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 June 30, 2008
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ______ to _______
Commission | Exact name of registrant as specified in its charter; | IRS Employer | ||
File Number | State or other jurisdiction of incorporation or organization | Identification No. | ||
001-14881 | MIDAMERICAN ENERGY HOLDINGS COMPANY | 94-2213782 | ||
(An Iowa Corporation) | ||||
666 Grand Avenue, Suite 500 | ||||
Des Moines, Iowa 50309-2580 | ||||
515-242-4300 | ||||
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 T No ¨
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 definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨ | Accelerated filer ¨ | Non-accelerated filer T | Smaller reporting company ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ¨ 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 July 31, 2008, 74,859,001 shares of common stock were outstanding.
TABLE OF CONTENTS
PART I - FINANCIAL INFORMATION | ||
PART II - OTHER INFORMATION | ||
2
PART I – FINANCIAL INFORMATION
Financial Statements |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
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 June 30, 2008, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 2008 and 2007, and of shareholders’ equity and cash flows for the six-month periods ended June 30, 2008 and 2007. 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, 2007, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated February 27, 2008, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of 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. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2007, 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
August 8, 2008
3
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of | ||||||||
June 30, | December 31, | |||||||
2008 | 2007 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1,002 | $ | 1,178 | ||||
Trade receivables, net | 1,352 | 1,406 | ||||||
Inventories | 476 | 476 | ||||||
Derivative contracts | 362 | 170 | ||||||
Guaranteed investment contracts | - | 397 | ||||||
Other current assets | 657 | 525 | ||||||
Deferred income taxes | 241 | 162 | ||||||
Total current assets | 4,090 | 4,314 | ||||||
Property, plant and equipment, net | 27,195 | 26,221 | ||||||
Goodwill | 5,336 | 5,339 | ||||||
Regulatory assets | 1,667 | 1,503 | ||||||
Derivative contracts | 377 | 227 | ||||||
Deferred charges, investments and other assets | 1,603 | 1,612 | ||||||
Total assets | $ | 40,268 | $ | 39,216 |
The accompanying notes are an integral part of these financial statements.
4
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
As of | ||||||||
June 30, | December 31, | |||||||
2008 | 2007 | |||||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 967 | $ | 1,063 | ||||
Accrued interest | 337 | 341 | ||||||
Accrued property, income and other taxes | 272 | 230 | ||||||
Derivative contracts | 370 | 266 | ||||||
Other current liabilities | 1,003 | 816 | ||||||
Short-term debt | 63 | 130 | ||||||
Current portion of long-term debt | 1,109 | 1,966 | ||||||
Current portion of MEHC subordinated debt | 234 | 234 | ||||||
Total current liabilities | 4,355 | 5,046 | ||||||
Regulatory liabilities | 1,647 | 1,629 | ||||||
Derivative contracts | 678 | 499 | ||||||
Other long-term liabilities | 1,246 | 1,372 | ||||||
MEHC senior debt | 5,120 | 4,471 | ||||||
MEHC subordinated debt | 826 | 891 | ||||||
Subsidiary and project debt | 12,292 | 12,131 | ||||||
Deferred income taxes | 3,927 | 3,595 | ||||||
Total liabilities | 30,091 | 29,634 | ||||||
Minority interest | 136 | 128 | ||||||
Preferred securities of subsidiaries | 128 | 128 | ||||||
Commitments and contingencies (Notes 4 and 8) | ||||||||
Shareholders’ equity: | ||||||||
Common stock - 115 shares authorized, no par value, 75 shares issued and outstanding | - | - | ||||||
Additional paid-in capital | 5,454 | 5,454 | ||||||
Retained earnings | 4,344 | 3,782 | ||||||
Accumulated other comprehensive income, net | 115 | 90 | ||||||
Total shareholders' equity | 9,913 | 9,326 | ||||||
Total liabilities and shareholders' equity | $ | 40,268 | $ | 39,216 |
The accompanying notes are an integral part of these financial statements.
5
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods | Six-Month Periods | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Operating revenue | $ | 2,992 | $ | 3,003 | $ | 6,348 | $ | 6,227 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Cost of sales | 1,410 | 1,383 | 3,029 | 2,900 | ||||||||||||
Operating expense | 707 | 724 | 1,394 | 1,407 | ||||||||||||
Depreciation and amortization | 292 | 298 | 570 | 584 | ||||||||||||
Total operating costs and expenses | 2,409 | 2,405 | 4,993 | 4,891 | ||||||||||||
Operating income | 583 | 598 | 1,355 | 1,336 | ||||||||||||
Other income (expense): | ||||||||||||||||
Interest expense | (330 | ) | (324 | ) | (658 | ) | (640 | ) | ||||||||
Capitalized interest | 12 | 16 | 23 | 30 | ||||||||||||
Interest and dividend income | 13 | 23 | 31 | 42 | ||||||||||||
Other income | 27 | 29 | 45 | 55 | ||||||||||||
Other expense | (4 | ) | (3 | ) | (5 | ) | (4 | ) | ||||||||
Total other income (expense) | (282 | ) | (259 | ) | (564 | ) | (517 | ) | ||||||||
Income before income tax expense, minority interest and preferred dividends of subsidiaries and equity income | 301 | 339 | 791 | 819 | ||||||||||||
Income tax expense | 82 | 100 | 229 | 260 | ||||||||||||
Minority interest and preferred dividends of subsidiaries | 5 | 5 | 9 | 17 | ||||||||||||
Equity income | (6 | ) | (8 | ) | (9 | ) | (12 | ) | ||||||||
Net income | $ | 220 | $ | 242 | $ | 562 | $ | 554 |
The accompanying notes are an integral part of these financial statements.
6
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)
FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 2008 AND 2007
(Amounts in millions)
Accumulated | ||||||||||||||||||||||||
Outstanding | Additional | Other | ||||||||||||||||||||||
Common | Common | Paid-in | Retained | Comprehensive | ||||||||||||||||||||
Shares | Stock | Capital | Earnings | Income (Loss), Net | Total | |||||||||||||||||||
Balance, January 1, 2007 | 74 | $ | - | $ | 5,420 | $ | 2,598 | $ | (7 | ) | $ | 8,011 | ||||||||||||
Adoption of FASB Interpretation No. 48 | - | - | - | (5 | ) | - | (5 | ) | ||||||||||||||||
Net income | - | - | - | 554 | - | 554 | ||||||||||||||||||
Other comprehensive income | - | - | - | - | 110 | 110 | ||||||||||||||||||
Other equity transactions | - | - | 2 | - | - | 2 | ||||||||||||||||||
Balance, June 30, 2007 | 74 | $ | - | $ | 5,422 | $ | 3,147 | $ | 103 | $ | 8,672 | |||||||||||||
Balance, January 1, 2008 | 75 | $ | - | $ | 5,454 | $ | 3,782 | $ | 90 | $ | 9,326 | |||||||||||||
Net income | - | - | - | 562 | - | 562 | ||||||||||||||||||
Other comprehensive income | - | - | - | - | 25 | 25 | ||||||||||||||||||
Balance, June 30, 2008 | 75 | $ | - | $ | 5,454 | $ | 4,344 | $ | 115 | $ | 9,913 |
The accompanying notes are an integral part of these financial statements.
7
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Six-Month Periods | ||||||||
Ended June 30, | ||||||||
2008 | 2007 | |||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 562 | $ | 554 | ||||
Adjustments to reconcile net income to net cash flows from operations: | ||||||||
Gain on other items, net | - | (15 | ) | |||||
Depreciation and amortization | 570 | 584 | ||||||
Amortization of regulatory assets and liabilities | (43 | ) | (8 | ) | ||||
Provision for deferred income taxes | 272 | 32 | ||||||
Other | 45 | (18 | ) | |||||
Changes in other items: | ||||||||
Trade receivables and other current assets | 112 | 5 | ||||||
Accounts payable and other accrued liabilities | (226 | ) | 278 | |||||
Net cash flows from operating activities | 1,292 | 1,412 | ||||||
Cash flows from investing activities: | ||||||||
Capital expenditures | (1,576 | ) | (1,667 | ) | ||||
Purchases of available-for-sale securities | (126 | ) | (984 | ) | ||||
Proceeds from sale of available-for-sale securities | 128 | 843 | ||||||
Proceeds from maturity of guaranteed investment contract | 393 | - | ||||||
Proceeds from sale of assets | 12 | 33 | ||||||
(Increase) decrease in restricted cash | (3 | ) | 58 | |||||
Other | 7 | 13 | ||||||
Net cash flows from investing activities | (1,165 | ) | (1,704 | ) | ||||
Cash flows from financing activities: | ||||||||
Proceeds from MEHC senior debt | 649 | 547 | ||||||
Repayments of MEHC senior and subordinated debt | (517 | ) | (67 | ) | ||||
Purchases of MEHC senior debt | (99 | ) | - | |||||
Proceeds from subsidiary and project debt | 398 | 1,400 | ||||||
Repayments of subsidiary and project debt | (572 | ) | (217 | ) | ||||
Payment of hedging instruments | (99 | ) | - | |||||
Net repayments of MEHC revolving credit facility | - | (152 | ) | |||||
Net repayments of subsidiary short-term debt | (66 | ) | (370 | ) | ||||
Other | 1 | (17 | ) | |||||
Net cash flows from financing activities | (305 | ) | 1,124 | |||||
Effect of exchange rate changes | 2 | 3 | ||||||
Net change in cash and cash equivalents | (176 | ) | 835 | |||||
Cash and cash equivalents at beginning of period | 1,178 | 343 | ||||||
Cash and cash equivalents at end of period | $ | 1,002 | $ | 1,178 |
The accompanying notes are an integral part of these financial statements.
8
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) | General |
MidAmerican Energy Holdings Company (“MEHC”) is a holding company which owns subsidiaries that are principally engaged in energy businesses. MEHC and its subsidiaries are referred to as the “Company.” MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”). The Company is 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 (owning a majority interest in the Casecnan project), CalEnergy Generation-Domestic (owning interests in independent power projects in the United States) and HomeServices of America, Inc. (collectively with its subsidiaries, “HomeServices”). Through these platforms, the Company owns and operates an electric utility company in the Western United States, a combined 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 financial statements as of June 30, 2008, and for the three- and six-month periods ended June 30, 2008 and 2007. Certain amounts in the prior period Consolidated Financial Statements have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported operating income, net income or retained earnings. The results of operations for the three- and six-month periods ended June 30, 2008 are not necessarily indicative of the results to be expected for the full year.
The unaudited Consolidated Financial Statements include the accounts of MEHC and its subsidiaries in which it holds a controlling financial interest. The Consolidated Statements of Operations include the revenues and expenses of an acquired entity from the date of acquisition. Intercompany accounts and transactions have been eliminated.
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 financial statements and the reported amounts of revenues 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, 2007 describes the most significant accounting estimates and policies used in the preparation of the Consolidated Financial Statements. There have been no significant changes in the Company’s assumptions regarding significant accounting policies during the first six months of 2008.
(2) | New Accounting Pronouncements |
In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand how and why an entity uses derivative instruments and their effects on an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company is currently evaluating the impact of adopting SFAS No. 161 on its disclosures included within the notes to its Consolidated Financial Statements.
9
In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) applies to all transactions or other events in which an entity obtains control of one or more businesses. SFAS No. 141(R) establishes how the acquirer of a business should recognize, measure and disclose in its financial statements the identifiable assets and goodwill acquired, the liabilities assumed and any noncontrolling interest in the acquired business. SFAS No. 141(R) is applied prospectively for all business combinations with an acquisition date on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, with early application prohibited. SFAS No. 141(R) will not have an impact on the Company’s historical Consolidated Financial Statements and will be applied to business combinations completed, if any, on or after January 1, 2009.
In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires entities to report noncontrolling interests as a separate component of shareholders’ equity in the consolidated financial statements. The amount of earnings attributable to the parent and to the noncontrolling interests should be clearly identified and presented on the face of the consolidated statements of operations. Additionally, SFAS No. 160 requires any changes in a parent’s ownership interest of its subsidiary, while retaining its control, to be accounted for as equity transactions. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008 and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting SFAS No. 160 on its consolidated financial position and results of operations.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment of FASB Statement No. 115” (“SFAS No. 159”). SFAS No. 159 permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option may only be made at initial recognition of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only to specified risks, cash flows or portions of that instrument. SFAS No. 159 does not affect any existing accounting literature that requires certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. The Company adopted SFAS No. 159 effective January 1, 2008, and did not elect the fair value option for any existing eligible items.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not impose fair value measurements on items not already accounted for at fair value; rather it applies, with certain exceptions, to other accounting pronouncements that either require or permit fair value measurements. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal or most advantageous market. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In February 2008, the FASB issued Staff Position No. 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delays the effective date of SFAS No. 157 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the consolidated financial statements on a recurring basis, until fiscal years beginning after November 15, 2008. These non-financial items include assets and liabilities such as non-financial assets and liabilities assumed in a business combination, reporting units measured at fair value in a goodwill impairment test and asset retirement obligations initially measured at fair value. The Company adopted the provisions of SFAS No. 157 for assets and liabilities recognized at fair value on a recurring basis effective January 1, 2008. The partial adoption of SFAS No. 157 did not have a material impact on the Company’s Consolidated Financial Statements. Refer to Note 10 for additional discussion.
In September 2006, the FASB issued 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)” (“SFAS No. 158”). SFAS No. 158 requires that an employer measure plan assets and obligations as of the end of the employer’s fiscal year, eliminating the option in SFAS No. 87 and SFAS No. 106 to measure up to three months prior to the financial statement date. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end is not required until fiscal years ending after December 15, 2008. As of June 30, 2008, PacifiCorp had not yet adopted the measurement date provisions of the statement. Upon adoption of the measurement date provisions, PacifiCorp will be required to record a transitional adjustment to retained earnings or to a regulatory asset depending on whether the amount is considered probable of being recovered in rates.
10
(3) | Property, Plant and Equipment, Net |
Property, plant and equipment, net consist of the following (in millions):
As of | |||||||||
Depreciation | June 30, | December 31, | |||||||
Life | 2008 | 2007 | |||||||
Regulated assets: | |||||||||
Utility generation, distribution and transmission system | 5-85 years | $ | 31,747 | $ | 30,369 | ||||
Interstate pipeline assets | 3-67 years | 5,439 | 5,484 | ||||||
37,186 | 35,853 | ||||||||
Accumulated depreciation and amortization | (12,583 | ) | (12,280 | ) | |||||
Regulated assets, net | 24,603 | 23,573 | |||||||
Non-regulated assets: | |||||||||
Independent power plants | 10-30 years | 680 | 680 | ||||||
Other assets | 3-30 years | 664 | 650 | ||||||
1,344 | 1,330 | ||||||||
Accumulated depreciation and amortization | (453 | ) | (427 | ) | |||||
Non-regulated assets, net | 891 | 903 | |||||||
Net operating assets | 25,494 | 24,476 | |||||||
Construction in progress | 1,701 | 1,745 | |||||||
Property, plant and equipment, net | $ | 27,195 | $ | 26,221 |
Substantially all of the construction in progress as of June 30, 2008 and December 31, 2007 relates to the construction of regulated assets.
In April 2008, PacifiCorp entered into a purchase agreement with TNA Merchant Projects, Inc., an affiliate of Suez Energy North America, Inc., to acquire 100% of the equity interests of an entity owning a 520-megawatt (“MW”) natural gas-fired facility located in Chehalis, Washington. PacifiCorp has obtained all necessary federal and state regulatory approvals and expects to close the transaction during the third quarter of 2008.
(4) | Regulatory Matters |
The following are updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2007.
Refund Matters
Kern River
Kern River’s 2004 general rate case hearing concluded in August 2005. On March 2, 2006, Kern River received an initial decision on the case from the administrative law judge. On October 19, 2006, the Federal Energy Regulatory Commission (“FERC”) issued an order that modified certain aspects of the administrative law judge’s initial decision, 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 load and inflation factors. Kern River and other parties filed their requests for rehearing of the initial order on November 20, 2006. On April 18, 2008, the FERC issued an order denying rehearing on the issues raised by Kern River and other parties to the proceeding except Kern River’s request to include gas pipeline master limited partnerships in the proxy group for determining the allowed rate of return on equity. The grant of rehearing on this issue is consistent with the FERC’s April 17, 2008 adoption of a policy statement that addresses the inclusion of master limited partnerships in the proxy group used to determine a pipeline’s allowed return on equity. The FERC reopened the record for a paper hearing to determine Kern River’s return on equity in accordance with the policy statement. Initial, reply and rebuttal briefs were submitted by August 1, 2008. Rate refunds will be due within 30 days after a final order on Kern River’s rate case is issued. Kern River was permitted to bill the requested rate increase prior to final approval by the FERC, subject to refund, beginning effective November 1, 2004. Since that time, Kern River has recorded a liability for rates subject to refunds. As of June 30, 2008 and December 31, 2007, the liability for rates subject to refund was $200 million and $191 million, respectively.
11
Oregon Senate Bill 408
In October 2007, PacifiCorp filed its tax report for 2006 under Oregon Senate Bill 408 (“SB 408”), which was enacted in September 2005. SB 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers file a report annually with the Oregon Public Utility Commission (the “OPUC”) comparing income taxes collected and income taxes paid, as defined by the statute and its administrative rules. PacifiCorp’s filing indicated that for the 2006 tax year, PacifiCorp paid $33 million more in federal, state and local taxes than was collected in rates from its retail customers. PacifiCorp proposed to recover $27 million of the deficiency over a one-year period starting June 1, 2008 and to defer any excess into a balancing account for future disposition. During the review process, PacifiCorp updated its filing to address the OPUC staff recommendations, which increased the initial request by $2 million for a total of $35 million. In April 2008, the OPUC approved PacifiCorp’s revised request, with $27 million to be recovered over a one-year period beginning June 1, 2008, and the remainder to be deferred until a later period, with interest to accrue at PacifiCorp’s authorized rate of return. In June 2008, PacifiCorp recorded a $27 million regulatory asset and associated revenues representing the amount that PacifiCorp will collect from its Oregon retail customers over the one-year period that began on June 1, 2008. In May 2008, the Industrial Customers of Northwest Utilities filed a petition for judicial review in the Court of Appeals of the State of Oregon challenging the OPUC order. Briefs are anticipated to be filed in late 2008. PacifiCorp believes the outcome of the judicial review will not have a material impact on its consolidated financial results. PacifiCorp expects to file its 2007 tax report under SB 408 during the fourth quarter of 2008. PacifiCorp has not recorded any amounts related to the expected filing for 2007.
(5) | Recent Debt Transactions |
On July 17, 2008, PacifiCorp issued $500 million of 5.65% first mortgage bonds due July 15, 2018 and $300 million of 6.35% first mortgage bonds due July 15, 2038. The net proceeds are being used for general corporate purposes.
On July 15, 2008, Northern Natural Gas issued $200 million of 5.75% senior notes due July 15, 2018. The net proceeds will be used to repay at maturity its $150 million, 6.75% senior notes due September 15, 2008 and for general corporate purposes.
On July 1, 2008, the Iowa Finance Authority issued $45 million of variable-rate tax-exempt bonds due July 1, 2038, the proceeds of which were loaned to MidAmerican Energy to pay environmental construction costs. Also on July 1, 2008, the Iowa Finance Authority issued $57 million of variable-rate tax-exempt bonds due May 1, 2023 to refinance $57 million of pollution control revenue bonds issued on behalf of MidAmerican Energy in 1993. MidAmerican Energy is contractually responsible for the timely payment of principal and interest on these variable-rate tax-exempt bonds.
On April 1, 2008, MidAmerican Energy increased its unsecured revolving credit facility, expiring in July 2012, from $500 million to $650 million. As of June 30, 2008, the unsecured revolving credit facility supports its $455 million commercial paper program and its variable-rate tax-exempt bonds.
On March 28, 2008, MEHC issued $650 million of 5.75% senior notes due April 1, 2018. The net proceeds are being used for general corporate purposes. Unused amounts are temporarily invested in short-term securities, money market funds, bank deposits and cash equivalents.
On March 25, 2008, MidAmerican Energy issued $350 million of 5.3% senior notes due March 15, 2018. The proceeds are being used by MidAmerican Energy to pay construction costs, including costs for its wind-powered generation projects in Iowa, repay short-term indebtedness and for general corporate purposes.
12
(6) | Risk Management and Hedging Activities |
The Company is exposed to the impact of market fluctuations in commodity prices, principally natural gas and electricity, particularly through its ownership of PacifiCorp and MidAmerican Energy. Interest rate risk exists on variable rate debt, commercial paper and future debt issuances. The Company is also exposed to foreign currency risk from its business operations and investments in Great Britain. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, options, swaps and other over-the-counter agreements. The risk management process established by each business platform is designed to identify, assess, monitor, report, manage, and mitigate each of the various types of risk involved in its business. The Company does not engage in a material amount of proprietary trading activities.
The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of June 30, 2008 (in millions):
Accumulated | ||||||||||||||||||||
Regulatory | Other | |||||||||||||||||||
Derivative Net Assets (Liabilities) | Net Assets | Comprehensive | ||||||||||||||||||
Assets(1) | Liabilities(1) | Net | (Liabilities) | (Income) Loss(2) | ||||||||||||||||
Commodity | $ | 739 | $ | (1,048 | ) | $ | (309 | ) | $ | 400 | $ | (38 | ) | |||||||
Current | $ | 362 | $ | (370 | ) | $ | (8 | ) | ||||||||||||
Noncurrent | 377 | (678 | ) | (301 | ) | |||||||||||||||
Total | $ | 739 | $ | (1,048 | ) | $ | (309 | ) |
(1) | Derivative assets (liabilities) include $65 million of a net asset for cash collateral. |
(2) | Before income taxes. |
The following table summarizes the various derivative mark-to-market positions included in the Consolidated Balance Sheet as of December 31, 2007 (in millions):
Accumulated | ||||||||||||||||||||
Regulatory | Other | |||||||||||||||||||
Derivative Net Assets (Liabilities) | Net Assets | Comprehensive | ||||||||||||||||||
Assets | Liabilities | Net | (Liabilities) | (Income) Loss(1) | ||||||||||||||||
Commodity | $ | 396 | $ | (659 | ) | $ | (263 | ) | $ | 277 | $ | (15 | ) | |||||||
Foreign currency | 1 | (106 | ) | (105 | ) | (1 | ) | 106 | ||||||||||||
Total | $ | 397 | $ | (765 | ) | $ | (368 | ) | $ | 276 | $ | 91 | ||||||||
Current | $ | 170 | $ | (266 | ) | $ | (96 | ) | ||||||||||||
Non-current | 227 | (499 | ) | (272 | ) | |||||||||||||||
Total | $ | 397 | $ | (765 | ) | $ | (368 | ) |
(1) | Before income taxes. |
(7) | Related Party Transactions |
As of June 30, 2008 and December 31, 2007, Berkshire Hathaway and its affiliates held 11% mandatory redeemable preferred securities due from certain wholly owned subsidiary trusts of MEHC of $754 million and $821 million, respectively. Interest expense on these securities totaled $22 million and $29 million for the three-month periods ended June 30, 2008 and 2007, respectively, and $45 million and $58 million for the six-month periods ended June 30, 2008 and 2007, respectively. Accrued interest totaled $16 million and $17 million as of June 30, 2008 and December 31, 2007, respectively.
13
For the six-month periods ended June 30, 2008 and 2007, the Company received cash payments for income taxes from Berkshire Hathaway totaling $83 million and $1 million, respectively.
(8) | Commitments and Contingencies |
Environmental Matters
The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, hazardous and solid waste disposal 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 current environmental requirements.
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 June 30, 2008 and December 31, 2007 was $38 million 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 associated with the retirement of those assets are separately accounted for as asset retirement obligations.
Hydroelectric Relicensing
PacifiCorp’s hydroelectric portfolio consists of 47 plants with an aggregate facility net owned capacity of 1,158 MW. The FERC regulates 98% of the net capacity of this portfolio through 16 individual licenses. During the six-month period ended June 30, 2008, PacifiCorp accepted a new license issued by the FERC for the Prospect hydroelectric project. PacifiCorp’s Klamath hydroelectric project is currently undergoing relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements and litigation are subject to uncertainties. PacifiCorp expects that future costs relating to these matters will 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. PacifiCorp had incurred $87 million and $89 million in costs as of June 30, 2008 and December 31, 2007, respectively, for ongoing hydroelectric relicensing projects, which are included in construction in progress and reflected in property, plant and equipment, net in the Consolidated Balance Sheets.
In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW (nameplate rating) Klamath hydroelectric project 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 to operate under annual licenses until the new operating license is issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. In January 2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with the March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies’ terms and conditions as part of the project’s relicensing. However, PacifiCorp expects to continue in settlement discussions with various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the project.
14
Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC issued its draft environmental impact statement on the Klamath hydroelectric project license. PacifiCorp filed comments on the draft statement by the close of the public comment period on December 1, 2006. Subsequently, 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 hydroelectric project’s impact on endangered species under a new FERC license consistent with the FERC staff’s recommended alternative and modified terms and conditions issued by the Departments of Interior and Commerce. The United States Fish and Wildlife Service asserts the hydroelectric project is currently not covered by previously issued biological opinions and that consultation under the Endangered Species Act is required by the issuance of annual license renewals. PacifiCorp disputes these assertions and believes that consultation on annual FERC licenses is not required. PacifiCorp is currently working with the United States Fish and Wildlife Service to resolve any endangered species issues. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license. PacifiCorp currently has an application pending in Oregon. In July 2008, PacifiCorp withdrew its application for water quality certification in California to facilitate settlement negotiations. PacifiCorp intends to resubmit its application in the near future.
In the relicensing of the Klamath hydroelectric project, PacifiCorp had incurred $52 million and $48 million in costs as of June 30, 2008 and December 31, 2007, respectively, which are included in construction in progress and reflected in property, plant and equipment, net in the Consolidated Balance Sheets. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be material.
Legal Matters
The Company is party in 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 effect 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 and penalties 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 plant in Wyoming. Under Wyoming state requirements, which are part of the Jim Bridger plant’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 alleges thousands of violations of six-minute compliance periods 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. The court granted a motion to bifurcate the trial into separate liability and remedy phases. In March 2008, the court indefinitely postponed the date for the liability-phase trial. The remedy-phase trial has not yet been scheduled. The court also has before it a number of motions on which it has not yet ruled. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time. PacifiCorp has already committed to invest at least $812 million in pollution control equipment at its generating facilities, including the Jim Bridger plant. This commitment is expected to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.
CalEnergy Generation-Foreign
In February 2002, pursuant to the share ownership adjustment mechanism in the CE Casecnan shareholder agreement, MEHC’s indirect wholly owned subsidiary, CE Casecnan Ltd., advised the minority shareholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”), that MEHC’s indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. 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. On January 3, 2006, the Superior Court of the State of California entered a judgment in favor of LPG against CE Casecnan Ltd. Pursuant to the judgment, 15% of the distributions of CE Casecnan was deposited into escrow plus interest at 9% per annum. The judgment was appealed, and as a result of the appellate decision, CE Casecnan Ltd. determined that LPG would retain 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, which are also being litigated. The remaining issues are fully briefed and pending before the court. The Company intends to vigorously defend and pursue the remaining claims.
15
On July 1, 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, seeking a declaratory judgment as to San Lorenzo’s right to repurchase shares in CE Casecnan. 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 Casecnan, that it is the rightful owner of such shares and that it is due all dividends paid on such shares. Currently, the action is in the discovery phase, and a one-week trial has been set to begin on November 3, 2008. The impact, if any, of this litigation on the Company cannot be determined at this time. The Company intends to vigorously defend the counterclaims.
(9) | Employee Benefit Plans |
Domestic Operations
Combined net periodic benefit cost for domestic pension, including supplemental executive retirement plans, and other postretirement benefit plans included the following components (in millions):
Three-Month Periods | Six-Month Periods | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Pension | ||||||||||||||||
Service cost | $ | 13 | $ | 13 | $ | 27 | $ | 26 | ||||||||
Interest cost | 27 | 27 | 53 | 56 | ||||||||||||
Expected return on plan assets | (29 | ) | (27 | ) | (58 | ) | (55 | ) | ||||||||
Net amortization | 2 | 8 | 4 | 17 | ||||||||||||
Net periodic benefit cost | $ | 13 | $ | 21 | $ | 26 | $ | 44 |
Other Postretirement | ||||||||||||||||
Service cost | $ | 2 | $ | 4 | $ | 6 | $ | 8 | ||||||||
Interest cost | 12 | 13 | 24 | 25 | ||||||||||||
Expected return on plan assets | (11 | ) | (12 | ) | (22 | ) | (22 | ) | ||||||||
Net amortization | 5 | 6 | 9 | 11 | ||||||||||||
Net periodic benefit cost | $ | 8 | $ | 11 | $ | 17 | $ | 22 |
Employer contributions to domestic pension and other postretirement plans are expected to be $77 million and $41 million, respectively, in 2008. As of June 30, 2008, $63 million and $22 million of contributions had been made to the pension and other postretirement plans, respectively.
CE Electric UK
Net periodic benefit cost for the UK pension plan included the following components (in millions):
Three-Month Periods | Six-Month Periods | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Service cost | $ | 5 | $ | 6 | $ | 11 | $ | 12 | ||||||||
Interest cost | 26 | 23 | 52 | 46 | ||||||||||||
Expected return on plan assets | (31 | ) | (29 | ) | (63 | ) | (58 | ) | ||||||||
Net amortization | 5 | 8 | 10 | 16 | ||||||||||||
Net periodic benefit cost | $ | 5 | $ | 8 | $ | 10 | $ | 16 |
Employer contributions to the UK pension plan are expected to be £48 million for 2008. As of June 30, 2008, £26 million, or $51 million, of contributions had been made to the UK pension plan.
16
(10) | Fair Value Measurements |
The Company has various financial instruments that are measured at fair value in the Consolidated Financial Statements, including marketable debt and equity securities and commodity derivatives. The Company’s financial assets and liabilities are measured 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 and 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 the Company’s own data. |
The following table presents the Company’s assets and liabilities recognized in the Consolidated Balance Sheet and measured at fair value on a recurring basis as of June 30, 2008 (in millions):
Input Levels for Fair Value Measurements | ||||||||||||||||||||
Description | Level 1 | Level 2 | Level 3 | Other(1) | Total | |||||||||||||||
Assets(2): | ||||||||||||||||||||
Available-for-sale securities | $ | 276 | $ | 141 | $ | 61 | $ | - | $ | 478 | ||||||||||
Commodity derivatives | 35 | 661 | 514 | (471 | ) | 739 | ||||||||||||||
$ | 311 | $ | 802 | $ | 575 | $ | (471 | ) | $ | 1,217 | ||||||||||
Liabilities: | ||||||||||||||||||||
Commodity derivatives | $ | (5 | ) | $ | (808 | ) | $ | (746 | ) | $ | 511 | $ | (1,048 | ) |
(1) | Primarily represents netting under master netting arrangements and cash collateral requirements. |
(2) | Does not include investments in either pension or other postretirement plan assets. |
The Company’s investments in debt and equity securities are classified as available-for-sale and stated at fair value. When available, the quoted market price or net asset value of an identical security in the principal market is used to record the fair value. In the absence of a quoted market price in a readily observable market, the fair value is determined using pricing models 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 broker quotes and pricing models based on unobservable inputs.
The Company uses various commodity derivative instruments, including forward contracts, futures, options, swaps and other over-the counter agreements. The fair value of commodity derivatives is determined using unadjusted quoted prices for identical instruments on the applicable exchange in which the Company transacts. When quoted prices for identical instruments 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 first six years, and 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 for the first six years or the instrument is not actively traded. Given that limited market data exists for these instruments, 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.
17
The following table reconciles the beginning and ending balance of the Company’s assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
Three-Month Periods | Six-Month Periods | |||||||||||||||
Ended June 30, 2008 | Ended June 30, 2008 | |||||||||||||||
Available- | Available- | |||||||||||||||
For-Sale | Commodity | For-Sale | Commodity | |||||||||||||
Securities | Derivatives | Securities | Derivatives | |||||||||||||
Beginning balance | $ | 66 | $ | (325 | ) | $ | 73 | $ | (311 | ) | ||||||
Changes included in earnings(1) | - | (10 | ) | - | (20 | ) | ||||||||||
Unrealized gains (losses) included in other comprehensive income | (5 | ) | - | (12 | ) | 1 | ||||||||||
Unrealized gains (losses) included in regulatory assets and liabilities | - | 103 | - | 98 | ||||||||||||
Ending balance | $ | 61 | $ | (232 | ) | $ | 61 | $ | (232 | ) |
(1) | Changes included in earnings are reported as operating revenues in the Consolidated Statement of Operations. Net unrealized losses included in earnings for the three- and six-month periods related to commodity derivatives held at June 30, 2008 totaled $10 million and $16 million, respectively. |
(11) | Comprehensive Income and Components of Accumulated Other Comprehensive Income, Net |
The components of comprehensive income are as follows (in millions):
Three-Month Periods | Six-Month Periods | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Net income | $ | 220 | $ | 242 | $ | 562 | $ | 554 | ||||||||
Other comprehensive income: | ||||||||||||||||
Unrecognized amounts on retirement benefits, net of tax of $1, $1, $2 and $4 | 3 | 1 | 6 | 6 | ||||||||||||
Foreign currency translation adjustment | 14 | 52 | 16 | 65 | ||||||||||||
Fair value adjustment on cash flow hedges, net of tax of $1, $15, $9 and $24 | 2 | 25 | 14 | 38 | ||||||||||||
Unrealized (losses) gains on marketable securities, net of tax of $(3), $1, $(8) and $1 | (3 | ) | 1 | (11 | ) | 1 | ||||||||||
Total other comprehensive income | 16 | 79 | 25 | 110 | ||||||||||||
Comprehensive income | $ | 236 | $ | 321 | $ | 587 | $ | 664 |
Accumulated other comprehensive income, net is included in the Consolidated Balance Sheets in shareholders’ equity, and consists of the following components (in millions):
As of | ||||||||
June 30, | December 31, | |||||||
2008 | 2007 | |||||||
Unrecognized amounts on retirement benefits, net of tax of $(126) and $(128) | $ | (323 | ) | $ | (329 | ) | ||
Foreign currency translation adjustment | 372 | 356 | ||||||
Fair value adjustment on cash flow hedges, net of tax of $47 and $38 | 71 | 57 | ||||||
Unrealized (losses) gains on marketable securities, net of tax of $(4) and $4 | (5 | ) | 6 | |||||
Total accumulated other comprehensive income, net | $ | 115 | $ | 90 |
18
(12) | Segment Information |
MEHC’s reportable segments were determined based on how the Company’s strategic units are managed. The Company’s foreign reportable segments include CE Electric UK, whose business is principally in Great Britain, and CalEnergy Generation-Foreign, whose business is in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company’s reportable segments is shown below (in millions):
Three-Month Periods | Six-Month Periods | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Operating revenue: | ||||||||||||||||
PacifiCorp | $ | 1,055 | $ | 1,026 | $ | 2,150 | $ | 2,053 | ||||||||
MidAmerican Funding | 1,081 | 971 | 2,454 | 2,208 | ||||||||||||
Northern Natural Gas | 139 | 108 | 371 | 342 | ||||||||||||
Kern River | 104 | 111 | 214 | 197 | ||||||||||||
CE Electric UK | 243 | 254 | 528 | 502 | ||||||||||||
CalEnergy Generation-Foreign | 29 | 64 | 58 | 130 | ||||||||||||
CalEnergy Generation-Domestic | 8 | 8 | 15 | 16 | ||||||||||||
HomeServices | 342 | 470 | 583 | 805 | ||||||||||||
Corporate/other(1) | (9 | ) | (9 | ) | (25 | ) | (26 | ) | ||||||||
Total operating revenue | $ | 2,992 | $ | 3,003 | $ | 6,348 | $ | 6,227 | ||||||||
Depreciation and amortization: | ||||||||||||||||
PacifiCorp | $ | 124 | $ | 122 | $ | 241 | $ | 243 | ||||||||
MidAmerican Funding | 77 | 76 | 149 | 145 | ||||||||||||
Northern Natural Gas | 14 | 15 | 29 | 29 | ||||||||||||
Kern River | 22 | 20 | 43 | 39 | ||||||||||||
CE Electric UK | 46 | 44 | 90 | 86 | ||||||||||||
CalEnergy Generation-Foreign | 6 | 17 | 11 | 35 | ||||||||||||
CalEnergy Generation-Domestic | 2 | 2 | 4 | 4 | ||||||||||||
HomeServices | 5 | 5 | 10 | 10 | ||||||||||||
Corporate/other(1) | (4 | ) | (3 | ) | (7 | ) | (7 | ) | ||||||||
Total depreciation and amortization | $ | 292 | $ | 298 | $ | 570 | $ | 584 | ||||||||
Operating income: | ||||||||||||||||
PacifiCorp | $ | 218 | $ | 210 | $ | 449 | $ | 430 | ||||||||
MidAmerican Funding | 104 | 113 | 279 | 258 | ||||||||||||
Northern Natural Gas | 52 | 22 | 200 | 171 | ||||||||||||
Kern River | 69 | 77 | 145 | 138 | ||||||||||||
CE Electric UK | 117 | 125 | 284 | 272 | ||||||||||||
CalEnergy Generation-Foreign | 21 | 32 | 42 | 76 | ||||||||||||
CalEnergy Generation-Domestic | 4 | 4 | 7 | 8 | ||||||||||||
HomeServices | 11 | 32 | (11 | ) | 27 | |||||||||||
Corporate/other(1) | (13 | ) | (17 | ) | (40 | ) | (44 | ) | ||||||||
Total operating income | 583 | 598 | 1,355 | 1,336 | ||||||||||||
Interest expense | (330 | ) | (324 | ) | (658 | ) | (640 | ) | ||||||||
Capitalized interest | 12 | 16 | 23 | 30 | ||||||||||||
Interest and dividend income | 13 | 23 | 31 | 42 | ||||||||||||
Other income | 27 | 29 | 45 | 55 | ||||||||||||
Other expense | (4 | ) | (3 | ) | (5 | ) | (4 | ) | ||||||||
Total income before income tax expense, minority interest and preferred dividends of subsidiaries and equity income | $ | 301 | $ | 339 | $ | 791 | $ | 819 |
19
Three-Month Periods | Six-Month Periods | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Interest expense: | ||||||||||||||||
PacifiCorp | $ | 80 | $ | 79 | $ | 164 | $ | 154 | ||||||||
MidAmerican Funding | 53 | 41 | 101 | 83 | ||||||||||||
Northern Natural Gas | 14 | 15 | 29 | 28 | ||||||||||||
Kern River | 18 | 19 | 36 | 37 | ||||||||||||
CE Electric UK | 46 | 59 | 97 | 117 | ||||||||||||
CalEnergy Generation-Foreign | 2 | 4 | 4 | 8 | ||||||||||||
CalEnergy Generation-Domestic | 5 | 4 | 9 | 9 | ||||||||||||
HomeServices | 1 | 1 | 1 | 1 | ||||||||||||
Corporate/other(1) | 111 | 102 | 217 | 203 | ||||||||||||
Total interest expense | $ | 330 | $ | 324 | $ | 658 | $ | 640 |
As of | ||||||||
June 30, | December 31, | |||||||
2008 | 2007 | |||||||
Total assets: | ||||||||
PacifiCorp | $ | 16,776 | $ | 16,049 | ||||
MidAmerican Funding | 9,979 | 9,377 | ||||||
Northern Natural Gas | 2,607 | 2,488 | ||||||
Kern River | 1,901 | 1,943 | ||||||
CE Electric UK | 6,564 | 6,802 | ||||||
CalEnergy Generation-Foreign | 464 | 479 | ||||||
CalEnergy Generation-Domestic | 544 | 544 | ||||||
HomeServices | 751 | 709 | ||||||
Corporate/other(1) | 682 | 825 | ||||||
Total assets | $ | 40,268 | $ | 39,216 |
(1) | The remaining differences between the segment amounts and the consolidated amounts described as “Corporate/other” relate principally to intersegment eliminations for operating revenue and, for the other items presented, to (i) corporate functions, including administrative costs, interest expense, corporate cash and related interest income and (ii) intersegment eliminations. |
Goodwill is allocated to each reportable segment included in total assets above. Goodwill as of December 31, 2007 and the changes for the six-month period ended June 30, 2008 by reportable segment are as follows (in millions):
Northern | CE | CalEnergy | ||||||||||||||||||||||||||||||
MidAmerican | Natural | Kern | Electric | Generation | Home- | |||||||||||||||||||||||||||
PacifiCorp | Funding | Gas | River | UK | Domestic | Services | Total | |||||||||||||||||||||||||
Goodwill at December 31, 2007 | $ | 1,125 | $ | 2,108 | $ | 275 | $ | 34 | $ | 1,335 | $ | 71 | $ | 391 | $ | 5,339 | ||||||||||||||||
Foreign currency translation | - | - | - | - | 4 | - | - | 4 | ||||||||||||||||||||||||
Other(1) | 2 | 3 | (13 | ) | - | 1 | - | - | (7 | ) | ||||||||||||||||||||||
Goodwill at June 30, 2008 | $ | 1,127 | $ | 2,111 | $ | 262 | $ | 34 | $ | 1,340 | $ | 71 | $ | 391 | $ | 5,336 |
(1) | Other goodwill adjustments relate primarily to income tax adjustments. |
20
Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following is management’s discussion and analysis of certain significant factors that have affected the financial condition and results of operations of MidAmerican Energy Holdings Company (“MEHC”) and its subsidiaries (collectively, 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 the Company’s historical unaudited Consolidated Financial Statements and the notes included elsewhere in Item 1 of this Form 10-Q. The Company’s actual results in the future could differ significantly from the historical results.
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 (owning a majority interest in the Casecnan project), CalEnergy Generation-Domestic (owning 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, a combined 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.
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. Forward-looking statements can typically be identified by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “intend,” “potential,” “plan,” “forecast,” and similar terms. These statements are based upon the Company’s current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the Company’s control and could cause actual results to differ materially from those expressed or implied by the Company’s forward-looking statements. These factors include, among others:
· | general economic, political and business conditions in the jurisdictions in which the Company’s facilities are located; |
· | changes in governmental, legislative or regulatory requirements affecting the Company or the electric or gas utility, pipeline or power generation industries; |
· | changes in, and compliance with, environmental laws, regulations, decisions and policies that could increase operating and capital improvement costs, reduce plant output and/or delay plant construction; |
· | the outcome of general rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies; |
· | changes in economic, industry or weather conditions, as well as demographic trends, that could affect customer growth and usage or supply of electricity and gas or the Company’s ability to obtain long-term contracts with customers; |
· | changes in the residential real estate brokerage and mortgage industries that could affect brokerage transaction levels; |
· | 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 a significant impact on generation capacity and energy costs; |
· | the financial condition and creditworthiness of the Company’s significant customers and suppliers; |
· | changes in business strategy or development plans; |
· | availability, terms and deployment of capital; |
· | performance of the Company’s generation facilities, including unscheduled generation outages or repairs; |
21
· | risks relating to nuclear generation; |
· | the impact of derivative instruments used to mitigate or manage volume and price risk and interest rate 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; |
· | the Company’s ability to successfully integrate future acquired operations into its business; |
· | other risks or unforeseen events, including litigation and 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 MEHC’s filings with the United States (“U.S.”) Securities and Exchange Commission (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 and other discussions contained in this Form 10-Q. 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.
Results of Operations
Overview
Net income for the second quarter of 2008 was $220 million, a decrease of $22 million, or 9%, from the comparable period in 2007. The decrease was due primarily to lower earnings at MidAmerican Funding due mainly to generation plant outages and increased storm and flood damage, lower earnings at HomeServices due to the continuing weak U.S. housing market, the transfer of two geothermal projects to the Philippine government in July 2007 and higher interest expense at MEHC and its domestic energy businesses. These decreases were partially offset by higher earnings at Northern Natural Gas due to higher revenue from stronger market conditions.
Net income for the first six months of 2008 was $562 million, an increase of $8 million, or 1%, from the comparable period in 2007. The increase was due primarily to favorable operating income at MEHC’s regulated businesses, due primarily to improved margins, a lower effective tax rate and lower minority interest expense, partially offset by the aforementioned lower earnings at HomeServices, the transfer of two geothermal projects and higher interest expense.
Segment Results
The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company’s significant accounting policies. The differences between the segment amounts and the consolidated amounts, described as “Corporate/other,” relate principally to corporate functions, including administrative costs and intersegment eliminations.
22
A comparison of operating revenue and operating income for the Company’s reportable segments are summarized as follows (in millions):
Second Quarter | First Six Months | |||||||||||||||||||||||||||||||
2008 | 2007 | Change | 2008 | 2007 | Change | |||||||||||||||||||||||||||
Operating revenue: | ||||||||||||||||||||||||||||||||
PacifiCorp | $ | 1,055 | $ | 1,026 | $ | 29 | 3 | % | $ | 2,150 | $ | 2,053 | $ | 97 | 5 | % | ||||||||||||||||
MidAmerican Funding | 1,081 | 971 | 110 | 11 | 2,454 | 2,208 | 246 | 11 | ||||||||||||||||||||||||
Northern Natural Gas | 139 | 108 | 31 | 29 | 371 | 342 | 29 | 8 | ||||||||||||||||||||||||
Kern River | 104 | 111 | (7 | ) | (6 | ) | 214 | 197 | 17 | 9 | ||||||||||||||||||||||
CE Electric UK | 243 | 254 | (11 | ) | (4 | ) | 528 | 502 | 26 | 5 | ||||||||||||||||||||||
CalEnergy Generation-Foreign | 29 | 64 | (35 | ) | (55 | ) | 58 | 130 | (72 | ) | (55 | ) | ||||||||||||||||||||
CalEnergy Generation-Domestic | 8 | 8 | - | - | 15 | 16 | (1 | ) | (6 | ) | ||||||||||||||||||||||
HomeServices | 342 | 470 | (128 | ) | (27 | ) | 583 | 805 | (222 | ) | (28 | ) | ||||||||||||||||||||
Corporate/other | (9 | ) | (9 | ) | - | - | (25 | ) | (26 | ) | 1 | 4 | ||||||||||||||||||||
Total operating revenue | $ | 2,992 | $ | 3,003 | $ | (11 | ) | - | $ | 6,348 | $ | 6,227 | $ | 121 | 2 |
Operating income: | ||||||||||||||||||||||||||||||||
PacifiCorp | $ | 218 | $ | 210 | $ | 8 | 4 | % | $ | 449 | $ | 430 | $ | 19 | 4 | % | ||||||||||||||||
MidAmerican Funding | 104 | 113 | (9 | ) | (8 | ) | 279 | 258 | 21 | 8 | ||||||||||||||||||||||
Northern Natural Gas | 52 | 22 | 30 | 136 | 200 | 171 | 29 | 17 | ||||||||||||||||||||||||
Kern River | 69 | 77 | (8 | ) | (10 | ) | 145 | 138 | 7 | 5 | ||||||||||||||||||||||
CE Electric UK | 117 | 125 | (8 | ) | (6 | ) | 284 | 272 | 12 | 4 | ||||||||||||||||||||||
CalEnergy Generation-Foreign | 21 | 32 | (11 | ) | (34 | ) | 42 | 76 | (34 | ) | (45 | ) | ||||||||||||||||||||
CalEnergy Generation-Domestic | 4 | 4 | - | - | 7 | 8 | (1 | ) | (13 | ) | ||||||||||||||||||||||
HomeServices | 11 | 32 | (21 | ) | (66 | ) | (11 | ) | 27 | (38 | ) | (141 | ) | |||||||||||||||||||
Corporate/other | (13 | ) | (17 | ) | 4 | 24 | (40 | ) | (44 | ) | 4 | 9 | ||||||||||||||||||||
Total operating income | $ | 583 | $ | 598 | $ | (15 | ) | (3 | ) | $ | 1,355 | $ | 1,336 | $ | 19 | 1 |
PacifiCorp
Operating revenue increased $29 million and $97 million for the second quarter and for the first six months of 2008, respectively. Retail revenue increased $66 million and $123 million, respectively, due to receiving approval from the Oregon Public Utility Commission (“OPUC”) to begin collecting in June 2008 $27 million of previously under-collected income taxes pursuant to Oregon Senate Bill 408, higher prices approved by regulators, growth in the average number of customers and higher average customer usage. Wholesale and other revenue increased $34 million for the first six months of 2008 due to higher average wholesale prices and higher transmission revenue, partially offset by lower wholesale volumes. Retail and wholesale and other revenue increases were partially offset by changes in the fair value of energy sales contracts accounted for as derivatives that decreased operating revenue by $37 million and $60 million for the second quarter and for the first six months of 2008, respectively.
Operating income increased $8 million and $19 million for the second quarter and for the first six months of 2008, respectively. Higher revenue described above was partially offset by higher energy costs of $15 million and $80 million, respectively. Energy costs increased due to higher unit costs of purchased electricity, natural gas and coal, partially offset by lower volumes of purchased electricity due in part to the addition of the 548-megawatt (“MW”) Lake Side plant and additional wind generation placed in-service in 2007 and 2008, and higher transmission costs due to higher prices and volumes. Natural gas volumes used were lower in the second quarter, but higher for the first six months of 2008. These energy cost increases were partially offset by changes in the fair value of energy purchase contracts accounted for as derivatives that decreased energy costs by $40 million and $54 million for the second quarter and for the first six months of 2008, respectively.
23
MidAmerican Funding
MidAmerican Funding’s operating revenue and operating income are summarized as follows (in millions):
Second Quarter | First Six Months | |||||||||||||||||||||||||||||||
2008 | 2007 | Change | 2008 | 2007 | Change | |||||||||||||||||||||||||||
Operating revenue: | ||||||||||||||||||||||||||||||||
Regulated electric | $ | 492 | $ | 467 | $ | 25 | 5 | % | $ | 975 | $ | 947 | $ | 28 | 3 | % | ||||||||||||||||
Regulated natural gas | 280 | 209 | 71 | 34 | 851 | 708 | 143 | 20 | ||||||||||||||||||||||||
Nonregulated and other | 309 | 295 | 14 | 5 | 628 | 553 | 75 | 14 | ||||||||||||||||||||||||
Total operating revenue | $ | 1,081 | $ | 971 | $ | 110 | 11 | $ | 2,454 | $ | 2,208 | $ | 246 | 11 | ||||||||||||||||||
Operating income: | ||||||||||||||||||||||||||||||||
Regulated electric | $ | 89 | $ | 94 | $ | (5 | ) | (5 | )% | $ | 205 | $ | 189 | $ | 16 | 8 | % | |||||||||||||||
Regulated natural gas | 3 | 1 | 2 | 200 | 48 | 42 | 6 | 14 | ||||||||||||||||||||||||
Nonregulated and other | 12 | 18 | (6 | ) | (33 | ) | 26 | 27 | (1 | ) | (4 | ) | ||||||||||||||||||||
Total operating income | $ | 104 | $ | 113 | $ | (9 | ) | (8 | ) | $ | 279 | $ | 258 | $ | 21 | 8 |
Regulated electric revenue increased $25 million and $28 million for the second quarter and for the first six months of 2008, respectively. Wholesale revenue increased $34 million and $27 million in the respective periods due to increased generation available from the addition of owned generation, partially offset by lower average prices for the first six months of 2008. Retail revenue decreased $8 million for the second quarter of 2008. Unfavorable weather conditions in the second quarter of 2008 were offset by growth in the average number of customers. Regulated natural gas revenue increased $71 million and $143 million for the second quarter and for the first six months of 2008, respectively, due primarily to a higher average per-unit cost of gas sold and higher retail sales volumes resulting from colder temperatures. Nonregulated and other revenue increased $14 million and $75 million for the second quarter and for the first six months of 2008, respectively, due primarily to higher gas revenue of $29 million and $53 million, respectively, as a result of higher prices and volumes. Nonregulated electric revenue decreased by $15 million for the second quarter due primarily to lower sales volumes resulting primarily from a reduction in the number of customers due to competition, partially offset by higher average prices. Nonregulated electric revenue increased by $22 million for the first six months of 2008 due primarily to higher average prices.
Regulated electric operating income decreased $5 million and increased $16 million for the second quarter and for the first six months of 2008, respectively. Wholesale gross margins increased $15 million and $34 million in the respective periods due to the increased generation available as discussed above. Operating expenses increased $19 million and $20 million in the respective periods due primarily to higher maintenance costs associated with scheduled plant outages, an increased level of storm and flood damage in 2008 and the additional generation placed in-service. Regulated natural gas operating income increased $6 million for the first six months of 2008 due primarily to higher retail sales volumes. Nonregulated and other operating income decreased $6 million and $1 million for the second quarter and for the first six months of 2008, respectively, due to lower gross margins.
Northern Natural Gas
Operating revenue increased $31 million and $29 million for the second quarter and for the first six months of 2008, respectively, due primarily to higher transportation revenue of $26 million and $37 million, respectively, due primarily to stronger market conditions, higher market area reservation revenue resulting from the Northern Lights expansion projects and revenue generated from new transportation service associated with the completion of the interconnect with the Rockies Express Pipeline, partially offset by lower rates on certain contract extensions. Additionally, storage revenue was higher by $4 million and $5 million for the second quarter and for the first six months of 2008, respectively, due to higher interruptible storage activity. The higher transportation and storage revenue for the first six months of 2008 was partially offset by lower sales of gas for operational purposes of $13 million due primarily to lower sales volumes.
Operating income increased $30 million and $29 million for the second quarter and for the first six months of 2008, respectively, due primarily to the aforementioned higher operating revenue.
24
Kern River
Operating revenue decreased $7 million and increased $17 million for the second quarter and for the first six months of 2008, respectively. Market oriented revenues, still strong in 2008, decreased $13 million and $19 million, respectively, as a result of less favorable market conditions. Operating revenue was favorably impacted for the second quarter and for the first six months of 2008 by a reduction in customer refund liabilities related to Kern River’s current rate proceeding.
Operating income decreased $8 million and increased $7 million for the second quarter and for the first six months of 2008, respectively, due primarily to the aforementioned change in operating revenue. Additionally, operating income for the first six months of 2008 was lower due primarily to a $6 million sales and use tax refund received in 2007 and higher depreciation expense in 2008.
CE Electric UK
Operating revenue decreased $11 million and increased $26 million for the second quarter and for the first six months of 2008, respectively. Distribution revenue was lower in the second quarter by $10 million and higher in the first six months by $22 million. Tariffs were higher in the first quarter of 2008 as rates were increased in 2007 to bill under-recovered amounts under the regulatory scheme. These rates were lowered in April 2008. Volumes distributed in both periods were lower as the average consumption per customer decreased.
Operating income decreased $8 million and increased $12 million for the second quarter and for the first six months of 2008, respectively. The decrease for the second quarter was due primarily to the aforementioned lower revenues. The increase for the first six months was due primarily to the aforementioned higher revenues, partially offset by a $17 million realized gain on the sale of certain CE Gas assets in 2007.
CalEnergy Generation-Foreign
Operating revenue decreased $35 million and $72 million for the second quarter and for the first six months of 2008, respectively, as the Malitbog and Mahanagdong projects were transferred on July 25, 2007 to the Philippine government, which reduced operating revenue by $42 million and $84 million, respectively. This decrease was partially offset by higher operating revenue of $7 million and $12 million for the second quarter and for the first six months of 2008, respectively, at the Casecnan project primarily due to higher variable energy fees as a result of increased generation from higher water flows.
Operating income decreased $11 million and $34 million for the second quarter and for the first six months of 2008, respectively, due primarily to the aforementioned transfer of the Malitbog and Mahanagdong projects, which resulted in lower operating income of $17 million and $43 million, respectively, partially offset by the aforementioned higher operating revenue at the Casecnan project.
HomeServices
Operating revenue decreased $128 million and $222 million for the second quarter and for the first six months of 2008, respectively, due to a significant decline in transaction volumes reflecting the continuing weak U.S. housing market.
Operating income decreased $21 million and $38 million for the second quarter and for the first six months of 2008, respectively, due primarily to the aforementioned decline in transaction volumes, partially offset by lower commissions and operating expenses.
25
Consolidated Other Income and Expense Items
Interest Expense
Interest expense is summarized as follows (in millions):
Second Quarter | First Six Months | |||||||||||||||||||||||||||||||
2008 | 2007 | Change | 2008 | 2007 | Change | |||||||||||||||||||||||||||
Subsidiary debt | $ | 208 | $ | 212 | $ | (4 | ) | (2 | )% | $ | 420 | $ | 417 | $ | 3 | 1 | % | |||||||||||||||
MEHC senior debt and other | 93 | 76 | 17 | 22 | 179 | 152 | 27 | 18 | ||||||||||||||||||||||||
MEHC subordinated debt-Berkshire Hathaway Inc. | 22 | 29 | (7 | ) | (24 | ) | 45 | 58 | (13 | ) | (22 | ) | ||||||||||||||||||||
MEHC subordinated debt-other | 7 | 7 | - | - | 14 | 13 | 1 | 8 | ||||||||||||||||||||||||
Total interest expense | $ | 330 | $ | 324 | $ | 6 | 2 | $ | 658 | $ | 640 | $ | 18 | 3 |
Interest expense increased $6 million and $18 million for the second quarter and for the first six months of 2008, respectively, due primarily to debt issuances at domestic energy businesses and at MEHC, partially offset by debt retirements and scheduled principal repayments.
Other Income, Net
Other income, net is summarized as follows (in millions):
Second Quarter | First Six Months | |||||||||||||||||||||||||||||||
2008 | 2007 | Change | 2008 | 2007 | Change | |||||||||||||||||||||||||||
Capitalized interest | $ | 12 | $ | 16 | $ | (4 | ) | (25 | )% | $ | 23 | $ | 30 | $ | (7 | ) | (23 | )% | ||||||||||||||
Interest and dividend income | 13 | 23 | (10 | ) | (43 | ) | 31 | 42 | (11 | ) | (26 | ) | ||||||||||||||||||||
Other income | 27 | 29 | (2 | ) | (7 | ) | 45 | 55 | (10 | ) | (18 | ) | ||||||||||||||||||||
Other expense | (4 | ) | (3 | ) | (1 | ) | (33 | ) | (5 | ) | (4 | ) | (1 | ) | (25 | ) | ||||||||||||||||
Total other income, net | $ | 48 | $ | 65 | $ | (17 | ) | (26 | ) | $ | 94 | $ | 123 | $ | (29 | ) | (24 | ) |
Capitalized interest and other income, which includes equity allowance for funds used during construction (“AFUDC”), decreased $4 million and $2 million, respectively, for the second quarter of 2008 and $7 million and $10 million, respectively, for the first six months of 2008 due primarily to lower work in progress.
Interest and dividend income decreased $10 million and $11 million for the second quarter and for the first six months of 2008, respectively, due primarily to the maturities of guaranteed investment contracts, one in December 2007 and one in February 2008. The proceeds of the maturities were used to retire debt maturing at CE Electric UK.
Income Tax Expense
Income tax expense decreased $18 million to $82 million and $31 million to $229 million for the second quarter and for the first six months of 2008, respectively. The effective tax rates were 27% and 29% for the second quarter of 2008 and 2007, respectively, and 29% and 32% for the first six months of 2008 and 2007, respectively. The decrease in the effective tax rates for the second quarter and for the first six months of 2008 were primarily due to higher production tax credits associated with increased wind generation production, the effects of rate making at PacifiCorp and MidAmerican Funding and lower foreign taxes primarily due to a favorable foreign tax ruling.
Minority Interest and Preferred Dividends of Subsidiaries
Minority interest and preferred dividends of subsidiaries decreased $8 million to $9 million for the first six months of 2008. The decrease was due primarily to additional expense in 2007 related to the minority ownership of the Casecnan project.
26
Liquidity and Capital Resources
The Company has available a variety of sources of liquidity and capital resources, both internal and external, including the Berkshire Hathaway Inc. Equity Commitment. These resources provide funds required for current operations, construction expenditures, debt retirement and other capital requirements.
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 were $1.0 billion as of June 30, 2008, compared to $1.18 billion as of December 31, 2007. The Company recorded separately in other current assets, restricted cash and investments as of June 30, 2008 and December 31, 2007 of $77 million and $73 million, respectively. The restricted cash and investments balance is mainly composed of current amounts deposited in restricted accounts relating to (i) the Company’s debt service reserve requirements relating to certain projects, (ii) trust funds related to mine reclamation costs, and (iii) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project. Additionally, the Company has restricted cash and investments recorded in deferred charges, investments and other assets of $371 million and $425 million as of June 30, 2008 and December 31, 2007, respectively, that principally relate to trust funds held for mine reclamation and nuclear decommissioning costs. As of June 30, 2008, MEHC had $556 million of availability under its $600 million revolving credit facility with letters of credit issued under the credit agreement totaling $44 million and no borrowings outstanding. As of June 30, 2008, MEHC’s subsidiaries had $2.2 billion of availability under their separate revolving credit facilities totaling $2.5 billion.
Cash Flows from Operating Activities
Cash flows generated from operations for the six-month periods ended June 30, 2008 and 2007 were $1.29 billion and $1.41 billion, respectively. The decrease was due primarily to the timing of payments and cash collections and the transfer of the Malitbog and Mahanagdong projects, partially offset by higher margins in 2008. The Company expects to pay refunds when the Kern River rate case is finalized as discussed in Note 4 to Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q.
Cash Flows from Investing Activities
Cash flows used in investing activities for the six-month periods ended June 30, 2008 and 2007 were $1.17 billion and $1.70 billion, respectively. In February 2008, the Company received proceeds from the maturity of a guaranteed investment contract of $393 million. Capital expenditures decreased $91 million in part due to Walter Scott, Jr. Energy Center Unit 4 beginning commercial operations in June 2007. Also, the change in net purchases and sales of available-for-sale securities reduced cash flows used in investing activities by $143 million.
27
Capital Expenditures
Capital expenditures by reportable segment are summarized as follows (in millions):
First Six Months | ||||||||
2008 | 2007 | |||||||
Capital expenditures*: | ||||||||
PacifiCorp | $ | 710 | $ | 731 | ||||
MidAmerican Funding | 561 | 656 | ||||||
Northern Natural Gas | 69 | 95 | ||||||
CE Electric UK | 218 | 174 | ||||||
Other reportable segments and corporate/other | 18 | 11 | ||||||
Total capital expenditures | $ | 1,576 | $ | 1,667 |
* | Excludes amounts for non-cash equity AFUDC. |
Capital expenditures consisted primarily of the following:
· | Combined, PacifiCorp and MidAmerican Energy spent $492 million during the first six months of 2008 on wind-powered generation of which 251 MW (nameplate ratings) were placed in service and an additional 891.5 MW (nameplate ratings) that are expected to be placed in service by December 31, 2008. |
· | Combined, PacifiCorp and MidAmerican Energy spent $132 million on emissions control equipment. |
· | Projects mainly for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand. |
The Company has significant future capital requirements. Forecasted capital expenditures for fiscal 2008, which exclude non-cash equity AFUDC, are approximately $4.3 billion. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. Estimates may change significantly at any time as a result of, among other factors, changes in rules and regulations, including environmental and nuclear, changes in income tax laws, general business conditions, load projections, the cost and efficiency of construction labor, equipment, and materials, and the cost of capital. In addition, there can be no assurance that costs related to capital expenditures will be fully recovered. The Company expects to meet its capital expenditure requirements with cash flows from operations and the issuance of debt. To the extent funds are not available to support capital expenditures, projects may be delayed and operating income may be reduced.
Forecasted capital expenditures for fiscal 2008 include the following:
· | Combined, PacifiCorp and MidAmerican Energy anticipate spending $1.7 billion on wind-powered generation facilities of which 1,142.5 MW (nameplate ratings) are expected to be placed in service in 2008. |
· | Combined, PacifiCorp and MidAmerican Energy are projecting to spend $314 million for emissions control equipment in 2008. |
· | PacifiCorp expects to spend $89 million for transmission system expansion and upgrades for the year ended December 31, 2008, which includes the construction of a 135-mile, double-circuit, 345-kilovolt transmission line to be built between the Populus substation located in southern Idaho and the Terminal substation located in the Salt Lake City area. This transmission line will be constructed in the Path C Transmission corridor, a primary transmission corridor in PacifiCorp’s balancing authority area. PacifiCorp expects to complete construction of this line in 2010. |
· | Projects mainly for distribution, transmission, generation, mining and other infrastructure needed to serve existing and growing demand. |
28
In July 2008, PacifiCorp filed with the FERC a petition for declaratory order to confirm incentive rate treatment for the Energy Gateway Transmission Expansion Project. The Energy Gateway Transmission Expansion Project is an investment plan to build in excess of 1,900 miles of new high-voltage transmission lines primarily in Wyoming, Utah, Idaho, Oregon and the desert Southwest. The plan, with an estimated cost of approximately $6 billion, includes projects that will address customers’ increasing electric energy use, improve system reliability and deliver wind and other renewable generation resources to more customers throughout PacifiCorp’s six-state service area and the Western United States. Major transmission segments associated with this plan are expected to be placed in service beginning 2010 with major segments in service by 2014 depending on siting, permitting and construction timeframes.
In April 2008, PacifiCorp entered into a purchase agreement with TNA Merchant Projects, Inc., an affiliate of Suez Energy North America, Inc., to acquire 100% of the equity interests of an entity owning a 520-MW natural gas-fired facility located in Chehalis, Washington. PacifiCorp has obtained all necessary federal and state regulatory approvals and expects to close the transaction during the third quarter of 2008.
The Company is subject to federal, state, local and foreign laws and regulations with regard to air and water quality, renewable portfolio standards, hazardous and solid waste disposal and other environmental matters. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Company. In particular, future mandates, including those associated with addressing the issue of global climate change, may impact the operation of the Company’s domestic generating facilities and may require both PacifiCorp and MidAmerican Energy to reduce emissions at their facilities through the installation of additional emission control equipment or to purchase additional emission allowances or offsets in the future. The Company is not aware of any proven commercially available technology that eliminates or captures and stores carbon dioxide emissions from coal-fired and other gas–fired generation facilities, and the Company is uncertain when, or if, such technology will be commercially available.
Refer to the Environmental Regulation section of Item 1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 for a detailed discussion of the topic.
Cash Flows from Financing Activities
Cash flows used in financing activities for the first six months of 2008 were $305 million. Uses of cash totaled $1.35 billion and consisted mainly of $616 million for repayments and purchases of MEHC senior and subordinated debt, $572 million for repayments of subsidiary and project debt, $99 million payment of hedging instruments related to the maturity of U.S. dollar denominated debt at CE Electric UK and $66 million of net repayments of subsidiary short-term debt. Sources of cash totaled $1.05 billion and consisted mainly of proceeds from the issuance of MEHC senior debt totaling $649 million and subsidiary and project debt totaling $398 million.
Cash flows generated from financing activities for the first six months of 2007 were $1.12 billion. Sources of cash totaled $1.95 billion and consisted mainly of proceeds from the issuance of subsidiary and project debt totaling $1.4 billion and MEHC senior debt totaling $547 million. Uses of cash totaled $823 million and consisted mainly of $370 million of net repayments of subsidiary short-term debt, $217 million for repayments of subsidiary and project debt, $152 million of net repayments of the MEHC revolving credit facility and $67 million of repayments of MEHC subordinated debt.
The Company may from time to time seek to acquire its outstanding securities through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases, if any, may be temporary, and will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
29
2008 Debt Transactions and Agreements
In addition to the debt issuances discussed herein, MEHC and its subsidiaries made scheduled repayments on MEHC senior and subordinated debt and subsidiary and project debt totaling $1.19 billion during the six-month period ended June 30, 2008.
· | On July 17, 2008, PacifiCorp issued $500 million of 5.65% first mortgage bonds due July 15, 2018 and $300 million of 6.35% first mortgage bonds due July 15, 2038. The net proceeds are being used for general corporate purposes. |
· | On July 15, 2008, Northern Natural Gas issued $200 million of 5.75% senior notes due July 15, 2018. The net proceeds will be used to repay at maturity its $150 million, 6.75% senior notes due September 15, 2008 and for general corporate purposes. |
· | On July 1, 2008, the Iowa Finance Authority issued $45 million of variable-rate tax-exempt bonds due July 1, 2038, the proceeds of which were loaned to MidAmerican Energy to pay environmental construction costs. Also on July 1, 2008, the Iowa Finance Authority issued $57 million of variable-rate tax-exempt bonds due May 1, 2023 to refinance $57 million of pollution control revenue bonds issued on behalf of MidAmerican Energy in 1993. MidAmerican Energy is contractually responsible for the timely payment of principal and interest on these variable-rate tax-exempt bonds. |
· | On April 1, 2008, MidAmerican Energy increased its unsecured revolving credit facility, expiring in July 2012, from $500 million to $650 million. As of June 30, 2008, the unsecured revolving credit facility supports its $455 million commercial paper program and its variable-rate tax-exempt bonds. |
· | On March 28, 2008, MEHC issued $650 million of 5.75% senior notes due April 1, 2018. The net proceeds are being used for general corporate purposes. Unused amounts are temporarily invested in short-term securities, money market funds, bank deposits and cash equivalents. |
· | On March 25, 2008, MidAmerican Energy issued $350 million of 5.3% senior notes due March 15, 2018. The proceeds are being used by MidAmerican Energy to pay construction costs, including costs for its wind-powered generation projects in Iowa, repay short-term indebtedness and for general corporate purposes. |
Credit Ratings
As of June 30, 2008, 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 certain of its subsidiaries are 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 June 30, 2008, PacifiCorp’s and MidAmerican Energy’s credit ratings from the three recognized credit rating agencies were investment grade; however if the ratings fell one rating below investment grade, the PacifiCorp and MidAmerican Energy estimated potential collateral requirements would total approximately $474 million and $169 million, respectively. Additional collateral requirements would be necessary if ratings fell further than one rating below investment grade. The potential collateral requirements could fluctuate considerably due to seasonality, market price volatility, and a loss of key generating facilities or other related factors.
30
Contractual Obligations and Commercial Commitments
Subsequent to December 31, 2007, there were no material changes outside the normal course of business in the contractual obligations and commercial commitments from the information provided in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, other than the 2008 debt issuances previously discussed. Additionally, refer to the “Capital Expenditures” discussion included in “Liquidity and Capital Resources.”
Regulatory Matters
In addition to the discussion contained herein regarding updates to regulatory matters based upon material changes that occurred subsequent to December 31, 2007, refer to Note 4 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for additional regulatory matter updates.
Federal Regulation
Northwest Power Act
The Northwest Power Act, through the Residential Exchange Program, provides access to the benefits of low-cost federal hydroelectricity to the residential and small-farm customers of the region’s investor-owned utilities. The program is administered by the Bonneville Power Administration (the ÒBPAÓ) in accordance with federal law. Pursuant to agreements between the BPA and PacifiCorp, benefits from the BPA are passed through to PacifiCorp’s Oregon, Washington and Idaho residential and small-farm customers in the form of electricity bill credits. Several publicly owned utilities, cooperatives and the BPA’s direct-service industry customers filed lawsuits against the BPA with the United States Court of Appeals for the Ninth Circuit (the ÒNinth CircuitÓ) seeking review of certain aspects of the BPA’s Residential Exchange Program, as well as challenging the level of benefits previously paid to investor-owned utility customers. In May 2007, the Ninth Circuit issued two decisions that resulted in the BPA suspending payments to the Pacific Northwest’s six utilities, including PacifiCorp. This resulted in increases to PacifiCorp’s residential and small-farm customers’ electric bills in Oregon, Washington and Idaho. In February 2008, the BPA initiated a rate proceeding under the Northwest Power Act to reconsider the level of benefits for the years 2002 through 2006 consistent with the Ninth Circuit’s decisions to re-establish the level of benefits for years 2007 and 2008 and to set the level of benefits for years 2009 and beyond. Also in February 2008, the BPA offered PacifiCorp and other investor-owned utilities an interim agreement intended to resume customer benefits pending the outcome of the rate proceeding. In March 2008, the OPUC ordered PacifiCorp to not execute the interim agreement offered by the BPA because the benefits offered were subject to true-up and acceptance of the benefits before the conclusion of the rate proceeding was not in the best interest of customers. In March and May 2008, PacifiCorp and other parties submitted testimony in the BPA rate proceeding and initial legal briefing was completed in June 2008. Because the benefit payments from the BPA are passed through to PacifiCorp’s customers, the outcome of this matter is not expected to have a significant effect on the Company’s consolidated financial results.
State Regulatory Actions
PacifiCorp is currently pursuing a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs.
Utah
In December 2007, PacifiCorp filed a general rate case with the UPSC requesting an annual increase of $161 million, or an average price increase of 11% with a test period for the forecasted twelve months ended June 2009. The increase is primarily due to increased capital spending and net power costs, both of which are driven by load growth. In February 2008, the UPSC issued an order determining that the test period should end December 2008. In March 2008, PacifiCorp filed supplemental testimony reducing the requested rate increase to $100 million. The change in the test period accounts for $40 million of the reduction. The supplemental filing also reflects an additional $21 million of reductions associated with recent UPSC orders on depreciation rate changes and two deferred accounting requests that were pending when the original case was filed. In May 2008, PacifiCorp filed rebuttal testimony that reduced the requested rate increase by an additional $15 million to $85 million. Hearings on the revenue requirement portion of the case were held in June 2008. Additional adjustments adopted at the hearings reduced the requested increase to $75 million. The rate-design phase of the case is scheduled for October 2008. PacifiCorp expects that initial rates, if approved, will become effective no later than August 13, 2008. In July 2008, PacifiCorp filed a general rate case with the UPSC requesting an annual increase of $161 million over PacifiCorp’s current rates, or an average price increase of 11%. This represents an increase of $86 million over the December 2007 pending rate request described above, or an additional average price increase of 6%. The new rates, if approved, are expected to become effective in March 2009.
31
Oregon
In April 2008, PacifiCorp filed its first annual renewable adjustment clause to recover the revenue requirement related to new renewable resources and associated transmission that are eligible under the Oregon Renewable Energy Act and are not reflected in general rates. PacifiCorp requested an annual increase of $39 million on an Oregon-allocated basis, or an average price increase of 4%. The OPUC is expected to issue a decision by November 2008, with rates effective January 1, 2009.
In July 2008, as part of its annual transition adjustment mechanism, PacifiCorp filed updated forecasted net power costs for 2009. PacifiCorp proposed a net power cost increase of $57 million on an Oregon-allocated basis, or an average price increase of 6%. The forecasted net power costs will be updated again in early November 2008 for OPUC ordered changes, changes to the forward price curve and new wholesale sales and purchases. A final update for changes in the forward price curve will be filed in November 2008. The OPUC is expected to issue a decision by November 2008, with rates effective January 1, 2009.
Wyoming
In June 2007, PacifiCorp filed a general rate case with the Wyoming Public Service Commission (the “WPSC”) requesting an annual increase of $36 million, or an average price increase of 8%. In addition, PacifiCorp requested approval of a new renewable resource recovery mechanism and a marginal cost pricing tariff to better reflect the cost of adding new generation. In January 2008, PacifiCorp reached a settlement in principle with parties to the case, subject to approval by the WPSC. The settlement provides for an annual rate increase of $23 million, or an average price increase of 5%. In addition, the parties also agreed to modify the current power cost adjustment mechanism (“PCAM”) to use forecasted power costs in the future and to terminate the PCAM by April 2011, unless a continuation is specifically applied for by PacifiCorp and approved by the WPSC. PacifiCorp’s marginal cost pricing tariff proposal will not be implemented, but will be the subject of a collaborative process to seek a new pricing proposal. Also as part of the settlement, PacifiCorp agreed to withdraw from this filing its request for a renewable resource recovery mechanism. The stipulation was approved by the WPSC in March 2008. The new rates were effective May 1, 2008.
In February 2008, PacifiCorp filed its annual PCAM application with the WPSC for costs incurred during the period December 1, 2006 through November 30, 2007. In March 2008, the WPSC approved PacifiCorp’s request on an interim basis effective April 1, 2008, resulting in a rate increase of $31 million, or an average price increase of 8%, to recover deferred power costs over a one-year period. In April 2008, PacifiCorp began collecting this interim surcharge from its Wyoming customers and will continue until the matter is either settled through negotiation with the parties or is litigated in a contested hearing, which has been scheduled for September 2008. In either case, the WPSC must approve the final surcharge and tariff.
In July 2008, PacifiCorp filed a general rate case with the WPSC requesting an annual increase of $34 million, or an average price increase of 7%, with an effective date of May 24, 2009. Power costs have been excluded from the filing and will be addressed separately in PacifiCorp’s annual PCAM application in February 2009.
32
Washington
In February 2008, PacifiCorp filed a general rate case with the WUTC for an annual increase of $35 million, or an average price increase of 15%. In August 2008, PacifiCorp filed with the WUTC an all-party settlement agreement with WUTC staff, Public Counsel, Industrial Customers of Northwest Utilities, and the Energy Project. Pursuant to the terms of the settlement, parties agreed to an overall rate increase of $20 million or 9%. If the WUTC approves the settlement, the increase will be composed of an $18 million increase to base rates and a $2 million annual surcharge for approximately three years related to recovery of higher power costs incurred in 2005 due to poor hydroelectric conditions. Recovery of these higher power costs was originally requested by PacifiCorp as a separate deferred cost filing in March 2005. The total recovery of these higher power costs will be $6 million plus interest collected over a three-year period. PacifiCorp agreed to drop the current proposal for a generation cost adjustment mechanism (“GCAM”) and further committed that PacifiCorp would not propose a GCAM in the next general rate case. A hearing on the settlement agreement is scheduled for September 2008. The new rates will be effective October 15, 2008, subject to WUTC approval.
Idaho
In June 2008, PacifiCorp filed a notice of intent to file a general rate case with the Idaho Public Utilities Commission (the “IPUC”). A notice of intent must be filed with the IPUC at least 60 days before a general rate case can be filed.
Environmental Matters
In addition to the discussion contained herein, refer to Note 8 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q and Item 1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 for additional information regarding certain environmental matters affecting PacifiCorp’s and MidAmerican Energy’s operations.
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. 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. The Iowa Department of Natural Resources recently notified emission sources, including MidAmerican Energy’s Riverside and Louisa coal-fired generating facilities, in Scott and Muscatine counties in Iowa that the two counties have not attained the fine particulate matter standard that was adopted in December 2006. It has not yet been determined if MidAmerican Energy’s facilities contribute to the nonattainment, and if they have, what impact the nonattainment designation may have on the operation of MidAmerican Energy’s facilities.
Regulated Air Pollutants
In March 2005, the EPA released the final Clean Air Interstate Rule (“CAIR”), calling for reductions of sulfur dioxide (“SO2”) and nitrogen oxide (“NOx”) emissions in the Eastern United States through, at each state’s option, a market-based cap and trade system, emission reductions, or both because of contributions to downwind nonattainment of the fine particulate matter and ozone standards. The SO2 and NOx emissions reductions were planned to be accomplished in two phases, in 2009-2010 and 2015. However, on July 11, 2008, the United States Court of Appeals for the District of Columbia Circuit held that the CAIR was fatally flawed and vacated the rule, remanding it to the EPA to consider which states are included in CAIR based on their contribution to nonattainment and connect states’ emission reductions to contributions to nonattainment in addition to distributing allowances appropriately. Given the court’s ruling, it is unknown when reductions in emissions of SO2 and NOx will be required or the level of any required reductions on MidAmerican Energy’s generation facilities. PacifiCorp’s generation facilities are not subject to the CAIR. Under the CAIR, a market for trading SO2 and NOx emission credits developed. As a result of the rule being vacated, that market has been adversely affected and the value of credits has declined. While MidAmerican Energy participated in the market for SO2 credits, management does not expect any impact from these market declines to be material to the Company.
33
The emissions reductions could be 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, NOX and mercury, as well as carbon dioxide and other gases that may affect global climate change.
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. In accordance with the federal requirements, states were required to submit state implementation plans by December 2007 to demonstrate reasonable progress toward achieving natural visibility conditions in certain Class I areas by requiring emission controls, known as best available retrofit technology (“BART”), on sources with emissions that are anticipated to cause or contribute to impairment of visibility. Iowa submitted its state implementation plan to the EPA by December 2007 and suggested that the emission reductions already made by MidAmerican Energy and additional reductions that will be made under the CAIR place the state in the position that no further reductions should be required. However, because the court has vacated the CAIR, emissions reductions could be required under the regional haze provisions at MidAmerican Energy’s BART-eligible sources. Until the outcome of the CAIR or its replacement is better known, it is not known whether emissions reductions will be required under this provision.
Renewable Portfolio Standards
In March 2008, Utah’s governor signed Utah Senate Bill 202, “Energy Resource and Carbon Emission Reduction Initiative.” Among other things, this law provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and demand-side management programs. Qualifying renewable energy sources can be located anywhere in the Western Electricity Coordinating Council areas, and renewable energy credits can be used. The costs of complying with the law will be a system cost and are expected to be recovered in retail rates in all states served, either through rate cases or adjustment mechanisms.
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 1 of this Form 10-Q.
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 Consolidated 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 Consolidated Financial Statements will likely increase or decrease in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets and goodwill, pension and postretirement obligations, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company’s critical accounting policies, see Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007. The Company’s critical accounting policies have not changed materially since December 31, 2007.
34
Quantitative and Qualitative Disclosures About Market Risk |
For quantitative and qualitative disclosures about market risk affecting the Company, see Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007. The Company’s exposure to market risk and its management of such risk has not changed materially since December 31, 2007. Refer to Note 6 of Notes to Consolidated Financial Statements included in Item 1 of this Form 10-Q for disclosure of the Company’s derivative positions as of June 30, 2008 and December 31, 2007.
Controls and Procedures |
At the end of the period covered by this Quarterly Report on Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon that evaluation, the Company’s management, including the Chief Executive Officer (principal executive officer) and the Chief Financial Officer (principal financial officer), concluded that the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to management, including the Company’s Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in the Company’s internal control over financial reporting during the quarter ended June 30, 2008 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
35
PART II – OTHER INFORMATION
Legal Proceedings |
For a description of certain legal proceedings affecting the Company, refer to Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 and Part II, Item 1 of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2008. In addition to the discussion contained herein regarding material developments to legal proceedings, refer to Note 8 of Notes to Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q.
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 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 United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) and briefing was completed in March 2006. In February 2008, the Ninth Circuit affirmed the District Court’s 2005 decisions dismissing the case. In May 2008, the plaintiffs filed a petition requesting review by the U.S. Supreme Court. PacifiCorp filed a brief in opposition to the petition in June 2008. PacifiCorp believes the outcome of this proceeding will not have a material impact on its consolidated financial results.
Risk Factors |
There has been no material change to the Company’s risk factors from those disclosed in Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007.
Unregistered Sales of Equity Securities and Use of Proceeds |
Not applicable.
Defaults Upon Senior Securities |
Not applicable.
Submission of Matters to a Vote of Security Holders |
Not applicable.
Other Information |
Not applicable.
Exhibits |
The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.
36
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
MIDAMERICAN ENERGY HOLDINGS COMPANY | |
(Registrant) | |
Date: August 8, 2008 | /s/ Patrick J. Goodman |
Patrick J. Goodman | |
Senior Vice President and Chief Financial Officer | |
(principal financial and accounting officer) |
37
Exhibit No. | Description |
15 | Awareness Letter of Independent Registered Public Accounting Firm. |
31.1 | Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.2 | Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.1 | Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.2 | Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
38