10-K 1 mehc123110form10k.htm MIDAMERICAN ENERGY HOLDINGS COMPANY FORM 10-K 12-31-10 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.
001-14881
 
MIDAMERICAN ENERGY HOLDINGS COMPANY
 
94-2213782
 
 
(An Iowa Corporation)
 
 
 
 
666 Grand Avenue, Suite 500
 
 
 
 
Des Moines, Iowa 50309-2580
 
 
 
 
515-242-4300
 
 
 
 
 
 
 
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes o No x
 
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 of the shares of common equity of MidAmerican Energy Holdings Company are privately held by a limited group of investors. As of January 31, 2011, 74,609,001 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 the Company's current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside of the Company's control and could cause actual results to differ materially from those expressed or implied by the Company's forward-looking statements. These factors include, among others:
•    
general economic, political and business conditions, as well as changes in laws and regulations affecting the Company'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, electricity and natural gas supply or the Company's ability to obtain long-term contracts with customers and suppliers;
•    
a high degree of variance between actual and forecasted load that could impact the Company's hedging strategy and the cost of balancing its generation resources and wholesale activities with its retail load obligations;
•    
performance and availability of the Company's generating facilities, including the impacts of outages or repairs, transmission constraints, weather and operating conditions;
•    
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 the Company'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 MEHC's and its subsidiaries' credit facilities;
•    
changes in MEHC's and its subsidiaries' credit ratings;
•    
risks relating to nuclear generation;
•    
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 regulated rates;
•    
increases in employee healthcare costs;
•    
the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements;
•    
changes in the residential real estate brokerage and mortgage industries and regulations that could affect brokerage and mortgage transaction levels;
•    
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 the Company's consolidated financial results;
•    
the Company's ability to successfully integrate future acquired operations into its business;

3

 

•    
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 MEHC'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 the Company are described in Item 1A and other discussions contained in this Form 10-K. The Company 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
 
MidAmerican Energy Holdings Company ("MEHC") is a holding company that owns subsidiaries principally engaged in energy businesses (collectively with its subsidiaries, the "Company"). MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). The balance of MEHC's common stock is owned by Mr. Walter Scott, Jr. (along with family members and related entities), a member of MEHC's Board of Directors, and Mr. Gregory E. Abel, a member of MEHC's Board of Directors and MEHC's President and Chief Executive Officer. As of January 31, 2011, Berkshire Hathaway, Mr. Scott (along with family members and related entities) and Mr. Abel owned 89.8%, 9.4% and 0.8%, respectively, of MEHC's voting common stock.
 
In March 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement (the "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 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. 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. 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.
 
The Company's operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), Northern Natural Gas Company ("Northern Natural Gas"), Kern River Gas Transmission Company ("Kern River"), CE Electric UK Funding Company ("CE Electric UK") (which primarily consists of Northern Electric Distribution Limited ("Northern Electric") and Yorkshire Electricity Distribution plc ("Yorkshire Electricity")), CalEnergy Philippines (which owns a majority interest in the Casecnan project in the Philippines), CalEnergy U.S. (which owns interests in independent power projects in the United States), and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). Through these platforms, the Company owns and operates an electric utility company in the Western United States, an electric and natural gas utility company in the Midwestern United States, two interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States.
 
MEHC's energy subsidiaries generate, transmit, store, distribute and supply energy. Approximately 91% of the Company's operating income during 2010 was generated from rate-regulated businesses. As of December 31, 2010, MEHC's electric and natural gas utility subsidiaries served 6.2 million electricity customers and end-users and 0.7 million natural gas customers. MEHC's natural gas pipeline subsidiaries operate interstate natural gas transmission systems that transported approximately 8% of the total natural gas consumed in the United States during 2010. These pipeline subsidiaries have approximately 17,000 miles of pipeline and a design capacity of approximately 7.4 billion cubic feet ("Bcf") of natural gas per day. As of December 31, 2010, the Company owned approximately 19,000 megawatts ("MW") of generation in operation and under construction, including approximately 18,000 MW of generation that is part of the regulated asset base of its electric utility businesses and approximately 1,000 MW of generation in independent power projects.
 
Refer to Note 22 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional segment information regarding MEHC's platforms.
 
MEHC's principal executive offices are located at 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580 and its telephone number is (515) 242-4300. MEHC was initially incorporated in 1971 as CalEnergy Company, Inc. under the laws of the state of Delaware and through a merger transaction in 1999 was reincorporated in Iowa under the name MidAmerican Energy Holdings Company.
 

5

 

PacifiCorp
 
General
 
PacifiCorp, an indirect wholly owned subsidiary of MEHC, is a United States regulated electric utility company headquartered in Oregon that serves 1.7 million retail electric customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp is principally engaged in the business of generating, transmitting, distributing and selling electricity. PacifiCorp's combined service territory covers approximately 136,000 square miles and includes a diverse regional economy 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.
 
PacifiCorp and MEHC agreed to certain material financial regulatory commitments that were established in connection with MEHC's acquisition of PacifiCorp in March 2006. Refer to Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of the financial regulatory commitments.
 
Regulated Electric Operations
 
Customers
 
The percentages of electricity sold to retail customers by jurisdiction for the years ended December 31 were as follows:
 
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 percentages of electricity sold to retail 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
 
 
 
 
 
 
Residential
30
%
 
30
%
 
30
%
Commercial
30
 
 
31
 
 
30
 
Industrial
39
 
 
38
 
 
40
 
Other
1
 
 
1
 
 
 
Total retail
100
%
 
100
%
 
100
%
 
 
 
 
 
 
Total GWh sold:
 
 
 
 
 
Retail
53,016
 
 
52,710
 
 
54,362
 
Wholesale(1)
11,415
 
 
12,349
 
 
12,345
 
Total retail and wholesale
64,431
 
 
65,059
 
 
66,707
 
 
 
 
 
 
 
Total average retail customers (in millions)
1.7
 
 
1.7
 
 
1.7
 
 
(1)    
Electricity sold into the wholesale market is either produced by PacifiCorp's generating facilities or purchased from other sources and resold in the market.
 
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.
 

7

 

Generating Facilities and Fuel Supply
 
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:
 
 
 
 
 
 
 
Facility
 
Net Owned
 
 
 
 
 
 
 
Net Capacity
 
Capacity
 
Location
 
Energy Source
 
Installed
 
(MW)(1)
 
(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:
 
 
 
 
 
 
 
 
 
Lewis River System
WA
 
Hydroelectric
 
1931-1958
 
578
 
 
578
 
North Umpqua River System
OR
 
Hydroelectric
 
1950-1956
 
200
 
 
200
 
Klamath River System
CA, OR
 
Hydroelectric
 
1903-1962
 
170
 
 
170
 
Bear River System
ID, UT
 
Hydroelectric
 
1908-1984
 
105
 
 
105
 
Rogue River System
OR
 
Hydroelectric
 
1912-1957
 
52
 
 
52
 
Minor hydroelectric facilities
Various
 
Hydroelectric
 
1895-1986
 
52
 
 
52
 
 
 
 
 
 
 
 
1,157
 
 
1,157
 
WIND:
 
 
 
 
 
 
 
 
 
Marengo
Dayton, WA
 
Wind
 
2007-2008
 
210
 
 
210
 
Glenrock
Glenrock, WY
 
Wind
 
2008-2009
 
138
 
 
138
 
Seven Mile Hill
Medicine Bow, WY
 
Wind
 
2008
 
119
 
 
119
 
Dunlap Ranch
Medicine Bow, WY
 
Wind
 
2010
 
111
 
 
111
 
Leaning Juniper
Arlington, OR
 
Wind
 
2006
 
101
 
 
101
 
High Plains
McFadden, WY
 
Wind
 
2009
 
99
 
 
99
 
Rolling Hills
Glenrock, WY
 
Wind
 
2009
 
99
 
 
99
 
Goodnoe Hills
Goldendale, WA
 
Wind
 
2008
 
94
 
 
94
 
Foote Creek
Arlington, WY
 
Wind
 
1999
 
41
 
 
33
 
McFadden Ridge
McFadden, WY
 
Wind
 
2009
 
28
 
 
28
 
 
 
 
 
 
 
 
1,040
 
 
1,032
 
OTHER:
 
 
 
 
 
 
 
 
 
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
 

8

 

 
(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.
 
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 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.
 
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.
 
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.
 
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
 

9

 

 
(1)    
These coal reserves are leased and mined by Bridger Coal Company, a joint venture between Pacific Minerals, Inc. ("PMI") and a subsidiary of Idaho Power Company. PMI, a 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, through its subsidiaries, 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's subsidiaries operate.
 
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.
 
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 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 Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
 
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.
 
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.

10

 

 
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"). 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 transmission and distribution system included 16,200 miles of transmission lines and 900 substations as of December 31, 2010.
 
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.
 
Future Generation
 
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 Washington Utilities and Transportation Commission ("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.
 
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 as part of regulated 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.

11

 

MidAmerican Energy
 
General
 
MidAmerican Energy, an indirect wholly owned subsidiary of MEHC, is a United States regulated electric and natural gas utility company headquartered in Iowa that serves 0.7 million regulated retail electric customers in portions of Iowa, Illinois and South Dakota and 0.7 million regulated retail and transportation natural gas customers in portions of Iowa, South Dakota, Illinois and Nebraska. MidAmerican Energy is principally engaged in the business of generating, transmitting, distributing and selling electricity and in distributing, selling and transporting natural gas. MidAmerican Energy has a diverse customer base consisting of residential, agricultural and a variety of commercial and industrial customer groups. Some of the larger industrial groups served by MidAmerican Energy include the processing and sales of food products; the manufacturing, processing and fabrication of primary metals; farm and other non-electrical machinery; real estate; and cement and gypsum products. In addition to retail sales and natural gas transportation, MidAmerican Energy sells electricity to markets operated by regional transmission organizations ("RTOs") and electricity and natural gas to other utilities, municipalities and energy marketing companies on a wholesale basis. MidAmerican Energy is a transmission-owning member of the Midwest Independent Transmission System Operator, Inc. ("MISO") and participates in its energy and ancillary services market.
 
MidAmerican Energy's regulated electric and natural gas operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The franchise agreements, with various expiration dates, are typically for 25-year terms. MidAmerican Energy generally has an exclusive right to serve electric customers within its service territories and, in turn, has an obligation to provide electricity service to those customers. In return, the state utility commissions have established rates on a cost-of-service basis, which are designed to allow MidAmerican Energy an opportunity to recover its costs of providing services and to earn a reasonable return on its investment.
 
MidAmerican Energy has nonregulated business activities that consist of competitive electricity and natural gas retail sales and gas income-sharing arrangements. Nonregulated electric activities predominantly include sales to retail customers in Illinois and other states that allow customers to choose their energy supplier. For its nonregulated gas activities, MidAmerican Energy purchases gas from producers and third party energy marketing companies and sells it directly to commercial and industrial end-users, as well as wholesalers, primarily in Iowa and Illinois. In addition, MidAmerican Energy manages gas supplies for a number of smaller commercial end-users, which includes the sale of gas to these customers to meet their supply requirements.
 
The percentages of MidAmerican Energy's operating revenue derived from the following business activities during the years ended December 31 were as follows:
 
2010
 
2009
 
2008
 
 
 
 
 
 
Regulated electric
47
%
 
47
%
 
43
%
Regulated gas
22
 
 
23
 
 
29
 
Nonregulated and other
31
 
 
30
 
 
28
 
 
100
%
 
100
%
 
100
%
 
Regulated Electric Operations
 
Customers
 
The percentages of electricity sold to retail customers by jurisdiction for the years ended December 31 were as follows:
 
2010
 
2009
 
2008
 
 
 
 
 
 
Iowa
90
%
 
90
%
 
90
%
Illinois
9
 
 
9
 
 
9
 
South Dakota
1
 
 
1
 
 
1
 
 
100
%
 
100
%
 
100
%
 

12

 

The percentages of electricity sold to retail customers by class of customer, total GWh sold and the average number of retail customers for the years ended December 31 were as follows:
 
2010
 
2009
 
2008
 
 
 
 
 
 
Residential
30
%
 
29
%
 
29
%
Commercial
19
 
 
20
 
 
20
 
Industrial
43
 
 
43
 
 
44
 
Other
8
 
 
8
 
 
7
 
Total retail
100
%
 
100
%
 
100
%
 
 
 
 
 
 
Total GWh sold:
 
 
 
 
 
Retail
21,710
 
20,185
 
20,928
Wholesale(1)
13,130
 
13,424
 
15,133
Total retail and wholesale
34,840
 
33,609
 
36,061
 
 
 
 
 
 
Total average retail customers (in millions)
0.7
 
 
0.7
 
 
0.7
 
 
(1)    
Electricity sold into the wholesale market is either produced by MidAmerican Energy's generating facilities or purchased from other sources and resold in the market.
 
In addition to the variations in weather from year to year, fluctuations in economic conditions within the service territory and elsewhere can impact customer usage, particularly for industrial and wholesale customers. Beginning in the third quarter of 2008, industrial 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 increase in retail demand during 2010 was substantially the result of weather and higher industrial customer usage driven by the improved economic conditions in the United States.
 
There are seasonal variations in MidAmerican Energy's electric business that are principally related to the use of electricity for air conditioning and the related effects of weather. Typically, 35-40% of MidAmerican Energy's regulated electric revenue is reported in the months of June, July, August and September.
 
The annual hourly peak demand on MidAmerican Energy's electric system usually occurs as a result of air conditioning use during the cooling season. Peak demand represents the highest demand on a given day and at a given hour. On July 14, 2010, retail customer usage of electricity caused a record hourly peak demand of 4,515 MW on MidAmerican Energy's electric system, which is 216 MW greater than the previous peak demand of 4,299 MW set June 22, 2009.
 

13

 

Generating Facilities and Fuel Supply
 
MidAmerican Energy has ownership interest in a diverse portfolio of generating facilities. The following table presents certain information concerning MidAmerican Energy's owned generating facilities as of December 31, 2010:
 
 
 
 
 
 
 
Facility
 
Net Owned
 
 
 
 
 
 
 
Net Capacity
 
Capacity
 
Location
 
Energy Source
 
Installed
 
(MW)(1)
 
(MW)(1)
COAL:
 
 
 
 
 
 
 
 
 
Walter Scott, Jr. Nos. 1, 2, 3 and 4
Council Bluffs, IA
 
Coal
 
1954-2007
 
1,660
 
1,183
George Neal Nos. 1, 2 and 3
Sergeant Bluff, IA
 
Coal
 
1964-1975
 
957
 
812
Louisa
Muscatine, IA
 
Coal
 
1983
 
746
 
657
Ottumwa
Ottumwa, IA
 
Coal
 
1981
 
717
 
373
George Neal No. 4
Salix, IA
 
Coal
 
1979
 
645
 
262
Riverside Nos. 3 and 5
Bettendorf, IA
 
Coal
 
1925-1961
 
133
 
133
 
 
 
 
 
 
 
4,858
 
3,420
NATURAL GAS:
 
 
 
 
 
 
 
 
 
Greater Des Moines
Pleasant Hill, IA
 
Natural gas
 
2003-2004
 
496
 
496
Electrifarm
Waterloo, IA
 
Natural gas/oil
 
1975-1978
 
199
 
199
Pleasant Hill
Pleasant Hill, IA
 
Natural gas/oil
 
1990-1994
 
164
 
164
Sycamore
Johnston, IA
 
Natural gas/oil
 
1974
 
156
 
156
River Hills
Des Moines, IA
 
Natural gas
 
1966-1967
 
121
 
121
Coralville
Coralville, IA
 
Natural gas
 
1970
 
60
 
60
Moline
Moline, IL
 
Natural gas
 
1970
 
63
 
63
Parr
Charles City, IA
 
Natural gas
 
1969
 
33
 
33
28 portable power modules
Various
 
Oil
 
2000
 
56
 
56
 
 
 
 
 
 
 
1,348
 
1,348
WIND:
 
 
 
 
 
 
 
 
 
Pomeroy
Pomeroy, IA
 
Wind
 
2007-2008
 
256
 
256
Century
Blairsburg, IA
 
Wind
 
2005-2008
 
200
 
200
Intrepid
Schaller, IA
 
Wind
 
2004-2005
 
176
 
176
Adair
Adair, IA
 
Wind
 
2008
 
175
 
175
Walnut
Walnut, IA
 
Wind
 
2008
 
153
 
153
Carroll
Carroll, IA
 
Wind
 
2008
 
150
 
150
Victory
Westside, IA
 
Wind
 
2006
 
99
 
99
Charles City
Charles City, IA
 
Wind
 
2008
 
75
 
75
 
 
 
 
 
 
 
1,284
 
1,284
NUCLEAR:
 
 
 
 
 
 
 
 
 
Quad Cities Nos. 1 and 2
Cordova, IL
 
Uranium
 
1972
 
1,783
 
446
 
 
 
 
 
 
 
 
 
 
OTHER:
 
 
 
 
 
 
 
 
 
Moline Nos. 1-4
Moline, IL
 
Hydroelectric
 
1941
 
3
 
3
 
 
 
 
 
 
 
 
 
 
Total Available Generating Capacity
 
 
 
 
 
 
9,276
 
6,501
 
 
 
 
 
 
 
 
 
 
PROJECTS UNDER CONTRUCTION(2):
 
 
 
 
 
 
 
 
Various wind projects
Iowa
 
Wind
 
 
 
593
 
593
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9,869
 
7,094
 
(1)    
Facility Net Capacity represents (except for wind-powered generating facilities, which are nominal ratings) total facility accredited net generating capacity based on MidAmerican Energy's accreditation approved by the MISO. A wind turbine generator's nominal rating is the manufacturer's contractually specified capability (in MW) under specified conditions. The accreditation of the wind-powered generating facilities totaled 102 MW and is considerably less than the nominal ratings due to the varying nature of wind. Net Owned Capacity indicates MidAmerican Energy's ownership of Facility Net Capacity.
(2)    
Facility Net Capacity and Net Owned Capacity for projects under construction each represent the estimated nominal ratings.
 
 

14

 

The following table shows the percentages of MidAmerican Energy's total energy supplied by energy source for the years ended December 31:
 
2010
 
2009
 
2008
 
 
 
 
 
 
Coal
66
%
 
60
%
 
59
%
Nuclear
11
 
 
11
 
 
10
 
Natural gas
2
 
 
1
 
 
3
 
Other(1)
10
 
 
10
 
 
6
 
Total energy generated
89
 
 
82
 
 
78
 
Energy purchased - short-term contracts and other
10
 
 
11
 
 
14
 
Energy purchased - long-term contracts
1
 
 
7
 
 
8
 
 
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.
 
The percentage of MidAmerican Energy'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, MidAmerican Energy must place more reliance on other energy sources. For example, MidAmerican Energy can generate more electricity using its low cost wind-powered generating facilities when factors associated with these facilities are favorable. When factors associated with wind resources are less favorable, MidAmerican Energy must increase its reliance on more expensive generation or purchased electricity. MidAmerican Energy 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.
 
All of the coal-fired generating facilities operated by MidAmerican Energy are fueled by low-sulfur, western coal from the Powder River Basin in northeast Wyoming. MidAmerican Energy's coal supply portfolio includes multiple suppliers and mines under short-term and multi-year agreements of varying terms and quantities. MidAmerican Energy's coal supply portfolio has a substantial majority of its expected 2011-2012 requirements under fixed-price contracts. MidAmerican Energy regularly monitors the western coal market for opportunities to enhance its coal supply portfolio. During the year ended December 31, 2010, MidAmerican Energy-owned generating facilities held sufficient allowances for sulfur dioxide and nitrogen oxides emissions to comply with the EPA Title IV and Clean Air Interstate Rule requirements.
 
MidAmerican Energy has a long-haul coal transportation agreement with Union Pacific Railroad Company ("Union Pacific") that expires in 2012. Under this agreement, Union Pacific delivers coal directly to MidAmerican Energy's George Neal and Walter Scott, Jr. Energy Centers and to an interchange point with Canadian Pacific Railway for short-haul delivery to the Louisa and Riverside Energy Centers. MidAmerican Energy has the ability to use BNSF Railway Company, an affiliate company, for delivery of coal to the Walter Scott, Jr., Louisa and Riverside Energy Centers should the need arise.
 
MidAmerican Energy is a 25% joint owner of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station"), a nuclear power plant. Exelon Generation Company, LLC ("Exelon Generation"), the 75% joint owner and the operator of Quad Cities Station, is a subsidiary of Exelon Corporation. Approximately one-third of the nuclear fuel assemblies in each reactor core at Quad Cities Station is replaced every 24 months. MidAmerican Energy has been advised by Exelon Generation that the following requirements for Quad Cities Station can be met under existing supplies or commitments: uranium requirements through 2014 and partial requirements through 2020; uranium conversion requirements through 2015 and partial requirements through 2020; enrichment requirements through 2012 and partial requirements through 2028; and fuel fabrication requirements through 2019. MidAmerican Energy has been advised by Exelon Generation that it does not anticipate it will have difficulty in contracting for uranium, uranium conversion, enrichment or fabrication of nuclear fuel needed to operate Quad Cities Station during these time periods.
 
MidAmerican Energy uses natural gas and oil as fuel for intermediate and peak demand electric generation, igniter fuel, transmission support and standby purposes. These sources are presently in adequate supply and available to meet MidAmerican Energy's needs.
 

15

 

MidAmerican Energy owns more wind-powered generating capacity than any other United States rate-regulated electric utility and believes wind-powered generation offers a viable, economical and environmentally prudent means of supplying electricity. Additionally, MidAmerican Energy has regulatory approval from the Iowa Utilities Board ("IUB") to construct up to 1,001 MW (nominal ratings) of additional wind-powered generation in Iowa through 2012.Wind-powered generation projects under this agreement are authorized to earn a 12.2% return on equity in any future Iowa rate proceeding. MidAmerican Energy is constructing 593 MW (nominal ratings) of wind-powered generation that it expects to place in service by December 31, 2011. MidAmerican Energy continues to pursue additional cost effective wind-powered generation. Renewable resources have low to no emissions, require little or no fossil fuel and are complemented by MidAmerican Energy's other generating facilities and wholesale transactions. MidAmerican Energy'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.
 
MidAmerican Energy purchases and sells electricity and ancillary services 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. MidAmerican Energy may also purchase electricity in the wholesale markets when it is more economical than generating electricity from its own facilities. MidAmerican Energy utilizes both swaps and fixed-price electricity sales and purchases contracts to reduce its exposure to electricity price volatility.
 
Transmission and Distribution
 
Electricity from MidAmerican Energy's generating facilities and purchased electricity is delivered to wholesale markets and its retail customers, via the transmission facilities of MidAmerican Energy and others. MidAmerican Energy determined that participation in an RTO energy and ancillary services market as a transmission-owning member would be superior to continuing as a stand-alone balancing control area and provide MidAmerican Energy with enhanced wholesale marketing opportunities and improved economic dispatch of its generating facilities. Effective September 1, 2009, MidAmerican Energy integrated its facilities with the MISO as a transmission-owning member. Accordingly, MidAmerican Energy now operates its transmission assets at the direction of the MISO.
 
In its role as the operator of its energy, capacity and ancillary service market, the MISO continually balances electric supply and demand in its day-ahead and real-time markets. Primarily through a centralized economic dispatch that optimizes the use of generation resources within the region, the MISO controls the day-to-day operations of the bulk power system for the region served by its members. Additionally, the MISO provides transmission service to MidAmerican Energy and others through its open access transmission tariff.
 
MidAmerican Energy can enter into wholesale bilateral transactions with a number of parties within the MISO market footprint and can also participate directly in the MISO market. MidAmerican Energy's wholesale transactions can also occur through the Southwest Power Pool, Inc. ("SPP") and PJM Interconnection, L.L.C. ("PJM") RTOs and several other major transmission-owning utilities in the region as a result of transmission interconnections MISO has with such organizations. MidAmerican Energy's transmission and distribution systems included 2,300 miles of transmission lines and 400 substations as of December 31, 2010.
 
Regulated Natural Gas Operations
 
MidAmerican Energy is engaged in the procurement, transportation, storage and distribution of natural gas for customers in its service territory. MidAmerican Energy purchases natural gas from various suppliers and contracts with interstate natural gas pipelines for transportation of the gas from the production areas to MidAmerican Energy's service territory and for storage services to manage fluctuations in system demand and seasonal pricing. MidAmerican Energy sells natural gas and delivery services to end-use customers on its distribution system; sells natural gas to other utilities, municipalities and energy marketing companies; and transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. During 2010, 47% of the total natural gas delivered through MidAmerican Energy's distribution system was transportation service.
 

16

 

The percentages of natural gas sold to retail customers by jurisdiction for the years ended December 31 were as follows:
 
2010
 
2009
 
2008
 
 
 
 
 
 
Iowa
77
%
 
76
%
 
77
%
South Dakota
12
 
 
13
 
 
12
 
Illinois
10
 
 
10
 
 
10
 
Nebraska
1
 
 
1
 
 
1
 
 
100
%
 
100
%
 
100
%
 
The percentages of natural gas sold to retail and wholesale customers by class of customer, total decatherms ("Dth") of natural gas sold, total Dth of transportation service and the average number of retail customers for the years ended December 31 were as follows:
 
2010
 
2009
 
2008
 
 
 
 
 
 
Residential
45
%
 
42
%
 
42
%
Commercial(1)
22
 
 
22
 
 
21
 
Industrial(1)
4
 
 
4
 
 
4
 
Total retail
71
 
 
68
 
 
67
 
Wholesale(2)
29
 
 
32
 
 
33
 
 
100
%
 
100
%
 
100
%
 
 
 
 
 
 
Total Dth of natural gas sold (000's)
112,117
 
 
121,355
 
 
132,172
 
Total Dth of transportation service (000's)
71,185
 
 
69,642
 
 
68,782
 
Total average number of retail customers (in millions)
0.7
 
 
0.7
 
 
0.7
 
 
(1)    
Commercial and industrial customers are classified primarily based on the nature of their business and natural gas usage. Commercial customers are business customers that use natural gas principally for heating. Industrial customers are business customers that use natural gas principally for their manufacturing processes.
(2)    
Wholesale sales are generally made to other utilities, municipalities and energy marketing companies for eventual resale to end-use customers.
 
There are seasonal variations in MidAmerican Energy's regulated natural gas business that are principally due to the use of natural gas for heating. Typically, 45-55% of MidAmerican Energy's regulated natural gas revenue is reported in the months of January, February, March and December.
 
On January 15, 2009, MidAmerican Energy recorded its all-time highest peak-day delivery through its distribution system of 1,155,473,599 Dth. This peak-day delivery consisted of 74% traditional retail sales service and 26% transportation service. MidAmerican Energy's 2010/2011 winter heating season peak-day delivery as of February 15, 2011 was 1,026,079 Dth reached on February 8, 2011. This preliminary peak-day delivery included 71% traditional retail sales service and 29% transportation service.
 
Fuel Supply and Capacity
 
MidAmerican Energy is allowed to recover its cost of natural gas from all of its regulated retail natural gas customers through purchased gas adjustment clauses ("PGA"). Accordingly, as long as MidAmerican Energy is prudent in its procurement practices, MidAmerican Energy's regulated retail natural gas customers retain the risk associated with the market price of natural gas. MidAmerican Energy uses several strategies designed to reduce volatility of natural gas prices for its regulated retail natural gas customers while maintaining system reliability. These strategies include purchasing a geographically diverse supply portfolio from producers and third party energy marketing companies, the use of storage gas and peak-shaving facilities, regulatory arrangements to share savings and costs with customers and short- and long-term financial and physical gas purchase contracts.
 
MidAmerican Energy contracts for firm natural gas pipeline capacity to transport natural gas from production areas to its service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Northern Natural Gas.
 

17

 

MidAmerican Energy utilizes gas storage leased from interstate pipelines to meet retail customer requirements and to manage the daily changes in demand due to changes in weather. The storage gas is typically replaced during off-peak months when the demand for natural gas is historically lower than during the heating season. In addition, MidAmerican Energy also utilizes its three liquefied natural gas ("LNG") facilities to meet peak day demands in the winter. The leased storage and LNG facilities reduce MidAmerican Energy's dependence on natural gas purchases during the volatile winter heating season and can deliver approximately 50% of MidAmerican Energy's design day sales requirements.
 
Natural gas property consists primarily of natural gas mains and services lines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The gas distribution facilities of MidAmerican Energy included 22,000 miles of gas mains and service lines as of December 31, 2010.
 
Demand-side Management
 
MidAmerican Energy has provided a comprehensive set of DSM programs to its Iowa electric and gas customers since 1990 and to customers in its other jurisdictions in more recent years. 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, MidAmerican Energy 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 residential customers who participate in the air conditioner load control program and nonresidential customers who participate in the nonresidential load management program. Although subject to prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for the DSM programs through state-specific energy efficiency service charges paid by all retail electric and gas customers. During 2010, $72 million was expended on MidAmerican Energy's DSM programs resulting in an estimated 239,000 MWh of electric and 557,000 Dth of gas first-year energy savings and an estimated 288 MW of electric and 6,054 Dth/day of gas peak load management.
 
Interstate Natural Gas Pipeline Companies
 
Northern Natural Gas
 
Northern Natural Gas, an indirect wholly owned subsidiary of MEHC, owns one of the largest interstate natural gas pipeline systems in the United States, which reaches from southern Texas to Michigan's Upper Peninsula. Northern Natural Gas' pipeline system, which is interconnected with many interstate and intrastate pipelines in the national grid system, consists of two distinct, but operationally integrated, markets. Its traditional end-use and distribution market area, referred to as the Market Area, includes points in Iowa, Nebraska, Minnesota, Wisconsin, South Dakota, Michigan and Illinois. Its natural gas supply and delivery service area, referred to as the Field Area, includes Kansas, Texas, Oklahoma and New Mexico. Northern Natural Gas primarily transports and stores natural gas for utilities, municipalities, other pipeline companies, gas marketing companies, industrial and commercial users and other end-users. Northern Natural Gas' pipeline system consists of 15,000 miles of natural gas pipelines, including 6,400 miles of mainline transmission pipelines and 8,600 miles of branch and lateral pipelines, with a Market Area design capacity of 5.5 Bcf per day and a Field Area delivery capacity of 2.0 Bcf per day to the Market Area. Based on a review of relevant 2009 industry data, the Northern Natural Gas system is believed to be the largest single pipeline in the United States as measured by pipeline miles and the twelfth-largest as measured by throughput. During 2010, Northern Natural Gas' transportation and storage revenue accounted for 93% of its total operating revenue, of which 87% was generated from reservation demand charges under firm transportation and storage contracts. About 64% of the reservation demand charges under the firm transportation and storage contracts were from utilities. Except for quantities of natural gas owned and managed for operational and system balancing purposes, Northern Natural Gas does not own the natural gas that is transported through its system. The sale of natural gas for operational and system balancing purposes accounts for the majority of the remaining 7% of Northern Natural Gas' 2010 operating revenue. Northern Natural Gas' transportation and most of its storage operations are subject to a regulated tariff that is on file with the FERC. The tariff rates are designed to allow Northern Natural Gas an opportunity to recover its costs and generate a regulated return on equity.
 
Northern Natural Gas' pipeline system provides its customers access to natural gas through direct connections or interconnections with other pipelines from key production areas, including the Hugoton, Permian, Anadarko and Rocky Mountain basins in its Field Area and the Rocky Mountain and Canadian basins in its Market Area. In each of these areas, Northern Natural Gas has numerous interconnecting receipt and delivery points.
 

18

 

During 2010, 77% of Northern Natural Gas' transportation and storage revenue was generated from Market Area customer transportation contracts. Northern Natural Gas transports natural gas primarily to local distribution markets and end-users in the Market Area. Northern Natural Gas directly serves 78 utilities, including MidAmerican Energy, and in turn, these utilities serve numerous residential, commercial and industrial customers. A majority of Northern Natural Gas' capacity in the Market Area is committed to customers under firm transportation contracts. As of December 31, 2010, 94% of Northern Natural Gas' customers' entitlement in the Market Area is contracted beyond 2011, and 53% is contracted beyond 2015. The weighted average remaining contract term for Northern Natural Gas' Market Area transportation contracts is approximately five years as of December 31, 2010.
 
During 2010, 10% of Northern Natural Gas' transportation and storage revenue was generated from Field Area customer transportation contracts. In the Field Area, customers holding contracted firm transportation capacity, or entitlement, consist primarily of energy marketing companies, producers, midstream gatherers and producers and power generators. The majority of this entitlement is contracted on a short-term basis, principally by energy marketing companies and producers. Northern Natural Gas expects short-term contracting to continue in the foreseeable future as Market Area customers presently need to purchase competitively priced supplies from the Field Area to support their growing demand requirements. However, the revenue received from these contracts is expected to vary in relationship to the spread in natural gas prices between the MidContinent Region and Canada. Additionally, a weaker economy and lower market loads in the upper Midwest markets east of Northern Natural Gas' pipeline system, such as in Chicago and Michigan, create a risk of more Canadian supply being delivered into Northern Natural Gas' Market Area providing competition to Northern Natural Gas' supply from the Field Area.
 
Northern Natural Gas has interconnections with several interstate pipelines and several intrastate pipelines, with receipt, delivery or bi-directional capabilities. Because of its location and multiple interconnections with interstate and intrastate pipelines, Northern Natural Gas is able to access natural gas from both traditional production areas, such as the Hugoton, Permian and Anadarko Basins, and growing supply areas, such as the Rocky Mountains, through Trailblazer Pipeline Company, Kinder Morgan Interstate Gas Transmission, Cheyenne Plains Pipeline, Colorado Interstate Gas Pipeline Company and Rockies Express Pipeline, LLC, as well as from Canadian production areas through Northern Border Pipeline Company ("Northern Border"), Great Lakes Gas Transmission Limited Partnership ("Great Lakes") and Viking Gas Transmission Company ("Viking"). This supply diversity provides significant flexibility to Northern Natural Gas' system and customers.
 
During 2010, 13% of Northern Natural Gas' transportation and storage revenue was generated from storage services. Northern Natural Gas' storage services are provided through the operation of one underground natural gas storage field in Iowa, two underground natural gas storage facilities in Kansas and two LNG storage peaking units, one in Iowa and one in Minnesota. The three underground natural gas storage facilities and two LNG storage peaking units have a total firm service and operational storage cycle capacity of 73 Bcf and over 2.0 Bcf of peak delivery capability. These storage facilities provide Northern Natural Gas with operational flexibility for the daily balancing of its system and provide services to customers to meet their winter peaking and year-round load swing requirements.
 
Since June 2006, Northern Natural Gas has added 14 Bcf of firm storage cycle capacity through investments and modifications made at its Cunningham, Kansas and Redfield, Iowa storage facilities. This capacity was sold to local distribution companies ("LDC") for terms of 20-21 years.
 
Northern Natural Gas' system experiences significant seasonal swings in demand and revenue, with the highest demand typically occurring during the months of November through March. This seasonality provides Northern Natural Gas with opportunities to deliver additional value-added services, such as firm and interruptible storage services. Northern Natural Gas' supply diversity provides significant flexibility to its system and customers. As a result of Northern Natural Gas' geographic location in the middle of the United States and its many interconnections with other pipelines, Northern Natural Gas has the opportunity to augment its steady end user and LDC revenue by capitalizing on opportunities for shippers to reach additional markets, such as Chicago, Illinois, other parts of the Midwest, and Texas, through interconnects.
 

19

 

Kern River
 
Kern River, an indirect wholly owned subsidiary of MEHC, owns an interstate natural gas pipeline system that extends from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. Kern River's pipeline system consists of 1,700 miles of natural gas pipelines, including 1,400 miles of mainline section and 300 miles of common facilities, with a design capacity of 1,900,575 Dth per day. Kern River owns the entire mainline section, which extends from the system's point of origination near Opal, Wyoming, through the Central Rocky Mountains area into Daggett, California. The mainline section consists of 1,300 miles of 36-inch diameter pipeline and 100 miles of various laterals that connect to the mainline. The common facilities are jointly owned by Kern River and Mojave Pipeline Company ("Mojave"), a wholly owned subsidiary of El Paso Corporation, as tenants-in-common, and ownership may increase or decrease pursuant to the capital contributions made by each respective joint owner. Kern River has exclusive rights to 1,613,400 Dth per day of the common facilities' capacity, and Mojave has exclusive rights to 414,000 Dth per day of capacity. Operation and maintenance of the common facilities are the responsibility of Mojave Pipeline Operating Company, an affiliate of Mojave. Except for quantities of natural gas owned for operational and system balancing purposes, Kern River does not own the natural gas that is transported through its system. Kern River's transportation operations are subject to a regulated tariff that is on file with the FERC. The tariff rates are designed to allow Kern River an opportunity to recover its costs and generate a regulated return on equity.
 
Kern River's 2010 Expansion project was placed in-service in April 2010 after final approval was received from the Pipeline and Hazardous Materials Safety Administration and the FERC. The project added an additional 145,000 Dth per day of capacity. Kern River received approval from the FERC in September 2010 to begin construction of its Apex Expansion project. The project is expected to be placed in-service in 2011 and will add an incremental 266,000 Dth per day of capacity. The Apex Expansion project is expected to require more than $370 million in capital expenditures through 2011, of which $145 million has been incurred through December 31, 2010.
 
Kern River has year-round long-term firm natural gas transportation service agreements for 1,900,575 Dth per day of capacity. Pursuant to these agreements, the pipeline receives natural gas on behalf of shippers at designated receipt points, transports the natural gas on a firm basis up to each shipper's maximum daily quantity and delivers thermally equivalent quantities of natural gas at designated delivery points. Each shipper pays Kern River the aggregate amount specified in its long-term firm natural gas transportation service agreement and Kern River's tariff, with such amount consisting primarily of a fixed monthly reservation fee based on each shipper's maximum daily quantity and a commodity charge based on the actual amount of natural gas transported.
 
These year-round, long-term firm natural gas transportation service agreements expire between September 30, 2011 and April 30, 2018, and have a weighted-average remaining contract term of six years. Shippers on the pipeline include major oil and natural gas companies or affiliates of such companies, electricity generating companies, energy marketing and trading companies, financial institutions and natural gas distribution utilities which provide services in Utah, Nevada and California. As of December 31, 2010, over 98% of the firm capacity has primary delivery points in California, with the flexibility to access secondary delivery points in Nevada and Utah.
 
Northern Natural Gas and Kern River Competition
 
Pipelines compete on the basis of cost (including both transportation costs and the relative costs of the natural gas they transport), flexibility, reliability of service and overall customer service. End-users often choose from various alternatives, such as natural gas, electricity, fuel oil and coal, primarily on the basis of price. Legislation and governmental regulations, the weather, the futures market, production costs and other factors beyond the control of Northern Natural Gas and Kern River influence the price of natural gas.
 
Northern Natural Gas' ability to extend existing customer contracts, remarket expiring contracted capacity or market new capacity is dependent on competitive alternatives, the regulatory environment and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility.
 
Subject to regulatory requirements, Northern Natural Gas attempts to recontract or remarket its capacity at the rates allowed under its tariff, although at times Northern Natural Gas discounts these rates to remain competitive. Northern Natural Gas' existing contracts mature at various times and in varying amounts of entitlement. Northern Natural Gas continues to manage its recontracting process to attempt to mitigate the risk of significant impacts on its revenue.
 

20

 

Historically, Northern Natural Gas has been able to provide competitively priced services because of its access to a variety of relatively low cost supply basins, its cost control measures and the relatively high level of firm entitlement that is sold on a seasonal and annual basis, which lowers the per unit cost of transportation. To date, Northern Natural Gas has avoided any significant pipeline system bypasses or turn-back of firm entitlement.
 
Northern Natural Gas' major competitors in the Market Area include ANR Pipeline Company, Northern Border and Natural Gas Pipeline Company of America LLC. Other competitors of Northern Natural Gas include Great Lakes and Viking. In the Field Area, Northern Natural Gas competes with a large number of interstate and intrastate pipeline companies where the vast majority of Northern Natural Gas' capacity is used for transportation services provided on a short-term firm basis.
 
Northern Natural Gas needs to compete aggressively to serve existing load and add new customers and load. Northern Natural Gas has been successful in competing for a significant amount of the increased demand related to residential and commercial needs and the construction of new power plants. The growth related to utilities is driven by population growth and increased commercial and industrial needs. The new power plant growth originates from re-powering coal-fired generation, as well as new combustion and combined-cycle gas-fired generation. The growth also may be supportive of the continued sale of Northern Natural Gas' storage services and Field Area transportation services.
 
Kern River competes with various interstate pipelines in developing expansion projects and entering into long-term agreements to serve market growth in Southern California; Las Vegas, Nevada; and Salt Lake City, Utah. Kern River also competes with various interstate pipelines and its shippers to market capacity that is unutilized under shorter term transactions. Kern River provides its customers with supply diversity through pipeline interconnections with Northwest Pipeline Corporation, Colorado Interstate, Overland Trails Pipeline, Questar Pipeline Company and Questar Overthrust Pipeline Company. These interconnections, in addition to the direct interconnections to natural gas processing facilities, allow Kern River to access natural gas reserves in Colorado, northwestern New Mexico, Wyoming, Utah and the Western Canadian Sedimentary Basin.
 
Kern River is the only interstate pipeline that presently delivers natural gas directly from a gas supply basin to end-users in the California market. This enables direct connect customers to avoid paying a "rate stack" (i.e., additional transportation costs attributable to the movement from one or more interstate pipeline systems to an intrastate system within California). Kern River believes that its historic levelized rate structure and access to upstream pipelines, storage facilities and economic Rocky Mountain gas reserves increases its competitiveness and attractiveness to end-users. Kern River believes it has an advantage relative to other competing interstate pipelines because its relatively new pipeline can be economically expanded and will require significantly less capital expenditures than other systems to comply with the Pipeline Safety Improvement Act of 2002 ("PSIA"). Kern River's favorable market position is tied to the availability and relatively favorable price of gas reserves in the Rocky Mountain area, an area that has attracted considerable expansion of pipeline capacity serving markets other than California and Nevada.
 
During 2010, Northern Natural Gas had three customers, including MidAmerican Energy, that each accounted for greater than 10% of its revenue and its ten largest customers accounted for 62% of its system-wide transportation and storage revenue. Northern Natural Gas has agreements to retain the vast majority of its two largest non-affiliated customers' volumes through at least 2017. Kern River had one customer who accounted for greater than 10% of its revenue. The loss of any of these significant customers, if not replaced, could have a material adverse effect on Northern Natural Gas' and Kern River's respective businesses.
 
CE Electric UK
 
General
 
CE Electric UK, an indirect wholly owned subsidiary of MEHC, is a holding company which owns two companies that distribute electricity in Great Britain, Northern Electric and Yorkshire Electricity. Northern Electric and Yorkshire Electricity serve 3.8 million end-users and operate in the north-east of England from North Northumberland through Tyne and Wear, County Durham, Cleveland and Yorkshire to North Lincolnshire, an area covering 10,000 square miles. The principal function of Northern Electric and Yorkshire Electricity is to build, maintain and operate the electricity distribution network through which the end-user receives a supply of electricity. In addition to Northern Electric and Yorkshire Electricity, CE Electric UK also owns an engineering contracting business that provides electrical infrastructure contracting services to third parties and a hydrocarbon exploration and development business that is focused on developing integrated upstream gas projects in Europe and Australia.
 

21

 

Electricity Distribution
 
Northern Electric and Yorkshire Electricity receive electricity from the national grid transmission system and distribute it to end-users' premises using their networks of transformers, switchgear and distribution lines and cables. Substantially all of the end-users in Northern Electric's and Yorkshire Electricity's distribution service areas are connected to the Northern Electric and Yorkshire Electricity networks and electricity can only be delivered to these end-users through their distribution systems, thus providing Northern Electric and Yorkshire Electricity with distribution volumes that are relatively stable from year to year. Northern Electric and Yorkshire Electricity each charge fees for the use of their distribution systems to the suppliers of electricity. The suppliers purchase electricity from generators, sell the electricity to end-user customers and use Northern Electric's and Yorkshire Electricity's distribution networks pursuant to an industry standard "Distribution Connection and Use of System Agreement." One supplier, RWE Npower PLC and certain of its affiliates, represented 30% of the total combined distribution revenue of Northern Electric and Yorkshire Electricity during 2010.
 
The service territory geographically features a diverse economy with no dominant sector. The mix of rural, agricultural, urban and industrial areas covers a broad customer base ranging from domestic usage through farming and retail to major industry including automotives, chemicals, mining, steelmaking and offshore marine construction. The industry within the area is concentrated around the principal centers of Newcastle, Middlesbrough, Sheffield and Leeds.
 
The price controlled revenue of the regulated distribution companies are set out in the special conditions of the licenses of those companies. The licenses are enforced by the regulator, the Gas and Electricity Markets Authority through its office of gas and electric markets (known as "Ofgem") and limit increases (or may require decreases) based upon the rate of inflation, other specified factors and other regulatory action. Changes to the price controls can be made only by agreement between a distribution company and the regulator or, if there is no agreement, following a report on a reference by the regulator to the Competition Commission. It has been the convention in the United Kingdom for regulators to conduct periodic regulatory reviews before making proposals for any changes to the price controls. The price controls have conventionally been based upon a 5-year price control period. The current price control period commenced April 1, 2010 and will be replaced by a new price control commencing April 1, 2015.
 
Electricity distributed to end-users and the total number of end-users as of and for the years ended December 31 were as follows:
 
2010
 
2009
 
2008
Electricity distributed (in GWh):
 
 
 
 
 
Northern Electric
15,859
 
15,567
 
16,563
Yorkshire Electricity
23,094
 
22,642
 
24,047
 
38,953
 
38,209
 
40,610
Number of end-users (in millions):
 
 
 
 
 
Northern Electric
1.6
 
1.6
 
1.6
Yorkshire Electricity
2.2
 
2.2
 
2.2
 
3.8
 
3.8
 
3.8
 
As of December 31, 2010, Northern Electric's and Yorkshire Electricity's electricity distribution network, on a combined basis, included 18,000 miles of overhead lines, 40,000 miles of underground cables and 700 major substations.
 
CalEnergy Philippines
 
The CalEnergy Philippines platform consists of MEHC's indirect majority ownership of the Casecnan project, which is a 150 MW combined irrigation and hydroelectric independent power project located on the Casecnan and Taan Rivers on the Philippine island of Luzon. The Company's net owned capacity for the Casecnan project is 128 MW.
 
The Casecnan project's sole customer is the Republic of the Philippines ("ROP"). The ROP has provided a performance undertaking under which the Philippine National Irrigation Administration's ("NIA") obligations under the Casecnan Project Agreement, as modified ("Project Agreement"), are guaranteed by the full faith and credit of the ROP. NIA also pays CE Casecnan Water and Energy Company, Inc. ("CE Casecnan") for delivery of water and electricity by CE Casecnan. The Casecnan project carries political risk insurance.
 

22

 

Under the terms of the Project Agreement, CE Casecnan will own and operate the project for a 20-year cooperation period which ends December 11, 2021, after which ownership and operation of the project will be transferred to NIA at no cost on an "as-is" basis. The Casecnan project is dependent upon sufficient rainfall to generate electricity and deliver water. Rainfall varies within the year and from year to year, which is outside the control of CE Casecnan, and impacts the amount of electricity generated and water delivered by the Casecnan project. Rainfall has historically been highest from June through December and lowest from January through May. The contractual terms for variable water delivery fees and variable energy fees can produce variability in revenue between reporting periods. NIA's payment obligation under the project agreement is substantially denominated in United States dollars and is the Casecnan project's sole source of operating revenue.
 
CalEnergy U.S.
 
The subsidiaries comprising the Company's CalEnergy U.S. platform own interests in 15 independent power projects in the United States. The following table presents certain information concerning CalEnergy U.S.'s owned independent power projects as of December 31, 2010:
 
 
Facility
 
 
 
 
 
 
 
 
 
 
 
 
Net or
 
Net
 
 
 
 
 
Power
 
 
 
 
Contract
 
Owned
 
 
 
 
 
Purchase
 
 
Operating
 
Capacity
 
Capacity
 
Energy
 
 
 
Agreement
 
Power
Project
 
(MW)(1)
 
(MW)(1)
 
Source
 
Location
 
Expiration
 
Purchaser(2)
 
 
 
 
 
 
 
 
 
 
 
 
 
CE Generation(3):
 
 
 
 
 
 
 
 
 
 
 
 
Natural-Gas Fired:
 
 
 
 
 
 
 
 
 
 
 
 
Saranac
 
240
 
90
 
Natural Gas
 
New York
 
2011
 
Shell
Power Resources
 
212
 
106
 
Natural Gas
 
Texas
 
2012
 
EDF
Yuma
 
50
 
25
 
Natural Gas
 
Arizona
 
2024
 
SDG&E
Total Natural-Gas Fired
 
502
 
221
 
 
 
 
 
 
 
 
Imperial Valley Projects
 
327
 
164
 
Geothermal
 
California
 
(4)
 
(4)
Total CE Generation
 
829
 
385
 
 
 
 
 
 
 
 
Cordova
 
537
 
537
 
Natural Gas
 
Illinois
 
2019
 
CECG
Wailuku
 
10
 
5
 
Hydroelectric
 
Hawaii
 
2023
 
HELCO
Total CalEnergy U.S.
 
1,376
 
927
 
 
 
 
 
 
 
 
 
(1)    
Facility Net or Contract Capacity represents total plant accredited net generating capacity from the summer of 2010 as approved by MAPP for Cordova and contract capacity for most other projects. Net Owned Capacity indicates CalEnergy U.S.'s ownership of the Facility Net or Contract Capacity.
(2)    
Shell Energy North America (US) L.P. ("Shell"); EDF Trading North America LLC ("EDF"); San Diego Gas & Electric Company ("SDG&E"); Constellation Energy Commodities Group, Inc. ("CECG"); and Hawaii Electric Light Company, Inc. ("HELCO").
(3)    
MEHC has a 50% ownership interest in CE Generation, LLC ("CE Generation") whose subsidiaries currently operate ten geothermal independent power projects in the Imperial Valley of California ("Imperial Valley Projects") and three natural gas-fired independent power proejcts.
(4)    
82% of the Company's interests in the Imperial Valley Projects' Contract Capacity are sold to Southern California Edison Company under long-term power purchase agreements expiring in 2016 through 2026.
 
HomeServices
 
HomeServices, a majority-owned subsidiary of MEHC, is the second largest full-service residential real estate brokerage firm in the United States. In addition to providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services, including mortgage originations through a joint venture; title and closing services; property and casualty insurance; home warranties; relocation services; and other home-related services. HomeServices' real estate brokerage business is subject to seasonal fluctuations because more home sale transactions tend to close during the second and third quarters of the year. As a result, HomeServices' operating results and profitability are typically higher in the second and third quarters relative to the remainder of the year. HomeServices currently operates nearly 300 broker offices in 20 states with over 15,000 sales associates under 22 brand names. The United States residential real estate brokerage business is subject to the general real estate market conditions, is highly competitive and consists of numerous local brokers and agents in each market seeking to represent sellers and buyers in residential real estate transactions.
 

23

 

Other Investments
 
Electric Transmission Joint Ventures
 
In December 2007, approval was received from the Public Utility Commission of Texas ("PUCT") to establish Electric Transmission Texas, LLC ("ETT"), a company owned equally by subsidiaries of American Electric Power Company, Inc. ("AEP") and MEHC, to own and operate electric transmission assets in the Electric Reliability Council of Texas ("ERCOT") footprint. The PUCT order also approved initial rates based on a 9.96% after tax rate of return on equity and a debt to equity capital structure of 60:40. In January 2009, the PUCT voted to assign approximately $800 million of transmission investment in support of Competitive Renewable Energy Zones ("CREZ") to ETT. Presently, ETT has approximately $1.3 billion of potential CREZ projects which, if approved, are forecast for completion between 2012 and 2013. Additionally, AEP subsidiaries have transferred to ETT the obligation to build approximately $1.9 billion of transmission projects within ERCOT which, if approved, are forecast for completion between 2011 and 2020.
 
Electric Transmission America, LLC ("ETA"), is a company owned equally by subsidiaries of AEP and MEHC to pursue transmission opportunities outside of ERCOT. During the second quarter of 2008, ETA formed joint ventures with Westar Energy, Inc. ("Prairie Wind Transmission, LLC") and a subsidiary of OGE Energy Corp. ("Tallgrass Transmission, LLC") to build and own new electric transmission assets within the SPP. The Prairie Wind Transmission, LLC transmission project ("Prairie Wind Project") includes approximately 110 miles of extra-high voltage transmission in Kansas, while the Tallgrass Transmission, LLC transmission project ("Tallgrass Project") includes approximately 170 miles of extra-high voltage in Oklahoma. In December 2008, both projects received the necessary approvals from the FERC, including a return on equity, inclusive of incentives, of 12.8%. The final voltage determination by the SPP for the Prairie Wind Project and the Tallgrass Project is anticipated to occur in early 2011. The completion of the Prairie Wind Project is subject to obtaining final SPP and FERC approvals for transfer from Westar Energy, Inc. to Prairie Wind Transmission, LLC. Completion of the Tallgrass Project is subject to final SPP approval to construct a 765-kilovolt transmission project, along with transfer to Tallgrass Transmission, LLC.
 
In April 2010, the SPP initially approved three additional 345-kilovolt transmission projects, which align with the Prairie Wind Project and the Tallgrass Project. Through its joint venture with ETA, Westar Energy, Inc. has agreed to construct a double-circuit 345-kilovolt transmission project totaling $224 million based on 104 miles versus the original route estimate of 75 miles.
 
Natural Gas Storage Joint Venture
 
In January 2011, approval was received from the Regulatory Commission of Alaska ("RCA") authorizing Cook Inlet Natural Gas Storage Alaska, LLC ("CINGSA"), a wholly-owned subsidiary of Alaska Storage Holdings Company, LLC ("ASHC"), to own, construct and operate an underground natural gas storage facility in south central Alaska. ASHC is owned 70% by ENSTAR Natural Gas Company, an indirect wholly-owned subsidiary of SEMCO ENERGY, Inc, and 30% by Alaska Gas Transmission Company, LLC, an indirect wholly-owned subsidiary of MEHC. CINGSA's gas storage facility will include a natural gas reservoir, five injection/withdrawal wells and associated piping allowing for an initial working gas capacity of 11 Bcf and the ability to deliver gas up to 0.15 Bcf per day. The facility is expected to be in-service by the summer of 2012 at an estimated cost of $180 million. The RCA order also approved the inception rates and terms of service. CINGSA has contracted to provide service to four customers for 20 years.
 
These investments are accounted for under the equity method.
 
Employees
 
As of December 31, 2010, the Company had approximately 15,800 employees, of which approximately 7,200 are covered by union contracts. The majority of the union employees are employed by PacifiCorp and MidAmerican Energy (the "Utilities") and are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Boilermakers and the United Mine Workers of America. These collective bargaining agreements have expiration dates ranging through September 2013. HomeServices' sales associates are independent contractors and not employees.
 

24

 

General Regulation
 
MEHC's subsidiaries are subject to comprehensive governmental regulation, which significantly influences their operating environment, prices charged to customers, capital structure, costs and their 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.
 
Domestic Regulated Public Utility Subsidiaries
 
The Utilities are subject to comprehensive regulation by various federal, state and local agencies. The more significant aspects of this regulatory framework are described below.
 
State Regulation
 
Historically, state regulatory commissions have established retail electric and natural gas 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 cost of sales, 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.
 
The retail electric rates of the Utilities are generally based on the cost of providing traditional bundled services, including generation, transmission and distribution services. Historically, the state regulatory framework in the service areas of the Utilities' systems reflect specified net power costs as part of bundled rates or incorporated net power cost adjustment clauses in the utility's rates and tariffs. In states where net power cost adjustment clauses exist, permitted periodic adjustments to cost recovery from customers provide protection to the Utilities against exposure to changes in net power costs.
 
Except for Oregon, Washington and Illinois, the Utilities have an exclusive right to serve retail customers within their service territories, and in turn, have an obligation to provide service to those customers. Under Oregon law, PacifiCorp has the exclusive right and obligation to provide electricity 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 the Company'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. In Illinois, state law has established a competitive environment so that all Illinois customers are free to choose their service supplier. MidAmerican Energy has an obligation to serve customers at regulated cost-based rates that leave MidAmerican Energy's system, but later choose to return. To date, there has been no significant loss of customers in Illinois.
 

25

 

PacifiCorp
 
In addition to recovery through retail 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 ("UPSC")
 
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 ("OPUC")
 
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 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 ("WUTC")
 
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 ("IPUC")
 
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 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 that allows for an annual update for forecasted and a true-up for prior year's net variable power costs.
 
 
 
 
 
 
 
 
 
Post test-year adjustment mechanism for 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.
 
    

26

 

MidAmerican Energy
 
The IUB has approved over the past several years a series of electric settlement agreements between MidAmerican Energy, the Iowa Office of Consumer Advocate ("OCA") and other intervenors under which MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2014. However, if MidAmerican Energy's Iowa jurisdictional return on equity falls below 10% for 2011 or is projected to fall below 10% for 2013, then MidAmerican Energy may seek a general increase in electric base rates to become effective in 2012 or 2013, respectively. Prior to filing for a general increase in electric rates, MidAmerican Energy is required to conduct 30 days of good faith negotiations with the signatories to the settlement agreements to attempt to avoid a general increase in rates. As a party to the settlement agreements, the OCA has agreed not to request or support any decrease in MidAmerican Energy's Iowa electric base rates to become effective prior to January 1, 2014. The settlement agreements specifically allow the IUB to approve or order electric rate design or cost-of-service rate changes that could result in changes to rates for specific customers as long as such changes do not result in an overall increase in revenue for MidAmerican Energy. Additionally, the settlement agreements also each provide that revenue associated with Iowa retail electric returns on equity within specified ranges will be shared with customers. The following table summarizes the ranges of Iowa electric returns on equity subject to revenue sharing under each of the remaining settlement agreements, the percent of revenue within those ranges to be assigned to customers, and the method by which the liability to customers will be settled.
 
 
 
 
 
Range of
 
 
 
 
 
 
 
 
Iowa Electric
 
Customers'
 
 
 
 
 
 
Return on
 
Share of
 
 
Date Approved
 
Years
 
Equity Subject
 
Revenue
 
Method to be Used to
by the IUB
 
Covered
 
to Sharing
 
Within Range
 
Settle Liability to Customers(1)
 
 
 
 
 
 
 
 
 
October 17, 2003
 
2006 - 2010
 
11.75% - 13%
 
40%
 
Credits against the cost of new generating facilities in Iowa
 
 
 
 
13% - 14%
 
50%
 
 
 
 
 
Above 14%
 
83.3%
 
January 31, 2005
 
2011
 
Same
 
Same
 
Credits to customer bills in 2012
April 18, 2006
 
2012
 
Same
 
Same
 
Credits to customer bills in 2013
July 27, 2007(2), June 16, 2008, August 27, 2008, December 14, 2009
 
2013
 
Same
 
Same
 
Credits against the cost of wind-powered generation projects covered by this agreement
 
(1)    
Total property, plant and equipment, net on the Consolidated Balance Sheets includes revenue sharing credits, net of related amortization, of $316 million and $322 million as of December 31, 2010 and 2009, respectively.
(2)    
If a rate case is filed pursuant to the 10% threshold, as discussed above, the revenue sharing arrangement for 2013 is changed such that the amount to be shared with customers will be 83.3% of revenue associated with Iowa electric operating income in excess of returns on equity allowed by the IUB as a result of the rate case.
 
Iowa law permits rate-regulated utilities to seek ratemaking principles with the IUB prior to the construction of new generating facilities. MidAmerican Energy has ratemaking principles approved by the IUB for a number of generating facilities, the first of which was completed in 2002. The related ratemaking principles approved by the IUB have authorized, upon the establishment of new Iowa electric base rates, a fixed rate of return on equity for the generating facilities covered by each agreement over the regulatory life of those facilities. The settlement agreement approved in December 2009 authorizes, subject to conditions, the construction of up to 1,001 MW (nominal ratings) of new wind-powered generating facilities in Iowa by December 31, 2012. Wind-powered generation projects under this agreement are authorized to earn 12.2% return on equity in any future Iowa rate proceeding. MidAmerican Energy has signed contracts to construct 593 MW of wind-powered generating facilities to be placed into service in 2011 that are subject to this agreement. Additionally, under this agreement, if prior to MidAmerican Energy requesting new Iowa electric base rates, the Iowa electric returns on equity fall below 10% in the years 2011-2012, MidAmerican Energy will be allowed to record revenue sharing to increase to 10% the returns on equity for the wind-powered generating facilities covered by that agreement. Such amounts would increase the related plant balances. As of December 31, 2010, $2.5 billion of property, plant and equipment, net was subject to the agreements at a weighted average return on equity of 11.9%.
 

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MidAmerican Energy is exposed to fluctuations in electric energy costs relating to retail sales in Iowa and Illinois as it does not have energy cost adjustment mechanisms through which fluctuations in electric energy costs can be recovered in those jurisdictions. MidAmerican Energy may not petition for implementation of a fuel adjustment clause in Illinois until November 2011. MidAmerican Energy's cost of gas is collected for each jurisdiction in its gas rates through a uniform PGA, which is updated monthly to reflect changes in actual costs. Subject to prudence reviews, the PGA accomplishes a pass-through of MidAmerican Energy's cost of gas to its customers and, accordingly, has no direct effect on net income. MidAmerican Energy's DSM program costs are collected through separately established rates that are adjusted annually 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 Natural Gas Act ("NGA"), the Energy Policy Act of 2005 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. The Utilities have implemented programs that facilitate compliance with the FERC regulations described below, including having instituted compliance monitoring procedures. MidAmerican Energy is also subject to regulation by the Nuclear Regulatory Commission ("NRC") pursuant to the Atomic Energy Act of 1954, as amended ("Atomic Energy Act"), with respect to its ownership of Quad Cities Station.
 
Wholesale Electricity and Capacity
 
The FERC regulates the Utilities' rates charged to wholesale customers for electricity and transmission capacity and related services. Most of the Utilities' 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 the Utilities' market-based pricing authority. Each utility must demonstrate the lack of market power in order to charge market-based rates for sales of wholesale electricity and electric generation capacity in their respective 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. MidAmerican Energy's next triennial filings are due in June and December 2011. Under the FERC's market-based rules, the Utilities 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. The Utilities are 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"). 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's rules. PacifiCorp has made several required compliance filings in accordance with these rules.
 
Effective September 1, 2009, MidAmerican Energy turned over functional control of its transmission system to the MISO as a transmission-owning member, as approved by the FERC, and no longer offers transmission services. While the MISO is responsible for directing the operation of MidAmerican Energy's transmission system, MidAmerican Energy retains ownership of its transmission assets and, accordingly, is subject to the FERC's reliability standards discussed below. The Utilities transmission business is managed and operated independently from its wholesale marketing business in accordance with the FERC Standards of Conduct.
 

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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. The Utilities must comply with all applicable standards. Compliance, enforcement and monitoring oversight of these standards is carried out by the FERC, the NERC and WECC for PacifiCorp and the Midwest Reliability Organization ("MRO") for MidAmerican Energy. 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 the Company's consolidated financial results.
 
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 16 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.
 
Nuclear Regulatory Commission
 
MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in Quad Cities Station. Exelon Generation, the operator and 75% owner of Quad Cities Station, is under contract with MidAmerican Energy to secure and keep in effect all necessary NRC licenses and authorizations.
 
The NRC regulates the granting of permits and licenses for the construction and operation of nuclear generating stations and regularly inspects such stations for compliance with applicable laws, regulations and license terms. Current licenses for Quad Cities Station provide for operation until December 14, 2032. The NRC review and regulatory process covers, among other things, operations, maintenance, and environmental and radiological aspects of such stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses.
 
Federal regulations provide that any nuclear operating facility may be required to cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility, and the deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy that an emergency preparedness plan for Quad Cities Station has been approved by the NRC. Exelon Generation has also advised MidAmerican Energy that state and local plans relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.
 
MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station through a combination of insurance purchased by Exelon Generation (the operator and joint owner of Quad Cities Station), insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988, which was amended and extended by the Energy Policy Act of 2005. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability.
 
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 about the coal mines and coal processing facilities that PacifiCorp's subsidiaries operate.
 

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Interstate Natural Gas Pipeline Subsidiaries
 
The natural gas pipeline and storage operations of the Company's United States interstate pipeline subsidiaries are regulated by the FERC, which administers, most significantly, the NGA and the Natural Gas Policy Act of 1978. Under this authority, the FERC regulates, among other items, (a) rates, charges, terms and conditions of service and (b) the construction and operation of interstate pipelines, storage and related facilities, including the extension, expansion or abandonment of such facilities.
 
Northern Natural Gas continues to use a modified straight fixed variable rate design methodology, whereby substantially all fixed costs, including a return on invested capital and income taxes, are collected through reservation charges, which are paid by firm transportation and storage customers regardless of volumes shipped. Commodity charges, which are paid only with respect to volumes actually shipped, are designed to recover the remaining, primarily variable, cost. Kern River's rates have historically been set using a "levelized cost-of-service" methodology so that the rate is constant over the contract period. This levelized cost of service has been achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense and return on equity amount decreases.
 
FERC regulations also restrict each pipeline's marketing affiliates' access to certain non-public information regarding their affiliated interstate natural gas transmission pipelines.
 
Interstate natural gas pipelines are also subject to regulations by a federal agency within the United States Department of Transportation ("DOT"), pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended, which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas facilities, and the PSIA, which implemented additional safety and pipeline integrity regulations for high consequence areas. The regulation also requires Northern Natural Gas and Kern River to complete baseline integrity assessments on their pipeline systems by December 17, 2012, and recurring inspections every seven years thereafter. Each pipeline is on schedule to have the initial baseline integrity assessments completed by December 2011.
 
In addition to FERC and DOT regulation, certain operations are subject to oversight by state regulatory commissions.
 
United Kingdom Electricity Distribution Companies
 
Northern Electric and Yorkshire Electricity, as holders of electricity distribution licenses, are subject to regulation by the Gas and Electricity Markets Authority ("GEMA"). GEMA discharges certain of its powers through its staff within Ofgem. Each of fourteen licensed distribution network operators ("DNOs") distributes electricity from the national grid system to end users within their respective distribution service areas.
 
DNOs are subject to price controls, enforced by Ofgem, that limit the revenue that may be recovered and retained from their electricity distribution activities. The regulatory regime that has been applied to electricity distributors in the United Kingdom encourages companies to look for efficiency gains in order to improve profits. The distribution price control formula also adjusts the revenue received by DNOs to reflect a number of factors, including, but not limited to, the rate of inflation (as measured by the retail price index), the quality of service delivered by the licensee's distribution system and system losses (i.e., the difference between the number of units entering and leaving the licensee's system). Currently, price controls are established every five years, although the formula has been, and may be, reviewed at the regulator's discretion. The procedure and methodology adopted at a price control review are at the reasonable discretion of Ofgem. Historically, Ofgem's judgment of the future allowed revenue of licensees has been based upon, among other things:
 
•    
actual operating costs of each of the licensees;
•    
pension deficiency payments of each of the licensees;
•    
operating costs which each of the licensees would incur if it were as efficient as, in Ofgem's judgment, the more efficient licensees;
•    
taxes that each licensee is expected to pay;
•    
regulatory value ascribed to and the allowance for depreciation related to the distribution network assets;
•    
rate of return to be allowed on investment in the distribution network assets by all licensees; and
•    
financial ratios of each of the licensees and the license requirement for each licensee to maintain investment grade status.
 

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The current electricity distribution price control became effective April 1, 2010 and is expected to continue through March 31, 2015. A resetting of the formula requires the consent of the DNO; however, license modifications may be unilaterally imposed by Ofgem without such consent following review by the British Competition Commission. Northern Electric and Yorkshire Electricity each agreed to Ofgem's proposals for the resetting of the formula that commenced April 1, 2010.
 
A number of incentive schemes also operate within the current price control period to encourage DNOs to provide an appropriate quality of service to end users with specified payments to be made for failures to meet prescribed standards of service. The aggregate of these payments is uncapped, but may be excused in certain prescribed circumstances that are generally beyond the control of the DNO.
 
The most recent price control review conducted by Ofgem led to an increase in allowed revenue for Northern Electric and Yorkshire Electricity. As a result, excluding the effects of incentive schemes, it is expected the base allowed revenue of Northern Electric and Yorkshire Electricity will be permitted to increase by approximately 7.7% and 6.5%, respectively, plus inflation (as measured by the United Kingdom's Retail Prices Index) in each of the next five regulatory years that commenced April 1, 2010.
 
Ofgem also monitors DNO compliance with license conditions and enforces the remedies resulting from any breach of condition. License conditions include the prices and terms of service, financial strength of the DNO, the provision of information to Ofgem and the public, as well as maintaining transparency, non-discrimination and avoidance of cross-subsidy in the provision of such services. Ofgem also monitors and enforces certain duties of a DNO set out in the Electricity Act of 1989 including the duty to develop and maintain an efficient, coordinated and economical system of electricity distribution. Under the Utilities Act 2000, the regulators are able to impose financial penalties on DNOs who contravene any of their license duties or certain of their duties under the Electricity Act 1989, as amended, or who are failing to achieve a satisfactory performance in relation to the individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee's revenue.
 
Independent Power Projects
 
Foreign
 
The Philippine Congress has passed the Electric Power Industry Reform Act of 2001 ("EPIRA"), which is aimed at restructuring the Philippine power industry, privatizing the National Power Corporation and introducing a competitive electricity market, among other initiatives. The implementation of EPIRA may impact the Company's future operations in the Philippines and the Philippine power industry as a whole, the effect of which is not yet known as changes resulting from EPIRA are ongoing.
 
Domestic
 
The Cordova, Saranac and Power Resources independent power projects are Exempt Wholesale Generators ("EWG") under the Energy Policy Act while the Yuma, Imperial Valley and Wailuku independent power projects are currently certified as Qualifying Facilities ("QF") under the Public Utility Regulatory Policies Act of 1978 ("PURPA"). Both EWGs and QFs are generally exempt from compliance with extensive federal and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities. In addition, the Cordova, Saranac, Power Resources and Yuma independent power projects have obtained authority from the FERC to sell their power using market-based rates.
 
EWGs are permitted to sell capacity and electricity only in the wholesale markets, not to end users. Additionally, utilities are required to purchase electricity produced by QFs at a price that does not exceed the purchasing utility's "avoided cost" and to sell back-up power to the QFs on a non-discriminatory basis, unless they have successfully petitioned the FERC for an exemption from this purchase requirement. Avoided cost is defined generally as the price at which the utility could purchase or produce the same amount of power from sources other than the QF on a long-term basis. The Energy Policy Act eliminated the purchase requirement for utilities with respect to new contracts under certain conditions. New QF contracts are also subject to FERC rate filing requirements, unlike QF contracts entered into prior to the Energy Policy Act. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates other than the utilities' avoided cost.
 

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Residential Real Estate Brokerage Company
 
HomeServices is regulated by the United States Department of Housing and Urban Development ("HUD"), most significantly under the Real Estate Settlement Procedures Act ("RESPA"), and by state agencies where it operates. RESPA primarily governs the real estate settlement process by mandating all parties fully inform borrowers about all closing costs, lender servicing and escrow account practices, and business relationships between closing service providers and other parties to the transaction. In addition, certain provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Reform Act"), enacted in July 2010 and expected to become effective in July 2011, require real estate mortgage lenders to verify a borrower's ability to repay the underlying loan, which can be achieved within the context of a safe harbor if the mortgage is a "qualifying" mortgage that satisfies specific statutory criteria and the costs of the loan to the borrower do not exceed a mandated threshold percentage. Upon implementation of these provisions, HomeServices and its affiliates could incur additional legal and regulatory compliance costs.
 
Environmental Laws and Regulations
 
The Company is subject to federal, state, local and foreign 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 the Company'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, local and international 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 the Company is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. The Company 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 the Company's forecasted environmental-related capital expenditures.
 
Item 1A.    Risk Factors
 
We and our subsidiaries 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 are a holding company and depend on distributions from subsidiaries, including joint ventures, to meet our obligations.
 
We are a holding company with no material assets other than the equity investments in our subsidiaries and joint ventures, collectively referred to as our subsidiaries. Accordingly, cash flows and the ability to meet our obligations are largely dependent upon the earnings of our subsidiaries and the payment of such earnings to us in the form of dividends or other distributions. Our subsidiaries are separate and distinct legal entities that do not guarantee the payment of any of our obligations or have an obligation, contingent or otherwise, to pay directly, or to make funds available for the payment of, amounts due pursuant to our senior and subordinated debt or our other obligations. Distributions from subsidiaries may also be limited by:
•    
their respective earnings, capital requirements, and required debt and preferred stock payments;
•    
the satisfaction of certain terms contained in financing, ring-fencing or organizational documents; and
•    
regulatory restrictions that limit the ability of our regulated utility subsidiaries to distribute profits.
 

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We are substantially leveraged, the terms of our senior and subordinated debt do not restrict the incurrence of additional debt by us or our subsidiaries, and our senior and subordinated debt is structurally subordinated to the debt of our subsidiaries, each of which could adversely affect our consolidated financial results.
 
A significant portion of our capital structure is comprised of debt, and we expect to incur additional debt in the future to fund acquisitions, capital investments or the development and construction of new or expanded facilities at our subsidiaries. As of December 31, 2010, we had the following outstanding obligations:
•    
senior debt of $5.371 billion;
•    
subordinated debt of $315 million, consisting of $150 million of trust preferred securities held by third parties and $165 million held by Berkshire Hathaway and its affiliates; and
•    
guarantees and letters of credit in respect of subsidiary and equity method investment debt aggregating $82 million.
 
Our consolidated subsidiaries also have significant amounts of outstanding debt, which totaled $13.805 billion as of December 31, 2010. These amounts exclude (a) trade debt, (b) preferred stock obligations, (c) letters of credit in respect of subsidiary debt, and (d) our share of the outstanding debt of our own or our subsidiaries' equity method investments.
 
Given our substantial leverage, we may not have sufficient cash to service our debt, which could limit our ability to finance future acquisitions, develop and construct additional projects, or operate successfully under adverse conditions, including those brought on by declining national and global economies and unfavorable financial markets. Our leverage could also impair our credit quality or the credit quality of our subsidiaries, making it more difficult to finance operations or issue future debt on favorable terms, and could result in a downgrade in debt ratings by credit rating agencies.
 
The terms of our senior and subordinated debt do not limit our ability or the ability of our subsidiaries to incur additional debt or issue preferred stock. Accordingly, we or our subsidiaries could enter into acquisitions, new financings, refinancings, recapitalizations, capital leases or other highly leveraged transactions that could significantly increase our or our subsidiaries' total amount of outstanding debt. The interest payments needed to service this increased level of debt could adversely affect our consolidated financial results. Further, if an event of default accelerates a repayment obligation and such acceleration results in an event of default under some or all of our other debt, we may not have sufficient funds to repay all of the accelerated debt, and the other risks described under "Our Corporate and Financial Structure Risks" may be magnified as well.
 
Because we are a holding company, the claims of our senior and subordinated debt holders are structurally subordinated with respect to the assets and earnings of our subsidiaries. Therefore, the rights of our creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary's creditors and preferred shareholders. In addition, a significant amount of the stock or assets of our operating subsidiaries is directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of our senior and subordinated debt.
 
A downgrade in our credit ratings or the credit ratings of our subsidiaries could negatively affect our or our subsidiaries' access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.
 
Our senior unsecured long-term debt is rated investment grade by various rating agencies. We cannot assure that our senior unsecured long-term debt 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 agreement 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.
 
Similarly, any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause us to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing our and our subsidiaries' liquidity and borrowing capacity.
 

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Most of our subsidiaries' large wholesale customers, suppliers and counterparties require our subsidiaries to have sufficient creditworthiness in order to enter into transactions with them, particularly in the wholesale energy markets. If the credit ratings of our subsidiaries 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 our subsidiaries. Such amounts may be material and may adversely affect our subsidiaries' liquidity and cash flows.
 
Our majority shareholder, Berkshire Hathaway, could exercise control over us in a manner that would benefit Berkshire Hathaway to the detriment of our creditors.
 
Berkshire Hathaway is our majority owner and has control over all decisions requiring shareholder approval, including the election of our directors. In circumstances involving a conflict of interest between Berkshire Hathaway and our creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of our creditors.
 
Our Business Risks
 
Much of our growth has been achieved through acquisitions, and additional acquisitions may not be successful.
 
Much of our growth has been achieved through acquisitions. Future acquisitions may range from buying individual assets to the purchase of entire businesses. We will continue to investigate and pursue opportunities for future acquisitions that we believe may increase shareholder value and expand or complement existing businesses. We may participate in bidding or other negotiations at any time for such acquisition opportunities which may or may not be successful. Any transaction that does take place may involve consideration in the form of cash or debt or equity securities.
 
Completion of any acquisition entails numerous risks, including, among others, the:
•    
failure to complete the transaction for various reasons, such as the inability to obtain the required regulatory approvals, materially adverse developments in the potential acquiree's business or financial condition or successful intervening offers by third parties;
•    
failure of the combined business to realize the expected benefits or to meet regulatory commitments; and
•    
need for substantial additional capital and financial investments.
 
An acquisition could cause an interruption of, or loss of momentum in, the activities of one or more of our businesses. The diversion of management's attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect our combined businesses and financial results and could impair our ability to realize the anticipated benefits of the acquisition.
 
We cannot assure you that future acquisitions, if any, or any related integration efforts will be successful, or that our ability to repay our obligations will not be adversely affected by any future acquisitions.
 
We and our businesses are subject to extensive federal, state, local and foreign legislation and regulation, including numerous environmental, health, safety and other laws and regulations that affect us and our businesses' 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 us and our businesses.
 
We and our businesses are required to comply with numerous federal, state, local and foreign laws and regulations that have broad application to us and our electric and natural gas utilities and interstate pipelines 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 between subsidiaries and 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, the NRC, the MSHA, the DOT, the IUB and the OPUC in the United States, and GEMA, which discharges certain of its powers through its staff within Ofgem, in the United Kingdom.
 

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Significant examples of laws and regulations and other requirements affecting us and our present and future operations include, among others, those described below:
 
•    
Under authority granted to it in the Energy Policy Act of 2005 ("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 holding companies; market transparency for natural gas marketing and transportation; 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 compliance costs on us and our public utility subsidiaries, which could adversely affect our consolidated financial results.
•    
In July 2010, the President signed into law 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 CAIR, 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; regulations that establish standards for air and water quality, wastewater discharges, solid waste, hazardous waste and coal combustion byproducts.
•    
The DOT regulations, effective in 2004, that establish mandatory inspections for all natural gas pipelines in high-consequence areas within 10 years and recurring inspections every seven years thereafter. These regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to life and property.
•    
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.
 
Compliance with applicable laws and regulations generally requires our subsidiaries 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, our subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals for their 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 our subsidiaries from operating their facilities, developing new facilities, expanding existing facilities or favorably locating new facilities. If our subsidiaries fail to comply with any environmental requirements, they 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 our subsidiaries to increase their 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 regulation could result in, but are not limited to, increased retail competition within our subsidiaries' service territories; new environmental requirements, including the implementation of renewable portfolio standards and greenhouse gas emissions ("GHG") 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 subsidiaries' distribution facilities; or a negative impact on our subsidiaries' current transportation and cost recovery arrangements.
 

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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 businesses. 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 businesses. To the extent that our regulated subsidiaries are not allowed by their 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 costs by our regulated subsidiaries is subject to regulatory review and approval, and the inability to recover costs may adversely affect our consolidated financial results.
 
State Rate Proceedings
 
The Utilities establish rates for their 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 the Utilities will be given an opportunity to earn on their sources of capital.
 
In Iowa, MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2014 unless its Iowa jurisdictional electric return on equity falls below 10% as determined by the applicable agreement. MidAmerican Energy expects to continue to make significant capital expenditures to maintain and improve the reliability of its generation, transmission and distribution facilities to reduce emissions and to support new business and customer growth. As a result, MidAmerican Energy's financial results may be adversely affected if it is not able to deliver electricity in a cost-efficient manner and is unable to offset inflation and the cost of infrastructure investments with cost savings or additional sales.
 
In certain states, the Utilities are not permitted to pass through energy, including fuel transportation, cost increases in their 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 the Utilities, 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.

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FERC Jurisdiction
 
The FERC establishes cost-based rates under which PacifiCorp provides transmission services to wholesale markets and retail markets in states that allow retail competition and establishes cost-based rates associated with MidAmerican Energy's transmission facilities, including those used to provide wholesale distribution service. Under the Federal Power Act, the Utilities may be obligated to file for changes, including general rate changes, to their system-wide transmission service rates. The FERC also has responsibility for approving both cost- and market-based rates under which the Utilities sell electricity at wholesale, has licensing authority over most of PacifiCorp's 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 could revoke or restrict the ability of the Utilities to sell electricity at market-based rates, which could adversely affect our consolidated financial results. As a transmission owning member of the MISO, MidAmerican Energy is also subject to MISO-directed modifications of market rules, which are subject to FERC approval and operational procedures. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC's rules and orders.
 
The FERC has jurisdiction over the construction and operation of pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the modification or abandonment of such facilities and rates, charges and terms and conditions of service for the transportation of natural gas in interstate commerce. The FERC was granted expanded market transparency authority under §23 of the NGA, a section added to the NGA by the Energy Policy Act of 2005. The FERC has adopted additional reporting and internet posting requirements for natural gas pipelines and buyers and sellers of natural gas.
 
Rates established for our interstate natural gas transmission and storage operations at Northern Natural Gas and Kern River are also subject to the FERC's regulatory authority. The rates the FERC authorizes these companies to charge their customers may not be sufficient to cover the costs incurred to provide services in any given period. These pipelines, from time to time, have in effect rate settlements approved by the FERC which prevent them or third parties from modifying rates, except for allowed adjustments, for certain periods. These settlements do not preclude the FERC from initiating a separate proceeding under the NGA to modify the rates. It is not possible to determine at this time whether any such actions would be instituted or what the outcome would be, but such proceedings could result in rate adjustments.
 
United Kingdom Electricity Distribution
 
Northern Electric and Yorkshire Electricity, as DNOs and holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of a DNO is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not directly constrain profits from year to year, but is a control on revenue that operates independently of most of the DNO's costs. It has been the practice of Ofgem to review and reset the formula at five-year intervals, although the formula has been, and may be, reviewed at other times at the discretion of Ofgem. The current five-year cost control period became effective on April 1, 2010 and extends through March 31, 2015. A resetting of the formula requires the consent of the DNO; however, license modifications may be unilaterally imposed by Ofgem without such consent following review by the British competition commission. GEMA is able to impose financial penalties on DNOs that contravene any of their electricity distribution license duties or certain of their duties under British law, or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the DNO's revenue. During the term of the price control, additional costs have a direct impact on the financial results of Northern Electric and Yorkshire Electricity.
 
Through our subsidiaries, we are actively pursuing, developing and constructing new or expanded facilities, the completion and expected cost of which are subject to significant risk, and our subsidiaries have significant funding needs related to their planned capital expenditures.
 
Through our subsidiaries, we are actively pursuing, developing and constructing new or expanded facilities. We expect that these subsidiaries will incur substantial annual capital expenditures over the next several years. Expenditures could include, among others, amounts for new generating facilities, electric transmission or distribution projects, environmental control and compliance systems, natural gas storage facilities, new or expanded pipeline systems, as well as the continued maintenance of existing assets.
 

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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 regulated rates or market prices our subsidiaries are able to charge their 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, our subsidiaries depend upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If we do not provide needed funding to our subsidiaries and the subsidiaries are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures.
 
Failure to construct these 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 PacifiCorp is not able to expand its existing generating facilities, it 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 or natural gas in the markets served by our subsidiaries would significantly decrease our operating revenue and adversely affect our consolidated financial results.
 
A sustained decrease in demand for electricity or natural gas in the markets served by our subsidiaries 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 or natural gas, such as the significant adverse changes in the economy and credit markets experienced in 2008 and 2009;
•    
an increase in the market price of electricity or natural gas 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 natural gas or other fuel sources for electricity generation or that limit the use of natural gas or 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.
 
Our subsidiaries 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, the Utilities purchase electricity and fuel in the open market as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market or short-term prices, PacifiCorp or MidAmerican Energy may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when PacifiCorp or MidAmerican Energy is a net seller of electricity in the wholesale market, PacifiCorp or MidAmerican Energy will earn less revenue.
 

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Our subsidiaries are subject to counterparty credit risk, which could adversely affect our consolidated financial results.
 
Our subsidiaries are subject to counterparty credit risk related to contractual obligations with wholesale suppliers, customers and, as is the case for MidAmerican Energy, other participants in organized RTO markets. Adverse economic conditions or other events affecting counterparties with whom our subsidiaries conduct business could impair the ability of these counterparties to timely pay for services. Our subsidiaries depend on these counterparties to remit payments on a timely basis. For example, certain wholesale suppliers, customers and other RTO market participants 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.
 
Transactional activities of MidAmerican Energy and other participants in organized RTO markets are governed by credit policies specified in each respective RTO's governing tariff and related business practices. Credit policies of RTO's, which have been developed through extensive stakeholder participation, generally seek to minimize potential loss in the event of a market participant default without unnecessarily inhibiting access to the marketplace. In the event of a default by a RTO market participant on its market-related obligations, losses are allocated among all other market participants in proportion to each participant's share of overall market activity during the period of time the loss was incurred. Because of this, MidAmerican Energy has potential indirect exposure to every other market participant in the RTO markets where it actively participates, including the MISO, the PJM, and the ERCOT.
 
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 subsidiaries wholesale customers' financial condition deteriorates as a result of economic conditions causing them to be unable to pay, significant losses could result.
 
Our subsidiaries are subject to counterparty performance risk, which could adversely affect our consolidated financial results.
 
Our subsidiaries are subject to counterparty performance risk related to performance of contractual obligations by wholesale suppliers, customers and, as is the case for MidAmerican Energy, other participants in organized RTO markets. Each subsidiary relies 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 the utilities to incur additional expenses to meet customer needs. In addition, when these contracts terminate, the utilities may be unable to purchase the commodities on terms equivalent to the terms of current contracts.
 
Our subsidiaries rely on wholesale customers to take delivery of the energy they have committed to purchase. Failure of customers to take delivery may require these subsidiaries to find other customers to take the energy at lower prices than the original customers committed to pay. If our subsidiaries' wholesale customers are unable to fulfill their obligations, there may be a significant adverse impact on our consolidated financial results.
 
Our subsidiaries are subject to the risk that customers will not renew their contracts or that our subsidiaries will be unable to obtain new customers for expanded capacity, each of which could adversely affect our consolidated financial results.
 
Certain of our subsidiaries are dependent upon a relatively small number of customers for a significant portion of their revenue. For example:
•    
a significant portion of our pipeline subsidiaries' capacity is contracted under long-term arrangements, and our pipeline subsidiaries are dependent upon relatively few customers for a substantial portion of their revenue; and
•    
generally, a single power purchaser takes electricity from each of our Philippine and United States qualifying generating facilities.
 
If our subsidiaries are unable to renew, remarket, or find replacements for their long-term arrangements, our sales volumes and operating revenue would be exposed to reduction and increased volatility. For example, without the benefit of long-term transportation agreements, we cannot assure that our pipeline subsidiaries will be able to transport natural gas at efficient capacity levels. Similarly, without long-term power purchase agreements, we cannot assure that our unregulated power generators will be able to operate profitably. Failure to maintain existing long-term agreements or secure new long-term agreements could adversely affect our consolidated financial results. The replacement of any existing long-term agreements depends on market conditions and other factors that may be beyond our subsidiaries' control.
 

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Disruptions in the financial markets could affect our and our subsidiaries' ability to obtain debt financing, draw upon or renew existing credit facilities, and have other adverse effects on us and our subsidiaries.
 
During 2008 and early 2009, the United States, the United Kingdom 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 and our subsidiaries' ability to access funds on favorable terms or at all. If we or our subsidiaries 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, acquisition financing and our consolidated financial results.
 
Inflation and changes in commodity prices and fuel transportation costs may adversely affect our consolidated financial results.
 
Inflation may affect our businesses by increasing both operating and capital costs. As a result of existing rate agreements and competitive price pressures, our subsidiaries may not be able to pass the costs of inflation on to their customers. If our subsidiaries are unable to manage cost increases or pass them on to their customers, our consolidated financial results could be adversely affected.
 
Some of our subsidiaries' financial results may be adversely affected if they are unable to obtain adequate, reliable and affordable access to electricity transmission service and natural gas transportation.
 
Some of our subsidiaries depend on electricity transmission and natural gas transportation facilities owned and operated by other companies to transport electricity and natural gas to both wholesale and retail markets, as well as natural gas purchased to supply some of our subsidiaries' generating facilities. If adequate transmission and transportation is unavailable, our subsidiaries may be unable to purchase and sell and deliver products. A lack of availability could also hinder our subsidiaries from providing adequate or cost-effective electricity or natural gas to their wholesale and retail electric and natural gas customers and could adversely affect our consolidated financial results.
 
The different regional power markets have varying and dynamic regulatory structures, which could affect our businesses' growth and performance. In addition, the independent system operators who oversee the transmission systems in regional power markets 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 most parts of the United States and other markets in which our subsidiaries 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 other areas, demand for electricity peaks during the winter. In addition, demand for natural gas and other fuels generally peaks during the winter when heating needs are higher. This is especially true in Northern Natural Gas' market area and MidAmerican Energy's retail natural gas business. 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 PacifiCorp's hydroelectric generating facilities, which may result in greater purchases of electricity from the wholesale market or from other sources at market prices. Additionally, the Utilities have added substantial wind-powered generation capacity, which is also a climate-dependent resource.
 
As a result, the overall financial results of our subsidiaries 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 subsidiaries' regulatory environment and contractual agreements, including their ability to recover energy costs, the existence of revenue sharing provisions and terms of the wholesale sale contracts.
 

40

 

Our subsidiaries are subject to operating uncertainties that could adversely affect our consolidated financial results.
 
The operation of complex electric and natural gas utility (including generation, transmission and distribution) systems or interstate natural gas pipeline 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, compressors, pipelines, 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 subsidiaries' revenue or significantly increase their expenses, thereby reducing the availability of distributions to us. For example, if our subsidiaries cannot operate their electricity or natural gas facilities at full capacity due to damage caused by a catastrophic event, their revenue could decrease and their expenses could increase due to the need to obtain energy from more expensive sources. Further, we and our subsidiaries self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs. The scope, cost and availability of our and our subsidiaries' insurance coverage may change, including the portion that is self-insured. Any reduction of our subsidiaries' revenue or increase in their expenses resulting from the risks described above, could adversely affect our consolidated financial results.
 
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 subsidiaries' operations to increased risks. The United States government has issued warnings that energy assets, specifically pipeline, nuclear generation and other electric utility infrastructure are potential targets for terrorist organizations. Political, economic or financial market instability or damage to the operating assets of our subsidiaries, 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 and our subsidiaries 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 and the ability of our subsidiaries to raise capital.
 
MidAmerican Energy is subject to the unique risks associated with nuclear generation.
 
The ownership and operation of nuclear power plants, such as MidAmerican Energy's 25% ownership interest in Quad Cities Station, involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. The prolonged unavailability of Quad Cities Station could materially adversely affect MidAmerican Energy's financial results, particularly when the cost to produce power at the plant is significantly less than market wholesale prices. The following are among the more significant of these risks:
•    
Operational Risk - Operations at any nuclear power plant could degrade to the point where the plant would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased electricity costs to meet supply commitments. Rather than incurring substantial costs to restart the plant, the plant could be shut down. Furthermore, a shut-down or failure at any other nuclear plant could cause regulators to require a shut-down or reduced availability at Quad Cities Station.
•    
Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act applicable regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.
•    
Nuclear Accident Risk - Accidents and other unforeseen problems have occurred at nuclear facilities other than Quad Cities Station, both in the United States and elsewhere. The consequences of an accident can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident could exceed MidAmerican Energy's resources, including insurance coverage.
 

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We own investments and projects located in foreign countries that are exposed to increased economic, regulatory and political risks.
 
We own and may acquire significant energy-related investments and projects outside of the United States. In addition to any disruption in the global financial markets, the economic, regulatory and political conditions in some of the countries where we have operations or are pursuing investment opportunities may present increased risks related to, among others, inflation, foreign currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, expropriation, trade sanctions, contract nullification and changes in law, regulations or tax policy. We may not be capable of either fully insuring against or effectively hedging these risks.
 
We are exposed to risks related to fluctuations in foreign currency exchange rates.
 
Our business operations and investments outside the United States increase our risk related to fluctuations in foreign currency exchange rates, primarily the British pound. Our principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from our foreign operations changes with the fluctuations of the currency in which they transact. We may selectively reduce some foreign currency exchange rate risk by, among other things, requiring contracted amounts be settled in United States dollars, indexing contracts to the United States dollar or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect our consolidated financial results. We attempt, in many circumstances, to structure foreign transactions to provide for payments to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars. We may not be able to obtain sufficient dollars or other hard currency or available dollars may not be allocated to pay such obligations, which could adversely affect our consolidated financial results.
 
Cyclical fluctuations in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.
 
The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions, including the current downturn in the United States housing market, which are beyond HomeServices' control. Any of the following, among others, are examples of items that could have a material adverse effect on HomeServices' businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:
•    
rising interest rates or unemployment rates, including the significant rise in unemployment in the United States which may continue into future periods;
•    
periods of economic slowdown or recession in the markets served, such as the significant adverse changes in the economy experienced in 2008 and 2009;
•    
decreasing home affordability;
•    
lack of available mortgage credit for potential homebuyers, such as the reduced availability of credit generally experienced in 2008 and 2009 and that may continue into future periods;
•    
declining demand for residential real estate as an investment;
•    
nontraditional sources of new competition; and
•    
changes in applicable tax law.
 

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Poor performance of plan and fund investments and other factors impacting the pension and other postretirement benefit plans and nuclear decommissioning 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 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 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, for example, funds dedicated to nuclear decommissioning 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 and our subsidiaries are involved in numerous legal proceedings, the outcomes of which are uncertain and could adversely affect our consolidated financial results.
 
We and our subsidiaries 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 and our subsidiaries 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 or our subsidiaries 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
 
Not applicable.
 
Item 2.    Properties
 
The Company's energy properties consist of the physical assets necessary to support its electricity and natural gas businesses. Properties of the Company's electricity businesses include electric generation, transmission and distribution facilities, as well as coal mining assets that support certain of the Company's electric generating facilities. Properties of the Company's natural gas businesses include natural gas distribution facilities, interstate pipelines, storage facilities, compressor stations and meter stations. In addition to these physical assets, the Company has rights-of-way, mineral rights and water rights that enable the Company to utilize its facilities. It is the opinion of the Company's management that the principal depreciable properties owned by the Company are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all or most of the properties of each of MEHC's subsidiaries (except MidAmerican Energy, Northern Natural Gas, CE Electric UK and CE Casecnan) are pledged or encumbered to support or otherwise provide the security for the related subsidiary debt. For additional information regarding the Company's energy properties, refer to Item 1 of this Form 10-K and Notes 3, 4 and 22 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
 

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The following table summarizes the electric generating facilities of MEHC's subsidiaries as of December 31, 2010:
 
 
 
 
 
 
Facility Net
 
Net Owned
Energy
 
 
 
 
 
Capacity
 
Capacity
Source
 
Entity
 
Location by Significance
 
(MW)
 
(MW)
 
 
 
 
 
 
 
 
 
Coal
 
PacifiCorp and MidAmerican Energy
 
Iowa, Wyoming, Utah, Arizona, Colorado and Montana
 
14,369
 
9,568
 
 
 
 
 
 
 
 
 
Natural gas and other
 
PacifiCorp, MidAmerican Energy and CalEnergy U.S.
 
Utah, Iowa, Illinois, Washington, Oregon, Texas, New York and Arizona
 
4,876
 
4,358
 
 
 
 
 
 
 
 
 
Wind
 
PacifiCorp and MidAmerican Energy
 
Iowa, Wyoming, Washington and Oregon
 
2,324
 
2,316
 
 
 
 
 
 
 
 
 
Hydroelectric
 
PacifiCorp, MidAmerican Energy, CalEnergy Philippines and CalEnergy U.S.
 
Washington, Oregon, The Philippines, Idaho, California, Utah, Hawaii, Montana, Illinois and Wyoming
 
1,320
 
1,293
 
 
 
 
 
 
 
 
 
Nuclear
 
MidAmerican Energy
 
Illinois
 
1,783
 
446
 
 
 
 
 
 
 
 
 
Geothermal
 
PacifiCorp and CalEnergy U.S.
 
California and Utah
 
361
 
198
 
 
 
 
Total
 
25,033
 
18,179
 
The right to construct and operate the Company's electric transmission and distribution facilities and interstate natural gas pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through the exercise of the power of eminent domain. PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River in the United States and Northern Electric and Yorkshire Electricity in the United Kingdom continue to have the power of eminent domain in each of the jurisdictions in which they operate their respective facilities, but the United States utilities do not have the power of eminent domain with respect to Native American tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management.
 
With respect to real property, each of the electric transmission and distribution facilities and interstate natural gas pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the electric generation stations, electric substations, natural gas compressor stations, natural gas meter stations and office sites; and (2) 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 electric transmission and distribution facilities and interstate natural gas pipelines. The Company believes that each of its energy subsidiaries has satisfactory title to all of the real property making up their respective facilities in all material respects.

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Item 3.    Legal Proceedings
 
The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company 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.
 
CalEnergy Philippines
 
In February 2002, pursuant to the share ownership adjustment mechanism in the CE Casecnan shareholder agreement, MEHC's indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. ("LPG"), that MEHC's indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. In 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco (the "Superior Court"), against CE Casecnan Ltd. and MEHC. In November 2010, following a series of Superior Court decisions, CE Casecnan Ltd., MEHC and LPG agreed to a settlement of all issues arising out of the litigation. The settlement resulted in LPG having a 15% ownership interest in CE Casecnan and had no material impact on the Consolidated Financial Statements.
 
In July 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo Ruiz Builders and Developers Group, Inc. ("San Lorenzo") in the District Court of Douglas County, Nebraska (the "District Court"), seeking a declaratory judgment as to San Lorenzo's right to repurchase up to 15% of the shares in CE Casecnan. In January 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it had effectively exercised its option to purchase up to 15% of the shares of CE Casecnan, that it was the rightful owner of such shares and that it was due all dividends previously paid on such shares. In March 2010, a directed verdict was issued in favor of San Lorenzo. In November 2010, CE Casecnan Ltd., MEHC and San Lorenzo agreed to a settlement of all issues arising out of the litigation and executed a Purchase Agreement and Release whereby, among other items, MEHC purchased San Lorenzo's ownership rights.
 
Item 4.    (Removed and Reserved)
 

45

 

PART II
 
Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
MEHC's common stock is owned by Berkshire Hathaway, Mr. Walter Scott, Jr. and certain of his family members and family controlled trusts and corporations, and Mr. Gregory E. Abel, its President and Chief Executive Officer, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. MEHC has not declared or paid any cash dividends on its common stock during the last ten fiscal years and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.
 
For a discussion of unregistered sales of equity securities and regulatory restrictions that limit PacifiCorp's and MidAmerican Energy's ability to pay dividends on their common stock to MEHC, refer to Note 17 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
 
Item 6.    Selected Financial Data
 
The following table sets forth the Company's selected consolidated historical financial data, which should be read in conjunction with the information in Item 7 of this Form 10-K and with the Company'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 the Company's audited historical Consolidated Financial Statements and notes thereto (in millions).
 
Years Ended December 31,
 
2010
 
2009
 
2008
 
2007
 
2006(1)
Consolidated Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Operating revenue
$
11,127
 
 
$
11,204
 
 
$
12,668
 
 
$
12,376
 
 
$
10,301
 
Net income(2)
1,310
 
 
1,188
 
 
1,871
 
 
1,219
 
 
943
 
Net income attributable to noncontrolling interests
72
 
 
31
 
 
21
 
 
30
 
 
27
 
Net income attributable to MEHC(2)
1,238
 
 
1,157
 
 
1,850
 
 
1,189
 
 
916
 
 
 
 
 
 
 
 
 
 
 
 
As of December 31,
 
2010
 
2009
 
2008
 
2007
 
2006(1)
Consolidated Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Total assets
$
45,668
 
 
$
44,684
 
 
$
41,441
 
 
$
39,216
 
 
$
36,447
 
Short-term debt
320
 
 
179
 
 
836
 
 
130
 
 
552
 
Long-term debt, including current maturities:
 
 
 
 
 
 
 
 
 
MEHC senior debt
5,371
 
 
5,371
 
 
5,121
 
 
5,471
 
 
4,479
 
MEHC subordinated debt
315
 
 
590
 
 
1,321
 
 
1,125
 
 
1,357
 
Subsidiary debt
13,805
 
 
13,791
 
 
12,954
 
 
13,097
 
 
11,614
 
Total MEHC shareholders' equity
13,232
 
 
12,576
 
 
10,207
 
 
9,326
 
 
8,011
 
Noncontrolling interests
176
 
 
267
 
 
270
 
 
256
 
 
242
 
 
(1)    
Reflects the acquisition of PacifiCorp on March 21, 2006.
(2)    
Reflects the $646 million after-tax gain recognized on the termination of the Constellation Energy Group, Inc. ("Constellation Energy") merger agreement on December 17, 2008.
 

46

 

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 the Company 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 the Company's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. The Company's actual results in the future could differ significantly from the historical results.
 
Results of Operations
 
Overview
 
Net income attributable to MEHC for 2010 was $1.238 billion, an increase of $81 million, or 7%, compared to 2009. Higher net income at PacifiCorp, MidAmerican Energy and CE Electric UK was partially offset by lower net income at Northern Natural Gas, Kern River, CalEnergy Philippines and CalEnergy U.S. PacifiCorp's net income increased primarily 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 ("AFUDC") and a lower effective income tax rate due to the effects of ratemaking and higher production tax credits, partially offset by lower net wholesale electricity activities, higher depreciation on higher plant placed in-service and higher operating expense. Net income at MidAmerican Energy increased due to higher margins on warmer weather and $21 million of income tax benefits for changes related to the tax capitalization policy for overhead costs and repairs deductions. These improvements were partially offset by higher maintenance costs from plant outages and storm damage. Net income was higher at CE Electric UK due to a $45 million tax free gain on the sale of CE Gas (Australia) Limited, the recognition of deferred income tax benefits totaling $25 million upon enactment of the reduction in the United Kingdom corporate income tax rate from 28% to 27%, a $15 million after-tax impairment of certain Australian hydrocarbon exploration and development assets in 2009 and higher distribution revenue. Net income at Northern Natural Gas and Kern River was lower as a result of lower revenue from less favorable market conditions. CalEnergy Philippines' net income decreased due to the settlement of a noncontrolling interest dispute totaling $38 million and lower rainfall and related lower revenue earned in 2010. Net income at CalEnergy U.S. decreased due to the expiration of a favorable power purchase contract in the second quarter of 2009. The results for 2009 included an after-tax stock-based compensation charge of $75 million as a result of the purchase of shares of common stock that were issued upon the exercise of stock options and an after-tax gain on the Constellation Energy common stock investment of $22 million.
 
Net income attributable to MEHC for 2009 was $1.157 billion, a decrease of $693 million, or 37%, compared to 2008. The results for 2009 included an after-tax stock-based compensation charge of $75 million and an after-tax gain on the Constellation Energy common stock investment of $22 million. The results for 2008 included a $646 million after-tax gain recognized on the termination of the Constellation Energy merger agreement in 2008. Excluding the impact of these items, net income attributable to MEHC increased $6 million for 2009 compared to 2008. Higher net income at PacifiCorp, MidAmerican Funding, CalEnergy Philippines and HomeServices and lower United States income taxes on foreign earnings was partially offset by lower net income at Northern Natural Gas, Kern River and CE Electric UK. Net income was higher at PacifiCorp as a result of higher operating income and a lower effective income tax rate, partially offset by higher interest expense. MidAmerican Funding's net income increased due to lower income taxes, which included income tax benefits of $55 million for repairs deductions, partially offset by lower operating income. MidAmerican Funding's operating income was lower due to lower regulated electric margins and higher depreciation and amortization, partially offset by lower maintenance costs as a result of the storm and flood damage in 2008. Net income was higher at CalEnergy Philippines due to higher rainfall and related revenue earned at the Casecnan project and at HomeServices due to lower office closure costs and other operating expenses. Net income at Northern Natural Gas and Kern River was lower as a result of less favorable market conditions, $30 million of after-tax gains on the sale of certain non-strategic operating assets at Northern Natural Gas in 2008 and a lower customer refund liability in 2008 related to Kern River's 2004 rate case of $26 million. Net income was lower at CE Electric UK due primarily to a stronger United States dollar that reduced net income $33 million, lower distribution revenue and a $15 million after-tax impairment of certain Australian hydrocarbon exploration and development assets recognized in 2009.
 

47

 

Segment Results
 
The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the segment amounts and the consolidated amounts, described as "Corporate/other," relate principally to corporate functions, including administrative costs and intersegment eliminations.
 
Operating revenue and operating income for the Company's reportable segments for the years ended December 31 are summarized as follows (in millions):
 
2010
 
2009
 
Change
 
2009
 
2008
 
Change
Operating revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PacifiCorp
$
4,432
 
 
$
4,457
 
 
$
(25
)
 
(1
)%
 
$
4,457
 
 
$
4,498
 
 
$
(41
)
 
(1
)%
MidAmerican Funding
3,815
 
 
3,699
 
 
116
 
 
3
 
 
3,699
 
 
4,715
 
 
(1,016
)
 
(22
)
Northern Natural Gas
624
 
 
689
 
 
(65
)
 
(9
)
 
689
 
 
769
 
 
(80
)
 
(10
)
Kern River
357
 
 
372
 
 
(15
)
 
(4
)
 
372
 
 
443
 
 
(71
)
 
(16
)
CE Electric UK
802