
 
•    
$26 million of decreases due to lower deferrals of incurred power costs in accordance with established adjustment mechanisms.
 
Operations and maintenance increased $50 million, or 5%, primarily due to costs associated with sales to the noncontrolling interest in Bridger Coal.
 
Depreciation and amortization increased $59 million, or 12%, primarily due to higher plant in service.
 
Taxes, other than income taxes increased $24 million, or 21%, primarily due to costs attributable to Bridger Coal and increased property taxes driven by higher plant in service.
 
Interest expense increased $51 million, or 15%, primarily due to higher average debt outstanding, partially offset by lower average rates on variable- and fixed-rate debt.
 
Allowance for borrowed and equity funds increased $18 million, or 22%, primarily due to higher qualified construction work-in-progress balances, partially offset by lower average rates.
 
Interest income increased $8 million, or 73%, substantially due to interest associated with SB 408.
 
Income tax expense decreased $4 million to $234 million for 2009 compared to 2008, primarily due to higher production tax credits associated with increased production at wind-powered generating facilities, substantially offset by higher pre-tax income. The effective tax rate was 30% for the year ended December 31, 2009 compared to 34% for the year ended December 31, 2008.
 

33

 

Liquidity and Capital Resources
 
As of December 31, 2010, PacifiCorp's total net liquidity was $1.086 billion. The components of total net liquidity were as follows (in millions):
 
Cash and cash equivalents
 
$
31
 
 
 
 
Available revolving credit facilities
 
$
1,395
 
Less:
 
 
Short-term debt
 
(36
)
Letters of credit and tax-exempt bond support
 
(304
)
Net revolving credit facilities available
 
$
1,055
 
 
 
 
Total net liquidity available
 
$
1,086
 
 
 
 
Unsecured revolving credit facilities:
 
 
Maturity dates(1)
 
2012-2013
 
Largest single bank commitment as a % of total(2)
 
 
15
%
 
(1)    
For further discussion regarding PacifiCorp's credit facilities, refer to Note 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
(2)    
An inability of financial institutions to honor their commitments could adversely affect PacifiCorp's short-term liquidity and ability to meet long-term commitments.
PacifiCorp's cash and cash equivalents were $31 million as of December 31, 2010, compared to $117 million as of December 31, 2009. PacifiCorp has restricted cash and investments included in other current assets and investments and other assets on the Consolidated Balance Sheets totaling $6 million and $88 million as of December 31, 2010 and 2009, respectively. The amount as of December 31, 2009 principally relates to funds held in trust at Bridger Coal for final mine reclamation. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding Bridger Coal.
 
In September 2010, the President signed the Small Business Jobs Act into law, extending retroactively to January 1, 2010 the 50% bonus depreciation for qualifying property purchased and placed in service in 2010. In December 2010, the President signed the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 into law, which provided for 100% bonus depreciation for qualifying property purchased and placed in service after September 8, 2010. As a result of the new laws, PacifiCorp's December 31, 2010 tax provision reflected bonus depreciation on qualifying assets placed in service during 2010. Accordingly, PacifiCorp's receivable for income taxes increased to $345 million as of December 31, 2010.
 
Operating Activities
 
Net cash flows from operating activities for the years ended December 31, 2010 and 2009 were $1.41 billion and $1.5 billion, respectively. The $90 million decrease was primarily due to changes in collateral posted for derivative contracts, lower net wholesale electricity sales and higher contributions to PacifiCorp's pension plan, partially offset by higher prices approved by regulators and higher income tax receipts in the current year primarily related to bonus depreciation.
 
Net cash flows from operating activities for the years ended December 31, 2009 and 2008 were $1.5 billion and $992 million, respectively. The $508 million increase was primarily due to higher income tax receipts related to the repairs deduction and bonus depreciation, lower net wholesale electricity purchases, changes in collateral posted for derivative contracts and higher prices approved by regulators.
 

34

 

Investing Activities
 
Net cash flows from investing activities for the years ended December 31, 2010 and 2009 were $(1.613) billion and $(2.308) billion, respectively. Capital expenditures decreased $721 million primarily due to lower expenditures for transmission system investments and wind-powered generating facilities.
 
Net cash flows from investing activities for the years ended December 31, 2009 and 2008 were $(2.308) billion and $(2.076) billion, respectively. Capital expenditures increased $539 million primarily due to construction costs for the Populus to Terminal transmission line, partially offset by the September 2008 acquisition of Chehalis Power Generating, LLC, an entity owning a 520-MW natural gas-fired generating facility located in Chehalis, Washington, for $308 million. Chehalis Power Generating, LLC was merged into PacifiCorp immediately following the acquisition.
 
Capital Expenditures
 
Capital expenditures, excluding the non-cash allowance for equity funds used during construction ("equity AFUDC"), consisted mainly of the following for the years ended December 31:
 
2010
 
•    
Transmission system investments totaling $391 million, including construction costs for the first major segment of the Energy Gateway Transmission Expansion Program, a 135-mile, double-circuit, 345-kilovolt transmission line between the Populus substation in southern Idaho and the Terminal substation near Salt Lake City, Utah, which was placed in service in 2010.
 
•    
Emissions control equipment totaling $398 million, including costs for the Dave Johnston generating facility Unit 3, which includes a sulfur dioxide scrubber that was placed in service in May 2010, as well as low nitrogen oxide burners and costs for installation or upgrade of sulfur dioxide scrubbers on various other generating facilities.
 
•    
The development and construction of wind-powered generating facilities totaling $152 million, for the 111-MW Dunlap Ranch I wind-powered generating facility near Medicine Bow, Wyoming, which was placed in service in October 2010.
 
•    
Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $666 million.
 
2009
 
•    
Transmission system investments totaling $748 million, including construction costs for a major segment of the Energy Gateway Transmission Expansion Program.
 
•    
The development and construction of wind-powered generating facilities totaling $407 million, including 218 MW placed in service in December 2008, 138 MW placed in service in January 2009 and 127 MW placed in service in September 2009. The expenditures also included construction costs for the 111-MW Dunlap Ranch I wind-powered generating facility.
 
•    
Emissions control equipment totaling $345 million, including the installation costs for emissions control equipment at the Dave Johnston generating facility related to the addition of the new sulfur dioxide scrubber on Unit 3 and the replacement of an existing sulfur dioxide scrubber on Unit 4, which is expected to be placed into service during 2012. Additional projects included installation of sulfur dioxide scrubbers on various other generating facilities.
 
•    
Distribution, generation, mining and other infrastructure needed to serve existing and expected demand totaling $828 million.
 

35

 

Financing Activities
 
Short-term Debt and Revolving Credit Facilities
 
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. PacifiCorp had $36 million of short-term debt outstanding as of December 31, 2010 at a weighted-average interest rate of 0.3% as compared to no short-term debt outstanding as of December 31, 2009. PacifiCorp had no outstanding borrowings under its unsecured revolving credit facilities as of December 31, 2010 or 2009.
 
For further discussion, refer to Note 8 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
 
Long-term Debt
 
In addition to the debt issuances discussed herein, PacifiCorp made scheduled repayments on long-term debt totaling $15 million and $138 million during the years ended December 31, 2010 and 2009, respectively.
 
In January 2009, PacifiCorp issued $350 million of its 5.50% First Mortgage Bonds due January 15, 2019 and $650 million of its 6.00% First Mortgage Bonds due January 15, 2039. The net proceeds were used to repay short-term debt, to fund capital expenditures and for general corporate purposes.
 
In June 2010, PacifiCorp completed a re-offering of a $45 million series of tax-exempt bond obligations. The interest rate for this obligation was previously fixed for a term which, upon scheduled expiration, was converted to a variable-rate with credit enhancement and liquidity support provided by a $46 million letter of credit issued under one of PacifiCorp's unsecured revolving credit facilities. In September 2010, PacifiCorp completed a re-offering of variable-rate tax-exempt bond obligations totaling $38 million. Letters of credit totaling $39 million were issued under one of PacifiCorp's unsecured revolving credit facilities to provide credit enhancement and liquidity support for these previously unenhanced obligations.
 
As of December 31, 2010, PacifiCorp had $601 million of letters of credit available to provide credit enhancement and liquidity support for variable-rate tax-exempt bond obligations totaling $587 million plus interest. These letters of credit were fully available at December 31, 2010 and expire periodically through May 2012.
 
PacifiCorp has regulatory authority from the OPUC and the IPUC to issue an additional $2.0 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. Also, in December 2010, PacifiCorp filed a shelf registration statement with the SEC covering future first mortgage bond issuances.
 
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 or deposits of cash. The amount of bonds that PacifiCorp may issue generally is also subject to a net earnings test. As of December 31, 2010, PacifiCorp estimated it would be able to issue up to $5.9 billion of new first mortgage bonds under the most restrictive issuance test in the mortgage. Any issuances are 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 or deposits of cash.
 
PacifiCorp may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by PacifiCorp may be reissued or resold by PacifiCorp from time to time and will depend on prevailing market conditions, PacifiCorp's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
 
Common Shareholder's Equity
 
In January 2011, PacifiCorp declared a dividend of $275 million payable to PPW Holdings LLC, a direct subsidiary of MEHC and PacifiCorp's direct parent company, on February 28, 2011.
 
Cash capital contributions from MEHC were $100 million and $125 million during the years ended December 31, 2010 and 2009, respectively.
 

36

 

Capitalization
 
PacifiCorp manages its capitalization and liquidity position to maintain a prudent capital structure with an objective of retaining strong investment grade credit ratings, which is expected to facilitate continuing access to flexible borrowing arrangements at favorable costs and rates. This objective, subject to periodic review and revision, attempts to balance the interests of all shareholders, customers and creditors and provide a competitive cost of capital and predictable capital market access.
 
As a result of authoritative accounting guidance, such as guidance pertaining to consolidations and leases, it is possible that new purchase power and gas agreements, transmission arrangements or amendments to existing arrangements may be accounted for as capital lease obligations or debt on PacifiCorp's financial 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 concerning minimum levels of common equity as a percentage of capitalization. This may lead PacifiCorp to seek amendments or waivers under financing agreements and from regulators, delay or reduce dividends or spending programs, seek additional new equity contributions from its indirect parent company, MEHC, or take other actions.
 
Future Uses of Cash
 
PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit rating, investors' judgment of risk and conditions in the overall capital market, including the condition of the utility industry in general.
 
Capital Expenditures
 
PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in rules and regulations, including environmental; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; and the cost and availability of capital. Expenditures for compliance-related items, such as pollution-control technologies, replacement generation, hydroelectric relicensing, hydroelectric decommissioning, and associated operating costs are generally incorporated into PacifiCorp's rates.
 
PacifiCorp estimates that it will spend approximately $5.1 billion on capital projects over the next three years, excluding non-cash equity AFUDC. These capital projects include new generating resources, including renewables; transmission investments; installation of emissions control equipment on existing generating facilities; and distribution investments in new connections, lines and substations.
 

37

 

Forecasted capital expenditures for the years ended December 31 are as follows (in millions):
 
 
2011
 
2012
 
2013
 
 
 
 
 
 
Forecasted capital expenditures(1):
 
 
 
 
 
Generation development
$
177
 
 
$
372
 
 
$
338
 
Transmission system investment
456
 
 
666
 
 
610
 
Environmental
229
 
 
149
 
 
245
 
Other
708
 
 
609
 
 
531
 
Total
$
1,570
 
 
$
1,796
 
 
$
1,724
 
 
(1)    
Excludes amounts for non-cash equity AFUDC.
 
The capital expenditure estimate for generation development projects primarily consists of construction of the approximately 637-MW Lake Side 2 combined-cycle combustion turbine natural gas-fired generating facility adjacent to the existing Lake Side generating facility that is expected to be placed in service in 2014.
 
Capital projects for transmission system investment include projects associated with the Energy Gateway Transmission Expansion Program totaling $1.0 billion, including the estimated remaining costs of $372 million for the 100-mile high-voltage transmission line being built between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley. A 65-mile segment of the Mona to Oquirrh transmission project will be a single-circuit 500-kV transmission line, while the remaining 35-mile segment will be a double-circuit 345-kV transmission line. The project is estimated to cost $440 million and is expected to be placed in service in 2013. Other segments associated with this program are expected to be placed in service through 2019, depending on siting, permitting and construction schedules.
 
The capital expenditure estimate for environmental projects includes emissions control equipment to meet anticipated air quality and visibility targets, including the reduction of sulfur dioxide, nitrogen oxide and particulate matter emissions. This estimate includes the installation of new or the replacement of existing emissions control equipment at a number of units at several of PacifiCorp's coal-fired generating facilities.
 
Capital expenditures related to operating projects consist of routine expenditures for distribution, generation, mining and other infrastructure needed to serve existing and expected demand.
 

38

 

Obligations and Commitments
 
Contractual Obligations
 
PacifiCorp has contractual cash obligations that may affect its consolidated financial condition. The following table summarizes PacifiCorp's material contractual cash obligations as of December 31, 2010 (in millions):
 
 
Payments Due By Periods
 
2011
 
2012-2013
 
2014-2015
 
2016 and After
 
Total
 
 
 
 
 
 
 
 
 
 
Long-term debt, including interest:
 
 
 
 
 
 
 
 
 
Fixed-rate obligations
$
941
 
 
$
858
 
 
$
801
 
 
$
9,382
 
 
$
11,982
 
Variable-rate obligations(1)
5
 
 
49
 
 
161
 
 
464
 
 
679
 
Short-term debt, including interest
36
 
 
 
 
 
 
 
 
36
 
Capital leases, including interest
8
 
 
19
 
 
15
 
 
87
 
 
129
 
Operating leases
6
 
 
9
 
 
7
 
 
39
 
 
61
 
Asset retirement obligations
5
 
 
13
 
 
22
 
 
287
 
 
327
 
Power purchase agreements(2):
 
 
 
 
 
 
 
 
 
Electricity commodity contracts
39
 
 
97
 
 
22
 
 
48
 
 
206
 
Electricity capacity contracts
117
 
 
146
 
 
145
 
 
335
 
 
743
 
Electricity mixed contracts
14
 
 
28
 
 
29
 
 
160
 
 
231
 
Transmission
115
 
 
205
 
 
145
 
 
745
 
 
1,210
 
Fuel purchase agreements(2):
 
 
 
 
 
 
 
 
 
Natural gas supply and transportation
160
 
 
78
 
 
78
 
 
285
 
 
601
 
Coal supply and transportation
604
 
 
1,121
 
 
967
 
 
2,306
 
 
4,998
 
Other purchase obligations
437
 
 
152
 
 
36
 
 
90
 
 
715
 
Other long-term liabilities(3)
85
 
 
8
 
 
7
 
 
58
 
 
158
 
Total contractual cash obligations
$
2,572
 
 
$
2,783
 
 
$
2,435
 
 
$
14,286
 
 
$
22,076
 
 
(1)    
Consists of principal and interest for tax-exempt bond obligations with interest rates scheduled to reset periodically prior to maturity. Future variable interest rates are set at December 31, 2010 rates. Refer to "Interest Rate Risk" in Item 7A of this Form 10-K for additional discussion related to variable-rate liabilities.
(2)    
Commodity contracts are agreements for the delivery of energy. Capacity contracts are agreements that provide rights to energy output, generally of a specified generating facility. Forecasted or other applicable estimated prices were used to determine total dollar value of the commitments for purposes of the table.
(3)    
Includes environmental and hydroelectric relicensing commitments recorded in the Consolidated Balance Sheets that are contractually or legally binding and contributions expected to be made to the PacifiCorp Retirement Plan during 2011 as disclosed in Note 11 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. Excludes regulatory liabilities and employee benefit plan obligations that are not legally or contractually fixed as to timing and amount. Deferred income taxes are excluded since cash payments are based primarily on taxable income for each year. Uncertain tax positions are also excluded because the amounts and timing of cash payments are not certain.
Commercial Commitments
 
PacifiCorp's commercial commitments include surety bonds that provide indemnities for PacifiCorp in relation to various commitments it has to third parties for obligations in the event of default by PacifiCorp. In the event of default by PacifiCorp, the bonding agency would seek recovery from PacifiCorp in the amount of the bond. The majority of these bonds are continuous in nature and renew annually. Based on current contractual commitments, PacifiCorp's level of surety bonding after December 31, 2010 is estimated to be approximately $25 million per year. This estimate is based on current information and actual amounts may vary due to rate changes or changes to the general operations of PacifiCorp.
 

39

 

Regulatory Matters
 
PacifiCorp is subject to comprehensive regulation. In addition to the discussion contained herein regarding regulatory matters, refer to Item 1 of this Form 10-K for further discussion regarding PacifiCorp's general regulatory framework.
 
Certain regulatory matters are subject to uncertainties that require the use of estimates on the Consolidated Financial Statements, particularly that related to SB 408. Refer to Note 5 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion.
 
FERC
 
As a result of a 2007 multi-party settlement with the FERC regarding long-term shared usage, coordinated operation and maintenance, and planning of certain 500-kV transmission lines, PacifiCorp agreed to file a Federal Power Act Section 205 general rate change filing for its system-wide transmission service rates no later than June 1, 2011. PacifiCorp is in the process of preparing for this filing, which will occur no later than the agreed upon date.
 
State Regulatory Matters
 
Utah
 
In March 2009, PacifiCorp filed for an ECAM with the UPSC. The filing recommended that the UPSC adopt the ECAM to recover the difference between base net power costs set in the next Utah general rate case and actual net power costs. The UPSC separated the application into two phases to first address whether the mechanism is in the public interest, and then if it is found to be in the public interest, to determine the type of mechanism that should be implemented. The UPSC completed the phase one hearings in January 2010. In February 2010, the UPSC issued an order to proceed to the second phase, concluding that the public interest determination is dependent on evidence to be provided in phase two. In February 2010, PacifiCorp filed an application with the UPSC seeking approval to defer the difference between the net power costs allowed by the UPSC's final order in PacifiCorp's 2009 general rate case and the actual net power costs incurred. Also in February 2010, the Utah Association of Energy Users filed a motion with the UPSC requesting deferral of incremental renewable energy credit revenue in excess of the renewable energy credit value utilized in Utah rates established by the 2009 general rate case. In July 2010, the UPSC issued an order approving a stipulation that would establish deferred accounts for both net power costs and renewable energy credit revenues in excess of the levels currently included in rates, subject to the UPSC's final determination of the ratemaking treatment of the deferrals. In November 2010, a final hearing on the ECAM was held with the UPSC. A final decision as to whether all or any of the net power costs and renewable energy credit revenues in excess of the levels currently included in rates will be collected from or passed through to customers is under consideration by the UPSC. In December 2010, the UPSC approved a separate stipulation that provides a $3 million monthly credit to customers effective January 1, 2011 that will be applied toward the UPSC's final decision.
 
In February 2010, PacifiCorp filed an application with the UPSC requesting an increase of $34 million associated with two major construction projects that were completed and in service by June 2010. The application requested recovery in conjunction with a future rate change. In March 2010, PacifiCorp updated its application to reflect the cost of capital decisions from the February 2010 general rate case order, reducing the amount requested for recovery to $33 million. In May 2010, a multi-party stipulation was filed with the UPSC agreeing to recovery of $31 million. In June 2010, the stipulation was approved by the UPSC.
 
In August 2010, PacifiCorp filed an application with the UPSC requesting an increase of $39 million associated with two major construction projects expected to be complete and in service by December 2010. The application requested a 5% increase in rates effective January 2011 encompassing both the $39 million requested increase and the $31 million increase approved by the UPSC in June 2010. In December 2010, the UPSC approved a stipulation that provides for a $64 million increase that encompasses both the February 2010 and the August 2010 applications. The stipulation also provides for collection of a one-time $16 million surcharge for recovery of amounts related to the February 2010 application that were deferred during the period July 2010 to December 2010. The new rates were effective January 1, 2011.
 
In January 2011, PacifiCorp filed a general rate case with the UPSC requesting a rate increase of $232 million, or an average price increase of 14%. If approved by the UPSC, the rates will be effective September 2011.
 

40

 

Oregon
 
In February 2010, PacifiCorp made its initial filing for the annual TAM with the OPUC for an annual increase of $69 million to recover the anticipated net power costs forecasted for calendar year 2011. In July 2010, an all-party stipulation was filed with the OPUC agreeing to an increase of $58 million, or an average price increase of 6%. The OPUC approved the all-party stipulation in September 2010, subject to updates for anticipated net power costs through November 2010. PacifiCorp filed the scheduled updates to net power costs in July and November 2010. In December 2010, PacifiCorp filed a final update to net power costs, reflecting an increase of $60 million, or an average price increase of 6%. The OPUC approved the increase in December 2010 with an effective date of January 1, 2011.
 
In March 2010, PacifiCorp filed a general rate case with the OPUC requesting an increase of $131 million, or an average price increase of 13%. In July 2010, a multi-party stipulation was filed with the OPUC agreeing to an annual increase of $85 million, or an average price increase of 8%. The stipulation required PacifiCorp to file updated costs for the Populus to Terminal transmission line once the asset was placed in service. In December 2010, PacifiCorp filed the updated costs based on the November 2010 placed-in-service date and reduced the annual increase to $80 million, or an average price increase of 8%. In December 2010, the OPUC approved the stipulation. The new rates were effective January 1, 2011.
 
Wyoming
 
In October 2009, PacifiCorp filed a general rate case with the WPSC requesting a rate increase of $71 million with an effective date of August 1, 2010. Net power costs included in the general rate case filing reflected an increase in coal costs and the expiration of low cost long-term power purchase contracts. The application was based on a test period ending December 31, 2010. In March 2010, a multi-party stipulation was filed with the WPSC agreeing to an overall rate increase of $36 million, or an average price increase of 7%, to be implemented in two phases. In May 2010, the WPSC approved the settlement agreement. The first phase of the rate increase, consisting of a $26 million increase, became effective July 1, 2010 and the second phase, consisting of the remaining $10 million increase, was effective February 1, 2011.
 
In January 2010, PacifiCorp filed its annual PCAM application with the WPSC requesting recovery of $8 million in deferred net power costs. In March 2010, a multi-party stipulation was filed with the WPSC agreeing to reduce the requested recovery to $4 million. In May 2010, the WPSC approved the settlement agreement allowing for the change in the PCAM surcharge rate effective April 1, 2010.
 
In April 2010, PacifiCorp filed an application with the WPSC requesting approval of a new ECAM to replace the existing PCAM. The PCAM concluded with the final deferral of net power costs in November 2010 and collection through March 2012. In November 2010, the WPSC approved effective December 1, 2010, the deferral of net power costs incurred above or below base net power costs currently provided for in rates until the WPSC issues an order on PacifiCorp's application for the ECAM. In November 2010, the WPSC held hearings for the establishment and design of an ECAM. In February 2011, the WPSC issued an order approving an ECAM under which the forecast of net power costs will be established in general rate cases and included in the ECAM charges. In addition, 70% of any difference between actual and forecasted net power costs would be subject to the ECAM mechanism between general rate cases.
 
In February 2011, PacifiCorp filed its final PCAM application with the WPSC requesting recovery of $16 million in deferred net power costs. If approved by the WPSC, the rates will become effective in April 2011 and will result in an $11 million rate increase over the $5 million currently reflected in the tariff.
 
In November 2010, PacifiCorp filed a general rate case with the WPSC requesting a rate increase of $98 million, or an average price increase of 17%. If approved by the WPSC, the rates will be effective September 2011.
 
Washington
 
In May 2010, PacifiCorp filed a general rate case with the WUTC requesting an annual increase of $57 million, or an average price increase of 21%. In November 2010, the requested annual increase was reduced to $49 million, or an average price increase of 18%. If approved by the WUTC, the rates will be effective April 2011.
 

41

 

Idaho
 
In February 2010, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $2 million in deferred net power costs. In March 2010, the IPUC issued an order approving PacifiCorp's ECAM application effective April 1, 2010.
 
In May 2010, PacifiCorp filed a general rate case with the IPUC requesting an annual increase of $28 million, or an average price increase of 14%. In November 2010, the requested annual increase was reduced to $25 million, or an average price increase of 12%. In December 2010, the IPUC issued an interim order approving an annual increase of $14 million, or an average price increase of 7% with an effective date of December 28, 2010. The IPUC plans to issue its final order in February 2011.
 
In June 2010, the IPUC approved an increase to PacifiCorp's energy efficiency rider to fund DSM programs of $1 million, or an average price increase of 1%, with an effective date of July 1, 2010. As a result of the 1% increase, the energy efficiency rider increased to 5%. In December 2010, the IPUC reduced the energy efficiency rider to 3%, effective December 28, 2010.
 
In February 2011, PacifiCorp filed an ECAM application with the IPUC requesting recovery of $13 million in deferred net power costs. If approved by the IPUC, the new rates will be effective April 1, 2011.
 
California
 
In November 2009, PacifiCorp filed a general rate case with the CPUC requesting an annual increase of $8 million, or an average price increase of 10%. In June 2010, PacifiCorp filed an all-party settlement agreement with the CPUC that reflects an annual increase of $4 million, or an average price increase of 5%, and includes the establishment of revised depreciation rates on California distribution assets. In September 2010, the CPUC approved the settlement agreement with an effective date of January 1, 2011.
 
In August 2010, PacifiCorp filed an application with the CPUC to increase rates pursuant to the ECAC. In the application, PacifiCorp requested a rate increase of $9 million, or an average price increase of 11%. In November 2010, the CPUC approved the ECAC with an effective date of January 1, 2011.
 
Environmental Laws and Regulations
 
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproducts, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various other state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. PacifiCorp believes it is in material compliance with all applicable laws and regulations. Refer to "Future Uses of Cash" for discussion of PacifiCorp's forecasted environmental-related capital expenditures.
 
Clean Air Standards
 
The Clean Air Act is a federal law, administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in State Implementation Plans ("SIPs"). SIPs, which are a collection of regulations, programs and policies to be followed, vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA. The major Clean Air Act programs, which most directly affect PacifiCorp's operations, are described below.
 

42

 

National Ambient Air Quality Standards
 
Under the authority of the Clean Air Act, the EPA sets minimum national ambient air quality standards for six principal pollutants, consisting of carbon monoxide, lead, nitrogen oxides, particulate matter, ozone and sulfur dioxide, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Most air quality standards require measurement over a defined period of time to determine the average concentration of the pollutant present.
 
In December 2009, the EPA designated the Utah counties of Davis and Salt Lake, as well as portions of Box Elder, Cache, Tooele, Utah and Weber counties, to be in nonattainment of the fine particulate matter standard. This designation has the potential to impact PacifiCorp's Little Mountain, Lake Side and Gadsby facilities, depending on the requirements to be established in the Utah SIP. The impact on the PacifiCorp facilities is not anticipated to be significant.
 
In January 2010, the EPA proposed a rule to strengthen the national ambient air quality standard for ground level ozone. The proposed rule arises out of legal challenges claiming that the March 2008 rule that reduced the standard from 80 parts per billion to 75 parts per billion was not strict enough. The new rule proposes a standard between 60 and 70 parts per billion. The EPA has delayed issuance of the final ozone standards until July 2011.
 
In January 2010, the EPA finalized a one-hour air quality standard for nitrogen dioxide at 0.10 part per million. State attainment designations were required to be submitted to the EPA by January 1, 2011, and the EPA must finalize the designations by January 1, 2012.
 
In June 2010, the EPA finalized a new national ambient air quality standard for sulfur dioxide. Under the new rule, the existing 24-hour and annual standards for sulfur dioxide, which were 140 parts per billion measured over 24 hours and 30 parts per billion measured over an entire year, were replaced with a new one-hour standard of 75 parts per billion. The new rule will utilize a three-year average to determine attainment. The rule will utilize source modeling, in addition to the installation of ambient monitors where sulfur dioxide emissions impact populated areas, with new monitors required to be in-service no later than January 2013. Attainment designations are due by June 2012, with SIPs due by 2014 and final attainment demonstrations by August 2017.
 
As new, more stringent standards are adopted, the number of counties designated as nonattainment areas is likely to increase. Businesses operating in newly designated nonattainment counties could face increased regulation and costs to monitor or reduce emissions. For instance, existing major emissions sources may have to install reasonably available control technologies to achieve certain reductions in emissions and undertake additional monitoring, recordkeeping and reporting. The construction or modification of facilities that are sources of emissions could become more difficult in nonattainment areas. Until additional monitoring and modeling is conducted, the impacts on PacifiCorp cannot be determined.
 
Clean Air Mercury Rule
 
The Clean Air Mercury Rule ("CAMR"), issued by the EPA in March 2005, was the United States' first attempt to regulate mercury emissions from coal-fired generating facilities through the use of a market-based cap-and-trade system. The CAMR, which mandated emissions reductions of approximately 70% by 2018, was overturned by the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") in February 2008. The EPA plans to propose a new rule that will require coal-fired generating facilities to reduce mercury emissions by utilizing a mandated "Maximum Achievable Control Technology" standard rather than a cap-and-trade system. In addition to regulating mercury under the new rule, the EPA may regulate other hazardous air pollutants. Under a consent decree, the EPA must issue a proposed rule to regulate mercury emissions by March 2011 and a final rule no later than November 2011. If adopted, the new rule will likely result in incremental costs to install and maintain mercury emissions control equipment at each of PacifiCorp's coal-fired generating facilities and would increase the cost of providing service to customers. Until the EPA issues the proposed and final rules, the impacts on PacifiCorp cannot be determined.
 

43

 

 
Regional Haze
 
The EPA has initiated a regional haze program intended to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's generating facilities meet the threshold applicability criteria to be eligible units under the Clean Air Visibility Rules. In accordance with the federal requirements, states were required to submit SIPs by December 2007 to demonstrate reasonable progress towards achieving natural visibility conditions in Class I areas by requiring emissions controls, known as best available retrofit technology, on sources constructed between 1962 and 1977 with emissions that are anticipated to cause or contribute to impairment of visibility. Wyoming issued best available retrofit technology permits to PacifiCorp on December 31, 2009, requiring PacifiCorp to implement emissions control projects that are consistent with the planned emissions reduction projects at PacifiCorp's Wyoming generating facilities. PacifiCorp appealed certain provisions of the Naughton and Jim Bridger generating facilities' permits, but the appeals were settled. Utah submitted its SIP and suggested that the emissions reduction projects planned by PacifiCorp are sufficient to meet its initial emissions reduction requirements. Utah is currently in the process of amending its SIP submittal, which will be open for public comment until March 2011. In January 2009, the EPA found that 37 states, including Wyoming, had failed to file a SIP that met some or all of the basic regional haze program requirements. Wyoming submitted its regional haze SIP to the EPA in January 2011. PacifiCorp believes that its planned emissions reduction projects will satisfy the regional haze requirements in Utah and Wyoming. It is possible that additional controls may be required after the respective SIPs have been submitted and approved by the EPA or that the timing of installation of planned controls could change.
 
New Source Review
 
Under existing New Source Review ("NSR") provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory agency prior to (a) beginning construction of a new major stationary source of a regulated pollutant or (b) making a physical or operational change to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations require pre-construction review and permitting under the Prevention of Significant Deterioration ("PSD") provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo an analysis to determine the best available control technology and evaluate the most effective emissions controls after consideration of a number of factors. Violations of NSR regulations, which may be alleged by the EPA, states, environmental groups and others, potentially subject a company to material fines and other sanctions and remedies, including installation of enhanced pollution controls and funding of supplemental environmental projects.
 
As part of an industry-wide investigation to assess compliance with the NSR and PSD provisions, the EPA has requested information and supporting documentation from numerous utilities regarding their capital projects for various generating facilities. A NSR enforcement case against an unrelated utility has been decided by the United States Supreme Court, holding that an increase in the annual emissions of a generating facility, when combined with a modification (i.e., a physical or operational change), may trigger NSR permitting. Between 2001 and 2003, PacifiCorp responded to requests for information relating to its capital projects at its generating facilities. PacifiCorp has been engaged in periodic discussions with the EPA over several years regarding PacifiCorp's historical projects and their compliance with NSR and PSD provisions. Final resolution has not been achieved. PacifiCorp cannot predict the outcome of its discussions with the EPA at this time; however, PacifiCorp could be required to install additional emissions controls and incur additional costs and penalties in the event it is determined that PacifiCorp's historical projects did not meet all regulatory requirements.
 
Numerous changes have been proposed to the NSR rules and regulations over the last several years. In addition to the proposed changes, differing interpretations by the EPA and the courts create risk and uncertainty for entities when seeking permits for new projects and installing emissions controls at existing facilities under NSR requirements. PacifiCorp monitors these changes and interpretations to ensure permitting activities are conducted in accordance with the applicable requirements.
 
Climate Change
 
The increased global attention to climate change has resulted in significant measures being proposed at the federal level to regulate GHG emissions. The United States Congress has considered, but has not adopted comprehensive climate change legislation, which included a market-based cap-and-trade program that was intended to reduce GHG emissions 83% below 2005 levels by 2050.
 

44

 

In December 2009, the EPA published its findings that GHG threaten the public health and welfare and is pursuing regulation of GHG emissions under the Clean Air Act. Additionally, in May 2010, the EPA issued the greenhouse gas "tailoring rule" to address permitting requirements for GHG after determining that GHG are subject to regulation and would trigger Clean Air Act permitting requirements for stationary sources beginning in January 2011. Numerous lawsuits have been filed on both the EPA's endangerment finding and the tailoring rule and are pending in the D.C. Circuit.
 
PacifiCorp supports the implementation of reasonable emissions caps, but opposes trading mechanisms that impose additional costs and do not result in decreased emissions. PacifiCorp also believes that any law or regulation should provide a reasonable transition period to allow the phase in of low-carbon generating technologies that will achieve sustainable and cost-effective GHG emissions reduction benefits.
 
While the debate continues at the federal and international level over the direction of climate change policy, several states have developed or are developing state-specific laws or regional initiatives to report or mitigate GHG emissions. In addition, governmental, non-governmental and environmental organizations have become more active in pursuing climate change related litigation under existing laws.
 
PacifiCorp voluntarily reports its GHG emissions to the California Climate Action Registry and The Climate Registry. In September 2009, the EPA issued its final rule regarding mandatory reporting of GHG ("GHG Reporting") beginning January 1, 2010. Under GHG Reporting, suppliers of fossil fuels, manufacturers of vehicles and engines, and facilities that emit 25,000 metric tons or more per year of GHG are required to submit annual reports to the EPA. PacifiCorp is subject to this requirement and will submit its first report by March 31, 2011.
 
PacifiCorp is committed to operating in an environmentally responsible manner. Examples of PacifiCorp's significant investments in programs and facilities that will mitigate its GHG emissions include:
•    
PacifiCorp owns the second largest portfolio of wind-powered generating capacity in the United States among rate-regulated utilities. As of December 31, 2010, PacifiCorp owned 1,032 MW of wind-powered generating capacity and has purchase power agreements with 705 MW of wind-powered generating capacity. PacifiCorp has invested $2.1 billion in wind-powered generating facilities.
•    
PacifiCorp owns 1,157 MW of hydroelectric generating capacity.
•    
PacifiCorp's Energy Gateway Transmission Expansion Program represents a plan to build approximately 2,000 miles of new high-voltage transmission lines with an estimated cost exceeding $6 billion. The plan includes several transmission line segments that will: (a) address customer load growth; (b) improve system reliability; (c) reduce transmission system constraints; (d) provide access to diverse generation resources, including renewable resources; and (e) improve the flow of electricity throughout PacifiCorp's six-state service area.
•    
PacifiCorp has offered customers a comprehensive set of DSM programs for more than 20 years. The programs assist customers to manage the timing of their usage, as well as to reduce overall energy consumption, resulting in lower utility bills.
•    
PacifiCorp has installed and upgraded emissions control equipment at certain of its coal-fired generating facilities to reduce emissions of sulfur dioxide and nitrogen oxides.

45

 

The impact of pending federal, regional, state and international accords, legislation, regulation, or judicial proceedings related to climate change cannot be quantified in any meaningful range at this time. New requirements limiting GHG emissions could have a material adverse impact on PacifiCorp, the United States and the global economy. Companies and industries with higher GHG emissions, such as utilities with significant coal-fired generating facilities, will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the requirements; the cost, availability and effectiveness of emissions control technology; the price, distribution method and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. Examples of how new requirements may impact PacifiCorp include:
 
•    
Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in excess of allocations that are received at no cost. These purchases would be necessary until new technologies could be developed and deployed to reduce emissions or lower carbon generation is available;
•    
Acquiring and renewing construction and operating permits for new and existing facilities may be costly and difficult;
•    
Additional costs may be incurred to purchase and deploy new generating technologies;
•    
Costs may be incurred to retire existing coal facilities before the end of their otherwise useful lives or to convert them to burn fuels, such as natural gas or biomass, that result in lower emissions;
•    
Operating costs may be higher and unit outputs may be lower;
•    
Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a financial risk; and
•    
PacifiCorp's electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.
PacifiCorp expects it will be allowed to recover the prudently incurred costs to comply with climate change requirements.
 
The impact of events or conditions caused by climate change, whether from natural processes or human activities, could vary widely, from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may cause physical and financial risk through, among other things, sea level rise, changes in precipitation and extreme weather events. Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence PacifiCorp's existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity production and increase the price customers pay or their demand for electricity.
 
International Accords
 
Under the United Nations Framework Convention on Climate Change, adopted in 1992, members of the convention meet periodically to discuss international responses to climate change. To date, the United States has not made a binding reduction commitment as a result of these international discussions.
 
Federal Legislation
 
In June 2009, the United States House of Representatives passed the American Clean Energy and Security Act of 2009 ("Waxman-Markey bill"). In addition to a federal RPS, which would have required utilities to obtain a portion of their energy from certain qualifying renewable sources and energy efficiency measures, the bill required a reduction in GHG emissions beginning in 2012, with emissions reduction targets of 3% below 2005 levels by 2012; 17% below 2005 levels by 2020; 42% below 2005 levels by 2030; and 83% below 2005 levels by 2050 under a cap-and-trade program. Similar legislation was introduced in the Senate, but it did not pass.
 

46

 

Greenhouse Gas Tailoring Rule
 
The EPA finalized the GHG "tailoring rule" in May 2010 requiring new or modified sources of GHG emissions with increases of 75,000 or more tons per year of total GHG to determine the best available control technology for their GHG emissions beginning in January 2011. New or existing major sources will also be subject to Title V operating permit requirements for GHG. Beginning July 1, 2011 through June 30, 2013, new construction projects that emit GHG emissions of at least 100,000 tons per year and modifications of existing facilities that increase GHG emissions by at least 75,000 tons per year will be subject to permitting requirements and facilities that were previously not subject to Title V permitting requirements will be required to obtain Title V permits if they emit at least 100,000 tons per year of carbon dioxide equivalents. Several legal challenges have been filed to the EPA's final GHG tailoring rule in the D.C. Circuit. The EPA issued a GHG best available control technology guidance document in November 2010 in an effort to provide permitting authorities guidance on how to conduct a best available control technology review for GHG. Until the permitting authorities begin to implement the tailoring rule and determine what constitutes best available control technology for GHG, the impacts of the tailoring rule on PacifiCorp cannot be fully determined.
 
Regional and State Activities
 
Several states have developed state-specific laws or regional legislative initiatives to report or mitigate GHG emissions that are expected to impact PacifiCorp, including:
•    
The Western Climate Initiative, a comprehensive regional effort to reduce GHG emissions by 15% below 2005 levels by 2020 through a cap-and-trade program that includes the electricity sector. The Western Climate Initiative includes the states of California, Montana, New Mexico, Oregon, Utah and Washington and the Canadian provinces of British Columbia, Manitoba, Ontario and Quebec. The state and provincial partners have agreed to begin reporting GHG emissions in 2011 for emissions that occurred in 2010. The first phase of the cap-and-trade program is scheduled to begin on January 1, 2012.
•    
An executive order signed by California's governor in June 2005 would reduce GHG emissions in that state to 2000 levels by 2010, to 1990 levels by 2020 and 80% below 1990 levels by 2050. The California Air Resources Board proposed regulations to adopt a GHG cap-and-trade program in October 2010; however, those regulations have not yet been finalized. In addition, California has adopted legislation that imposes a GHG emissions performance standard to all electricity generated within the state or delivered from outside the state that is no higher than the GHG emissions levels of a state-of-the-art combined-cycle natural gas-fired generating facility, as well as legislation that adopts an economy-wide cap on GHG emissions to 1990 levels by 2020.
•    
Over the past several years, the states of California, Washington and Oregon have adopted GHG emissions performance standards for base load electrical generating resources. Under the laws in all three states, the emissions performance standards provide that emissions must not exceed 1,100 lbs of carbon dioxide per MWh. These GHG emissions performance standards generally prohibit electric utilities from entering into long-term financial commitments (e.g., new ownership investments, upgrades, or new or renewed contracts with a term of 5 or more years) unless any base load generation supplied under long-term financial commitments comply with the GHG emissions performance standards.
•    
The Washington and Oregon governors enacted legislation in May 2007 and August 2007, respectively, establishing goals for the reduction of GHG emissions in their respective states. Washington's goals seek to (a) reduce emissions to 1990 levels by 2020; (b) reduce emissions to 25% below 1990 levels by 2035; and (c) reduce emissions to 50% below 1990 levels by 2050, or 70% below Washington's forecasted emissions in 2050. Oregon's goals seek to (a) cease the growth of Oregon GHG emissions by 2010; (b) reduce GHG levels to 10% below 1990 levels by 2020; and (c) reduce GHG levels to at least 75% below 1990 levels by 2050. Each state's legislation also calls for state government to develop policy recommendations in the future to assist in the monitoring and achievement of these goals.
Renewable Portfolio Standards
 
The RPS described below could significantly impact PacifiCorp's consolidated financial results. Resources that meet the qualifying electricity requirements under the RPS vary from state to state. Each state's RPS requires some form of compliance reporting and PacifiCorp can be subject to penalties in the event of noncompliance.
 
In November 2006, Washington voters approved a ballot initiative establishing a RPS requirement for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020. The WUTC has adopted final rules to implement the initiative.
 

47

 

In June 2007, the Oregon Renewable Energy Act ("OREA") was adopted, providing a comprehensive renewable energy policy for Oregon. Subject to certain exemptions and cost limitations established in the OREA, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, 20% in 2020 through 2024, and 25% in 2025 and subsequent years. As required by the OREA, the OPUC has approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy generating facilities and associated transmission costs.
 
California RPS requires electric utilities to increase their procurement of eligible renewable resources by at least 1% of their annual retail electricity sales per year so that 20% of their annual electricity sales are procured from eligible renewable resources by no later than December 31, 2010. PacifiCorp expects that it will meet this compliance target for which the underlying data is subject to verification by the California Energy Commission and review by the CPUC.
 
In September 2010, the California Air Resources Board unanimously adopted a Renewable Electricity Standard ("RES") pursuant to Executive Order S-21-09 issued in September 2009 under California's Global Warming Solutions Act to expand existing RPS targets to 33% by 2020 for most retail sellers of electricity in California, including PacifiCorp. Additional changes to the RES are anticipated, in part due to potential impacts of Senate Bill 23 that was introduced in the California Legislature in December 2010. PacifiCorp cannot predict the final outcome of the California legislation or how the RES or Senate Bill 23 may interact with the requirements of the California RPS.
 
In March 2008, Utah's governor signed Utah Senate Bill 202. Among other things, this law provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and DSM programs. Qualifying renewable energy sources can be located anywhere in the WECC areas, and renewable energy credits can be used.
 
Water Quality Standards
 
The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. In July 2004, the EPA established significant new technology-based performance standards for existing electric generating facilities that take in more than 50 million gallons of water per day. These rules are aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the Second Circuit remanded almost all aspects of the rule to the EPA, without addressing whether companies with cooling water intake structures were required to comply with these requirements. On appeal from the Second Circuit, in April 2009, the United States Supreme Court ruled that the EPA permissibly relied on a cost-benefit analysis in setting the national performance standards regarding "best technology available for minimizing adverse environmental impact" at cooling water intake structures and in providing for cost-benefit variances from those standards as part of the §316(b) Clean Water Act Phase II regulations. The United States Supreme Court remanded the case back to the Second Circuit to conduct further proceedings consistent with its opinion. Compliance and the potential costs of compliance, therefore, cannot be ascertained until such time as the Second Circuit takes action or further action is taken by the EPA. Currently, PacifiCorp's Dave Johnston generating facility, which has water cooling towers, exceeds the 50 million gallons of water per day intake threshold. In the event that PacifiCorp's existing intake structures require modification or alternative technology required by new rules, expenditures to comply with these requirements could be significant. PacifiCorp believes that it currently has, or has initiated the process to receive, all required water quality permits.
 

48

 

Coal Combustion Byproduct Disposal
 
In December 2008, an ash impoundment dike at the Tennessee Valley Authority's Kingston power plant collapsed after heavy rain, releasing a significant amount of fly ash and bottom ash, coal combustion byproducts, and water to the surrounding area. In light of this incident, federal and state officials have called for greater regulation of the storage and disposal of coal combustion byproducts. In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts, presenting two alternatives to regulation under the Resource Conservation and Recovery Act ("RCRA"). Under the first option, coal combustion byproducts would be regulated as special waste under RCRA Subtitle C and the EPA would establish requirements for coal combustion byproducts from the point of generation to disposition, including the closure of disposal units. Alternatively, the EPA is considering regulation under RCRA Subtitle D under which it would establish minimum nationwide standards for the disposal of coal combustion byproducts. Under both options, surface impoundments utilized for coal combustion byproducts would have to be cleaned and closed unless they could meet more stringent regulatory requirements; in addition, more stringent requirements would be implemented for new ash landfills and expansions of existing ash landfills. PacifiCorp operates 16 surface impoundments and six landfills that contain coal combustion byproducts. These ash impoundments and landfills may be impacted by the newly proposed regulation, particularly if the materials are regulated as hazardous or special waste under RCRA Subtitle C, and could pose significant additional costs associated with ash management and disposal activities at PacifiCorp's coal-fired generating facilities. The public comment period closed in November 2010; however, the timing of the final rule is not known. The impact of the proposed regulations on coal combustion byproducts cannot be determined at this time.
 
Other
 
Other laws, regulations and agencies to which PacifiCorp is subject to include, but are not limited to:
•    
The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs.
•    
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.
•    
The FERC oversees the relicensing of existing hydroelectric systems and is also responsible for the oversight and issuance of licenses for new construction of hydroelectric systems, dam safety inspections and environmental monitoring. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the relicensing of certain of PacifiCorp's existing hydroelectric facilities.

49

 

Collateral and Contingent Features
 
PacifiCorp's senior secured and senior unsecured debt credit ratings are as follows:
 
 
Fitch
 
Moody's
 
Standard & Poor's
 
 
 
 
 
 
Senior secured debt
A-
 
A2
 
A
Senior unsecured debt
BBB+
 
Baa1
 
A-
Outlook
Stable
 
Stable
 
Stable
 
Debt and preferred securities of PacifiCorp are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of PacifiCorp's ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time.
 
PacifiCorp has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt and a change in ratings is not an event of default under the applicable debt instruments. PacifiCorp's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities. 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 accordance with industry practice, certain wholesale energy agreements, including derivative contracts, contain provisions that require PacifiCorp to maintain specific credit ratings on its unsecured debt from one or more of the three recognized credit rating agencies. These agreements, including derivative contracts, may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" in the event of a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of December 31, 2010, PacifiCorp's credit ratings from the three recognized credit rating agencies were investment grade. If all credit-risk-related contingent features or adequate assurance provisions for these agreements, including derivative contracts, had been triggered as of December 31, 2010, PacifiCorp would have been required to post $225 million of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors. Refer to Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for a discussion of PacifiCorp's collateral requirements specific to PacifiCorp's derivative contracts.
 
In July 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Reform Act"). The Reform Act reshapes financial regulation in the United States by creating new regulators, regulating new markets and firms and providing new enforcement powers to regulators. Virtually all major areas of the Reform Act, including collateral requirements on derivative contracts, will be the subject of regulatory interpretation and implementation rules requiring rulemaking proceedings that may take several years to complete.
 
PacifiCorp is a party to derivative contracts, including over-the-counter derivative contracts. The Reform Act provides for extensive new regulation of over-the-counter derivative contracts and certain market participants, including imposition of mandatory clearing, exchange trading, capital and margin requirements for "swap dealers" and "major swap participants." The Reform Act provides certain exemptions from these regulations for commercial end-users that use derivatives to hedge and manage the commercial risk of their businesses. Although PacifiCorp generally does not enter into over-the-counter derivative contracts for purposes unrelated to hedging of commercial risk and does not believe it will be considered a swap dealer or major swap participant, the outcome of the rulemaking proceedings cannot be predicted and, therefore, the impact of the Reform Act on PacifiCorp's consolidated financial results cannot be determined at this time.