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 March 31, 2006
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ______ to _______
Commission File No. 001-14881
MIDAMERICAN ENERGY HOLDINGS COMPANY
(Exact name of registrant as specified in its charter)
Iowa | 94-2213782 | |
(State or other jurisdiction of | (I.R.S. Employer | |
incorporation or organization) | Identification No.) | |
666 Grand Avenue, Des Moines, Iowa | 50309 | |
(Address of principal executive offices) | (Zip Code) | |
(515) 242-4300 | ||
(Registrant’s telephone number, including area code) | ||
(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 ¨ No T
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See the definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer T
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ¨ 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 May 1, 2006, 74,164,001 shares of common stock were outstanding.
TABLE OF CONTENTS
PART I - FINANCIAL INFORMATION
Item 1. | Financial Statements | 3 |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 26 |
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 42 |
Item 4. | Controls and Procedures | 45 |
PART II - OTHER INFORMATION | ||
Item 1. | Legal Proceedings | 46 |
Item 1A. | Risk Factors | 47 |
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 47 |
Item 3. | Defaults Upon Senior Securities | 47 |
Item 4. | Submission of Matters to a Vote of Security Holders | 47 |
Item 5. | Other Information | 47 |
Item 6. | Exhibits | 47 |
Signatures | 48 | |
Exhibit Index | 49 |
2
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
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 March 31, 2006, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the three-month periods ended March 31, 2006 and 2005. 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, 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended (not presented herein); and in our report dated March 3, 2006, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2005 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
May 4, 2006
3
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
As of | |||||||
March 31, | December 31, | ||||||
2006 | 2005 | ||||||
(Unaudited) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 709.1 | $ | 357.9 | |||
Short-term investments | 44.5 | 38.4 | |||||
Restricted cash and short-term investments | 91.2 | 102.9 | |||||
Accounts receivable, net | 1,183.4 | 802.6 | |||||
Amounts held in trust | 142.0 | 108.5 | |||||
Inventories | 296.5 | 128.2 | |||||
Derivative contracts | 244.2 | 54.0 | |||||
Deferred income taxes | 151.2 | 177.7 | |||||
Other current assets | 206.0 | 140.1 | |||||
Total current assets | 3,068.1 | 1,910.3 | |||||
Properties, plants and equipment, net | 22,056.8 | 11,915.4 | |||||
Goodwill | 5,245.0 | 4,156.2 | |||||
Regulatory assets | 1,815.8 | 441.1 | |||||
Other investments | 937.4 | 798.7 | |||||
Derivative contracts | 350.0 | 6.1 | |||||
Deferred charges and other assets | 1,368.7 | 1,142.9 | |||||
Total assets | $ | 34,841.8 | $ | 20,370.7 |
The accompanying notes are an integral part of these financial statements.
4
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Amounts in millions)
As of | |||||||
March 31, | December 31, | ||||||
2006 | 2005 | ||||||
(Unaudited) | |||||||
LIABILITIES AND STOCKHOLDERS' EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 745.9 | $ | 523.6 | |||
Accrued interest | 268.5 | 198.3 | |||||
Accrued property and other taxes | 270.8 | 189.1 | |||||
Amounts held in trust | 142.0 | 108.5 | |||||
Derivative contracts | 146.6 | 61.7 | |||||
Other liabilities | 629.0 | 389.3 | |||||
Short-term debt | 191.9 | 70.1 | |||||
Current portion of long-term debt | 526.5 | 313.7 | |||||
Current portion of parent company subordinated debt | 234.0 | 234.0 | |||||
Total current liabilities | 3,155.2 | 2,088.3 | |||||
Other long-term accrued liabilities | 1,097.1 | 766.9 | |||||
Regulatory liabilities | 1,577.8 | 773.9 | |||||
Pension and postretirement obligations | 1,436.4 | 633.3 | |||||
Derivative contracts | 564.6 | 106.8 | |||||
Parent company senior debt | 4,476.3 | 2,776.2 | |||||
Parent company subordinated debt | 1,354.7 | 1,354.1 | |||||
Subsidiary and project debt | 10,599.5 | 6,836.6 | |||||
Deferred income taxes | 3,295.2 | 1,539.6 | |||||
Total liabilities | 27,556.8 | 16,875.7 | |||||
Minority interest | 73.4 | 21.4 | |||||
Preferred securities of subsidiaries | 129.4 | 88.4 | |||||
Commitments and contingencies (Note 8) | |||||||
Stockholders' equity: | |||||||
Zero-coupon convertible preferred stock - no shares authorized, issued or outstanding at March 31, 2006; 50.0 shares authorized, no par value, 41.3 shares issued and outstanding at December 31, 2005 | - | - | |||||
Common stock - 115.0 shares authorized, no par value, 74.2 shares issued and outstanding at March 31, 2006; 60.0 shares authorized, no par value, 9.3 shares issued and outstanding at December 31, 2005 | - | - | |||||
Additional paid-in capital | 5,393.6 | 1,963.3 | |||||
Retained earnings | 1,930.6 | 1,719.5 | |||||
Accumulated other comprehensive loss, net | (242.0 | ) | (297.6 | ) | |||
Total stockholders' equity | 7,082.2 | 3,385.2 | |||||
Total liabilities and stockholders' equity | $ | 34,841.8 | $ | 20,370.7 |
The accompanying notes are an integral part of these financial statements.
5
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
Three-Month Periods | |||||||
Ended March 31, | |||||||
2006 | 2005 | ||||||
(Unaudited) | |||||||
Operating revenue | $ | 2,054.6 | $ | 1,804.2 | |||
Costs and expenses: | |||||||
Cost of sales | 954.1 | 812.7 | |||||
Operating expense | 450.0 | 407.3 | |||||
Depreciation and amortization | 188.0 | 159.6 | |||||
Total costs and expenses | 1,592.1 | 1,379.6 | |||||
Operating income | 462.5 | 424.6 | |||||
Other income (expense): | |||||||
Interest expense | (221.7 | ) | (231.6 | ) | |||
Capitalized interest | 4.6 | 3.6 | |||||
Interest and dividend income | 15.3 | 8.4 | |||||
Other income | 122.9 | 21.0 | |||||
Other expense | (1.2 | ) | (3.3 | ) | |||
Total other income (expense) | (80.1 | ) | (201.9 | ) | |||
Income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income | 382.4 | 222.7 | |||||
Income tax expense | 131.2 | 74.0 | |||||
Minority interest and preferred dividends of subsidiaries | 4.0 | 2.9 | |||||
Income from continuing operations before equity income | 247.2 | 145.8 | |||||
Equity income | 1.8 | 4.9 | |||||
Income from continuing operations | 249.0 | 150.7 | |||||
Income from discontinued operations, net of income tax | - | 1.7 | |||||
Net income available to common and preferred stockholders | $ | 249.0 | $ | 152.4 |
The accompanying notes are an integral part of these financial statements.
6
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
FOR THE THREE-MONTH PERIODS ENDED MARCH 31, 2006 AND 2005
(Unaudited)
(Amounts in millions)
Accumulated | |||||||||||||||||||
Outstanding | Additional | Other | |||||||||||||||||
Common | Common | Paid-in | Retained | Comprehensive | |||||||||||||||
Shares | Stock | Capital | Earnings | Loss | Total | ||||||||||||||
Balance, January 1, 2005 | 9.0 | $ | - | $ | 1,950.7 | $ | 1,156.8 | $ | (136.3 | ) | $ | 2,971.2 | |||||||
Net income | - | - | - | 152.4 | - | 152.4 | |||||||||||||
Other comprehensive income: | |||||||||||||||||||
Foreign currency translation adjustment | - | - | - | - | (24.3 | ) | (24.3 | ) | |||||||||||
Fair value adjustment on cash flow hedges, net of tax of $(2.7) | - | - | - | - | (5.9 | ) | (5.9 | ) | |||||||||||
Minimum pension liability adjustment, net of tax of $(0.5) | - | - | - | - | 0.4 | 0.4 | |||||||||||||
Unrealized losses on securities, net of tax of $(0.1) | - | - | - | - | (0.1 | ) | (0.1 | ) | |||||||||||
Total comprehensive income | 122.5 | ||||||||||||||||||
Balance, March 31, 2005 | 9.0 | $ | - | $ | 1,950.7 | $ | 1,309.2 | $ | (166.2 | ) | $ | 3,093.7 | |||||||
Balance, January 1, 2006 | 9.3 | $ | - | $ | 1,963.3 | $ | 1,719.5 | $ | (297.6 | ) | $ | 3,385.2 | |||||||
Net income | - | - | - | 249.0 | - | 249.0 | |||||||||||||
Other comprehensive income: | |||||||||||||||||||
Foreign currency translation adjustment | - | - | - | - | 16.2 | 16.2 | |||||||||||||
Fair value adjustment on cash flow hedges, net of tax of $25.1 | - | - | - | - | 40.4 | 40.4 | |||||||||||||
Minimum pension liability adjustment, net of tax of $(0.9) | - | - | - | - | (2.0 | ) | (2.0 | ) | |||||||||||
Unrealized gains on securities, net of tax of $0.6 | - | - | - | - | 1.0 | 1.0 | |||||||||||||
Total comprehensive income | 304.6 | ||||||||||||||||||
Preferred stock conversion to common stock | 41.3 | - | - | - | - | - | |||||||||||||
Exercise of common stock options | 0.5 | - | 13.1 | - | - | 13.1 | |||||||||||||
Tax benefit from exercise of common stock options | - | - | 19.8 | - | - | 19.8 | |||||||||||||
Common stock issuances | 35.2 | - | 5,109.5 | - | - | 5,109.5 | |||||||||||||
Common stock purchases | (12.1 | ) | - | (1,712.1 | ) | (37.9 | ) | - | (1,750.0 | ) | |||||||||
Balance, March 31, 2006 | 74.2 | $ | - | $ | 5,393.6 | $ | 1,930.6 | $ | (242.0 | ) | $ | 7,082.2 |
The accompanying notes are an integral part of these financial statements.
7
MIDAMERICAN ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
Three-Month Periods | |||||||
Ended March 31, | |||||||
2006 | 2005 | ||||||
(Unaudited) | |||||||
Cash flows from operating activities: | |||||||
Income from continuing operations | $ | 249.0 | $ | 150.7 | |||
Adjustments to reconcile income from continuing operations to cash flows from continuing operations: | |||||||
Distributions less income on equity investments | 1.1 | (1.5 | ) | ||||
Gain on other items, net | (97.9 | ) | (6.7 | ) | |||
Depreciation and amortization | 188.0 | 159.6 | |||||
Amortization of regulatory assets and liabilities | 6.7 | 20.6 | |||||
Amortization of deferred financing costs | 4.1 | 7.9 | |||||
Provision for deferred income taxes | 102.8 | 45.7 | |||||
Other | (41.6 | ) | 14.2 | ||||
Changes in other items, net of effects from acquisitions: | |||||||
Accounts receivable and other current assets | 178.9 | 53.3 | |||||
Accounts payable and other accrued liabilities | (93.0 | ) | (53.3 | ) | |||
Deferred income | (2.7 | ) | (1.7 | ) | |||
Net cash flows from continuing operations | 495.4 | 388.8 | |||||
Net cash flows from discontinued operations | - | (0.2 | ) | ||||
Net cash flows from operating activities | 495.4 | 388.6 | |||||
Cash flows from investing activities: | |||||||
PacifiCorp acquisition, net of cash acquired | (4,932.5 | ) | - | ||||
Other acquisitions, net of cash acquired | (10.6 | ) | (0.7 | ) | |||
Capital expenditures relating to operating projects | (244.6 | ) | (164.9 | ) | |||
Construction and other development costs | (64.0 | ) | (63.4 | ) | |||
Purchases of available-for-sale securities | (398.7 | ) | (680.2 | ) | |||
Proceeds from sale of available-for-sale securities | 466.3 | 683.7 | |||||
Other | 15.7 | 30.1 | |||||
Net cash flows from continuing operations | (5,168.4 | ) | (195.4 | ) | |||
Net cash flows from discontinued operations | - | 2.8 | |||||
Net cash flows from investing activities | (5,168.4 | ) | (192.6 | ) | |||
Cash flows from financing activities: | |||||||
Issuances of common stock | 5,122.6 | - | |||||
Purchases of common stock | (1,750.0 | ) | - | ||||
Proceeds from parent company senior debt | 1,699.3 | - | |||||
Proceeds from subsidiary and project debt | 2.3 | 6.1 | |||||
Repayments of subsidiary and project debt | (34.0 | ) | (433.8 | ) | |||
Net proceeds from (repayments of) subsidiary short-term debt | (11.5 | ) | 0.1 | ||||
Net repayments of parent company revolving credit facility | (51.0 | ) | - | ||||
Net proceeds from settlement of treasury rate lock agreements | 53.0 | - | |||||
Other | (6.6 | ) | (1.5 | ) | |||
Net cash flows from continuing operations | 5,024.1 | (429.1 | ) | ||||
Net cash flows from discontinued operations | - | 0.2 | |||||
Net cash flows from financing activities | 5,024.1 | (428.9 | ) | ||||
Effect of exchange rate changes | 0.1 | (5.5 | ) | ||||
Net change in cash and cash equivalents | 351.2 | (238.4 | ) | ||||
Cash and cash equivalents at beginning of period | 357.9 | 837.3 | |||||
Cash and cash equivalents at end of period | $ | 709.1 | $ | 598.9 |
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 |
The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and the instructions for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of the management of MidAmerican Energy Holdings Company and subsidiaries (“MEHC” or the “Company”), the unaudited consolidated financial statements contain all adjustments, including normal recurring items, considered necessary for a fair presentation of the financial position as of March 31, 2006 and the results of operations, the changes in stockholders’ equity and the cash flows for the three-month periods ended March 31, 2006 and 2005. The results of operations for the three-month period ended March 31, 2006 are not necessarily indicative of the results to be expected for the full year.
Preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the period. Management believes the most complex and sensitive judgments, because of their significance to the consolidated financial statements, result primarily from the need to make estimates about the effects of matters that are inherently uncertain. Actual results could differ materially from management’s estimates. Management’s Discussion and Analysis and Note 2 to the consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, describe the most significant accounting estimates and policies used in preparation of the consolidated financial statements. There have been no significant changes in the Company’s assumptions regarding critical accounting estimates during the first three months of 2006.
The unaudited consolidated financial statements include the accounts of MEHC and its wholly-owned subsidiaries, except for certain trusts formed to hold trust preferred securities which were deconsolidated under Financial Accounting Standards Board Interpretation No. 46R, “Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51.” Subsidiaries which are less than 100% owned but greater than 50% owned are consolidated with a minority interest. Subsidiaries that are 50% owned or less, but where the Company has the ability to exercise significant influence, are accounted for under the equity method of accounting. All inter-enterprise transactions and accounts have been eliminated. The results of operations of the Company include the Company’s proportionate share of results of operations of entities acquired from the date of each acquisition for purchase business combinations.
Berkshire Hathaway, Inc. (“Berkshire Hathaway”) currently owns 88.2% (86.6% on a diluted basis) of the outstanding common stock of MEHC. 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, CalEnergy Generation-Domestic and HomeServices of America, Inc. (“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 natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.
Certain amounts in the prior period consolidated financial statements and supporting note disclosures have been reclassified to conform to the current period presentation. Such reclassifications did not impact previously reported net income or retained earnings. As of December 31, 2005, the Company reclassified $1.6 billion of accumulated depreciation related to the acquisitions of the Northern Natural Gas and Kern River from property to accumulated depreciation to conform to its current period presentation.
9
2. | PacifiCorp Acquisition |
On March 21, 2006, a wholly-owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp from a wholly-owned subsidiary of Scottish Power plc for a cash purchase price of $5,109.5 million, which was funded through the issuance of common stock (see Note 3). MEHC also incurred $10.7 million of direct transaction costs associated with the acquisition, which consisted principally of investment banker commissions and outside legal and accounting fees and expenses, resulting in a total purchase price of $5,120.2 million. As a result of the acquisition, MEHC controls the significant majority of PacifiCorp’s voting securities, which include both common and preferred stock. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006.
PacifiCorp is a regulated electric utility company serving approximately 1.6 million residential, commercial and industrial customers in service territories aggregating approximately 136,000 square miles in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The regulatory commissions in each state approve rates for retail electric sales within their respective states. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and to incorporated municipalities. Wholesale activities are regulated by the Federal Energy Regulatory Commission (“FERC”). As of March 31, 2006, PacifiCorp owns, or has interests in, 69 thermal, hydroelectric and wind generating plants, with an aggregate nameplate rating of 9,050.8 MW and plant net capability of 8,470.4 MW.
Allocation of Purchase Price
Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations” requires that the total purchase price be allocated to PacifiCorp’s net tangible and identified intangible assets acquired and liabilities assumed based on their estimated fair values as of the acquisition date. PacifiCorp’s operations are regulated, which provide revenue derived from cost, and are accounted for pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (“SFAS 71”). PacifiCorp has demonstrated a past history of recovering its costs incurred through its rate making process. Given the size and timing of the acquisition, the fair values set forth below are preliminary and are subject to adjustment as additional information is obtained. When finalized, adjustments to goodwill may result. The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed as of the acquisition date (in millions).
Preliminary | ||||
Fair Value | ||||
Current assets, including cash and cash equivalents of $182.5 | $ | 1,115.3 | ||
Properties, plants and equipment, net | 10,050.9 | |||
Goodwill | 1,074.3 | |||
Regulatory assets | 1,398.2 | |||
Other non-current assets | 659.5 | |||
Current liabilities, including short-term debt of $184.4 and current portion of long-term debt of $220.6 | (1,255.8 | ) | ||
Regulatory liabilities | (816.3 | ) | ||
Pension and postretirement obligations | (826.8 | ) | ||
Subsidiary and project debt, less current portion | (3,762.3 | ) | ||
Deferred income taxes | (1,681.9 | ) | ||
Other non-current liabilities | (834.9 | ) | ||
Net assets acquired | $ | 5,120.2 |
The Company has not identified any material pre-acquisition contingencies where the related asset, liability or impairment is probable and the amount of the asset, liability or impairment can be reasonably estimated. Prior to the end of the purchase price allocation period, if information becomes available that a pre-acquisition related loss had been incurred and the amounts can be reasonably estimated, such items will be included in the purchase price allocation.
Certain transition activities will occur as PacifiCorp is integrated into the Company. Costs, consisting primarily of employee termination activities, will be incurred associated with such transition activities. The Company is in the process of finalizing these plans and expects to execute these plans over the next several months. In accordance with Emerging Issues Task Force Issue No. 95-3, “Recognition of Liabilities in Connection with a Purchase Business Combination” (“EITF 95-3”), the finalization of certain integration plans will result in adjustments to the purchase price allocation for the acquired assets and assumed liabilities of PacifiCorp. Severance costs accrued pursuant to EITF 95-3 totaled $8.8 million at March 31, 2006. Transition costs that do not meet the criteria in EITF 95-3 are expensed in the period incurred.
10
Properties, Plants and Equipment, Net
The fair values of properties, plants and equipment, net as of the acquisition date are as follows (in millions):
Ranges of Estimated | Preliminary | ||||||
Useful Life | Fair Value | ||||||
Utility generation and distribution system, net | 5-85 years | $ | 9,314.0 | ||||
Other assets, net | 5-30 years | 8.9 | |||||
Construction in progress(1) | 728.0 | ||||||
Total properties, plants and equipment, net | $ | 10,050.9 |
(1) - Includes $173.5 million related to the Currant Creek Power Plant, a 523 MW combined cycle plant in Utah that went into service on March 22, 2006.
Goodwill
The excess of the purchase price paid over the estimated fair values of the identifiable assets acquired and liabilities assumed totaled $1,074.3 million and was allocated as goodwill to the PacifiCorp reportable segment. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” goodwill is not amortized, but rather is reviewed annually for impairment or more frequently if indicators of impairment exist. In accordance with SFAS No. 109, “Accounting for Income Taxes,” a deferred tax liability was not recorded on the goodwill since it is not tax deductible.
The recognition of goodwill from the acquisition of PacifiCorp resulted from various attributes of PacifiCorp’s operations and business in general. There is no assurance that these attributes will continue to exist to the same degree as believed at the time of the acquisition. These attributes include, but are not limited to:
· | Ability to improve operational results through the prudent deployment of capital; |
· | Operates in six states providing regulatory and geographic diversity; |
· | Ability to improve regulatory relationships and develop customer solutions; |
· | Low-cost competitive position; |
· | Generation and fuel diversification, including: |
§ | The operation of coal generation; |
§ | The operation of several coal mines contributing to low-cost supply and supply certainty; |
§ | Access to multiple gas suppliers; and |
§ | Low-cost hydroelectric generation; |
· | Strong customer service reputation; and |
· | Significant customer and load growth opportunities. |
Regulatory Assets and Liabilities
The fair values of regulatory assets as of the acquisition date are as follows (in millions):
Preliminary | ||||
Fair Value | ||||
Pension and postretirement benefits | $ | 684.5 | ||
Deferred income taxes | 480.3 | |||
Derivative contracts(1) | 94.7 | |||
Other | 138.7 | |||
Total regulatory assets | $ | 1,398.2 |
(1) | Represents net unrealized losses related to derivative contracts included in rates as of the acquisition date. |
As of the acquisition date, PacifiCorp had $1,372.1 million of regulatory assets not included in rate base and, therefore, not earning a return. PacifiCorp evaluates the recovery of all regulatory assets periodically and as events occur. The evaluation includes the probability of recovery as well as changes in the regulatory environment. Regulatory and/or legislative action in Utah, Oregon, Wyoming, Washington, Idaho and California may require PacifiCorp to record regulatory asset write-offs and charges for impairment of long-lived assets in future periods.
11
The fair values of regulatory liabilities as of the acquisition date are as follows (in millions):
Preliminary | ||||
Fair Value | ||||
Asset retirement removal costs | $ | 711.4 | ||
Deferred income taxes | 43.7 | |||
Other | 61.2 | |||
Total regulatory liabilities | $ | 816.3 |
Derivative Instruments
In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, PacifiCorp records derivative instruments as assets or liabilities measured at estimated fair value, unless they qualify for the exemptions afforded by SFAS 133. PacifiCorp uses derivative instruments (primarily forward purchases and sales) to manage the commodity price risk inherent in its fuel and electricity obligations, as well as to optimize the value of power generation assets and related contracts.
The contracts that qualify as normal purchases and normal sales are not subject to the requirements of SFAS 133 and are therefore not marked-to-market. The realized gains and losses on these contracts are reflected in the consolidated statements of operations at the contract settlement date.
Unrealized gains and losses on derivative contracts held for trading purposes are presented on a net basis in the consolidated statements of operations as operating revenue. Unrealized gains and losses on derivative contracts not held for trading purposes are presented on a gross basis in the consolidated statements of operations as operating revenue for sales contracts and as cost of sales and operating expense for purchase contracts and financial swaps. Certain derivative contracts utilized by PacifiCorp are recoverable through retail rates. Accordingly, unrealized changes in fair value of these contracts are deferred as regulatory assets or liabilities pursuant to SFAS 71.
PacifiCorp has the following types of commodity transactions:
Wholesale electricity purchase and sales contracts - PacifiCorp makes continuing projections of future retail and wholesale loads and future resource availability to meet these loads based on a number of criteria, including historical load and forward market and other economic information and experience. Based on these projections, PacifiCorp purchases and sells electricity on a forward yearly, quarterly, monthly, daily and hourly basis to match actual resources to actual energy requirements and sells any surplus at the prevailing market price. This process involves hedging transactions, which include the purchase and sale of firm energy under long-term contracts, forward physical contracts or financial contracts for the purchase and sale of a specified amount of energy at a specified price over a given period of time.
Natural gas and other fuel purchase contracts - PacifiCorp manages its natural gas supply requirements by entering into forward commitments for physical delivery of natural gas. PacifiCorp also manages its exposure to increases in natural gas supply costs through forward commitments for the purchase of physical natural gas at fixed prices and financial swap contracts that settle in cash based on the difference between a fixed price that PacifiCorp pays and a floating market-based price that PacifiCorp receives.
The fair values of derivative instruments as of the acquisition date are as follows (in millions):
Preliminary Fair Value | ||||||||||
Non-Trading | Trading | Total | ||||||||
Maturity: | ||||||||||
Less than 1 year | $ | 123.6 | $ | 0.2 | $ | 123.8 | ||||
1-3 years | 132.6 | - | 132.6 | |||||||
4-5 years | 10.9 | - | 10.9 | |||||||
Excess of 5 years | (259.4 | ) | - | (259.4 | ) | |||||
Total | $ | 7.7 | $ | 0.2 | $ | 7.9 | ||||
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Reflected as: | ||||||||||
Current asset | $ | 221.7 | ||||||||
Non-current asset | 345.3 | |||||||||
Current liability | (97.9 | ) | ||||||||
Non-current liability | (461.2 | ) | ||||||||
Total | $ | 7.9 |
Short-Term and Long-Term Debt
The fair values of short-term and long-term debt as of the acquisition date are as follows (in millions):
Average | Preliminary | ||||||
Interest Rate | Fair Value | ||||||
Short-term debt - notes payable and commercial paper | 4.8 | % | $ | 184.4 | |||
Long-term debt: | |||||||
First mortgage bonds - | |||||||
4.3% to 8.8%, due through 2011 | 6.0 | $ | 901.7 | ||||
5.0% to 9.2%, due 2012 to 2016 | 6.5 | 1,040.4 | |||||
8.5% to 8.6%, due 2017 to 2021 | 8.5 | 5.0 | |||||
6.7% to 8.5%, due 2022 to 2026 | 7.4 | 424.0 | |||||
5.3% to 7.7%, due 2032 to 2036 | 6.3 | 800.0 | |||||
Guaranty of pollution-control revenue bonds - | |||||||
Variable rates, due 2014 | 3.1 | 40.7 | |||||
Variable rates, due 2014 to 2026 | 3.2 | 325.2 | |||||
Variable rates, due 2025 | 3.2 | 175.8 | |||||
3.4% to 5.7%, due 2014 to 2026 | 4.5 | 184.0 | |||||
6.2%, due 2031 | 6.2 | 12.7 | |||||
Preferred stock subject to mandatory redemption | - | 45.0 | |||||
Other | 11.7 | % | 28.4 | ||||
3,982.9 | |||||||
Less current portion | (220.6 | ) | |||||
Total long-term debt | $ | 3,762.3 |
The annual repayments of the long-term debt are as follows: remaining nine months of 2006 - $214.7 million; 2007 - $167.7 million; 2008 - $410.4 million; 2009 - $142.2 million; 2010 - $15.8 million; and $3,039.5 thereafter. Unamortized debt discounts and funds held by trustees totaled $7.4 million at March 21, 2006.
Additionally, PacifiCorp has in place an $800.0 million committed bank revolving credit agreement expiring on August 29, 2010. The credit agreement carries an interest rate that is generally based on LIBOR plus a margin that varies based on PacifiCorp’s credit ratings and requires that PacifiCorp’s ratio of consolidated debt to total capitalization not exceed 0.65 to 1. PacifiCorp was in compliance with all covenants related to its revolving credit agreement as of the acquisition date.
Pension and Postretirement Obligations
PacifiCorp sponsors defined benefit pension plans that cover the majority of its employees. In addition, certain bargaining unit employees participate in a joint trust plan to which PacifiCorp contributes. Benefits under the main plan are based on final average pay formulas. Pension costs are funded annually by no more than the maximum amount that can be deducted for federal income tax purposes.
PacifiCorp also provides health care and life insurance benefits through various plans for eligible retirees. The cost of other postretirement benefits is accrued over the active service period of employees. PacifiCorp funds other postretirement benefits through a combination of funding vehicles.
The measurement date for plan assets and obligations for the pension and postretirement benefit plans is December 31 of each year. The weighted-average discount rate and rate of increase in compensation levels assumed in the actuarial calculations used to determine benefit obligations for the pension and postretirement benefit plans were 5.75% and 4.00%, respectively, as of the most recent measurement date.
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The projected benefit obligation, value of plan assets and funded status of the pension and postretirement benefit plans as of the acquisition date are as follows:
Post- | |||||||
Pension | Retirement | ||||||
Projected benefit obligation | $ | (1,338.5 | ) | $ | (581.9 | ) | |
Plan assets at fair value | 824.9 | 292.1 | |||||
Funded status | $ | (513.6 | ) | $ | (289.8 | ) |
The pension plan aggregated accumulated benefit obligation was $1,170.9 million and the fair value of assets was $828.6 million, measured as of December 31, 2005, and included contributions prior to the acquisition date. Included in the pension plan obligations are the PacifiCorp Retirement Plan (the “Retirement Plan”) and the Supplemental Executive Retirement Plan (the “SERP”), which currently have assets with a fair value that is less than the accumulated benefit obligation under the Retirement Plan and the SERP, primarily due to declines in the equity markets and historically low interest rate levels. Through the purchase price allocation, the resulting minimum pension liabilities were adjusted to the funded status of each plan and represent the pension and postretirement obligations as of the acquisition date. PacifiCorp continues to recover substantially all of its pension and postretirement costs based on actuarial calculations utilizing pre-acquisition values.
Although the SERP had no qualified assets as of the acquisition date, PacifiCorp has a Rabbi trust that holds corporate-owned life insurance and other investments to provide funding for the future cash requirements of the SERP. Because this plan is nonqualified, the assets in the Rabbi trust are not considered plan assets. The cash surrender value of all of the policies included in the Rabbi trust plus the fair market value of other Rabbi trust investments was $36.4 million at the acquisition date, net of amounts borrowed against the cash surrender value.
Deferred Income Taxes
The net deferred tax liability as of the acquisition date consists of the following (in millions):
Deferred tax assets: | ||||
Regulatory liabilities | $ | 316.9 | ||
Employee benefits | 170.8 | |||
Other | 178.6 | |||
Total deferred tax assets | 666.3 | |||
Deferred tax liabilities: | ||||
Property, plant and equipment | 1,591.0 | |||
Regulatory assets | 658.9 | |||
Other | 115.2 | |||
Total deferred tax liabilities | 2,365.1 | |||
Net deferred tax liability | $ | 1,698.8 | ||
Reflected as: | ||||
Current liability | $ | 16.9 | ||
Non-current liability | 1,681.9 | |||
$ | 1,698.8 |
Pro Forma Financial Information
The following pro forma condensed consolidated results of operations assume that the acquisition of PacifiCorp was completed as of January 1, 2006 and 2005, respectively (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2006 | 2005 | ||||||
Operating revenue | $ | 3,207.0 | $ | 2,426.3 | |||
Net income available to common and preferred stockholders | $ | 385.8 | $ | 239.9 |
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The pro forma financial information represents the historical operating results of the combined company with adjustments for purchase accounting and is not necessarily indicative of the results of operations that would have been achieved if the acquisition had taken place at the beginning of each period presented.
3. | Stockholders’ Equity and Related Party Transactions |
On February 9, 2006, following the effective date of the repeal of the Public Utility Holding Company Act of 1935, Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par zero-coupon convertible preferred stock into an equal number of shares of MEHC’s common stock. As a consequence, Berkshire Hathaway owns in excess of 80.0% of both the outstanding common stock and voting securities of MEHC, consolidates the Company in its financial statements as a majority-owned subsidiary, and includes the Company in its consolidated federal U.S. income tax return.
On March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement (the “Berkshire Equity Commitment”) pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of common equity of MEHC upon any requests authorized from time to time by the Board of Directors of MEHC. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of the Company’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request. The Berkshire Equity Commitment will expire on February 28, 2011, was not used for the PacifiCorp acquisition and will not be used for other future acquisitions.
On March 2, 2006, MEHC amended its Articles of Incorporation to (i) increase the amount of its common stock authorized for issuance to 115.0 million shares and (ii) no longer provide for the authorization to issue any preferred stock of MEHC.
On March 6, 2006, Mr. David L. Sokol, Chairman and Chief Executive Officer of MEHC, exercised 450,000 common stock options having an exercise price of $29.01 per share. Additionally, Mr. Sokol put 344,274 shares of common stock to MEHC for a purchase price of $50.0 million.
On March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing stockholders and related companies invested $5,109.5 million, in the aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide equity funding for the PacifiCorp acquisition (see Note 2). The per share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by MEHC’s stockholders.
On March 28, 2006, MEHC purchased 11,724,138 shares of common stock from Berkshire Hathaway for an aggregate purchase price of $1,700.0 million.
As of January 1, 2006, the Company adopted SFAS No. 123R, “Share-Based Payment” (“SFAS 123R”). Adoption of SFAS 123R did not effect the Company’s financial position, results of operations or cash flows as all of the Company’s outstanding stock options were fully vested on January 1, 2006. Modifications to outstanding stock options after January 1, 2006 may result in additional compensation expense pursuant to the provisions of SFAS 123R.
At both March 31, 2006 and December 31, 2005, Berkshire Hathaway and its affiliates owned 11% mandatory redeemable preferred securities due from certain wholly-owned subsidiary trusts of MEHC of $1,289.2 million. Interest expense was $35.5 million and $40.6 million, respectively, for the three-month periods ended March 31, 2006 and 2005.
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4. | Properties, Plants and Equipment, Net |
Properties, plants and equipment, net consist of the following (in millions):
Ranges of | As of | |||||||||
Estimated | March 31, | December 31, | ||||||||
Useful Life | 2006 | 2005 | ||||||||
Utility generation and distribution system | 5-85 years | $ | 25,810.9 | $ | 10,499.1 | |||||
Interstate pipeline assets | 3-67 years | 5,212.7 | 5,321.8 | |||||||
Independent power plants | 10-30 years | 1,384.9 | 1,384.6 | |||||||
Other assets | 3-30 years | 466.9 | 476.5 | |||||||
Total operating assets | 32,875.4 | 17,682.0 | ||||||||
Accumulated depreciation and amortization | (12,269.6 | ) | (6,614.2 | ) | ||||||
Net operating assets | 20,605.8 | 11,067.8 | ||||||||
Construction in progress | 1,451.0 | 847.6 | ||||||||
Properties, plants and equipment, net | $ | 22,056.8 | $ | 11,915.4 |
The utility generation and distribution system and interstate pipeline assets are the regulated assets of PacifiCorp, MidAmerican Funding, Northern Natural Gas, Kern River and CE Electric UK. At March 31, 2006 and December 31, 2005, accumulated depreciation and amortization related to the Company’s regulated assets totaled $11.4 billion and $5.7 billion, respectively. Additionally, substantially all of the construction in progress at March 31, 2006 and December 31, 2005 relates to the construction of regulated assets.
5. | Recent Debt Issuances |
On March 24, 2006, MEHC completed a $1.7 billion offering of unsecured senior bonds due 2036 (the ‘‘Bonds’’). The Bonds were issued at an offering price of 99.957%, will accrue interest at a rate of 6.125% per annum and will mature on April 1, 2036. Accrued interest on the Bonds is payable on April 1 and October 1 of each year, commencing on October 1, 2006, until the principal amount of the Bonds is paid in full. The proceeds were used to fund MEHC’s exercise of its right to purchase shares of its common stock previously issued to Berkshire Hathaway.
6. | Other Income and Expense |
Other income consists of the following (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2006 | 2005 | ||||||
Gain on Mirant bankruptcy claim | $ | 89.3 | $ | - | |||
Gains from non-strategic assets and investments | 12.7 | 11.9 | |||||
Allowance for equity funds used during construction | 7.5 | 4.7 | |||||
Gain on contractual settlement | 5.4 | - | |||||
Other | 8.0 | 4.4 | |||||
Total other income | $ | 122.9 | $ | 21.0 |
Mirant Americas Energy Marketing (“Mirant”) Claim
Mirant was one of the shippers that entered into a 15-year, 2003 Expansion Project, firm gas transportation contract (90,000 Dth per day) with Kern River (the “Mirant Agreement”) and provided a letter of credit equivalent to 12 months of reservation charges as security for its obligations thereunder. In July 2003, Mirant filed for Chapter 11 bankruptcy protection and Kern River subsequently drew on the letter of credit and held the proceeds thereof, $14.8 million, as cash collateral. Kern River claimed $210.2 million in damages due to the rejection of the Mirant Agreement. The bankruptcy court ultimately determined that Kern River was entitled to a general unsecured claim of $74.4 million in addition to the $14.8 million cash collateral. In January 2006, Mirant emerged from bankruptcy and on February 6, 2006, a stipulated judgment was entered that allowed Kern River to receive a pro rata amount of shares of new Mirant stock determined by Kern River’s allowed claim amount plus interest in relation to the unsecured creditor class of over $6 billion. In February 2006, Kern River received an initial distribution of such shares in payment of the majority of its allowed claim. Kern River sold all of the shares of new Mirant stock received from its allowed claim amount plus interest during the three-month period ended March 31, 2006 and recognized a gain from those sales of $89.3 million.
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7. | Regulatory Matters |
The following are updates to regulatory matters based upon changes that occurred during the three-month period ended March 31, 2006:
PacifiCorp
Utah
In March 2006, PacifiCorp filed a general rate case with the Utah Public Service Commission (“UPSC”) related to increased investments in Utah due to growing demand for electricity. PacifiCorp is seeking an increase of $197.2 million annually, or 17.0%. If approved by the UPSC, the increase would take effect in December 2006. In April 2006, PacifiCorp filed a revised case reflecting the effects of PacifiCorp’s sale to MEHC. The revised case reduced the original increase requested from $197.2 million to $194.1 million.
Oregon
In February 2006, PacifiCorp filed a general rate case request with the Oregon Public Utility Commission (“OPUC”) for $112.0 million, which represents a 13.2% overall increase. The request is related to investments in generation, transmission and distribution infrastructure and increases in fuel and general operating expenses, including the maintenance of low-cost but aging power plants. A procedural schedule has been established with a decision from the OPUC expected by December 2006.
In September 2005, Oregon’s governor signed into law Senate Bill 408. This legislation is intended to address differences between income taxes collected by Oregon public utilities in retail rates and actual taxes paid by the utilities or consolidated groups in which utilities are included for income tax reporting purposes. This legislation authorizes an automatic adjustment to rates based on the taxes paid to governmental entities on or after January 1, 2006. The OPUC adopted a temporary rule in September 2005 to establish filing requirements for an annual tax report mandated by Senate Bill 408. The definitions adopted in the temporary rule would allocate a share of individual taxable losses of affiliate companies to the utility even when the consolidated tax group pays more taxes than the utility collects in retail rates. The temporary rule expired on March 13, 2006. PacifiCorp is actively participating in the rulemaking process for adopting permanent rules required by Senate Bill 408. PacifiCorp expects that the permanent rules will be issued during the fiscal quarter ending September 30, 2006.
In September 2005, the OPUC issued an order granting a general rate increase of $25.9 million, or an average increase of 3.2%, effective October 2005. PacifiCorp filed its general rate case in November 2004, and following four partial stipulations with participating parties, PacifiCorp’s requested revenue requirement increase was $52.5 million. The OPUC’s order reduced PacifiCorp’s revenue requirement by $26.6 million based on the OPUC’s interpretation of Senate Bill 408. In October 2005, PacifiCorp filed with the OPUC a motion for reconsideration and rehearing of the rate order generally on the basis that the tax adjustment was not made in compliance with applicable law. With the motion, PacifiCorp also filed a deferred accounting application with the OPUC to track revenues related to the disallowed tax expenses. The OPUC granted PacifiCorp’s motion for reconsideration and rehearing in December 2005 and will reconsider whether Oregon Senate Bill 408 applies to the general rate case and, if it does, whether the tax adjustment ordered by the OPUC results in rates that are unconstitutional. A hearing and submissions of written briefs are scheduled to be completed in June 2006 with a decision expected by the third quarter of 2006.
Wyoming
In March 2006, the Wyoming Public Service Commission approved an agreement settling the general rate case filed by PacifiCorp in October 2005 and a separate request filed by PacifiCorp in December 2005 to recover increased costs of net wholesale purchased power used to serve Wyoming customers. The agreement provides for an annual rate increase of $15.0 million effective March 1, 2006, an additional annual rate increase of $10.0 million effective July 1, 2006, a power cost adjustment mechanism and an agreement by the parties to support a forecast test year in the next general rate case application.
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Washington
In May 2005, PacifiCorp filed a general rate case request with the Washington Utilities and Transportation Commission (“WUTC”) for $39.2 million annually. Hearings took place in January and February 2006 and this amount was reduced to $30.0 million. As part of the general rate case, PacifiCorp was also seeking to recover $8.3 million in hydroelectric costs. On April 17, 2006, the WUTC issued an order denying PacifiCorp’s request to increase retail electric rates. The WUTC determined that application of PacifiCorp’s cost allocation methodology failed to satisfy the statutory requirements that resources must benefit Washington ratepayers. On April 27, 2006, PacifiCorp filed a petition for reconsideration of the order and filed a separate, limited rate request seeking rate relief of $7.0 million, or 2.99%, along with a motion to consolidate the two filings.
MidAmerican Funding
On December 16, 2005, MidAmerican Energy filed with the Iowa Utilities Board (“IUB”) a settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate (“OCA”) regarding ratemaking principles for up to 545 MW of additional wind-powered generation capacity in Iowa, based on nameplate ratings. The settlement agreement, which was approved by the IUB on April 18, 2006, extends through 2012 MidAmerican Energy’s commitment not to seek a general increase in electric rates unless its Iowa jurisdictional electric return on equity for the calendar year 2011 falls below 10%. Additionally, the revenue sharing mechanism is extended through 2012, and the OCA agrees not to seek any decrease in Iowa electric base rates to become effective prior to January 1, 2013.
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, which, among other things, proposed an authorized rate of return of 9.34%. Kern River is currently authorized to collect an authorized rate of return of 13.25% with respect to its 2003 expansion. Briefs on exceptions were filed on April 3, 2006, and briefs opposing exceptions were filed on April 24, 2006. The administrative law judge’s initial decision is non-binding and after briefing, the FERC will issue its initial decision on the case. The initial FERC decision, which may result in rate refunds, typically becomes binding on all parties while rehearing requests on the FERC decision and/or court appeals are pending. The initial FERC decision is not expected until late 2006 or early 2007. The final resolution of the rate case is dependent on receiving a final, non-appealable decision on the case from the FERC, or approval of a settlement of the case by the FERC.
8. | Commitments and Contingencies |
Environmental Matters
PacifiCorp and MidAmerican Energy are subject to numerous environmental laws, including the federal Clean Air Act and various state air quality laws; the Endangered Species Act; the Comprehensive Environmental Response, Compensation and Liability Act, and similar state laws relating to environmental cleanups; the Resource Conservation and Recovery Act and similar state laws relating to the storage and handling of hazardous materials; and the Clean Water Act, and similar state laws relating to water quality. These laws have the potential for impacting the Company’s operations. Specifically, the Clean Air Act will likely impact the operation of PacifiCorp’s and MidAmerican Energy’s generating facilities and will likely require PacifiCorp and MidAmerican Energy to either reduce emissions from those facilities through the installation of emission controls or the purchase of additional emission allowances, or some combination thereof.
Air Quality
PacifiCorp and MidAmerican Energy are subject to applicable provisions of the Clean Air Act and related air quality standards promulgated by the United States Environmental Protection Agency (“EPA”). The Clean Air Act provides the framework for regulation of certain air emissions and permitting and monitoring associated with those emissions. PacifiCorp and MidAmerican Energy believe they are in material compliance with current air quality requirements.
The EPA has in recent years implemented more stringent national ambient air quality standards for ozone and new standards for fine particulate matter. These standards set the minimum level of air quality that must be met throughout the United States. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment of the standard. Areas that fail to meet the standard are designated as being nonattainment areas. Generally, once an area has been designated as a nonattainment area, sources of emissions that contribute to the failure to achieve the ambient air quality standards are required to make emissions reductions. The EPA has concluded that the counties in Washington, Idaho, Montana, Wyoming, Colorado, Utah and Arizona, where PacifiCorp’s major emission sources are located, and the entire state of Iowa, where MidAmerican Energy’s major emission sources are located, are in attainment of the ozone and the current fine particulate matter standards.
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In December 2005, the EPA proposed a revision of the ambient air quality standards for fine particles that would maintain the current annual standard and set a new, more stringent 24-hour standard for concentration of fine particulate in the ambient air. The EPA is scheduled to issue final rules in September 2006.
In March 2005, the EPA released the final Clean Air Mercury Rule (“CAMR”). The CAMR utilizes a market-based cap and trade mechanism to reduce mercury emissions from coal-burning power plants from the 1999 nationwide level of 48 tons to 15 tons at full implementation. The CAMR’s two-phase reduction program requires initial reductions of mercury emission in 2010 and an overall reduction in mercury emissions from coal-burning power plants of 70% by 2018. Individual states are required to implement the CAMR or alternative requirements to achieve equivalent or greater mercury emission reductions through their state implementation plans.
In March 2005, the EPA released the final Clean Air Interstate Rule (“CAIR”), calling for reductions of sulfur dioxide (“SO2”) and nitrogen oxides (“NOx”) emissions in the eastern United States through, at each state’s option, a market-based cap and trade system, emission reductions, or both. The state of Iowa is implementing rules that exercise the option of the market-based cap and trade system. While the state of Iowa has been determined to be in attainment of the ozone and fine particulate standards, Iowa has been found to significantly contribute to nonattainment of the fine particulate standard in Cook County, Illinois; Lake County, Indiana; Madison County, Illinois; St. Clair County, Illinois; and Marion County, Indiana. The EPA has also concluded that emissions from Iowa significantly contribute to ozone nonattainment in Kenosha and Sheboygan counties in Wisconsin and Macomb County, Michigan. Under the final CAIR, the first phase reductions of SO2 emissions are effective on January 1, 2010, with the second phase reductions effective January 1, 2015. For NOx, the first phase emissions reductions are effective January 1, 2009, and the second phase reductions are effective January 1, 2015. The CAIR calls for overall reductions of SO2 and NOx in Iowa of 68% and 67%, respectively, from 2003 levels by 2015.
The CAMR or the CAIR could, in whole or in part, be superseded or made more stringent by one of a number of multi-pollutant emission reduction proposals currently under consideration at the federal level, including pending legislative proposals that contemplate 70% to 90% reductions of SO2, NOX and mercury, as well as possible new federal regulation of carbon dioxide and other gases that may affect global climate change. In addition to any federal legislation that could be enacted by Congress to supersede the CAMR and the CAIR, the rules could be changed or overturned as a result of litigation. The sufficiency of the standards established by both the CAMR and the CAIR has been legally challenged in the United States District Court for the District of Columbia.
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. PacifiCorp and other stakeholders are participating in the Western Regional Air Partnership to help develop the technical and policy tools needed to comply with this program, while MidAmerican Energy and other stakeholders are participating in the Central States Regional Air Partnership to help develop the technical and policy tools needed to comply with this program.
As of March 31, 2006, PacifiCorp’s environmental contingencies principally consist of air quality matters. Pending or proposed air regulations will require PacifiCorp to reduce the emissions of SO2, NOx and other pollutants at its generating facilities below current levels. The acquisition of PacifiCorp by MEHC includes a regulatory commitment to spend approximately $812 million to reduce emissions at PacifiCorp’s generating facilities to address existing and future air quality requirements. These costs and any additional expenditures necessitated by air quality regulations are expected to be recoverable through the ratemaking process.
MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions that may be required to meet emissions reductions as promulgated by the EPA. In accordance with an Iowa law passed in 2001, MidAmerican Energy has on file with the IUB its current multi-year plan and budget for managing SO2 and NOX from its generating facilities in a cost-effective manner. The plan, which is required to be updated every two years, provides specific actions to be taken at each coal-fired generating facility and the related costs and timing for each action. Pursuant to an unrelated rate settlement agreement approved by the IUB on October 17, 2003, if prior to January 1, 2011, capital and operating expenditures to comply with environmental requirements cumulatively exceed $325 million, then MidAmerican Energy may seek to recover the additional expenditures from customers.
Under existing New Source Review (“NSR”) provisions of the Clean Air Act, any facility that emits regulated pollutants is required to obtain a permit from the EPA or a state regulatory agency prior to (1) beginning construction of a new major stationary source of an NSR-regulated pollutant or (2) making a physical or operational change to an existing stationary source of such pollutants that increases certain levels of emissions, unless the changes are exempt under the regulations (including routine maintenance, repair and replacement of equipment). In general, projects subject to NSR regulations are subject to pre-construction review and permitting under the Prevention of Significant Deterioration (“PSD”) provisions of the Clean Air Act. Under the PSD program, a project that emits threshold levels of regulated pollutants must undergo a Best Available Control Technology analysis and evaluate the most effective emissions controls. These controls must be installed in order to receive a permit. Violations of NSR regulations, which may be alleged by the EPA, states, and environmental groups, among others, potentially subject a utility to material expenses for fines and other sanctions and remedies including requiring installation of enhanced pollution controls and funding supplemental environmental projects.
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In 2002 and 2003, the EPA proposed various changes to its NSR rules that clarify what constitutes routine repair, maintenance and replacement for purposes of triggering NSR requirements. These changes have been subject to legal challenge and, until such time as the legal challenges are resolved and the rules are effective, PacifiCorp and MidAmerican Energy will continue to manage projects at its generating plants in accordance with the rules in effect prior to 2002. In October 2005, the EPA proposed a rule that would change or clarify how emission increases are to be calculated for purposes of determining the applicability of the NSR permitting program for existing power plants.
In February 2005, the Kyoto Protocol became effective, requiring 35 developed countries to reduce greenhouse gas emissions by approximately 5% between 2008 and 2012. While the United States did not ratify the protocol, the ratification and implementation of its requirements in other countries has resulted in increased attention to climate change in the United States. In 2005, the Senate adopted a “sense of the Senate” resolution that puts the Senate on record that Congress should enact a comprehensive and effective national program of mandatory, market-based limits and incentives on emissions of greenhouse gases that slow, stop, and reverse the growth of such emissions at a rate and in a manner that will not significantly harm the United States economy; and will encourage comparable action by other nations that are major trading partners and key contributors to global emissions. It is anticipated that the resolution may be further addressed by Congress in 2006. While debate continues at the national level over the direction of domestic climate policy, several states are developing state-specific or regional legislative initiatives to reduce greenhouse gas emissions. In December 2005, the states of Connecticut, Delaware, Maine, New Hampshire, New Jersey, New York and Vermont signed a mandatory regional pact to reduce greenhouse gas emissions that would become effective in 2009 and ultimately would require a reduction in greenhouse gas emissions of 10 percent from 1990 levels. An executive order signed by California’s governor in June 2005 would reduce greenhouse gas emissions in that state to 2000 levels by 2010, to 1990 levels by 2020 and 80 percent below 1990 levels by 2050. In addition, California is seeking to apply a greenhouse gas emission performance standard to all electricity generated within the state or delivered from outside the state that is no higher than the greenhouse gas emission levels of a state-of-the-art combined-cycle natural gas generation facility.
Litigation was filed in the federal district court for the southern district of New York seeking to require reductions of carbon dioxide emissions from generating facilities of five large electric utilities. The court dismissed the public nuisance suit, holding that such critical issues affecting the United States such as greenhouse gas emissions reductions are not the domain of the court and should be resolved by the Executive Branch and the U.S. Congress. This ruling has been appealed to the Second Circuit Court of Appeals. The outcome of climate change litigation and federal and state initiatives cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly impact the Company’s fossil-fueled facilities and, therefore, its results of operations.
The EPA’s regulation of certain pollutants under the Clean Air Act, and its failure to regulate other pollutants, is being challenged by various lawsuits brought by both individual state attorney generals and environmental groups. To the extent that these actions may be successful in imposing additional and/or more stringent regulation of emissions on fossil-fueled facilities in general and PacifiCorp’s and MidAmerican Energy’s facilities in particular, such actions could significantly impact the Company’s fossil-fueled facilities and, therefore, its results of operations.
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PacifiCorp’s hydroelectric portfolio consists of 51 plants with an aggregate plant net capability of 1,159.4 MW. The FERC regulates 93.9% of the installed capacity of this portfolio through 18 individual licenses. Several of PacifiCorp’s hydroelectric plants are in some stage of the relicensing process with the FERC. PacifiCorp also has requested the FERC to allow decommissioning of four hydroelectric plants. Hydroelectric relicensing and the related environmental compliance requirements are subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and will consist primarily of additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result from the additional environmental requirements. PacifiCorp has accumulated $70.3 million in costs as of March 31, 2006 for ongoing hydroelectric relicensing, which are reflected in properties, plants and equipment, net in the accompanying consolidated balance sheet. PacifiCorp expects that these and future costs will be included in rates and, as such, will not have a material adverse impact on PacifiCorp’s consolidated financial position or results of operations.
In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 161.4 MW Klamath hydroelectric project. The FERC is scheduled to complete its required analysis by January 2007. The U.S. Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006; PacifiCorp filed alternatives to the federal agencies’ proposal and challenges to its factual assumptions in April 2006. PacifiCorp continues to participate in the mediated settlement discussions with state and federal agencies, Native American tribes and other stakeholders in an effort to reach a comprehensive agreement on project relicensing. As of March 31, 2006, PacifiCorp has incurred costs of $35.9 million, which are reflected in properties, plants and equipment, net in the accompanying consolidated balance sheet, in the relicensing of the Klamath project. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be significant.
Mine Reclamation
The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of mining activities. These obligations mandate that mine property be restored consistent with specific standards and the approved reclamation plan. PacifiCorp's mining operations are subject to these reclamation and closure requirements. Significant expenditures are being incurred for both ongoing and final reclamation. PacifiCorp’s estimated mine and plant reclamation costs for its coal mines was $136.1 million at March 31, 2006 and is the asset retirement obligation for these mines, which is reflected in other long-term accrued liabilities in the accompanying consolidated balance sheet. PacifiCorp has established trusts for the investment of funds for mine and plant reclamation. The fair value of the assets held in trusts was $101.9 million at March 31, 2006, and is reflected in other investments in the accompanying consolidated balance sheet.
Nuclear Decommissioning
Expected nuclear decommissioning costs for Quad Cities Station have been developed based on a site-specific decommissioning study that includes decontamination, dismantling, site restoration, dry fuel storage cost and an assumed shutdown date. Quad Cities Station nuclear decommissioning costs are included in base rates in MidAmerican Energy’s Iowa tariffs. MidAmerican Energy’s share of estimated decommissioning costs for Quad Cities Station was $165.4 million and $163.0 million as of March 31, 2006 and December 31, 2005, respectively, and is the asset retirement obligation for Quad Cities Station, which is reflected in other long-term accrued liabilities in the accompanying consolidated balance sheets. MidAmerican Energy has established trusts for the investment of funds for decommissioning the Quad Cities Station. The fair value of the assets held in the trusts was $235.5 million and $228.1 million, respectively, as of March 31 2006 and December 31, 2005, and is reflected in other investments in the accompanying consolidated balance sheets. MidAmerican Energy’s depreciation and amortization includes costs for Quad Cities Station decommissioning. The regulatory provision charged to expense is equal to the funding that is being collected in Iowa rates.
Accrued Environmental Costs
The Company's policy is to accrue environmental clean-up costs of a non-capital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on assessments of many factors, including changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement. The liability recorded at March 31, 2006 and December 31, 2005 was $42.0 million and $7.5 million, respectively.
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In addition to the proceeding described below, the Company is currently party to various items of litigation or arbitration in the normal course of business, none of which are reasonably expected by the Company to have a material adverse effect on its financial position, results of operations or cash flows.
CalEnergy Generation-Foreign
Pursuant to the share ownership adjustment mechanism in the CE Casecnan stockholder agreement, which is based upon pro forma financial projections of the Casecnan project prepared following commencement of commercial operations, in February 2002, MEHC’s indirect wholly-owned subsidiary, CE Casecnan Ltd., advised the minority stockholder of CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”), that MEHC’s indirect ownership interest in CE Casecnan had increased to 100% effective from commencement of commercial operations. On July 8, 2002, LPG filed a complaint in the Superior Court of the State of California, City and County of San Francisco against CE Casecnan Ltd. and MEHC. LPG’s complaint, as amended, seeks compensatory and punitive damages arising out of CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma financial projections On January 21, 2004, CE Casecnan Ltd., LPG and CE Casecnan entered into a status quo agreement pursuant to which the parties agreed to set aside certain distributions related to the shares subject to the LPG dispute and CE Casecnan agreed not to take any further actions with respect to such distributions without at least 15 days prior notice to LPG. Accordingly, 15% of the CE Casecnan dividend distributions declared in 2004 and 2005, totaling $17.6 million, was set aside in a separate bank account in the name of CE Casecnan and is shown as restricted cash and short-term investments and other current liabilities in the accompanying consolidated balance sheets.
On August 4, 2005, the court issued a decision, ruling in favor of LPG on five of the eight disputed issues in the first phase of the litigation. On September 12, 2005, LPG filed a motion seeking the release of the funds which have been set aside pursuant to the status quo agreement referred to above. MEHC and CE Casecnan Ltd. filed an opposition to the motion on October 3, 2005, and at the hearing on October 26, 2005, the court denied LPG’s motion. On January 3, 2006, the court entered a judgment in favor of LPG against CE Casecnan Ltd. According to the judgment LPG would retain its ownership of 15% of the shares of CE Casecnan and distributions of the amounts deposited into escrow plus interest at 9% per annum. On February 28, 2006, CE Casecnan Ltd. filed an appeal of this judgment and the August 4, 2005 decision. Initial briefs are due May 24, 2006. The appeal is expected to be resolved sometime in 2007. The impact, if any, of this litigation on the Company cannot be determined at this time.
In February 2003, San Lorenzo Ruiz Builders and Developers Group, Inc. (“San Lorenzo”), an original shareholder substantially all of whose shares in CE Casecnan were purchased by MEHC in 1998, threatened to initiate legal action against the Company in the Philippines in connection with certain aspects of its option to repurchase such shares. On July 1, 2005, MEHC and CE Casecnan Ltd. commenced an action against San Lorenzo in the District Court of Douglas County, Nebraska, seeking a declaratory judgment as to MEHC’s and CE Casecnan Ltd.'s rights vis-à-vis San Lorenzo in respect of such shares. San Lorenzo filed a motion to dismiss on September 19, 2005. Subsequently, San Lorenzo purported to exercise its option to repurchase such shares. On January 30, 2006, San Lorenzo filed a counterclaim against MEHC and CE Casecnan Ltd. seeking declaratory relief that it has effectively exercised its option to purchase 15% of the shares of CE Casecnan, that it is the rightful owner of such shares, and that it is due all dividends paid on such shares. On March 9, 2006, the court granted San Lorenzo’s motion to dismiss, but has since permitted MEHC and CE Casecnan Ltd. to file an amended complaint incorporating the purported exercise of the option. The impact, if any, of San Lorenzo’s purported exercise of its option and the Nebraska litigation on the Company cannot be determined at this time. The Company intends to vigorously defend the counterclaims.
9. | Retirement Plans |
PacifiCorp
PacifiCorp sponsors noncontributory defined benefit pension plans that cover the majority of its employees. In addition, certain bargaining unit employees participate in a joint trust plan to which PacifiCorp contributes. PacifiCorp also maintains noncontributory, nonqualified defined benefit supplemental executive retirement plans for active and retired participants. The net periodic benefit cost under these plans was $2.0 million for the period from acquisition to March 31, 2006.
PacifiCorp provides health care and life insurance benefits through various plans for eligible retirees. The net period benefit cost under these plans was $0.9 million for the period from acquisition to March 31, 2006.
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PacifiCorp expects to contribute $80.6 million and $56.7 million during the period from acquisition to December 31, 2006 to its pension and postretirement plans, respectively. For the period from the acquisition to March 31, 2006, $29.2 million of contributions have been made to the postretirement plans. In April 2006, PacifiCorp contributed $72.7 million to its pension plans.
MidAmerican Funding
MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering substantially all employees of MEHC and its domestic energy subsidiaries, except for PacifiCorp and its subsidiaries. MidAmerican Energy also sponsors certain postretirement health care and life insurance benefits covering substantially all retired employees of MEHC and its domestic energy subsidiaries, except for PacifiCorp and its subsidiaries. Net periodic benefit cost for the three-month periods ended March 31 for the pension, including supplemental retirement, and postretirement benefit plans included the following components for MEHC and the aforementioned subsidiaries (in millions):
Pension | Postretirement | ||||||||||||
2006 | 2005 | 2006 | 2005 | ||||||||||
Service cost | $ | 6.4 | $ | 6.7 | $ | 1.7 | $ | 1.7 | |||||
Interest cost | 9.5 | 9.2 | 3.5 | 3.6 | |||||||||
Expected return on plan assets | (9.7 | ) | (9.5 | ) | (2.5 | ) | (2.3 | ) | |||||
Amortization of net transition balance | - | - | 0.6 | 0.6 | |||||||||
Amortization of prior service cost | 0.6 | 0.6 | - | - | |||||||||
Amortization of prior year loss | 0.3 | 0.4 | 0.4 | 0.4 | |||||||||
Net periodic benefit cost | $ | 7.1 | $ | 7.4 | $ | 3.7 | $ | 4.0 |
The Company expects to contribute $6.7 million and $14.5 million in 2006 to its pension and postretirement plans, respectively. As of March 31, 2006, $1.5 million and $3.4 million of contributions have been made to the pension and postretirement plans, respectively.
CE Electric UK
Certain wholly-owned subsidiaries of CE Electric UK participate in the Northern Electric group of the United Kingdom industry-wide Electricity Supply Pension Scheme (the “UK Plan”), which provides pension and other related defined benefits, based on final pensionable pay, to substantially all employees of CE Electric UK’s certain wholly-owned subsidiaries. Net periodic benefit cost for the pension plan included the following components for CE Electric UK (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2006 | 2005 | ||||||
Service cost | $ | 4.4 | $ | 4.0 | |||
Interest cost | 18.5 | 19.9 | |||||
Expected return on plan assets | (24.1 | ) | (25.2 | ) | |||
Amortization of prior service cost | 0.4 | 0.5 | |||||
Amortization of prior year loss | 8.1 | 5.6 | |||||
Net periodic benefit cost | $ | 7.3 | $ | 4.8 |
Employer contributions to the UK Plan, including £23.1 million for the existing funding deficiency, are expected to be £35.0 million for 2006. As of March 31, 2006, £8.8 million, or $15.3 million, of contributions have been made to the UK Plan, including £5.8 million, or $10.1 million, in respect of the existing funding deficiency.
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10. | Segment Information |
The Company has identified eight reportable segments: PacifiCorp, MidAmerican Funding, Northern Natural Gas, Kern River, CE Electric UK, CalEnergy Generation-Foreign, CalEnergy Generation-Domestic, and HomeServices. The Company’s determination of reportable segments considers the strategic units under which the Company is 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. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company’s significant accounting policies including the allocation of goodwill. Information related to the Company’s reportable segments is shown below (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2006 | 2005 | ||||||
Operating revenue: | |||||||
PacifiCorp | $ | 76.5 | $ | - | |||
MidAmerican Funding | 1,041.7 | 856.3 | |||||
Northern Natural Gas | 213.7 | 201.2 | |||||
Kern River | 79.3 | 78.6 | |||||
CE Electric UK | 210.4 | 239.2 | |||||
CalEnergy Generation-Foreign | 85.4 | 72.2 | |||||
CalEnergy Generation-Domestic | 7.5 | 7.9 | |||||
HomeServices | 355.5 | 362.3 | |||||
Total reportable segments | 2,070.0 | 1,817.7 | |||||
Corporate/other(1) | (15.4 | ) | (13.5 | ) | |||
Total operating revenue | $ | 2,054.6 | $ | 1,804.2 | |||
Depreciation and amortization: | |||||||
PacifiCorp | $ | 13.3 | $ | - | |||
MidAmerican Funding | 75.0 | 63.8 | |||||
Northern Natural Gas | 14.2 | 17.2 | |||||
Kern River | 26.6 | 15.6 | |||||
CE Electric UK | 30.7 | 35.7 | |||||
CalEnergy Generation-Foreign | 22.6 | 22.7 | |||||
CalEnergy Generation-Domestic | 2.2 | 2.2 | |||||
HomeServices | 5.1 | 4.3 | |||||
Total reportable segments | 189.7 | 161.5 | |||||
Corporate/other(1) | (1.7 | ) | (1.9 | ) | |||
Total depreciation and amortization | $ | 188.0 | $ | 159.6 | |||
Operating income: | |||||||
PacifiCorp | $ | 22.5 | $ | - | |||
MidAmerican Funding | 134.5 | 99.4 | |||||
Northern Natural Gas | 124.4 | 111.2 | |||||
Kern River | 40.2 | 49.0 | |||||
CE Electric UK | 114.0 | 125.7 | |||||
CalEnergy Generation-Foreign | 57.5 | 43.9 | |||||
CalEnergy Generation-Domestic | 3.0 | 4.4 | |||||
HomeServices | (0.3 | ) | 8.1 | ||||
Total reportable segments | 495.8 | 441.7 | |||||
Corporate/other(1) | (33.3 | ) | (17.1 | ) | |||
Total operating income | 462.5 | 424.6 | |||||
Interest expense | (221.7 | ) | (231.6 | ) | |||
Capitalized interest | 4.6 | 3.6 | |||||
Interest and dividend income | 15.3 | 8.4 | |||||
Other income | 122.9 | 21.0 | |||||
Other expense | (1.2 | ) | (3.3 | ) | |||
Total income from continuing operations before income tax expense, minority interest and preferred dividends of subsidiaries and equity income | $ | 382.4 | $ | 222.7 |
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Three-Month Periods | |||||||
Ended March 31, | |||||||
2006 | 2005 | ||||||
Interest expense: | |||||||
PacifiCorp | $ | 8.2 | $ | - | |||
MidAmerican Funding | 39.1 | 33.8 | |||||
Northern Natural Gas | 12.5 | 13.3 | |||||
Kern River | 18.1 | 18.5 | |||||
CE Electric UK | 49.7 | 59.6 | |||||
CalEnergy Generation-Foreign | 5.6 | 8.6 | |||||
CalEnergy Generation-Domestic | 4.4 | 4.6 | |||||
HomeServices | 0.5 | 0.6 | |||||
Total reportable segments | 138.1 | 139.0 | |||||
Corporate/other(1) | 83.6 | 92.6 | |||||
Total interest expense | $ | 221.7 | $ | 231.6 | |||
As of | |||||||
March 31, | December 31 | ||||||
2006 | 2005 | ||||||
Total assets: | |||||||
PacifiCorp | $ | 14,262.5 | $ | - | |||
MidAmerican Funding | 8,005.6 | 8,003.4 | |||||
Northern Natural Gas | 2,252.4 | 2,245.3 | |||||
Kern River | 2,048.5 | 2,099.6 | |||||
CE Electric UK | 5,888.5 | 5,742.7 | |||||
CalEnergy Generation-Foreign | 660.9 | 643.1 | |||||
CalEnergy Generation-Domestic | 545.4 | 555.1 | |||||
HomeServices | 858.8 | 814.3 | |||||
Total reportable segments | 34,522.6 | 20,103.5 | |||||
Corporate/other(1) | 319.2 | 267.2 | |||||
Total assets | $ | 34,841.8 | $ | 20,370.7 |
Goodwill is allocated to each reportable segment included in total assets above. Goodwill as of December 31, 2005 and the changes for the three-month period ended March 31, 2006 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, 2005 | $ | - | $ | 2,117.6 | $ | 327.1 | $ | 33.9 | $ | 1,207.2 | $ | 72.4 | $ | 398.0 | $ | 4,156.2 | |||||||||
Goodwill from acquisitions | 1,074.3 | - | - | - | - | - | 11.6 | 1,085.9 | |||||||||||||||||
Foreign currency translation | - | - | - | - | 9.0 | - | - | 9.0 | |||||||||||||||||
Other(2) | - | 0.8 | (6.5 | ) | - | (0.2 | ) | (0.1 | ) | (0.1 | ) | (6.1 | ) | ||||||||||||
Goodwill at March 31, 2006 | $ | 1,074.3 | $ | 2,118.4 | $ | 320.6 | $ | 33.9 | $ | 1,216.0 | $ | 72.3 | $ | 409.5 | $ | 5,245.0 |
(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, (ii) intersegment eliminations and (iii) fair value adjustments relating to acquisitions. |
(2) | Other goodwill adjustments include primarily income tax adjustments. |
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The following is management’s discussion and analysis of certain significant factors which have affected the financial condition and results of operations of MidAmerican Energy Holdings Company and its subsidiaries (“MEHC” or the “Company”) during the periods included in the accompanying consolidated financial statements. This discussion should be read in conjunction with the Company’s historical consolidated financial statements and the related notes thereto included elsewhere in this report. The Company’s actual results in the future could differ significantly from the historical results.
Forward-Looking Statements
This report contains statements that do not directly or exclusively relate to historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “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; |
· | the financial condition and creditworthiness of the Company’s significant customers and suppliers; |
· | governmental, statutory, legislative, regulatory or administrative initiatives, including those relating to the recently enacted Energy Policy Act of 2005 (“Energy Policy Act”), or ratemaking actions affecting the Company or the electric or gas utility, pipeline or power generation industries; |
· | the outcome of general rate cases and other proceedings conducted before regulatory authorities; |
· | weather effects on sales and revenue; |
· | changes in expected customer growth or usage of electricity or gas; |
· | economic or industry trends that could impact electricity or gas usage; |
· | increased competition in the power generation, electric and gas utility or pipeline industries; |
· | fuel, fuel transportation and power costs and availability; |
· | continued availability of accessible gas reserves; |
· | changes in business strategy, development plans or customer or vendor relationships; |
· | availability, terms and deployment of capital; |
· | availability of qualified personnel; |
· | unscheduled outages or repairs; |
· | risks relating to nuclear generation; |
· | financial or regulatory accounting principles or policies imposed by the Public Company Accounting Oversight Board, the Financial Accounting Standards Board, the U.S. Securities and Exchange Commission (“SEC”), the Federal Energy Regulatory Commission (“FERC”), state public utility commissions and similar entities with regulatory oversight; |
· | changes in, and compliance with, environmental laws, regulations, decisions and policies that could increase operating and capital improvement costs or affect plant output and/or delay plant construction; |
· | the Company’s ability to successfully integrate PacifiCorp’s operations into the Company’s business; |
· | other risks or unforeseen events, including wars, the effects of terrorism, embargos and other catastrophic events; and |
· | other business or investment considerations that may be disclosed from time to time in SEC filings or in other publicly disseminated written documents. |
Further details of the potential risks and uncertainties affecting the Company are described in MEHC’s filings with the SEC, including Item 1A. Risk Factors and other discussions contained in this Form 10-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.
Executive Summary
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, CalEnergy Generation-Domestic and HomeServices of America, Inc. (“HomeServices”). These platforms are discussed in detail in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, except for PacifiCorp, which is discussed herein. Through these platforms, the Company owns and operates an electric utility company in the Western United States, a combined electric and natural gas utility company in the Midwestern United States, two natural gas pipeline companies in the United States, two electricity distribution companies in Great Britain, a diversified portfolio of domestic and international independent power projects and the second largest residential real estate brokerage firm in the United States.
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The following significant events occurred during the three-month periods ended March 31, 2006 and 2005, respectively, as discussed in more detail herein, that highlight some of the factors which affected, or may affect in the future, the Company’s financial condition, results of operations and liquidity:
· | In May 2005, MEHC reached a definitive agreement with Scottish Power plc (“ScottishPower”) and its subsidiary, PacifiCorp Holdings, Inc., to acquire 100% of the common stock of ScottishPower’s wholly-owned indirect subsidiary PacifiCorp for $5.1 billion in cash. On March 21, 2006, MEHC issued common stock of $5.1 billion to Berkshire Hathaway, Inc. (“Berkshire Hathaway”) and other existing stockholders and closed the PacifiCorp acquisition. The results of PacifiCorp are included in MEHC’s results beginning March 21, 2006. |
· | On February 9, 2006, following the effective date of the repeal of the Public Utility Holding Company Act of 1935 (“PUHCA 1935”), Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par, zero-coupon convertible preferred stock into an equal number of shares of MEHC’s common stock. |
· | On March 1, 2006, MEHC and Berkshire Hathaway entered into an Equity Commitment Agreement (the “Berkshire Equity Commitment”) pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of common equity through February 28, 2011. |
· | In the three-month period ended March 31, 2006, Kern River sold all of the shares of Mirant Americas Energy Marketing (Mirant”) stock received from its allowed bankruptcy claim amount plus interest and recognized an after-tax gain from those sales of $55.3 million. |
· | MidAmerican Energy’s regulated electric operating income improved due principally to an increase in gross margin for electric wholesale sales compared to the first quarter of 2005. An increase in the average electric wholesale margins per megawatt-hour sold increased electric wholesale gross margin by $36.5 million. A 45.6% increase in wholesale sales volumes resulted in a $4.7 million increase in electric wholesale gross margin. |
The regulatory expense related to the Iowa revenue sharing arrangement increased by $9.0 million. Amounts under the arrangement are determined based upon Iowa electric returns on equity which were favorably impacted by the higher wholesale revenues in the 2006 quarter. Iowa revenue sharing is recorded as depreciation and amortization in the accompanying consolidated statements of operations.
· | Kern River filed for a rate increase with the FERC in April 2004, with the new rates being effectuated on November 1, 2004, subject to refund. The general rate case hearing concluded in August 2005 and Kern River received an adverse initial decision on the case from the administrative law judge on March 2, 2006, which, among other things, proposed an authorized rate of return of 9.34%. Kern River is currently authorized to collect an authorized rate of return of 13.25% with respect to its 2003 expansion. The final resolution of the rate case is dependent on receiving a final, non-appealable decision on the case from the FERC, or approval of a settlement of the case by the FERC, and is not expected at the earliest until late 2006 or early 2007. |
· | MidAmerican Energy is currently constructing Council Bluffs Energy Center Unit No. 4 (“CBEC Unit 4”), a 790 megawatt (“MW”) (expected accreditation) super-critical-temperature, coal-fired generating plant, of which MidAmerican Energy’s share is 479 MW, and expects to invest approximately $737 million in the project through 2007. Through March 31, 2006, $542.1 million had been invested, including $121.3 million for MidAmerican Energy’s share of deferred payments allowed by the construction contract. |
· | On March 24, 2006, MEHC completed a $1.7 billion offering of unsecured senior bonds due 2036 (the ‘‘Bonds’’). The Bonds were issued at an offering price of 99.957%, will accrue interest at a rate of 6.125% per annum and will mature on April 1, 2036. |
· | On March 28, 2006, MEHC exercised its right to purchase $1.7 billion of common stock from Berkshire Hathaway. |
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PacifiCorp Acquisition
On March 21, 2006, a wholly-owned subsidiary of MEHC acquired 100% of the common stock of PacifiCorp from a wholly-owned subsidiary of ScottishPower for a cash purchase price of $5,109.5 million, which was funded through the issuance of common stock. MEHC also incurred $10.7 million of direct transaction costs associated with the acquisition, which consisted principally of investment banker commissions and outside legal and accounting fees and expenses, resulting in a total purchase price of $5,120.2 million. The results of PacifiCorp’s operations are included in the Company’s results beginning March 21, 2006.
In February and March 2006, the state commissions in all six states where PacifiCorp has retail customers approved the sale of PacifiCorp to MEHC. The approvals were conditioned on a number of regulatory commitments, including expected financial benefits in the form of reduced corporate overhead and financing costs, certain mid- to long-term capital and other expenditures of significant amounts and a commitment not to seek utility rate increases attributable solely to the change in ownership. The capital and other expenditures proposed by MEHC and PacifiCorp include:
· | Approximately $812 million in investments (generally to be made over several years following the sale and subject to subsequent regulatory review and approval) in emissions reduction technology for PacifiCorp's existing coal plants, which, when coupled with the use of reduced emissions technology for anticipated new coal-fueled generation, is expected to result in significant reductions in emissions rates of sulfur dioxide, nitrogen oxide and mercury and to avoid an increase in the carbon dioxide emissions rate; and |
· | Approximately $520 million in investments (to be made over several years following the sale and subject to subsequent regulatory review and approval) in PacifiCorp's transmission and distribution system that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization. |
The commitments approved by the state commissions also include credits that will reduce retail rates generally through 2010 to the extent that PacifiCorp does not achieve identified cost reductions or demonstrate mitigation of certain risks to customers. The maximum potential value of these rate credits to customers in all six states is $142.5 million. PacifiCorp and MEHC have made additional commitments to the state commissions that limits the dividends PacifiCorp makes to MEHC or its affiliates. As of March 31, 2006, the most restrictive of these commitments prohibits PacifiCorp from making any distribution to MEHC or its affiliates without prior state regulatory approval to the extent that it would reduce PacifiCorp’s common stock equity below 48.25% of its total capitalization, excluding short-term debt and current maturities of long-term debt. After December 31, 2008, this minimum level of common equity declines annually to 44.0% after December 31, 2011.
PacifiCorp is a regulated electric utility company serving approximately 1.6 million residential, commercial and industrial customers in service territories aggregating approximately 136,000 square miles in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. The regulatory commissions in each state approve rates for retail electric sales within their respective states. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and to incorporated municipalities. Wholesale activities are regulated by the FERC. The FERC and the six state regulatory commissions also have authority over the construction and operation of PacifiCorp’s electric generation facilities. PacifiCorp delivers electricity through approximately 59,510 miles of distribution lines and approximately 15,580 miles of transmission lines.
PacifiCorp owns, or has interests in, the following types of electricity generating plants at March 31, 2006:
Nameplate | Net Plant | Energy | |||||||||||
Rating | Capability | Requirements | |||||||||||
Plants | Megawatts | Megawatts | Supplied | ||||||||||
Coal | 11 | 6,585.9 | 6,104.4 | 65.1 | % | ||||||||
Natural gas and other | 6 | 1,348.7 | 1,174.0 | 4.0 | |||||||||
Hydroelectric | 51 | 1,083.6 | 1,159.4 | 7.2 | |||||||||
Wind | 1 | 32.6 | 32.6 | 0.2 | |||||||||
Total | 69 | 9,050.8 | 8,470.4 | 76.5 | % |
PacifiCorp obtains the remainder of its energy requirements, including additional energy required beyond expectations, through short- and long-term contracts or spot market purchases. The share of PacifiCorp’s energy requirements generated by its plants will vary from year to year and is determined by factors such as planned and unplanned outages, availability and price of coal and natural gas, precipitation and snowpack levels, environmental considerations and the market price of electricity.
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During PacifiCorp’s fiscal year ended March 31, 2006, no single retail customer accounted for more than 2.0% of its retail electric revenues, and the 20 largest retail customers accounted for 13.0% of total retail electric revenues. The geographical distribution of PacifiCorp’s retail operating revenues for its fiscal year ended March 31, 2006 was: Utah, 40.9%; Oregon, 29.3%; Wyoming, 13.3%; Washington, 8.4%; Idaho, 5.7%; and California, 2.4%.
As a result of the geographically diverse area of operations, PacifiCorp's service territory has historically experienced complementary seasonal load patterns. In the western portion, customer demand peaks in the winter months due to heating requirements. In the eastern portion, customer demand peaks in the summer when irrigation and air-conditioning systems are heavily used.
Recent Developments Regarding Berkshire Hathaway
On February 9, 2006, following the effective date of the repeal of the PUHCA 1935, Berkshire Hathaway converted its 41,263,395 shares of MEHC’s no par zero-coupon convertible preferred stock into an equal number of shares of MEHC’s common stock. As a consequence, Berkshire Hathaway owns in excess of 80.0% of both the outstanding common stock and voting securities of MEHC, consolidates the Company in its financial statements as a majority-owned subsidiary, and includes the Company in its consolidated federal U.S. income tax return.
On March 1, 2006, MEHC and Berkshire Hathaway entered into the Berkshire Equity Commitment pursuant to which Berkshire Hathaway has agreed to purchase up to $3.5 billion of common equity of MEHC upon any requests authorized from time to time by the Board of Directors of MEHC. The proceeds of any such equity contribution shall only be used for the purpose of (a) paying when due MEHC’s debt obligations and (b) funding the general corporate purposes and capital requirements of the Company’s regulated subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such request. The Berkshire Equity Commitment will expire on February 28, 2011, was not used for the PacifiCorp acquisition and will not be used for other future acquisitions.
On March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing stockholders and related companies invested $5,109.5 million, in the aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide equity funding for the PacifiCorp acquisition. The per share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by MEHC’s stockholders.
On March 28, 2006, MEHC purchased 11,724,138 shares of common stock from Berkshire Hathaway for an aggregate purchase price of $1,700.0 million.
Results of Operations
Consolidated Executive Summary
Consolidated statement of operations results for the first quarter of 2006 and 2005 are summarized in the following table (in millions):
2006 | 2005 | ||||||
Operating revenue | $ | 2,054.6 | $ | 1,804.2 | |||
Operating income | $ | 462.5 | $ | 424.6 | |||
Interest expense | (221.7 | ) | (231.6 | ) | |||
Other income, net | 141.6 | 29.7 | |||||
Income tax expense | (131.2 | ) | (74.0 | ) | |||
Minority interest and preferred dividends of subsidiaries | (4.0 | ) | (2.9 | ) | |||
Equity income | 1.8 | 4.9 | |||||
Income from continuing operations | 249.0 | 150.7 | |||||
Income from discontinued operations, net of income tax | - | 1.7 | |||||
Net income available to common and preferred stockholders | $ | 249.0 | $ | 152.4 |
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Net income for the first quarter of 2006 increased $96.6 million, or 63.4%, to $249.0 million from the comparable period in 2005. In 2006, Kern River realized a $55.3 million after tax gain from the sale of Mirant common stock received as part of its Mirant bankruptcy claim award. Additionally, the Company benefited from favorable comparative results at MidAmerican Funding due primarily to higher electric wholesale margins, earnings from PacifiCorp, beginning March 21, 2006, of $10.2 million, better operating results and a gain from a contractual settlement at Northern Natural Gas and higher energy sales at CE Casecnan due to higher electricity generation.
These improvements were partially offset by lower earnings from Kern River due to estimates of the rate case outcome, lower earnings at the domestic independent power plants due to scheduled overahauls, an unrealized loss at CE Gas related to its Australian gas production hedges and lower earnings from HomeServices due to lower revenues and margins, primarily in the California market, as well as higher corporate charges associated with the acquisition of PacifiCorp and higher compensation related charges.
Segment Results
The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company’s significant accounting policies. The differences between the segment amounts and the consolidated amounts, described as “Corporate/other,” relate principally to corporate functions including administrative costs, intersegment eliminations and fair value adjustments relating to acquisitions.
A comparison of operating revenue and operating income for the Company’s reportable segments for the first quarter of 2006 and 2005 follows (in millions):
2006 | 2005 | ||||||
Operating revenue: | |||||||
PacifiCorp | $ | 76.5 | $ | - | |||
MidAmerican Funding | 1,041.7 | 856.3 | |||||
Northern Natural Gas | 213.7 | 201.2 | |||||
Kern River | 79.3 | 78.6 | |||||
CE Electric UK | 210.4 | 239.2 | |||||
CalEnergy Generation-Foreign | 85.4 | 72.2 | |||||
CalEnergy Generation-Domestic | 7.5 | 7.9 | |||||
HomeServices | 355.5 | 362.3 | |||||
Total reportable segments | 2,070.0 | 1,817.7 | |||||
Corporate/other | (15.4 | ) | (13.5 | ) | |||
Total operating revenue | $ | 2,054.6 | $ | 1,804.2 |
Operating income: | |||||||
PacifiCorp | $ | 22.5 | $ | - | |||
MidAmerican Funding | 134.5 | 99.4 | |||||
Northern Natural Gas | 124.4 | 111.2 | |||||
Kern River | 40.2 | 49.0 | |||||
CE Electric UK | 114.0 | 125.7 | |||||
CalEnergy Generation-Foreign | 57.5 | 43.9 | |||||
CalEnergy Generation-Domestic | 3.0 | 4.4 | |||||
HomeServices | (0.3 | ) | 8.1 | ||||
Total reportable segments | 495.8 | 441.7 | |||||
Corporate/other | (33.3 | ) | (17.1 | ) | |||
Total operating income | $ | 462.5 | $ | 424.6 |
PacifiCorp
On March 21, 2006, MEHC acquired 100% of the common stock of PacifiCorp. Operating income of $22.5 million and net income of $10.2 million, respectively, from PacifiCorp’s operations, beginning March 21, 2006, are included in the Company’s results for the first quarter of 2006.
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MidAmerican Funding
MidAmerican Funding’s operating revenue and operating income for the first quarter of 2006 and 2005 are summarized as follows (in millions):
2006 | 2005 | ||||||
Operating revenue: | |||||||
Regulated electric | $ | 415.2 | $ | 312.6 | |||
Regulated natural gas | 455.8 | 467.5 | |||||
Nonregulated | 170.7 | 76.2 | |||||
Total operating revenue | $ | 1,041.7 | $ | 856.3 | |||
Operating income: | |||||||
Regulated electric | $ | 99.2 | $ | 61.1 | |||
Regulated natural gas | 31.6 | 34.6 | |||||
Nonregulated | 3.7 | 3.7 | |||||
Total operating income | $ | 134.5 | $ | 99.4 |
Regulated Electric Operations
The operating results of MidAmerican Energy’s regulated electric business for the first quarter of 2006 and 2005 are summarized as follows (in millions, except for average number of customers):
2006 | 2005 | ||||||
Retail | $ | 289.7 | $ | 267.2 | |||
Wholesale | 125.5 | 45.4 | |||||
Total operating revenue | 415.2 | 312.6 | |||||
Cost of fuel, energy and capacity | 135.6 | 88.8 | |||||
Margin | 279.6 | 223.8 | |||||
Operating expense | 113.3 | 106.9 | |||||
Depreciation and amortization | 67.1 | 55.8 | |||||
Operating income | $ | 99.2 | $ | 61.1 | |||
Sales (gigawatt-hours): | |||||||
Retail | 4,793 | 4,412 | |||||
Wholesale | 2,503 | 1,719 | |||||
7,296 | 6,131 |
MidAmerican Energy’s regulated electric retail revenue for the first quarter of 2006 increased $22.5 million, or 8.4%, to $289.7 million from the comparable period in 2005. Electric retail sales volumes increased 8.6% compared to the first quarter of 2005. A growing retail customer base improved electric retail revenue by $12.0 million, while electricity usage factors not dependent on weather, such as the size of homes, technology changes and the use of multiple appliances, increased electric revenue by $6.8 million compared to the first quarter of 2005. Milder average temperatures during the first quarter of 2006 compared to the same period in 2005 resulted in a $2.8 million decrease in electric retail revenue. Transmission revenue increased $4.1 million.
In addition to retail sales, MidAmerican Energy sells electric energy to other utilities, marketers and municipalities. These sales are referred to as wholesale sales. MidAmerican Energy’s wholesale revenue for the first quarter of 2006 increased $80.1 million, or 176.4%, to $125.5 million from the comparable period in 2005. The effect of higher electric energy prices increased wholesale energy revenue in 2006 by $59.4 million. Wholesale units for the first quarter of 2006 increased 45.6% from the first quarter of 2005, resulting in a $20.7 million increase in revenue. The primary reason for the increase in wholesale sales volumes for the first quarter of 2006 was due in part to outages at the Louisa Generating Station and the Ottumwa Generating Station during the first quarter of 2005.
Cost of fuel, energy and capacity for the first quarter of 2006 increased $46.8 million, or 52.7%, to $135.6 million from the comparable period in 2005 due to an increase in the average cost of purchased power and the increase in sales volumes, partially offset by a decrease in the average cost of generation in part due to additional wind-powered generation.
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Regulated electric operating expense for the first quarter of 2006 increased $6.4 million, or 6.0%, to $113.3 million from the comparable period in 2005 due principally to higher transmission operations costs of $6.0 million related to the increase in purchased power and wholesale sales.
Regulated electric depreciation and amortization expense for the first quarter of 2006 increased $11.3 million to $67.1 million from the comparable period in 2005 due to a $9.0 million increase in regulatory expense pursuant to a revenue sharing arrangement with the state of Iowa due to higher Iowa electric equity returns. The remainder of the increase was due primarily to 200 MW of wind power facilities placed in-service in late 2005.
Regulated Natural Gas Operations
Regulated natural gas revenue includes purchased gas adjustment clauses through which MidAmerican Energy is allowed to recover the cost of gas sold from its retail gas utility customers. Consequently, fluctuations in the cost of gas sold do not affect gross margin or operating income because revenues reflect comparable fluctuations through the purchased gas adjustment clauses. Compared to the first quarter of 2005, MidAmerican Energy’s average per-unit cost of gas sold increased 16.4%, resulting in a $53.5 million increase in revenue and cost of gas sold for the first quarter of 2006. The increase in cost of gas sold and natural gas revenues as a result of the increase in the average per-unit cost was more than offset by the effect of a 15.7% decrease in sales volumes due to milder temperature conditions and other usage factors.
Nonregulated Operations
MidAmerican Funding’s nonregulated operating revenue for the first quarter of 2006 increased $94.5 million, or 124.0%, to $170.7 million from the comparable period in 2005 in part due to a change in management strategy related to certain end-use natural gas contracts that resulted in recording prospectively the related revenues and cost of sales on a gross, rather than net, basis in accordance with Emerging Issues Task Force Issue No. 02-3, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts Under Issues No. 98-10 and 00-17.” Additionally, an increase in the per-unit cost of natural gas contributed $23.6 million to the increase in nonregulated operating revenue and cost of sales compared to the first quarter of 2005.
Northern Natural Gas
Operating income for the first quarter of 2006 increased $13.2 million, or 11.9%, to $124.4 million from the comparable period in 2005.
Operating revenue for the first quarter of 2006 increased $12.5 million, or 6.2%, to $213.7 million from the comparable period in 2005. The increase was mainly due to higher transportation revenues of $13.4 million, due to increased field area demand and rates as well as new transportation contracts, and higher gas and liquids sales of $11.4 million, due to higher sales of gas from operational storage utilized to manage physical flows on the pipeline system. These increases were partially offset by the February 2005 system levelized account settlement, which increased operating revenue in the first quarter of 2005 by $12.5 million.
Cost of sales for the first quarter of 2006 increased $10.3 million to $12.1 million from the comparable period in 2005 due to higher gas and liquids sales resulting from higher sales of gas from operational storage utilized to manage physical flows on the pipeline system.
Operating expense for the first quarter of 2006 decreased $8.0 million, or 11.3%, to $63.0 million from the comparable period in 2005 due mainly to the February 2005 system levelized account settlement, which increased operating expense in the first quarter of 2005 by $13.3 million, partially offset by higher environmental remediation accruals, storage, marketing and other operating expenses totaling $4.9 million.
Depreciation and amortization for the first quarter of 2006 decreased $3.0 million, or 17.4%, to $14.2 million from the comparable period in 2005 due primarily to the ongoing impact of changes in the useful lives of Northern Natural Gas’ transmission, storage and intangible assets resulting from the June 2005 settlement of its consolidated rate case proceeding.
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Kern River
Operating income for the first quarter of 2006 decreased $8.8 million, or 18.0%, to $40.2 million from the comparable period in 2005.
Operating revenue for the first quarter of 2006 increased $0.7 million, or 0.9%, to $79.3 million from the comparable period in 2005. The increase in operating revenue resulted from higher interruptible transportation revenue of $1.8 million, higher commodity transportation revenue of $0.3 million and additional facility charge revenue of $0.6 million. This increase was partially offset by lower demand transportation revenues due mainly to an adjustment in the expected rates, subject to refund, for the current rate proceeding.
Operating expense for the first quarter of 2006 decreased $1.4 million, or 10.0%, to $12.6 million from the comparable period in 2005. This decrease was mainly due to lower outside contractual services expenses. Depreciation and amortization for the first quarter of 2006 increased $11.0 million, or 70.5%, to $26.6 million from the comparable period in 2005 due to higher deprecation rates in connection with the current rate proceeding.
CE Electric UK
Operating income for the first quarter of 2006 decreased $11.7 million, or 9.3%, to $114.0 million from the comparable period in 2005.
Operating revenue for the first quarter of 2006 decreased $28.8 million, or 12.0%, to $210.4 million from the comparable period in 2005 due mainly to a $17.5 million adverse impact from the exchange rate and a $14.4 million unrealized loss at CE Gas related to its derivative condensate contracts, which are marked to market, partially offset by $4.6 million of higher distribution revenues at NEDL and YEDL.
Operating expenses for the first quarter of 2006 decreased $8.7 million, or 18.9%, to $37.3 million from the comparable period in 2005 due mainly to lower costs of $5.8 million associated with the withdrawal from the metering market and a $3.4 million favorable impact from the exchange rate. Depreciation and amortization decreased $5.0 million, or 14.0%, to $30.7 million from the comparable period in 2005 due mainly to $3.2 million of YEDL out-performance amortization recognized in the first quarter of 2005 and a $2.6 million favorable impact from the exchange rate.
CalEnergy Generation-Foreign
Operating income for the first quarter of 2006 increased $13.6 million, or 31.0%, to $57.5 million from the comparable period in 2005. Operating revenue for the first quarter of 2006 increased $13.2 million, or 18.3%, to $85.4 million from the comparable period in 2005. The increase in operating income and operating revenue was mainly due to higher variable energy fees of $10.8 million as a result of significantly higher water flows and corresponding higher variable energy fees at the Casecnan Project as well as higher capacity fees of $1.4 million at the Leyte Projects.
HomeServices
Operating income for the first quarter of 2006 decreased $8.4 million, or 103.7%, to an operating loss of $0.3 million from the comparable period in 2005. Operating revenue for the first quarter of 2006 decreased $6.8 million, or 1.9%, to $355.5 million and cost of sales decreased $4.6 million, or 1.8%, to $245.6 million from the comparable period in 2005. The decreases in operating revenue and cost of sales were due to a decline from existing businesses totaling $13.8 million and $9.6 million, respectively, reflecting primarily lower brokerage transactions, particularly in California, partially offset by acquisitions not included in the comparable 2005 period totaling $7.0 million and $5.0 million, respectively.
Operating expenses for the first quarter of 2006 increased $5.4 million, or 5.4%, to $105.1 million from the comparable period in 2005 mainly due to $3.7 million in higher operating expense at existing businesses due primarily to higher marketing and occupancy expenses and $1.7 million related to acquisitions not included in the comparable 2005 period. Depreciation and amortization for the first quarter of 2006 increased $0.8 million, or 18.0%, to $5.1 million from the comparable period in 2005 due mainly to office expansions and acquisitions not included in the comparable 2005 period.
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Consolidated Other Income and Expense Items
Interest Expense
Interest expense for the first quarter of 2006 decreased $9.9 million to $221.7 million from the comparable period in 2005. Interest expense was lower in 2006 due to a $10.2 million charge incurred in February 2005 to exercise the call option on the £155.0 million Variable Rate Reset Trust Securities at CE Electric UK as well as maturities of and principal repayments on parent company senior and subordinated debt and subsidiary and project debt. Additional interest expense was incurred on CE Electric UK’s 5.125% £350.0 million bonds issued in May 2005 and MidAmerican Energy’s 5.75% $300.0 million debt issuance in November 2005 as well as $8.2 million of PacifiCorp’s interest expense.
Other Income, Net
Other income, net for the first quarter of 2006 and 2005 is summarized as follows (in millions):
2006 | 2005 | ||||||
Capitalized interest | $ | 4.6 | $ | 3.6 | |||
Interest and dividend income | 15.3 | 8.4 | |||||
Other income | 122.9 | 21.0 | |||||
Other expense | (1.2 | ) | (3.3 | ) | |||
Total other income, net | $ | 141.6 | $ | 29.7 |
Capitalized interest for the first quarter of 2006 increased $1.0 million to $4.6 million from the comparable period in 2005 due to higher capitalized interest at MidAmerican Energy associated with an increase in the construction of generation facilities.
Interest and dividend income for the first quarter of 2006 increased $6.9 million to $15.3 million from the comparable period in 2005 mainly due to earnings on guaranteed investment contracts (£100.0 million at 4.75% and £200.0 million at 4.73%) at CE Electric UK in May 2005 as well as earnings on higher cash balances and higher short-term interest rates.
Other income for the first quarter of 2006 increased $101.9 million to $122.9 million from the comparable period in 2005. In January 2006, Mirant emerged from bankruptcy and on February 6, 2006, a stipulated judgment was entered that allowed Kern River to receive a pro rata amount of shares of new Mirant stock determined by Kern River’s allowed claim amount plus interest in relation to the unsecured creditor class of over $6 billion. In February 2006, Kern River received an initial distribution of such shares in payment of the majority of its allowed claim. Other income in 2006 included Kern River’s $89.3 million of gains from the sales of Mirant stock, MidAmerican Funding’s realized gain of $7.3 million from the sale of a non-strategic investment and Northern Natural Gas’ gain of $5.4 million from a contractual settlement. In 2005, MidAmerican Funding realized gains of $10.2 million from the sales of certain non-strategic investments. Additionally, the allowance for equity funds used during construction for 2006 increased $2.8 million compared to 2005 due to increased levels of capital project expenditures at MidAmerican Energy.
Other expense for the first quarter of 2006 decreased $2.1 million to $1.2 million from the comparable period in 2005 due primarily to $1.9 million of losses for other-than-temporary impairments of MidAmerican Funding’s investments in commercial passenger aircraft leased to major domestic airlines recognized in 2005.
Income Tax Expense
Income tax expense for the first quarter of 2006 increased $57.2 million to $131.2 million from the comparable period in 2005. The effective tax rate was 34.3% and 33.2% for 2006 and 2005, respectively. The higher effective tax rate in 2006 was mainly due to higher taxes on foreign sourced income and higher tax accruals for uncertain tax positions, partially offset by a lower effective tax rate at MidAmerican Funding due mainly to the effects of rate making and production tax credits associated with wind generation.
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Minority Interest and Preferred Dividends of Subsidiaries
Minority interest and preferred dividends of subsidiaries for the first quarter of 2006 increased $1.1 million to $4.0 million from the comparable period in 2005 due mainly to higher earnings at CE Casecnan.
Equity Income
Equity income for the first quarter of 2006 decreased $3.1 million to $1.8 million from the comparable period in 2005 due mainly to lower earnings at CE Generation, LLC resulting from the timing of overhauls.
Liquidity and Capital Resources
The Company has available a variety of sources of liquidity and capital resources, both internal and external, including the Berkshire Equity Commitment. These resources provide funds required for current operations, construction expenditures, debt retirement and other capital requirements. The Company may from time to time seek to retire its outstanding securities through cash purchases in the open market, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Each of MEHC’s direct or indirect subsidiaries is organized as a legal entity separate and apart from MEHC and its other subsidiaries. Pursuant to separate financing agreements at each subsidiary, the assets of each subsidiary may be pledged or encumbered to support or otherwise provide the security for their own project or subsidiary debt. It should not be assumed that any asset of any subsidiary of MEHC will be available to satisfy the obligations of MEHC or any of its other subsidiaries; provided, however, that unrestricted cash or other assets which are available for distribution may, subject to applicable law and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to MEHC or affiliates thereof.
The Company’s cash and cash equivalents and short-term investments, which consist primarily of auction rate securities that are used in the Company’s cash management program, were $753.6 million at March 31, 2006, compared to $396.3 million at December 31, 2005. In addition, the Company recorded separately, in restricted cash and short-term investments and in deferred charges and other assets, restricted cash and investments of $122.2 million and $136.7 million at March 31, 2006 and December 31, 2005, respectively. The restricted cash balance is mainly composed of amounts deposited in restricted accounts relating to (i) the Company’s debt service reserve requirements relating to certain projects, (ii) customer deposits held in escrow, (iii) custody deposits, and (iv) unpaid dividends declared obligations. The debt service funds are restricted by their respective project debt agreements to be used only for the related project.
Cash Flows from Operating Activities
The Company generated cash flows from operations of $495.4 million for the first quarter of 2006, compared with $388.6 million from the comparable period in 2005. The increase was mainly due to better cash flow at MidAmerican Funding due to higher electric wholesale results and the greater utilization of income tax net operating loss carryforwards.
Cash Flows from Investing Activities
Capital Expenditures, Construction and Other Development Costs
Cash flows used in investing activities for the first quarter of 2006 and 2005 were $5,168.4 million and $192.6 million, respectively. The increase was primarily due to the acquisition of PacifiCorp, net of cash acquired, and an $80.3 million increase in capital expenditures, construction and other development costs. Additionally, Kern River received proceeds totaling $89.3 million from the sale of Mirant shares received in payment of the majority of its allowed bankruptcy claim.
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Capital expenditures, construction and other development costs were $308.6 million for the first quarter of 2006 compared with $228.3 million from the comparable period in 2005. The following table summarizes the expenditures by reportable segment (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2006 | 2005 | ||||||
Capital expenditures: | |||||||
PacifiCorp | $ | 63.8 | $ | - | |||
MidAmerican Funding | 130.6 | 142.9 | |||||
Northern Natural Gas | 19.1 | 10.4 | |||||
CE Electric UK | 87.0 | 73.5 | |||||
Other reportable segments | 8.0 | 1.5 | |||||
Total reportable segments | 308.5 | 228.3 | |||||
Corporate/other | 0.1 | - | |||||
Total capital expenditures | $ | 308.6 | $ | 228.3 |
Forecasted capital expenditures, construction and other development costs for fiscal 2006 are approximately $2.3 billion. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of such reviews. The Company expects to meet these capital expenditures with cash flows from operations and the issuance of debt. Capital expenditures relating to operating projects, consisting mainly of recurring expenditures and the funding of growing load requirements, were $244.6 million for the first quarter of 2006. Construction and other development costs were $64.0 million for the first quarter of 2006. These costs consist mainly of expenditures for large scale generation projects at PacifiCorp and MidAmerican Energy as described below.
PacifiCorp
As required by state regulators, PacifiCorp uses Integrated Resource Plans (“IRP”) to develop a long-term view of prudent future actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. The IRP process identifies the amount and timing of PacifiCorp's expected future resource needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts and other factors. The IRP is a coordinated effort with stakeholders in each of the six states where PacifiCorp operates.
PacifiCorp filed its 2004 IRP with the relevant state commissions in January 2005. The 2004 IRP identified a need for approximately 2,800 MW of additional resources by the summer of fiscal year 2015. This resource deficit was to be met with a combination of thermal generation (2,629 MW) and load control programs (177 MW). PacifiCorp released an update to the 2004 IRP in November 2005 and is currently preparing the 2006 IRP. In addition to new generation resources, future load growth could require substantial transmission investments to deliver power to customers. The actual investment requirement will depend on the location and other characteristics of the new generation resources.
In March 2006, PacifiCorp completed construction of the Currant Creek Power Plant, a 523 MW combined cycle plant in Utah. Total project costs incurred through March 31, 2006 were approximately $338 million. Presently under construction is the Lake Side Power Plant, an estimated 550 MW combined cycle plant in Utah, expected to be in service by the summer of 2007. The cost of the Lake Side Power Plant is expected to total approximately $347 million, of which approximately $209 million has been incurred through March 31, 2006. Both plants are 100% owned and operated by PacifiCorp.
Additionally, in conjunction with regulatory commitments made by the Company, approximately $520 million in investments are anticipated being made to PacifiCorp’s transmission and distribution system over the next several years that would enhance reliability, facilitate the receipt of renewable resources and enable further system optimization. Such investments would be subject to regulatory review and approval.
PacifiCorp’s capital requirements for 2006, subsequent to the Company’s acquisition of PacifiCorp, is estimated to be $975.6 million, which includes $127.2 million for the generation development projects described above, $101.7 million for emissions control equipment to address current and anticipated air quality regulations and $746.7 million for ongoing operational projects, including connections for new customers and facilities to accommodate load growth.
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MidAmerican Funding
MidAmerican Energy anticipates a continuing increase in demand for electricity from its regulated customers. To meet anticipated demand and ensure adequate electric generation in its service territory, MidAmerican Energy is currently constructing CBEC Unit 4, a 790 MW (expected accreditation) super-critical-temperature, coal-fired generating plant. MidAmerican Energy will operate the plant and hold an undivided ownership interest as a tenant in common with the other owners of the plant. MidAmerican Energy's current ownership interest is 60.67%, equating to 479 MW of output. Municipal, cooperative and public power utilities will own the remainder, which is a typical ownership arrangement for large base-load plants in Iowa. MidAmerican Energy expects to invest approximately $737 million in CBEC Unit 4, including transmission facilities and excluding allowance for funds used during construction. Through March 31, 2006, MidAmerican Energy has invested $542.1 million in the project, including $121.3 million for MidAmerican Energy’s share of deferred payments allowed by the construction contract.
On December 16, 2005, MidAmerican Energy filed with the Iowa Utilities Board (“IUB”) a settlement agreement between MidAmerican Energy and the Iowa Office of Consumer Advocate regarding ratemaking principles for up to 545 MW (nameplate ratings) of additional wind-powered generation capacity in Iowa. Generally speaking, accredited capacity ratings for wind power facilities are considerably less than the nameplate ratings due to the varying nature of wind. The settlement agreement was approved by the IUB on April 18, 2006. MidAmerican Energy has entered into an agreement for the construction of approximately 99 MW (nameplate rating) of wind turbines to be constructed in 2006.
MidAmerican Energy’s capital requirements for 2006 are estimated to be $796.6 million, which includes $422.1 million for the generation development projects described above, $60.9 million for emissions control equipment to address current and anticipated air quality regulations and $313.6 million for ongoing operational projects, including connections for new customers, facilities to accommodate load growth, infrastructure replacement and information technology systems.
Cash Flows from Financing Activities
Cash flows generated from financing activities for the first quarter of 2006 were $5,024.1 million. Sources of cash totaled $6,877.2 million and consisted mainly of $5,122.6 million of proceeds from the issuance of common stock and $1,699.3 million of proceeds from the issuance of parent company senior debt. Uses of cash totaled $1,853.1 million and consisted primarily of $1,750.0 million for purchases of common stock.
Cash flows used in financing activities for the first quarter of 2005 were $428.9 million. Uses of cash totaled $435.3 million and consisted primarily of $433.8 million for repayments of subsidiary and project debt. Sources of cash totaled $6.4 million.
Recent Debt Issuances and Stock Transactions
On March 6, 2006, Mr. David L. Sokol, Chairman and Chief Executive Officer of MEHC, exercised 450,000 common stock options having an exercise price of $29.01 per share. Additionally, Mr. Sokol put 344,274 shares of common stock to MEHC for a purchase price of $50.0 million.
On March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing stockholders and related companies invested $5,109.5 million, in the aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide equity funding for the PacifiCorp acquisition. The per share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by MEHC’s stockholders.
On March 24, 2006, MEHC completed a $1.7 billion offering of unsecured senior bonds due 2036 (the ‘‘Bonds’’). The Bonds were issued at an offering price of 99.957%, will accrue interest at a rate of 6.125% per annum and will mature on April 1, 2036. Accrued interest on the Bonds is payable on April 1 and October 1 of each year, commencing on October 1, 2006, until the principal amount of the Bonds is paid in full. The proceeds were used to fund MEHC’s exercise of its right to purchase shares of its common stock previously issued to Berkshire Hathaway.
On March 28, 2006, MEHC purchased 11,724,138 shares of common stock from Berkshire Hathaway for an aggregate purchase price of $1,700.0 million.
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The Energy Policy Act
On August 8, 2005, the Energy Policy Act was signed into law. That law potentially impacts many segments of the energy industry. A tax provision extended the federal production tax credit for new renewable electricity generation projects through December 31, 2007. In part as a result of that portion of the law, PacifiCorp and MidAmerican Energy began development efforts to add additional wind-powered generation. The law also results in expanding the FERC’s regulatory authority in areas such as mandatory electric system reliability standards, electric transmission expansion incentives and pricing, regulation of utility holding companies, and enforcement authority to issue substantial civil penalties.
CalEnergy Generation-Foreign - Customers
The Philippine National Oil Company-Energy Development Corporation (“PNOC-EDC”)’s and the Philippine National Irrigation Administration’s obligations under the project agreements are substantially denominated in U.S. Dollars and are the Leyte Projects’ and the Casecnan Project’s sole source of operating revenue. Because of the dependence on a single customer, any material failure of the customer to fulfill its obligations under the project agreements and any material failure of the Republic of the Philippines to fulfill its obligation under the performance undertaking would significantly impair the ability to meet existing and future obligations, including obligations pertaining to the outstanding project debt.
The 10-year cooperation periods for the Leyte Projects end in June 2006 and July 2007, respectively, at which time each project will be transferred to the PNOC-EDC at no cost on an “as-is” basis. For the first quarter of 2006, the Upper Mahiao Project’s financial results represented 0.6%, 1.2% and 1.7%, respectively, and the Mahanagdong and Malitbog Projects’ combined financial results represented 1.8%, 4.7% and 5.5%, respectively, of MEHC’s total consolidated operating revenue, income from continuing operations and operating cash flows from continuing operations. Additionally, the net properties, plants and equipment and the project debt of the Leyte Projects represented less than 1%, respectively, of MEHC’s total consolidated net properties, plants and equipment and subsidiary and project debt at March 31, 2006.
Credit Ratings Risks
Debt and preferred securities of MEHC and its subsidiaries may be rated by nationally recognized credit rating agencies. Assigned credit ratings are based on each rating agency’s assessment of the rated company’s ability to, in general, meet the obligations of its 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 its 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 it 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 March 31, 2006, PacifiCorp’s and MidAmerican Energy’s credit ratings from the three recognized credit rating agencies were investment grade; however if the ratings fell below investment grade, PacifiCorp’s and MidAmerican Energy’s estimated potential collateral requirements totaled approximately $334 million and $156 million, respectively. PacifiCorp’s and MidAmerican Energy’s potential collateral requirements could fluctuate considerably due to seasonality, market price volatility, and a loss of key generating facilities or other related factors.
Yorkshire Power Group Limited (“YPGL”), a subsidiary of CE Electric UK, has in effect certain currency rate swap agreements for its Yankee bonds with three large multi-national financial institutions. The swap agreements effectively convert the U.S. dollar fixed interest rate to a fixed rate in sterling for $281.0 million of 6.496% Yankee bonds outstanding at March 31, 2006. The agreements extend until February 25, 2008 and convert the U.S. dollar interest rate to a fixed sterling rate ranging from 7.3175% to 7.3450%. The estimated fair value of these swap agreements at March 31, 2006, was $68.0 million based on quotes from the counterparties to these instruments and represents the estimated amount that the Company would expect to pay if these agreements were terminated. Certain of these counterparties have the option to terminate the swap agreements and demand payment of the fair value of the swaps if YPGL’s credit ratings from the three recognized credit rating agencies decline below investment grade. As of March 31, 2006, YPGL’s credit ratings from the three recognized credit rating agencies were investment grade; however, if the ratings fell below investment grade, payment requirements would have been $31.7 million.
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Contractual Obligations and Commercial Commitments
The Company has contractual obligations and commercial commitments that may affect its financial condition. Contractual obligations to make future payments arise from parent company and subsidiary long-term debt and notes payable, operating leases and power and fuel purchase contracts. Other obligations and commitments arise from unused lines of credit and letters of credit. Material obligations and commitments as of March 31, 2006 are as follows (in millions):
Payments Due By Period | ||||||||||||||||
Remainder | 2011 and | |||||||||||||||
Total | of 2006 | 2007-2008 | 2009-2010 | After | ||||||||||||
Contractual Cash Obligations: | ||||||||||||||||
Parent company senior debt | $ | 4,475.0 | $ | - | $ | 1,550.0 | $ | - | $ | 2,925.0 | ||||||
Parent company subordinated debt | 1,663.8 | 234.0 | 468.0 | 422.5 | 539.3 | |||||||||||
Subsidiary and project debt | 11,016.6 | 495.2 | 1,530.6 | 557.2 | 8,433.6 | |||||||||||
Interest payments on long-term debt | 14,215.9 | 900.8 | 2,027.4 | 1,594.1 | 9,693.6 | |||||||||||
Short-term debt | 191.9 | 191.9 | - | - | - | |||||||||||
Coal, electricity and natural gas contract commitments(1) | 9,649.0 | 1,108.9 | 2,244.7 | 1,545.0 | 4,750.4 | |||||||||||
Owned hydroelectric commitments(1) | 637.1 | 21.6 | 68.3 | 68.6 | 478.6 | |||||||||||
Operating leases(1) | 420.7 | 70.4 | 147.7 | 85.5 | 117.1 | |||||||||||
Deferred costs on construction contract(2) | 200.0 | - | 200.0 | - | - | |||||||||||
Total contractual cash obligations | $ | 42,470.0 | $ | 3,022.8 | $ | 8,236.7 | $ | 4,272.9 | $ | 26,937.6 |
Commitment Expiration per Period | ||||||||||||||||
Remainder | 2011 and | |||||||||||||||
Total | of 2006 | 2007-2008 | 2009-2010 | After | ||||||||||||
Other Commercial Commitments: | ||||||||||||||||
Unused revolving credit facilities and lines of credit - | ||||||||||||||||
Parent company revolving credit facility | $ | 339.9 | $ | - | $ | - | $ | 339.9 | $ | - | ||||||
Subsidiary revolving credit facilities and lines of credit | 1,426.0 | 22.6 | - | 1,403.4 | - | |||||||||||
Total unused revolving credit facilities and lines of credit | $ | 1,765.9 | $ | 22.6 | $ | - | $ | 1,743.3 | $ | - | ||||||
Parent company letters of credit outstanding | $ | 61.2 | $ | - | $ | 61.2 | $ | - | $ | - | ||||||
Pollution control revenue bond standby letters of credit | $ | 296.9 | $ | - | $ | - | $ | 296.9 | $ | - | ||||||
Standby bond purchase agreements | $ | 220.9 | $ | 124.4 | $ | - | $ | - | $ | 96.5 | ||||||
Other standby letters of credit | $ | 40.5 | $ | 23.7 | $ | 16.8 | $ | - | $ | - |
______________
(1) | The coal, electricity and natural gas contract commitments, owned hydroelectric commitments and operating leases are not reflected on the consolidated balance sheets. |
(2) | MidAmerican Energy is allowed to defer up to $200.0 million in payments to the contractor under its contract to build CBEC Unit 4. Approximately 39.3% of this commitment is expected to be funded by the joint owners of CBEC Unit 4. |
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· | Debt service reserve guarantees |
· | Asset retirement obligations |
· | Nuclear decommissioning costs |
· | Residual guarantees on operating leases |
· | Pension and postretirement commitments |
Regulatory Matters
In addition to the discussion contained herein regarding updates to regulatory matters based upon changes that occurred during the three-month period ended March 31, 2006, refer to Note 7, “Regulatory Matters,” to the Interim Financial Statements for additional regulatory matter updates.
PacifiCorp
Pursuant to the FERC’s orders granting PacifiCorp authority to sell capacity and energy at market-based rates, PacifiCorp and certain of its former affiliates had been required to submit a joint market power analysis every three years. Under the FERC’s current policy, applicants must demonstrate that they do not possess market power in order to charge market-based rates for sales of wholesale energy and capacity in the applicants’ control areas. An analysis demonstrating an applicant’s passage of certain threshold screens for assessing generation market power establishes a rebuttable presumption that the applicant does not possess generation market power, while failure to pass any screen creates a rebuttable presumption that the applicant has generation market power. In February 2005, PacifiCorp submitted a joint triennial market power analysis in compliance with the FERC’s requirements. The analysis indicated that PacifiCorp failed to pass one of the generation market power screens in PacifiCorp’s eastern control area and in Idaho Power Company’s control area. In May 2005, the FERC issued an order instituting a proceeding pursuant to Section 206 of the Federal Power Act to determine whether PacifiCorp may continue to charge market-based rates for sales of wholesale energy and capacity. Under the terms of the order, PacifiCorp and its formerly affiliated co-applicants were required to submit additional information and analysis to the FERC within 60 days to rebut the presumption that PacifiCorp has generation market power. In June and July 2005, PacifiCorp filed additional analysis in response to the FERC’s May 2005 order. In January 2006, the FERC requested PacifiCorp to amend its previous filings with additional analysis, which was filed in March 2006. If the FERC ultimately finds that PacifiCorp has market power, PacifiCorp will be required to implement measures to mitigate any exercise of market power, which may result in decreased revenues and/or increased operating expenses. PacifiCorp believes the outcome of this proceeding will not have a material impact on its consolidated financial position or results of operations.
MidAmerican Funding
On July 13, 2004, the FERC issued an order requiring MidAmerican Energy to conduct a study to determine whether MidAmerican Energy or its affiliates possess generation market power. MidAmerican Energy is being required to show the absence of generation market power in order to be allowed to continue to sell wholesale electric power at market-based rates. The FERC order is intended to have MidAmerican Energy conform to what has become the FERC’s general practice for utilities given authorization to make wholesale market-based sales. Under this general practice, utilities authorized to make market-based electric sales must submit a new market power study to the FERC every three years. MidAmerican Energy filed the required study on October 29, 2004. On June 1, 2005, the FERC issued an order setting for investigation the reasonableness of MidAmerican Energy’s market-based rates within its control area. The order also terminated the previously established November 1, 2004, refund date and instead required that market-based sales made by MidAmerican Energy within its control area beginning August 7, 2005, be subject to refund until the matter is resolved. The FERC also required MidAmerican Energy to file additional information by July 1, 2005, and August 1, 2005. In its August 1, 2005 filing, MidAmerican Energy filed a proposed cost-based sales tariff (“CBST”) applicable to sales made within its control area to replace its market-based sales tariff. On March 17, 2006, the FERC issued an order (the “March 17 Order”) accepting MidAmerican Energy’s commitment not to make sales using market-based rates in its control area but rejected the proposed applicable tariff language. The FERC directed MidAmerican Energy to file revised tariff language by April 17, 2006. MidAmerican Energy made such filing together with a request for clarification, or in the alternative, rehearing (the “Request for Clarification”) of the March 17 Order. The FERC also rejected Service Schedule B of the CBST and established a procedural schedule to consider the reasonableness of the rates proposed for short-term sales under Service Schedule A of the CBST. On April 3, 2006, MidAmerican Energy filed an amendment to Service Schedule A to incorporate certain components of Service Schedule B. Testimony supporting the reasonableness of the Service Schedule A rates was filed on April 19, 2006. MidAmerican Energy estimates that its maximum refund obligation is $17 million and its minimum refund obligation is $50,000 for the period August 7, 2005 through March 31, 2006. The actual refund will depend upon the FERC’s ruling on the Request for Clarification and the applicability of the CBST to certain sales made within the control area for delivery outside the control area.
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Environmental Matters
In addition to the discussion contained herein, refer to Note 8, “Commitments and Contingencies,” to the Interim Financial Statements for additional information regarding certain environmental matters affecting PacifiCorp’s and MidAmerican Energy’s operations.
In conjunction with state regulatory approvals of the Company’s acquisition of PacifiCorp, the Company and PacifiCorp committed to invest approximately $812 million in capital spending over several years for emission control equipment to address current and future air quality initiatives implemented by the EPA or the states in which PacifiCorp operates facilities. Additional capital expenditures for emission reduction projects may be required, depending on the outcome of pending or new air quality regulations. PacifiCorp’s capital requirements for 2006, subsequent to the Company’s acquisition of PacifiCorp, total $101.7 million related to expenditures for such emission control capital projects.
MidAmerican Energy has implemented a planning process that forecasts the site-specific controls and actions that may be required to meet air emissions reductions as promulgated by the EPA. The plan allows MidAmerican Energy to more effectively manage its expenditures required to comply with emissions standards. On April 1, 2006, MidAmerican Energy submitted to the IUB an updated plan, as required every two years by Iowa law, which increased its estimate of required expenditures. MidAmerican Energy currently estimates that the incremental capital expenditures for emission control equipment to comply with air quality requirements will total approximately $540 million for January 1, 2006, through December 31, 2015. For 2006, MidAmerican Energy currently expects to incur $60.9 million of such capital expenditures.
In addition to capital expenditure requirements, incremental operating costs are expected to be incurred by PacifiCorp and MidAmerican Energy in conjunction with the utilization of the emission control equipment. Estimates of environmental capital and operating requirements may change significantly at any time as a result of, among other factors, changes in related regulations, prices of products used to meet the requirements, competition in the industry for similar technology and management’s strategies for achieving compliance with the regulations.
Critical Accounting Policies
The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, assumptions and estimates that affect the amounts reported in the consolidated financial statements and accompanying notes. Note 2 to the Company’s consolidated financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of long-lived assets, contingent liabilities and the accounting for revenue. Actual results could differ from these estimates.
For additional discussion of the Company’s critical accounting policies, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005. The Company’s critical accounting policies have not changed materially since December 31, 2005, except as they relate to the PacifiCorp acquisition and PacifiCorp’s derivative instruments.
PacifiCorp Acquisition
Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations” requires that the total purchase price of acquired companies be allocated to the net tangible and identified intangible assets acquired and liabilities assumed based on their estimated fair values as of the acquisition date. Such a valuation requires management to make significant estimates and assumptions. Management makes estimates of fair value based upon assumptions believed to be reasonable. These estimates are based on historical experience and information obtained from the management of the acquired companies. These estimates are inherently uncertain and unpredictable. Assumptions may be incomplete or inaccurate, and unanticipated events and circumstances may occur which may affect the accuracy or validity of such assumptions, estimates or actual results.
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PacifiCorp’s operations are regulated, which provide revenue derived from cost, and are accounted for pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” PacifiCorp has demonstrated a past history of recovering its costs incurred through its rate making process. Given the size and timing of the acquisition, the fair values established to date are preliminary and are subject to adjustment as additional information is obtained. When finalized, adjustments to goodwill may result.
The Company has not identified any material pre-acquisition contingencies where the related asset, liability or impairment is probable and the amount of the asset, liability or impairment can be reasonably estimated. Prior to the end of the purchase price allocation period, if information becomes available that a pre-acquisition related loss had been incurred and the amounts can be reasonably estimated, such items will be included in the purchase price allocation.
Certain transition activities will occur as PacifiCorp is integrated into the Company. Costs, consisting primarily of employee termination activities, will be incurred associated with such transition activities. The Company is in the process of finalizing these plans and expects to execute these plans over the next several months. In accordance with Emerging Issues Task Force Issue No. 95-3, “Recognition of Liabilities in Connection with a Purchase Business Combination” (“EITF 95-3”), the finalization of certain integration plans will result in adjustments to the purchase price allocation for the acquired assets and assumed liabilities of PacifiCorp. Transition costs that do not meet the criteria in EITF 95-3 are expensed in the period incurred.
Derivative Instruments
On April 1, 2001, PacifiCorp adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (“SFAS 133”), as amended. PacifiCorp uses derivative instruments (primarily forward purchases and sales) to manage the commodity price risk inherent in its fuel and electricity obligations, as well as to optimize the value of power generation assets and related contracts. PacifiCorp also enters into short-term energy derivatives on a limited basis for arbitrage purposes to take advantage of opportunities arising from market inefficiencies. SFAS 133 applies not only to traditional financial derivative instruments, but to any contract having the accounting characteristics of a derivative.
SFAS 133 requires that derivative instruments be recorded on the balance sheet at fair value. The fair values of derivative instruments are determined using forward price curves. Forward price curves represent PacifiCorp’s estimates of the prices at which a buyer or seller could contract today for delivery or settlement of a commodity at future dates. PacifiCorp bases its forward price curves upon market price quotations when available and uses internally developed, modeled prices when market quotations are unavailable. In general, PacifiCorp estimates the fair value of a contract by calculating the present value of the difference between the contract and the applicable forward price curve.
Price quotations for certain major electricity trading hubs are generally readily obtainable for the first six years and, therefore, PacifiCorp’s forward price curves for those locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively traded, forward price curves must be estimated in other ways. For short-term contracts at less actively traded locations, prices are modeled based on observed historical price relationships with actively traded locations. For long-term contracts extending beyond six years, the forward price curve is based upon the use of a fundamentals model (cost-to-build approach), due to the limited information available. Factors used in the fundamentals model include the forward prices for the commodities used as fuel to generate electricity, the expected system heat rate (which measures the efficiency of power plants in converting fuel to electricity) in the region where the purchase or sale takes place and a fundamentals forecast of expected spot prices for a commodity in a region based on modeled supply of and demand for the commodity in the region. The assumptions in these models are critical, since any changes in assumptions could have a significant impact on the fair value of the contract.
Despite the large volume of implementation guidance, SFAS 133 and the supplemental guidance do not provide specific guidance on all contract issues. As a result, significant judgment must be used in applying SFAS 133 and its interpretations.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
For quantitative and qualitative disclosures about market risk affecting the Company, see Item 7A, “Qualitative and Quantitative Disclosures About Market Risk,” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005. The Company’s exposure to market risk has not changed materially since December 31, 2005, except for the acquisition of PacifiCorp.
PacifiCorp participates in a wholesale energy market that includes public utility companies, electricity and natural gas marketers, financial institutions, industrial companies and government entities. A variety of products exist in this market, ranging from electricity and natural gas purchases and sales for physical delivery to financial instruments such as futures, swaps, options and other complex derivatives. Transactions may be conducted directly with customers and suppliers, through brokers, or with an exchange that serves as a central clearing mechanism.
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PacifiCorp is subject to the various risks inherent in the energy business, including credit risk, interest rate risk and commodity price risk. The risk management process established by PacifiCorp is designed to identify, assess, monitor, report, manage and mitigate each of the various types of risk involved in its business and activities and to measure quantitative market risk exposure and identify qualitative market risk exposure in its businesses. To assist in managing the volatility relating to these exposures, PacifiCorp enters into various transactions, including derivative transactions, consistent with PacifiCorp’s risk management policy and procedures. The risk management policy governs energy transactions and is designed for hedging PacifiCorp’s existing energy and asset exposures, and to a limited extent, the policy permits arbitrage activities to take advantage of market inefficiencies. The policy and procedures also govern PacifiCorp’s use of derivative instruments for commodity derivative transactions, as well as its energy purchase and sales practices, and describe PacifiCorp’s credit policy and management information systems required to effectively monitor such derivative use. PacifiCorp’s risk management policy provides for the use of only those instruments that have a similar volume or price relationship to its portfolio of assets, liabilities or anticipated transactions, thereby ensuring that such instruments will be primarily used for hedging. PacifiCorp’s portfolio of energy derivatives is substantially used for non-trading purposes.
PacifiCorp continues to actively manage its exposure to commodity price volatility. These activities may include adding to the generation portfolio and entering into transactions that help to shape PacifiCorp’s system resource portfolio, including wholesale contracts and financially settled weather-related derivative instruments that reduce volume and price risk due to weather extremes.
Credit Risk
Credit risk relates to the risk of loss that might occur as a result of non-performance by counterparties of their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with such counterparty.
To mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp has entered into netting and collateral arrangements that include margining and cross-product netting agreements and obtaining third-party guarantees, letters of credit and cash deposits. Counterparties may be assessed interest fees for delayed receipts. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement. At March 31, 2006, 81.6% of PacifiCorp’s credit exposure, net of collateral, within its electricity and natural gas portfolio of purchase and sale contracts was with counterparties having “investment grade” credit ratings from at least one major credit rating agency.
Interest Rate Risk
PacifiCorp is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and commercial paper. PacifiCorp manages its interest rate exposure by maintaining a blend of fixed-rate and variable-rate debt and by monitoring the effects of market changes in interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by PacifiCorp's pension plan assets, mining reclamation trust funds and cash balances. PacifiCorp’s principal sources of variable-rate debt are commercial paper and pollution control revenue bonds remarketed on a periodic basis. Commercial paper is periodically refinanced with fixed-rate debt when needed and when interest rates are considered favorable. PacifiCorp may also enter into financial derivative instruments, including interest rate swaps, swaptions and United States Treasury lock agreements, to manage and mitigate interest rate exposure. PacifiCorp does not anticipate using financial derivatives as the principal means of managing interest rate exposure. PacifiCorp’s weighted-average cost of debt is recoverable in rates. Increases or decreases in interest rates are reflected in PacifiCorp’s cost of debt calculation as rate cases are filed. Any adverse change to PacifiCorp’s credit rating could negatively impact PacifiCorp’s ability to borrow and the interest rates that are charged.
As of March 31, 2006, PacifiCorp had fixed-rate long-term debt of $3,405.4 million in aggregate principal amount and having a fair value of $3,597.1 million. These instruments are fixed-rate and therefore do not expose PacifiCorp to the risk of earnings loss due to changes in market interest rates. However, the fair value of these instruments would decrease by approximately $114 million if interest rates were to increase by 10% from their levels at March 31, 2006. In general, such a decrease in fair value would impact earnings and cash flows only if PacifiCorp were to reacquire all or a portion of these instruments prior to their maturity.
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As of March 31, 2006, PacifiCorp had $726.1 million of variable-rate liabilities and $113.6 million of temporary cash investments. At March 31, 2006, PacifiCorp had no financial derivatives in effect relating to interest rate exposure. Based on a sensitivity analysis as of March 31, 2006, for a one-year horizon, PacifiCorp estimates that if market interest rates average 1.0% higher (lower) in fiscal 2007 than in fiscal 2006, interest expense, net of offsetting impacts on interest income, would increase (decrease) by $6.1 million. This amount includes the effect of invested cash and was determined by considering the impact of the hypothetical interest rates on the variable-rate securities outstanding as of March 31, 2006. If interest rates change significantly, PacifiCorp might take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that might be taken and their possible effects, the sensitivity analysis assumes no changes in PacifiCorp’s financial structure.
Commodity Price Risk
PacifiCorp’s exposure to market risk due to commodity price change is primarily related to its fuel and electricity commodities, which are subject to fluctuations due to unpredictable factors, such as weather, electricity demand and plant performance, that affect energy supply and demand. PacifiCorp's energy purchase and sales activities are governed by PacifiCorp’s risk management policy and the risk levels established as part of that policy.
PacifiCorp’s energy commodity price exposure arises primarily from its electric supply obligation in the western United States. PacifiCorp manages this risk principally through the operation of its generation plants with a net capability of 8,470.4 MW, as well as transmission rights held both on some of its own 15,580-mile transmission system and on third-party transmission systems, and through its wholesale energy purchase and sales activities. Wholesale contracts are utilized primarily to balance PacifiCorp’s physical excess or shortage of net electricity for future time periods. Financially settled contracts are utilized to further mitigate commodity price risk. PacifiCorp may from time to time enter into other financially settled, temperature-related derivative instruments that reduce volume and price risk on days with weather extremes. In addition, a financially settled hydroelectric streamflow hedge is in place through September 2006 to reduce volume and price risks associated with PacifiCorp’s hydroelectric generation resources.
The fair value of derivative instruments is determined using forward price curves. Forward price curves represent PacifiCorp’s estimates of the prices at which a buyer or seller could contract today for delivery or settlement of a commodity at future dates. PacifiCorp bases its forward price curves upon market price quotations when available and internally developed and commercial models with internal and external fundamental data inputs when market quotations are unavailable. In general, PacifiCorp estimates the fair value of a contract by calculating the present value of the difference between the prices in the contract and the applicable forward price curve. Price quotations for certain major electricity trading hubs are generally readily obtainable for the first six years, and therefore PacifiCorp’s forward price curves for those locations and periods reflect observable market quotes. However, in the later years or for locations that are not actively traded, PacifiCorp must develop forward price curves. For short-term contracts at less actively traded locations, prices are modeled based on observed historical price relationships with actively traded locations. For long-term contracts extending beyond six years, the forward price curve is based upon the use of a fundamentals model (cost-to-build approach) due to the limited information available.
Factors used in the fundamentals model include the forward prices for the commodities used as fuel to generate electricity, the expected system heat rate (which measures the efficiency of electricity plants in converting fuel to electricity) in the region where the purchase or sale takes place and a fundamental forecast of expected spot prices based on modeled supply and demand in the region. The assumptions in these models are critical since any changes to the assumptions could have a significant impact on the fair value of the contract. Contracts with explicit or embedded optionality are valued by separating each contract into its physical and financial forward and option components. Forward components are valued against the appropriate forward price curve. The optionality is valued using a modified Black-Scholes model or a stochastic simulation (Monte Carlo) approach. Each option component is modeled and valued separately using the appropriate forward price curve. PacifiCorp's valuation models and assumptions are continuously updated to reflect current market information, and evaluations and refinements of model assumptions are performed on a periodic basis.
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The following table shows summarized information with respect to contractual maturities of PacifiCorp’s energy-related contracts qualifying as derivatives under SFAS 133 as of March 31, 2006.
Non-Trading | Trading | Total | ||||||||
Maturity: | ||||||||||
Less than 1 year | $ | 123.6 | $ | 0.2 | $ | 123.8 | ||||
1-3 years | 132.6 | - | 132.6 | |||||||
4-5 years | 10.9 | - | 10.9 | |||||||
Excess of 5 years | (259.4 | ) | - | (259.4 | ) | |||||
Total | $ | 7.7 | $ | 0.2 | $ | 7.9 |
Item 4. Controls and Procedures.
An evaluation was performed under the supervision and with the participation of the Company’s management, including the chief executive officer and chief financial officer, regarding 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) as of March 31, 2006. Based on that evaluation, the Company’s management, including the chief executive officer and chief financial officer, concluded that the Company’s disclosure controls and procedures were effective. As a result of the acquisition of PacifiCorp in the first quarter of 2006, the Company has expanded its internal control over financial reporting to include consolidation of the PacifiCorp results of operations, as well as acquisition related accounting and disclosures. There have been no other changes during the quarter covered by this report in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
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PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
For a description of certain legal proceedings affecting the Company, please review Item 3, “Legal Proceedings” included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005. In addition to the discussion contained herein, refer to Note 8, “Commitments and Contingencies,” to the Interim Financial Statements for additional information regarding the Company’s legal proceedings.
PacifiCorp
In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by the Klamath Tribes of Oregon, individual Klamath Tribal members and the Klamath Claims Committee. The complaint generally alleges that PacifiCorp and its predecessors affected the Klamath Tribes’ federal treaty rights to fish for salmon in the headwaters of the Klamath River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. In September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for sucker and steelhead in the headwaters of the Klamath River. The complaint seeks in excess of $1.0 billion in compensatory and punitive damages. In July 2005, the District Court dismissed the case and in September 2005 denied the Klamath Tribes’ request to reconsider the dismissal. In October 2005, the Klamath Tribes appealed the District Court’s decision to the Ninth Circuit Court of Appeals and briefing was completed in March 2006. Any final order of the Court of Appeals will be subject to appeal. PacifiCorp believes the outcome of this proceeding will not have a material impact on its consolidated financial position, results of operations or liquidity.
In October 2005, PacifiCorp was added as a defendant to a lawsuit originally filed in February 2005 in state district court in Salt Lake City, Utah by USA Power, LLC and its affiliated companies, USA Power Partners, LLC and Spring Canyon, LLC (collectively, “USA Power”), against Utah attorney Jody L. Williams and the law firm Holme, Roberts & Owen, LLP, who represent PacifiCorp on various matters from time to time. USA Power is the developer of a planned generation project in Mona, Utah, called Spring Canyon, which PacifiCorp, as part of its resource procurement process, at one time considered as an alternative to the Currant Creek Power Plant. USA Power’s complaint alleges that PacifiCorp misappropriated confidential proprietary information in violation of Utah’s Uniform Trade Secrets Act and accuses PacifiCorp of breach of contract and related claims. USA Power seeks $250.0 million in damages, statutory doubling of damages for its trade secrets violation claim, punitive damages, costs and attorneys’ fees. PacifiCorp believes it has a number of defenses and intends to vigorously oppose any claim of liability for the matters alleged by USA Power. Furthermore, PacifiCorp expects that the outcome of this proceeding will not have a material impact on its consolidated financial position, results of operations or liquidity.
MidAmerican Funding
On December 28, 2004, an apparent gas explosion and fire resulted in three fatalities, one serious injury and property damage at a commercial building in Ramsey, Minnesota. According to the Minnesota Office of Pipeline Safety, an improper installation of a pipeline connection may have been a cause of the explosion and fire. A predecessor company to MidAmerican Energy allegedly provided gas service in Ramsey, Minnesota at the time of the original installation of the pipeline in 1980. In 1993, a predecessor of CenterPoint Resources Corp. (“CenterPoint”) acquired all of the Minnesota gas properties owned by the MidAmerican Energy predecessor company.
As a result of the explosion and fire, MidAmerican Energy and CenterPoint have received settlement demands which total $15.5 million. MidAmerican Energy’s exposure, if any, to these demands are covered under its liability insurance coverage to which a $2.0 million retention applies. In addition, counsel for CenterPoint stated that a replacement program has been initiated for the purpose of locating and replacing all mechanical couplings in the former North Central Public Service Company properties located in Minnesota. Counsel for CenterPoint has represented that the value of the replacement claim may be in the range of $35-$45 million.
Three lawsuits are currently on file related to this incident. On February 8, 2006, MidAmerican Energy was served with a Third Party Complaint filed in U.S. District Court, District of Minnesota, by CenterPoint. The Third Party Complaint seeks contribution and indemnity on a wrongful death claim filed by the estate of one of the decedents and all sums associated with CenterPoint’s replacement program. MidAmerican Energy was served with a second Third Party Complaint filed in U.S. District Court, District of Minnesota, by CenterPoint seeking contribution and indemnity on a property damage and business interruption claim filed by Ramsey Premier Partners, LLC, and all sums associated with CenterPoint’s replacement program. MidAmerican Energy filed a motion for summary judgment in both of these cases on April 27, 2006. An additional complaint filed in Anoka County District Court, State of Minnesota, by the estate of one of the decedents seeks damages from MEHC and other defendants, including CenterPoint, on a wrongful death claim arising from this incident. This wrongful death claim was settled by CenterPoint during mediation in March 2006; however, the complaint remains on file with the court until the appropriate documents relating to the estate are filed. MEHC and MidAmerican Energy intend to vigorously defend the Company’s position in these claims and believe their ultimate outcome will not have a material impact on the Company’s results of operations, financial position or cash flows.
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Item 1A. Risk Factors.
There has been no material change to the Company’s risk factors from those disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2005, except for those related to the acquisition of PacifiCorp, which was consummated on March 21, 2006. The Company’s risk factors after consummation of the acquisition of PacifiCorp are incorporated by reference into this Item 1A by reference to Exhibit 20.1 to MEHC’s Current Report on Form 8-K dated March 17, 2006.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
On March 6, 2006, Mr. David L. Sokol, Chairman and Chief Executive Officer of MEHC put 344,274 shares of common stock to MEHC for a purchase price of $50.0 million.
On March 21, 2006, Berkshire Hathaway and certain other of MEHC’s existing stockholders and related companies invested $5,109.5 million, in the aggregate, in 35,237,931 shares of MEHC’s common stock in order to provide equity funding for the PacifiCorp acquisition. The per share value assigned to the shares of common stock issued, which were effected pursuant to a private placement and were exempt from the registration requirements of the Securities Act of 1933, as amended, was based on an assumed fair market value as agreed to by MEHC’s stockholders.
On March 28, 2006, MEHC purchased 11,724,138 shares of common stock from Berkshire Hathaway for an aggregate purchase price of $1,700.0 million.
Item 3. Defaults Upon Senior Securities.
Not applicable.
Item 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
Item 5. Other Information.
Not applicable.
Item 6. Exhibits.
The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.
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SIGNATURES
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: May 5, 2006 | /s/ Patrick J. Goodman |
Patrick J. Goodman | |
Senior Vice President and Chief Financial Officer |
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EXHIBIT INDEX
Exhibit No. | Description |
31.1 | Chief Executive Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.2 | Chief Financial Officer’s Certificate Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.1 | Chief Executive Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.2 | Chief Financial Officer’s Certificate Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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