10-Q 1 mehc93010form10q.htm MIDAMERICAN ENERGY HOLDINGS COMPANY FORM 10-Q 9.30.10 WebFilings | EDGAR view
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the quarterly period ended September 30, 2010
 
or
 
[  ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the transition period from ______ to _______
 
Commission
File Number
 
Exact name of registrant as specified in its charter;
State or other jurisdiction of incorporation or organization
 
IRS Employer
Identification No.
 
 
 
 
 
001-14881
 
MIDAMERICAN ENERGY HOLDINGS COMPANY
 
94-2213782
 
 
(An Iowa Corporation)
 
 
 
 
666 Grand Avenue, Suite 500
 
 
 
 
Des Moines, Iowa 50309-2580
 
 
 
 
515-242-4300
 
 
 
 
 
 
 
 
 
N/A
 
 
(Former name, former address and former fiscal year, if changed since last report)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x  No  o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  o  No  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer o
Accelerated filer o
Non-accelerated filer x
Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes  o  No  x
 
All of the shares of common equity of MidAmerican Energy Holdings Company are privately held by a limited group of investors. As of October 31, 2010, 74,609,001 shares of common stock were outstanding.

 

TABLE OF CONTENTS
 
PART I
 
 
PART II
 
 

2

 

PART I
 
 
Item 1.    
Financial Statements
 
 
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
To the Board of Directors and Shareholders of
MidAmerican Energy Holdings Company
Des Moines, Iowa
 
We have reviewed the accompanying consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries (the "Company") as of September 30, 2010, and the related consolidated statements of operations and comprehensive income for the three-month and nine-month periods ended September 30, 2010 and 2009, and of cash flows and changes in equity for the nine-month periods ended September 30, 2010 and 2009. These interim financial statements are the responsibility of the Company's management.
 
We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
 
Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
 
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of MidAmerican Energy Holdings Company and subsidiaries as of December 31, 2009, and the related consolidated statements of operations, cash flows, changes in equity, and comprehensive income for the year then ended (not presented herein); and in our report dated March 1, 2010, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2009 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
 
 
/s/ Deloitte & Touche LLP
 
 
Des Moines, Iowa
November 5, 2010

3

 

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
 
 
As of
 
September 30,
2010
 
December 31,
2009
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
521
 
 
$
429
 
Trade receivables, net
1,097
 
 
1,308
 
Income taxes receivable
440
 
 
88
 
Inventories
578
 
 
591
 
Derivative contracts
175
 
 
136
 
Investments and restricted cash and investments
101
 
 
83
 
Other current assets
372
 
 
458
 
Total current assets
3,284
 
 
3,093
 
 
 
 
 
 
 
Property, plant and equipment, net
31,469
 
 
30,936
 
Goodwill
5,036
 
 
5,078
 
Investments and restricted cash and investments
2,464
 
 
2,702
 
Regulatory assets
2,300
 
 
2,093
 
Derivative contracts
30
 
 
52
 
Other assets
940
 
 
730
 
 
 
 
 
 
 
Total assets
$
45,523
 
 
$
44,684
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 

4

 

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
 
 
As of
 
September 30,
2010
 
December 31,
2009
LIABILITIES AND EQUITY
Current liabilities:
 
 
 
Accounts payable
$
798
 
 
$
918
 
Accrued interest
337
 
 
344
 
Accrued property, income and other taxes
303
 
 
277
 
Derivative contracts
204
 
 
123
 
Short-term debt
226
 
 
179
 
Current portion of long-term debt
792
 
 
379
 
Other current liabilities
782
 
 
683
 
Total current liabilities
3,442
 
 
2,903
 
 
 
 
 
 
 
Regulatory liabilities
1,633
 
 
1,603
 
Derivative contracts
468
 
 
458
 
MEHC senior debt
5,371
 
 
5,371
 
MEHC subordinated debt
193
 
 
402
 
Subsidiary debt
13,187
 
 
13,600
 
Deferred income taxes
6,185
 
 
5,604
 
Other long-term liabilities
1,634
 
 
1,900
 
Total liabilities
32,113
 
 
31,841
 
 
 
 
 
 
 
Commitments and contingencies (Note 12)
 
 
 
 
 
 
 
 
 
 
 
Equity:
 
 
 
 
 
MEHC shareholders' equity:
 
 
 
 
 
Common stock - 115 shares authorized, no par value,
 
 
 
75 shares issued and outstanding
 
 
 
Additional paid-in capital
5,439
 
 
5,453
 
Retained earnings
7,600
 
 
6,788
 
Accumulated other comprehensive income, net
143
 
 
335
 
Total MEHC shareholders' equity
13,182
 
 
12,576
 
Noncontrolling interests
228
 
 
267
 
Total equity
13,410
 
 
12,843
 
 
 
 
 
 
 
Total liabilities and equity
$
45,523
 
 
$
44,684
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 

5

 

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
 
 
Three-Month Periods
Ended September 30,
 
Nine-Month Periods
Ended September 30,
 
2010
 
2009
 
2010
 
2009
 
 
 
 
 
 
 
 
Operating revenue:
 
 
 
 
 
 
 
Energy
$
2,510
 
 
$
2,429
 
 
$
7,537
 
 
$
7,448
 
Real estate
253
 
 
312
 
 
793
 
 
764
 
Total operating revenue
2,763
 
 
2,741
 
 
8,330
 
 
8,212
 
 
 
 
 
 
 
 
 
 
Operating costs and expenses:
 
 
 
 
 
 
 
 
Energy:
 
 
 
 
 
 
 
 
Cost of sales
976
 
 
875
 
 
2,956
 
 
2,818
 
Operating expense
577
 
 
598
 
 
1,799
 
 
1,908
 
Depreciation and amortization
316
 
 
313
 
 
939
 
 
916
 
Real estate
250
 
 
294
 
 
773
 
 
748
 
Total operating costs and expenses
2,119
 
 
2,080
 
 
6,467
 
 
6,390
 
 
 
 
 
 
 
 
 
Operating income
644
 
 
661
 
 
1,863
 
 
1,822
 
 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
 
Interest expense
(309
)
 
(316
)
 
(923
)
 
(957
)
Capitalized interest
14
 
 
12
 
 
42
 
 
30
 
Interest and dividend income
4
 
 
8
 
 
24
 
 
36
 
Other, net
33
 
 
41
 
 
89
 
 
119
 
Total other income (expense)
(258
)
 
(255
)
 
(768
)
 
(772
)
 
 
 
 
 
 
 
 
Income before income tax expense and equity income
386
 
 
406
 
 
1,095
 
 
1,050
 
Income tax expense
38
 
 
39
 
 
165
 
 
211
 
Equity income
(24
)
 
(21
)
 
(29
)
 
(49
)
Net income
372
 
 
388
 
 
959
 
 
888
 
Net income attributable to noncontrolling interests
8
 
 
12
 
 
100
 
 
24
 
Net income attributable to MEHC
$
364
 
 
$
376
 
 
$
859
 
 
$
864
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 

6

 

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
 
 
Nine-Month Periods
Ended September 30,
 
2010
 
2009
Cash flows from operating activities:
 
 
 
Net income
$
959
 
 
$
888
 
Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
 
 
Gain on other items, net
(52
)
 
(4
)
Depreciation and amortization
950
 
 
929
 
Stock-based compensation
 
 
123
 
Changes in regulatory assets and liabilities
25
 
 
28
 
Provision for deferred income taxes
572
 
 
700
 
Other, net
(32
)
 
(39
)
Changes in other operating assets and liabilities:
 
 
 
Trade receivables and other assets
174
 
 
293
 
Derivative collateral, net
(93
)
 
93
 
Trading securities
 
 
499
 
Contributions to pension and other postretirement benefit plans, net
(139
)
 
(74
)
Accounts payable and other liabilities
(284
)
 
(453
)
Net cash flows from operating activities
2,080
 
 
2,983
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
Capital expenditures
(1,862
)
 
(2,592
)
Purchases of available-for-sale securities
(77
)
 
(483
)
Proceeds from sales of available-for-sale securities
65
 
 
242
 
Proceeds from Constellation Energy 14% note
 
 
1,000
 
Proceeds from sale of assets and business, net
140
 
 
 
Other, net
(63
)
 
(13
)
Net cash flows from investing activities
(1,797
)
 
(1,846
)
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
Proceeds from MEHC senior debt
 
 
250
 
Repayments of MEHC subordinated debt
(259
)
 
(667
)
Proceeds from subsidiary debt
231
 
 
992
 
Repayments of subsidiary debt
(142
)
 
(383
)
Net proceeds from (repayments of) MEHC revolving credit facility
142
 
 
(216
)
Net repayments of subsidiary short-term debt
(87
)
 
(506
)
Net purchases of common stock
(56
)
 
(123
)
Other, net
(19
)
 
(23
)
Net cash flows from financing activities
(190
)
 
(676
)
 
 
 
 
 
 
Effect of exchange rate changes
(1
)
 
3
 
 
 
 
 
 
 
Net change in cash and cash equivalents
92
 
 
464
 
Cash and cash equivalents at beginning of period
429
 
 
280
 
Cash and cash equivalents at end of period
$
521
 
 
$
744
 
 
The accompanying notes are an integral part of these consolidated financial statements.

7

 

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
 (Amounts in millions)
 
 
MEHC Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
 
 
 
Additional
 
 
 
Comprehensive
 
 
 
 
 
Common
 
Paid-in
 
Retained
 
(Loss) Income,
 
Noncontrolling
 
Total
 
Shares
 
Stock
 
Capital
 
Earnings
 
Net
 
Interests
 
Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, January 1, 2009
75
 
 
$
 
 
$
5,455
 
 
$
5,631
 
 
$
(879
)
 
$
270
 
 
$
10,477
 
Net income
 
 
 
 
 
 
864
 
 
 
 
24
 
 
888
 
Other comprehensive income
 
 
 
 
 
 
 
 
1,182
 
 
 
 
1,182
 
Stock-based compensation
 
 
 
 
123
 
 
 
 
 
 
 
 
123
 
Exercise of common
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
stock options
1
 
 
 
 
25
 
 
 
 
 
 
 
 
25
 
Common stock purchases
(1
)
 
 
 
(148
)
 
 
 
 
 
 
 
(148
)
Contributions
 
 
 
 
 
 
 
 
 
 
23
 
 
23
 
Distributions
 
 
 
 
 
 
 
 
 
 
(53
)
 
(53
)
Other equity transactions
 
 
 
 
(2
)
 
 
 
 
 
13
 
 
11
 
Balance, September 30, 2009
75
 
 
$
 
 
$
5,453
 
 
$
6,495
 
 
$
303
 
 
$
277
 
 
$
12,528
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, January 1, 2010
75
 
 
$
 
 
$
5,453
 
 
$
6,788
 
 
$
335
 
 
$
267
 
 
$
12,843
 
Deconsolidation of Bridger Coal
 
 
 
 
 
 
 
 
 
 
(84
)
 
(84
)
Net income
 
 
 
 
 
 
859
 
 
 
 
100
 
 
959
 
Other comprehensive loss
 
 
 
 
 
 
 
 
(192
)
 
 
 
(192
)
Common stock purchases
 
 
 
 
(9
)
 
(47
)
 
 
 
 
 
(56
)
Distributions
 
 
 
 
 
 
 
 
 
 
(19
)
 
(19
)
Other equity transactions
 
 
 
 
(5
)
 
 
 
 
 
(36
)
 
(41
)
Balance, September 30, 2010
75
 
 
$
 
 
$
5,439
 
 
$
7,600
 
 
$
143
 
 
$
228
 
 
$
13,410
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 

8

 

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)
 
 
Three-Month Periods
Ended September 30,
 
Nine-Month Periods
Ended September 30,
 
2010
 
2009
 
2010
 
2009
 
 
 
 
 
 
 
 
Net income
$
372
 
 
$
388
 
 
$
959
 
 
$
888
 
 
 
 
 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
 
 
 
Unrecognized amounts on retirement benefits, net of
 
 
 
 
 
 
 
tax of $-, $6, $18 and $(8)
(23
)
 
13
 
 
23
 
 
(24
)
Foreign currency translation adjustment
123
 
 
(73
)
 
(86
)
 
231
 
Fair value adjustment on cash flow hedges, net of
 
 
 
 
 
 
 
tax of $(14), $3, $(12) and $(5)
(21
)
 
7
 
 
(18
)
 
(6
)
Unrealized gains (losses) on marketable securities, net of
 
 
 
 
 
 
 
tax of $51, $651, $(73) and $653
77
 
 
978
 
 
(111
)
 
981
 
Total other comprehensive income (loss), net of tax
156
 
 
925
 
 
(192
)
 
1,182
 
 
 
 
 
 
 
 
 
 
Comprehensive income
528
 
 
1,313
 
 
767
 
 
2,070
 
Comprehensive income attributable to noncontrolling
 
 
 
 
 
 
 
interests
8
 
 
12
 
 
100
 
 
24
 
Comprehensive income attributable to MEHC
$
520
 
 
$
1,301
 
 
$
667
 
 
$
2,046
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 

9

 

MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 
(1)    
General
 
MidAmerican Energy Holdings Company ("MEHC") is a holding company that owns subsidiaries principally engaged in energy businesses (collectively with its subsidiaries, the "Company"). MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). The balance of MEHC's common stock is owned by Mr. Walter Scott, Jr. (along with family members and related entities), a member of MEHC's Board of Directors, and Mr. Gregory E. Abel, a member of MEHC's Board of Directors and MEHC's President and Chief Executive Officer. As of September 30, 2010, Berkshire Hathaway, Mr. Scott (along with family members and related entities) and Mr. Abel owned 89.8%, 9.4% and 0.8%, respectively, of MEHC's voting common stock.
 
The Company is organized and managed as eight distinct platforms: PacifiCorp, MidAmerican Funding, LLC ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), Northern Natural Gas Company ("Northern Natural Gas"), Kern River Gas Transmission Company ("Kern River"), CE Electric UK Funding Company ("CE Electric UK") (which primarily consists of Northern Electric Distribution Limited ("Northern Electric") and Yorkshire Electricity Distribution plc ("Yorkshire Electricity")), CalEnergy Philippines (which owns a majority interest in the Casecnan project in the Philippines), CalEnergy U.S. (which owns interests in independent power projects in the United States), and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). Through these platforms, MEHC owns and operates an electric utility company in the Western United States, an electric and natural gas utility company in the Midwestern United States, two interstate natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of independent power projects and the second largest residential real estate brokerage firm in the United States.
 
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the Consolidated Financial Statements as of September 30, 2010 and for the three- and nine-month periods ended September 30, 2010 and 2009. The results of operations for the three- and nine-month periods ended September 30, 2010 are not necessarily indicative of the results to be expected for the full year.
 
The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2009 describes the most significant accounting policies used in the preparation of the Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2010.
 
(2)    
New Accounting Pronouncements
 
In January 2010, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2010-06 ("ASU No. 2010-06"), which amends FASB Accounting Standards Codification ("ASC") Topic 820, "Fair Value Measurements and Disclosures." ASU No. 2010-06 requires disclosure of (a) the amount of significant transfers into and out of Levels 1 and 2 of the fair value hierarchy and the reasons for those transfers and (b) gross presentation of purchases, sales, issuances and settlements in the Level 3 fair value measurement rollforward. This guidance clarifies that existing fair value measurement disclosures should be presented for each class of assets and liabilities. The existing disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements have also been clarified to ensure such disclosures are presented for the Levels 2 and 3 fair value measurements. The Company adopted this guidance as of January 1, 2010, with the exception of the disclosure requirement to present purchases, sales, issuances and settlements gross in the Level 3 fair value measurement rollforward, which is effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.

10

 

 
In June 2009, the FASB issued authoritative guidance (which was codified into ASC Topic 810, "Consolidation," with the issuance of ASU No. 2009-17) that requires a primarily qualitative analysis to determine if an enterprise is the primary beneficiary of a variable interest entity. This analysis is based on whether the enterprise has (a) the power to direct the activities of the variable interest entity that most significantly impact the entity's economic performance and (b) the obligation to absorb losses of the entity or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. In addition, enterprises are required to more frequently reassess whether an entity is a variable interest entity and whether the enterprise is the primary beneficiary of the variable interest entity. Finally, the guidance for consolidation or deconsolidation of a variable interest entity is amended and disclosure requirements about an enterprise's involvement with a variable interest entity are enhanced. The Company adopted this guidance as of January 1, 2010 on a prospective basis. As a result, PacifiCorp's coal mining joint venture, Bridger Coal Company ("Bridger Coal"), was deconsolidated and is being accounted for under the equity method of accounting as the power to direct the activities that most significantly impact Bridger Coal's economic performance are shared with the joint venture partner. The deconsolidation of Bridger Coal resulted in a decrease in assets, liabilities and noncontrolling interest equity as of January 1, 2010 of $192 million, $108 million and $84 million, respectively.
 
(3)    
Property, Plant and Equipment, Net
 
Property, plant and equipment, net consists of the following (in millions):
 
 
 
As of
 
Depreciable
Life
 
September 30,
2010
 
December 31,
2009
 
 
 
 
 
 
Regulated assets:
 
 
 
 
 
Utility generation, distribution and transmission system
5-85 years
 
$
36,322
 
 
$
35,616
 
Interstate pipeline assets
3-67 years
 
5,880
 
 
5,809
 
 
 
 
42,202
 
 
41,425
 
Accumulated depreciation and amortization
 
 
(13,581
)
 
(13,336
)
Regulated assets, net
 
 
28,621
 
 
28,089
 
 
 
 
 
 
 
 
 
Nonregulated assets:
 
 
 
 
 
 
 
Independent power plants
10-30 years
 
678
 
 
677
 
Other assets
3-30 years
 
417
 
 
480
 
 
 
 
1,095
 
 
1,157
 
Accumulated depreciation and amortization
 
 
(480
)
 
(462
)
Nonregulated assets, net
 
 
615
 
 
695
 
 
 
 
 
 
 
 
 
Net operating assets
 
 
29,236
 
 
28,784
 
Construction in progress
 
 
2,233
 
 
2,152
 
Property, plant and equipment, net
 
 
$
31,469
 
 
$
30,936
 
 
Substantially all of the construction in progress as of September 30, 2010 and December 31, 2009 relates to the construction of regulated assets.

11

 

 
(4)    
Regulatory Matters
 
The following are updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2009.
 
Rate Matters
 
Kern River Rate Case
 
In January 2009, the Federal Energy Regulatory Commission ("FERC") ordered Kern River to file compliance rates based on an allowed return on equity of 11.55%. Kern River made the initial compliance filing in March 2009, and a revised filing in September 2009. A request for rehearing of the FERC's January 2009 order, as well as comments and protests on Kern River's March 2009 and September 2009 compliance filings, were timely filed. In December 2009, the FERC issued an order establishing rates for the period of Kern River's current long-term contracts ("Period One rates"), and affirmed its prior opinion with regard to Kern River's allowed return, while requiring that rates be levelized for shippers that elect to continue to take service following the expiration of their current contracts ("Period Two rates"). The FERC set all other issues related to Period Two rates for settlement processes, and a hearing should settlement processes fail. Kern River made a compliance filing conforming its Period One rates to the FERC's order in January 2010 and filed illustrative Period Two rates in February 2010 as required by the FERC's order. Also in January 2010, Kern River filed a request for rehearing of the FERC's December 2009 order and filed in the United States Court of Appeals for the District of Columbia Circuit ("DC Circuit") a request for review of the rulings in the FERC's December 2009 order. In March 2010, Kern River sought and was granted the FERC's authority to issue provisional refunds to its shippers subject to its right of recoupment, if necessary, based on the final rulings in the matter. Also in March 2010, the settlement discussions ordered by the FERC regarding Period Two rates reached an impasse and were terminated. Discovery commenced under a contested case procedural schedule and Kern River filed testimony in June and September 2010. Also in June 2010, the DC Circuit dismissed Kern River's request for review without prejudice to its ability to re-file when all the proceedings at the FERC, including those related to Period Two rates, are concluded. Also in September 2010, Kern River filed with the FERC regarding Period One rates a motion for clarification related to recovery of certain regulatory assets and a tariff filing for a periodic rate adjustment, which will not be necessary if the requested clarification is granted. Final testimony in the Period Two rates phase of the proceeding was filed in October 2010. Formal hearings for Period Two rates are scheduled to commence in December 2010.
 
Oregon Senate Bill 408
 
Oregon Senate Bill 408 ("SB 408") requires PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers to file an annual report each October with the Oregon Public Utility Commission ("OPUC") comparing income taxes collected and income taxes paid, as defined by the statute and its administrative rules. If after its review, the OPUC determines the amount of income taxes collected differs from the amount of income taxes paid by more than $100,000, the OPUC must require the public utility to establish an automatic adjustment clause to account for the difference.
 
The OPUC's April 2008 order approving the recovery of $35 million, plus interest, related to PacifiCorp's 2006 tax report is being challenged by the Industrial Customers of Northwest Utilities, which has petitioned the Oregon Court of Appeals for judicial review of, among other things, the application of certain administrative rules considered in the April 2008 order. In July 2010, the Oregon Court of Appeals held oral arguments on the matter. A decision is not expected until 2011, which could impact PacifiCorp's 2006 through 2009 tax reports filed under SB 408. PacifiCorp believes the outcome of these proceedings will not have a material impact on its consolidated financial results. The $35 million, plus interest, was previously recorded in earnings.
 
In October 2009, PacifiCorp filed for a surcharge of $38 million in its 2008 tax report under SB 408. In January 2010, PacifiCorp entered into a stipulation with OPUC staff and the Citizens' Utility Board of Oregon, agreeing to a lower surcharge totaling $2 million, including interest. In April 2010, the OPUC issued an order adopting the stipulation in its entirety, at which time PacifiCorp recorded the $2 million in earnings.
 
In October 2010, PacifiCorp filed for a surcharge of $29 million, plus interest, in its 2009 tax report under SB 408. No amounts have been recorded in relation to the 2009 tax report.
 

12

 

(5)    
Fair Value Measurements
 
The carrying value of the Company's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
 
•    
Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
 
•    
Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
 
•    
Level 3 — Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.
 
The following table presents the Company's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
 
 
Input Levels for Fair Value Measurements
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other(1)
 
Total
As of September 30, 2010
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
5
 
 
$
422
 
 
$
32
 
 
$
(254
)
 
$
205
 
Investments in available-for-sale securities:
 
 
 
 
 
 
 
 
 
 
 
Money market mutual funds(2)
 
378
 
 
 
 
 
 
 
 
378
 
Debt securities
 
86
 
 
41
 
 
41
 
 
 
 
168
 
Equity securities
 
2,026
 
 
 
 
 
 
 
 
2,026
 
Investments in trading securities - Equity
 
9
 
 
 
 
 
 
 
 
9
 
 
 
$
2,504
 
 
$
463
 
 
$
73
 
 
$
(254
)
 
$
2,786
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
(19
)
 
$
(693
)
 
$
(359
)
 
$
399
 
 
$
(672
)
 
As of December 31, 2009
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
3
 
 
$
318
 
 
$
36
 
 
$
(169
)
 
$
188
 
Investments in available-for-sale securities:
 
 
 
 
 
 
 
 
 
 
Money market mutual funds(2)
 
376
 
 
 
 
 
 
 
 
376
 
Debt securities
 
70
 
 
79
 
 
46
 
 
 
 
195
 
Equity securities
 
2,230
 
 
8
 
 
 
 
 
 
2,238
 
 
 
$
2,679
 
 
$
405
 
 
$
82
 
 
$
(169
)
 
$
2,997
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
(5
)
 
$
(395
)
 
$
(395
)
 
$
218
 
 
$
(577
)
Interest rate derivative
 
 
 
(4
)
 
 
 
 
 
(4
)
 
 
$
(5
)
 
$
(399
)
 
$
(395
)
 
$
218
 
 
$
(581
)
 
(1)    
Represents netting under master netting arrangements and a net cash collateral receivable of $145 million and $49 million as of September 30, 2010 and December 31, 2009, respectively.

13

 

(2)    
Amounts are included in cash and cash equivalents; current investments and restricted cash and investments; and noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.
 
When available, the fair value of derivative contracts is determined using unadjusted quoted prices for identical contracts on the applicable exchange in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves derived from market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on significant unobservable inputs. Refer to Note 6 for further discussion regarding the Company's risk management and hedging activities.
 
The Company's investments in money market mutual funds and debt and equity securities are accounted for as either available-for-sale or trading securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics. The fair value of the Company's investments in auction rate securities, where there is no current liquid market, is determined using pricing models based on available observable market data and the Company's judgment about the assumptions, including liquidity and nonperformance risks, which market participants would use when pricing the asset.
 
The following table reconciles the beginning and ending balances of the Company's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
 
Three-Month Period
Ended September 30, 2010
 
Three-Month Period
Ended September 30, 2009
 
Commodity
Derivatives
 
Debt
Securities
 
Commodity
Derivatives
 
Debt
Securities
 
 
 
 
 
 
 
 
Beginning balance
$
(390
)
 
$
41
 
 
$
(360
)
 
$
38
 
Changes included in earnings(1)
10
 
 
 
 
(3
)
 
 
Changes in fair value recognized in other
 
 
 
 
 
 
 
comprehensive income
 
 
 
 
(1
)
 
2
 
Changes in fair value recognized in net regulatory assets
14
 
 
 
 
(2
)
 
 
Purchases, sales, issuances and settlements
36
 
 
 
 
33
 
 
 
Net transfers (to) from Level 2
3
 
 
 
 
 
 
 
Ending balance
$
(327
)
 
$
41
 
 
$
(333
)
 
$
40
 
 
Nine-Month Period
Ended September 30, 2010
 
Nine-Month Period
Ended September 30, 2009
 
Commodity
Derivatives
 
Debt
Securities
 
Commodity
Derivatives
 
Debt
Securities
 
 
 
 
 
 
 
 
Beginning balance
$
(359
)
 
$
46
 
 
$
(369
)
 
$
37
 
Changes included in earnings(1)
15
 
 
 
 
16
 
 
 
Changes in fair value recognized in other
 
 
 
 
 
 
 
comprehensive income
 
 
(5
)
 
 
 
3
 
Changes in fair value recognized in net regulatory assets
(35
)
 
 
 
32
 
 
 
Purchases, sales, issuances and settlements
49
 
 
 
 
11
 
 
 
Net transfers (to) from Level 2
3
 
 
 
 
(23
)
 
 
Ending balance
$
(327
)
 
$
41
 
 
$
(333
)
 
$
40
 

14

 

 
(1)    
Changes included in earnings are reported as operating revenue on the Consolidated Statements of Operations. For commodity derivatives held as of September 30, 2010 and 2009, net unrealized gains (losses) included in earnings for the three-month periods ended September 30, 2010 and 2009 totaled $5 million and $(3) million, respectively, and for the nine-month periods ended September 30, 2010 and 2009 totaled $10 million and $12 million, respectively.
The Company's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of the Company's long-term debt has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt (in millions):
 
As of September 30, 2010
 
As of December 31, 2009
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
 
 
 
 
 
 
 
Long-term debt
$
19,543
 
 
$
22,464
 
 
$
19,752
 
 
$
21,042
 
 
(6)    
Risk Management and Hedging Activities
 
The Company is exposed to the impact of market fluctuations in commodity prices, interest rates and foreign currency exchange rates. The Company is principally exposed to electricity and natural gas commodity price risk through MEHC's ownership of PacifiCorp and MidAmerican Energy (the "Utilities") as they have an obligation to serve retail customer load in their regulated service territories. MidAmerican Energy also provides nonregulated retail natural gas and electricity services in competitive markets. The Utilities' load and generation assets represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity, wholesale electricity that is purchased and sold and natural gas supply for regulated and nonregulated retail customers. Electricity and natural gas prices are subject to wide price swings as supply and demand for these commodities are impacted by, among many other unpredictable items, changing weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt, commercial paper and future debt issuances. Additionally, the Company is exposed to foreign currency exchange rate risk from its business operations and investments in Great Britain. The Company does not engage in a material amount of proprietary trading activities.
 
Each of the Company's business platforms has established a risk management process that is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business. To mitigate a portion of its commodity risk, the Company uses commodity derivative contracts, including forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company manages its interest rate risk by limiting its exposure to variable interest rates and by monitoring market changes in interest rates. The Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate the Company's exposure to interest rate risk. The Company does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
 
There have been no significant changes in the Company's accounting policies related to derivatives. Refer to Note 5 for additional information on derivative contracts.
 

15

 

The following table, which excludes contracts that qualify for the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of the Company's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
 
Derivative Assets
 
Derivative Liabilities 
 
 
 
Current
 
Noncurrent
 
Current
 
Noncurrent
 
Total
As of September 30, 2010
 
 
 
 
 
 
 
 
 
Not Designated as Hedging Contracts(1)(2):
 
 
 
 
 
 
 
 
 
Commodity assets
$
280
 
 
$
43
 
 
$
44
 
 
$
69
 
 
$
436
 
Commodity liabilities
(82
)
 
(12
)
 
(300
)
 
(529
)
 
(923
)
Total
198
 
 
31
 
 
(256
)
 
(460
)
 
(487
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Designated as Hedging Contracts(1):
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity assets
12
 
 
 
 
6
 
 
5
 
 
23
 
Commodity liabilities
(3
)
 
 
 
(76
)
 
(69
)
 
(148
)
Total
9
 
 
 
 
(70
)
 
(64
)
 
(125
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total derivatives
207
 
 
31
 
 
(326
)
 
(524
)
 
(612
)
Cash collateral (payable) receivable
(32
)
 
(1
)
 
122
 
 
56
 
 
145
 
Total derivatives - net basis
$
175
 
 
$
30
 
 
$
(204
)
 
$
(468
)
 
$
(467
)
 
As of December 31, 2009
 
 
 
 
 
 
 
 
 
Not Designated as Hedging Contracts(1)(2):
 
 
 
 
 
 
 
 
 
Commodity assets
$
219
 
 
$
70
 
 
$
22
 
 
$
31
 
 
$
342
 
Commodity liabilities
(30
)
 
(17
)
 
(171
)
 
(476
)
 
(694
)
Interest rate liability
 
 
 
 
 
 
(4
)
 
(4
)
Total
189
 
 
53
 
 
(149
)
 
(449
)
 
(356
)
 
 
 
 
 
 
 
 
 
 
Designated as Hedging Contracts(1):
 
 
 
 
 
 
 
 
 
Commodity assets
5
 
 
 
 
7
 
 
3
 
 
15
 
Commodity liabilities
(4
)
 
 
 
(53
)
 
(44
)
 
(101
)
Total
1
 
 
 
 
(46
)
 
(41
)
 
(86
)
 
 
 
 
 
 
 
 
 
 
Total derivatives
190
 
 
53
 
 
(195
)
 
(490
)
 
(442
)
Cash collateral (payable) receivable
(54
)
 
(1
)
 
72
 
 
32
 
 
49
 
Total derivatives - net basis
$
136
 
 
$
52
 
 
$
(123
)
 
$
(458
)
 
$
(393
)
 
(1)    
Derivative contracts within these categories subject to master netting arrangements are presented on a net basis on the Consolidated Balance Sheets.
(2)    
The Company's commodity derivatives not designated as hedging contracts are generally included in regulated rates, and as of September 30, 2010 and December 31, 2009, a net regulatory asset of $483 million and $353 million, respectively, was recorded related to the net derivative liability of $487 million and $352 million, respectively.
 

16

 

Not Designated as Hedging Contracts
 
For the Company's commodity derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as net regulatory assets. The following table reconciles the beginning and ending balances of the Company's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2010
 
2009
 
2010
 
2009
 
 
 
 
 
 
 
 
Beginning balance
$
479
 
 
$
247
 
 
$
353
 
 
$
446
 
Changes in fair value recognized in net regulatory assets
31
 
 
15
 
 
102
 
 
(182
)
Net gains reclassified to earnings - operating revenue
10
 
 
74
 
 
59
 
 
243
 
Net losses reclassified to earnings - cost of sales
(37
)
 
(91
)
 
(31
)
 
(262
)
Ending balance
$
483
 
 
$
245
 
 
$
483
 
 
$
245
 
 
For the Company's derivatives not designated as hedging contracts and for which changes in fair value are not recorded as a net regulatory asset or liability, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for sales contracts, cost of sales and operating expense for purchase contracts and electricity and natural gas swap contracts and interest expense for the interest rate derivative. The following table summarizes the pre-tax gains (losses) included on the Consolidated Statements of Operations associated with the Company's derivative contracts not designated as hedging contracts and not recorded as a net regulatory asset or liability (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2010
 
2009
 
2010
 
2009
Commodity derivatives:
 
 
 
 
 
 
 
Operating revenue
$
10
 
 
$
(2
)
 
$
22
 
 
$
22
 
Cost of sales
(11
)
 
6
 
 
(24
)
 
(5
)
Operating expense
 
 
(1
)
 
(1
)
 
 
Interest rate derivative - interest expense
 
 
 
 
4
 
 
 
Total
$
(1
)
 
$
3
 
 
$
1
 
 
$
17
 
 
Designated as Hedging Contracts
 
The Company uses derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices for delivery to nonregulated customers, spring operational sales, natural gas storage and other transactions. The Company's derivative contracts designated as fair value hedges were not significant.
 

17

 

The following table reconciles the beginning and ending balances of the Company's accumulated other comprehensive loss (pre-tax) and summarizes pre-tax gains and losses on derivative contracts designated and qualifying as cash flow hedges recognized in other comprehensive income ("OCI"), as well as amounts reclassified to earnings (in millions):
 
Three-Month Periods Ended September 30,
 
2010
 
2009
 
Commodity
Derivatives
 
Commodity
Derivatives
 
Interest Rate
Derivative
 
Total(1)
 
 
 
 
 
 
 
 
Beginning balance
$
76
 
 
$
104
 
 
$
4
 
 
$
108
 
Net losses recognized in OCI
36
 
 
34
 
 
 
 
34
 
Net losses reclassified to earnings - revenue
(1
)
 
(1
)
 
 
 
(1
)
Net losses reclassified to earnings - cost of sales
 
 
(30
)
 
 
 
(30
)
Ending balance
$
111
 
 
$
107
 
 
$
4
 
 
$
111
 
 
 
Nine-Month Periods Ended September 30,
 
2010
 
2009
 
Commodity
Derivatives
 
Commodity
Derivatives
 
Interest Rate
Derivative
 
Total(1)
 
 
 
 
 
 
 
 
Beginning balance
$
81
 
 
$
83
 
 
$
6
 
 
$
89
 
Net losses (gains) recognized in OCI
54
 
 
109
 
 
(2
)
 
107
 
Net gains (losses) reclassified to earnings - revenue
4
 
 
(2
)
 
 
 
(2
)
Net losses reclassified to earnings - cost of sales
(28
)
 
(83
)
 
 
 
(83
)
Ending balance
$
111
 
 
$
107
 
 
$
4
 
 
$
111
 
 
(1)    
Certain derivative contracts, principally interest rate locks, have settled and the fair value at the date of settlement remains in accumulated other comprehensive income ("AOCI") and is recognized in earnings when the forecasted transactions impact earnings.
 
Realized gains and losses on all hedges and hedge ineffectiveness are recognized in income as operating revenue, cost of sales, operating expense or interest expense depending upon the nature of the item being hedged. For the three- and nine-month periods ended September 30, 2010 and 2009, hedge ineffectiveness was insignificant. As of September 30, 2010, the Company had cash flow hedges with expiration dates extending through December 2022 and $40 million of pre-tax net unrealized losses are forecasted to be reclassified from AOCI into earnings over the next twelve months as contracts settle.
 
Derivative Contract Volumes
 
The following table summarizes the net notional amounts of outstanding derivative contracts with fixed price terms that comprise the mark-to-market values as of September 30 (in millions):
 
Unit of Measure
 
2010
 
2009
Commodity contracts:
 
 
 
 
 
Electricity sales
Megawatt hours
 
(12
)
 
(20
)
Natural gas purchases
Decatherms
 
242
 
 
262
 
Fuel purchases
Gallons
 
9
 
 
4
 
Interest rate derivative — variable to fixed swap
Australian dollars
 
 
 
59
 
 

18

 

Credit Risk
 
The Utilities extend unsecured credit to other utilities, energy marketers, financial institutions and other market participants in conjunction with wholesale energy supply and marketing activities. Credit risk relates to the risk of loss that might occur as a result of nonperformance by counterparties on 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 the counterparty.
 
The Utilities analyze the financial condition of each significant wholesale 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 an ongoing basis. To mitigate exposure to the financial risks of wholesale counterparties, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed interest fees for delayed payments. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.
 
MidAmerican Energy also has potential indirect credit exposure to other market participants in the regional transmission organization ("RTO") markets where it actively participates, including the Midwest Independent Transmission System Operator, Inc., the PJM Interconnection, L.L.C., and the Electric Reliability Council of Texas. In the event of a default by a RTO market participant on its market-related obligations, losses are allocated among all other market participants in proportion to each participant's share of overall market activity during the period of time the loss was incurred. Transactional activities of MidAmerican Energy and other participants in organized RTO markets are governed by credit policies specified in each respective RTO's governing tariff or related business practices. Credit policies of RTO's, which have been developed through extensive stakeholder participation, generally seek to minimize potential loss in the event of a market participant default without unnecessarily inhibiting access to the marketplace. MidAmerican Energy's share of historical losses from defaults by other RTO market participants has not been material. 
 
Collateral and Contingent Features
 
In accordance with industry practice, certain derivative contracts contain provisions that require MEHC's subsidiaries, principally the Utilities, to maintain specific credit ratings from one or more of the major credit rating agencies on their unsecured debt. These derivative contracts may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" in the event of a material adverse change in the subsidiary's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2010, these subsidiary's credit ratings from the three recognized credit rating agencies were investment grade.
 
The aggregate fair value of the Company's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $741 million and $473 million as of September 30, 2010 and December 31, 2009, respectively, for which the Company had posted collateral of $174 million and $99 million, respectively. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2010 and December 31, 2009, the Company would have been required to post $304 million and $237 million, respectively, of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
 

19

 

(7)    
Investments and Restricted Cash and Investments
 
Investments and restricted cash and investments consists of the following (in millions):
 
As of
 
September 30,
2010
 
December 31,
2009
Investments:
 
 
 
BYD common stock
$
1,808
 
 
$
1,986
 
Rabbi trusts
273
 
 
268
 
Other
101
 
 
97
 
Total investments
2,182
 
 
2,351
 
 
 
 
 
 
 
Restricted cash and investments:
 
 
 
 
 
Nuclear decommissioning trust funds
278
 
 
264
 
Mine reclamation trust funds
 
 
79
 
Other
105
 
 
91
 
Total restricted cash and investments
383
 
 
434
 
 
 
 
 
 
 
Total investments and restricted cash and investments
2,565
 
 
2,785
 
Less current portion
(101
)
 
(83
)
Noncurrent portion
$
2,464
 
 
$
2,702
 
 
MEHC's investment in BYD Company Limited ("BYD") common stock is accounted for as an available-for-sale security with changes in fair value recognized in AOCI. As of September 30, 2010 and December 31, 2009, the fair value of MEHC's investment in BYD common stock was $1.808 billion and $1.986 billion, respectively, which resulted in a pre-tax unrealized gain of $1.576 billion and $1.754 billion as of September 30, 2010 and December 31, 2009, respectively.
 
During 2009, the Company sold 19.9 million shares of Constellation Energy Group, Inc. ("Constellation Energy") common stock for $536 million, or an average price of $26.93 per share. For the nine-month period ended September 30, 2009, the Company recognized pre-tax gains on Constellation Energy common stock totaling $37 million, which are included in other, net on the Consolidated Statements of Operations. 
 
The Company's restricted cash and investments are related to (a) the Company's debt service reserve requirements for certain projects, (b) funds held in trust for nuclear decommissioning and coal mine reclamation and (c) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project. Effective January 1, 2010, the Company deconsolidated Bridger Coal. Refer to Note 2 for further discussion.
 
(8)    
Recent Debt Transactions
 
In July 2010, MEHC called and repaid at par value $92 million of 6.25% CalEnergy Capital Trust II subordinated debt due in February 2012.
 
In July 2010, Yorkshire Electricity closed on a £151 million finance contract with the European Investment Bank and issued £151 million of 4.13% notes due July 20, 2022. The net proceeds are being used to fund capital expenditures. Also in July 2010, Northern Electric closed on a £119 million finance contract with the European Investment Bank. Amounts available under the finance contract may be drawn upon through 2011.
 
In March 2010, CE Electric UK replaced its expiring £100 million unsecured credit facility with a £150 million unsecured credit facility expiring in March 2013. The £150 million credit facility has substantially the same covenant terms as the expired £100 million credit facility.
 

20

 

(9)    
Related Party Transactions
 
As of September 30, 2010 and December 31, 2009, Berkshire Hathaway and its affiliates held 11% mandatory redeemable preferred securities due from certain wholly-owned subsidiary trusts of MEHC of $186 million and $353 million, respectively. Interest expense on these securities totaled $7 million and $13 million for the three-month periods ended September 30, 2010 and 2009, respectively, and $25 million and $47 million for the nine-month periods ended September 30, 2010 and 2009, respectively. Accrued interest totaled $4 million and $8 million as of September 30, 2010 and December 31, 2009, respectively.
 
For the nine-month periods ended September 30, 2010 and 2009, the Company received net cash payments for income taxes from Berkshire Hathaway totaling $132 million and $178 million, respectively.
 
(10)    
Employee Benefit Plans
 
Domestic Operations
 
Net periodic benefit cost for the domestic pension and other postretirement benefit plans included the following components (in millions):
 
Three-Month Periods
Ended September 30,
 
Nine-Month Periods
Ended September 30,
 
2010
 
2009
 
2010
 
2009
Pension:
 
 
 
 
 
 
 
Service cost
$
8
 
 
$
9
 
 
$
22
 
 
$
26
 
Interest cost
25
 
 
29
 
 
78
 
 
85
 
Expected return on plan assets
(29
)
 
(29
)
 
(86
)
 
(85
)
Net amortization
3
 
 
1
 
 
10
 
 
1
 
Net periodic benefit cost
$
7
 
 
$
10
 
 
$
24
 
 
$
27
 
 
 
 
 
 
 
 
 
Other Postretirement:
 
 
 
 
 
 
 
Service cost
$
2
 
 
$
2
 
 
$
7
 
 
$
6
 
Interest cost
10
 
 
12
 
 
31
 
 
33
 
Expected return on plan assets
(11
)
 
(11
)
 
(32
)
 
(30
)
Net amortization
5
 
 
3
 
 
11
 
 
9
 
Net periodic benefit cost
$
6
 
 
$
6
 
 
$
17
 
 
$
18
 
 
Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $143 million and $27 million, respectively, during 2010. As of September 30, 2010, $138 million and $19 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.
 
In March 2010, the President signed into law healthcare reform legislation that included provisions to eliminate the tax deductibility of other postretirement costs to the extent of retiree drug subsidies received from the federal government beginning after December 31, 2012. Accordingly, the Company increased deferred income tax liabilities and, consistent with the expectation that such additional income tax expense amounts are probable of inclusion in regulated rates, recorded a $53 million increase to net regulatory assets.
 

21

 

United Kingdom Operations
 
Net periodic benefit cost for the UK pension plan included the following components (in millions):
 
 
Three-Month Periods
Ended September 30,
 
Nine-Month Periods
Ended September 30,
 
2010
 
2009
 
2010
 
2009
 
 
 
 
 
 
 
 
Service cost
$
5
 
 
$
3
 
 
$
12
 
 
$
9
 
Interest cost
22
 
 
22
 
 
66
 
 
62
 
Expected return on plan assets
(26
)
 
(27
)
 
(76
)
 
(77
)
Net amortization
7
 
 
4
 
 
22
 
 
11
 
Net periodic benefit cost
$
8
 
 
$
2
 
 
$
24
 
 
$
5
 
 
Employer contributions to the UK pension plan are expected to be £45 million during 2010. As of September 30, 2010, £34 million, or $51 million, of contributions had been made to the UK pension plan.
 
(11)    
Income Taxes
 
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
 
Three-Month Periods
Ended September 30,
 
Nine-Month Periods
Ended September 30,
 
2010
 
2009
 
2010
 
2009
 
 
 
 
 
 
 
 
Federal statutory income tax rate
35
 %
 
35
 %
 
35
 %
 
35
 %
Federal and state income tax credits
(14
)
 
(8
)
 
(11
)
 
(9
)
State income tax, net of federal income tax benefit
4
 
 
 
 
3
 
 
1
 
Change in United Kingdom corporate income tax rate
(6
)
 
 
 
(2
)
 
 
Tax free gain on sale of business
(4
)
 
 
 
(1
)
 
 
Effects of ratemaking
(4
)
 
(1
)
 
(3
)
 
(1
)
Tax effect of foreign income
(2
)
 
1
 
 
(3
)
 
(1
)
Tax method change
 
 
(14
)
 
(1
)
 
(5
)
CE Casecnan noncontrolling interest verdict
 
 
 
 
(2
)
 
 
Other, net
1
 
 
(3
)
 
 
 
 
Effective income tax rate
10
 %
 
10
 %
 
15
 %
 
20
 %
 
Federal and state income tax credits primarily relate to production tax credits at the Utilities. The Utilities' wind-powered generating facilities are eligible for federal renewable electricity production tax credits for 10 years from the date that the facilities were placed in-service.
 
In July 2010, the Company recognized $25 million of deferred income tax benefits upon the enactment of the reduction in the United Kingdom corporate income tax rate from 28% to 27% to be effective April 1, 2011.
 
In September 2010, the Company sold its interest in CE Gas (Australia) Limited and recognized a tax free gain of $45 million during the three- and nine-month periods ended September 30, 2010.
 

22

 

The Utilities changed the method by which they determine current income tax deductions for repairs on certain of their regulated utility assets (the "repairs deduction"), which results in current deductibility for certain costs that are capitalized for book purposes. The Utilities were allowed to retroactively apply the method change and take a deduction for prior-year costs on the tax return being prepared at the time of the change. A repairs deduction for MidAmerican Funding's regulated gas utility assets, which was computed for tax years 2004 and forward and deducted on the 2009 income tax return, resulted in the recognition of $7 million of net tax benefits in earnings for the nine-month period ended September 30, 2010. Earnings for the three- and nine-month periods ended September 30, 2009 reflect $55 million of net tax benefits recognized for a repairs deduction related to MidAmerican Funding's regulated electric utility assets, which was computed for tax years 1998 and forward and deducted on the 2008 income tax return. Iowa, MidAmerican Funding's largest jurisdiction for rate regulated operations, requires immediate income recognition of such temporary differences. The ongoing impact of the repairs deduction change, along with other items recognized currently in income tax expense as the result of ratemaking, is reflected in the effects of ratemaking line above.
 
(12)    
Commitments and Contingencies
 
Legal Matters
 
The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.
 
PacifiCorp
 
In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of the Wyoming state opacity standards at PacifiCorp's Jim Bridger generating facility in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger generating facility's Title V permit and are enforceable by private citizens under the federal 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 that is obscured in the flue of a generating facility. The complaint alleged thousands of violations of asserted six-minute compliance periods and sought an injunction ordering the Jim Bridger generating facility's compliance with opacity limits, civil penalties of $32,500 per day per violation and the plaintiffs' costs of litigation. In February 2010, PacifiCorp, the Sierra Club and the Wyoming Outdoor Council reached an agreement in principle to settle all outstanding claims in the action. The settlement was reviewed by the United States Environmental Protection Agency ("EPA") and approved by the court. This matter is now concluded and did not have a material impact on PacifiCorp's consolidated financial results.
  
CalEnergy Philippines
 
In February 2002, pursuant to the share ownership adjustment mechanism in the CE Casecnan Water and Energy Company, Inc. ("CE Casecnan") shareholder agreement, MEHC's indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. ("LPG") that MEHC's indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. In 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco (the "Superior Court"), against CE Casecnan Ltd. and MEHC. 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 Philippine National Irrigation Administration arbitration. In January 2006, the Superior Court entered a judgment in favor of LPG against CE Casecnan Ltd regarding the calculation of the proforma financial projections. Pursuant to the judgment, 15% of the distributions of CE Casecnan were deposited into escrow plus interest at 9% per annum. The judgment was appealed, and as a result of the appellate decision, LPG retained ownership of 10% of the shares of CE Casecnan, with the remaining 5% share to be transferred to CE Casecnan Ltd. subject to certain buy-up rights under the shareholder agreement. The issues relating to the exercise of the buy-up right were decided by the Superior Court and in June 2009, LPG exercised its buy-up rights with respect to the remaining 5% ownership interest. In October 2009, the Superior Court issued a judgment declaring that after the buy up LPG was a 15% shareholder. The judgment was appealed in January 2010 and is expected to conclude in 2011. In July 2010, the Superior Court issued a decision denying the remainder of LPG's claims.
 

23

 

In July 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo Ruiz Builders and Developers Group, Inc. ("San Lorenzo") in the District Court of Douglas County, Nebraska (the "District Court"), seeking a declaratory judgment as to San Lorenzo's right to repurchase up to 15% of the shares in CE Casecnan. In January 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it has effectively exercised its option to purchase up to 15% of the shares of CE Casecnan, that it is the rightful owner of such shares and that it is due all dividends previously paid on such shares. In March 2010, after a two-week jury trial, the District Court declined to submit the claims and defenses in the case to the jury. Instead, the District Court issued a directed verdict in April 2010, which management believes is based in part on the January 2006 findings of the Superior Court in the California litigation involving LPG discussed above. The order finds that San Lorenzo was entitled to be a 15% shareholder of CE Casecnan effective March 30, 2002 and is owed $32 million as of March 31, 2010. The Superior Court subsequently issued an order in the California litigation which management believes contradicts the April 2010 order issued by the District Court. MEHC filed motions to vacate or modify the order of the District Court or to grant a new trial based on errors in the proceeding and in light of the Superior Court order in the California litigation based on the same facts. The District Court denied the motions to vacate and modify its order, and any final ruling is expected to be appealed.
 
As a result of the court's ruling, the Company established a $48 million noncontrolling interest attributable to San Lorenzo in CE Casecnan. The noncontrolling interest established consisted of (1) 15% of CE Casecnan's equity as of March 30, 2002 totaling $17 million; (2) an $83 million charge to net income attributable to noncontrolling interests representing 15% of CE Casecnan's earnings since March 30, 2002; and (3) a $52 million reduction to San Lorenzo's noncontrolling interest for 15% of CE Casecnan's dividends paid since March 30, 2002, which is recorded in other current liabilities on the Consolidated Balance Sheet. The court's ruling resulted in a $59 million after-tax charge to net income attributable to MEHC in March 2010. Depending on the ultimate outcome of the litigation, adjustments to this estimate may be necessary.
 
Environmental Laws and Regulations
 
The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, renewable portfolio standards, climate change, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.
 
Accrued Environmental Costs
 
The Company is fully or partly responsible for environmental remediation at various contaminated sites, including sites that are or were part of the Company's operations and sites owned by third parties. The Company accrues environmental remediation expenses when the expenses are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available site-specific information, site investigation results, expected remediation or settlement timelines, the Company's proportionate responsibility, contractual indemnities and coverage provided by insurance policies. The liability recorded as of September 30, 2010 and December 31, 2009 was $18 million and $21 million, respectively, and is included in other current liabilities and other long-term liabilities on the Consolidated Balance Sheets. Environmental remediation liabilities that separately result from the normal operation of long-lived assets and that are legal obligations associated with the retirement of those assets are separately accounted for as asset retirement obligations.
 
Hydroelectric Relicensing
 
PacifiCorp's hydroelectric portfolio consists of 46 generating facilities with an aggregate facility net owned capacity of 1,157 megawatts ("MW"). The FERC regulates 98% of the net capacity of this portfolio through 16 individual licenses, which typically have terms of 30 to 50 years. PacifiCorp expects to incur ongoing operating and maintenance expense and capital expenditures associated with the terms of its renewed hydroelectric licenses and settlement agreements, including natural resource enhancements. PacifiCorp's Klamath hydroelectric system is currently operating under annual licenses. Substantially all of PacifiCorp's remaining hydroelectric generating facilities are operating under licenses that expire between 2030 and 2058.
 
In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 170-MW Klamath hydroelectric system in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license issued by the FERC and expects to continue operating under annual licenses until the relicensing process is complete or the system's four mainstem dams are removed.
 

24

 

As part of the relicensing process, the FERC is required to perform an environmental review and in November 2007, the FERC issued its final environmental impact statement. The United States Fish and Wildlife Service and the National Marine Fisheries Service issued final biological opinions in December 2007 analyzing the Klamath hydroelectric system's impact on endangered species under a new FERC license consistent with the FERC staff's recommended license alternative and terms and conditions issued by the United States Departments of the Interior and Commerce. These terms and conditions include construction of upstream and downstream fish passage facilities at the Klamath hydroelectric system's four mainstem dams. Prior to the FERC issuing a final license, PacifiCorp is required to obtain water quality certifications from Oregon and California. PacifiCorp currently has water quality applications pending in Oregon and California; however, Oregon issued a letter in March 2010, holding the certification process in abeyance during the United States Secretary of the Interior's public interest determination on dam removal, and California issued a resolution in October 2010, holding the certification process in abeyance until May 2011.
 
In November 2008, PacifiCorp signed a non-binding agreement in principle ("AIP") that laid out a framework for the disposition of PacifiCorp's Klamath hydroelectric system relicensing process, including a path toward potential dam transfer and removal by an entity other than PacifiCorp no earlier than 2020. Subsequent to release of the AIP, negotiations between the parties continued with an expanded group of stakeholders. The parties to the Klamath Hydroelectric Settlement Agreement ("KHSA"), which include PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the State of California, the State of Oregon and various other governmental and non-governmental settlement parties, signed the KHSA in February 2010. PacifiCorp expects that federal legislation will be introduced in the United States Congress in 2011 to endorse and enact provisions of the KHSA.
 
Under the terms of the KHSA, the United States Departments of the Interior and Commerce will conduct scientific and engineering studies and consult with state, local and tribal governments and other stakeholders, as appropriate, to determine by March 31, 2012 whether removal of the Klamath hydroelectric system's four mainstem dams will advance restoration of the salmonid fisheries of the Klamath Basin and is in the public interest. This determination will be made by the United States Secretary of the Interior. If it is determined that dam removal should proceed, dam removal is expected to commence no earlier than 2020.
 
Under the KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. For dam removal to occur, federal legislation consistent with the KHSA must be enacted to provide, among other things, protection for PacifiCorp from all liabilities associated with dam removal activities. In addition, the KHSA limits PacifiCorp's contribution to dam removal costs to no more than $200 million, of which up to $184 million would be collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California customers. An additional $250 million for dam removal costs is expected to be raised through a California bond measure. If PacifiCorp's contribution to dam removal costs exceeds $200 million or if the State of California is unable to raise the funds necessary for dam removal costs, sufficient funds would need to be obtained elsewhere in order for the KHSA and dam removal to proceed.
 
Actual removal of a facility would occur only after all permits for removal are obtained and the facility and associated land are transferred to a dam removal entity. Prior to potential removal of a facility, the facility will generally continue to operate as it does currently. However, PacifiCorp is responsible for implementing interim measures to provide additional resource protections, water quality improvements, habitat enhancement for aquatic species and increased funding for hatchery operations in the Klamath River Basin.
 
In July 2009, Oregon's governor signed a bill authorizing PacifiCorp to collect surcharges from its Oregon customers for Oregon's share of the customer contribution for the cost of removing the Klamath hydroelectric system's four mainstem dams. In March 2010, PacifiCorp filed with the OPUC to begin collecting the surcharge from Oregon customers, as of that date, subject to refund based on the OPUC's determination that the surcharges result in rates that are fair, just and reasonable. Also, in March 2010, PacifiCorp filed with the California Public Utilities Commission ("CPUC") to collect a surcharge from PacifiCorp's California customers beginning January 1, 2011. The proceeds from the surcharges will be deposited in trust accounts to be established by each of the respective utility commissions. In September 2010, the OPUC issued an order approving dam removal surcharges for Oregon customers. The CPUC is expected to issue an order on PacifiCorp's California surcharge filing in April 2011.
 

25

 

As of September 30, 2010 and December 31, 2009, PacifiCorp had $73 million and $67 million, respectively, in costs related to the relicensing of the Klamath hydroelectric system included in construction in progress and reflected in property, plant and equipment, net on the Consolidated Balance Sheets. Recovery of relicensing costs is anticipated through traditional rate proceedings. The all-party settlement proposed in the Oregon general rate case recommended recovery of relicensing costs effective January 1, 2011. As of September 30, 2010, PacifiCorp's Klamath hydroelectric system generating facilities had a net book value of $60 million with an average remaining depreciable life of 36 years. In August 2010, PacifiCorp received an order from the OPUC approving a change to depreciation rates for certain of the Klamath hydroelectric system generating facilities. The depreciation rate change will be effective January 1, 2011 and will allow for full depreciation of the assets by December 31, 2019. PacifiCorp has made a similar filing in California and plans to include a similar request in upcoming rate cases in the rest of the states comprising its service territory.
 
Purchase Obligations