SEC Info - Berkshire Hathaway Energy Co

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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, 2006

[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from ______ to _______

Commission	Registrant’s Name, State of Incorporation,	IRS Employer
File Number	Address and Telephone Number	Identification No.

001-14881	MIDAMERICAN ENERGY HOLDINGS COMPANY	94-2213782
	(An Iowa Corporation)
	666 Grand Avenue, PO Box 657
	Des Moines, Iowa 50306-0657
	515-242-4300

N/A
(Former name or former address, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act: N/A

Securities registered pursuant to Section 12(g) of the Act: N/A

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes མ 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 T No ྑ

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 o No T

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, or a non-accelerated filer. See the definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer o

Non-accelerated filer T

Indicate by check mark whether the registrant is a shell company (as defined in rule 12b-2 of the Exchange Act).Yes མ 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, 2007, 74,489,001 shares of common stock were outstanding.

TABLE OF CONTENTS

PART I

Item 1.	Business	4
Item 1A.	Risk Factors	38
Item 1B.	Unresolved Staff Comments	49
Item 2.	Properties	49
Item 3.	Legal Proceedings	49
Item 4.	Submission of Matters to a Vote of Security Holders	52

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	53
Item 6.	Selected Financial Data	53
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	74
Item 8.	Financial Statements and Supplementary Data	78
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	131
Item 9A.	Controls and Procedures	131
Item 9B.	Other Information	131

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	132
Item 11.	Executive Compensation	133
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	148
Item 13.	Certain Relationships and Related Transactions, and Director Independence	150
Item 14.	Principal Accountant Fees and Services	151

PART IV

Item 15.	Exhibits and Financial Statement Schedules	153
Signatures		158
Exhibit Index		160

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 the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements 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 are located;

·	financial condition and creditworthiness of significant customers and suppliers;

·	changes in governmental, legislative or regulatory requirements affecting the Company or the electric or gas utility, pipeline or power generation industries;

·	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;

·	changes in prices and availability for both purchases and sales of wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have significant impact on energy costs;

·	changes in business strategy or development plans;

·	availability, terms and deployment of capital;

·	performance of generation facilities, including unscheduled outages or repairs;

·	risks relating to nuclear generation;

·	the impact of derivative instruments used to mitigate or manage interest rate risk and volume and price risk and changes in the commodity prices, interest rates and other conditions that affect the value of the derivatives;

·	the impact of increases in healthcare costs, changes in interest rates, mortality, morbidity and investment performance on pension and other postretirement benefits expense, as well as the impact of changes in legislation on funding requirements;

·	changes in MEHC’s and its subsidiaries’ credit ratings;

·	unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future generation plants and infrastructure additions;

·	the impact of new accounting pronouncements or changes in current accounting estimates and assumptions on financial results;

·	changes in, and compliance with, environmental laws, regulations, decisions and policies that could increase operating and capital improvement costs, reduce plant output and/or delay plant construction;

·	the Company’s ability to successfully integrate PacifiCorp’s operations into the Company’s business;

·	other risks or unforeseen events, including wars, the effects of terrorism, embargos and other catastrophic events; and

·	other business or investment considerations that may be disclosed from time to time in filings with the SEC or in other publicly disseminated written documents.

Further details of the potential risks and uncertainties affecting the Company are described in MEHC’s filings with the SEC, including Item 1A. Risk Factors 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

Item 1. Business.

General

MidAmerican Energy Holdings Company (“MEHC”) is a holding company owning subsidiaries (together with MEHC, the “Company”) that are principally engaged in energy businesses. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”). The balance of MEHC’s common stock is owned by a private investor group comprised of Mr. Walter Scott, Jr. (along with family members and related entities), who is a member of MEHC’s Board of Directors, Mr. David L. Sokol, MEHC’s Chairman and Chief Executive Officer, and Mr. Gregory E. Abel, MEHC’s President and Chief Operating Officer. As of December 31, 2006, Berkshire Hathaway, Mr. Scott (along with family members and related entities), Mr. Sokol and Mr. Abel owned 87.8%, 11.0%, 0.9% and 0.3%, respectively, of MEHC’s voting common stock and held diluted ownership interests of 86.6%, 10.8%, 1.6% and 1.0%, respectively.

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 minimum 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 us in exchange for additional shares of MEHC’s common stock. The Berkshire Equity Commitment will expire 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 includes the subsidiaries owning the Malitbog and Mahanagdong projects (collectively, the “Leyte Projects”) and the Casecnan Project), CalEnergy Generation-Domestic (which includes the subsidiaries owning interests in independent power projects in the United States), and HomeServices of America, Inc. (collectively with its subsidiaries, “HomeServices”). Refer to Note 24 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional segment information regarding the Company’s platforms. Through these platforms, the Company owns and operates an electric utility company in the Western United States, a combined electric and natural gas utility company in the Midwestern United States, two natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international 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 89% of the Company’s operating income in 2006 was generated from rate-regulated businesses. As of December 31, 2006, MEHC’s electric and natural gas utility subsidiaries served approximately 6.2 million electricity customers and end users and approximately 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 2006. These pipeline subsidiaries have approximately 17,600 miles of pipeline in operation and a design capacity of 6.7 billion cubic feet of natural gas per day. As of December 31, 2006, the Company had interests in approximately 16,400 net owned MW of power generation facilities in operation and under construction, including approximately 15,000 net owned MW in facilities that are part of the regulated asset base of its electric utility businesses and approximately 1,400 net owned MW in non-utility power generation facilities. Substantially all of the Company’s non-utility power generation facilities have long-term contracts for the sale of energy and/or capacity from the facilities.

MEHC’s principal executive offices are located at 666 Grand Avenue, PO Box 657, Des Moines, Iowa 50306-0657 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, at which time it changed its name from CalEnergy Company, Inc. to MidAmerican Energy Holdings Company.

In this annual report, references to “U.S. dollars,” “dollars,” “$” or “cents” are to the currency of the United States, references to “pounds sterling,” “£,” “sterling,” “pence” or “p” are to the currency of Great Britain and references to “pesos” are to the currency of the Philippines. References to kW means kilowatts, MW means megawatts, GW means gigawatts, kWh means kilowatt hours, MWh means megawatt hours, GWh means gigawatt hours, kV means kilovolts, MMcf means million cubic feet, Bcf means billion cubic feet, Tcf means trillion cubic feet and Dth means decatherms or one million British thermal units.

PacifiCorp

On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp, a public utility company, from a wholly owned subsidiary of Scottish Power plc (“ScottishPower”) for a cash purchase price of $5,120.1 million, which includes direct transaction costs. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006.

In the first quarter of 2006, the state commissions in all six states where PacifiCorp has retail customers approved the sale of PacifiCorp to MEHC. The approvals were conditioned on a number of regulatory commitments. Refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of these regulatory commitments.

General

PacifiCorp serves approximately 1.7 million regulated retail electric customers in its service territories in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The combined service territory’s diverse regional economy ranges from rural, agricultural and mining areas to urbanized manufacturing and government service centers. No single segment of the economy dominates the service territory, which mitigates PacifiCorp’s exposure to economic fluctuations. In the eastern portion of the service territory, mainly consisting of Utah, Wyoming and southeast Idaho, the principal industries are manufacturing, health services, recreation and mining or extraction of natural resources. In the western portion of the service territory, mainly consisting of Oregon, southeastern Washington and northern California, the principal industries are agriculture, technology and manufacturing, with forest products, food processing and primary metals being the largest industrial sectors. In addition to retail sales, PacifiCorp sells electric energy to other utilities, marketers and municipalities. These sales are referred to as wholesale sales.

PacifiCorp’s regulated electric operations are conducted under franchise agreements, certificates, permits and licenses obtained from state and local authorities. The average term of these franchise agreements is approximately 30 years, although their terms range from five-years to indefinite.

On May 10, 2006, the PacifiCorp Board of Directors elected to change PacifiCorp’s fiscal year-end from March 31 to December 31. Therefore, in the following pages, the nine-month period ended December 31, 2006, information covers the transition period beginning April 1, 2006 and ending December 31, 2006.

Electric Operations

Customers

The percentages of electricity sold (measured in MWh) to retail and wholesale customers, by class of customer, and the total number of retail customers (in millions) as of and for the nine months ended December 31 and as of and for the years ended March 31 were as follows:

	December 31,			March 31,
	2006			2006			2005

Residential		22.6	%		23.4	%		22.7	%
Commercial		23.8			23.5			23.5
Industrial		31.9			31.1			31.3
Wholesale		20.9			21.1			21.4
Other		0.8			0.9			1.1
		100.0	%		100.0	%		100.0	%

Total retail customers		1.7			1.6			1.6

The percentages of retail electric operating revenue, by jurisdiction, for the nine months ended December 31 and for the years ended March 31 were as follows:

	December 31,			March 31,
	2006			2006			2005

Utah		41.9	%		40.9	%		40.6	%
Oregon		28.5			29.3			29.3
Wyoming		13.4			13.3			13.6
Washington		7.7			8.4			8.0
Idaho		6.2			5.7			6.1
California		2.3			2.4			2.4
		100.0	%		100.0	%		100.0	%

Customer demand is typically highest in the summer across PacifiCorp’s service territory when air-conditioning and irrigation systems are heavily used. Customer demand also peaks in the winter months primarily due to heating requirements in the western portion of PacifiCorp’s service territory as well as the eastern portion due to other electricity demands.

For residential customers, within a given year, weather conditions are the dominant cause of usage variations from normal seasonal patterns. Strong Utah residential growth over the last several years and increasing installations of central air conditioning systems are contributing to increased summer peak growth.

Power and Fuel Supply

The estimated percentages of PacifiCorp’s total energy requirements supplied by its generation plants and through long- and short-term contracts or spot market purchases for the nine months ended December 31 and for the years ended March 31 were as follows:

	December 31,			March 31,
	2006			2006			2005

Coal		62.4	%		67.5	%		67.3	%
Natural gas		7.0			3.8			4.2
Hydroelectric		5.7			6.2			4.6
Wind		0.2			0.2			0.2
Other		0.5			0.5			0.6
Total energy generated		75.8			78.2			76.9
Energy purchased-long-term contracts		7.4			8.8			7.9
Energy purchased-short-term contracts and spot market		16.8			13.0			15.2
		100.0	%		100.0	%		100.0	%

The percentage of PacifiCorp’s energy requirements generated by its plants will vary from year to year and is determined by factors such as planned and unplanned outages, the availability and price of coal and natural gas, weather including precipitation and snowpack levels, environmental considerations and the market price of electricity.

As of December 31, 2006, PacifiCorp had an estimated 241.7 million tons of recoverable coal reserves in mines owned or leased by it. During the nine months ended December 31, 2006, these mines supplied 31.1% of PacifiCorp’s total coal requirements, compared to 32.3% during the year ended March 31, 2006 and 28.6% during the year ended March 31, 2005. The remaining coal requirements are acquired through other long- and short-term contracts. PacifiCorp’s mines are located adjacent to many of its coal-fired generating plants, which significantly reduces overall transportation costs included in fuel expense. In an effort to lower costs and obtain better quality coal, the Jim Bridger mine is in the process of developing an underground mine to access 57.0 million tons of PacifiCorp’s coal reserves. Underground mine developments and limited coal production began during the year ended March 31, 2005 and sustained operations are expected to begin by March 31, 2007.

Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves. Recoverable coal reserves at December 31, 2006, based on PacifiCorp’s most recent engineering studies, were as follows (in millions):

Location	Plant Served	Mining Method	Recoverable Tons


Craig, CO	Craig	Surface	47.7	⁽¹⁾
Huntington & Castle Dale, UT	Huntington and Hunter	Underground	50.3	⁽²⁾
Rock Springs, WY	Jim Bridger	Surface/Underground	143.7	⁽³⁾
			241.7

⁽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 21.4%.

⁽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 subsidiary of PacifiCorp, has a two-thirds interest in the joint venture. The Jim Bridger mine is in the process of converting from surface operation to primarily underground operation, while currently continuing production at its surface operations.

PacifiCorp believes that the coal reserves available to the Craig, Huntington, Hunter and Jim Bridger plants, together with coal available under both long- and short-term contracts with external suppliers, will be substantially sufficient to provide these plants with fuel for their current economically useful lives. Recoverability by surface mining methods typically ranges from 90.0% to 95.0%. Recoverability by underground mining techniques ranges from 50.0% to 70.0%. Most of PacifiCorp’s coal reserves are held pursuant to leases from the federal government through the Bureau of Land Management and from certain states and private parties. The leases generally have multi-year terms that may be renewed or extended only with the consent of the lessor and require payment of rents and royalties.

PacifiCorp also uses natural gas as fuel for intermediate and peak demand electric generation. Oil and natural gas are also used for igniter fuel, and to fuel generation for transmission support and standby purposes. These sources are presently in adequate supply and available to meet PacifiCorp’s needs.

PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses from the FERC with terms of 30 to 50 years. Several of PacifiCorp’s long-term operating licenses have expired. Hydroelectric facilities operating under expired licenses operate under temporary licenses issued by the FERC annually until new long-term operating licenses are issued. The amount of electricity PacifiCorp is able to generate from its hydroelectric facilities depends on a number of factors, including snowpack in the mountains upstream of its hydroelectric facilities, reservoir storage, precipitation in its watersheds, plant availability and restrictions imposed by oversight bodies due to competing water management objectives. When these factors are favorable, PacifiCorp can generate more electricity using its hydroelectric facilities. When these factors are unfavorable, PacifiCorp must increase its reliance on more expensive thermal plants and purchased electricity.

In addition to its portfolio of generating plants, PacifiCorp purchases electricity in the wholesale markets to meet its retail load and long-term wholesale obligations, for system balancing requirements and to enhance the efficient use of its generating capacity over the long-term. PacifiCorp enters into wholesale purchase and sale transactions to balance its supply when actual retail loads are higher or lower than expected, subject to pricing and transmission constraints. Generation varies with the levels of outages, hydroelectric conditions and transmission constraints. Retail load varies with the weather, distribution system outages, consumer trends and the level of economic activity. In addition, PacifiCorp purchases electricity in the wholesale markets when it is more economical than generating it at its own plants. Many of PacifiCorp’s purchased electricity contracts have fixed-price components, which provide some protection against price volatility.

Historically, PacifiCorp has been able to purchase electricity from utilities in the Western United States for its own requirements. These purchases are conducted through PacifiCorp and third-party transmission systems, which connect with market hubs in the Pacific Northwest to provide access to primarily hydroelectric generation and in the Southwestern United States to provide access to primarily fossil-fuel generation. The transmission system is available for common use consistent with open-access regulatory requirements.

PacifiCorp manages certain risks relating to its natural gas supply requirements and its wholesale transactions by entering into various financial derivative instruments, including forward purchases and sales, futures, swaps and options. Refer to Item 7A. Quantitative and Qualitative Disclosures About Market Risk for a discussion of commodity price risk and derivative instruments.

The following table sets out certain information concerning PacifiCorp’s power generating facilities as of December 31, 2006:

					Facility
					Net Capacity	Net MW
	Location		Energy Source	Installed	(MW)⁽¹⁾	Owned⁽¹⁾
COAL:
Jim Bridger	Rock Springs, WY		Coal	1974-1979	2,120	1,414
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
Hunter No. 1	Castle Dale, UT		Coal	1978	430	403
Hunter No. 2	Castle Dale, UT		Coal	1980	430	259
Hunter No. 3	Castle Dale, UT		Coal	1983	460	460
Cholla No. 4	Joseph City, AZ		Coal	1981	380	380
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 No. 1	Hayden, CO		Coal	1965-1976	184	45
Hayden No. 2	Hayden, CO		Coal	1965-1976	262	33
					9,466	6,104
NATURAL GAS:
Currant Creek	Mona, UT		Natural gas/Steam	2005-2006	540	540
Hermiston	Hermiston, OR		Natural gas/Steam	1996	474	237
Gadsby Steam	Salt Lake City, UT		Natural gas	1951-1952	235	235
Gadsby Peakers	Salt Lake City, UT		Natural gas	2002	120	120
Little Mountain	Ogden, UT		Natural gas	1972	14	14
					1,383	1,146
HYDROELECTRIC:
Swift No. 1	Cougar, WA		Lewis River	1958	264	264
Merwin	Ariel, WA		Lewis River	1931-1958	151	151
Yale	Amboy, WA		Lewis River	1953	164	164
Five North Umpqua Plants	Toketee Falls, OR		N. Umpqua River	1950-1956	141	141
John C. Boyle	Keno, OR		Klamath River	1958	83	83
Copco Nos. 1 and 2	Hornbrook, CA		Klamath River	1918-1925	62	62
Clearwater Nos. 1 and 2	Toketee Falls, OR		Clearwater River	1953	49	49
Grace	Grace, ID		Bear River	1908-1923	33	33
Prospect No. 2	Prospect OR		Rogue River	1928	36	36
Cutler	Collingston, UT		Bear River	1927	29	29
Oneida	Preston, ID		Bear River	1915-1920	28	28
Iron Gate	Hornbrook, CA		Klamath River	1962	19	19
Soda	Soda Springs, ID		Bear River	1924	14	14
Fish Creek	Toketee Falls, OR		Fish Creek	1952	10	10
30 minor hydroelectric plants	Various		Various	1895-1990	77	77
					1,160	1,160
WIND:
Foote Creek	Arlington, WY		Wind	1997	41	32
Leaning Juniper 1	Arlington, OR		Wind	2006	101	101
					142	133
OTHER:
Camas Co-Gen	Camas, WA		Black liquor	1996	22	22
Blundell	Milford, UT		Geothermal	1984	23	23
					45	45

Total Available Generating Capacity					12,196	8,588

PROJECTS UNDER CONSTRUCTION ⁽²⁾:
Lake Side		Vineyard, UT	Natural gas/Steam	N/A	534	534
Marengo		Dayton, WA	Wind	N/A	140	140
					12,870	9,262

⁽¹⁾	Facility Net Capacity (MW) represents the total capability of a generating unit as demonstrated by actual operating experience, or test experience, less power generated and used for auxiliaries and other station uses, and is determined using average annual temperatures. Net MW Owned indicates current legal ownership.

⁽²⁾	Facility Net Capacity (MW) and Net MW Owned for projects under construction each represent the estimated nameplate ratings. A generator’s nameplate rating is its full-load capacity under normal operating conditions as defined by the manufacturer. The expected in-service dates for the Lake Side and Marengo Plants are June 2007 and August 2007, respectively.

Future Generation

As required by state regulators, PacifiCorp uses Integrated Resource Plans (“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. Each state commission that has IRP adequacy rules judges whether the IRP reasonably meets its standards and guidelines at the time the IRP is filed. If the IRP is found to be adequate, then it is formally “acknowledged.” The IRP can then be used as evidence by parties in rate-making or other regulatory proceedings. PacifiCorp files an IRP on a biennial basis and expects to file its 2006 plan in early 2007.

In November 2005, PacifiCorp released an update to its 2004 IRP. The updated 2004 IRP identified a need for approximately 2,113 MW of additional resources by summer 2014, to be met with a combination of thermal generation (1,936 MW) and load-control programs (177 MW). PacifiCorp also planned to implement energy conservation programs of 450 MW, to continue to seek procurement of 1,400 MW of economic renewable resources and to use wholesale electricity transactions to make up for the remaining difference between retail load obligations and available resources.

In July 2006, PacifiCorp filed its 2012 draft request for proposals under its updated 2004 IRP with the Utah Public Service Commission (“UPSC”) and the Oregon Public Utility Commission (“OPUC”). The draft request for proposals is for generation resources of between 840 MW and 915 MW to be available in 2012 and 2013. The scope of this draft request for proposals is focused on resources capable of delivering energy and capacity in or to PacifiCorp’s network transmission system in PacifiCorp’s eastern service territory. All transaction and resource decisions will be evaluated on a comparable least-cost and risk-balanced approach. In response to issues and concerns from stakeholders, PacifiCorp filed a revised version of the 2012 draft request for proposals in October 2006.

In January 2007, the OPUC issued an order denying the 2012 request for proposals. This denial does not preclude the issuance of the request for proposals. PacifiCorp is analyzing the order and will develop its strategy for its next steps. In December 2006, the UPSC issued an order suggesting modifications to the request for proposals. In February 2007, PacifiCorp filed the 2012 request for proposals in Utah for final approval.

Transmission and Distribution

PacifiCorp operates one control area on the western portion of its service territory and one control area on the eastern portion of its service territory. A control area is a geographic area with electric systems that control generation to maintain schedules with other control areas and ensure reliable operations. In operating the control areas, PacifiCorp is responsible for continuously balancing electric supply and demand by dispatching generating resources and interchange transactions so that generation internal to the control area, plus net imported power, matches customer loads. PacifiCorp also schedules deliveries over its transmission system in accordance with FERC requirements.

PacifiCorp’s transmission system is part of the Western Interconnection, the regional grid in the west. The Western Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico that make up the Western Electric Coordinating Council. PacifiCorp’s transmission system, together with contractual rights on other transmission systems, enables PacifiCorp to integrate and access generation resources to meet its customer load requirements.

PacifiCorp’s wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp’s Open Access Transmission Tariff (“OATT”). In accordance with the OATT, PacifiCorp offers several transmission services to wholesale customers:

·	Network transmission service (guaranteed service that integrates generating resources to serve retail loads);

·	Long- and short-term firm point-to-point transmission service (guaranteed service with fixed delivery and receipt points); and

·	Non-firm point-to-point service (“as available” service with fixed delivery and receipt points).

These services are offered on a non-discriminatory basis, meaning that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp’s transmission business is managed and operated independently from the generating and marketing business in accordance with the FERC Standards of Conduct. Transmission costs are not separated from, but rather are “bundled” with, generation and distribution costs in retail rates approved by state regulatory commissions.

The electric transmission system of PacifiCorp as of December 31, 2006, included approximately 15,800 miles of transmission lines. As of December 31, 2006, PacifiCorp owned approximately 900 substations.

MidAmerican Energy

General

MidAmerican Energy, an indirect wholly owned subsidiary of MEHC, is a public utility company, headquartered in Iowa, which serves approximately 0.7 million regulated retail electric customers and approximately 0.7 million regulated retail and transportation natural gas customers. 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 distributes electricity at retail in Council Bluffs, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities (Davenport and Bettendorf, Iowa and Rock Island, Moline and East Moline, Illinois); and a number of adjacent communities and areas. It also distributes natural gas at retail in Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities; Sioux Falls, South Dakota; and a number of adjacent communities and areas. Additionally, MidAmerican Energy transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. In addition to retail sales and natural gas transportation, MidAmerican Energy sells electric energy and natural gas to other utilities, marketers and municipalities. These sales are referred to as wholesale sales.

MidAmerican Energy’s regulated electric and gas operations are conducted under franchise agreements, certificates, permits and licenses obtained from state and local authorities. The franchise agreements, which represent the most important of these government authorizations, have various expiration dates but are typically for 25-year terms.

MidAmerican Energy has a diverse customer base consisting of residential, agricultural, and a variety of commercial and industrial customer groups. Among the primary industries served by MidAmerican Energy are those that are concerned with food products, the manufacturing, processing and fabrication of primary metals, real estate, farm and other non-electrical machinery, and cement and gypsum products.

MidAmerican Energy also has non-regulated business activities in addition to its traditional regulated electric and natural gas services, including unregulated sales of electricity and natural gas in Illinois, Michigan, Ohio, Maryland and the District of Columbia.

MidAmerican Energy’s operating revenues were derived from the following business activities during the years ended December 31:

	2006			2005			2004

Regulated electric		51.6	%		47.9	%		52.7	%
Regulated gas		32.2			41.8			37.5
Non-regulated		16.2			10.3			9.8
		100.0	%		100.0	%		100.0	%

Electric Operations

Customers

	2006			2005			2004

Residential		18.6	%		21.3	%		19.6	%
Commercial		13.1			15.0			14.5
Industrial		27.6			27.9			26.7
Wholesale		36.0			30.5			34.2
Other		4.7			5.3			5.0
		100.0	%		100.0	%		100.0	%

Total retail customers		0.7			0.7			0.7

The percentages of retail electric operating revenue, by jurisdiction, for the years ended December 31 were as follows:

	2006			2005			2004

Iowa		89.5	%		89.0	%		88.7	%
Illinois		9.5			10.1			10.3
South Dakota		1.0			0.9			1.0
		100.0	%		100.0	%		100.0	%

There are seasonal variations in MidAmerican Energy's electric business that are principally related to the use of electricity for air conditioning. Typically, 35-40% of MidAmerican Energy's regulated electric revenues are 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. On July 31, 2006, retail customer usage of electricity caused a new record hourly peak demand of 4,136 MW on MidAmerican Energy’s electric system, an increase of 137 MW from the previous record set in 2005.

Power and Fuel Supply

The estimated percentages of MidAmerican Energy’s total energy requirements supplied by its generation plants and through long- and short-term contracts or spot market purchases for the years ended December 31 were as follows

	2006			2005			2004

Coal		55.4	%		62.6	%		64.4	%
Nuclear		10.5			11.6			11.3
Wind		3.5			2.1			-
Natural gas		2.6			2.5			0.7
Other		0.1			0.1			0.1
Total energy generated		72.1			78.9			76.5
Energy purchased-long-term contracts		7.2			7.9			12.6
Energy purchased-short-term contracts and spot market		20.7			13.2			10.9
		100.0	%		100.0	%		100.0	%

The share of MidAmerican Energy’s energy requirements generated by its plants will vary from year to year and is determined by factors such as planned and unplanned outages, the availability and price of fuels, weather, environmental considerations and the market price of electricity.

MidAmerican Energy is exposed to fluctuations in energy costs relating to retail sales in Iowa and Illinois as it does not have a fuel adjustment clause. Under its South Dakota electric tariffs, MidAmerican Energy is allowed to recover fluctuations in the cost of purchased energy and all fuels used for retail electric generation through a fuel cost adjustment clause. In November 2006, the Illinois Commerce Commission (“ICC”) approved a proposal to eliminate MidAmerican Energy’s monthly fuel adjustment clause. Base rates were adjusted to include recoveries at average 2004/2005 cost levels on January 1, 2007. Rate case approval required for any base rate changes. MidAmerican Energy may not petition for reinstatement of the Illinois fuel adjustment clause for five years.

All of the coal-fired generating stations operated by MidAmerican Energy are fueled by low-sulfur coal from the Powder River Basin in Wyoming. MidAmerican Energy’s coal supply portfolio includes multiple suppliers and mines under agreements of varying terms and quantities. MidAmerican Energy’s coal supply portfolio has 96% of its 2007 requirements under fixed-price contracts. MidAmerican Energy regularly monitors the western coal market, looking for opportunities to enhance its coal supply portfolio. Well-publicized operational delays in rail transportation out of the Powder River Basin during 2005 and 2006 have resulted in the reduction of coal inventories to suboptimum levels. MidAmerican Energy believes the transportation issues have been largely resolved and that its coal inventories will be restored to their target ranges during 2007.

MidAmerican Energy has a long-term coal transportation agreement with Union Pacific Railroad Company (“Union Pacific”). Under this agreement, Union Pacific delivers contractually specified amounts of coal directly to MidAmerican Energy’s Neal and Council Bluffs Energy Centers and to an interchange point with the Iowa, Chicago & Eastern Railroad Corporation for delivery to the Louisa and Riverside Energy Centers. MidAmerican Energy has the ability to use The Burlington Northern and Santa Fe Railway Company for delivery of a small amount of coal to the Council Bluffs, Louisa and Riverside Energy Centers should the need arise.

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. MidAmerican Energy manages a portion of its natural gas supply requirements by entering into various financial derivative instruments, including forward purchases and sales, futures, swaps and options. Refer to Item 7A. Quantitative and Qualitative Disclosures About Market Risk for a discussion of commodity price risk and derivative instruments.

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 the core at Quad Cities Station are replaced every 24 months. MidAmerican Energy has been advised by Exelon Generation that its uranium requirements for Quad Cities Station through 2009 and part of the requirements through 2015 can be met under existing supplies or commitments. Additionally, under existing supplies and commitments, uranium conversion requirements can be met through 2009 and part of 2010 and enrichment requirements can be met through 2011. Commitments for fuel fabrication have been obtained for the next eight years. MidAmerican Energy has been advised by Exelon Generation that it does not anticipate that it will have difficulty in contracting for uranium, conversion, enrichment or fabrication of nuclear fuel needed to operate Quad Cities Station during this time.

The following table sets out certain information concerning MidAmerican Energy’s power generating facilities as of December 31, 2006:

				Facility Net
				Capacity	Net MW
	Location	Energy Source	Installed	(MW) ^{(1) (2)}	Owned ^{(1) (2)}
COAL:
Council Bluffs Unit No. 1	Council Bluffs, IA	Coal	1954	45	45
Council Bluffs Unit No. 2	Council Bluffs, IA	Coal	1958	88	88
Council Bluffs Unit No. 3	Council Bluffs, IA	Coal	1978	690	546
Neal Unit No. 1	Sergeant Bluff, IA	Coal	1964	135	135
Neal Unit No. 2	Sergeant Bluff, IA	Coal	1972	300	300
Neal Unit No. 3	Sergeant Bluff, IA	Coal	1975	515	371
Neal Unit No. 4	Salix, IA	Coal	1979	632	256
Louisa	Muscatine, IA	Coal	1983	700	616
Ottumwa	Ottumwa, IA	Coal	1981	672	349
Riverside Unit No. 3	Bettendorf, IA	Coal	1925	4	4
Riverside Unit No. 5	Bettendorf, IA	Coal	1961	130	130
				3,911	2,840
NATURAL GAS:
Greater Des Moines	Pleasant Hill, IA	Natural gas	2003-2004	491	491
Coralville	Coralville, IA	Natural gas	1970	64	64
Electrifarm	Waterloo, IA	Natural gas/Oil	1975-1978	200	200
Moline	Moline, IL	Natural gas	1970	64	64
Parr	Charles City, IA	Natural gas	1969	32	32
Pleasant Hill	Pleasant Hill, IA	Natural gas/Oil	1990-1994	163	163
River Hills	Des Moines, IA	Natural gas	1966-1967	120	120
Sycamore	Johnston, IA	Natural gas/Oil	1974	149	149
28 portable power modules	Various	Oil	2000	56	56
				1,339	1,339
NUCLEAR:
Quad Cities Unit No. 1	Cordova, IL	Uranium	1972	872	218
Quad Cities Unit No. 2	Cordova, IL	Uranium	1972	876	219
				1,748	437
WIND:
Intrepid	Schaller, IA	Wind	2004-2005	176	176
Century	Blairsburg, IA	Wind	2005	185	185
Victory	Westside, IA	Wind	2006	99	99
				460	460
OTHER:
4 hydroelectric plants	Moline, IL	Mississippi River	1970	3	3

Total Available Generating Capacity				7,461	5,079

PROJECTS UNDER CONSTRUCTION ⁽²⁾:
Council Bluffs Unit No. 4	Council Bluffs, IA	Coal	N/A	790	479
Pomeroy	Pomeroy, IA	Wind	N/A	123	123
				913	602

				8,374	5,681

⁽¹⁾	Facility Net Capacity (MW) represents total plant accredited net generating capacity from the summer 2006 as approved by the Mid-Continent Area Power Pool (“MAPP”), except for wind-powered generation facilities, which are nameplate ratings. Net MW Owned indicates MidAmerican Energy’s ownership of Facility Net Capacity. The 2006 summer accreditation of the Intrepid and Century facilities totaled 59 MW and is considerably less than the nameplate ratings due to the varying nature of wind. Additionally, the Victory wind-powered generation facility was placed in service in the fourth quarter of 2006, which was after the 2006 summer accreditation.

⁽²⁾	Facility Net Capacity (MW) and Net MW Owned represents the expected accredited generating capacity for the coal-fired generation project under construction (MW) and the estimated nameplate ratings (MW) for wind-powered generation projects under construction. The expected in-service date for the Council Bluffs Unit No. 4 facility is June 2007 and the Pomeroy project is planned to be completed by the end of 2007.

Future Generation

On April 18, 2006, the Iowa Utilities Board (“IUB”) approved a settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate (“OCA”) regarding rate-making principles for up to 545 MW (nameplate ratings) of wind-powered generation capacity in Iowa to be installed in 2006 and 2007. In the second half of 2006, MidAmerican Energy placed in service 99 MW (nameplate ratings) of wind-powered generation facilities and is constructing the 123 MW (nameplate ratings) Pomeroy wind-powered generation project which is planned to be completed by the end of 2007. MidAmerican Energy continues to pursue additional cost effective wind-powered generation.

Transmission and Distribution

MidAmerican Energy is interconnected with utilities in Iowa and neighboring states. MidAmerican Energy is also a party to an electric generation reserve sharing pool and regional transmission group administered by MAPP. MAPP is a voluntary association of electric utilities doing business in Minnesota, Nebraska, North Dakota and the Canadian provinces of Saskatchewan and Manitoba and portions of Iowa, Montana, South Dakota and Wisconsin. Its membership also includes power marketers, regulatory agencies and independent power producers. MAPP performs functions including administration of its short-term regional OATT, coordination of regional planning and operations, and operation of the generation reserve sharing pool.

MidAmerican Energy’s transmission system connects its generating facilities with distribution substations and interconnects with 14 other transmission providers in Iowa and five adjacent states. Under normal operating conditions, MidAmerican Energy's transmission system has adequate capacity to deliver energy to MidAmerican Energy’s distribution system and to export and import energy with other interconnected systems. The electric transmission system of MidAmerican Energy at December 31, 2006, included approximately 1,000 miles of 345-kV lines and approximately 1,100 miles of 161-kV lines. MidAmerican Energy's electric distribution system included approximately 400 substations at December 31, 2006.

Natural Gas Operations

MidAmerican Energy is engaged in the procurement, transportation, storage and distribution of natural gas for customers in the Midwest. MidAmerican Energy purchases natural gas from various suppliers, transports it from the production areas to its service territory under contracts with interstate pipelines, stores it in various storage facilities to manage fluctuations in system demand and seasonal pricing, and delivers it to customers through its distribution system.

MidAmerican Energy sells natural gas and transportation services to end-use customers and natural gas to other utilities, marketers and municipalities. MidAmerican Energy also transports through its distribution system natural gas purchased independently by a number of end-use customers. During 2006, 47.2% of total natural gas delivered through MidAmerican Energy’s system for end use customers was under natural gas transportation service.

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.

The percentages of regulated natural gas revenue, excluding transportation throughput, by class of customer, for the years ended December 31 were as follows:

	2006			2005			2004

Residential		37.2	%		37.5	%		40.0	%
Small general service ⁽¹⁾		18.1			18.2			19.6
Large general service ⁽¹⁾		3.6			4.1			2.2
Wholesale ⁽²⁾		41.1			40.2			38.0
Other		-			-			0.2
		100.0	%		100.0	%		100.0	%

⁽¹⁾	Small and large general service customers are classified primarily based on the nature of their business and natural gas usage. Small general service customers are business customers whose natural gas usage is principally for heating. Large general service customers are business customers whose principal natural gas usage is for their manufacturing processes.

⁽²⁾	Wholesale generally includes other utilities, marketers and municipalities to whom natural gas is sold at wholesale for eventual resale to ultimate end-use customers.

The percentages of regulated natural gas revenue, excluding transportation throughput, by jurisdiction, for the years ended December 31 were as follows:

	2006			2005			2004

Iowa		77.3	%		77.4	%		77.7	%
South Dakota		12.0			11.7			11.5
Illinois		9.8			10.0			9.9
Nebraska		0.9			0.9			0.9
		100.0	%		100.0	%		100.0	%

MidAmerican Energy purchases natural gas supplies from producers and third-party marketers. To enhance system reliability, a geographically diverse supply portfolio with varying terms and contract conditions is utilized for the natural gas supplies. MidAmerican Energy attempts to optimize the value of its regulated assets by engaging in wholesale sales transactions. IUB and South Dakota Public Utilities Commission (“SDPUC”) rulings have allowed MidAmerican Energy to retain 50% of the respective jurisdictional margins earned on wholesale sales of natural gas, with the remaining 50% being returned to customers through the purchased gas adjustment clauses discussed below.

MidAmerican Energy has rights to firm pipeline capacity to transport natural gas to its service territory through direct interconnects to the pipeline systems of Northern Natural Gas (an affiliate company), Natural Gas Pipeline Company of America (“NGPL”), Northern Border Pipeline Company (“Northern Border”) and ANR Pipeline Company (“ANR”). At times, the capacity available through MidAmerican Energy’s firm capacity portfolio may exceed the demand on MidAmerican Energy’s distribution system. Firm capacity in excess of MidAmerican Energy’s system needs can be resold to other companies to achieve optimum use of the available capacity. Past IUB and SDPUC rulings have allowed MidAmerican Energy to retain 30% of the respective jurisdictional margins earned on the resold capacity, with the remaining 70% being returned to customers through the purchased gas adjustment clauses.

MidAmerican Energy is allowed to recover its cost of natural gas from all of its regulated natural gas customers through purchased gas adjustment clauses. 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 to reduce the market price risk for its natural gas customers, including the use of storage gas and peak-shaving facilities, sharing arrangements to share savings and costs with customers and short-term and long-term financial and physical gas purchase agreements.

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 three liquefied natural gas (“LNG”) plants and two propane-air plants 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.

In 1995, the IUB gave initial approval of MidAmerican Energy’s Incentive Gas Supply Procurement Program. In December 2006, the IUB extended the program through October 31, 2010. Under the program, as amended, MidAmerican Energy is required to file with the IUB every six months a comparison of its natural gas procurement costs to a reference price. If MidAmerican Energy’s cost of natural gas for the period is less or greater than an established tolerance band around the reference price, then MidAmerican Energy shares a portion of the savings or costs with customers. A similar program is currently in effect in South Dakota through October 31, 2010. Since the implementation of the program, MidAmerican Energy has successfully achieved and shared savings with its natural gas customers.

On February 2, 1996, MidAmerican Energy had its highest peak-day delivery of 1,143,026 Dth. This peak-day delivery consisted of 88% traditional sales service and 12% transportation service of customer-owned gas. As of March 1, 2007, MidAmerican Energy’s 2006/2007 winter heating season peak-day delivery of 1,071,380 Dth was reached on February 5, 2007. This peak-day delivery included 68% traditional sales service and 32% transportation service.

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 at December 31, 2006, included approximately 22,000 miles of gas mains and services pipelines.

Interstate Pipeline Companies

Northern Natural Gas

Northern Natural Gas, an indirect wholly owned subsidiary of MEHC acquired in 2002, owns one of the largest interstate natural gas pipeline systems in the United States. It reaches from Texas to Michigan’s Upper Peninsula and is engaged in the transmission and storage of natural gas for utilities, municipalities, other pipeline companies, gas marketers, industrial and commercial users and other end users. Northern Natural Gas owns and operates approximately 15,900 miles of natural gas pipelines, consisting of approximately 6,900 miles of mainline transmission pipelines and approximately 9,000 miles of branch and lateral pipelines, with a Market Area design capacity of 4.9 Bcf per day. Based on a review of relevant 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. Northern Natural Gas’ revenue is derived from the interstate transportation and storage of natural gas for third parties. 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. 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 it an opportunity to recover its costs and generate a regulated return on equity.

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 is at the northern part of the system, including delivery points in Michigan, Illinois, Iowa, Minnesota, Nebraska, Wisconsin and South Dakota, which Northern Natural Gas refers to as the Market Area. Its natural gas supply and delivery service area is at the southern part of the system, including Kansas, Oklahoma, Texas and New Mexico, which Northern Natural Gas refers to as the Field Area.

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, the Rocky Mountain and Canadian basins in our Market Area. In each of these areas, Northern Natural Gas has numerous interconnecting receipt and delivery points.

Northern Natural Gas transports natural gas primarily to end-user and local distribution markets in the Market Area. In 2006, 68% of Northern Natural Gas’ transportation and storage revenue was generated from Market Area customer transportation contracts. Its market area customers consist of local distribution companies (“LDCs”), utilities, other pipeline companies, gas marketers and end-users. Northern Natural Gas directly serves approximately 75 utilities and LDCs, with six large LDCs accounting for the majority of its Market Area revenues in 2006. In turn, these large LDCs serve numerous small communities. In 2006, over 86% of Northern Natural Gas’ transportation and storage revenue for the Field and Market Areas was generated from reservation charges under firm transportation and storage contracts and 73% of that revenue was from LDCs.

A majority of Northern Natural Gas’ capacity in the Market Area is dedicated to Market Area customers under firm transportation contracts. As of December 31, 2006, approximately 61% of Northern Natural Gas’ contracted firm transportation capacity in the Market Area is contracted beyond 2008, and approximately 39% is contracted beyond 2015.

As part of Northern Natural Gas’ Northern Lights project, Northern Natural Gas has applied to the FERC for facilities to deliver approximately 440,000 Dthd throughout its Market Area. This load is concentrated primarily in the Twin Cities area of Minnesota. Northern Lights currently consists of three phases. Almost all of the service for these three phases is expected to begin by November 1, 2007, although some smaller projects are scheduled to be in service by June 2007 and November 2008. Phase 1 of Northern Lights consists of 374,225 Dthd, representing $26.5 million of annual revenue. Phases 2 and 3 consist of service primarily for new ethanol plants in Northern Natural Gas’ Market Area. Northern Natural Gas is geographically well situated to serve the expanding ethanol industry and now serve approximately one-third of the nation’s ethanol manufacturing capacity. Entitlement for Phases 2 and 3 of the Northern Lights project is approximately 44,200 Dthd and 24,000 Dthd, respectively, which are expected to generate annual revenues of $5.1 million and $2.7 million, respectively. All of the Northern Lights entitlement except 31,400 Dthd in Phase 1 and 6,200 Dthd in Phase 3 is associated with new service. All three phases of Northern Lights are entirely supported by executed contracts, the majority of which (87% by volume) have terms ranging from five to twenty years. In total, the current Northern Lights expansion projects are expected to require approximately $156.0 million in capital expenditures.

In the Field Area, customers holding transportation capacity consist of LDCs, marketers, producers, and end-users. The majority of Northern Natural Gas’ Field Area firm transportation is currently conducted under long-term firm transportation contracts that expire on October 31, 2007, with such volumes supplemented by volumes transported on an interruptible basis. The majority of this entitlement is expected to be recontracted as of November 1, 2007 by LDCs, marketers, or producers, although in the near term the contracts may be for shorter terms. Northern Natural Gas expects recontracting to occur since Market Area customers are expected to need to purchase gas connected to its Field Area in order to meet their growing demand levels. Market Area demand cannot presently be met without the purchase of supplies from the Field Area. In 2006, 21% 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 storage field in Iowa, two underground storage facilities in Kansas and one LNG storage peaking unit each in Garner, Iowa and Wrenshall, Minnesota. The three underground natural gas storage facilities and two LNG storage peaking units have a total firm service cycle capacity of approximately 65 Bcf and over 1.9 Bcf per day of FERC-certificated peak delivery capability. These storage facilities provide Northern Natural Gas with operational flexibility for the daily balancing of its system and provide services to customers to meet their winter peaking and year-round loadswing requirements. In 2006, 11% of Northern Natural Gas’ transportation and storage revenue was generated from storage services.

Northern Natural Gas’ system experiences significant seasonal swings in demand, with the highest demand occurring during the months of November through March. This seasonality provides Northern Natural Gas opportunities to deliver value-added services, such as firm and interruptible storage services, as well as no-notice services, particularly during the lower demand months. Because of its location and multiple interconnections with other 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, Pony Express Pipeline, Cheyenne Plains Pipeline and Colorado Interstate Gas Pipeline Company (“Colorado Interstate”), as well as from Canadian production areas through Northern Border, Great Lakes Gas Transmission Limited Partnership (“Great Lakes”) and Viking Gas Transmission Company (“Viking”). 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 augments 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 interconnections.

Kern River

Kern River, an indirect wholly owned subsidiary of MEHC acquired in 2002, owns an interstate natural gas transportation pipeline system consisting of approximately 1,700 miles of pipeline, with an approximate design capacity of 1,755,575 Dth per day, extending from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. On May 1, 2003, Kern River placed into service an approximately 700-mile expansion project (the “2003 Expansion Project”), which increased the design capacity of Kern River’s pipeline system by 885,575 Dth per day to its current capacity. 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 it an opportunity to recover its costs and generate a regulated return on equity.

Kern River’s pipeline consists of two sections: the mainline section and the common facilities. Kern River owns the entire mainline section, which extends from the pipeline’s point of origination near Opal, Wyoming through the Central Rocky Mountains area into Daggett, California. The mainline section consists of the original approximately 700 miles of 36-inch diameter pipeline, approximately 600 miles of 36-inch diameter loop pipeline related to the 2003 Expansion Project and approximately 100 miles of various laterals that connect to the mainline.

The common facilities consist of an approximately 200-mile section of original pipeline that extends from the point of interconnection with the mainline in Daggett to Bakersfield, California and an additional approximately 100 miles related to the 2003 Expansion Project. The common facilities are jointly owned by Kern River (approximately 76.8% as of December 31, 2006) and Mojave Pipeline Company (“Mojave”), a wholly owned subsidiary of El Paso Corporation, (approximately 23.2% as of December 31, 2006), 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 approximately 1,570,500 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.

As of December 31, 2006, Kern River had long-term firm natural gas transportation service agreements for 1,661,575 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 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 nearly ten years. Shippers on the pipeline include major oil and gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies, and natural gas distribution utilities which provide services in Utah, Nevada and California. As of December 31, 2006, over 95% of the firm capacity has primary delivery points in California, with the flexibility to access secondary delivery points in Nevada and Utah. Kern River has an additional 94,000 Dth per day of available long-term firm capacity that was sold to a number of shippers at a discounted daily demand rate for the period of April 2006 through September 2008 on a short-term basis. Kern River will continue to market this capacity or use it for any future expansion needs for any period beyond September 2008.

Calpine Corp., including Calpine Energy Services, L.P. (“Calpine”), filed for Chapter 11 bankruptcy protection on December 20, 2005. Calpine holds two 50,000 Dth per day incremental 2003 Expansion Project firm transportation contracts that have termination dates of April 30, 2018. Pursuant to Kern River’s credit requirements, Calpine provided approximately $19 million as cash security for the transportation contracts, with approximately $3 million being applied against Calpine’s pre-petition invoices. Post-petition, to date, Calpine has continued to nominate on its transportation contracts and pay its post-petition invoices; however, Calpine has not yet determined whether it will assume or reject the transportation contracts.

Kern River and Northern Natural Gas 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. Industrial end-users often have the ability to choose from alternative fuel sources, such as fuel oil and coal, in addition to natural gas. Natural gas competes with other forms of energy, including electricity, coal and fuel oil, primarily on the basis of price. Legislation and governmental regulations, the weather, the futures market, production costs and other factors beyond the control of Kern River and Northern Natural Gas 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. In recent years, Northern Natural Gas has retained and signed long-term contracts with customers such as CenterPoint, 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, Northern Border and NGPL. Other competitors of Northern Natural Gas include Great Lakes and Viking. In the Field Area, Northern Natural Gas competes with a large number of pipeline companies. Particularly in the Field Area, a significant amount of Northern Natural Gas’ capacity is used for transportation services provided on a short-term or interruptible basis. Historically in summer months, Northern Natural Gas’ Market Area customers often release significant amounts of their unused firm entitlement to other shippers. This released entitlement competes with Northern Natural Gas’ short-term and interruptible services. Northern Natural Gas attempts to maintain its competitive position through selective discounting of firm transportation to keep delivered natural gas prices in line with delivered prices for alternative fuels and by using flexible short-term and interruptible transportation services that are contracted for on an as-needed basis.

Although it needs to compete aggressively to retain and build load, Northern Natural Gas believes that current and anticipated changes in its competitive environment have created opportunities to serve its existing customers more efficiently and to meet certain growing supply needs. While peak day delivery growth of LDCs is driven by population growth and alternative fuel replacement, new baseload or off-peak demand growth is being driven primarily by power and ethanol plant expansion. This baseload or off-peak demand growth is important to Northern Natural Gas as this demand provides revenues year round and allows Northern Natural Gas to utilize facilities on a year-round basis. Northern Natural Gas has been successful in competing for a significant amount of the increased demand related to the construction of new power and ethanol plants.

Kern River competes with various interstate pipelines and its shippers in order to market any unutilized or unsubscribed capacity serving the southern California, Las Vegas, Nevada and Salt Lake City, Utah market areas. Kern River provides its customers with supply diversity through pipeline interconnections with Northwest Pipeline, Colorado Interstate, Overland Trail 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 to 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 to comply with the Pipeline Safety Improvement Act of 2002 (“PSIA”) than other systems. Kern River’s levelized rate structure has been challenged in its 2004 general rate case. Certain parties have advocated converting the system to a traditional declining rate base rate structure. 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 addition, Kern River’s 2003 Expansion Project relies substantially on long-term transportation service agreements with several electric generation companies, which face significant competitive and financial pressures due to, among other things, the financial stress of energy markets and the build-up of electric generation capacity in California and other markets. This condition is improving as demand for electric generation in Kern River’s market territory increases and older, less efficient power plants in the region are retired.

In 2006, Northern Natural Gas had two customers who each accounted for greater than 10% of its revenue and its six largest customers accounted for 56.5% of its transportation and storage revenues. Northern Natural Gas has agreements to retain the vast majority of its two largest customers’ volumes through at least 2017. Kern River also had two customers who each 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, primarily, two companies that distribute electricity in Great Britain, Northern Electric and Yorkshire Electricity. Northern Electric and Yorkshire Electricity operate in the north-east of England from North Northumberland through Durham, Tyne and Wear, Tees Valley and Yorkshire to North Lincolnshire, an area covering approximately 10,000 square miles, and serves approximately 3.8 million end users.

The principal function of Northern Electric and Yorkshire Electricity is to build and maintain the electricity distribution network to serve the end user. The service territory geographically features a diverse economy with no dominant sector. The mix of rural, agricultural, urban and industrial areas covers a wide range of customer base 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 revenues of the regulated distribution companies are agreed with the regulator based around 5-year price control periods, with the current price control period commencing April 1, 2005.

In addition to building and maintaining the electricity distribution network, CE Electric UK also owns a utility contracting business and a gas exploration business.

Electricity Distribution

Northern Electric’s and Yorkshire Electricity’s operations consist primarily of the distribution of electricity in the Great Britain. Northern Electric and Yorkshire Electricity receive electricity from the national grid transmission system and distribute it to their customers’ premises using their network 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 through their distribution system, thus providing Northern Electric and Yorkshire Electricity with distribution volume that is relatively stable from year to year. Northern Electric and Yorkshire Electricity charge fees for the use of the distribution system to the suppliers of electricity. The suppliers, which purchase electricity from generators and sell the electricity to end-user customers, use Northern Electric’s and Yorkshire Electricity’s distribution networks pursuant to an industry standard “Distribution Connection and Use of System Agreement,” which Northern Electric and Yorkshire Electricity separately entered into with the various suppliers of electricity in their respective distribution service areas. One such supplier, RWE Npower PLC and certain of its affiliates, represented approximately 42% of the total combined distribution revenues of Northern Electric and Yorkshire Electricity in 2006. The fees that may be charged by Northern Electric and Yorkshire Electricity for use of their distribution systems are controlled by a formula prescribed by the United Kingdom’s electricity regulatory body that limits increases (and may require decreases) based upon the rate of inflation, other factors and other regulatory action.

Electricity distributed (in GWh) to end users and the total number of end users (in millions) as of and for the years ended December 31 were as follows:

	2006		2005		2004
Electricity distributed:
Northern Electric		17,203		17,207		17,280
Yorkshire Electricity		25,025		24,781		24,842
		42,228		41,988		42,122
Number of end users:
Northern Electric		1.6		1.5		1.5
Yorkshire Electricity		2.2		2.2		2.2
		3.8		3.7		3.7

As of December 31, 2006, Northern Electric’s and Yorkshire Electricity’s electricity distribution network (excluding service connections to consumers) on a combined basis included approximately 34,000 kilometers of overhead lines and approximately 65,000 kilometers of underground cables. In addition, as of December 31, 2006, Northern Electric’s and Yorkshire Electricity’s distribution facilities included approximately 700 major substations. Substantially all substations are owned, with the balance being leased from third parties and mostly having remaining terms of at least 10 years.

Utility Services

Integrated Utility Services Limited, CE Electric UK’s indirect wholly-owned subsidiary, is an engineering contracting company providing electrical infrastructure contracting services to third parties.

Gas Exploration and Production

CalEnergy Gas (Holdings) Limited (“CE Gas”), CE Electric UK’s indirect wholly owned subsidiary, is a gas exploration and production company that is focused on developing integrated upstream gas projects in Australia, the United Kingdom and Poland. Its upstream gas business consists of full or partial ownership in exploration, construction and production projects, which, if successful, result in the sale of gas and other hydrocarbon products to third parties.

CalEnergy Generation-Foreign

The CalEnergy Generation-Foreign platform consists of MEHC’s indirect ownership of the Leyte Projects, which are two geothermal power plants located on the island of Leyte in the Philippines, and a combined irrigation and hydroelectric power generation project located in the central part of the island of Luzon in the Philippines (the “Casecnan Project”).

The following table sets out certain information concerning CalEnergy Generation-Foreign’s non-utility power projects in operation as of December 31, 2006:

Power

Contract

Energy

Contract

Purchaser/

Capacity

Net MW

Project

Location

Source

Expiration

Guarantor ⁽¹⁾

(MW) ⁽²⁾

Owned ⁽²⁾

Mahanagdong

Philippines

Geothermal

July 2007

PNOC-EDC/ROP

154

150

Malitbog

Philippines

Geothermal

July 2007

PNOC-EDC/ROP

216

Casecnan ⁽³⁾

Philippines

Casecnan and Taan Rivers

December 2021

NIA/ROP

150

Total

520

516

⁽¹⁾	Separate sovereign performance undertakings of the Republic of the Philippines (“ROP”) support PNOC-Energy Development Corporation’s (“PNOC-EDC”) obligations for the Leyte Projects. The ROP has also provided a performance undertaking under which National Irrigation Administration (“NIA”)’s obligations under the Casecnan Project agreement, as supplemented by the Supplemental 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 the delivery of water and electricity by CE Casecnan. All projects carry political risk insurance.

⁽²⁾	Contract Capacity (MW) represents the contract capacity for the facility. Net MW Owned indicates legal ownership of Contract Capacity.

⁽³⁾	Net MW Owned of approximately 150 MW is subject to repurchase rights of up to 15% of the project by an initial minority shareholder and a dispute with the other initial minority shareholder regarding an additional 15% of the project. Refer to Item 3. Legal Proceedings for additional information.

PNOC-EDC’s and NIA’s obligations under the project agreements are substantially denominated in U.S. dollars and are the Leyte Projects’ and Casecnan Project’s sole source of operating revenue. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations under the project agreements and any material failure of the ROP to fulfill its obligation under the performance undertaking would significantly impair the ability to meet existing and future obligations of the relevant project company, including obligations pertaining to the outstanding project debt.

On July 25, 2007, the Mahanagdong and the Malitbog Projects’ separate 10-year cooperation periods will end and the Mahanagdong and the Malitbog Projects will each be transferred by the Company to PNOC-EDC at no cost on an “as-is” basis. The Mahanagdong and the Malitbog Projects take geothermal steam and fluid, provided at no cost by PNOC-EDC, and convert their thermal energy into electrical energy which is sold to PNOC-EDC, which in turn sells the power to the National Power Corporation (“NPC”), the government-owned and controlled corporation that is the primary supplier of electricity in the Philippines, for distribution on the islands of Cebu and Luzon. Payments under the Mahanagdong and Malitbog agreements are primarily denominated in U.S. dollars, or computed in U.S. dollars and paid in pesos at the then-current exchange rate.

The Casecnan Project is a combined irrigation and hydroelectric power generation project. CE Casecnan owns and operates the Casecnan Project under the terms of the Project Agreement between CE Casecnan and NIA, which was modified by a Supplemental Agreement between CE Casecnan and NIA effective on October 15, 2003 (the “Supplemental Agreement”). CE Casecnan will own and operate the project for a 20-year cooperation period which commenced on December 11, 2001, the start of the Casecnan Project’s commercial operations, 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 will impact the amounts 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 (described below) can produce significant variability in revenue between reporting periods.

Under the Supplemental Agreement, CE Casecnan is paid a fee for the delivery of water and a fee for the generation of electricity. With respect to water deliveries, the water delivery fees are recorded each month pro-rated to a minimum threshold of water delivered per month until such minimum threshold has been reached for the contract year. Subsequent water delivery fees within the contract year are based on actual water delivered. With respect to electricity, CE Casecnan is paid a guaranteed energy delivery fee each month. The guaranteed energy delivery fee is payable regardless of the amount of energy actually generated and delivered by CE Casecnan in any month. NIA also pays CE Casecnan an excess energy delivery fee, which is a variable amount based on actual electrical energy, if any, delivered in each month in excess of a minimum threshold. Within each contract year, no variable energy fees are payable until energy in excess of the cumulative minimum threshold per month for the contract year to date has been delivered. If the Casecnan Project is not dispatched up to 150 MW whenever water is available, NIA will pay for energy that could have been generated but was not as a result of such dispatch constraint.

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, 2006:

Facility

Net or

Power

Contract

Net

Purchase

Operating

Capacity

Energy

Agreement

Power

Project

(MW) ⁽¹⁾

Owned ⁽¹⁾

Source

Location

Expiration

Purchaser ⁽²⁾

Cordova

537

Gas

Illinois

2019

Constellation

Wailuku

Wailuku River

Hawaii

2023

HELCO

CE Generation ⁽³⁾:

Imperial Valley Projects

327

164

Geo

California

⁽⁴⁾

Natural-Gas Fired -

Saranac

240

Gas

New York

2009

NYSE&G

Power Resources

212

106

Gas

Texas

2009

Constellation

Yuma

Gas

Arizona

2024

SDG&E

502

221

Total CE Generation

829

385

Total CalEnergy-Domestic

1,376

927

⁽¹⁾	Facility Net or Contract Capacity (MW) represents total plant accredited net generating capacity from the summer 2006 as approved by MAPP for Cordova and contract capacity for most other projects. Net MW Owned indicates legal ownership of the Facility Net Capacity or Contract Capacity.

⁽²⁾	Constellation Energy Commodities Group, Inc. (“Constellation”); Hawaii Electric Company (“HELCO”); New York State Electric & Gas Corporation (“NYSE&G”); and San Diego Gas & Electric Company (“SDG&E”).

⁽³⁾	MEHC has a 50% ownership interest in CE Generation, LLC (“CE Generation”) whose affiliates currently operate ten geothermal plants in the Imperial Valley of California (the “Imperial Valley Projects”) and three natural gas-fired power generation facilities.

⁽⁴⁾	Approximately 80% of the Company’s interests in the Imperial Valley Projects’ Contract Capacity (MW) is sold to Southern California Edison under long-term power purchase agreements expiring in 2016 through 2026.

Electric Transmission Texas LLC

In January 2007, MEHC and American Electric Power (“AEP”) reached an agreement to form Electric Transmission Texas LLC (“ETT”), as a joint venture to build transmission facilities in Texas principally within the Electricity Reliability Council of Texas (“ERCOT”) market. Later in January, ETT filed with the Public Utility Commission of Texas for approval to operate as an electric transmission utility in Texas and establish initial rates. In its filing, ETT also requests approval for the transfer of transmission assets currently under construction by a subsidiary of AEP, AEP Texas Central Company, to the joint venture company valued at approximately $76 million.

Upon receipt of all required regulatory approvals and other standard closing conditions, AEP Utilities, a wholly-owned subsidiary of AEP, and MEHC Texas Transco, LLC, a wholly-owned subsidiary of MEHC each will acquire a 50% interest in the joint venture.

MEHC and AEP expect ETT to invest in additional transmission projects in ERCOT, which could exceed $1 billion during the next several years. The anticipated utility capitalization structure of ETT is targeted at 40% equity and 60% debt. The joint venture is expected to be operational by the end of the year.

HomeServices

HomeServices 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 and mortgage banking, primarily through joint ventures, title and closing services and other 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 in 19 states under the following 20 brand names: Carol Jones REALTORS, CBSHOME Real Estate, Champion Realty, Edina Realty Home Services, Esslinger-Wooten-Maxwell REALTORS, First Realty/GMAC, Harry Norman Realtors, HOME Real Estate, Huff Realty, Iowa Realty, Jenny Pruitt and Associates REALTORS, Long Realty, Prudential California Realty, Prudential Carolinas Realty, RealtySouth, Rector-Hayden REALTORS, Reece & Nichols, Roberts Brothers, Inc., Semonin REALTORS and Woods Bros. Realty. HomeServices generally occupies the number one or number two market share position in each of its major markets based on aggregate closed transaction sides. HomeServices’ major markets consist of the following metropolitan areas: Minneapolis and St. Paul, Minnesota; Los Angeles and San Diego, California; Kansas City, Kansas; Kansas City and Springfield, Missouri; Des Moines, Iowa; Atlanta, Georgia; Omaha and Lincoln, Nebraska; Birmingham, Auburn and Mobile, Alabama; Tucson, Arizona; Winston-Salem and Charlotte, North Carolina; Louisville and Lexington, Kentucky; Annapolis, Maryland; Cincinnati, Ohio; and Miami, Florida. The U.S. residential real estate brokerage business 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.

Employees

As of December 31, 2006, the Company employed approximately 17,800 people, of which approximately 7,800 are covered by union contracts. The majority of the union employees are employed by PacifiCorp and MidAmerican Energy 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 expirations dates ranging from April 2007 to September 2009. HomeServices’ residential real estate agents are independent contractors and not employees.

General Regulation

MEHC’s energy 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.

Domestic Regulated Public Utility Subsidiaries

MEHC’s domestic regulated public utility subsidiaries, PacifiCorp and MidAmerican Energy, 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 service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its costs of providing services and to earn a reasonable return on its investment. A utility’s cost-of-service generally reflects its allowed operating expenses, including operation and maintenance expense, depreciation expense and taxes. Some portion of margins earned on wholesale sales for electricity and capacity and gas transmission service has historically been included as a component of retail cost of service upon which retail rates are based. State utility commissions may adjust rates pursuant to a review of (i) a utility’s revenues and expenses during a defined test period and (ii) such utility’s level of investment. State utility commissions typically have the authority to review and change service rates on their own initiative. Some states may initiate reviews at the request of a 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 PacifiCorp and MidAmerican Energy are generally based on the cost of providing traditional bundled service, including generation, transmission and distribution services. Historically, the state regulatory framework in the service areas of PacifiCorp’s and MidAmerican Energy’s 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. Power and fuel adjustment clauses permit periodic adjustments to cost recovery from customers and therefore provide protection against exposure to cost changes.

Except for Oregon, Washington and Illinois, PacifiCorp and MidAmerican Energy 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, certain commercial and industrial customers have the right to choose alternative electric suppliers. The impact of these programs on the Company’s financial results has not been and is not expected to be material. In Washington, the state statute 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 state commission. In Illinois, all customers are free to choose their electricity supplier and MidAmerican Energy has an obligation to serve customers at regulated rates that leave MidAmerican Energy’s system, but later choose to return. To date, there has been no significant loss of customers in Illinois.

In connection with the 2006 acquisition of PacifiCorp, MEHC and PacifiCorp have made commitments to the state commissions that limit the dividends PacifiCorp can pay to MEHC or its affiliates. As of December 31, 2006, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to MEHC or its affiliates without prior state regulatory approval to the extent PacifiCorp’s common stock equity would be reduced below 48.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt. After December 31, 2008, this minimum level of common equity declines annually to 44.0% after December 31, 2011. As of December 31, 2006, PacifiCorp’s ratio, as calculated pursuant to the requirements of the applicable commitment, exceeded the minimum threshold.

In conjunction with the March 1999 acquisition of MidAmerican Energy by MEHC, MidAmerican Energy committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain a common equity to total capitalization ratio above 42%, except under circumstances beyond its control. MidAmerican Energy’s common equity to total capitalization ratio is not allowed to decline below 39% for any reason. If the ratio declines below the defined threshold, MidAmerican Energy must seek the approval of a reasonable utility capital structure from the IUB. MidAmerican Energy’s ability to issue debt could also be restricted. As of December 31, 2006, MidAmerican Energy’s common equity to total capitalization ratio, computed on a basis consistent with the commitment, was 53.6%.

PacifiCorp

The following table illustrates the current rate case status in each state jurisdictions in which PacifiCorp operates:

Jurisdiction	State Regulator	Base Rate ⁽¹⁾	Power Costs ⁽¹⁾	Test Period	% of Retail Revenue ⁽²⁾

Utah	Utah Public Service Commission (“UPSC”)	December 2006 stipulation calls for an annual increase of $115.0 million with $85.0 million effective in December 2006 and the remaining $30.0 million effective in June 2007 ⁽³⁾.	No separate power cost recovery mechanism.	Forecasted test year.	41.9%
Oregon	Oregon Public Utility Commission (“OPUC”)	September 2006 settlement agreement resulted in an annual increase for non-power costs of $33.0 million effective in January 2007 ⁽⁴⁾.	Uses an annual transition adjustment mechanism, resulting in a $10.0 million increase in January 2007. After 2007, PacifiCorp's power costs will be updated annually.	Forecasted test year.	28.5%
Wyoming	Wyoming Public Service Commission (“WPSC”)	In March 2006, the WPSC approved the settlement of the general rate case. The settlement agreement provided for an annual rate increase of $15.0 million effective in March 2006, and an additional annual increase of $10.0 million effective in July 2006.	Power cost adjustment mechanism, subject to sharing and collars, was approved in March 2006 with an implementation date effective July 1, 2006.	Typically uses a historical test year with known and measurable changes. Key parties have agreed to allow PacifiCorp to file a forecasted test year in the next general rate case application.	13.4%
Washington	Washington Utilities and Transportation Commission (“WUTC”)	General rate increase of $23.2 million requested in October 2006. The WUTC decision is expected in June 2007.	Currently, no separate power cost recovery mechanism; Power cost recovery mechanism proposed in general rate case filing.	Historical with known and measurable changes.	7.7%
Idaho	Idaho Public Utilities Commission (“IPUC”)	In December 2006, the IPUC approved an $8.3 million rate increase for certain customers effective January 2007.	No separate power cost recovery mechanism.	Typically uses a historical test year with known and measurable changes.	6.2%
California	California Public Utilities Commission (“CPUC”)	In December 2006, the CPUC settled the general rate case, which provided for a $7.3 million annual increase. The settlement also provides for a post-test year adjustment mechanism that provides for inflation-based increases in rates in 2008 and 2009, the ability to seek recovery of the California-allocable portion of major plant additions exceeding $50.0 million, and scheduled increases under the terms of the transition plan for Klamath irrigators.	In December 2006, the CPUC approved a dollar-for-dollar energy cost adjustment clause that allows for annual changes in the level of net power costs.	Forecasted test year.	2.3%
					100.0%

⁽¹⁾	Margins earned on net wholesale sales for energy and capacity have historically been included as a component of retail cost of service upon which retail rates are based.

⁽²⁾	Represents the geographic distribution of PacifiCorp’s retail electric operating revenue for the nine months ended December 31, 2006.

⁽³⁾	PacifiCorp has agreed that another rate case will not be filed in Utah until after December 11, 2007.

⁽⁴⁾	PacifiCorp has agreed that another rate case will not be filed in Oregon until after September 1, 2007. Also, refer to Note 6 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding Oregon Senate Bill 408.

MidAmerican Energy

Iowa

Under a series of electric settlement agreements between MidAmerican Energy, the OCA and other interveners approved by the IUB, MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2013, unless its Iowa jurisdictional electric return on equity in any year falls below 10%. 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 seek any decrease in MidAmerican Energy’s Iowa electric base rates prior to January 1, 2013. 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 revenues for MidAmerican Energy. Additionally, under the incentive regulation aspects of the settlements, earnings exceeding a return on equity of 11.75% are shared with customers. Refer to Note 6 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional discussion regarding these settlements.

MidAmerican Energy does not have an electric fuel and purchased power adjustment clause in Iowa. A monthly purchased gas cost adjustment clause combined with an Incentive Gas Supply Procurement Plan provides protection from market changes in gas costs while offering financial incentives for MidAmerican Energy to minimize the cost of its gas supply portfolio.

Illinois

In December 1997, Illinois enacted a law to restructure Illinois’ electric utility industry. The law changed how and what electric services are regulated by the ICC and transitioned portions of the traditional electric services to a competitive environment. Electric base rates in Illinois were generally frozen until January 1, 2007, and are now subject to cost-based ratemaking.

Effective January 2007, MidAmerican Energy and the ICC have eliminated the monthly adjustment clause for recovery of fuel for electric generation and purchased power costs in Illinois. Base rates have been adjusted to include recoveries at average 2004/2005 cost levels. The elimination of the fuel adjustment clause exposes MidAmerican Energy to monthly market price changes for fuel and purchased power costs in Illinois, with rate case approval required for any base rate changes. With the elimination of the fuel adjustment clause, MidAmerican Energy may not petition for its reinstatement until November 2011. A monthly adjustment clause remains in effect for MidAmerican Energy’s purchased gas costs.

Federal Regulation

The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act and the Energy Policy Act. MidAmerican Energy is also subject to regulation by the Nuclear Regulatory Commission (“NRC”) pursuant to the Atomic Energy Act of 1954, as amended, with respect to the operation of the Quad Cities Station.

Federal Power Act

Under the Federal Power Act, the FERC regulates rates for interstate sales of electricity at wholesale, transmission of electric power, accounting, securities issuances and other matters, including construction and operation of hydroelectric projects. Margins earned on wholesale sales for electricity and capacity and transmission service have historically been included as a component of retail cost of service upon which retail rates are based.

Wholesale Electricity and Capacity

The FERC regulates PacifiCorp’s and MidAmerican Energy’s rates charged to wholesale customers for electricity, and capacity and transmission services. Most of PacifiCorp’s and MidAmerican Energy’s electric wholesale sales and purchases take place under market-based pricing allowed by the FERC and are therefore subject to market volatility. A December 2006 decision of the United States Court of Appeals for the Ninth Circuit changed the interpretation of the relevant standard which the FERC should apply when reviewing wholesale contracts for electricity or capacity. The decision raises some concerns regarding the finality of contract prices, particularly from the sellers’ side of the transactions. Parties to this proceeding are seeking review before the U.S. Supreme Court. Whether the U.S. Supreme Court will hear the case or the outcome of its ruling, should it decide to consider the matter, cannot be predicted at this time. All sellers subject to the FERC’s jurisdiction, including PacifiCorp and MidAmerican Energy, are currently subject to increased risk as a result of this decision.

The FERC conducts a triennial review of PacifiCorp’s and MidAmerican Energy’s market-based pricing authority. Each utility must demonstrate the lack of generation market power in order to charge market-based rates for sales of wholesale electricity and capacity in their respective control areas. In June 2006, the FERC ruled at the conclusion of its most recent review that PacifiCorp does not have market power and may continue to charge market-based rates. A change in filing status relating to new generation was confirmed by FERC in February 2007, reaching the same conclusion. Unless a current FERC rulemaking proceeding revises the triennial review requirement, PacifiCorp’s next triennial review will occur in 2009. MidAmerican Energy’s most recent review, which began in October 2004, is complete pending the FERC’s final ruling on certain sales made within MidAmerican Energy’s control area for delivery outside the control area. MidAmerican Energy has FERC authorization to sell at market-based rates outside of its control area. Based on its estimate of MidAmerican Energy’s potential refund obligation, the Company does not believe the ultimate resolution of this issue will have a material impact on MidAmerican Energy’s financial results. Subject to the outcome of the above rulemaking, MidAmerican Energy will submit its next triennial review three years after the date of the final order in the current review proceeding.

Transmission

The FERC regulates PacifiCorp’s and MidAmerican Energy’s wholesale transmission services. The regulation requires each to provide open access transmission service at cost-based rates. The FERC also regulates unbundled transmission service to retail customers. These services are offered on a non-discriminatory basis, meaning that all potential customers are provided an equal opportunity to access the transmission system. Our transmission businesses are managed and operated independently from our generating and wholesale marketing businesses in accordance with the FERC Standards of Conduct.

On February 16, 2007, the FERC adopted a final rule 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 to exempt intermittent generators, 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 redispatch. As transmission providers with OATT on file with FERC, PacifiCorp and MidAmerican Energy will be required to comply with the requirements of the new rule. Certain details related to the rule, such as the precise methodology that will be used to calculate available transfer capability, will be determined prospectively and thus, it is difficult to make a precise determination of the effect of this new rule on PacifiCorp’s and MidAmerican Energy’s transmission operations. In addition, it is difficult to determine the effect of this new rule once fully implemented on the availability and price of transmission service from the perspective of the wholesale marketing function. However, at least on a preliminary basis, the rule is not anticipated to have a significant impact on PacifiCorp’s or MidAmerican Energy’s financial results.

In January 2007, the FERC approved a settlement with PacifiCorp regarding PacifiCorp’s use of its transmission system while conducting wholesale power transactions with third parties. PacifiCorp discovered possible violations of its FERC-approved tariff during an internal review of its compliance with certain FERC regulations shortly before MEHC’s acquisition of PacifiCorp. Upon completion of the acquisition, PacifiCorp self-reported the potential violations to the FERC. The potential violations primarily related to the way PacifiCorp used its own transmission system to transmit energy using network service instead of point-to-point service as the FERC believes is required by PacifiCorp’s tariff. This use of transmission service neither enriched PacifiCorp’s shareholders nor harmed its retail customers. As part of the settlement, PacifiCorp voluntarily refunded $0.9 million to other transmission customers in April 2006 and paid a $10.0 million fine to the U.S. Treasury in January 2007.

Neither PacifiCorp nor MidAmerican Energy is part of a Regional Transmission Organization, but MidAmerican Energy has hired an independent transmission system coordinator to administer various MidAmerican Energy OATT functions for transmission service. PacifiCorp, along with other private utilities and public power organizations throughout the Pacific Northwest and Western United States, is a member of the Northern Tier Transmission Group, which initially will conduct reliability and economic planning coordination for its members.

Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 50 plants with an aggregate facility net owned capacity of 1,160.1 MW. The FERC regulates 97.9% of the installed capacity of this portfolio through 18 individual licenses. Several of PacifiCorp’s hydroelectric plants are in some stage of relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements are subject to significant uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. Refer to Note 19 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding hydroelectric relicensing.

Energy Policy Act

On August 8, 2005, the Energy Policy Act was signed into law and has significantly impacted the energy industry. In particular, the law expanded the FERC’s regulatory authority in areas such as electric system reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority to issue civil penalties of up to $1 million per day. While the FERC has now issued rules and decisions on multiple aspects of the Energy Policy Act, the full impact of those decisions remains uncertain.

The Energy Policy Act also repealed the Public Utility Holding Company Act of 1935 (“PUHCA 1935”) and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”), effective February 8, 2006. PUHCA 1935 extensively regulated and restricted the activities of registered public utility holding companies and their subsidiaries. PUHCA 2005 eliminated the substantive requirements and restrictions previously applicable to holding companies under PUHCA 1935. Its repeal enabled Berkshire Hathaway to convert its shares of MEHC’s no par, zero-coupon non-voting convertible preferred stock into an equal number of shares of MEHC’s voting common stock. As a consequence, MEHC became a majority owned subsidiary of Berkshire Hathaway. PUHCA 2005 also increased the FERC’s authority over utility mergers, provides the FERC with access to books and records and requires holding companies to comply with its record retention requirements.

The Energy Policy Act also gives the FERC “backstop” transmission siting authority and directs the FERC to oversee the establishment of mandatory transmission reliability standards. The Energy Policy Act also extended the federal production tax credit for new renewable electricity generation projects through December 31, 2007. In part as a result of that portion of the law, PacifiCorp and MidAmerican Energy began development efforts to add additional wind-powered generation facilities.

Nuclear Regulatory Commission

MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in Quad Cities Station. Exelon Generation is the operator of Quad Cities Station and 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. On October 29, 2004, the NRC extended the operating licenses for Quad Cities Station until December 14, 2032. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses. Federal regulations provide that any nuclear operating facility may be required to cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility, and the deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy that an emergency preparedness plan for Quad Cities Station has been approved by the NRC. Exelon Generation has also advised MidAmerican Energy that state and local plans relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.

MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station through a combination of insurance purchased by Exelon Generation (the operator and joint owner of Quad Cities Station), insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988, which was amended and extended by the Energy Policy Act of 2005. The general types of coverage are: nuclear liability, property coverage and nuclear worker liability.

U.S. Interstate Pipeline Subsidiaries

The natural gas pipeline and storage operations of the Company’s U.S. interstate pipeline subsidiaries are regulated by the FERC, which administers, most significantly, the Natural Gas Act and the Natural Gas Policy Act of 1978. Under this authority, the FERC regulates, among other items, (i) rates, charges, terms and conditions of service, and (ii) the construction and operation of U.S. 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 assignable to firm transportation and storage customers, including a return on invested capital and income taxes, are to be recovered through fixed monthly demand reservation charges regardless of volumes shipped. Commodity charges, which are paid only with respect to volumes actually shipped, are designed to recover the remaining, primarily variable, cost. Kern River’s rates have historically been set using a “levelized cost-of-service” methodology so that the rate is constant over the contract period; however, rate design is the subject of Kern River’s current rate case before the FERC and may be subject to change as a result of the rate case outcome. This levelized cost of service has been achieved by using a FERC-approved depreciation schedule in which depreciation increases as interest expense decreases. Refer to Note 6 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding recent rate case proceedings.

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

Additional proposals and proceedings that might affect the interstate natural gas pipeline industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Company cannot predict when or if any new proposals might be implemented or, if so, how Northern Natural Gas and Kern River Gas might be affected.

U.S. interstate natural gas pipelines are also subject to the regulations of the Department of Transportation (“DOT”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities, and the federal PSIA, which implemented additional safety and pipeline integrity regulations for high consequence areas.

The NGPSA requires any entity that owns or operates pipeline facilities to comply with applicable safety standards, to establish and maintain inspection and maintenance plans and to comply with such plans. The Company’s pipeline operations conduct internal audits of their major facilities at least every four years, with more frequent reviews of those it deems of higher risk. The DOT also routinely audits these pipeline facilities. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis.

The PSIA, as amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, established mandatory inspections for all natural gas pipelines in high-consequence areas. These regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protection in areas where the consequences of potential pipeline accidents pose the greatest risk to life and property. The Company believes its pipeline operations comply in all material respects to this regulation. The regulation also requires Northern Natural Gas and Kern River to complete certain modifications to their pipeline systems by December 17, 2012. Each pipeline is scheduled to have this work completed by December 2011.

In addition to FERC regulation, certain operations are subject to oversight by state regulatory commissions.

U.K. 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 the Office of Gas and Electricity Markets (“Ofgem”). Each of fourteen distribution license holders (“DLH”) distributes electricity from the national grid system to end use customers within their respective distribution service areas effectively creating a monopoly on electricity distribution within each area.

Given the absence of a competitive market, the amount of revenue that can be collected from customers by a DLH is controlled by a distribution price control formula. This encourages companies to look for efficiency gains in order to improve profits. The distribution price control formula also adjusts the revenue received by DLHs to reflect an increase or decrease in distribution of units and number of end users. 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 was agreed in December 2004, became effective April 2005 and is expected to continue through March 2010. Prices during this 5-year period will be allowed to increase by no more than the rate of inflation (based upon the retail price index). Ofgem also indicated that during the current price control period, the retention of any actual reductions in operating costs from the assumptions used in setting the new price control might depend on the successful implementation of revised cost reporting guidelines prescribed by Ofgem and to be applied by all DLHs.

In 2005, the triennial process to value the UK pension plan’s assets and liabilities, using a March 31, 2004 measurement date, was completed and showed a £190.3 million funding deficiency. Contributions are computed based on the objective of eliminating the funding deficiency by April 1, 2017. CE Electric UK contributed £17.3 million in 2005 and £23.1 million in 2006 and intends to contribute an additional £23.1 million in 2007 to reduce the funding deficiency. Both Northern Electric’s and Yorkshire Electricity’s current price control allows for the recovery of the majority of the deficiency payments over time.

A number of incentive schemes also operate within the current price control period to encourage DLHs to provide an appropriate quality of service 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 force majeure circumstances. There are also incentive schemes pursuant to which allowed revenue may increase by up to 3.3% or decrease by up to 3.5% in any year.

Ofgem also monitors DLH compliance with license conditions and enforces the remedies resulting from any breach of condition. Under the Utilities Act 2000, the regulators are able to impose financial penalties on DLHs 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.

On November 3, 2006, Ofgem announced that it was investigating the possible breach by Northern Electric and Yorkshire Electricity of license conditions that require them to provide Ofgem with certain information pertaining to the number and duration of interruptions in the supply of electricity through the licensee’s electricity distribution system and the number and identity of customers who had telephoned the licensee to report a loss of supply. The investigation is ongoing and if Ofgem concludes a violation of the standard has occurred, it may impose a penalty as described above.

Independent Power Projects

Foreign

The Philippine Congress passed the Electric Power Industry Reform Act of 2001 (“EPIRA”), legislation aimed at restructuring the Philippine power industry, privatizing the NPC and introducing a competitive electricity market. 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. However, CE Casecnan has received written confirmation from the Philippine government that the issues with respect to the Casecnan Project that had been raised by the interagency review of independent power producers in the Philippines or that may have existed with respect to the project under certain provisions of EPIRA, which authorized the ROP to seek to renegotiate certain contracts such as the Project Agreement, have been satisfactorily addressed.

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.

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. 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 U.S. Department of Housing and Urban Development, 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.

Environmental Regulation

MEHC and its energy subsidiaries are subject to federal, state, local, and foreign laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters and are subject to zoning and other regulation by local authorities. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance including fines, injunctive relief and other sanctions. The Company believes it is in material compliance with all laws and regulations. The most significant environmental laws and regulations affecting MEHC’s subsidiaries include:

The federal Clean Air Act, as well as state laws and regulations impacting air emissions, including State Implementation Plans related to existing and new national ambient air quality standards. Rules issued by the United States Environmental Protection Agency (“EPA”) and certain states require substantial reductions in sulfur dioxide (“SO₂”), mercury, and nitrogen oxide (“NO_x”) emissions beginning in 2009 and extending through 2018. The Company has already installed certain emission control technology and is taking other measures to comply with required reductions. Refer to the Clean Air Standards section below for additional discussion regarding this topic.

The Clean Water Act and individual state clean water laws that regulate cooling water intake structures and discharges of wastewater, including storm water runoff. The Company believes that it currently has, or has initiated the process to receive, all required water quality permits. Refer to the Clean Water Standards section below for additional discussion regarding this topic.

The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws, which may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs. Refer to Note 19 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding environmental contingencies.

The Nuclear Waste Policy Act of 1982, under which the U.S. Department of Energy is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. Refer to Note 12 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding the nuclear decommissioning and mine reclamation obligations.

The FERC oversees the relicensing of existing hydroelectric projects and is also responsible for the oversight and issuance of licenses for new construction of hydroelectric projects, dam safety inspections and environmental monitoring. Refer to Note 19 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding the relicensing of certain of PacifiCorp’s existing hydroelectric facilities.

The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Company. In particular, the Clean Air Act will likely continue to impact the operation of the Company’s domestic generating facilities and will likely require both PacifiCorp and MidAmerican Energy to make emissions reductions at their facilities through the installation of emission controls or to comply with the regulations through the purchase of additional emission allowances or some combination thereof.

Expenditures for compliance-related items such as pollution-control technologies, replacement generation, mine reclamation, nuclear decommissioning, hydroelectric relicensing, hydroelectric decommissioning and associated operating costs are generally incorporated into the routine cost structure of MEHC’s energy subsidiaries. An inability to recover these costs from the Company’s customers, either through regulated rates, long-term arrangements or market prices, could adversely affect the Company’s future financial results.

Clean Air Standards

The Clean Air Act provides a framework for protecting and improving the nation’s air quality, and controlling mobile and stationary sources of air emissions. The major Clean Air Act programs, which most directly affect the Company’s electric generating facilities, are briefly described below. Many of these programs are implemented and administered by the states, which can impose additional, more stringent requirements.

National Ambient Air Quality Standards

The EPA implements national ambient air quality standards for ozone and fine particulate matter, as well as for other criteria pollutants that set the minimum level of air quality for the United States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area are required to make emissions reductions. The counties in Washington, Idaho, Montana, Wyoming, Colorado, Utah and Arizona, where PacifiCorp’s major emission sources are located, and the entire state of Iowa, where MidAmerican Energy’s major emission sources are located, are in attainment of the ambient air quality standards. A new, more stringent standard for fine particulate matter became effective on December 18, 2006, but is under legal challenge in the United States Court of Appeals for the District of Columbia Circuit. Air quality modeling and preliminary air quality monitoring data indicate that portions of the states in which PacifiCorp and MidAmerican Energy have major emission sources may not meet the new standards. Until three years of data are collected and attainment designations under the new fine particulate standard are made, the impact of these new standards on PacifiCorp and MidAmerican Energy will not be known.

Regulated Air Pollutants

In March 2005, the EPA released the final Clean Air Mercury Rule (“CAMR”), a two-phase program that utilizes a market-based cap and trade mechanism to reduce mercury emissions from coal-burning power plants from the 1999 nationwide level of 48 tons to 15 tons. The program requires initial reductions of mercury emission in 2010 and an overall reduction in mercury emissions from coal-burning power plants of 70% by 2018. Individual states are required to implement the CAMR or alternative measures to achieve equivalent or greater mercury emission reductions through their state implementation plans. The CAMR is applicable to all PacifiCorp and MidAmerican Energy coal-fired facilities.

In March 2005, the EPA released the final Clean Air Interstate Rule (“CAIR”), calling for reductions of SO₂ and NO_x emissions in the eastern United States through, at each state’s option, a market-based cap and trade system, emission reductions, or both. The state of Iowa has adopted rules implementing the market-based cap and trade system. Under the CAIR, the first phase of NO_x emissions reductions are effective January 1, 2009, and the first phase of SO₂ emissions reductions are effective January 1, 2010. For both NO_x and SO₂, the second-phase reductions are effective January 1, 2015. The CAIR requires overall reductions by 2015 of SO₂ and NO_x in Iowa of 68% and 67%, respectively, from 2003 levels. PacifiCorp’s generation facilities are not subject to the CAIR.

The CAMR or the CAIR could, in whole or in part, be superseded or made more stringent by current or future regulatory and legislative proposals at the federal or state levels that would result in significant reductions of SO₂, NO_X and mercury, as well as carbon dioxide and other gases that may affect global climate change. In addition to any federal rules or legislation that could be enacted, the CAMR and the CAIR could be changed or overturned as a result of litigation. The sufficiency of the standards established by both the CAMR and the CAIR has been legally challenged in the United States District Court of Appeals for the District of Columbia Circuit.

Regional Haze

The EPA has initiated a regional haze program intended to improve visibility at specific federally protected areas. Some of PacifiCorp’s and MidAmerican Energy’s plants meet the threshold applicability criteria under the Clean Air Visibility Rules. With other stakeholders, PacifiCorp is participating in the Western Regional Air Partnership and MidAmerican Energy is participating in the Central States Regional Air Partnership to help develop the technical and policy tools needed to comply with this program.

New Source Review

Under existing New Source Review (“NSR”) provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory agency prior to (1) beginning construction of a new major stationary source of an NSR-regulated pollutant or (2) making a physical or operational change to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations are subject to pre-construction review and permitting under the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo a Best Available Control Technology analysis and evaluate the most effective emissions controls. These controls must be installed in order to receive a permit. Violations of NSR regulations, which may be alleged by the EPA, states and environmental groups, among others, potentially subject a utility to material expenses for fines and other sanctions and remedies including requiring installation of enhanced pollution controls and funding supplemental environmental projects.

As part of an industry-wide investigation to assess compliance with the PSD and the New Source Performance Standards of the Clean Air Act (referred to collectively as NSR), the EPA has requested from numerous utilities information and supporting documentation regarding their capital projects for various generating plants. In 2001 and 2003, PacifiCorp received requests for information relating to capital projects at seven of its generating plants. In 2002 and 2003, MidAmerican Energy received requests to provide documentation related to its capital projects at its generating plants. PacifiCorp and MidAmerican Energy have submitted information to the EPA in response to these requests, and there are currently no outstanding data requests pending from the EPA. An NSR enforcement case against another utility has been argued and is currently pending decision in the Supreme Court. The Supreme Court’s decision in that case may provide a definitive legal ruling on the proper legal test that EPA may apply in examining data such as that submitted by PacifiCorp and MidAmerican Energy to determine whether there has been an emissions increase. PacifiCorp and MidAmerican Energy cannot predict the outcome of EPA’s review of the data they have submitted at this time.

In 2002 and 2003, the EPA proposed various changes to its NSR rules that clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. These changes have been subject to legal challenge and in March 2006, a panel of the United States Court of Appeals for the District of Columbia Circuit invalidated portions of EPA’s new NSR rules, holding that they conflicted with the wording of the statute. However, EPA has asked the Supreme Court to review portions of the case. Until such time as the legal challenges are resolved and the revised rules are effective, PacifiCorp and MidAmerican Energy will continue to manage projects at their generating plants in accordance with the rules in effect prior to 2002, except for pollution-control projects, which are now subject to permitting under the PSD program. In 2005, the EPA proposed a rule that would change or clarify how emission increases are to be calculated for purposes of determining the applicability of the NSR permitting program for existing power plants. The EPA also proposed additional changes to the NSR rules in September 2006 that are intended to simplify the permitting process and allow facilities to undertake activities that improve their safety, reliability and efficiency without triggering NSR requirements. The EPA plans to finalize the rules by May 2007.

Refer to the Liquidity and Capital Resources section of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information regarding planned capital expenditures related to air quality standards. Refer to Note 19 of Notes to the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding commitments and litigation related to air quality standards.

Climate Change

As a result of increased attention to climate change in the United States numerous bills have been introduced in the current session of the United States Congress that would reduce greenhouse gas emissions in the United States. Congressional leadership has made climate change legislation a priority and many congressional observers expect to see the passage of climate change legislation within the next several years. While debate continues at the national level over the direction of domestic climate policy, several states have developed state-specific or regional legislative initiatives to reduce greenhouse gas emissions. For example, the states of Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont have signed a mandatory regional pact to reduce greenhouse gas emissions by ten percent from 1990 levels that would become effective in 2009. An executive order signed by California’s governor in 2005 would reduce greenhouse gas emissions in that state to 2000 levels by 2010, to 1990 levels by 2020 and 80 percent below 1990 levels by 2050. In August 2006, California enacted a greenhouse gas emission performance standard applicable to all electricity generated within the state or delivered from outside the state that is no higher than the greenhouse gas emission levels of a state-of-the-art combined-cycle natural gas generation facility. California also adopted a statewide greenhouse gas emission cap to reduce greenhouse gas emissions by approximately 25% from 1990 levels by 2020. In November 2006, Washington voters passed a measure, which modified state law to require utilities that serve more than 25,000 Washington customers to obtain at least 15% of their electricity from renewable resources by the year 2020. The outcome of federal and state climate change legislation cannot be determined at this time; however, adoption of stringent limits on greenhouse emissions could significantly impact the Company’s fossil-fueled facilities, and, therefore, its financial results.

Water Quality Standards

The Clean Water Act establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the “best technology available for minimizing adverse environmental impact” to aquatic organisms. In July 2004, the EPA established significant new national technology-based performance standards for existing electric generating facilities that take in more than 50 million gallons of water a day. These rules are aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the Second Circuit Court of Appeals remanded almost all aspects of the rule to the EPA, leaving companies with cooling water intake structures uncertain regarding compliance with these requirements. Compliance and the potential costs of compliance, therefore, cannot be ascertained until such time as further action is taken by the EPA. In the event that PacifiCorp’s or MidAmerican Energy’s existing intake structures require modification or alternative technology is required by new rules, expenditures to comply with these requirements could be significant.

Item 1A. Risk Factors.

We are subject to certain risks in our business operations which are described below. Careful consideration of these risks should be made before making an investment decision. The risks and uncertainties described below are not the only ones facing us. 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 stock of our subsidiaries and joint ventures, or 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, loans, advances or other distributions. Our subsidiaries are separate and distinct legal entities and they have no obligation, contingent or otherwise, to provide us with funds or to guarantee the payment of any of our 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 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 debt 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 have an adverse impact on our 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. At December 31, 2006, we had the following outstanding obligations:

·	senior indebtedness of $4.5 billion;

·	subordinated indebtedness of $1.4 billion, consisting of $0.3 billion of trust preferred securities held by third parties and $1.1 billion held by Berkshire Hathaway and its affiliates; and

·	guarantees and letters of credit in respect of subsidiary and equity investment indebtedness aggregating $97.8 million.

Our consolidated subsidiaries also have outstanding indebtedness, which totaled $11.6 billion at December 31, 2006. These amounts exclude (i) trade debt or preferred stock obligations, (ii) letters of credit in respect of subsidiary indebtedness, and (iii) our share of the outstanding indebtedness of our own or our subsidiaries’ equity investments.

Given our substantial leverage, we may not generate 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 economic conditions. It 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, 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 have a material adverse effect on our or our subsidiaries’ 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.

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 the revolving credit agreements, 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, operating costs would likely increase because counterparties may require a letter of credit, collateral in the form of cash-related instruments or some other security 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 strategic acquisitions, and additional acquisitions may not be successful.

Our growth has been achieved largely through strategic acquisitions, including, since 2002, those of Kern River, Northern Natural Gas, PacifiCorp and various residential real estate brokerage businesses. We will continue to investigate and pursue opportunities for strategic 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, debt or equity securities.

Completion of any business or asset 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;

·	failure of the combined business to realize the expected benefits; and

·	need for substantial additional capital and financial investments.

An acquisition could cause an interruption of, or loss of momentum in, the activities of one or more of our businesses. The diversion of management’s attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect our combined businesses and financial results and could impair our ability to realize the anticipated benefits of the acquisition.

Our regulated businesses are subject to extensive regulations that affect their operations and costs. These regulations 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, FERC, EPA, NRC, and the DOT. In addition, our 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 equity or debt 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 materially impact our financial results. For example, such changes could result in, but are not limited to, increased retail competition within our subsidiaries’ service territories, new environmental requirements, the acquisition by a municipality or other quasi-governmental body of our subsidiaries’ distribution facilities (by negotiation, legislation or condemnation or by a vote in favor of a Public Utility District under Oregon law), or a negative impact on our subsidiaries’ current transportation and cost recovery arrangements, including income tax recovery.

Federal and state energy regulation changes are emerging as one of the more challenging aspects of managing utility operations. New and expanded regulations imposed by policy makers, court systems, and industry restructuring have imposed changes on the industry. The following are current or recent changes to our regulatory environment that may impact us:

Energy Policy Act of 2005 - In the United States, the Energy Policy Act impacts many segments of the energy industry. Congress granted the FERC additional authority in the Energy Policy Act which expanded its regulatory role from a regulatory body to an enforcement agency. To implement the law, the FERC has and will continue to issue new regulations and regulatory decisions addressing electric system reliability, electric transmission expansion and pricing, regulation of utility holding companies, and enforcement authority, including the ability to assess civil penalties of up to one million dollars per day per infraction for non-compliance. The full impact of those decisions remains uncertain however, the FERC has recently 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 effective June 1, 2007. Under the new regime, a transmission owner’s reliability compliance issues could result in financial penalties. Such measures could impose more comprehensive or stringent requirements on us or our subsidiaries, which would result in increased compliance costs and could adversely affect our financial results.

FERC Orders - FERC has issued several orders, including Orders 636 and 637, to encourage competition in natural gas markets, the expansion of existing pipelines and the construction of new pipelines. Local distribution companies 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.

Hydroelectric Relicensing - Several of PacifiCorp’s hydroelectric projects whose operating licenses have expired or will expire in the next few years are in some stage of the FERC relicensing process. 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, whether new licenses will ultimately be issued or whether PacifiCorp will be willing to meet the relicensing requirements to continue operating its hydroelectric projects. Loss of hydroelectric resources or additional commitments arising from relicensing could increase PacifiCorp’s operating costs or result in large capital expenditures that reduce earnings and cash flows.

Recovery of costs by our energy subsidiaries is subject to regulatory review and approval, and the inability to recover costs may adversely affect their financial results.

State Rate Proceedings - Public Utility Subsidiaries

Two of our regulated subsidiaries, PacifiCorp and MidAmerican Energy, 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 normal, 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. Certain states use a future test year or allow for escalation of historical costs while other states use an historical test year. Use of an historical test year may cause regulatory lag which results in our utilities incurring costs, including significant new investments, for which recovery through rates is delayed. State commissions also decide the allowed rate of return we will be permitted to earn on our equity investment. They also decide the allowed levels of expense and investment that they deem is just and reasonable in providing service. The state commissions may disallow recovery in rates for any costs that do not meet such standard.

In Iowa, MidAmerican Energy has agreed not to seek a general increase in electric base rates to become effective prior to January 1, 2013 unless its Iowa jurisdictional electric return on equity for any year falls below 10%. MidAmerican Energy expects to continue to make significant capital expenditures to maintain and improve the reliability of its generation, transmission and distributions 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 costs savings or additional sales.

In certain states, PacifiCorp and MidAmerican Energy are not permitted to pass through energy cost increases in their electric rates without a general rate case. Any significant increase in fuel costs or purchased power costs for electricity generation 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 instruments. Any of these consequences could adversely affect our financial results.

While rate regulation is premised on providing a fair opportunity to obtain a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that we will be able to realize a reasonable rate of return.

FERC Jurisdiction - Public Utility Subsidiaries

FERC establishes cost-based tariffs under which both PacifiCorp and MidAmerican Energy provide transmission services to wholesale markets and retail markets in states that allow retail competition. FERC also has responsibility for approving both cost- and market-based rates under which both companies sell electricity at wholesale and has licensing authority over most of PacifiCorp’s hydroelectric generation facilities. 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 financial results. FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act, FERC’s rules or orders.

Interstate Pipelines

FERC has jurisdiction over, among other things, 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. FERC also has jurisdiction over the rates, charges and terms and conditions of service for the transportation of natural gas in interstate commerce.

Rates established for our U.S. interstate gas transmission and storage operations at Northern Natural Gas and Kern River are subject to FERC’s regulatory authority. The rates 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 FERC which prevent them or third parties from modifying rates, except for allowed adjustments, for certain periods. These settlements do not preclude FERC from initiating a separate proceeding under the Natural Gas Act to modify the rates. It is not possible to determine at this time whether any such actions would be instituted or what the outcome would be, but such proceedings could result in rate adjustments.

U.K. Electricity Distribution

Northern Electric and Yorkshire Electricity, as holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of the electricity distribution license holders is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not constrain profits from year to year, but is a control on revenue that operates independently of most of the electricity distribution license holder’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. A resetting of the formula requires the consent of the electricity distribution license holder however, license modifications may be unilaterally imposed by Ofgem without such consent following review by the British competition commission. GEMA is able to impose financial penalties on electricity distribution companies who 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 electricity distribution license holder’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 energy subsidiaries, we are actively pursuing, developing and constructing new or expanded facilities, the completion and expected cost of which is subject to significant risk, and our electric utility subsidiaries have significant funding needs related to their planned capital expenditures.

Through energy 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 coal-fired, natural gas and wind powered 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 These risks may result in higher than expected costs to complete an asset and place it into service. Such costs, if found to be imprudent, may not be recoverable in the rates our subsidiaries are able to charge their customers. The inability to successfully and timely complete a project, avoid unexpected costs or to recover any such costs may materially affect our financial results.

Furthermore, our energy 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 projects could limit opportunities for revenue growth and increase operating costs. For example, if PacifiCorp is not able to expand its existing generating facilities it may be required to enter into bilateral long-term electricity procurement contracts or procure electricity at more volatile and potentially higher prices in the spot markets to support growing retail loads.

Our subsidiaries are subject to numerous environmental, health, safety and other laws, regulations and other requirements that may adversely affect our 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 CAIR, which established cap and trade programs to reduce sulfur dioxide, or SO₂, and nitrous oxide, or NO_x, emissions starting in 2009 to address alleged contributions to downwind non-attainment with the revised National Ambient Air Quality Standards;

·	the EPA’s CAMR, which establishes a cap and trade program to reduce mercury emissions from coal-fired power plants starting in 2010;

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

·	other laws or regulations that establish or could establish standards for greenhouse gas emissions, water quality, wastewater discharges, solid waste and hazardous waste.

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 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 or developing 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 financial results. Proposals for voluntary initiatives and mandatory controls are being discussed both in the United States and worldwide to reduce so-called ‘‘greenhouse gases’’ such as carbon dioxide, a by-product of burning fossil fuels, methane (the primary component of natural gas), and methane leaks from pipelines. These actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any greenhouse gas emissions program. These actions could also impact the consumption of natural gas, thereby affecting our operations.

Further, the regulatory rate structure or long-term customer contracts may not necessarily allow our subsidiaries to recover all costs incurred to comply with new environmental requirements. Although we believe that, in most cases, our regulated subsidiaries are legally entitled to recover these kinds of costs, the inability to fully recover such costs in a timely manner could adversely affect our financial results.

Site Clean-up and Contamination

Environmental, health, safety, and other laws, regulations and other 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 generation facilities, and electric and natural gas transmission and distribution assets which 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. 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 which may be material. MidAmerican Energy is also 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.

Our subsidiaries are exposed to credit risk of counterparties with whom they do business and failure of their significant customers to perform under or to renew their contracts could reduce our operating revenues materially.

Certain of our subsidiaries are dependent upon a relatively small number of customers for a significant portion of their revenues. For example:

·	a 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 revenues;

·	PacifiCorp and MidAmerican Energy rely on their wholesale customers to fulfill their commitments and pay for energy delivered to them on a timely basis;

our U.K. utility electricity distribution businesses are dependent upon a relatively small number of retail suppliers. In particular, one supplier, RWE Npower PLC and certain of its affiliates represented approximately 42% of the total distribution revenues of our U.K. distribution companies in 2006; and

·	generally, a single power purchaser takes energy from our non-utility generating facilities.

Adverse economic conditions or other events affecting counterparties with whom our subsidiaries conduct business could impair the ability of these counterparties to pay for services or fulfill their contractual obligations, or cause them to delay or reduce such payments to our subsidiaries. Our subsidiaries depend on these counterparties to remit payments on a timely basis. Any delay or default in payment or limitation on the subsidiaries to negotiate alternative arrangements could adversely affect our financial results.

If our subsidiaries are unable to renew, remarket, or find replacements for their long-term arrangements, our sales volume and revenue would be exposed to increased volatility. For example, without the benefit of long-term transportation, transmission or power purchase agreements, we cannot assure that our pipeline subsidiaries will be able to transport gas at efficient capacity levels, our regulated subsidiaries’ will be able to operate profitably, or our unregulated power generators will be able to sell the power generated by the non-utility generating facilities. Failure to secure these long-term arrangements could adversely affect our financial results.

The replacement of any existing long-term customer arrangements depends on market conditions and other factors that are beyond our subsidiaries’ control.

Inflation and changes in commodity prices and fuel transportation costs may adversely affect our financial results.

Inflation affects our businesses through increased operating costs and increased capital costs for plant and equipment. As a result of existing rate agreements and competitive price pressures, our subsidiaries may not be able to pass the costs of inflation on to their customers. If our subsidiaries are unable to manage costs increases or pass them on to their customers, our financial results could be adversely affected.

We are also heavily exposed to changes in prices and availability of coal and natural gas and the transportation of coal and natural gas because a substantial majority of our generation capacity utilizes these fossil fuels. Each of our electric utilities currently has contracts of varying durations for the supply and transportation of coal for much of their existing generation capacity, although PacifiCorp obtains some of its coal supply from mines owned or leased by it. When these contracts expire or if they are not honored, we may not be able to purchase or transport coal on terms as favorable as the current contracts. We have similar exposures regarding the market price of natural gas. Changes in the cost of coal or natural gas supply and transportation and changes in the relationship between such costs and the market price of power will affect our financial results. Since the sales price we receive for power may not change at the same rate as our coal or natural gas supply and transportation costs, we may be unable to pass on the changes in costs to our customers. In addition, the overall prices we charge our retail customers in some jurisdictions are capped and our fuel recovery mechanisms in other states are frozen for various periods of time or have been eliminated.

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

A sustained decrease in demand for natural gas in the markets served by our subsidiaries’ pipeline and gas distribution systems would significantly reduce our operating revenue and adversely affect our financial results. Factors that could lead to a decrease in market demand include, among others:

·	a recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on natural gas;

·	an increase in the market price of natural gas or a decrease in the price of other competing forms of energy, including electricity, coal and fuel oil;

·	efforts by customers to reduce their consumption of natural gas through various conservation measures and programs;

·	higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or that limit the use of natural gas; and

·	a shift to more fuel-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation proposing to mandate higher fuel economy, price differentials, incentives or otherwise.

Our public utility subsidiaries’ financial results may be adversely affected if they are unable to obtain adequate, reliable and affordable access to transmission service.

Our public utility subsidiaries depend on transmission facilities owned and operated by other utilities to transport electricity and natural gas to both wholesale and retail markets, as well as natural gas purchased to supply some of our subsidiaries’ electric generation facilities. If adequate transmission is unavailable, our subsidiaries may be unable to purchase and sell and deliver products. Such unavailability could also hinder our subsidiaries from providing adequate or economical electricity or natural gas to their wholesale and retail electric and gas customers and could adversely affect their financial results.

The different regional power markets have varying and dynamic regulatory structures, which could affect our businesses growth and performance. In addition, the independent system operators who oversee the transmission systems in regional power markets have imposed in the past, and may impose in the future, price limitations and other mechanisms to counter volatility in the power markets. These types of price limitations and other mechanisms may adversely impact the financial results of our utilities.

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. PacifiCorp and MidAmerican Energy 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.

Wholesale electricity prices in PacifiCorp’s service areas are influenced primarily by factors throughout the western United States relating to supply and demand. Those factors include the adequacy of generating capacity, scheduled and unscheduled outages of generating facilities, hydroelectric generation levels, prices and availability of fuel sources for generation, disruptions or constraints to transmission facilities, weather conditions, economic growth and changes in technology. Volumetric changes are caused by unanticipated changes in generation availability and/or changes in customer loads due to the weather, the economy, regulations or customer behavior. Although PacifiCorp plans for resources to meet its current and expected retail and wholesale load obligations, PacifiCorp is a net buyer of electricity during peak periods and therefore, its energy costs may be adversely impacted by market risk. In addition, PacifiCorp may not be able to timely recover all, if any, of those increased costs unless the state regulators authorize such recovery.

MidAmerican Energy’s total accredited net generating capability exceeds its historical peak load. As a result, in comparison to PacifiCorp, which relies to a significant extent on wholesale power purchases to satisfy its peak load, MidAmerican Energy has less exposure to wholesale electricity market price fluctuations. The actual amount of generation capacity available at any time, however, may be less than the accredited capacity due to regulatory restrictions, transmission constraints, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling, modifications or other reasons. In such circumstances, MidAmerican Energy may need to purchase energy in the wholesale markets and it may not recover in rates all of the additional costs that may be associated with such purchases. Most of MidAmerican Energy’s electric wholesale sales and purchases take place under market-based pricing allowed by the FERC and are therefore subject to market volatility, including price fluctuations.

PacifiCorp and MidAmerican Energy are also exposed to risks related to performance of contractual obligations by wholesale suppliers and customers. Each utility relies on 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 contractual agreements terminate, the utilities may be unable to purchase the commodities on terms equivalent to the terms of current contractual agreements.

PacifiCorp and MidAmerican Energy 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 PacifiCorp and MidAmerican Energy for energy needed to satisfy their customers’ energy needs may exceed the amounts they receive through rates from these customers. If the strategy used to hedge these risk exposures is ineffective, significant losses could result.

Our operating results may fluctuate on a seasonal and quarterly basis.

The sale of electric power and natural gas are generally seasonal businesses. In most parts of the United States and other markets in which our subsidiaries operate, demand for electricity peaks during the hot summer months when cooling needs are higher. Market prices for electric supply also generally peak at that time. In other areas, demand for electricity peaks during the winter. In addition, demand for gas and other fuels generally peaks during the winter when heating needs are higher. This is especially true in Northern Natural Gas’ market area and MidAmerican Energy’s retail gas business. Further, extreme weather conditions such as heat waves or winter storms could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snow-pack may also impact electric generation at PacifiCorp’s hydroelectric projects.

As a result, the overall financial results of our energy subsidiaries may fluctuate substantially on a seasonal and quarterly basis. We have historically sold less power, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect our financial results through lower revenues or increased energy costs. Conversely, unusually extreme weather conditions could increase our costs to provide power and adversely affect our financial results. Furthermore, during or following periods of low rainfall or snowpack, PacifiCorp may obtain substantially less electricity from hydroelectric projects and must purchase greater amounts of electricity from the wholesale market or from other sources at market prices. The extent of fluctuation in financial results may change depending on a number of factors related to our subsidiaries’ regulatory environment and contractual agreements, including their ability to recover power costs, the existence of revenue sharing provisions and terms of the power sale contracts.

Our subsidiaries are subject to operating uncertainties that may adversely affect our financial results.

The operation of complex electric and gas utility (including generation, transmission and distribution) systems, pipelines or power generating facilities that are spread over large geographic areas involves many operating uncertainties and events beyond our control. These potential events include the breakdown or failure of power generation equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, unscheduled plant outages, work stoppages, shortage of qualified labor, transmission and distribution system constraints or outages, fuel shortages or interruptions, unavailability of critical equipment, materials and supplies, low water flows, performance below expected levels of output, capacity or efficiency, operator error and catastrophic events such as severe storms, fires, earthquakes or explosions. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Any of these risks or other operational risks could significantly reduce or eliminate our subsidiaries’ revenues or significantly increase their expenses, thereby reducing the availability of distributions to us. For example, if our subsidiaries cannot operate their electric or natural gas facilities at full capacity due to damage caused by a catastrophic event, their revenues could decrease due to decreased wholesale sales and their expenses could increase due to the need to obtain energy from more expensive sources. Further, we self-insure many risks and current and future insurance coverage may not be sufficient to replace lost revenues or cover repair and replacement costs. Any reduction of revenues for such reason, or any other reduction of our subsidiaries’ revenues or increase in their expenses resulting from the risks described above could adversely affect our financial results.

Potential terrorist activities or military or other actions could adversely affect us.

The continued threat of terrorism since September 11, 2001 and the impact of military and other actions by the United States and its allies may lead to increased political, economic and financial market instability and subject our subsidiaries’ operations to increased risk of acts of terrorism. The United States government has issued warnings that energy assets, specifically pipeline, nuclear generation and other electric utility infrastructure are potential targets for terrorist organizations. Political, economic or financial market instability or damage to the operating assets of our subsidiaries, customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to natural gas and electric energy, increased security, repair or other costs that may materially adversely affect us and our subsidiaries in ways that cannot be predicted at this time. Any of these risks could materially affect our financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect our ability and the ability of our subsidiaries to raise capital.

The insurance industry changed in response to these events. As a result, insurance covering risks we and our subsidiaries typically insure against may decrease in scope and availability and we may elect to self-insure against many such risks. In addition, the available insurance may have higher deductibles, higher premiums and more restrictive policy terms.

MidAmerican Energy is subject to the unique risks associated with nuclear generation.

The ownership and operation of nuclear power plants, such as MidAmerican Energy’s 25% ownership interest in the Quad Cities Station involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. The prolonged unavailability of the Quad Cities Station could materially affect MidAmerican Energy’s financial results, particularly when the cost to produce power at the plant is significantly less than market wholesale power prices. The following are among the more significant of these risks:

Operational Risk - Operations at any nuclear power plant could degrade to the point where the plant would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased power expense to meet supply commitments. Rather than incurring substantial costs to restart the plant, the plant could be shut down. Furthermore, a shut-down or failure at any other nuclear plant could cause regulators to require a shut-down or reduced availability at the Quad Cities Station.

Regulatory Risk - The NRC, may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, applicable regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for the Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.

Nuclear Accident Risk - Accidents and other unforeseen problems have occurred at nuclear facilities other than the Quad Cities Station, both in the United States and elsewhere. The consequences of an accident can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident could exceed MidAmerican Energy’s resources, including insurance coverage.

We own investments and projects located in foreign countries that are exposed to increased economic, regulatory and political risks.

We own and may acquire significant energy-related investments and projects outside of the United States. The economic, regulatory and political conditions in some of the countries where we have operations or are pursuing investment opportunities may present increased risks related to, among others, inflation, currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, expropriation, trade sanctions, contract nullification and changes in law, regulations, or tax policy. We may not be capable of either fully insuring against or effectively hedging these risks.

We are exposed to risks related to fluctuations in currency rates.

Our business operations and investments outside the United States increase our risk related to fluctuations in currency rates, primarily the British pound and the Philippine peso. Our principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from our foreign operations changes with the fluctuations of the currency in which they transact. We may selectively reduce some foreign currency risk by, among other things, requiring contracted amounts be settled in United States dollars, indexing contracts to the United States dollar or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect our financial results. We attempt, in many circumstances, to structure foreign transactions to provide for payments to be made in, or indexed to, United States dollars or a currency freely convertible into United States dollars. We may not be able to obtain sufficient dollars or other hard currency or available dollars may not be allocated to pay such obligations, which could adversely affect our financial results.

Cyclical fluctuations in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.

The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions which are beyond HomeServices’ control. Any of the following are examples of items that could have a material adverse effect on HomeServices’ businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:

·	rising interest rates or unemployment rates;

·	periods of economic slowdown or recession in the markets served;

·	decreasing home affordability;

·	declining demand for residential real estate as an investment; and

·	nontraditional sources of new competition.

We and our subsidiaries are involved in numerous legal proceedings, the outcomes of which are uncertain and could negatively affect our financial results.

We and our subsidiaries are parties to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters. It is reasonably possible that the final resolution of some of the matters in which we and our subsidiaries are involved could result in additional payments in excess of established reserves over an extended period of time and in amounts that could have a material adverse effect on our financial results. Similarly, it is also reasonably possible that the terms of resolution could require that we or our subsidiaries change business practices and procedures, which could also have a material adverse effect on our financial results.

Potential changes in accounting standards might cause us to revise our financial results and disclosure in the future, which may change the way analysts measure our business or financial performance.

Accounting irregularities discovered in the past few years in various industries have caused regulators and legislators to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent auditors and retirement plan practices. Because it is still unclear what laws or regulations will ultimately develop, we cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards Board, or FASB, the FERC or the SEC could enact new or revised accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets and liabilities.

Item 1B. Unresolved Staff Comments.

Not applicable.

Item 2. Properties.

The Company’s energy properties consist of the physical assets necessary and appropriate to generate, transmit, store, distribute and supply energy and consist mainly of electric generation, transmission and distribution facilities and gas distribution plants, natural gas pipelines, storage facilities, compressor stations and meter stations, along with the related rights-of-way. It is the opinion of the Company’s management that the principal depreciable properties owned by the Company are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all or most of the properties of each of the Company’s subsidiaries (except CE Electric UK, all of MidAmerican Energy’s gas utility properties and Northern Natural Gas) are pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. For additional information regarding the Company’s energy properties, refer to Item 1. Business and Note 4 and Note 24 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.

The right to construct and operate the Company’s electric transmission and distribution facilities and pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through the exercise of the power of eminent domain. PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River in the United States and Northern Electric and Yorkshire Electricity in the United Kingdom continue to have the power of eminent domain in each of the jurisdictions in which they operate their respective facilities, but the United States utilities do not have the power of eminent domain with respect to Native American tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management.

With respect to real property, each of the electric transmission and distribution facilities and pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the generation stations, electric substations, compressor stations, measurement stations and office sites; and (2) parcels where the interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and pipelines. The Company believes that each of its energy subsidiaries have satisfactory title to all of the real property making up their respective facilities in all material respects.

Item 3. Legal Proceedings.

In addition to the proceedings described below, the Company is currently party to various items of litigation or arbitration in the normal course of business, none of which are reasonably expected by the Company to have a material adverse effect on its consolidated financial results.

Regulated Utility Companies

In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by the Klamath Tribes of Oregon, individual Klamath Tribal members and the Klamath Claims Committee. The complaint generally alleges that PacifiCorp and its predecessors affected the Klamath Tribes’ federal treaty rights to fish for salmon in the headwaters of the Klamath River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. In September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for sucker and steelhead in the headwaters of the Klamath River. The complaint seeks in excess of $1.0 billion in compensatory and punitive damages. In July 2005, the District Court dismissed the case and in September 2005 denied the Klamath Tribes’ request to reconsider the dismissal. In October 2005, the Klamath Tribes appealed the District Court’s decision to the Ninth Circuit Court of Appeals and briefing was completed in March 2006. Any final order will be subject to appeal. PacifiCorp believes the outcome of this proceeding will not have a material impact on its financial results.

In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a compliant against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Clean Air Act’s opacity standards at PacifiCorp’s Jim Bridger Power Plant in Wyoming. Under the Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light in the flue of a generating facility. The complaint alleges thousands of violations and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation, and the plaintiffs’ costs of litigation. PacifiCorp believes it has a number of defenses to the claims, and it has already committed to invest at least $812.0 million in pollution control equipment at its generating facilities, including the Jim Bridger plant, that is expected to significantly reduce emissions. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time.

On December 28, 2004, an apparent gas explosion and fire resulted in three fatalities, one serious injury and property damage at a commercial building in Ramsey, Minnesota. According to the Minnesota Office of Pipeline Safety, an improper installation of a pipeline connection may have been a cause of the explosion and fire. A predecessor company to MidAmerican Energy provided gas service in Ramsey, Minnesota, at the time of the original installation in 1980. In 1993, a predecessor of CenterPoint Energy, Inc. (“CenterPoint”) acquired all of the Minnesota gas properties owned by the MidAmerican Energy predecessor company.

As a result of the explosion and fire, MidAmerican Energy and CenterPoint have received settlement demands which total $15.5 million. MidAmerican Energy’s exposure, if any, to these demands is covered under its liability insurance to which a $2.0 million retention applies. In addition, CenterPoint has completed replacing all service lines in the former North Central Public Service Company properties located in Minnesota at a cost of approximately $39 million according to publicly filed reports.

Two lawsuits naming MidAmerican Energy as a third party defendant have been filed by CenterPoint Energy Resources Corp. d/b/a CenterPoint Energy, in the U.S. District Court, District of Minnesota, related to this incident. The complaints seek contribution and indemnity on a wrongful death claim filed by the estate of one of the decedents and on a property damage and business interruption claim filed by the business whose premises were involved together with all sums associated with CenterPoint’s service lines replacement program. All claims arising from this incident have been settled by CenterPoint pursuant to Confidential Orders and Agreements; however, the third party actions remain. A Report and Recommendation on MidAmerican Energy’s motion for summary judgment in both of these cases was issued on January 16, 2007, recommending that CenterPoint’s third party claims based upon negligent installation be barred against MidAmerican Energy; however, claims based upon negligent operation and maintenance of the gas pipeline may continue. The parties timely objected to the Report and Recommendation and filed an appeal. MidAmerican Energy intends to vigorously defend its position in these claims and believes its ultimate outcome will not have a material impact on MidAmerican Energy’s financial results.

Interstate Pipeline Companies

In 1998, the United States Department of Justice informed the then current owners of Northern Natural Gas and Kern River that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against such entities and certain of their subsidiaries including Northern Natural Gas and Kern River. Mr. Grynberg has also filed claims against numerous other energy companies and alleges that the defendants violated the False Claims Act in connection with the measurement and purchase of hydrocarbons. The relief sought is an unspecified amount of royalties allegedly not paid to the federal government, treble damages, civil penalties, attorneys’ fees and costs. Motions to Dismiss based on various jurisdictional grounds were filed on June 4, 2004. On May 17, 2005, Northern Natural Gas and Kern River each received a Special Master’s Report and Recommendations in which the Special Master recommended that the action against Northern Natural Gas and Kern River be dismissed for lack of subject matter jurisdiction. Grynberg and the coordinated defendants each filed motions relating to the Special Master’s Report and Recommendations on June 27, 2005. On October 20, 2006, the United States District Court for the District of Wyoming ruled that Grynberg’s 1995 Qui Tam Litigation Documents constituted public disclosure not only with regard to Northern Natural Gas and Kern River (which were party to that action) but also as to all the other defendants which were not party to that action. The District Court thus affirmed the Special Master’s Report and Recommendation that the court lacked subject matter jurisdiction and dismissed Grynberg’s compliant as to all defendants. On November 16, 2006, Grynberg filed 74 separate notices of appeal from the district court’s decision of dismissal. In connection with the purchase of Kern River from The Williams Companies, Inc. (“Williams”) in 2002, Williams agreed to indemnify MEHC against any liability for this claim; however, no assurance can be given as to the ability of Williams to perform on this indemnity should it become necessary. No such indemnification was obtained in connection with the purchase of Northern Natural Gas in 2002. The Company believes that the Grynberg cases filed against Northern Natural Gas and Kern River are without merit and that Williams, on behalf of Kern River pursuant to its indemnification, and Northern Natural Gas, intend to defend these actions vigorously and believes its ultimate outcome will not have a material impact on their financial results.

On June 8, 2001, a number of interstate pipeline companies, including Northern Natural Gas and Kern River, were named as defendants in a nationwide class action lawsuit which had been pending in the 26th Judicial District, District Court, Stevens County Kansas, Civil Department against other defendants, generally pipeline and gathering companies, since May 20, 1999. The plaintiffs allege that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. On May 12, 2003, the plaintiffs filed a motion for leave to file a fourth amended petition alleging a class of gas royalty owners in Kansas, Colorado and Wyoming. The court granted the motion for leave to amend on July 28, 2003. Kern River was not a named defendant in the amended complaint and has been dismissed from the action. Northern Natural Gas filed an answer to the fourth amended petition on August 22, 2003. On January 4, 2005, the plaintiffs filed their class certification motion and brief in support of that motion. Northern Natural Gas and other defendants filed their joint briefs and expert affidavits in opposition to class certification on February 22, 2005. The plaintiffs filed their reply brief in support of class certification on March 18, 2005. On November 9, 2006, the plaintiffs filed a request for a new briefing schedule on class certification in light of a new Kansas Supreme Court case on class actions which ruled that in that case the trial court failed to engage in properly rigorous analysis of class certification and choice of law issues and remanded a denial of class certification for such an analysis. The plaintiffs hope to use this as grounds for further class certification briefing. Northern Natural Gas believes that this claim is without merit and intends to defend these actions vigorously and believes its ultimate outcome will not have a material impact on its financial results.

Similar to the June 8, 2001 matter referenced above, the plaintiffs in that matter filed a new companion action against a number of parties, including Northern Natural Gas but excluding Kern River, in a Kansas state district court for damages for mismeasurement of British thermal unit content, resulting in lower royalties. The action was filed on May 12, 2003. On January 4, 2005, the plaintiffs filed their class certification motion and brief in support of that motion. Northern Natural Gas and other defendants filed their joint briefs and expert affidavits in opposition to class certification on February 22, 2005. The plaintiffs filed their reply brief in support of class certification on March 18, 2005. On November 9, 2006, the plaintiffs filed a request for a new briefing schedule on class certification in light of a new Kansas Supreme Court case on class actions which ruled that in that case the trial court failed to engage in properly rigorous analysis of class certification and choice of law issues and remanded a denial of class certification for such an analysis. The plaintiffs hope to use this as grounds for further class certification briefing. Northern Natural Gas believes that this claim is without merit and intends to defend these actions vigorously and believes its ultimate outcome will not have a material impact on its financial results.

Independent Power Projects

Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon proforma financial projections of the Casecnan Project prepared following commencement of commercial operations, in February 2002, MEHC’s indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”), that MEHC’s indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against CE Casecnan Ltd. and MEHC. LPG’s complaint, as amended, seeks compensatory and punitive damages arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma financial projections and alleged improper settlement of the NIA arbitration. On January 21, 2004, CE Casecnan Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which the parties agreed to set aside certain distributions related to the shares subject to the LPG dispute and CE Casecnan agreed not to take any further actions with respect to such distributions without at least 15 days prior notice to LPG. Accordingly, 15% of the CE Casecnan dividend declarations in 2006, 2005 and 2004, totaling $32.5 million, was set aside in a separate bank account in the name of CE Casecnan.

On August 4, 2005, the court issued a decision, ruling in favor of LPG on five of the eight disputed issues in the first phase of the litigation. On September 12, 2005, LPG filed a motion seeking the release of the funds which have been set aside pursuant to the status quo agreement referred to above. MEHC and CE Casecnan Ltd. filed an opposition to the motion on October 3, 2005, and at the hearing on October 26, 2005, the court denied LPG’s motion. On January 3, 2006, the court entered a judgment in favor of LPG against CE Casecnan Ltd. According to the judgment, LPG would retain its ownership of 15% of the shares of CE Casecnan and distributions of the amounts deposited into escrow plus interest at 9% per annum. On February 28, 2006, CE Casecnan Ltd. filed an appeal of this judgment and the August 4, 2005 decision. On February 21, 2007, California Court of Appeals remanded the case to the lower court to modify its finding on one of the five disputed issues previously determined in favor of LPG. The judgment was affirmed in all other respects. The Company is currently evaluating the Court of Appeal’s order. The parties are proceeding in the trial court on LPG’s remaining claim against MEHC for damages for alleged breach of fiduciary duty. This claim is expected to be resolved sometime in 2007. The Company intends to vigorously defend the remaining claims.

In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San Lorenzo”), an original shareholder substantially all of whose shares in CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal action against the Company in the Philippines in connection with certain aspects of its option to repurchase such shares. The Company believes that San Lorenzo has no valid basis for any claim and, if named as a defendant in any action that may be commenced by San Lorenzo, the Company will vigorously defend such action. On July 1, 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo in the District Court of Douglas County, Nebraska, seeking a declaratory judgment as to MEHC’s and CE Casecnan Ltd.’s rights vis-à-vis San Lorenzo in respect of such shares. San Lorenzo filed a motion to dismiss on September 19, 2005. Subsequently, San Lorenzo purported to exercise its option to repurchase such shares. On January 30, 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it has effectively exercised its option to purchase 15% of the shares of CE Cascenan, that it is the rightful owner of such shares and that it is due all dividends paid on such shares. On March 9, 2006, the court granted San Lorenzo’s motion to dismiss, but has since permitted MEHC and CE Casecnan Ltd. to file an amended complaint incorporating the purported exercise of the option. The complaint has been amended and the matter is currently in the early stages of discovery. The Company intends to vigorously defend the counterclaims.

Item 4. Submission of Matters to a Vote of Security Holders.

Not applicable.

PART II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Since March 14, 2000, MEHC’s common stock has been owned by Berkshire Hathaway, Mr. Walter Scott, Jr. and certain of his family members and family controlled trusts and corporations, Mr. David L. Sokol, its Chairman and Chief Executive Officer, and Mr. Gregory E. Abel, its President and Chief Operating Officer, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. MEHC has not declared or paid any cash dividends on its common stock since March 14, 2000 and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.

For a discussion of contractual and regulatory restrictions that limit certain of MEHC’s subsidiaries’ ability to pay dividends on their common stock to MEHC, refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 11 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.

On November 17, 2006, MEHC issued 200,000 shares of its common stock, no par value, to Mr. Sokol upon the exercise by Mr. Sokol of 200,000 of his outstanding common stock options. The common stock options were exercisable at a price of $34.69 per share and the aggregate exercise price paid by Mr. Sokol was $6.9 million. MEHC also issued, on November 15, 2006, 125,000 shares of its common stock, no par value, to Mr. Abel upon the exercise by Mr. Abel of 125,000 of his outstanding common stock options. The common stock options were exercisable at a weighted-average price of $17.68 per share and the aggregate exercise price paid by Mr. Abel was $2.2 million. These issuances were pursuant to private placements and were exempt from the registration requirements of the Securities Act of 1933, as amended.

Item 6. Selected Financial Data.

The following table sets forth the Company’s selected consolidated historical financial data, which should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and with the Company’s historical Consolidated Financial Statements and notes thereto included in Item 8. Financial Statements and Supplementary Data. The selected consolidated historical financial data has been derived from the Company’s audited historical Consolidated Financial Statements and notes thereto.

	Years Ended December 31,
	2006 ⁽¹⁾		2005		2004			2003			2002 ⁽²⁾
	(in millions)
Consolidated Statement of Operations Data:
Operating revenue	$	10,300.7	$	7,115.5	$	6,553.4		$	5,965.6		$	4,795.2
Income from continuing operations		916.1		557.5		537.8			442.7			397.4
Income (loss) from discontinued operations, net of tax ⁽³⁾		-		5.2		(367.6	)		(27.1	)		(17.4	)
Net income available to common and preferred shareholders		916.1		562.7		170.2			415.6			380.0

	As of December 31,
		2006 ⁽¹⁾		2005		2004			2003			2002 ⁽²⁾
	(in millions)
Consolidated Balance Sheet Data:
Total assets	$	36,447.3	$	20,370.7	$	19,903.6		$	19,145.0		$	18,434.9
Parent company senior debt ⁽⁴⁾		3,928.9		2,776.2		2,772.0			2,777.9			2,323.4
Parent company subordinated debt ⁽⁴⁾		1,122.6		1,354.1		1,585.8			1,772.1			-
Company-obligated mandatory redeemable preferred securities of subsidiary trusts		-		-		-			-			2,063.4
Subsidiary and project debt ⁽⁴⁾		11,060.6		6,836.6		6,304.9			6,674.6			7,077.1
Preferred securities of subsidiaries		128.5		88.4		89.5			92.1			93.3
Total shareholders’ equity		8,010.6		3,385.2		2,971.2			2,771.4			2,294.3

⁽¹⁾	Reflects the acquisition of PacifiCorp on March 21, 2006.

⁽²⁾	Reflects the acquisitions of Kern River on March 27, 2002 and Northern Natural Gas on August 16, 2002

⁽³⁾	Reflects MEHC’s decision to cease operations of the Zinc Recovery Project effective September 10, 2004, which resulted in a non-cash, after-tax impairment charge of $340.3 million being recorded to write-off the Zinc Recovery Project, rights to quantities of extractable minerals, and allocated goodwill (collectively, the “Mineral Assets”). The charge and related activity of the Mineral Assets are classified separately as discontinued operations.

⁽⁴⁾	Excludes current portion.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following is management’s discussion and analysis of certain significant factors which have affected the financial condition and results of operations of the Company during the periods included herein. Explanations include management’s best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with Item 6. Selected Financial Data and with the Company’s historical Consolidated Financial Statements and notes thereto included in Item 8. Financial Statements and Supplementary Data. The Company’s actual results in the future could differ significantly from the historical results.

Executive Summary

The Company’s operations are organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding (which primarily includes MidAmerican Energy), Northern Natural Gas, Kern River, CE Electric UK (which primarily includes Northern Electric and Yorkshire Electricity), CalEnergy Generation-Foreign, CalEnergy Generation-Domestic and HomeServices. Through these platforms, MEHC owns and operates an electric utility company in the Western United States, a combined electric and natural gas utility company in the Midwestern United States, two natural gas interstate pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.

The following significant events and changes occurred during 2006 as discussed in more detail herein and in Item 1. Business, that highlight some of the factors which affected, or may affect in the future, the Company’s financial condition, results of operations and liquidity:

·	On February 9, 2006, following the effective date of the repeal of PUHCA 1935, Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par, zero-coupon convertible preferred stock into an equal number of shares of MEHC’s common stock.

On March 1, 2006, MEHC and Berkshire Hathaway entered into the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of MEHC common equity. 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 the MEHC’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request in minimum 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 us in exchange for additional shares of MEHC’s common stock. The Berkshire Equity Commitment will expire on February 28, 2011.

On March 21, 2006, MEHC issued common stock of $5.1 billion to Berkshire Hathaway and other existing shareholders and purchased PacifiCorp, a wholly owned indirect subsidiary of ScottishPower, for $5.1 billion in cash. The results of PacifiCorp are included in MEHC’s results beginning March 21, 2006.

MEHC’s subsidiaries continue to invest primarily in rate-regulated infrastructure assets including significant new coal, gas and wind generation facilities, as well as transmission and distribution assets and environmental compliance equipment. In 2006, the Company’s capital expenditures were $2.4 billion. The Company is currently estimating 2007 capital expenditures to be approximately $3 billion. On a consolidated basis, the Company issued $2.4 billion of long-term debt and repurchased $1.75 billion of common equity in 2006.

Results of Operations

Overview

Net income for 2006 increased $353.4 million, or 62.8%, to $916.1 million compared to 2005. Net income related to PacifiCorp, which was acquired on March 21, 2006, was $214.8 million during 2006. Also contributing to the increase in net income were favorable comparative results at most of the Company’s energy businesses and from $73.3 million of after tax gains on sales of available-for-sale securities. These improvements were partially offset by lower earnings at HomeServices and higher interest expense on parent company senior debt.

Net income for 2005 increased $392.5 million, or 230.6%, to $562.7 million compared to 2004. The increase was primarily due to a $367.6 million after-tax loss from discontinued operations recognized in 2004 as a result of management’s decision to cease operations of the Zinc Recovery Project. The remaining increase was the result of favorable comparative results at most of the Company’s domestic businesses and from gains on sales of certain non-strategic assets and investments. These improvements were partially offset by lower earnings at CE Electric UK, primarily associated with the distribution businesses, and an after-tax gain of $43.7 million, recognized in 2004, from the realization of certain Enron-related bankruptcy claims.

Segment Results

The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company’s significant accounting policies. The differences between the segment amounts and the consolidated amounts, described as “Corporate/other,” relate principally to corporate functions, including administrative costs, intersegment eliminations and fair value adjustments relating to acquisitions. Additionally, the activity of the Company’s Mineral Assets, which was previously reported in the CalEnergy Generation-Domestic reportable segment, is presented as discontinued operations within the Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.

A comparison of operating revenue and operating income for the Company’s reportable segments for the years ended December 31 follows (in millions):

	2006			2005			2004
Operating revenue:
PacifiCorp	$	2,939.2		$	-		$	-
MidAmerican Funding		3,452.8			3,166.1			2,701.7
Northern Natural Gas		633.6			569.1			544.8
Kern River		325.2			323.6			316.1
CE Electric UK		928.3			884.1			936.4
CalEnergy Generation-Foreign		336.3			312.3			307.4
CalEnergy Generation-Domestic		31.7			33.8			39.0
HomeServices		1,701.8			1,868.5			1,756.5
Total reportable segments		10,348.9			7,157.5			6,601.9
Corporate/other		(48.2	)		(42.0	)		(48.5	)
Total operating revenue	$	10,300.7		$	7,115.5		$	6,553.4

Operating income:
PacifiCorp	$	528.4		$	-		$	-
MidAmerican Funding		420.6			381.1			355.9
Northern Natural Gas		269.1			208.8			190.3
Kern River		216.9			204.5			204.8
CE Electric UK		515.7			483.9			497.4
CalEnergy Generation-Foreign		229.9			185.0			188.5
CalEnergy Generation-Domestic		14.4			15.1			21.5
HomeServices		54.7			125.3			112.9
Total reportable segments		2,249.7			1,603.7			1,571.3
Corporate/other		(129.2	)		(75.0	)		(45.9	)
Total operating income	$	2,120.5		$	1,528.7		$	1,525.4

PacifiCorp

On March 21, 2006, MEHC acquired 100% of the common stock of PacifiCorp. Operating revenue for 2006 consisted of $2,328.6 million of retail revenues and $610.6 million of wholesale and other revenues. Operating income for 2006 totaled $528.4 million. PacifiCorp’s results included $37.7 million of after-tax, non-cash losses from the period of acquisition to December 31, 2006, on its electricity and natural gas forward purchase and sales contracts. The losses related principally to unfavorable mark-to-market movements in forward price curves. PacifiCorp uses derivative instruments (primarily forward purchases and sales) to manage the commodity price risk inherent in its fuel and electricity obligations, as well as to optimize the value of power generation assets and related contracts.

MidAmerican Funding

MidAmerican Funding’s operating revenue and operating income for the years ended December 31 are summarized as follows (in millions):

	2006		2005		2004
Operating revenue:
Retail	$	1,269.0	$	1,222.0	$	1,136.7
Wholesale		510.5		291.2		285.0
Total regulated electric	$	1,779.5	$	1,513.2	$	1,421.7
Regulated natural gas		1,111.6		1,322.7		1,010.9
Non-regulated		561.7		330.2		269.1
Total operating revenue	$	3,452.8	$	3,166.1	$	2,701.7

Operating income:
Regulated electric	$	372.1	$	334.6	$	304.0
Regulated natural gas		36.4		38.7		42.4
Non-regulated		12.1		7.8		9.5
Total operating income	$	420.6	$	381.1	$	355.9

Regulated Electric Operations

Sales volumes and average number of customers of MidAmerican Energy’s regulated electric business for the years ended December 31 are summarized as follows (in millions, except for average number of customers):

	2006		2005		2004
Sales (GWh):
Retail		19,831		19,044		17,865
Wholesale		11,168		8,378		9,260
		30,999		27,422		27,125

Average number of customers		709,912		701,111		691,984

MidAmerican Energy’s regulated electric retail revenue for 2006 increased $47.0 million, or 3.8%, to $1,269.0 million compared to 2005 and the related gross margin increased $39.4 million. Growth in retail demand, which included a 1.3% increase in the average number of retail customers and the addition of a large steel manufacturer in October 2005, contributed $36.4 million to the revenue increase. Changes in non-weather electricity usage factors, such as home size, technology changes and multiple appliances, accounted for another $10.6 million of the increase. These increases were offset by $20.8 million in lower revenue due to mild summer temperatures in 2006. Also, contributing to higher electric retail revenue were a $14.0 million increase in transmission service revenues, earned to transport wholesale volumes across MidAmerican Energy’s system, and $7.1 million in energy efficiency revenues.

In addition to electric retail sales, MidAmerican Energy sells electric energy, or wholesale sales, to other utilities, marketers and municipalities. Wholesale revenue for 2006 increased $219.3 million, or 75.3%, to $510.5 million compared to 2005 and the related gross margin increased $31.4 million. Higher average electric energy prices increased wholesale revenue by $122.3 million, while a 33.3% increase in wholesale sales volumes accounted for the remaining $97.0 million increase resulting from MidAmerican Energy-owned wind-powered generation and greater market opportunities.

MidAmerican Energy’s regulated electric operating income in 2006 increased $37.5 million, or 11.2%, to $372.1 million compared to 2005 due to the aforementioned $70.8 million combined increase in retail and wholesale gross margins which was partially offset by $27.6 million in higher operating expenses and $5.8 million in higher deprecation expense. Operating expenses increased primarily due to higher generating plant operating and maintenance expenses including additional expense for wind generation.

MidAmerican Energy’s regulated electric retail revenue for 2005 increased $85.3 million, or 7.5%, to $1,222.0 million compared to 2004. Electric retail sales volumes increased 6.6% compared to 2004. Higher average temperatures during 2005 compared to 2004 resulted in a $43.4 million increase in electric retail revenue. A growing retail customer base in 2005 improved electric retail revenue by $17.7 million, while non-weather electricity usage factors increased electric revenue by $9.1 million. Additionally, transmission revenue increased $7.9 million.

MidAmerican Energy’s wholesale revenue for 2005 increased $6.2 million, or 2.2%, to $291.2 million compared to 2004. The effect of higher electric energy prices, offset partially by a higher proportion of lower-priced, off-peak sales, increased wholesale energy revenue in 2005 by $33.3 million. Wholesale units for 2005 decreased 9.5% from 2004, resulting in a $27.1 million decrease in revenue. The primary reason for the decrease in wholesale sales volumes for 2005 was the timing of planned generation outages for the Louisa Generating Station and the loss of generating capacity at the Ottumwa Generating Station Unit No. 1 (“OGS Unit No. 1”), which experienced a failure of its step-up transformer on February 20, 2005. OGS Unit No. 1 returned to service on May 3, 2005.

MidAmerican Energy’s regulated electric operating income for 2005 increased $30.6 million, or 10.1%, to $334.6 million compared to 2004. Regulated electric retail and wholesale sales gross margin increased $22.0 million as the cost of fuel, energy and capacity for 2005 increased $69.5 million, or 17.4%, compared to 2004, which offset the majority of the increased revenue. The increase in the cost of fuel, energy and capacity was principally due to the cost of replacement power in connection with the generating station outages previously discussed and the increased use of gas-fired generation, primarily from the Greater Des Moines Energy Center. Regulated electric operating expense for 2005 decreased $10.6 million compared to 2004 due principally to the timing of generating plant maintenance and lower postretirement benefit costs, partially offset by higher distribution and transmission operations costs.

Regulated Natural Gas Operations

Under its purchase gas adjustment clauses, MidAmerican Energy is permitted to recover the cost of gas used to service its retail gas utility customers. Consequently, neither fluctuations in the cost of gas sold nor changes in wholesale gas sales have a significant effect on regulated gross margin or operating income.

The average per-unit cost of gas sold decreased 13.2% in 2006 resulting in a $134.7 million decrease in revenue and cost of gas sold compared to 2005. Wholesale volumes were 4.7% lower and retail sales volumes were 8.3% lower in 2006 compared to 2005, due to mild temperatures, resulting in a $75.2 million decrease in revenue and cost of gas sold. The lower retail volumes were the primary factor in the lower regulated natural gas operating income.

The average per-unit cost of gas sold increased 32.8% in 2005 resulting in a $271.6 million increase in revenue and cost of gas sold compared to 2004. Wholesale volumes were 10.8% higher and retail volumes were 0.9% higher in 2005 compared to 2004, resulting in a $36.8 million increase to revenue and cost of gas sold. Regulated natural gas operating income in 2005 decreased $3.7 million primarily due to higher operating costs, partially offset by the small increase in retail sales volumes.

Non-regulated Operations

MidAmerican Funding’s non-regulated operating revenue for 2006 increased $231.5 million, or 70.1%, to $561.7 million compared to 2005. The increase was primarily due to a change in the management strategy related to certain end-use natural gas contracts that required the related revenues and cost of sales to be recorded prospectively on a gross, rather than net, basis. For 2005, cost of sales totaling $289.2 million were netted in non-regulated operating revenue for such end-use gas contracts. Partially offsetting this increase to non-regulated operating revenue in 2006 was a decrease in natural gas sales volumes and lower electric and natural gas prices compared to 2005.

Northern Natural Gas

Operating revenue for 2006 increased $64.5 million, or 11.3%, to $633.6 million compared to 2005. Transportation revenue increased $55.0 million, or 12.2%, due to favorable market conditions resulting in higher field area demand and rates and new transportation contracts related to new and growing demand. Storage revenue increased $10.4 million due to favorable market conditions on interruptible services and the expansion of our firm storage cycle capacity. Transportation and storage revenues were also favorably impacted in 2006 by an $8.6 million reduction in 2005 due to the net effects of rate case settlements.

Operating income for 2006 increased $60.3 million, or 28.9%, to $269.1 million compared to 2005 due to the aforementioned increase in transportation and storage revenues as well as a $29.0 million asset impairment charge in 2005, partially offset by a gain of $19.7 million in 2005 from the sale of an idled section of pipeline in Oklahoma and Texas and the adjustments from two FERC-approved settlements that increased operating income in 2005 by $16.0 million.

Operating revenue for 2005 increased $24.3 million, or 4.5%, to $569.1 million compared to 2004. The increase was mainly due to higher gas and liquids sales of $25.6 million, due to higher sales of gas from operational storage utilized to manage physical flows on the pipeline system, and higher transportation and storage revenues of $5.4 million, due to changes in the composition of transportation contracts. These increases were partially offset by the net effects of the consolidated rate case and system levelized account (“SLA”) settlements, which decreased operating revenue by $8.6 million.

Operating income for 2005 increased $18.5 million, or 9.7%, to $208.8 million compared to 2004 due to the $19.7 million gain on sale of the pipeline asset, $16.0 million impact of rate case settlements, the $5.4 million increase in transportation and storage revenues and lower operating expenses, partially offset by the $29.0 million asset impairment charge in 2005.

Kern River

In October 2006, the FERC issued an order that modified certain aspects of the administrative law judge’s initial decision on Kern River’s pending rate case received earlier in 2006, including changing the allowed return on equity from 9.34% to 11.2% and granting Kern River an income tax allowance. The order also affirmed the rejection of certain issues included in Kern River’s filed position, including the rates for the vintage system being designed on a 95% load factor basis as the FERC determined a 100% load factor basis should be used. The FERC also rejected a 3% inflation factor for certain operating expenses and a shorter useful life for certain plant. As a result of the October 2006 order, Kern River increased its estimate for rates subject to refund by $35.6 million and reduced depreciation expense by $28.2 million.

Operating revenue for 2006 increased $1.6 million, or 0.5%, to $325.2 million compared to 2005 due primarily to higher transportation revenues of $33.9 million due to favorable market conditions, largely offset by the aforementioned $33.6 million adjustment to Kern River’s provision for estimated refunds.

Operating income for 2006 increased $12.4 million, or 6.1%, to $216.9 million compared to 2005 due primarily to the higher transportation revenues discussed above and lower depreciation and amortization due primarily to changes in the expected rates in connection with the current rate proceeding.

Operating revenue for 2005 increased $7.5 million, or 2.4%, to $323.6 million compared to 2004. The increase in operating revenue resulted from higher demand and commodity transportation revenues of $14.0 million due mainly to higher rates, subject to refund, for the current rate proceeding which became effective on November 1, 2004. This increase was partially offset by lower interruptible transportation revenue of $5.9 million. Operating income remained relatively flat in 2005 compared to 2004.

CE Electric UK

Operating revenue for 2006 increased $44.2 million, or 5.0%, to $928.3 million compared to 2005 due primarily to higher contracting revenue of $20.9 million, higher distribution revenues at Northern Electric and Yorkshire Electricity of $13.7 million due to higher units distributed and the favorable impact of the exchange rate of $12.3 million. Operating income for 2006 increased $31.8 million, or 6.6%, to $515.7 million due primarily to the aforementioned increase in operating revenue, partially offset by higher cost of sales of $17.1 million due to higher contracting revenues.

Operating revenue for 2005 decreased $52.3 million, or 5.6%, to $884.1 million compared to 2004 due primarily to $37.0 million of lower distribution revenues at Northern Electric and Yorkshire Electricity due to higher units distributed, $9.1 million of lower contracting revenues and a $6.9 million adverse impact of the exchange rate. Operating income for 2005 decreased $13.5 million, or 2.7%, to $483.9 million due mainly to the previously discussed reductions in operating revenue, partially offset by lower cost of sales of $7.5 million due primarily to lower contracting work and exit charges from the National Grid Company and a gain of $13.3 million on the partial disposal of certain CE Gas Australian assets and lower costs of $11.2 million associated with the withdrawal from the metering market.

CalEnergy Generation-Foreign

Operating revenue for 2006 increased $24.0 million, or 7.7%, to $336.3 million compared to 2005. Higher revenue at the Casecnan Project of $41.5 million as a result of higher water flows throughout 2006 was partially offset by lower operating revenue at the Leyte Projects of $17.5 million as the Upper Mahiao Project was transferred on June 25, 2006 to the Philippine government.

Operating income for 2006 increased $44.9 million, or 24.3%, to $229.9 million compared to 2005 due primarily to the higher revenue as well as lower operating expenses of $14.8 million due primarily to the aforementioned transfer of the Upper Mahiao Project.

HomeServices

Operating revenue for 2006 decreased $166.7 million, or 8.9%, to $1,701.8 million compared to 2005 resulting in lower gross margin of $43.3 million. The decrease in operating revenue was due to a decline from existing businesses totaling $282.5 million reflecting fewer brokerage transactions as a result of the general slowdown in the U.S. housing market, partially offset by the results of acquired companies totaling $115.8 million not included in the comparable 2005 period.

Operating income for 2006 decreased $70.6 million compared to 2005 due to the aforementioned decrease in gross margin, higher operating expenses of $13.2 million and higher acquisition related amortization of $10.1 million. Operating expenses increased mainly due to $29.5 million for acquired companies not included in the comparable 2005 period, partially offset by $16.3 million in lower operating expense at existing businesses due primarily to lower salaries and employee benefits expenses.

Operating revenue for 2005 increased $112.0 million, or 6.4%, to $1,868.5 million compared to 2004 resulting in higher gross margin of $33.3 million. The increase in operating revenue was due to growth from existing businesses totaling $62.1 million reflecting primarily higher average sales prices and the results of acquired companies not included in the comparable 2004 period totaling $49.4 million.

Operating income for 2005 increased by $12.4 million due to the aforementioned increase in gross margin, partially offset by higher operating expenses of $24.5 million. Operating expenses increased mainly due to $12.8 million for acquired companies not included in the comparable 2004 period and $11.7 million in higher operating expense at existing businesses due primarily to higher marketing and occupancy costs.

Consolidated Other Income and Expense Items

Interest Expense

Interest expense for the years ended December 31 is summarized as follows (in millions):

	2006		2005		2004

Subsidiary debt	$	757.7	$	533.3	$	521.5
Parent company senior debt and other		233.5		173.2		184.8
Parent company subordinated debt-Berkshire		133.8		157.3		169.9
Parent company subordinated debt-other		27.5		27.2		27.0
Total interest expense	$	1,152.5	$	891.0	$	903.2

Interest expense on subsidiary debt for 2006 increased $224.4 million to $757.7 million compared to 2005 due primarily to PacifiCorp’s interest expense which totaled $223.5 million during the period from acquisition to December 31, 2006. Additionally, interest expense on subsidiary debt was higher in 2006 compared to 2005 due to additional debt at MidAmerican Energy offset by scheduled maturities of debt and principal repayments and a $10.2 million charge incurred in February 2005 to exercise the call option on CE Electric UK debt.

Interest expense on subsidiary debt for 2005 increased $11.8 million to $533.3 million compared to 2004 due mainly to a $10.2 million charge to exercise the call option on CE Electric UK debt, as well as due to additional interest expense on the £350.0 million of 5.125% bonds issued by certain indirect wholly-owned subsidiaries of CE Electric UK in May 2005 and additional debt at MidAmerican Energy. These increases were partially offset by lower interest expense due to maturities of debt and principal repayments.

Interest expense on parent company senior debt for 2006 increased $60.3 million to $233.5 million compared to 2005 due to MEHC’s 6.125% $1,700.0 million debt issuance in March 2006, partially offset by scheduled debt maturities. Interest expense on parent company short-term and senior debt for 2005 decreased $11.6 million to $173.2 million compared to 2004 due primarily to the scheduled redemption of $260.0 million of 7.23% notes in September 2005.

Interest expense on parent company subordinated debt-Berkshire for 2006 decreased $23.5 million to $133.8 million compared to 2005 and decreased $12.6 million to $157.3 million compared to 2004 as a result of scheduled principal repayments.

Other Income, Net

Other income, net for the years ended December 31 is summarized as follows (in millions):

	2006			2005			2004

Capitalized interest	$	39.7		$	16.7		$	20.0
Interest and dividend income		73.5			58.1			38.9
Other income		239.3			74.5			128.2
Other expense		(13.0	)		(22.1	)		(10.1	)
Total other income, net	$	339.5		$	127.2		$	177.0

Capitalized interest for 2006 increased $23.0 million to $39.7 million compared to 2005 mainly due to $18.5 million from PacifiCorp and increased levels of capital project expenditures at MidAmerican Energy. Capitalized interest for 2005 decreased $3.3 million to $16.7 million compared to 2004 due to lower capitalization at Northern Electric and Yorkshire Electricity, partially offset by increased levels of capital projects at MidAmerican Energy.

Interest and dividend income for 2006 increased $15.4 million to $73.5 million from the comparable period in 2005 mainly due to $8.9 million from PacifiCorp and earnings on guaranteed investment contracts (£100.0 million at 4.75% and £200.0 million at 4.73%) purchased by certain indirect wholly owned subsidiaries of CE Electric UK in May 2005. Interest and dividend income for 2005 increased $19.2 million to $58.1 million compared to 2004 mainly due to earnings on guaranteed investment contracts described previously, as well as earnings on higher cash balances and higher short-term interest rates.

Other income for 2006 increased $164.8 million to $239.3 million compared to 2005. Other income in 2006 included Kern River’s $89.3 million of gains from the sales of Mirant stock and MidAmerican Funding’s $32.1 million of gains from the disposition of common shares held in an electronic energy and metals trading exchange. Also contributing to the increase in other income for 2006 was higher allowance for equity funds used during construction of $30.5 million, primarily due to $17.9 million from PacifiCorp and $12.8 million due largely to increased levels of capital project expenditures at MidAmerican Energy. Excluding the allowance for equity funds used during construction, PacifiCorp also contributed $8.7 million to the increase in other income in 2006.

Other income for 2005 decreased $53.7 million to $74.5 million compared to 2004. In 2005, the Company realized gains from sales of certain non-strategic investments at MidAmerican Funding of $13.4 million and CE Electric UK of $8.4 million. In 2004, the Company recognized a $72.2 million gain on Northern Natural Gas’ sale of an approximately $259 million note receivable with Enron (the “Enron Note Receivable”) and a $14.8 million gain on amounts collected by Kern River on its claim for damages against Mirant. Additionally, the allowance for equity funds used during construction for 2005 increased $5.7 million compared to 2004 due to increased levels of capital project expenditures at MidAmerican Energy.

Other expense for 2006 decreased $9.1 million to $13.0 million compared to 2005 due primarily to losses for other-than-temporary impairments of MidAmerican Funding’s investments in commercial passenger aircraft leased to major domestic airlines of $15.6 million in 2005. Other expense for 2005 increased $12.0 million to $22.1 million compared to 2004 due to the aforementioned impairment losses on investments in commercial passenger aircraft leased to major domestic airlines.

Income Tax Expense

Income tax expense for 2006 increased $162.0 million to $406.7 million compared to 2005. The effective tax rates were 31.1% and 32.0% for 2006 and 2005, respectively. The lower effective tax rate in 2006 was due primarily to the effects of production tax credits related to energy produced by MidAmerican Energy’s wind facilities and lower income taxes on foreign earnings in 2006.

Income tax expense for 2005 decreased $20.3 million to $244.7 million compared to 2004. The effective tax rates were 32.0% and 33.2% for 2005 and 2004, respectively. The lower effective tax rate in 2005 was mainly due to the effects of production tax credits related to energy produced by MidAmerican Energy’s wind facilities and lower income taxes on foreign earnings in 2005, partially offset by a change in the state of Iowa’s income tax laws in 2004 related to bonus depreciation that lowered income tax expense and benefits from CE Electric UK’s settlement of various positions with the Inland Revenue.

Minority Interest and Preferred Dividends of Subsidiaries

Minority interest and preferred dividends of subsidiaries for 2006 increased $12.2 million to $28.2 million compared to 2005 due mainly to higher earnings at CE Casecnan and preferred dividends at PacifiCorp. Minority interest and preferred dividends for 2005 remained relatively flat from the comparable period in 2004.

Equity Income

Equity income for 2006 decreased $9.8 million to $43.5 million compared to 2005 due primarily to lower earnings at CE Generation as a result of higher depreciation and maintenance expenses and lower equity income at HomeServices due to lower refinancing activity at its residential mortgage loan joint ventures.

Equity income for 2005 increased $36.4 million to $53.3 million compared to 2004. The increase was mainly due to higher earnings at CE Generation due to higher energy rates, partially offset by higher fuel costs, mainly at its natural gas-fired generation facilities and increased production at the Imperial Valley Projects due to the timing and length of scheduled outages and lower major maintenance costs, partially offset by higher fuel costs. Additionally, 2004 results included MEHC’s $16.8 million after-tax portion of a charge as a result of the partial impairment of the carrying value of CE Generation’s Power Resources project.

Discontinued Operations

On September 10, 2004, management made the decision to cease operations of the Zinc Recovery Project. In connection with ceasing operations, the Zinc Recovery Project’s assets have been dismantled and sold and certain employees of the operator of the Zinc Recovery Project were paid one-time termination benefits. Implementation of the decommissioning plan began in September 2004 and, as of December 31, 2005, the dismantling, decommissioning, and sale of remaining assets of the Zinc Recovery Project was completed.

The income from discontinued operations, net of income tax, of $5.2 million for the year ended December 31, 2005 reflects the proceeds received from the sale of assets, partially offset by the disposal costs incurred, in connection with the Zinc Recovery Project. The loss from discontinued operations, net of income tax, of $367.6 million for the year ended December 31, 2004 consists primarily of a $340.3 million impairment charge recognized in connection with ceasing the operations of the Zinc Recovery Project.

Liquidity and Capital Resources

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including the Berkshire Equity Commitment. These resources provide funds required for current operations, construction expenditures, debt retirement and other capital requirements. The Company may from time to time seek to retire its outstanding securities through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Each of MEHC’s direct and indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for its own project or subsidiary debt. It should not be assumed that any asset of any subsidiary of MEHC’s will be available to satisfy the obligations of MEHC or any of its other subsidiaries’ obligations. However, unrestricted cash or other assets which are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof.

The Company’s cash and cash equivalents and short-term investments, which consist primarily of auction rate securities that are used in the Company’s cash management program, were $357.8 million as of December 31, 2006, compared to $396.3 million as of December 31, 2005. In addition, the Company recorded separately, in restricted cash and short-term investments and in deferred charges and other assets, restricted cash and investments as of December 31, 2006 and 2005 of $162.2 million and $136.7 million, respectively. The restricted cash balance is mainly composed of amounts deposited in restricted accounts relating to (i) the Company’s debt service reserve requirements relating to certain projects, (ii) customer deposits held in escrow, (iii) custody deposits, and (iv) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project.

Cash Flows from Operating Activities

The Company generated cash flows from operations of $1,923.2 million for the year ended December 31, 2006 as compared to $1,310.8 million for the comparable period in 2005. The increase was mainly due to the inclusion of $423.4 million of PacifiCorp’s operating cash flows for the period from acquisition to December 31, 2006, more favorable operating results at most other energy businesses and an accrual for rate refunds at Kern River which will likely be paid in 2007, partially offset by lower cash flow from operations at CE Electric UK and HomeServices.

Cash Flows from Investing Activities

Cash flows used in investing activities for the years ended December 31, 2006 and 2005 were $7,321.4 million and $1,551.3 million, respectively. The increase was due primarily to the 2006 acquisition of PacifiCorp, net of cash acquired, for $4,932.4 million; a $1,226.9 million increase in capital expenditures, construction and other development costs due primarily to PacifiCorp capital expenditures of $1,114.4 million for the period from acquisition through December 31, 2006; and a $68.7 million increase in other acquisitions, net of cash acquired. These increases were partially offset by the 2005 purchase of two guaranteed investment contracts by certain indirect wholly owned subsidiaries of CE Electric UK totaling $556.6 million.

PacifiCorp Acquisition

On March 21, 2006, a wholly owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp from a wholly owned subsidiary of ScottishPower for a cash purchase price of $5,109.5 million, which was funded through the issuance of common stock. MEHC also incurred $10.6 million of direct transaction costs associated with the acquisition, which consisted principally of investment banker commissions and outside legal and accounting fees and expenses, resulting in a total purchase price of $5,120.1 million. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006.

In the first quarter of 2006, the state commissions in all six states where PacifiCorp has retail customers approved the sale of PacifiCorp to MEHC. The approvals were conditioned on a number of regulatory commitments, including expected financial benefits in the form of reduced corporate overhead and financing costs, certain mid- to long-term capital and other expenditures of significant amounts and a commitment not to seek utility rate increases attributable solely to the change in ownership. The capital and other expenditures proposed by MEHC and PacifiCorp include:

Approximately $812 million in investments (generally to be made over several years following the sale and subject to subsequent regulatory review and approval) in emissions reduction technology for PacifiCorp’s existing coal plants, which, when coupled with the use of reduced emissions technology for anticipated new coal-fueled generation, is expected to result in significant reductions in emissions rates of SO₂, NO_x, and mercury and to avoid an increase in the carbon dioxide emissions rate;

Approximately $520 million in investments (to be made over several years following the sale and subject to subsequent regulatory review and approval) in PacifiCorp’s transmission and distribution system that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization; and

·	The addition of 400 MW of cost-effective renewable resources to PacifiCorp’s generation portfolio by December 31, 2007, including 100 MW of cost-effective wind resources by March 21, 2007.

The commitments approved by the state commissions also include credits that will reduce retail rates generally through 2010 to the extent that PacifiCorp does not achieve identified cost reductions or demonstrate mitigation of certain risks to customers. The maximum potential value of these rate credits to customers in all six states is $142.5 million. PacifiCorp and MEHC have made additional commitments to the state commissions that limit the dividends PacifiCorp can pay to MEHC or its affiliates. As of December 31, 2006, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to MEHC or its affiliates without prior state regulatory approval to the extent that it would reduce PacifiCorp’s common stock equity below 48.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt. After December 31, 2008, this minimum level of common equity declines annually to 44.0% after December 31, 2011. As of December 31, 2006, PacifiCorp’s ratio, as calculated pursuant to the requirements of the applicable commitment exceeded the minimum threshold.

These commitments also restrict PacifiCorp from making any distributions to either PPW Holdings LLC or MEHC if PacifiCorp’s unsecured debt rating is BBB- or lower by Standard & Poor’s Rating Services or Fitch Ratings or Baa3 or lower by Moody’s Investor Service, as indicated by two of the three rating services. At December 31, 2006, PacifiCorp’s unsecured debt rating was BBB+ by Standard & Poor’s Rating Services and Fitch Ratings and Baa1 by Moody’s Investor Service.

Capital Expenditures, Construction and Other Development Costs

Capital expenditures, construction and other development costs were $2,423.1 million for the year ended December 31, 2006, compared with $1,196.2 million for the same period in 2005. The following table summarizes the expenditures by business segment for the years ended December 31 (in millions):

	2006		2005
Capital expenditures:
PacifiCorp	$	1,114.4	$	-
MidAmerican Energy		758.2		701.0
Northern Natural Gas		122.1		124.7
CE Electric UK		404.4		342.6
Other reportable segments and corporate/other		24.0		27.9
Total capital expenditures	$	2,423.1	$	1,196.2

Forecasted capital expenditures, construction and other development costs for fiscal 2007, which exclude the non-cash equity allowance for funds used during construction (“AFUDC”), are approximately $3 billion. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. Estimates of environmental capital and operating requirements may change significantly at any time as a result of, among other factors, changes in related regulations, prices of products used to meet the requirements, competition in the industry for similar technology and management’s strategies for achieving compliance with the regulations. The Company expects to meet these capital expenditures with cash flows from operations and the issuance of debt. Capital expenditures relating to operating projects, consisting mainly of recurring expenditures and the funding of growing load requirements, were $1,684.3 million and $796.3 million, respectively, for the years ended December 31, 2006 and 2005. Construction and other development costs were $738.8 million and $399.9 million, respectively, for the years ended December 31, 2006 and 2005. These costs consist mainly of expenditures for large scale generation projects at PacifiCorp and MidAmerican Energy as described below.

PacifiCorp and MidAmerican Energy anticipate a continuing increase in demand for electricity from their regulated customers. To meet existing and anticipated demand and ensure adequate electric generation in their service territory, PacifiCorp and MidAmerican Energy have been and are each continuing to construct major generation projects.

PacifiCorp

In March 2006, PacifiCorp completed construction of the Currant Creek Power Plant, a 540-MW combined-cycle plant in Utah. Total project costs incurred were approximately $343 million. Presently under construction is the Lake Side Power Plant, an estimated 534-MW combined cycle plant in Utah, which is expected to be in service by June 2007. The cost of the Lake Side Power Plant is expected to total approximately $347 million, including approximately $13 million of non-cash equity AFUDC, of which $284.0 million, including $9.6 million of non-cash equity AFUDC, has been incurred through December 31, 2006. Both plants are 100% owned and operated by PacifiCorp.

In July 2006, PacifiCorp entered into an agreement to acquire a 100.5-MW wind energy generation facility that became operational in September 2006. An initial investment in an additional 140.4-MW wind energy generation facility occurred in September 2006 and construction is scheduled to be completed by August 2007. PacifiCorp continues to pursue additional cost-effective wind-powered generation.

Additionally, in conjunction with regulatory commitments made by the Company, approximately $520 million in investments are anticipated being made to PacifiCorp’s transmission and distribution system over the next several years that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization. Such investments would be subject to regulatory review and approval.

PacifiCorp’s capital requirements for 2007, which exclude the non-cash equity AFUDC, are estimated to be approximately $1,489 million, which includes $632 million for the generation development projects described above, $127 million for emissions control equipment to address current and anticipated air quality regulations and $730 million for ongoing operational projects, including connections for new customers and facilities to accommodate load growth.

In conjunction with state regulatory approvals of MEHC’s acquisition of PacifiCorp, MEHC and PacifiCorp committed to invest approximately $812 million, which include the $127 million planned for 2007, in capital spending over several years for emission control equipment to address current and future air quality initiatives implemented by the EPA or the states in which PacifiCorp operates facilities. Additional capital expenditures for emission reduction projects may be required, depending on the outcome of pending or new air quality regulations. In addition to capital expenditure requirements, incremental operating costs are expected to be incurred by PacifiCorp in conjunction with the utilization of the emission control equipment.

MidAmerican Funding

MidAmerican Energy is currently constructing Council Bluffs Unit 4, a 790-MW (expected accreditation) super-critical-temperature, coal-fired generating plant. MidAmerican Energy will operate the plant and hold an undivided ownership interest as a tenant in common with the other owners of the plant. MidAmerican Energy’s current ownership interest is 60.67%, equating to 479 MW of output. Municipal, cooperative and public power utilities own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. The facility will provide service to regulated retail electricity customers. Wholesale sales may also be made from the facility to the extent the power is not immediately needed for regulated retail service. MidAmerican Energy has obtained regulatory approval to include the Iowa portion of the actual cost of CBEC Unit 4 in its Iowa rate base as long as the actual cost does not exceed the agreed cap that MidAmerican Energy has deemed to be reasonable. If the cap is exceeded, MidAmerican Energy has the right to demonstrate the prudence of the expenditures above the cap, subject to regulatory review. MidAmerican Energy expects to invest approximately $870 million in CBEC Unit 4, including transmission facilities and approximately $64 million of non-cash equity AFUDC. Through December 31, 2006, MidAmerican Energy has invested $785.9 million in the plant, including $121.3 million for MidAmerican Energy’s share of deferred payments allowed by the construction contract and $49.2 million of non-cash equity AFUDC.

On April 18, 2006, the IUB approved a settlement agreement between MidAmerican Energy and the OCA regarding ratemaking principles for up to 545 MW (nameplate ratings) of wind-powered generation capacity in Iowa to be installed in 2006 and 2007. In the second half of 2006, MidAmerican Energy placed in service 99 MW (nameplate ratings) of wind-powered generation. In June 2006, MidAmerican Energy entered into agreements to add 123 MW (nameplate ratings) of wind-powered generation by the end of 2007. MidAmerican Energy continues to pursue additional cost effective wind-powered generation.

MidAmerican Energy’s capital requirements for 2007, which exclude the non-cash AFUDC, are estimated to be approximately $926 million, which includes approximately $375 million for the generation development projects discussed above, approximately $150 million for emissions control equipment to address current and anticipated air quality regulations and approximately $401 million for ongoing operational projects, including connections for new customers and facilities to accommodate load growth.

MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions that may be required to meet emissions reductions as promulgated by the EPA. The plan allows MidAmerican Energy to more effectively manage its expenditures required to comply with emissions standards. On April 1, 2006, MidAmerican Energy submitted to the IUB an updated plan, as required every two years by Iowa law, which increased its estimate of required expenditures. MidAmerican Energy currently estimates that the incremental capital expenditures for emission control equipment to comply with air quality requirements will total approximately $540 million for January 1, 2007 through December 31, 2015. Additionally, MidAmerican Energy expects to incur significant incremental operating costs in conjunction with the utilization of the emissions control equipment.

HomeServices’ Acquisitions

In 2006, HomeServices separately acquired three real estate companies for an aggregate purchase price of $44.3 million, net of cash acquired, plus working capital and certain other adjustments. For the year ended December 31, 2005, these real estate companies had combined revenue of $149.4 million on approximately 17,600 closed sides representing $5.2 billion of sales volume.

Cash Flows from Financing Activities

Cash flows from financing activities were $5,377.4 million for the year ended December 31, 2006. Sources of cash totaled $7,899.0 million and consisted primarily of $5,131.7 million of proceeds from the issuance of common stock, $1,699.3 million of proceeds from the issuance of parent company senior debt and $717.7 million of proceeds from the issuance of subsidiary and project debt. Uses of cash totaled $2,521.6 million and consisted primarily of $1,750.0 million of repurchases of common stock, $516.5 million for repayments of subsidiary and project debt and $234.0 million for repayments of parent company subordinated debt.

Cash flows used in financing activities were $219.1 million for the year ended December 31, 2005. Uses of cash totaled $1,336.9 million and consisted primarily of $875.4 million for repayments of subsidiary and project debt and $448.5 million for repayments of parent company senior and subordinated debt. Sources of cash totaled $1,117.8 million and consisted primarily of $1,050.6 million of proceeds from the issuance of subsidiary and project debt and $51.0 million of net proceeds from MEHC’s revolving credit facility.

Stock Transactions and Agreements

On March 1, 2006, MEHC and Berkshire Hathaway entered into 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 the MEHC’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request. The Berkshire Equity Commitment will expire on February 28, 2011, was not used for the PacifiCorp acquisition and will not be used for future acquisitions.

On March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing shareholders and related companies invested $5,109.5 million, in the aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide equity funding for the PacifiCorp acquisition. The per-share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by MEHC’s shareholders.

In March 2006, MEHC repurchased 12,068,412 shares of common stock for an aggregate purchase price of $1,750.0 million.

In 2006, 775,000 common stock options were exercised having a weighted average exercise price of $28.65 per share and in 2005, 200,000 common stock options were exercised having an exercise price of $29.01 per share.

2006 Debt Issuances, Redemptions and Maturities

In addition to the debt issuances, redemptions and maturities discussed herein, MEHC and its subsidiaries made scheduled repayments on parent company subordinated debt and subsidiary and project debt totaling approximately $590 million during the year ended December 31, 2006.

·	On March 24, 2006, MEHC completed a $1,700.0 million offering of 6.125% unsecured senior bonds due 2036. The proceeds were used to fund MEHC’s exercise of its right to repurchase shares of its common stock previously issued to Berkshire Hathaway.

·	On June 15, 2006, MidAmerican Energy’s 6.375% series of notes, totaling $160.0 million, matured.

On July 6, 2006, MEHC entered into a $600.0 million credit facility pursuant to the terms and conditions of an amended and restated credit agreement. The amended and restated credit agreement remains unsecured, carries a variable interest rate based on LIBOR or a base rate, at MEHC’s option, plus a margin, and the termination date was extended to July 6, 2011. The facility is for general corporate purposes and also continues to support letters of credit for the benefit of certain subsidiaries and affiliates.

·	On August 10, 2006, PacifiCorp issued $350.0 million of 6.1%, 30-year first mortgage bonds. The proceeds from this offering were used to repay a portion of PacifiCorp’s short-term debt and for general corporate purposes.

On October 6, 2006, MidAmerican Energy completed the sale of $350.0 million in aggregate principal amount of its 5.8% medium-term notes due October 15, 2036. The proceeds from this offering are being used to support construction of MidAmerican Energy’s electric generation projects, to repay a portion of its short-term debt and for general corporate purposes.

2005 Debt Issuances, Redemptions and Maturities

In addition to the debt issuances, redemption and maturities discussed herein, MEHC and its subsidiaries made scheduled repayments on parent company subordinated debt and subsidiary and project debt totaling approximately $565 million during the year ended December 31, 2005.

·	In February 2005, a subsidiary of CE Electric UK exercised a call option to purchase, and then cancelled, its £155.0 million Variable Rate Reset Trust Securities, due in 2020. A charge to exercise the call option of $10.2 million was recognized in interest expense.

·	On February 15, 2005, MidAmerican Energy’s 7% series of mortgage bonds, totaling $90.5 million, was repaid upon maturity.

·	On April 14, 2005, Northern Natural Gas issued $100.0 million of 5.125% senior notes due May 1, 2015. The proceeds were used by Northern Natural Gas to repay its outstanding $100.0 million 6.875% senior notes due May 1, 2005.

On May 5, 2005, Northern Electric Finance plc, an indirect wholly owned subsidiary of CE Electric UK, issued £150.0 million of 5.125% bonds due 2035, guaranteed by Northern Electric and guaranteed as to scheduled payments of principal and interest by Ambac. Additionally, on May 5, 2005, Yorkshire Electricity, a wholly owned subsidiary of CE Electric UK, issued £200.0 million of 5.125% bonds due 2035, guaranteed as to scheduled payments of principal and interest by Ambac. The proceeds from the offerings are being invested and used for general corporate purposes. Investments include a £100.0 million, 4.75%, fixed rate guaranteed investment contract maturing in December 2007 and a £200.0 million, 4.73%, fixed rate guaranteed investment contract maturing in February 2008. The proceeds from the maturing guaranteed investment contracts will be used to repay certain long-term debt of subsidiaries of CE Electric UK. In connection with the issuance of such bonds, CE Electric UK entered into agreements amending certain terms and conditions of its £200.0 million 7.25% bonds due 2022.

·	On September 15, 2005, MEHC’s 7.23% senior notes, totaling $260.0 million, were repaid upon maturity.

·	On November 1, 2005, MidAmerican Energy issued $300.0 million of 5.75% medium-term notes due in 2035. The proceeds are being used to support construction of its electric generation projects and for general corporate purposes.

Credit Ratings

As of January 31, 2007, MEHC’s senior unsecured debt credit ratings were as follows: Moody’s Investor Service, “Baa1/stable”; Standard and Poor’s, “BBB+/stable”; and Fitch Ratings, “BBB+/stable.”

Debt and preferred securities of MEHC and its subsidiaries may be rated by nationally recognized credit rating agencies. Assigned credit ratings are based on each rating agency’s assessment of the rated company’s ability to, in general, meet the obligations of its issued debt or preferred securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. Other than the agreements discussed below, MEHC and its subsidiaries do not have any credit agreements that require termination or a material change in collateral requirements or payment schedule in the event of a downgrade in the credit ratings of the respective company’s securities.

In conjunction with their risk management activities, PacifiCorp and MidAmerican Energy must meet credit quality standards as required by counterparties. In accordance with industry practice, master agreements that govern PacifiCorp’s and MidAmerican Energy’s energy supply and marketing activities either specifically require each company to maintain investment grade credit ratings or provide the right for counterparties to demand “adequate assurances” in the event of a material adverse change in PacifiCorp’s or MidAmerican Energy’s creditworthiness. If one or more of PacifiCorp’s or MidAmerican Energy’s credit ratings decline below investment grade, PacifiCorp or MidAmerican Energy may be required to post cash collateral, letters of credit or other similar credit support to facilitate ongoing wholesale energy supply and marketing activities. As of January 31, 2007, PacifiCorp’s and MidAmerican Energy’s credit ratings from the three recognized credit rating agencies were investment grade; however if the ratings fell below investment grade, PacifiCorp’s and MidAmerican Energy’s estimated potential collateral requirements would total approximately $257 million and $249 million, respectively. PacifiCorp’s and MidAmerican Energy’s potential collateral requirements could fluctuate considerably due to seasonality, market price volatility, and a loss of key generating facilities or other related factors.

Yorkshire Power Group Limited (“YPGL”), a subsidiary of CE Electric UK, has in effect certain currency rate swap agreements for its Yankee bonds with three large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in sterling for $281.0 million of 6.496% Yankee bonds outstanding as of December 31, 2006. The agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed sterling rate ranging from 7.3175% to 7.3450%. The estimated fair value of these swap agreements as of December 31, 2006 was $104.7 million based on quotes from the counterparties to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated. Certain of these counterparties have the option to terminate the swap agreements and demand payment of the fair value of the swaps if YPGL’s credit ratings from the three recognized credit rating agencies decline below investment grade. As of January 31, 2007, YPGL’s credit ratings from the three recognized credit rating agencies were investment grade; however, if the ratings fell below investment grade, payment requirements would have been $48.8 million.

Inflation

Inflation has not had a significant impact on the Company’s costs.

Obligations and Commitments

The Company has contractual obligations and commercial commitments that may affect its financial condition. Contractual obligations to make future payments arise from parent company and subsidiary long-term debt and notes payable, operating leases and power and fuel purchase contracts. Other obligations and commitments arise from unused lines of credit and letters of credit. Material obligations and commitments as of December 31, 2006 are as follows (in millions):

	Payments Due By Periods
					2008-		2010-		2012 and
	Total		2007		2009		2011		After
Contractual Cash Obligations:
Parent company senior debt	$	4,475.0	$	550.0	$	1,000.0	$	-	$	2,925.0
Parent company subordinated debt		1,429.8		234.0		468.0		331.6		396.2
Subsidiary and project debt		11,513.0		553.4		1,406.1		1,274.9		8,278.6
Interest payments on long-term debt		14,984.3		1,151.0		1,904.9		1,635.7		10,292.7
Short-term debt		551.8		551.8		-		-		-
Coal, electricity and natural gas contract commitments ⁽¹⁾		8,688.2		1,538.7		2,071.9		1,313.3		3,764.3
Owned hydroelectric commitments ⁽¹⁾		706.2		48.5		129.3		144.1		384.3
Operating leases ⁽¹⁾		550.6		106.3		153.9		97.0		193.4
Deferred costs on construction contract ⁽²⁾		200.0		200.0		-		-		-
Total contractual cash obligations	$	43,098.9	$	4,933.7	$	7,134.1	$	4,796.6	$	26,234.5

	Commitment Expiration per Period
					2008-		2010-		2012 and
	Total		2007		2009		2011		After
Other Commercial Commitments:
Unused revolving credit facilities and lines of credit -
Parent company revolving credit facility	$	388.3	$	-	$	-	$	388.3	$	-
Subsidiary revolving credit facilities and lines of credit		1,125.6		-		22.5		1,103.1		-
Total unused revolving credit facilities and lines of credit	$	1,513.9	$	-	$	22.5	$	1,491.4	$	-
Parent company letters of credit outstanding	$	60.8	$	48.7	$	12.1	$	-	$	-
Pollution control revenue bond standby letters of credit	$	296.9	$	-	$	-	$	296.9	$	-
Pollution control revenue bond standby bond purchase agreements	$	220.9	$	124.4	$	-	$	96.5	$	-
Other standby letters of credit	$	91.6	$	27.2	$	-	$	64.4	$	-

⁽¹⁾	The coal, electricity and natural gas contract commitments, owned hydroelectric commitments and operating leases are not reflected on the Consolidated Balance Sheets.

⁽²⁾	MidAmerican Energy is allowed to defer up to $200.0 million in payments to the contractor under its contract to build Council Bluffs Unit 4. Approximately 39.3% of this commitment is expected to be funded by the joint owners of Council Bluffs Unit 4.

The Company has other types of commitments that are subject to change and relate primarily to the items listed below. For additional information, refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplemental Data.

·	Construction and other development costs (Liquidity and Capital Resources included within this Item 7)

·	Debt service reserve guarantees (Note 13)

·	Asset retirement obligations (Note 12)

·	Residual guarantees on operating leases (Note 19)

·	Pension and postretirement commitments (Note 20)

Off-Balance Sheet Arrangements

The Company has certain investments that are accounted for under the equity method in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Accordingly, an amount is recorded on the Company’s Consolidated Balance Sheets as an equity investment and is increased or decreased for the Company’s pro-rata share of earnings or losses, respectively, less any dividend distribution from such investments.

As of December 31, 2006, the Company’s investments that are accounted for under the equity method had long-term debt and letters of credit outstanding of $702.4 million and $90.8 million, respectively. As of December 31, 2006, the Company’s pro-rata share of such long-term debt and outstanding letters of credit was $346.6 million and $45.4 million, respectively. All of the Company’s pro-rata share of the outstanding long-term debt is non-recourse to the Company. $35.2 million of the Company’s pro-rata share of the outstanding letters of credit is recourse to the Company and is included in the Obligations and Commitments table. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse long-term debt could result in a loss of invested equity.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data.

Critical Accounting Policies

Certain accounting policies require management to make estimates and judgments concerning transactions that will be settled in the future. Amounts recognized in the financial statements from such estimates are necessarily based on numerous assumptions involving varying and potentially significant degrees of judgment and uncertainty. Accordingly, the amounts currently reflected in the financial statements will likely increase or decrease in the future as additional information becomes available. The following critical accounting policies are impacted significantly by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.

Accounting for the Effects of Certain Types of Regulation

PacifiCorp, MidAmerican Energy, Northern Natural Gas and Kern River (the “Domestic Regulated Businesses”) prepare their financial statements in accordance with the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation,” (“SFAS No. 71”) which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS No. 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated entity is required to defer the recognition of costs or income if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, the Domestic Regulated Businesses have deferred certain costs and income that will be recognized in earnings over various future periods.

Management continually evaluates the applicability of SFAS No. 71 and assesses whether its regulatory assets are probable of future recovery by considering factors such as a change in the regulator’s approach to setting rates from cost-based rate making to another form of regulation, other regulatory actions or the impact of competition which could limit the Company’s ability to recover its costs. Based upon this continual assessment, management believes the application of SFAS No. 71 continues to be appropriate and its existing regulatory assets are probable of recovery. The assessment reflects the current political and regulatory climate at both the state and federal levels and is subject to change in the future. If it becomes no longer probable that these costs will be recovered, the regulatory assets and regulatory liabilities would be written off and recognized in operating income. Total regulatory assets were $1,827.2 million and total regulatory liabilities were $1,838.7 million as of December 31, 2006. Refer to Note 6 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for additional information regarding the Company’s regulatory assets and liabilities.

Derivatives

The Company is exposed to variations in the market prices of electricity and natural gas, foreign currency and interest rates and uses derivative instruments, including forward purchases and sales, futures, swaps and options to manage these inherent market price risks.

Measurement Principles

Derivative instruments are recorded in the Consolidated Balance Sheets at fair value as either assets or liabilities unless they are designated and qualifying for the normal purchases and normal sales exemptions afforded by GAAP. The fair values of derivative instruments are determined using forward price curves. Forward price curves represent the Company’s estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations when available and uses internally developed, modeled prices when market quotations are unavailable. The assumptions used in these models are critical, since any changes in assumptions could have a significant impact on the fair value of the contracts.

Classification and Recognition Methodology

The majority of the Company’s contracts are either probable of recovery in rates and therefore recorded as a net regulatory asset or liability or are accounted for as cash flow hedges and therefore recorded as accumulated other comprehensive income. Accordingly, amounts are generally not recognized in earnings until the contracts are settled. As of December 31, 2006, the Company had $244.2 million recorded as net regulatory assets and $29.2 million recorded as accumulated other comprehensive income, net of tax, related to these contracts in the Consolidated Balance Sheets. If it becomes no longer probable that a contract will be recovered in rates, the regulatory asset will be written-off and recognized in earnings. For contracts designated in hedge relationships (“hedge contracts”), the Company discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued, future changes in the value of the derivative are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in accumulated other comprehensive income will remain there until the hedged item is realized, unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in accumulated other comprehensive income are immediately recognized in earnings.

Impairment of Long-Lived Assets and Goodwill

The Company evaluates long-lived assets, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable or the assets meet the criteria of held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated discounted present value of the expected future cash flows from using the asset. For regulated assets, any impairment charge is offset by the establishment of a regulatory asset to the extent recovery in rates is probable. For non-regulated assets, any resulting impairment loss is reflected in the Consolidated Statement of Operations.

The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what the Company would expect to recover from the future use of the asset. Changes in judgment that could significantly alter the calculation of the fair value or the recoverable amount of the asset may result from, but are not limited to, significant changes in the market price of the asset, the use of the asset, management’s plans, legal factors, the business climate or the physical condition of the asset. An impairment analysis of generating facilities or pipelines requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the facilities. Any resulting impairment loss is highly dependent on those underlying assumptions and could significantly affect the Company’s results of operations.

The Company’s Consolidated Balance Sheet as of December 31, 2006 includes goodwill of acquired businesses of $5.3 billion. Goodwill is allocated to each reporting unit and is tested for impairment using a variety of methods, principally discounted projected future net cash flows, at least annually and impairments, if any, are charged to earnings. The Company completed its annual review as of October 31. A significant amount of judgment is required in performing goodwill impairment tests. Key assumptions used in the testing include, but are not limited to, the use of an appropriate discount rate and estimated future cash flows. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating cash flows, the Company incorporates current market information as well as historical factors.

During 2005 and 2004, the Company recognized impairments on certain of its long-lived assets and goodwill. For additional discussion of these impairments, refer to Notes 4 and 17 of Notes to Consolidated Financial Statements Included in Item 8. Financial Statements and Supplementary Data.

Accrued Pension and Postretirement Expense

The Company sponsors defined benefit pension and other postretirement benefit plans that cover the majority of its employees. In addition, certain bargaining unit employees participate in a joint trust plan to which PacifiCorp contributes. Effective with the adoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” as of December 31, 2006, the funded status of defined benefit pension and postretirement plans must be recognized in the balance sheet. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2006, the Company recognized an asset totaling $66.6 million for the over-funded status and a liability totaling $838.7 million for the under-funded status for the Company’s defined benefit pension and other postretirement benefit plans.

The expense and benefit obligations relating to these pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected returns on plan assets, and health care cost trend rates. These actuarial assumptions are reviewed annually and modified as appropriate. The Company believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior experience, market conditions and the advice of plan actuaries. Refer to Note 20 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for disclosures about the Company’s pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic cost for these plans as of and for the period ended December 31, 2006.

In establishing its assumption as to the expected return on assets, the Company reviews the expected asset allocation and develops return assumptions for each asset class based on historical performance and independent advisors’ forward-looking views of the financial markets. Pension and other postretirement benefit expenses increase as the expected rate of return on retirement plan and other postretirement benefit plan assets decreases. The Company regularly reviews its actual asset allocations and periodically rebalances its investments to its targeted allocations when considered appropriate.

The Company chooses a discount rate based upon high quality fixed-income investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities, as well as expenses, increase as the discount rate is reduced.

The Company chooses a health care cost trend rate which reflects the near and long-term expectations of increases in medical costs. The health care cost trend rate gradually declines to 5% in 2010 through 2012 at which point the rate is assumed to remain constant. Refer to Note 20 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data for health care cost trend rate sensitivity disclosures.

The actuarial assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded. If changes were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

	Domestic Plans
						Other Postretirement					United Kingdom
	Pension Plans					Benefit Plans					Pension Plan
	+0.5%			-0.5%		+0.5%			-0.5%		+0.5%			-0.5%
						(in millions)
Effect on December 31, 2006,
Benefit Obligations:
Discount rate	$	(121.7	)	$	133.2	$	(47.5	)	$	52.5	$	(133.1	)	$	150.7

Effect on 2006 Periodic Cost:
Discount rate	$	(10.7	)	$	10.9	$	(3.6	)	$	3.7	$	(7.5	)	$	7.5
Expected return on assets		(7.0	)		7.0		(2.3	)		2.3		(7.5	)		7.5

A variety of factors, including the plan funding practices of the Company, affect the funded status of the plans. The Pension Protection Act of 2006 imposed generally more stringent funding requirements for defined benefit pension plans, particularly for those significantly under-funded, and allowed for greater tax deductible contributions to such plans than previous rules permitted under the Employee Retirement Income Security Act. As a result of the Pension Protection Act of 2006, the Company does not anticipate any significant changes to the amount of funding previously anticipated through 2007; however, depending on a variety of factors which impact the funded status of the plans, including asset returns, discount rates and plan changes, the Company may be required to accelerate contributions to its domestic pension plans for periods after 2007 and there may be more volatility in annual contributions than historically experienced, which could have a material impact on cash flows.

Income Taxes

In determining the Company’s tax liabilities, management is required to interpret complex tax laws and regulations. In preparing tax returns, the Company is subject to continuous examinations by federal, state, local and foreign tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Internal Revenue Service has closed examination of the Company’s income tax returns through 2001. Although the ultimate resolution of the Company’s federal and state tax examinations is uncertain, the Company believes it has made adequate provisions for these tax positions and the aggregate amount of any additional tax liabilities that may result from these examinations, if any, is not expected to have a material adverse affect on the Company’s financial results.

Both PacifiCorp and MidAmerican Energy are required to pass income tax benefits related to certain accelerated tax depreciation and other property-related basis differences on to their customers in most state jurisdictions. These amounts were recognized as a net regulatory asset totaling $581.0 million as of December 31, 2006, and will be included in rates when the temporary differences reverse. Management believes the existing regulatory assets are probable of recovery. If it becomes probable that these costs will not be recovered, the assets would be written-off and recognized in earnings.

The Company has not provided U.S. deferred income taxes on its currency translation adjustment or the cumulative earnings of international subsidiaries that have been determined by management to be reinvested indefinitely. The cumulative earnings related to ongoing operations were approximately $1.1 billion as of December 31, 2006. Because of the availability of U.S. foreign tax credits, it is not practicable to determine the U.S. federal income tax liability that would be payable if such earnings were not reinvested indefinitely. Deferred taxes are provided for earnings of international subsidiaries when the Company plans to remit those earnings. The Company periodically evaluates its cash requirements in the U.S. and abroad and evaluates its short-term and long-term operational and fiscal objectives in determining whether the earnings of its foreign subsidiaries are indefinitely invested outside the U.S. or will be remitted to the U.S. within the foreseeable future.

Revenue Recognition - Unbilled Revenue

Unbilled revenues were $407.3 million as of December 31, 2006. Historically, any differences between the actual and estimated amounts have been immaterial.

Electric and Natural Gas Retail Revenues and Electric Distribution Revenues

Revenue from electric customers is recognized as electricity is delivered and includes amounts for services rendered. Revenue from the sale and distribution of natural gas is recognized when either the service is provided or the product is delivered.

For PacifiCorp and MidAmerican Energy, the determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, PacifiCorp and MidAmerican Energy record unbilled revenues representing an estimate of the amount customers will be billed for energy provided between the meter-reading dates and the end of that month. This estimate is reversed in the following month and actual revenue is recorded based on subsequent meter readings.

The monthly unbilled revenues of PacifiCorp and MidAmerican Energy are determined by the estimation of unbilled energy provided during the period, the assignment of unbilled energy provided to customer classes and the average rate per customer class. Factors that can impact the estimate of unbilled energy provided include, but are not limited to, seasonal weather patterns, historical trends, line losses, economic impacts and composition of customer classes.

The distribution businesses in Great Britain record unbilled revenue representing the estimated amounts that customers will be billed for electricity distributed during the period based upon information received from the national settlement system.

Natural Gas Transportation and Storage

The majority of the pipelines’ transportation and storage revenue is derived from fixed reservation charges based on contractual quantities and rates. The remaining revenue, consisting primarily of commodity charges, is based on contractual rates and actual or estimated usage. The usage is based on scheduled quantities and is subject to volume estimates, which include estimates of meter readings and lost and unaccounted for volumes.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The Company’s Consolidated Balance Sheets include assets and liabilities whose fair values are subject to market risks. The Company’s significant market risks are primarily associated with commodity prices, currency exchange rates and interest rates. The following sections address the significant market risks associated with the Company’s business activities. The Company also has established guidelines for credit risk management. Refer to Notes 2 and 14 of Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data of this Form 10-K for additional information regarding the Company’s accounting for derivative contracts.

Commodity Price Risk

MEHC is subject to significant commodity risk, particularly through its ownership of PacifiCorp and MidAmerican Energy. Exposures include variations in the price of wholesale electricity that is purchased and sold, fuel costs to generate electricity, and natural gas supply for regulated retail gas customers. Electricity and natural gas prices are subject to wide price swings as demand responds to, among many other items, changing weather, limited storage, transmission and transportation constraints, and lack of alternative supplies from other areas. To mitigate a portion of the risk, both use derivative instruments, including forwards, futures, options, swaps and other over-the-counter agreements, to effectively secure future supply or sell future production at fixed prices. The settled cost of these contracts is generally recovered from customers in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives, that are probable of recovery in rates, are recorded as regulatory assets or liabilities. Financial results may be negatively impacted if the costs of wholesale electricity, fuel and or natural gas are higher than what is permitted to be recovered in rates.

MidAmerican Energy also uses futures, options and swap agreements to economically hedge gas and electric commodity prices for physical delivery to non-regulated customers. The Company does not engage in a material amount of proprietary trading activities.

The table that follows summarizes the Company’s commodity risk on energy derivative contracts as of December 31, 2006 and shows the effects of a hypothetical 10% increase and a 10% decrease in forward market prices by the expected volumes for these contracts as of that date. The selected hypothetical change does not reflect what could be considered the best or worst case scenarios (in millions):

	Fair Value			Hypothetical Price Change		Estimated Fair Value after Hypothetical Change in Price
As of December 31, 2006	$	(272.9	)		10% increase	$	(220.1	)
					10% decrease	$	(325.7	)

Foreign Currency Risk

MEHC’s business operations and investments outside the United States increase its risk related to fluctuations in currency rates primarily in relation to the British pound and the Philippine peso. Our principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from our foreign operations changes with the fluctuations of the currency in which they transact.

CE Electric UK’s functional currency is the British pound. At December 31, 2006, a 10% devaluation in the British pound to the United States dollar would result in MEHC’s Consolidated Balance Sheet being negatively impacted by a $179.4 million cumulative translation adjustment in accumulated other comprehensive income. A 10% devaluation in the average currency exchange rate would have resulted in lower reported earnings for CE Electric UK of $27.9 million in 2006. CalEnergy Generation-Foreign has also mitigated a significant portion of its foreign currency risk as PNOC-EDC’s and NIA’s obligations under the project agreements are substantially denominated in U.S. dollars. Accordingly, its functional currency is the United States dollar and no translation adjustment is required.

MEHC also selectively reduces its foreign currency risk by hedging through foreign currency derivatives. CE Electric UK has entered into certain currency exchange rate swap agreements with large multi-national financial institutions for its U.S. dollar denominated senior notes and Yankee bonds. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in sterling for $237.0 million of 6.995% senior notes and $281.0 million of 6.496% Yankee bonds outstanding at December 31, 2006. The following table summarizes the outstanding currency exchange rate swap agreements as of December 31, 2006, and shows the estimated changes in value of the contracts assuming change in the underlying exchange rates. The changes in value do not necessarily reflect the best or worst case results and actual results may differ (dollars in millions):

		Fair Value			Hypothetical devaluation of the U.S. dollar versus British pound			Estimated Fair Value after Hypothetical Change in Price
As of December 31, 2006		$	(145.3	)		10%		$	(213.1	)

Interest Rate Risk

At December 31, 2006, The Company had fixed-rate long-term debt totaling $16,722.8 million with a total fair value of $17,565.9 million. Because of their fixed interest rates, these instruments do not expose the Company to the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would decrease by approximately $733 million if interest rates were to increase by 10% from their levels as of December 31, 2006. In general, such a decrease in fair value would impact earnings and cash flows only if the Company were to reacquire all or a portion of these instruments prior to their maturity. Comparatively, at December 31, 2005, the Company had fixed-rate long-term debt totaling $11,348.0 million with a total fair value of $12,066.0 million. The fair value of these instruments would have decreased by approximately $434 million if interest rates had increased by 10% from their levels as of December 31, 2005.

At December 31, 2006 and 2005, the Company had floating-rate obligations totaling $726.6 million and $166.6 million, respectively, that expose the Company to the risk of increased interest expense in the event of increases in short-term interest rates. This market risk is not hedged; however, if floating interest rates were to increase by 10% from December 31, 2006 levels, it would not have a material effect on the Company’s consolidated annual interest expense in either year.

The Company may enter into contractual agreements to hedge exposure to interest rate risk. Specifically, MEHC and its subsidiaries periodically enter into agreements to protect against increases in interest rates in anticipation of issuing long-term debt. Changes in fair value of these agreements designated as cash flow hedges are reported in accumulated other comprehensive income to the extent the hedge is effective until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related debt issuance. In September 2006, MEHC entered into a treasury rate lock agreement in the notional amount of $1.55 billion to protect the Company against an increase in interest rates on future long-term debt issuances.

	Fair Value		Hypothetical Basis-point Change		Estimated Fair Value after Hypothetical Change in Price
As of December 31, 2006	$	13.0		20 basis point increase	$	57.0
				20 basis point decrease	$	(35.2	)

Credit Risk

Domestic Regulated Operations

PacifiCorp and MidAmerican Energy extend unsecured credit to other utilities, energy marketers, financial institutions and certain commercial and industrial end-users in conjunction with wholesale energy marketing activities. Credit risk relates to the risk of loss that might occur as a result of non-performance by counterparties of their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with such counterparty.

PacifiCorp and MidAmerican Energy analyze the financial condition of each significant counterparty before entering into any transactions, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on a daily basis. To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp and MidAmerican Energy enter into netting and collateral arrangements that include margining and cross-product netting agreements and obtaining third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed interest fees for delayed receipts. If required, PacifiCorp and MidAmerican Energy exercise rights under these arrangements, including calling on the counterparty’s credit support arrangement.

At December 31, 2006, 66.9% of PacifiCorp’s and 82.6% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale operations was with counterparties having externally rated “investment grade” credit ratings, while an additional 11.9% of PacifiCorp’s and 14.9% of MidAmerican Energy’s credit exposure, net of collateral, from wholesale operations was with counterparties having financial characteristics deemed equivalent to “investment grade” by PacifiCorp and MidAmerican Energy based on internal review.

Northern Natural Gas’ primary customers include regulated local distribution companies in the upper Midwest. Kern River’s primary customers are major oil and gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies and natural gas distribution utilities which provide services in Utah, Nevada and California. As a general policy, collateral is not required for receivables from creditworthy customers. Customers’ financial condition and creditworthiness are regularly evaluated, and historical losses have been minimal. In order to provide protection against credit risk, and as permitted by the separate terms of each of Northern Natural Gas’ and Kern River’s tariffs, the companies have required customers that lack creditworthiness, as defined by the tariffs, to provide cash deposits, letters of credit or other security until their creditworthiness improves.

CE Electric UK

Northern Electric and Yorkshire Electricity charge fees for the use of their electrical infrastructure levied on supply companies. The supply companies, which purchase electricity from generators and traders and sell the electricity to end-use customers, use Northern Electric’s and Yorkshire Electricity’s distribution networks pursuant to the multilateral “Distribution Connection and Use of System Agreement” that replaced the former bilateral “Distribution Use of System Agreement” in October 2006, which Northern Electric and Yorkshire Electricity separately entered into with the various suppliers of electricity in their respective distribution service areas. Northern Electric’s and Yorkshire Electricity’s customers are concentrated in a small number of electricity supply businesses with RWE Npower PLC accounting for approximately 42% of distribution revenues in 2006. The Office of Gas and Electricity Markets (“Ofgem”) has determined a framework which sets credit limits for each supply business based on its credit rating or payment history and requires them to provide credit cover if their value at risk (measured as being equivalent to 45 days usage) exceeds the credit limit. Acceptable credit typically is provided in the form of a parent company guarantee, letter of credit or an escrow account. Ofgem has indicated that, provided Northern Electric and Yorkshire Electricity have implemented credit control, billing and collection in line with best practice guidelines and can demonstrate compliance with the guidelines or are able to satisfactorily explain departure from the guidelines, any bad debt losses arising from supplier default will be recovered through an increase in future allowed income. Losses incurred to date have not been material.

CalEnergy Generation-Foreign

PNOC-EDC’s and NIA’s obligations under the project agreements are the Leyte Projects’ and Casecnan Project’s sole source of operating revenue. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations under the project agreements and any material failure of the ROP to fulfill its obligation under the performance undertaking would significantly impair the ability to meet existing and future obligations, including obligations pertaining to the outstanding project debt. Total operating revenue for CalEnergy Generation-Foreign was $187.8 million for the Leyte Projects and $148.5 million for the Casecnan Project for the year ended December 31, 2006. On June 25, 2006, the Upper Mahiao Project was transferred, as scheduled, to the Philippine government. The remaining Leyte Projects’ agreements each expire in July 2007, while the Casecnan Project’s agreement expires in December 2021.

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm	79

Consolidated Balance Sheets as of December 31, 2006 and 2005	80

Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005 and 2004	82

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2006, 2005 and 2004	83

Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004	84

Notes to Consolidated Financial Statements	85

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

MidAmerican Energy Holdings Company

Des Moines, Iowa

We have audited the accompanying consolidated balance sheets of MidAmerican Energy Holdings Company and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedules listed in the Index at Item 15. These financial statements and financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R),” as of December 31, 2006.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

February 27, 2007

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in millions)

	As of December 31,
	2006		2005

ASSETS

Current assets:
Cash and cash equivalents	$	342.8	$	357.9
Short-term investments		15.0		38.4
Restricted cash and short-term investments		132.3		102.9
Accounts receivable, net		1,280.3		802.6
Amounts held in trust		96.9		108.5
Inventories		407.0		128.2
Derivative contracts		236.0		54.0
Deferred income taxes		152.2		177.7
Other current investments		195.8		-
Other current assets		281.1		140.1
Total current assets		3,139.4		1,910.3

Property, plant and equipment, net		24,039.4		11,915.4
Goodwill		5,344.7		4,156.2
Regulatory assets		1,827.2		441.1
Other investments		835.2		798.7
Derivative contracts		247.6		6.1
Deferred charges and other assets		1,013.8		1,142.9

Total assets	$	36,447.3	$	20,370.7

The accompanying notes are an integral part of these financial statements.

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (continued)

(Amounts in millions)

	As of December 31,
	2006			2005

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	1,049.1		$	523.6
Accrued interest		306.3			198.3
Accrued property and other taxes		231.1			189.1
Amounts held in trust		96.9			108.5
Derivative contracts		270.6			61.7
Other liabilities		616.3			389.3
Short-term debt		551.8			70.1
Current portion of long-term debt		1,103.3			313.7
Current portion of parent company subordinated debt		234.0			234.0
Total current liabilities		4,459.4			2,088.3

Other long-term accrued liabilities		860.9			766.9
Regulatory liabilities		1,838.7			773.9
Pension and post-retirement obligations		855.2			633.3
Derivative contracts		618.2			106.8
Parent company senior debt		3,928.9			2,776.2
Parent company subordinated debt		1,122.6			1,354.1
Subsidiary and project debt		11,060.6			6,836.6
Deferred income taxes		3,449.3			1,539.6
Total liabilities		28,193.8			16,875.7

Minority interest		114.4			21.4
Preferred securities of subsidiaries		128.5			88.4

Commitments and contingencies (Note 19)

Shareholders’ equity:
Zero coupon convertible preferred stock - no shares authorized, issued or outstanding as of December 31, 2006; 50.0 shares authorized, no par value, 41.3 shares issued and outstanding as of December 31, 2005		-			-
Common stock - 115.0 shares authorized, no par value, 74.5 shares issued and outstanding as of December 31, 2006; 60.0 shares authorized, no par value; 9.3 shares issued and outstanding as of December 31, 2005		-			-
Additional paid-in capital		5,420.4			1,963.3
Retained earnings		2,597.7			1,719.5
Accumulated other comprehensive loss, net		(7.5	)		(297.6	)
Total shareholders’ equity		8,010.6			3,385.2

Total liabilities and shareholders’ equity	$	36,447.3		$	20,370.7

The accompanying notes are an integral part of these financial statements.

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in millions)

	Years Ended December 31,
	2006			2005			2004

Operating revenue	$	10,300.7		$	7,115.5		$	6,553.4

Costs and expenses:
Cost of sales		4,587.4			3,293.4			2,757.9
Operating expense		2,586.0			1,685.2			1,631.9
Depreciation and amortization		1,006.8			608.2			638.2
Total costs and expenses		8,180.2			5,586.8			5,028.0

Operating income		2,120.5			1,528.7			1,525.4

Other income (expense):
Interest expense		(1,152.5	)		(891.0	)		(903.2	)
Capitalized interest		39.7			16.7			20.0
Interest and dividend income		73.5			58.1			38.9
Other income		239.3			74.5			128.2
Other expense		(13.0	)		(22.1	)		(10.1	)
Total other income (expense)		(813.0	)		(763.8	)		(726.2	)

Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income		1,307.5			764.9			799.2
Income tax expense		406.7			244.7			265.0
Minority interest and preferred dividends of subsidiaries		28.2			16.0			13.3
Income from continuing operations before equity income		872.6			504.2			520.9
Equity income		43.5			53.3			16.9
Income from continuing operations		916.1			557.5			537.8
Income (loss) from discontinued operations, net of tax (Note 17)		-			5.2			(367.6	)
Net income available to common and preferred shareholders	$	916.1		$	562.7		$	170.2

The accompanying notes are an integral part of these financial statements.

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

FOR THE THREE YEARS ENDED DECEMBER 31, 2006

(Amounts in millions)

												Accumulated
	Outstanding					Additional						Other
	Common			Common		Paid-in			Retained			Comprehensive
	Shares			Stock		Capital			Earnings			Loss			Total
Balance, January 1, 2004		9.3		$	-	$	1,957.3		$	999.6		$	(185.5	)	$	2,771.4
Net income		-			-		-			170.2			-			170.2
Other comprehensive income:
Foreign currency translation adjustment		-			-		-			-			107.4			107.4
Fair value adjustment on cash flow hedges, net of tax of $(6.1)		-			-		-			-			(12.3	)		(12.3	)
Minimum pension liability adjustment, net of tax of $(19.9)		-			-		-			-			(46.4	)		(46.4	)
Unrealized gains on securities, net of tax of $0.3		-			-		-			-			0.5			0.5
Total comprehensive income																219.4
Common stock purchase		(0.2	)		-		(7.0	)		(13.0	)		-			(20.0	)
Other equity transactions		-			-		0.4			-			-			0.4
Balance, December 31, 2004		9.1			-		1,950.7			1,156.8			(136.3	)		2,971.2
Net income		-			-		-			562.7			-			562.7
Other comprehensive income:
Foreign currency translation adjustment		-			-		-			-			(186.2	)		(186.2	)
Fair value adjustment on cash flow hedges, net of tax of $(9.8)		-			-		-			-			(19.5	)		(19.5	)
Minimum pension liability adjustment, net of tax of $18.0		-			-		-			-			43.7			43.7
Unrealized gains on securities, net of tax of $0.5		-			-		-			-			0.7			0.7
Total comprehensive income																401.4
Exercise of common stock options		0.2			-		5.8			-			-			5.8
Tax benefit from exercise of common stock options		-			-		6.2			-			-			6.2
Other equity transactions		-			-		0.6			-			-			0.6
Balance, December 31, 2005		9.3			-		1,963.3			1,719.5			(297.6	)		3,385.2
Net income		-			-		-			916.1			-			916.1
Other comprehensive income:
Foreign currency translation adjustment		-			-		-			-			262.6			262.6
Fair value adjustment on cash flow hedges, net of tax of $32.0		-			-		-			-			53.4			53.4
Minimum pension liability adjustment, net of tax of $145.6		-			-		-			-			338.4			338.4
Unrealized gains on securities, net of tax of $1.9		-			-		-			-			2.8			2.8
Total comprehensive income																1,573.3
Adjustment to initially apply FASB Statement No. 158, net of tax of $(159.7)		-			-		-			-			(367.1	)		(367.1	)
Preferred stock conversion to common stock		41.3			-		-			-			-			-
Exercise of common stock options		0.8			-		22.2			-			-			22.2
Tax benefit from exercise of common stock options		-			-		34.1			-			-			34.1
Common stock issuances		35.2			-		5,109.5			-			-			5,109.5
Common stock purchases		(12.1	)		-		(1,712.1	)		(37.9	)		-			(1,750.0	)
Other equity transactions		-			-		3.4			-			-			3.4
Balance, December 31, 2006		74.5		$	-	$	5,420.4		$	2,597.7		$	(7.5	)	$	8,010.6

The accompanying notes are an integral part of these financial statements.

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in millions)

	Years Ended December 31,
	2006			2005			2004
Cash flows from operating activities:
Income from continuing operations	$	916.1		$	557.5		$	537.8
Adjustments to reconcile income from continuing operations to cash flows from continuing operations:
Distributions less income on equity investments		(6.8	)		(18.9	)		20.0
Gain on other items, net		(145.1	)		(6.3	)		(71.8	)
Depreciation and amortization		1,006.8			608.2			638.2
Amortization of regulatory assets and liabilities		26.2			38.7			(1.6	)
Amortization of deferred financing costs		18.7			16.1			20.9
Provision for deferred income taxes		260.3			130.0			176.6
Other		(11.4	)		(37.8	)		16.9
Changes in other items, net of effects from acquisitions:
Accounts receivable and other current assets		(39.0	)		(136.0	)		(43.6	)
Accounts payable and other accrued liabilities		(70.1	)		167.4			171.5
Deferred income		(32.5	)		(7.8	)		(6.5	)
Net cash flows from continuing operations		1,923.2			1,311.1			1,458.4
Net cash flows from discontinued operations		-			(0.3	)		(33.8	)
Net cash flows from operating activities		1,923.2			1,310.8			1,424.6
Cash flows from investing activities:
PacifiCorp acquisition, net of cash acquired		(4,932.4	)		(5.2	)		-
Other acquisitions, net of cash acquired		(73.7	)		(5.0	)		(36.7	)
Capital expenditures relating to operating projects		(1,684.3	)		(796.3	)		(778.3	)
Construction and other development costs		(738.8	)		(399.9	)		(401.1	)
Purchases of available-for-sale securities		(1,504.0	)		(2,842.4	)		(2,819.7	)
Proceeds from sale of available-for-sale securities		1,605.7			2,913.1			2,738.0
Purchase of other investments		-			(556.6	)		-
Proceeds from sale of assets		30.2			102.8			8.6
Proceeds from notes receivable		-			-			169.2
Proceeds from affiliate notes		1.0			4.4			14.1
(Increase) decrease in restricted cash and investments		(31.8	)		26.7			(18.5	)
Other		6.7			0.7			25.3
Net cash flows from continuing operations		(7,321.4	)		(1,557.7	)		(1,099.1	)
Net cash flows from discontinued operations		-			6.4			1.0
Net cash flows from investing activities		(7,321.4	)		(1,551.3	)		(1,098.1	)
Cash flows from financing activities:

Berkshire Hathaway Energy Co – ‘10-K’ for 12/31/06

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