10-K 1 mehc123109_10k.htm MIDAMERICAN ENERGY HOLDINGS COMPANY FORM 10-K 12-31-09 mehc123109_10k.htm
 
 

 

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, 2009

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 0 No T

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 0 No T

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 T No 0

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes 0 No 0

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. T

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  0
Accelerated filer  0
Non-accelerated filer  T
Smaller reporting company  0

Indicate by check mark whether the registrant is a shell company (as defined in rule 12b-2 of the Exchange Act).Yes 0 No T

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, 2010, 74,859,001 shares of common stock were outstanding.

 
 

 
 
TABLE OF CONTENTS
 
PART I
     
     
PART II
     
     
PART III
     
     
PART IV
     
 
 
 
 

 

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 “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 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 in the jurisdictions in which the Company’s facilities operate;
 
·
changes in federal, state and local governmental, legislative or regulatory requirements, including those pertaining to income taxes, affecting the Company or the electric or gas utility, pipeline or power generation industries;
 
 
·
changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce plant output or delay plant construction;
 
 
·
the outcome of general rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies;
 
 
·
changes in economic, industry or weather conditions, as well as demographic trends, that could affect customer growth and usage or supply of electricity and gas or the Company’s ability to obtain long-term contracts with customers and suppliers;
 
 
·
a high degree of variance between actual and forecasted load and prices that could impact the hedging strategy and costs to balance electricity and load supply;
 
 
·
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 generation 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 MidAmerican Energy Holdings Company’s (“MEHC”) and its subsidiaries’ credit facilities;
 
·
changes in MEHC’s and its subsidiaries’ credit ratings;
 
·
performance of the Company’s generating facilities, including unscheduled outages or repairs;
 
 
·
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 the commodity prices, interest rates and other conditions that affect the fair value of derivative contracts;
 
·
increases in employee healthcare costs and the potential impact of federal healthcare reform legislation;
 
·
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 that could affect brokerage 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;
 
3

 
 
·
the impact of new accounting pronouncements or changes in current accounting estimates and assumptions on consolidated financial results;
 
 
·
the Company’s ability to successfully integrate future acquired operations into its business;
 
 
·
other risks or unforeseen events, including litigation, wars, the effects of 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.
 
 

 

PART I
 
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, 2010, Berkshire Hathaway, Mr. Scott (along with family members and related entities) and Mr. Abel owned 89.5%, 9.7% and 0.8%, respectively, of MEHC’s voting common stock.

On March 1, 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. The Berkshire Equity Commitment expires on February 28, 2011.

The Company’s operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily includes 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 includes Northern Electric Distribution Limited (“Northern Electric”) and Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy Generation-Foreign (which owns a majority interest in the Casecnan project in the Philippines), CalEnergy Generation-Domestic (which owns interests in independent power projects in the United States), and HomeServices of America, Inc. (collectively with its subsidiaries, “HomeServices”). Through these platforms, MEHC 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 97% of the Company’s operating income in 2009 was generated from rate-regulated businesses. As of December 31, 2009, 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 in 2009. These pipeline subsidiaries have approximately 17,000 miles of pipeline and a design capacity of more than 7.0 billion cubic feet (“Bcf”) of natural gas per day. As of December 31, 2009, the Company had interests in approximately 18,000 net owned megawatts (“MW”) of power generation facilities in operation, including approximately 17,000 net owned MW in facilities that are part of the regulated asset base of its electric utility businesses and approximately 1,000 net owned MW in non-utility power generation facilities.

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 under the laws of the state of Delaware and reincorporated in 1999 in Iowa, which resulted in a change of its name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.
 
 

 

PacifiCorp

General

On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of Scottish Power plc for a cash purchase price of $5.12 billion, including direct transaction costs. In connection with MEHC’s acquisition of PacifiCorp, PacifiCorp and MEHC agreed to certain material financial regulatory commitments as discussed in Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

PacifiCorp 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. 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. No single segment of the economy dominates the service territory, which helps mitigate PacifiCorp’s exposure to economic fluctuations. In addition to retail sales, PacifiCorp sells electric energy to other utilities, municipalities and marketers on a wholesale basis.

PacifiCorp’s regulated electric operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The average term of these franchise 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.

Regulated Electric Operations

Customers

The percentages of electricity sold to retail customers by jurisdiction for the years ended December 31 were as follows:

   
2009
   
2008
   
2007
 
                   
Utah
    42 %     42 %     42 %
Oregon
    25       26       26  
Wyoming
    17       17       16  
Washington
    8       7       8  
Idaho
    6       6       6  
California
    2       2       2  
      100 %     100 %     100 %
 
 

 

The percentages of electricity sold to retail and wholesale customers by class of customer, total gigawatt hours (“GWh”) sold and the average number of retail customers for the years ended December 31 were as follows:

   
2009
   
2008
   
2007
 
                   
Residential
    24 %     24 %     24 %
Commercial
    25       24       24  
Industrial
    31       32       31  
Other
    1       1       1  
Total retail
    81       81       80  
Wholesale
    19       19       20  
Total retail and wholesale
    100 %     100 %     100 %
                         
Total GWh sold:
                       
Retail
    52,710       54,362       53,390  
Wholesale
    12,349       12,345       13,724  
Total retail and wholesale
    65,059       66,707       67,114  
                         
Total average retail customers (in millions)
    1.7       1.7       1.7  

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 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 in 2009, resulting in lower retail demands than in 2008.

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 the year ended December 31, 2009, PacifiCorp’s peak demand was 9,420 MW in the summer and 9,336 MW in the winter.
 
 

 

Power and Fuel Supply

PacifiCorp has ownership interests in a diverse portfolio of power generating facilities. The following table presents certain information concerning PacifiCorp’s owned power generating facilities as of December 31, 2009:

               
Facility
       
               
Net Capacity
   
Net MW
 
 
Location
 
Energy Source
 
Installed
   
(MW)(1)
   
Owned(1)
 
COAL:
                       
Jim Bridger
Rock Springs, WY
 
Coal
    1974-1979       2,117       1,411  
Hunter Nos. 1, 2 and 3
Castle Dale, UT
 
Coal
    1978-1983       1,320       1,122  
Huntington
Huntington, UT
 
Coal
    1974-1977       895       895  
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  
                    9,478       6,116  
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       122       122  
Little Mountain
Ogden, UT
 
Natural gas
    1971       14       14  
                    2,469       2,232  
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       53       53  
                    1,158       1,158  
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  
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  
                    929       921  
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
                14,090       10,483  
 

(1)
Facility Net Capacity (MW) represents (except for wind-powered generation 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 MW Owned indicates PacifiCorp’s ownership of Facility Net Capacity.
 

 

The following table shows the percentage of PacifiCorp’s total energy supplied by energy source for the years ended December 31:

   
2009
   
2008
   
2007
 
                   
Coal
    63 %     65 %     64 %
Natural gas
    12       12       11  
Hydroelectric
    5       5       5  
Other(1)
    4       2       1  
Total energy generated
    84       84       81  
Energy purchased - short-term contracts and other
    10       11       14  
Energy purchased - long-term contracts
    6       5       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 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 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 owns coal mines that support its coal-fired generating facilities. These mines supplied 31% of PacifiCorp’s total coal requirements during each of the years ended December 31, 2009, 2008 and 2007. The remaining coal requirements are acquired through long- and short-term third-party contracts. PacifiCorp’s mines are located adjacent to many 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, 2009, based on PacifiCorp’s most recent engineering studies, were as follows (in millions):

Location
 
Plant Served
 
Mining Method
 
Recoverable Tons
             
Craig, CO
 
Craig
 
Surface
 
46
(1)
Huntington & Castle Dale, UT
 
Huntington and Hunter
 
Underground
 
30
(2)
Rock Springs, WY
 
Jim Bridger
 
Surface
 
83
(3)
Rock Springs, WY
 
Jim Bridger
 
Underground
 
50
(3)
           
209
 

(1)
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.
   
(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 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 represents only PacifiCorp’s two-thirds interest in the coal reserves.
 
9

 
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 technologies for controlling sulfur dioxide (“SO2”) 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 remaining generating facilities over their currently expected useful lives.

During the year ended December 31, 2009, PacifiCorp-owned coal-fired generating facilities held sufficient SO2 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, 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 River System, refer to Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

PacifiCorp is pursuing 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 generation facilities and wholesale transactions. PacifiCorp’s wind-powered generating facilities are eligible for federal renewable electricity production tax credits (“PTCs”) for 10 years from the date that the facilities were placed in-service. In February 2009, legislation was passed extending the date by which such facilities must be placed in service to be eligible for PTCs to December 31, 2012.

In addition to its portfolio of generating facilities, PacifiCorp purchases and sells electricity in the wholesale markets to serve its retail load and to enhance the efficient use of its generating capacity over the long-term. PacifiCorp purchases electricity in the wholesale markets when it is more economical than generating it at its own facilities. PacifiCorp sells into the wholesale market available electricity arising from imbalances between generation and retail load obligations, subject to pricing and transmission constraints. Many of PacifiCorp’s purchased electricity contracts have fixed-price components, which provide some protection against price volatility.

Transmission and Distribution

PacifiCorp operates two balancing authority areas in its service territory, a geographic area with electric 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 electric 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 Electric 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. The electric transmission system of PacifiCorp included 15,900 miles of transmission lines and 900 substations as of December 31, 2009.

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, Oregon and the desert Southwest. 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 resource areas, including renewable resources; and (e) improve the flow of electricity throughout PacifiCorp’s six-state service area and the Western United States. Proposed transmission line segments are re-evaluated to ensure maximum benefits and timing before committing to move forward with permitting and construction. The first major transmission segments associated with this plan are expected to be placed in service during 2010, with other segments placed in service through 2019, depending on siting, permitting and construction schedules.
 
10

 
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 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. In May 2009, PacifiCorp filed its 2008 IRP with each of its state commissions. During 2009, PacifiCorp received orders from Washington and Idaho acknowledging that the IRP met their applicable standards and guidelines. In February 2010, the OPUC issued an order acknowledging the 2008 IRP. Acknowledgement of the 2008 IRP by the UPSC is pending.

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. Subject to random prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for the DSM programs through state-specific energy efficiency service charges paid by retail electric customers. In addition to these DSM programs, PacifiCorp has load curtailment contracts with a number of large industrial customers that deliver up to 342 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. In 2009, $106 million was expended on the DSM programs in PacifiCorp’s six-state service area, resulting in an estimated 457,000 megawatt hours (“MWh”) of first-year energy savings and 441 MW of peak load management. Total demand-side load available for control in 2009, including both load management from the large industrial curtailment contracts and DSM programs, was 783 MW.

MidAmerican Energy

General

MidAmerican Energy, an indirect wholly owned subsidiary of MEHC, is a United States regulated electric and 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 electric energy to markets operated by regional transmission organizations (“RTOs”) and electric energy and natural gas to other utilities, municipalities and marketers on a wholesale basis.
 
 
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MidAmerican Energy’s regulated electric and 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 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 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 electric 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 marketers 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:

   
2009
   
2008
   
2007
 
                   
Regulated electric
    47 %     43 %     45 %
Regulated gas
    23       29       28  
Nonregulated and other
    30       28       27  
      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:

   
2009
   
2008
   
2007
 
                   
Iowa
    90 %     90 %     90 %
Illinois
    9       9       9  
South Dakota
    1       1       1  
      100 %     100 %     100 %
 
 
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The percentages of electricity sold to retail and wholesale customers by class of customer, total GWh sold and the average number of retail customers for the years ended December 31 were as follows:

   
2009
   
2008
   
2007
 
                   
Residential
    17 %     17 %     18 %
Commercial
    12       12       12  
Industrial
    26       25       27  
Other
    5       4       5  
Total retail
    60       58       62  
Wholesale
    40       42       38  
Total retail and wholesale
    100 %     100 %     100 %
                         
Total GWh sold:
                       
Retail
    20,185       20,928       20,976  
Wholesale
    13,424       15,133       12,638  
Total retail and wholesale
    33,609       36,061       33,614  
                         
Total average retail customers (in millions)
    0.7       0.7       0.7  

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 in 2009, resulting in lower retail demand than in 2008.

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 June 22, 2009, retail customer usage of electricity caused a record hourly peak demand of 4,299 MW on MidAmerican Energy’s electric system, which is 59 MW greater than the previous peak demand of 4,240 MW set August 13, 2007.
 
 
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Power and Fuel Supply

MidAmerican Energy has ownership interests in a diverse portfolio of power generating facilities. The following table presents certain information concerning MidAmerican Energy’s owned power generating facilities as of December 31, 2009:

               
Facility
       
               
Net Capacity
   
Net MW
 
 
Location
 
Energy Source
 
Installed
   
(MW)(1)
   
Owned(1)
 
COAL:
                       
Walter Scott, Jr. Nos. 1, 2, 3 and 4
Council Bluffs, IA
 
Coal
    1954-2007       1,623       1,156  
George Neal Nos. 1, 2 and 3
Sergeant Bluff, IA
 
Coal
    1964-1975       945       801  
Louisa
Muscatine, IA
 
Coal
    1983       745       656  
Ottumwa
Ottumwa, IA
 
Coal
    1981       710       369  
George Neal No. 4
Salix, IA
 
Coal
    1979       644       261  
Riverside Nos. 3 and 5
Bettendorf, IA
 
Coal
    1925-1961       135       135  
                    4,802       3,378  
NATURAL GAS:
                             
Greater Des Moines
Pleasant Hill, IA
 
Natural gas
    2003-2004       498       498  
Electrifarm
Waterloo, IA
 
Natural gas/oil
    1975-1978       199       199  
Pleasant Hill
Pleasant Hill, IA
 
Natural gas/oil
    1990-1994       162       162  
Sycamore
Johnston, IA
 
Natural gas/oil
    1974       149       149  
River Hills
Des Moines, IA
 
Natural gas
    1966-1967       119       119  
Coralville
Coralville, IA
 
Natural gas
    1970       64       64  
Moline
Moline, IL
 
Natural gas
    1970       64       64  
Parr
Charles City, IA
 
Natural gas
    1969       32       32  
28 portable power modules
Various
 
Oil
    2000       56       56  
                    1,343       1,343  
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       1,740       435  
                               
OTHER:
                             
Moline Nos. 1-4
Moline, IL
 
Mississippi River
    1941       3       3  
                               
Total Available Generating Capacity
                9,172       6,443  

(1)
Facility Net Capacity (MW) represents (except for wind-powered generation facilities, which are nominal ratings) total plant accredited net generating capacity from the summer of 2009 based on MidAmerican Energy’s accreditation approved by the Mid-Continent Area Power Pool (“MAPP”). The 2009 summer accreditation of the wind-powered generation facilities in service at that time totaled 297 MW and is considerably less than the nominal ratings due to the varying nature of wind. Net MW Owned indicates MidAmerican Energy’s ownership of Facility Net Capacity.
 
 
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The following table shows the percentage of MidAmerican Energy’s total energy supplied by energy source for the years ended December 31:

   
2009
   
2008
   
2007
 
                   
Coal
    60 %     59 %     56 %
Nuclear
    11       10       10  
Natural gas
    1       3       3  
Other(1)
    10       6       5  
Total energy generated
    82       78       74  
Energy purchased - short-term contracts and other
    11       14       19  
Energy purchased - long-term contracts
    7       8       7  
      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 may place more reliance on other energy sources. For example, when wind conditions are favorable, MidAmerican Energy can generate more electricity using its low cost wind-powered generating facilities. When 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 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 2010-2011 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, 2009, MidAmerican Energy-owned generating facilities held sufficient allowances for SO2 and nitrogen oxide (“NOx”) 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”). 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 a small amount 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 the Quad Cities Station is replaced every 24 months. MidAmerican Energy has been advised by Exelon Generation that the following requirements for the Quad Cities Station can be met under existing supplies or commitments: uranium requirements through 2012 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.
 
 
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MidAmerican Energy has the largest owned wind-powered generation fleet of any United States electric utility and believes wind-powered generation offers a viable, economical and environmentally prudent means of supplying electricity. Additionally, MidAmerican Energy has regulatory approval to construct up to 1,001 MW (nominal ratings) of additional wind-powered generation in Iowa through 2012, the last 251 MW of which is subject to confirmation from the Iowa Utilities Board (“IUB”). MidAmerican Energy has further committed that not greater than 500 MW will be placed in service during 2012. Wind projects under this agreement are authorized to earn a 12.2% return on equity in any future Iowa rate proceeding. 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 are eligible for federal renewable electricity PTCs for 10 years from the date the facilities were placed in-service. In February 2009, legislation was passed extending the date by which such facilities must be placed in service to be eligible for PTCs to December 31, 2012.

In addition to its portfolio of generating facilities, MidAmerican Energy purchases and sells electricity and ancillary services in the wholesale markets to serve its retail load and to enhance the efficient use of its generating capacity over the long-term. MidAmerican Energy purchases electricity in the wholesale markets when it is more economical than generating it at its own facilities. MidAmerican Energy sells into the wholesale market available electricity arising from imbalances between generation and retail load obligations, subject to pricing and transmission constraints.

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 service 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 Midwest Independent Transmission System Operator, Inc. (“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. RTOs and several other major transmission-owning utilities in the region as a result of transmission interconnections MISO has with such organizations. The electric transmission and distribution systems of MidAmerican Energy included 2,300 miles of transmission lines and 400 substations as of December 31, 2009.

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, transports it from the production areas to MidAmerican Energy’s service territory under contracts with interstate natural gas pipelines, stores it in various storage facilities to manage fluctuations in system demand and seasonal pricing, and delivers it to customers through MidAmerican Energy’s distribution system. MidAmerican Energy sells natural gas and transportation services to end-use customers and natural gas to other utilities, municipalities and marketers. MidAmerican Energy also transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. During 2009, 46% of the total natural gas delivered through MidAmerican Energy’s system for end-use customers was under natural gas transportation service.
 
 
16 

 

The percentages of natural gas sold to retail customers by jurisdiction for the years ended December 31 were as follows:

   
2009
   
2008
   
2007
 
                   
Iowa
    76 %     77 %     77 %
South Dakota
    13       12       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:

   
2009
   
2008
   
2007
 
                   
Residential
    42 %     42 %     40 %
Commercial(1)
    22       21       19  
Industrial(1)
    4       4       4  
Total retail
    68       67       63  
Wholesale(2)
    32       33       37  
      100 %     100 %     100 %
                         
Total Dth of natural gas sold (000’s)
    121,355       132,172       124,391  
Total Dth of transportation service (000’s)
    69,642       68,782       65,876  
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 whose natural gas usage is principally for heating. Industrial customers are business customers whose principal natural gas usage is for their manufacturing processes.
   
(2)
Wholesale generally includes other utilities, municipalities and marketers to whom natural gas is sold at wholesale for eventual resale to end-use customers.

There are seasonal variations in MidAmerican Energy’s 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 of 1,147,599 Dth. This peak-day delivery consisted of approximately 75% traditional retail sales service and 25% transportation service of customer-owned gas. As of January 31, 2010, MidAmerican Energy’s 2009/2010 winter heating season peak-day delivery of 1,058,757 Dth was reached on January 4, 2010. This 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 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 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 natural gas customers while maintaining system reliability, including a geographically diverse supply portfolio from producers and third party marketers, the use of storage gas and peak-shaving facilities, sharing arrangements to share savings and costs with customers and short- and long-term financial and physical gas purchase contracts.

MidAmerican Energy has rights to firm natural gas pipeline capacity to transport natural gas to its service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Northern Natural Gas, an affiliate company.
 
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MidAmerican Energy utilizes leased gas storage to meet peak day 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”) plants and one propane-air plant to meet peak day demands in the winter. The storage and peak shaving facilities reduce MidAmerican Energy’s dependence on natural gas purchases during the volatile winter heating season. MidAmerican Energy can deliver approximately 50% of its design day sales requirements from its storage and peak shaving supply sources.

Natural gas property consists primarily of natural gas mains and services pipelines, 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 pipelines as of December 31, 2009.

Demand-side Management

MidAmerican Energy has provided a comprehensive set of DSM programs to its Iowa electric and gas customers since 1990, its Illinois electric and gas customers since 2008 and, beginning in 2009, its South Dakota gas customers. 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. 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. In 2009, $63 million was expended on the DSM programs resulting in an estimated 240,000 MWh of electric and 474,000 Dth of gas first-year energy savings and an estimated 304 MW of electric and 6,691 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 marketers, 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 2008 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 eighth-largest as measured by throughput. In 2009, Northern Natural Gas’ transportation and storage revenue accounted for 94% of its total operating revenue, of which 85% was generated from reservation charges under firm transportation and storage contracts. About 57% of the 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 6% of its 2009 operating revenue. Northern Natural Gas’ transportation and 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 from key production areas, including the Hugoton, Permian, Anadarko and Rocky Mountain basins in its Field Area and, through interconnections with other pipelines, the Rocky Mountain, Williston and Canadian basins in its Market Area. In each of these areas, Northern Natural Gas has numerous interconnecting receipt and delivery points.
 
18

 
Northern Natural Gas transports natural gas primarily to end-users and local distribution markets in the Market Area. In 2009, 70% of Northern Natural Gas’ transportation and storage revenue was generated from Market Area customer transportation contracts. Northern Natural Gas directly serves 76 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, 2009, 93% of Northern Natural Gas’ customers’ entitlement in the Market Area is contracted beyond 2010, and 50% is contracted beyond 2015. The weighted average remaining contract term for Northern Natural Gas’ Market Area transportation contracts is approximately six years as of December 31, 2009.

Northern Natural Gas’ Northern Lights expansion project is concentrated primarily in the Twin Cities area of Minnesota and is expected to serve incremental load due to residential and commercial growth in natural gas demand, gas-fired power plants and ethanol facilities. Northern Natural Gas has commitments to two of its largest customers to meet minimum levels of incremental capacity requests through 2026. The project is designed to deliver volumes needed to meet those commitments. The project is expected to add 650,000 Dth per day of capacity to its Market Area by the end of 2010, of which 610,000 Dth per day has been added as of December 31, 2009. In total, the Northern Lights expansion project is expected to require more than $340 million in capital expenditures through 2010, of which $320 million has been incurred through December 31, 2009.

In the Field Area, customers that contract for firm transportation capacity, or entitlement, consist primarily of marketers, power generators and producers. The majority of this entitlement is contracted on a short-term basis, principally by marketers and producers. Northern Natural Gas expects short-term contracting to continue in the foreseeable future to support Market Area customers’ demand requirements. Supplies from the Field Area have historically been less expensive than the supply alternatives available from other sources that bring Canadian supply to Northern Natural Gas’ system in the Market Area. 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. In 2009, 16% of Northern Natural Gas’ transportation and storage revenue was generated from Field Area customer transportation contracts.

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 cycle capacity of 73 Bcf and over 2.0 Bcf of peak day 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. In 2009, 14% of Northern Natural Gas’ transportation and storage revenue was generated from storage services.

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. 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 (“Colorado Interstate”) and Rockies Express Pipeline, 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. 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.
 
 
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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 1,755,575 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 (77% as of December 31, 2009) and Mojave Pipeline Company (“Mojave”), a wholly owned subsidiary of El Paso Corporation, as tenants-in-common. Kern River’s ownership percentage in the common facilities will increase or decrease pursuant to the capital contributions made by the respective joint owners. Kern River has exclusive rights to 1,570,600 Dth per day of the common facilities’ capacity, and Mojave has exclusive rights to 400,000 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 system operations, 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 will be placed in-service when final approval is received from the Pipeline and Hazardous Materials Safety Administration. Approval is expected in 2010. The project will add an additional 145,000 Dth per day of capacity by increasing the maximum allowable operating pressure from 1,200 pounds per square inch (“psig”) to 1,333 psig. Kern River will begin construction of its Apex Expansion project after it receives approval from the FERC. The project is expected to be placed in-service in 2011 and will add an incremental 266,000 Dth per day of capacity.

Kern River has year-round long-term firm natural gas transportation service agreements for 1,755,575 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 almost seven years. Shippers on the pipeline include major oil and gas companies or affiliates of such companies, electric 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, 2009, 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.

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 its relatively high load factor throughput, 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. In recent years, Northern Natural Gas has retained and signed long-term contracts with customers such as CenterPoint Energy Minnesota Gas, Xcel Energy Inc. (“Xcel Energy”) and Metropolitan Utilities District, which in some cases, because of competition, resulted in lower reservation charges relative to the contracts being replaced.

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.
 
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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 through its Northern Lights expansion project. 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 in recent years has attracted considerable expansion of pipeline capacity serving markets other than California and Nevada.

In 2009, Northern Natural Gas had two customers that each accounted for greater than 10% of its revenue and its ten largest customers accounted for 55% of its system-wide transportation and storage revenue. Northern Natural Gas has agreements to retain the vast majority of its two largest 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, Tees Valley 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 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 volume that is 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 33% of the total combined distribution revenue of Northern Electric and Yorkshire Electricity in 2009.

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 and Leeds.

The price controlled revenue of the regulated distribution companies are set out in the special conditions of the licenses of the companies. The licenses are enforced by the regulator, the Office of Gas and Electricity Markets (“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, 2005 and will be replaced by a new price control commencing April 1, 2010.

Electricity distributed to end-users and the total number of end-users as of and for the years ended December 31 were as follows:

   
2009
   
2008
   
2007
 
Electricity distributed (in GWh):
                 
Northern Electric
    15,567       16,563       16,977  
Yorkshire Electricity
    22,642       24,047       24,281  
      38,209       40,610       41,258  
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, 2009, 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 Generation-Foreign

The CalEnergy Generation-Foreign platform consists of MEHC’s indirect majority ownership of the Casecnan project, which is a 150 MW combined irrigation and hydroelectric power generation 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 and is subject to disputes with two initial minority shareholders with respect to ownership rights. Refer to Item 3 of this Form 10-K for additional information.

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.
 
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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 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.

On June 25, 2006, the Upper Mahiao project’s and on July 25, 2007, the Malitbog and Mahanagdong projects’ separate 10-year cooperation periods ended and the projects, representing a total of 485 MW of net owned contract capacity, were transferred to PNOC-Energy Development Corporation by the Company at no cost on an “as-is” basis.

CalEnergy Generation-Domestic

The subsidiaries comprising the Company’s CalEnergy Generation-Domestic platform own interests in 15 non-utility power projects in the United States. The following table sets out certain information concerning CalEnergy Generation-Domestic’s non-utility power projects in operation as of December 31, 2009:

   
Facility
                         
   
Net or
               
Power
       
   
Contract
   
Net
         
Purchase
       
Operating
 
Capacity
   
MW
 
Energy
     
Agreement
   
Power
 
Project
 
(MW)(1)
   
Owned(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
    2011    
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  
Wailuku River
 
Hawaii
    2023    
HELCO
 
Total CalEnergy Generation-Domestic
    1,376       927                        

(1)
Facility Net or Contract Capacity (MW) represents total plant accredited net generating capacity from the summer of 2009 as approved by MAPP for Cordova and contract capacity for most other projects. Net MW Owned indicates CalEnergy Generation-Domestic’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 Company (“HELCO”).
   
(3)
MEHC has a 50% ownership interest in CE Generation, LLC (“CE Generation”) whose subsidiaries currently operate ten geothermal plants in the Imperial Valley of California (“Imperial Valley Projects”) and three natural gas-fired power generation facilities.
   
(4)
82% of the Company’s interests in the Imperial Valley Projects’ Contract Capacity (MW) are sold to Southern California Edison Company under long-term power purchase agreements expiring in 2016 through 2026.
 
 
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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, primarily through joint ventures; title and closing services; property and casualty insurance; home warranties; 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 300 broker offices in 20 states with about 16,000 sales associates under 21 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.

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. The CREZ projects are currently pending final project specific, PUCT approval before construction begins. Additionally, AEP subsidiaries have transferred to ETT the obligation to build approximately $1.5 billion of transmission projects within its ERCOT footprint. Substantially all of these projects are scheduled for completion by the end of 2017. The majority of these projects are in the process of being reviewed for possible endorsement by ERCOT or negotiated with generation customers. Construction will begin only after these steps are complete.

The City of Garland has appealed the PUCT’s decision on assignment of CREZ which could impact the level and timing of capital expenditures. In June 2009, the Texas legislature passed and the Texas governor signed a new law that clarifies the PUCT’s authority to grant certificates of convenience and necessity (“CCN”) to transmission-only utilities such as ETT. ETT filed for a new, conditional CCN under this law in September 2009 to the PUCT for approval. A final order on this matter is expected in 2010.

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. and a subsidiary of OGE Energy Corp. to build and own new electric transmission assets within the SPP. The Westar Energy, Inc. project includes approximately 110 miles of extra-high voltage transmission in Kansas, while the OGE Energy Corp. project includes approximately 170 miles of extra-high voltage in Oklahoma. Both projects received necessary approval from FERC in December 2008 including a return on equity, inclusive of incentives, of 12.3%. The completion of these projects is subject to obtaining SPP and necessary state regulatory approvals.

The investments are accounted for under the equity method.

Employees

As of December 31, 2009, the Company had approximately 16,300 employees, of which approximately 7,400 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.
 
 
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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 state utility commissions, federal agencies, and other state and local regulatory agencies. The more significant aspects of this regulatory framework are described below.

State Regulation

Historically, state utility commissions have established rates on a cost-of-service basis, which are designed to allow a utility an opportunity to recover its costs of providing services and to earn a reasonable return on its investments. A utility’s cost-of-service generally reflects its allowed operating expenses, including cost of sales, operation and maintenance expense, depreciation expense and income and other tax expense, reduced by wholesale electric sales and other revenue. State utility 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 utility commissions typically have the authority to review and change rates on their own initiative. States 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 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 reflected specified power and fuel costs as part of bundled rates or incorporated power or fuel adjustment clauses in the utility’s rates and tariffs. In states where power and fuel adjustment clauses exist, permitted periodic adjustments to cost recovery from customers provide protection to utilities against exposure to power and fuel cost changes.

Except for Oregon, Washington and Illinois, the Utilities have an exclusive right to serve electricity customers within their service territories and, in turn, have the obligation to provide electric service to those customers. Under Oregon law, PacifiCorp has the exclusive right and obligation to provide electric distribution services to all customers within its allocated service territory; however, nonresidential customers have the right to choose alternative electricity service suppliers. The impact of these programs on 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 Washington Utilities and Transportation Commission (“WUTC”). In Illinois, a law that changed how and what electric services are regulated by the Illinois Commerce Commission (“ICC”) transitioned traditional electric services to a competitive environment so that all Illinois customers are free to choose their electricity 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 general rates, PacifiCorp also achieves recovery of certain costs through various adjustment mechanisms as summarized below.

State Regulator
 
Base Rate Test Period
 
Adjustment Mechanism(1)
Utah Public Service Commission (“UPSC”)
 
Forecasted or historical with known and measurable changes(2)
 
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, a mechanism for annual rate adjustments for 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(2)
 
Power cost adjustment mechanism based on forecasted net power costs, later trued-up to actual net power costs, subject to dead bands and customer sharing.
 
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 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, a mechanism that allows for rate adjustments outside of the context of a traditional 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 to actual and forecasted 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 and forecasted test periods. The WPSC has not issued a final ruling on its preference between historical or forecasted test periods.

PacifiCorp’s energy efficiency program costs are collected through separately established rates that are adjusted periodically based on actual and expected costs, as approved by the respective state utility commission.
 
 
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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, unless its Iowa jurisdictional electric return on equity for any twelve-month period covered by the applicable agreement falls below 10%, computed as prescribed in each respective agreement. 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 generation plant 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)
 
2013
 
Same
 
Same
 
Credits against the cost of wind-powered generation projects covered by this agreement

(1)
Revenue sharing credits recorded against the cost of new generation totaled $354 million as of December 31, 2009.
   
(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.

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. In Illinois, base rates were adjusted to include recoveries at average 2004/2005 energy cost levels beginning January 1, 2007, and regulatory approval is required for any base rate changes. MidAmerican Energy may not petition for reinstatement of the Illinois fuel adjustment clause until November 2011.

 
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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 energy efficiency program costs are collected through separately established rates that are adjusted annually based on actual and expected costs, as approved by the respective state utility commission. As such, recovery of energy efficiency 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 and other federal statutes. The FERC regulates rates for interstate sales of electricity in wholesale markets; transmission of electric power, including pricing and expansion of transmission systems; electric system reliability; utility holding companies; accounting; securities issuances; and other matters, including construction and operation of hydroelectric projects. 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 the operation of the 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 electric 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 next triennial filing is due in June 2010 and MidAmerican Energy’s 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 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, meaning that all potential customers are provided an equal opportunity to access the transmission system. 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 Company’s transmission businesses are managed and operated independently from its wholesale marketing businesses in accordance with the FERC Standards of Conduct.

In February 2007, the FERC adopted a final rule in Order No. 890 designed to strengthen the pro-forma OATT by providing greater specificity and increasing transparency. The most significant revisions to the pro forma OATT relate to the development of more consistent methodologies for calculating available transfer capability, changes to the transmission planning process, changes to the pricing of certain generator and energy imbalances to encourage efficient scheduling behavior and changes regarding long-term point-to-point transmission service, including the addition of conditional firm long-term point-to-point transmission service, and generation re-dispatch. The FERC has issued rules through a set of subsequent orders clarifying Order No. 890. As a transmission provider with an OATT on file with the FERC, PacifiCorp is required to comply with the requirements of the new rule. PacifiCorp made its first compliance filing amending its OATT in July 2007. The FERC has continued to issue rules through a set of subsequent orders clarifying Order No. 890. In response to these various orders, PacifiCorp has made several required compliance filings.
 
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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 WECC for PacifiCorp and the Midwest Reliability Organization (“MRO”) for MidAmerican Energy. During 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 in principle with the WECC. The results of the settlement will not have a material impact on the Company’s consolidated financial results. In September 2008, the MRO issued a public report to the NERC stating MidAmerican Energy was found to be 100% compliant with all standards addressed in the latest MRO on-site audit conducted in August 2008.

Hydroelectric Relicensing – Klamath River Hydroelectric Facilities

PacifiCorp’s Klamath hydroelectric system is the only 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 the 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 the 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 the Quad Cities Station through a combination of insurance purchased by Exelon Generation (the operator and joint owner of the 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.
 
 
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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, regulations and state regulatory agencies. The Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”), enacted in June 2006, amended previous mine safety and health laws to improve mine safety and health and accident preparedness. PacifiCorp is required to develop a written emergency response plan specific to each underground mine it operates. These plans must be reviewed by MSHA every six months. It also requires every mine to have at least two rescue teams located within one hour, and it limits the legal liability of rescue team members and the companies that employ them. The MINER Act also increases civil and criminal penalties for violations of federal mine safety standards and gives MSHA the ability 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 the penalties or fines.

United States 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 United States 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. In an order issued in November 2009 pursuant to Section 5 of the NGA, the FERC is investigating the reasonableness of Northern Natural Gas’ rates. 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 decreases.

FERC regulations also restrict each pipeline’s marketing affiliates’ access to United States interstate pipeline natural gas transmission customer data and place certain conditions on services provided by the United States interstate pipelines to their marketing affiliates.

United States 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. Each pipeline is on schedule to have this work 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 use customers within their respective distribution service areas.
 
 
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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 UK 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 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). The price controls that apply until March 31, 2010, also vary allowed revenue by reference to the change in the number of units distributed, but this will cease commencing April 1, 2010. 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 an investment grade status.
 
The current electricity distribution price control became effective in April 2005 and will continue through March 2010. The most recent review will result in a new formula that will commence April 1, 2010 and is expected to continue in force for five years. 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 have each agreed to Ofgem’s proposals for the resetting of the formula commencing 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, Northern Electric is expected to be permitted to increase its regulated revenue by 7.7% (plus inflation as measured by the United Kingdom’s Retail Prices Index) in each of the next five regulatory years commencing April 1, 2010. Yorkshire Electricity may increase its regulated revenue by 6.5% (plus inflation) in each year over the same period.

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.
 
 
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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

Both the Cordova and Power Resources Projects are Exempt Wholesale Generators (“EWG”) under the Energy Policy Act while the remaining domestic 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, Cordova, Yuma Cogeneration Associates, Saranac Power Partners, L.P. and Power Resources Limited 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 for QFs of greater than 20 MW. 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.

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 November 2008, as a result of a rulemaking proceeding initiated earlier in the year the HUD adopted a new RESPA rule that updated procedures and forms, enhanced notice and communication requirements and further clarified the scope of business relationships among closing service providers. The Company does not believe the new rule will materially affect HomeServices’ ability to do business.

Environmental Laws and Regulation

The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, renewable portfolio standards, climate change, 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 the Liquidity and Capital Resources section of Item 7 of this Form 10-K for additional information regarding environmental laws and regulation and the Company’s forecasted environmental-related capital expenditures.
 
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Risk Factors
 
We are subject to numerous risks, including, but not limited to, those set forth 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 securities 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 which limit the ability of our regulated utility subsidiaries to distribute profits.
 
We are substantially leveraged, the terms of our senior and subordinated indebtedness do not restrict the incurrence of additional indebtedness by us or our subsidiaries, and our senior and subordinated debt is structurally subordinated to the indebtedness of our subsidiaries, each of which could adversely affect our consolidated financial results.

A significant portion of our capital structure is debt and we expect to incur additional indebtedness in the future to fund acquisitions, capital investments or the development and construction of new or expanded facilities. As of December 31, 2009, we had the following outstanding obligations:
 
·
senior indebtedness of $5.371 billion;
 
·
subordinated indebtedness of $590 million, consisting of $237 million of trust preferred securities held by third parties and $353 million held by Berkshire Hathaway and its affiliates; and
 
·
guarantees and letters of credit in respect of subsidiary and equity investment indebtedness aggregating $91 million.
 
Our consolidated subsidiaries also have significant amounts of outstanding indebtedness, which totaled $13.791 billion as of December 31, 2009. These amounts exclude (a) trade debt, (b) preferred stock obligations, (c) letters of credit in respect of subsidiary indebtedness, and (d) our share of the outstanding indebtedness of our own or our subsidiaries’ equity 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, such as those experienced in the United States in 2008 and 2009. 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 indebtedness 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 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 indebtedness 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 indebtedness, we may not have sufficient funds to repay all of the accelerated indebtedness, and the other risks described under “Our Corporate and Financial Structure Risks” may be magnified as well.
 
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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.

Most of our large customers, suppliers and counterparties require sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If our credit ratings or the credit ratings of our subsidiaries were to decline, especially below investment grade, financing costs and borrowing 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 transactions with us or our subsidiaries.

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.
 
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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.

Our regulated businesses are subject to extensive regulations and legislation that affect their operations and costs. These regulations and laws are complex, dynamic and subject to change.

Our businesses are subject to numerous regulations and laws enforced by regulatory agencies. In the United States, these regulatory agencies include, among others, the FERC, the EPA, the NRC, and the DOT. In addition, our domestic utility subsidiaries are subject to state utility regulation in each state in which they operate. In the United Kingdom, these regulatory agencies include, among others, GEMA, which discharges certain of its powers through its staff within Ofgem.

Regulations affect almost every aspect of our business and limit our ability to independently make and implement management decisions regarding, among other items, business combinations; constructing, acquiring or disposing of operating assets; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; engaging in transactions between our domestic utilities and other subsidiaries and affiliates; and paying dividends. Regulations are subject to ongoing policy initiatives, and we cannot predict the future course of changes in regulatory laws, regulations and orders, or the ultimate effect that regulatory changes may have on us. However, such changes could adversely affect our consolidated financial results through higher capital expenditures and operating costs and an overall change in how we operate our business. For example, such changes could result in, but are not limited to, increased retail competition within our subsidiaries’ service territories; new environmental requirements, including the implementation of RPS and greenhouse gas (“GHG”) emission reduction goals; the issuance of stricter air quality standards and the implementation of energy efficiency mandates; the acquisition by a municipality of our subsidiaries’ distribution facilities (by a vote in favor of a public utility district under state law or by condemnation, negotiation or legislation under state law); or a negative impact on our subsidiaries’ current transportation and cost recovery arrangements, including income tax recovery.

Federal and state energy regulation is one of the more challenging aspects of managing utility operations. The United States Congress and federal policy makers, with President Obama’s support, are considering comprehensive climate change legislation, such as the American Clean Energy and Security Act of 2009 (“Waxman-Markey bill”) that was passed by the United States House of Representatives in June 2009. In addition to a federal RPS, which would require utilities to obtain a portion of their energy from certain qualifying renewable sources and energy efficiency measures, the bill requires a reduction in GHG emissions beginning in 2012, with emission reduction targets of 3% below 2005 levels by 2012; 17% below 2005 levels by 2020; 42% below 2005 levels by 2030; and 83% below 2005 levels by 2050 under a “cap and trade” program. In September 2009, a similar bill was introduced in the United States Senate by Senators Barbara Boxer and John Kerry, which would require an initial reduction in GHG emissions beginning in 2012 with emission reduction targets consistent with the Waxman-Markey bill, with the exception of the 2020 target, which requires 20% reduction below 2005 levels. In December 2009, the EPA issued a proposed determination that carbon dioxide (“CO2”) emissions can be regulated under the Clean Air Act and stated its intent to issue regulations limiting the release of CO2 from sources including fossil fuel based electric generating facilities.

The impact of pending federal, regional, state and international accords, legislation or regulation related to climate change, including new laws, regulations or rules limiting GHG emissions could have a material adverse impact on us. Our regulated subsidiaries have significant coal-fired generating facilities that will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be quantified at this time. In addition to unknown factors, known factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the cost, availability and effectiveness of emission control technology; the price and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. To the extent that our regulated subsidiaries are not allowed by their regulators to recover or cannot otherwise recover the costs to comply with climate change requirements, these requirements could have a material adverse impact 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 sales volumes, this could have a material adverse impact on our consolidated financial results.
 
 
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New and expanded regulations imposed by policy makers, court systems, and industry restructuring have imposed changes on the industry. The following are examples of recent changes to our regulatory environment that have impacted us:
 
·
Energy Policy Act of 2005 - The United States Energy Policy Act impacts many segments of the energy industry. The United States Congress granted the FERC additional authority in the Energy Policy Act which expanded its role from a regulatory body to an enforcement agency. To implement the law, the FERC adopted new regulations and issued regulatory decisions addressing electric system reliability, electric transmission planning, operation, expansion and pricing, regulation of utility holding companies, market transparency for natural gas marketing and transportation, and enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation for non-compliance with regulations in either the electric or natural gas areas of the FERC’s jurisdiction. The FERC has essentially completed its implementation of the Energy Policy Act, and the emphasis of its recent decisions is on reporting and compliance. In that regard, the FERC has vigorously exercised its enforcement authority by imposing significant civil penalties for violations of its rules and regulations. In addition, as a result of past events affecting electric reliability, the Energy Policy Act requires federal agencies, working together with non-governmental organizations charged with electric reliability responsibilities, to adopt and implement measures designed to ensure the reliability of electric transmission and distribution systems. Since the adoption of the Energy Policy Act, the FERC has approved numerous electric reliability and critical infrastructure protection standards developed by the NERC. A transmission owner’s reliability compliance issues with these and future standards could result in financial penalties. In FERC Order No. 693, the FERC implemented its authority to impose penalties of up to $1 million per day per violation for failure to comply with electric reliability standards. The adoption of these and future electric reliability standards has imposed more comprehensive and stringent requirements on us and our public utility subsidiaries, which has increased compliance costs. It is possible that the cost of complying with these and any additional standards adopted in the future could adversely affect our consolidated financial results.
 
·
FERC OrdersThe FERC has issued a series of orders to encourage competition in natural gas markets, the expansion of existing pipelines and the construction of new pipelines and to foster greater competition in wholesale power markets by reducing barriers to entry in the provision of transmission service. As a result of FERC Order Nos. 636 and 637, in the natural gas markets, LDCs and end-use customers have additional choices in this more competitive environment and may be able to obtain service from more than one pipeline to fulfill their natural gas delivery requirements. Any new pipelines that are constructed could compete with our pipeline subsidiaries to service customer needs. Increased competition could reduce the volumes of gas transported by our pipeline subsidiaries or, in the absence of long-term fixed rate contracts, could force our pipeline subsidiaries to lower their rates to remain competitive. This could adversely affect our pipeline subsidiaries’ financial results. In FERC Order Nos. 888, 889 and 890, the FERC required electric utilities to adopt a proforma OATT, by which transmission service would be provided on a just, reasonable and not unduly discriminatory or preferential basis. The rules adopted by these orders promote transparency and consistency in the administration of the OATT, increase the ability of customers to access new generating resources and promote efficient utilization of transmission by requiring an open, transparent and coordinated transmission planning process. Together with the increased reliability standards required of transmission providers, the costs of operating the transmission system and providing transmission service have increased and, to the extent such increased costs are not recovered in rates charged to customers, they could adversely affect our consolidated financial results.
 
·
Hydroelectric Relicensing – Currently, we are engaged in the FERC relicensing process for our Klamath hydroelectric system, for which the operating license has expired. We are currently operating under an annual license. Through a settlement signed in February 2010 with relicensing stakeholders, disposition of the relicensing process and a path toward dam transfer and removal by a third party may occur as an alternative to relicensing. Hydroelectric relicensing is a political and public regulatory process involving sensitive resource issues and uncertainties. We cannot predict with certainty the requirements (financial, operational or otherwise) that may be imposed by relicensing, the economic impact of those requirements, and whether new licenses will ultimately be issued or whether PacifiCorp will be willing to meet the relicensing requirements to continue operating its hydroelectric generating facilities. Loss of hydroelectric resources or additional commitments arising from relicensing could adversely affect our consolidated financial results.
 
 
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Our subsidiaries are subject to numerous environmental, health, safety and other laws, regulations and other requirements that could adversely affect our consolidated financial results.

Operational Standards

Our subsidiaries are subject to numerous environmental, health, safety and other laws, regulations and other requirements affecting many aspects of their present and future operations, including, among others:
 
·
the EPA’s Clean Air Interstate Rule (“CAIR”), which established cap-and-trade programs to reduce SO2 and NOx emissions starting in 2009 to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards;
 
·
the implementation of federal and state RPS;
 
·
other laws or regulations that establish or could establish standards for GHG emissions, water quality, wastewater discharges, solid waste and hazardous waste;
 
·
the DOT regulations, effective in 2004, that establish mandatory inspections for all natural gas transmission pipelines in high-consequence areas within 10 years. 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; and
 
·
the provisions of the MINER Act to improve underground coal mine safety and emergency preparedness.
 
These and related laws, regulations and orders generally require our subsidiaries to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals.

Compliance with environmental, health, safety, and other laws, regulations and other requirements 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 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 all applicable environmental requirements, they may be subject to penalties and fines or other sanctions. The costs of complying with current or new environmental, health, safety and other laws, regulations and other requirements could adversely affect our consolidated financial results. Not being able to operate existing facilities or develop new electric generating facilities to meet customer energy needs could require our subsidiaries to increase their purchases of power from the wholesale markets which could increase market and price risks and adversely affect our consolidated financial results.

Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide, such as the December 2009 climate conference in Copenhagen, Denmark, to reduce greenhouse gases such as CO2 (a by-product of burning fossil fuels) and methane (the primary component of natural gas). These actions could result in increased costs to (a) operate and maintain our facilities, (b) install new emission controls on our facilities and (c) administer and manage compliance with any GHG emissions program, such as through the purchase of emission credits as may be required. These actions could also increase the demand for natural gas, causing increased natural gas prices, thereby adversely affecting our operations. See the preceding risk titled, “Our regulated businesses are subject to extensive regulations and legislation that affect their operations and costs. These regulations and laws are complex, dynamic and subject to change” for more detail on the United States’ efforts and a discussion of the Waxman-Markey bill.

Site Cleanup and Contamination

Environmental, health, safety and other laws, regulations and requirements also impose obligations to remediate contaminated properties or to pay for the cost of such remediation, often by parties that did not actually cause the contamination. Our subsidiaries are generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of their assets, including power generating facilities and electric and natural gas transmission and distribution assets that our subsidiaries have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with acquisitions, we or our subsidiaries may obtain or require indemnification against some environmental liabilities. If our subsidiaries incur a material liability, or the other party to a transaction fails to meet its indemnification obligations, our subsidiaries could suffer material losses. Our subsidiaries have established reserves to recognize their estimated obligations for known remediation liabilities, but such estimates may change materially over time. PacifiCorp is required to fund its portion of the costs of mine reclamation at its coal mining operations, which include principally site restoration. Also, MidAmerican Energy is required to fund its portion of the costs of decommissioning the Quad Cities Station when it is retired from service, which may include site remediation or decontamination. In addition, future events, such as changes in existing laws or policies or their enforcement, or the discovery of currently unknown contamination, may give rise to additional remediation liabilities that may be material.
 
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Recovery of costs by our regulated subsidiaries is subject to regulatory review and approval, and the inability to recover costs may adversely affect their financial results.

Public Utility Subsidiaries – 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 additional uncertainty associated with the approval proceedings.

Each state sets retail rates based in part upon the state utility 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 will not be sufficient to cover those costs. Each state utility commission generally sets rates based on a test year established in accordance with that commission’s policies. The test year data adopted by a regulatory commission may create a lag between the incurrence of a cost and its recovery in rates. They also decide the allowed levels of expense and investment that they deem are just and reasonable in providing service. The state regulatory commissions 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 for any twelve-month period falls below 10%. 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 cost increases in their electric rates without a general rate case. Any significant increase in fuel costs for electricity generation or purchased power costs could have a negative impact on PacifiCorp or MidAmerican Energy, 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.

Public Utility Subsidiaries – 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. The FERC also has responsibility for approving both cost- and market-based rates under which both these companies 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 may (pursuant to pending or future proceedings) revoke or restrict the ability of our public utility subsidiaries 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.
 
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Interstate Pipelines

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, including revisions to the FERC Form No. 2 and the adoption of FERC Form 552, an annual report of aggregate volumes of gas sales and purchases at wholesale. The FERC has closed an inquiry into the methodology for rate recovery by natural gas pipelines of fuel and lost and unaccounted-for gas costs and while not taking any action, the FERC expressed its support for an amendment to the NGA that would provide it with the authority to order refunds in connection with its review of interstate pipeline transportation rates.

Rates established for our United States 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, as it did in November 2009 when it initiated a Section 5 proceeding to investigate the reasonableness of Northern Natural Gas’ rates. It is not possible to determine at this time whether any additional such actions would be instituted or what the outcome of the ongoing proceeding or any other 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, 2005 and is due to be replaced by a new formula effective April 1, 2010. 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 have each agreed to Ofgem’s proposals for the resetting of the formula commencing April 1, 2010. 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 continuing to develop and construct 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 electric generating facilities, electric transmission or distribution projects, environmental control and compliance systems, gas storage facilities, new or expanded pipeline systems, as well as the continued maintenance of the installed asset base.

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.
 
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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 electric 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 electricity procurement contracts or procure electricity at more volatile and potentially higher prices in the spot markets to support growing retail loads.

A significant decrease in demand for natural gas or electricity in the markets served by our subsidiaries’ pipeline and gas distribution systems would significantly decrease our operating revenue and thereby adversely affect our business and consolidated financial results.

A sustained decrease in demand for natural gas or electricity 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, including the significant adverse changes in the economy and credit markets in 2008 and 2009 that may continue into future periods;
 
·
an increase in the market price of natural gas or electricity or a decrease in the price of other competing forms of energy;
 
·
efforts by customers, legislators and regulators to reduce their 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 the fuel source 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, counterparty performance risk and other risks associated with wholesale energy markets.

In general, wholesale market risk is the risk of adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas and coal, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. Wholesale electricity prices may be influenced by several factors, such as the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric and wind-powered generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth and changes in technology. Volumetric changes are caused by unanticipated changes in generation availability or changes in customer loads due to the weather, electricity prices, the economy, regulations or customer behavior. The Utilities purchase electricity and fuel in the open market or pursuant to short-term or variable-priced contracts 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.

The Utilities are also exposed to risks related to performance of contractual obligations by wholesale suppliers, customers and other participants in organized RTO markets. Each utility 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.

The Utilities rely on wholesale customers to take delivery of the energy they have committed to purchase and to pay for the energy on a timely basis. Failure of customers to take delivery may require these subsidiaries to find other customers to take the energy at lower prices than the original customers committed to pay. At certain times of the year, prices paid by the Utilities for energy needed to satisfy their customers’ energy needs may exceed the amounts they receive through rates. If our wholesale customers are unable to pay us for energy or fulfill their obligations, there may be a significant adverse impact on our cash flows. If the strategy used to minimize these risk exposures is ineffective or if PacifiCorp’s or MidAmerican Energy’s wholesale customers’ financial condition deteriorates as a result of recent economic conditions causing them to be unable to pay, significant losses could result.

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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 MISO, PJM, and ERCOT.

The deterioration in the credit quality of certain wholesale suppliers and customers and other RTO market participants of the Utilities as a result of the adverse economic conditions experienced in 2008 and 2009 could have an adverse impact on their ability to perform their contractual obligations, which in turn could have an adverse impact on our consolidated financial results.

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 who were able to find financing, and in other cases resulted in the unavailability of certain types of debt financing. In 2008 and 2009, the United States federal government enacted legislation in an attempt to stabilize the economy, increased the federal deposit insurance, invested billions of dollars in financial institutions and took other steps to infuse liquidity into the economy. The United States federal government Troubled Asset Relief Program (“TARP”) and current accommodative monetary stance in the United States and most other industrialized countries have reduced liquidity concerns, relieved credit constraints and provided many financial institutions with the ability to strengthen their financial position. However, there is no certainty that the credit environment will improve and it is also possible that financial institutions may not be able to provide previously arranged funding under revolving credit facilities or other arrangements like those that we and our subsidiaries have established as potential sources of liquidity. It is also difficult to predict how the financial markets will react to the United States federal government’s 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, consolidated financial condition and results of operations.

Our subsidiaries are exposed to credit risk of counterparties with whom they do business, and the failure of their significant customers to perform under or to renew their contracts, or failure to obtain new customers for expanded capacity, 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;
 
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The Utilities rely on their wholesale customers to fulfill their commitments and pay for energy delivered to them on a timely basis;
 
·