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,September 30, 2007
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ______ to _______
Commission | | Exact name of registrant as specified in its charter | | IRS Employer |
| | State or other jurisdiction of incorporation or organization | | |
|
1-5152 | | PacifiCorp | | 93-0246090 |
| | (An Oregon Corporation) | | |
| | 825 N.E. Multnomah Street | | |
| | Portland, Oregon 97232 | | |
| | 503-813-5000 | | |
|
|
(Former name, former address and former fiscal year, if changed since last report) |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes T No མ¨
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 མ¨ | Accelerated filer མ¨ | Non-accelerated filer T |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes མ¨ No T
As of April 30,October 31, 2007, all 357,060,915 outstanding shares of PacifiCorp’s common stock were indirectly owned by MidAmerican Energy Holdings Company.
TABLE OF CONTENTS
PART I -– FINANCIAL INFORMATION
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of PacifiCorp:
We have reviewed the accompanying consolidated balance sheet of PacifiCorp and its subsidiaries (“PacifiCorp”) as of March 31,September 30, 2007, and the related consolidated statements of income for the three-month and nine-month periods ended September 30, 2007 and 2006, and the related consolidated statements of cash flows for the three-month periodnine-month periods ended March 31, 2007.September 30, 2007 and 2006. These interim financial statements are the responsibility of PacifiCorp’s management.
We conducted our reviewreviews 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 review,reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements as of March 31, 2007, and for the three-month period then ended 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 PacifiCorp and its subsidiaries as of December 31, 2006, and the related consolidated statements of income, common shareholder’s equity and comprehensive income, and of cash flows for the nine-month period then ended (not presented herein); and in our report dated February 27, 2007, we expressed an unqualified opinion on those consolidated financial statements, which included an explanatory paragraph related to the adoption of SFASStatement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132(R). In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2006, is fairly presented,stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
The accompanying consolidated financial information for the three-month period ended March 31, 2006, was not audited or reviewed by us and, accordingly, we do not express an opinion or any form of assurance on it.
/s/ Deloitte & Touche LLP
Portland, Oregon
May 4,November 2, 2007
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(Amounts in millions)
| | Three-Month Periods | | | Three-Month Periods | | | Nine-Month Periods | |
| | Ended March 31, | | | Ended September 30, | | | Ended September 30, | |
| | 2007 | | 2006 | | | 2007 | | | 2006 | | | 2007 | | | 2006 | |
| | | | | | | | | | | | | | | | | | | |
Revenues | | $ | 1,027 | | $ | 1,230 | | | $ | 1,137 | | | $ | 1,097 | | | $ | 3,190 | | | $ | 3,187 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Operating expenses: | | | | | | | | | | | | | | | | | | | | | | | |
Energy costs | | | 415 | | | 548 | | | 487 | | | 567 | | | 1,327 | | | 1,451 | |
Operations and maintenance | | | 262 | | | 274 | | | 230 | | | 253 | | | 747 | | | 787 | |
Depreciation and amortization | | | 121 | | | 113 | | | 125 | | | 118 | | | 368 | | | 347 | |
Taxes, other than income taxes | | | 28 | | | 24 | | | | 26 | | | | 27 | | | | 77 | | | | 77 | |
Total | | | 826 | | | 959 | | | | 868 | | | | 965 | | | | 2,519 | | | | 2,662 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Income from operations | | | 201 | | | 271 | | | | 269 | | | | 132 | | | | 671 | | | | 525 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Interest expense and other (income) expense: | | | | | | | | |
Interest and other expense (income): | | | | | | | | | | | | | | | | | |
Interest expense | | | 75 | | | 69 | | | 76 | | | 72 | | | 230 | | | 210 | |
Interest income | | | (3 | ) | | (2 | ) | | (3 | ) | | (3 | ) | | (10 | ) | | (7 | ) |
Allowance for borrowed funds | | | (7 | ) | | (5 | ) | | (8 | ) | | (6 | ) | | (24 | ) | | (16 | ) |
Allowance for equity funds | | | (7 | ) | | (6 | ) | | (11 | ) | | (6 | ) | | (28 | ) | | (18 | ) |
Other | | | - | | | (2 | ) | | | 2 | | | | (1 | ) | | | - | | | | (3 | ) |
Total | | | 58 | | | 54 | | | | 56 | | | | 56 | | | | 168 | | | | 166 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Income before income tax expense | | | 143 | | | 217 | | | 213 | | | 76 | | | 503 | | | 359 | |
Income tax expense | | | 44 | | | 70 | | | | 78 | | | | 17 | | | | 164 | | | | 110 | |
Net income | | | 99 | | | 147 | | | $ | 135 | | | $ | 59 | | | $ | 339 | | | $ | 249 | |
Preferred dividend requirement | | | (1 | ) | | (1 | ) | |
Earnings on common stock | | $ | 98 | | $ | 146 | | |
The accompanying notes are an integral part of these financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | As of | | | | |
| | March 31, | | December 31, | | | September 30, | | | December 31, | |
| | 2007 | | 2006 | | | | | | | |
| | | | | | |
ASSETS | ASSETS | ASSETS | |
| | | | | | | | | | | | | |
Current assets: | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 449 | | $ | 59 | | | $ | 56 | | | $ | 59 | |
Accounts receivable, net | | | 316 | | | 342 | | | 406 | | | 342 | |
Unbilled revenue | | | 153 | | | 178 | | | 182 | | | 178 | |
Amounts due from affiliates - MEHC | | | 11 | | | 53 | | |
Amounts due from affiliates | | | 15 | | | 53 | |
Inventories at average costs: | | | | | | | | | | | | | | | |
Materials and supplies | | | 150 | | | 140 | | | 162 | | | 140 | |
Fuel | | | 111 | | | 104 | | | 127 | | | 104 | |
Derivative contract asset | | | 123 | | | 151 | | |
Derivative contracts | | | 140 | | | 151 | |
Deferred income taxes | | | 61 | | | 28 | | | 75 | | | 28 | |
Other | | | 55 | | | 57 | | | | 124 | | | | 57 | |
Total current assets | | | 1,429 | | | 1,112 | | | | 1,287 | | | | 1,112 | |
| | | | | | | | | | | | | | | |
Property, plant and equipment | | | 16,008 | | | 15,843 | | | 16,866 | | | 15,843 | |
Accumulated depreciation and amortization | | | (5,932 | ) | | (5,842 | ) | | | (6,081 | ) | | | (5,842 | ) |
| | | 10,076 | | | 10,001 | | | 10,785 | | | 10,001 | |
Construction work-in-progress | | | 1,000 | | | 809 | | | | 787 | | | | 809 | |
Total property, plant and equipment, net | | | 11,076 | | | 10,810 | | | | 11,572 | | | | 10,810 | |
| | | | | | | | | | | | | | | |
Other assets: | | | | | | | | | | | | | | | |
Regulatory assets | | | 1,412 | | | 1,397 | | | 1,318 | | | 1,397 | |
Derivative contract asset | | | 208 | | | 235 | | |
Derivative contracts | | | 178 | | | 235 | |
Deferred charges and other | | | 295 | | | 298 | | | | 282 | | | | 298 | |
Total other assets | | | 1,915 | | | 1,930 | | | | 1,778 | | | | 1,930 | |
| | | | | | | | | | | | | | | |
Total assets | | $ | 14,420 | | $ | 13,852 | | | $ | 14,637 | | | $ | 13,852 | |
The accompanying notes are an integral part of these financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
| | As of | | | | |
| | March 31, | | December 31, | | | September 30, | | | December 31, | |
| | 2007 | | 2006 | | | | | | | |
| | | | |
LIABILITIES AND SHAREHOLDERS’ EQUITY | LIABILITIES AND SHAREHOLDERS’ EQUITY | LIABILITIES AND SHAREHOLDERS’ EQUITY | |
| | | | | | | |
Current liabilities: | | | | | | | | | | | | | |
Accounts payable | | $ | 382 | | $ | 385 | | | $ | 401 | | | $ | 385 | |
Amounts due to affiliates - MEHC | | | 38 | | | 1 | | |
Amounts due to affiliates | | | 2 | | | 1 | |
Accrued employee expenses | | | 117 | | | 85 | | | 118 | | | 85 | |
Taxes payable, other than income taxes | | | 46 | | | 30 | | | 63 | | | 30 | |
Interest payable | | | 63 | | | 57 | | | 78 | | | 57 | |
Derivative contract liability | | | 110 | | | 110 | | |
Derivative contracts | | | 160 | | | 110 | |
Long-term debt and capital lease obligations, currently maturing | | | 121 | | | 127 | | | 413 | | | 127 | |
Preferred stock subject to mandatory redemption, currently maturing | | | 38 | | | 38 | | | - | | | 38 | |
Short-term debt | | | 216 | | | 397 | | | 206 | | | 397 | |
Other | | | 132 | | | 135 | | | | 136 | | | | 135 | |
Total current liabilities | | | 1,263 | | | 1,365 | | | | 1,577 | | | | 1,365 | |
| | | | | | | | | | | | | | | |
Deferred credits: | | | | | | | | | | | | | | | |
Deferred income taxes | | | 1,625 | | | 1,641 | | | 1,665 | | | 1,641 | |
Investment tax credits | | | 60 | | | 62 | | | 56 | | | 62 | |
Regulatory liabilities | | | 815 | | | 822 | | | 794 | | | 822 | |
Derivative contract liability | | | 494 | | | 504 | | |
Derivative contracts | | | 459 | | | 504 | |
Pension and other post employment liabilities | | | 666 | | | 691 | | | 513 | | | 691 | |
Other | | | 394 | | | 374 | | | | 427 | | | | 374 | |
Total deferred credits | | | 4,054 | | | 4,094 | | | | 3,914 | | | | 4,094 | |
| | | | | | | | | | | | | | | |
Long-term debt and capital lease obligations, net of current maturities | | | 4,567 | | | 3,967 | | | | 4,166 | | | | 3,967 | |
Total liabilities | | | 9,884 | | | 9,426 | | | | 9,657 | | | | 9,426 | |
| | | | | | | | | | | | | | | |
Commitments and contingencies (See Note 6) | | | | | | | | |
Commitments and contingencies (Note 5) | | | | | | | | | |
| | | | | | | | | | | | | | | |
Shareholders’ equity: | | | | | | | | | | | | | | | |
Preferred stock | | | 41 | | | 41 | | | | 41 | | | | 41 | |
Common equity: | | | | | | | | | | | | | | | |
Common shareholder’s capital - 750 shares authorized, no par value, 357 shares issued and outstanding | | | 3,602 | | | 3,600 | | | 3,804 | | | 3,600 | |
Retained earnings | | | 901 | | | 789 | | | 1,139 | | | 789 | |
Accumulated other comprehensive loss, net | | | (8 | ) | | (4 | ) | | | (4 | ) | | | (4 | ) |
Total common equity | | | 4,495 | | | 4,385 | | | | 4,939 | | | | 4,385 | |
Total shareholders’ equity | | | 4,536 | | | 4,426 | | | | 4,980 | | | | 4,426 | |
Total liabilities and shareholders' equity | | $ | 14,420 | | $ | 13,852 | | |
| | | | | | | | | |
Total liabilities and shareholders’ equity | | | $ | 14,637 | | | $ | 13,852 | |
The accompanying notes are an integral part of these financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | Three-Month Periods | | | Nine-Month Periods | |
| | Ended March 31, | | | | |
| | 2007 | | 2006 | | | | | | | |
| | | | | | | | | | | | | |
Cash flows from operating activities: | | | | | | | | | | | | | |
Net income | | $ | 99 | | $ | 147 | | | $ | 339 | | | $ | 249 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | | | | | | |
Unrealized gain on derivative contracts, net | | | (3 | ) | | (53 | ) | |
Unrealized loss (gain) on derivative contracts, net | | | (4 | ) | | 45 | |
Depreciation and amortization | | | 121 | | | 113 | | | 368 | | | 347 | |
Deferred income taxes and investment tax credits, net | | | (12 | ) | | 8 | | | 17 | | | (32 | ) |
Regulatory asset/liability establishment and amortization | | | 2 | | | 6 | | | (37 | ) | | 22 | |
Other | | | 8 | | | 6 | | | 11 | | | 33 | |
Changes in: | | | | | | | | | | | | | | | |
Accounts receivable, net and other assets | | | 49 | | | 32 | | | (76 | ) | | (67 | ) |
Inventories | | | (17 | ) | | (23 | ) | | (45 | ) | | (38 | ) |
Amounts due to/from affiliates - MEHC, net | | | 79 | | | - | | | 39 | | | - | |
Amounts due to/from affiliates - ScottishPower, net | | | - | | | (1 | ) | |
Accounts payable and other liabilities | | | 12 | | | 86 | | | | 38 | | | | 117 | |
Net cash provided by operating activities | | | 338 | | | 321 | | | | 650 | | | | 676 | |
| | | | | | | | | | | | | | | |
Cash flows from investing activities: | | | | | | | | | | | | | | | |
Capital expenditures | | | (376 | ) | | (333 | ) | | (1,136 | ) | | (1,113 | ) |
Proceeds from sale of assets | | | 6 | | | - | | | 9 | | | - | |
Proceeds from available-for-sale securities | | | 14 | | | 32 | | | 22 | | | 78 | |
Purchases of available-for-sale securities | | | (12 | ) | | (20 | ) | | (19 | ) | | (80 | ) |
Other | | | 8 | | | (15 | ) | | | 12 | | | | (7 | ) |
Net cash used in investing activities | | | (360 | ) | | (336 | ) | | | (1,112 | ) | | | (1,122 | ) |
| | | | | | | | | | | | | | | |
Cash flows from financing activities: | | | | | | | | | | | | | | | |
Changes in short-term debt | | | (181 | ) | | (30 | ) | | (191 | ) | | (135 | ) |
Proceeds from long-term debt, net of issuance costs | | | 600 | | | - | | | 599 | | | 346 | |
Proceeds from equity contributions | | | - | | | 110 | | | 200 | | | 255 | |
Dividends paid | | | (1 | ) | | (17 | ) | | (2 | ) | | (18 | ) |
Repayments and redemptions on long-term debt and capital lease obligations | | | (6 | ) | | (100 | ) | |
Repayments and redemptions on long-term debt, preferred stock subject to mandatory redemption and capital lease obligations | | | (153 | ) | | (108 | ) |
Other | | | - | | | 8 | | | | 6 | | | | 10 | |
Net cash provided by (used in) financing activities | | | 412 | | | (29 | ) | |
Net cash provided by financing activities | | | | 459 | | | | 350 | |
| | | | | | | | | | | | | | | |
Change in cash and cash equivalents | | | 390 | | | (44 | ) | | (3 | ) | | (96 | ) |
Cash and cash equivalents at beginning of period | | | 59 | | | 164 | | | | 59 | | | | 164 | |
Cash and cash equivalents at end of period | | $ | 449 | | $ | 120 | | | $ | 56 | | | $ | 68 | |
The accompanying notes are an integral part of these financial statements.
PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1)General
PacifiCorp (which includes PacifiCorp and its subsidiaries) is a United States electric utility company serving retail customers in portions of the states of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp generates electricity and also engages in electricity sales and purchases on a wholesale basis. The subsidiaries of PacifiCorp support its electric utility operations by providing coal mining facilities and services steam delivery services and environmental remediation. PacifiCorp is an indirect subsidiary of MidAmerican Energy Holdings Company (“MEHC”), whicha holding company based in Des Moines, Iowa, owning subsidiaries that are principally engaged in energy businesses. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”).
The accompanying unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and the U.S. Securities and Exchange Commission’s (the “SEC”) rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements include all adjustments (consisting only of normal recurring adjustments) considered necessary for fair presentation of the financial statements as of March 31,September 30, 2007, and for the three-monththree- and nine-month periods ended March 31,September 30, 2007 and 2006. A portion of PacifiCorp’s business is of a seasonal nature and, therefore, results of operations for the three-monththree- and nine-month periods ended March 31,September 30, 2007, and 2006 are not necessarily indicative of the results to be expected for athe full year.
The accompanying unaudited Consolidated Financial Statements include the accounts of PacifiCorp and its subsidiaries in which it holds a controlling financial interest. Intercompany accounts and transactions have been eliminated.
The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Management’s Discussion and Analysis and Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006, describedescribes the most significant accounting estimates and policies used in the preparation of the Consolidated Financial Statements. There have been no significant changes in PacifiCorp’s assumptions regarding critical accounting estimates and significant accounting policies during the first threenine months of 2007, except as described in Note 2.
(2)New Accounting Pronouncements
In February 2007,July 2006, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment to SFAS No. 115”(“SFAS No. 159”). SFAS No. 159 permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at initial recognition of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only to specified risks, cash flows or portions of that instrument. SFAS No. 159 does not affect any existing accounting standards that require certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. PacifiCorp is currently evaluating the impact of adopting SFAS No. 159 on its consolidated financial position and results of operations.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”(“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not impose fair value measurements on items not already accounted for at fair value; rather, it applies, with certain exceptions, to other accounting pronouncements that either require or permit fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. PacifiCorp is currently evaluating the impact of adopting SFAS No. 157 on its consolidated financial position and results of operations.
In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-anTaxes – an interpretation of FASB Statement No. 109” (“FIN 48”). PacifiCorp adopted the provisions of FIN 48 effective January 1, 2007. Under FIN 48, tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in PacifiCorp’s tax returns that do not meet these recognition and measurements standards.
As of January 1, 2007, PacifiCorp had an asset of $22 million for uncertain tax positions. PacifiCorp recognized a net increase in the asset of $22 million as a cumulative effect of adopting FIN 48, which was offset by increases in beginning retained earnings of $13 million and deferred income tax liabilities of $9 million in the Consolidated Balance Sheet. The $22 million isas of January 1, 2007, was included in other deferred credits in the Consolidated Balance Sheet.
Included in the asset of $22 million areis $14 million of net uncertain tax positions that, if recognized, would have an impact on the effective tax rate. The remaining amounts relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax positions, other than applicable interest and penalties, would not affect PacifiCorp’s effective tax rate. PacifiCorp recognizes interest and penalties accrued related to uncertain tax positions in income tax expense. As of January 1, 2007, PacifiCorp had $7 million accrued for the receipt of interest, which is included in the asset for uncertain tax positions.
Prior to 2006, PacifiCorp filed income tax returns in the U.S. federal jurisdiction and various state jurisdictions. The U.S. Internal Revenue Service has closed examination of PacifiCorp’s income tax returns through its tax year ended March 31, 2000. In addition, open tax years related to a number of state jurisdictions remain subject to examination. As a result of the sale of PacifiCorp to MEHC on March 21, 2006, Berkshire Hathaway commenced including PacifiCorp in its U.S. Federalfederal income tax returns. During
In February 2007, the three-month period ended March 31, 2007, there were no material changesFASB issued Statement of Financial Accounting Standards (“SFAS”) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - including an amendment to SFAS No. 115”(“SFAS No. 159”). SFAS No. 159 permits entities to elect to measure many financial instruments and certain other items at fair value. Upon adoption of SFAS No. 159, an entity may elect the fair value option for eligible items that exist at the adoption date. Subsequent to the initial adoption, the election of the fair value option should only be made at initial recognition of the asset or liability or upon a remeasurement event that gives rise to new-basis accounting. The decision about whether to elect the fair value option is applied on an instrument-by-instrument basis, is irrevocable and is applied only to an entire instrument and not only to specified risks, cash flows or portions of that instrument. SFAS No. 159 does not affect any existing accounting standards that require certain assets and liabilities to be carried at fair value nor does it eliminate disclosure requirements included in other accounting standards. SFAS No. 159 is effective for uncertain tax positions.fiscal years beginning after November 15, 2007. PacifiCorp does not anticipate electing the fair value option for any existing eligible items. However, PacifiCorp will continue to evaluate items on a case-by-case basis for consideration of the fair value option.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”(“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 does not impose fair value measurements on items not already accounted for at fair value; rather, it applies, with certain exceptions, to other accounting pronouncements that either require or permit fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. PacifiCorp is currently evaluating the impact of adopting SFAS No. 157 on its consolidated financial position and results of operations.
(3)Recent Debt TransactionTransactions
In October 2007, PacifiCorp entered into a new unsecured revolving credit facility with total bank commitments of $700 million. The facility will support PacifiCorp's commercial paper program and terminates on October 23, 2012. Terms and conditions, including borrowing rates, are substantially similar to PacifiCorp's existing revolving credit facility.
OnIn October 2007, PacifiCorp issued $600 million of its 6.25% First Mortgage Bonds due October 15, 2037. The proceeds will be used to repay short-term debt and for general corporate purposes.
In June 2007, PacifiCorp redeemed $38 million of outstanding preferred stock subject to mandatory redemption, representing the remaining outstanding shares of PacifiCorp’s $7.48 No Par Serial Preferred Stock series.
In March 14, 2007, PacifiCorp issued $600 million of its 5.75% First Mortgage Bonds due April 1, 2037. The proceeds are beingwere used to repay short-term debt and for other general corporate purposes.
(4)Risk Management and Hedging Activities
PacifiCorp is directly exposed to the impact of market fluctuations in thecommodity prices, ofprincipally natural gas and electricity. PacifiCorp is exposed to interestInterest rate risk as a result of the issuance of fixed andexists on variable rate debt.debt, commercial paper and future debt issuances. PacifiCorp employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, swaps and options. The risk management process established by PacifiCorp is designed to identify, measure, assess, monitor, report, manage and managemitigate each of the various types of risk involved in its business. PacifiCorp’s portfolio of energy derivatives is substantially used for non-trading purposes. As of March 31,September 30, 2007 and December 31, 2006, PacifiCorp had no financial derivatives in effect relating to interest rate exposure.
The following table summarizes the various derivative mark-to-market positions included in the accompanying Consolidated Balance SheetsSheet as of March 31,September 30, 2007 (in millions):
| | | | | | | | | | Accumulated | | | | | | | | | | | | | | | Accumulated | |
| | | | | | | | Regulatory | | Other | | | | | | | | | | | | Regulatory | | | Other | |
| | Derivative Net Asset (Liability) | | Net Asset | | Comprehensive | | | Derivative Net Assets (Liabilities) | | | Net Assets | | | Comprehensive | |
| | Assets | | Liabilities | | Total | | (Liability) | | Income (Loss) (1) | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity derivatives | | $ | 330 | | $ | (604 | ) | $ | (274 | ) | $ | 271 | | $ | (3 | ) | |
Foreign currency contracts | | | 1 | | | - | | | 1 | | | (1 | ) | | - | | |
Commodity | | | $ | 314 | | | $ | (619 | ) | | $ | (305 | ) | | $ | 311 | | | $ | (3 | ) |
Foreign currency | | | | 4 | | | | - | | | | 4 | | | | (4 | ) | | | - | |
Total | | $ | 331 | | $ | (604 | ) | $ | (273 | ) | $ | 270 | | $ | (3 | ) | | $ | 318 | | | $ | (619 | ) | | $ | (301 | ) | | $ | 307 | | | $ | (3 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current | | $ | 123 | | $ | (110 | ) | $ | 13 | | | | | | | | | $ | 140 | | | $ | (160 | ) | | $ | (20 | ) | | | | | | | | |
Non-current | | | 208 | | | (494 | ) | | (286 | ) | | | | | | | | | 178 | | | | (459 | ) | | | (281 | ) | | | | | | | | |
Total | | $ | 331 | | $ | (604 | ) | $ | (273 | ) | | | | | | | | $ | 318 | | | $ | (619 | ) | | $ | (301 | ) | | | | | | | | |
The following table summarizes the various derivative mark-to-market positions included in the accompanying Consolidated Balance SheetsSheet as of December 31, 2006 (in millions):
| | | | | | | | | | Accumulated | | | | | | | | | | | | | | | Accumulated | |
| | | | | | | | Regulatory | | Other | | | | | | | | | | | | Regulatory | | | Other | |
| | Derivative Net Asset (Liability) | | Net Asset | | Comprehensive | | | Derivative Net Assets (Liabilities) | | | Net Assets | | | Comprehensive | |
| | Assets | | Liabilities | | Total | | (Liability) | | Income (Loss) (1) | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Commodity derivatives | | $ | 383 | | $ | (614 | ) | $ | (231 | ) | $ | 233 | | $ | 3 | | |
Foreign currency contracts | | | 3 | | | - | | | 3 | | | (3 | ) | | - | | |
Commodity | | | $ | 383 | | | $ | (614 | ) | | $ | (231 | ) | | $ | 233 | | | $ | (3 | ) |
Foreign currency | | | | 3 | | | | - | | | | 3 | | | | (3 | ) | | | - | |
Total | | $ | 386 | | $ | (614 | ) | $ | (228 | ) | $ | 230 | | $ | 3 | | | $ | 386 | | | $ | (614 | ) | | $ | (228 | ) | | $ | 230 | | | $ | (3 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current | | $ | 151 | | $ | (110 | ) | $ | 41 | | | | | | | | | $ | 151 | | | $ | (110 | ) | | $ | 41 | | | | | | | | | |
Non-current | | | 235 | | | (504 | ) | | (269 | ) | | | | | | | | | 235 | | | | (504 | ) | | | (269 | ) | | | | | | | | |
Total | | $ | 386 | | $ | (614 | ) | $ | (228 | ) | | | | | | | | $ | 386 | | | $ | (614 | ) | | $ | (228 | ) | | | | | | | | |
The following table summarizes the amount of the pre-tax unrealized gains and losses included within the Consolidated Statements of Income associated with changes in the fair value of PacifiCorp’s derivative contracts that are not included in rates (in millions):
| | Three-Month Periods | |
| | Ended March 31, | |
| | 2007 | | 2006 | |
| | | | | | | |
Revenues | | $ | 6 | | $ | 278 | |
Operating expenses: | | | | | | | |
Energy costs | | | (3 | ) | | (223 | ) |
Operations and maintenance | | | - | | | (2 | ) |
Total unrealized gain on derivative contracts | | $ | 3 | | $ | 53 | |
(5)Common Shareholder’s Equity
During the three-month period ended March 31, 2006, PacifiCorp issued 9,902,728 shares of its common stock to PacifiCorp Holdings, Inc. (“PHI”), its former parent company, at a total price of $110 million. | | Three-Month Periods | | | Nine-Month Periods | |
| | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Revenues | | $ | (3 | ) | | $ | 81 | | | $ | 22 | | | $ | 333 | |
Operating expenses: | | | | | | | | | | | | | | | | |
Energy costs | | | 9 | | | | (146 | ) | | | (18 | ) | | | (376 | ) |
Operations and maintenance | | | - | | | | (1 | ) | | | - | | | | (2 | ) |
Total unrealized gain (loss) on derivative contracts | | $ | 6 | | | $ | (66 | ) | | $ | 4 | | | $ | (45 | ) |
(6)(5) Commitments and Contingencies
Environmental Matters
PacifiCorp is subject to numerous federal, state and local environmental laws and regulations, including the Clean Air Act, related air quality standards promulgated by the Environmental Protection Agency (“EPA”) and various state air quality laws; the Endangered Species Act; the Comprehensive Environmental Response, Compensation and Liability Act, 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 to impact PacifiCorp’s current and future operations; the cost of complying with applicable environmental laws, regulations and rules is expected to be material to PacifiCorp’s domestic generation facilities.operations. Current and future Clean Air Act and associated requirements will impact the operations of PacifiCorp’s generating facilities and will require PacifiCorp to reduce sulfur dioxide, nitrogen oxides and mercury emissions from current levels through the installation of additional or improved emission controls, the purchase of additional emission allowances, or some combination thereof. PacifiCorp is also subject to various state renewables portfolio standards. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to PacifiCorp’s generation facilities. Additionally, the adoption of stringent limits on greenhouse emissions could significantly impact PacifiCorp’s fossil-fueled facilities, and, therefore, its financial results. As of March 31, 2007, PacifiCorp’s environmental contingencies consist principally of air quality matters. PacifiCorp believes it is in material compliance with current environmental requirements.
Accrued Environmental Costs
PacifiCorp is fully or partly responsible for environmental remediation that results from other than normal operations at various contaminated sites, including sites that are or were part of PacifiCorp’s operations and sites owned by third parties. PacifiCorp accrues environmental remediation expenses when the expense is believed to be probable and can be reasonably estimated. The quantification of environmental exposures is based on many factors, including changing laws and regulations, advancements in environmental technologies, the quality of available site-specific information, site investigation results, expected remediation or settlement timelines, PacifiCorp’s proportionate responsibility, contractual indemnities and coverage provided by insurance policies. The liability recorded as of March 31,September 30, 2007 and December 31, 2006 was $36$23 million and $40 million, respectively, and is included in other liabilities and other deferred credits on the accompanying Consolidated Balance Sheets. Environmental remediation liabilities that separately result from the normal operation of long-lived assets and that are associated with the retirement of those assets are separately accounted for as asset retirement obligations.
Hydroelectric Relicensing
PacifiCorp’s hydroelectric portfolio consists of 5048 plants with an aggregate plant net owned capacity of 1,1601,158 megawatts (“MW”). The Federal Energy Regulatory Commission (the “FERC”) regulates 97.9%98% of the net capacity of this portfolio through 18 individual licenses. Several of PacifiCorp’s hydroelectric projects are in some stage of relicensing with the FERC. Hydroelectric relicensing and the related environmental compliance requirements and litigation are subject to uncertainties. PacifiCorp expects that future costs relating to these matters 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 had incurred $81$86 million in costs at March 31, 2007 and $79 million in costs at September 30, 2007 and December 31, 2006, respectively, for ongoing hydroelectric relicensing, which are reflected in construction work-in-progress on the Consolidated Balance Sheets.
In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW nameplate-rated Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license issued by the FERC and expects to continue to operate under annual licenses until the new operating license is issued. AsIn January 2007, as part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensingmodified terms and conditions consistent with the FERC in March 2006 filings, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. In January 2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies’ terms and conditions as part of the project’s relicensing. However, PacifiCorp expects to continue in settlement discussions with various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the project.
Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC issued its draft environmental impact statement on the Klamath hydroelectric project license. The public comment period on the draft environmental impact statement closed on December 1, 2006. The FERC is expected todid not issue its final environmental impact statement in springthe summer of 2007 after which otheras scheduled, and it has provided no new issuance date. Other federal agencies willare also working to complete their endangered species analyses. The states ofanalyses by December 1, 2007. PacifiCorp will need to obtain water quality certifications from Oregon and California will need to issue water quality certifications prior to the FERC issuing a final license. PacifiCorp currently has applications pending before each state.
In the relicensing of the Klamath hydroelectric project, PacifiCorp had incurred $43$46 million and $42 million in costs at March 31,September 30, 2007 and December 31, 2006, respectively, which are reflected in construction work-in-progress in the accompanying Consolidated Balance Sheets. While the costs of implementing new license provisions cannot be determined until such time as a new license is issued, such costs could be material.
Legal Matters
PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material effect on its consolidated financial results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines and penalties in substantial amounts.amounts and are described below.
In February 2007, the Sierra Club and the Wyoming Outdoor Council filed a complaint against PacifiCorp in the federal district court in Cheyenne, Wyoming, alleging violations of air qualityWyoming state opacity standards at PacifiCorp’s Jim Bridger Power Plantplant in Wyoming. Opacity is an indicationUnder Wyoming state requirements, which are part of the amountJim Bridger plant’s Title V permit and are enforceable by private citizens under the federal Clean Air Act, a potential source of pollutants such as a coal-fired generating facility must meet minimum standards for opacity, which is a measurement of light that is obscured in the flue of a generating facility. The complaint alleges thousands of violations of asserted six-minute compliance periods and seeks an injunction ordering the Jim Bridger plant’s compliance with opacity limits, civil penalties of $32,500 per day per violation, and the plaintiffs’ costs of litigation. The court granted a motion to bifurcate the trial into separate liability and remedy phases. A five-day trial on the liability phase is scheduled to begin on April 21, 2008. The remedy-phase trial has not yet been set. PacifiCorp believes it has a number of defenses to the claims. PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its outcome at this time. PacifiCorp has already committed to invest at least $812 million in pollution control equipment at its generating facilities, including the Jim Bridger plant. This commitment is expected to significantly reduce system-wide emissions, including emissions at the Jim Bridger plant.
FERC Issues
California Refund Case
On April 11,June 21, 2007, PacifiCorp executed athe FERC approved PacifiCorp’s settlement and release of claims agreement (“Settlement”) with Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & Electric Company, the People of the State of California, ex rel. Edmund G. Brown Jr., Attorney General, the California Electricity Oversight Board, and the California Public Utilities Commission (collectively, the “California Parties”), certain of which purchased energy in the California Independent System Operator (“ISO”) and the California Power Exchange (“PX”) markets during past periods of high energy prices in 2000 and 2001. The Settlement, filed with FERCwhich was executed by PacifiCorp on April 11, 2007, settles claims brought by the California Parties against PacifiCorp for refunds and remedies in numerous related proceedings (together, the “FERC Proceedings”), as well as certain potential civil claims, arising from events and transactions in Western United States energy markets during the period January 1, 2000 through June 20, 2001 (the “Refund Period”). Under the Settlement, PacifiCorp made a cash paymentpayments to escrows controlled by the California Parties in the amount of $16 million onin April 30, 2007, and upon FERC approval of the agreement in June 2007, PacifiCorp will allowallowed the PX to release an additional $12 million to such escrows, which representsrepresented PacifiCorp’s estimated unpaid receivablesreceivable from the transactions in the PX and ISO markets during the Refund Period, plus interest. The monies held in the escrows will, upon FERC acceptance of the settlement, be distributedescrow are for distribution to buyers of power from the ISO and PX markets that purchased power during the Refund Period. Other buyers in the ISO and PX markets will be provided the option of joining in the Settlement, in which case they will receive payments from one of the escrows. The agreement provides for the release of claims by the California Parties (as well as additional parties that join in the Settlement) against PacifiCorp for refunds, disgorgement of profits, or other monetary or non-monetary remedies in the FERC Proceedings, and provides a mutual release of claims for civil damages and equitable relief. As PacifiCorp previously accrued for these items, the settlement did not materially impact PacifiCorp’s financial results.
(7)Northwest Refund Case
In June 2003, the FERC terminated its proceeding relating to the possibility of requiring refunds for wholesale spot-market bilateral sales in the Pacific Northwest between December 2000 and June 2001. The FERC concluded that ordering refunds would not be an appropriate resolution of the matter. In November 2003, the FERC issued its final order denying rehearing. Several market participants filed petitions in the United States Ninth Circuit Court of Appeals (the “Ninth Circuit”) for review of the FERC’s final order. On August 24, 2007, the Ninth Circuit issued its order on this appeal, concluding that the FERC failed to adequately explain how it considered or examined new evidence showing intentional market manipulation in California and its potential ties to the Pacific Northwest and that the FERC should not have excluded from the Pacific Northwest refund proceeding purchases of energy made by the California Energy Resources Scheduling (“CERS”) division in the Pacific Northwest spot market. The Ninth Circuit remanded the case to the FERC to (i) address the new market manipulation evidence in detail and account for it in any future orders regarding the award or denial of refunds in the proceedings, (ii) include sales to CERS in its analysis, and (iii) further consider its refund decision in light of related, intervening opinions of the court. The Ninth Circuit offered no opinion on the FERC’s findings based on the record established by the administrative law judge and did not rule on the merits of the FERC’s November 2003 decision to deny refunds. Due to the remand, PacifiCorp cannot predict the impact of this ruling at this time.
(6) Employee Benefit Plans
In December 2006, non-bargaining employees were notified that PacifiCorp is switchingwould switch from a traditional final average pay formula for the PacifiCorp Retirement Plan to a cash balance formula effective June 1, 2007. BenefitsAs a result of the change, benefits under the traditional final average pay formula will bewere frozen as of May 31, 2007, with no further benefit accrual under that formula. All future benefits will be earned under the cash balance formula.and PacifiCorp’s pension liability and regulatory assets each decreased by $111 million.
The components of net periodic benefit cost for thePacifiCorp’s pension and other postretirement benefit plans for the three-month periods ended March 31 were as follows (in millions):
| | | | Other | | | Three-Month Periods | | | Nine-Month Periods | |
| | Pension | | Postretirement | | | | | | | |
| | 2007 | | 2006 | | 2007 | | 2006 | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Pension: | | | | | | | | | | | | | |
Service cost | | $ | 8 | | $ | 8 | | $ | 2 | | $ | 2 | | | $ | 7 | | | $ | 8 | | | $ | 21 | | | $ | 23 | |
Interest cost | | | 19 | | | 19 | | | 8 | | | 8 | | | 17 | | | 19 | | | 55 | | | 57 | |
Expected return on plan assets | | | (17 | ) | | (19 | ) | | (6 | ) | | (7 | ) | | (18 | ) | | (18 | ) | | (52 | ) | | (55 | ) |
Amortization and other costs | | | 8 | | | 9 | | | 5 | | | 5 | | |
Net amortization and other costs | | | | 6 | | | | 7 | | | | 20 | | | | 25 | |
Net periodic benefit cost | | $ | 18 | | $ | 17 | | $ | 9 | | $ | 8 | | | $ | 12 | | | $ | 16 | | | $ | 44 | | | $ | 50 | |
| | | | | | | | | | | | |
Other postretirement: | | | | | | | | | | | | |
Service cost | | $ | 1 | | | $ | 2 | | | $ | 5 | | | $ | 6 | |
Interest cost | | | 8 | | | | 8 | | | | 25 | | | | 24 | |
Expected return on plan assets | | | (7 | ) | | | (6 | ) | | | (20 | ) | | | (19 | ) |
Net amortization and other costs | | | 6 | | | | 5 | | | | 15 | | | | 15 | |
Net periodic benefit cost | | $ | 8 | | | $ | 9 | | | $ | 25 | | | $ | 26 | |
Excluded from tablethe tables above wereare contributions to certain multi-employer and joint trust union plans of $3 million and $2 millionfor each of contributions to the joint pension and other postretirement plans for the three-month periods ended March 31,September 30, 2007 and 2006, and $9 million and $7 million for the nine-month periods ended September 30, 2007 and 2006, respectively.
Employer Contributions
Employer contributions to the pension plans and the other postretirement planplans are expected to be approximately $88 million and $34 million, respectively, in 2007. As of March 31,September 30, 2007, $32$85 million and $9$21 million respectively, of contributions had been made to the pension plans and the other postretirement plan.plans, respectively.
Severance
PacifiCorp has reviewed its organization and workforce requirements. As a result, PacifiCorp incurred severance expense of $- million and $15 million during the three-month periods ended September 30, 2007 and 2006, respectively; and $7 million and $35 million during the nine-month periods ended September 30, 2007 and 2006, respectively.
Severance
PacifiCorp has undertaken a review of its organization and workforce. As a result of the review, PacifiCorp incurred severance expense of $6 million during the three-month period ended March 31, 2007, compared to $12 million during the three-month period ended March 31, 2006.
(8)(7) Comprehensive Income and Components of Accumulated Other Comprehensive Income (Loss)Loss
The components of comprehensive income for the three-month periods ended March 31 are as follows (in millions):
| | 2007 | | 2006 | |
| | | | | | | |
Net income | | $ | 99 | | $ | 147 | |
Fair value adjustment on cash flow hedges, net of tax of $(3) and $- | | | (4 | ) | | - | |
Minimum pension liability, net of tax of $- and $3 | | | - | | | 5 | |
Unrealized losses on marketable securities, net of tax of $- and $- | | | - | | | (1 | ) |
Total comprehensive income | | $ | 95 | | $ | 151 | |
| | Three-Month Periods | | | Nine-Month Periods | |
| | Ended September 30, | | | Ended September 30, | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Net income | | $ | 135 | | | $ | 59 | | | $ | 339 | | | $ | 249 | |
Other comprehensive income (loss): | | | | | | | | | | | | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $-; $-; $-; and $- | | | (1 | ) | | | - | | | | - | | | | - | |
Fair value adjustment on cash flow hedges, net of tax of $(1); $14; $-; and $11 | | | (1 | ) | | | 22 | | | | - | | | | 18 | |
Minimum pension liability, net of tax of $-; $-; $-; and $3 | | | - | | | | - | | | | - | | | | 5 | |
Unrealized gains (losses) on marketable securities, net of tax of $-; $1; $-; and $- | | | - | | | | 2 | | | | - | | | | (1 | ) |
Total other comprehensive income (loss) | | | (2 | ) | | | 24 | | | | - | | | | 22 | |
| | | | | | | | | | | | | | | | |
Comprehensive income | | $ | 133 | | | $ | 83 | | | $ | 339 | | | $ | 271 | |
Accumulated other comprehensive loss is included in shareholders’ equity in the Consolidated Balance Sheets and consists of the following components, net of tax (in millions):
| | As of | | | | |
| | March 31, | | December 31, | | | September 30, | | | December 31, | |
| | | 2007 | | | 2006 | | | | | | | |
| | | | | | | | | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $(4) and $(4) | | $ | (6 | ) | $ | (6 | ) | | $ | (6 | ) | | $ | (6 | ) |
Fair value adjustment on cash flow hedges, net of tax of $(1) and $1 | | | (2 | ) | | 2 | | |
Fair value adjustment on cash flow hedges, net of tax of $1 and $1 | | | | 2 | | | | 2 | |
Total accumulated other comprehensive loss, net | | $ | (8 | ) | $ | (4 | ) | | $ | (4 | ) | | $ | (4 | ) |
The following is management’s discussion and analysis of certain significant factors whichthat have affected the financial condition and results of operations of PacifiCorp and its subsidiaries (collectively, “PacifiCorp”) during the periods included herein. Explanations include management’s best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with PacifiCorp’s historical unaudited Consolidated Financial Statements and the notes thereto included elsewhere in Item 1. PacifiCorp’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. Forward-looking statements are typically identified by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast,” “intend,” and similar terms. These statements are based on PacifiCorp’s current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside PacifiCorp’s control and could cause actual results to differ materially from those expressed or implied by PacifiCorp’s forward-looking statements. These factors include, among others:
| · | The outcome of general rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies; |
| · | Changes in prices and availability for both purchases and sales of wholesale electricity and purchases of coal, natural gas and other fuel sources that could have a significant impact on generation capacity and energy costs; |
| · | Changes in regulatory requirements or other legislation, including limits on the ability of public utilities to recover income tax expense in rates such as Oregon Senate Bill 408; |
| · | Changes in economic, industry or weather conditions, as well as demographic trends, that could affect customer growth and electricity usage or supply; |
| · | A high degree of variance between actual and forecasted load and prices that could impact the hedging strategy and costs to balance electricity load and supply; |
| · | Hydroelectric conditions, as well as the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings, that could have a significant impact on electric capacity and cost and on PacifiCorp’s ability to generate electricity; |
| · | Performance of PacifiCorp’s generation facilities, including unscheduled outages or repairs; |
| · | Changes in, and compliance with, environmental and endangered species laws, regulations, decisions and policies that could increase operating and capital improvement costs, reduce plant output and/or delay plant construction; |
| · | The impact of new accounting pronouncements or changes in current accounting estimates and assumptions on financial position and results of operations; |
| · | The impact of increases in healthcare costs, changes in interest rates and investment performance on pension and other post-retirement benefits expense, as well as the impact of changes in legislation on funding requirements; |
| · | Availability, terms and deployment of capital; |
| · | Financial condition and creditworthiness of significant customers and suppliers; |
| · | The impact of financial derivativesderivative instruments used to mitigate or manage interest ratevolume and price risk and volume and priceinterest rate risk and changes in the commodity prices, interest rates and other conditions that affect the value of the derivatives; |
| · | Changes in PacifiCorp’s credit ratings; |
| · | Timely and appropriate completion of PacifiCorp’s resource procurement process; unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future generation plants and infrastructure additions; |
| · | 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 the U.S. Securities and Exchange Commission (the “SEC”) filings or in other publicly disseminated written documents. |
Further details of the potential risks and uncertainties affecting PacifiCorp are described in PacifiCorp’s filings with the SEC.SEC, including Item 1A. and other discussions contained in this Form 10-Q. PacifiCorp 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.
Company Overview
PacifiCorp is a regulated electric utility company serving approximately 1.7 million retail 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 commission in each state approves rates for retail electric sales within that state. PacifiCorp also sells electricity on the wholesale market to public and private utilities, energy marketing companies and incorporated municipalities. Wholesale activities are regulated by the FERC. PacifiCorp owns, or has interests in, 69 thermal, hydroelectric and wind generating plants with a net plant owned capacity of 8,588-MW. The six state regulatory commissions and the FERC also have authority over the construction and operation of PacifiCorp’s electric generation facilities. PacifiCorp transmits electricity through approximately 15,600 miles of transmission lines. PacifiCorp is an indirect subsidiary of MidAmerican Energy Holdings Company (“MEHC”). MEHC, a global energy company based in Des Moines, Iowa, is a consolidated subsidiary of Berkshire Hathaway Inc. (“Berkshire Hathaway”).
Results of Operations
Overview
PacifiCorp’s net income was $99increased $90 million during the nine-month period ended September 30, 2007, to $339 million compared to $249 million for the three-monthnine-month period ended March 31, 2007 compared to $147 million for the three-month period ended March 31, 2006. The $48 million decrease in net income wasSeptember 30, 2006, primarily due to lower net unrealized gains on derivative contracts, increased fuel costs due to higher volumes and pricesretail revenues and higher depreciation expense. These decreases to net income werewholesale sales and purchases, partially offset by higher fuel costs.
Retail revenues increased due to higher retail prices approved by regulators, and lower income tax expenseas well as continued growth in the current period.number of retail customers and usage. Net unrealized gainsmargin on derivative contracts were $3 million during the three-month period ended March 31, 2007, compared to $53 million during the three-month period ended March 31, 2006. The decrease in net unrealized gains on derivative contracts waswholesale activities increased primarily due to higher average prices on wholesale sales and lower purchased electricity volumes. PacifiCorp’s financial results were further improved by higher output at PacifiCorp’s thermal and wind plants serving the change in estimate during the three-month period ended September 30, 2006 for contracts considered probablehigher retail load. These improvements were partially offset by higher prices of receiving recovery in rates due to regulatory settlements in Utahcoal, natural gas and Oregon, which resulted in more activity being recordedpurchased electricity, as a net regulatory asset in the current period.well as lower hydroelectric generation.
Output from PacifiCorp’s thermal plants for the three-monthnine-month period ended March 31,September 30, 2007, increased by 485,1453,135,182 megawatt-hours (“MWh”), or 4%9%, compared to the three-monthnine-month period ended March 31, 2006. This increase wasSeptember 30, 2006, primarily due to the Currant Creek plant becoming fully operational at the end of March 2006. Output from PacifiCorp’s wind plants increased by 261,137 MWh, or 314%, during the nine-month period ended September 30, 2007, compared to the nine-month period ended September 30, 2006, primarily due to the Leaning Juniper plant being placed into service in September 2006 and the Marengo plant being placed into service in August 2007. Output from PacifiCorp’s hydroelectric facilities decreased by 374,534621,155 MWh, or 23%18%, during the three-monthnine-month period ended March 31,September 30, 2007, compared to the three-monthnine-month period ended March 31, 2006. This decrease wasSeptember 30, 2006, primarily due to drier than normal conditions in the current period.
Three-Month PeriodPeriods Ended March 31,September 30, 2007 Compared to Three-Month Period Ended March 31,and 2006
Revenues (in(dollars in millions)
| | Three-Month Periods | | | | | Three-Month Periods | | | | |
| | Ended March 31, | | Favorable/(Unfavorable) | | | | | | | |
| | 2007 | | 2006 | | $ Change | | % Change | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Retail | | $ | 777 | | $ | 714 | | $ | 63 | | | 9 | % | | $ | 904 | | | $ | 803 | | | $ | 101 | | | 13 | % |
Wholesale sales and other | | | 250 | | | 516 | | | (266 | ) | | (52 | ) | | | 233 | | | | 294 | | | | (61 | ) | | | (21 | ) |
Total revenues | | $ | 1,027 | | $ | 1,230 | | $ | (203 | ) | | (17 | ) | | $ | 1,137 | | | $ | 1,097 | | | $ | 40 | | | | 4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Retail energy sales (gigawatt - hours) | | | 13,076 | | | 12,766 | | | 310 | | | 2 | | | 14,188 | | | 13,704 | | | 484 | | | 4 | |
Wholesale energy sales (gigawatt - hours) | | | 3,496 | | | 3,480 | | | 16 | | | - | | | 3,129 | | | 3,401 | | | (272 | ) | | (8 | ) |
Total retail customers (in thousands) | | | 1,674 | | | 1,640 | | | 34 | | | 2 | | |
Average retail customers (in thousands) | | | 1,688 | | | 1,655 | | | 33 | | | 2 | |
Retail revenues increased $63$101 million, or 9%13%, primarily due to:
| · | $4260 million of increases from higher retail prices approved by regulators; |
| · | $12 million of increases relating to growth in the number of customers; |
· | $628 million of increases due to higher average customer usage resulting primarily as a result of colder weather as compared to the prior period;from warmer weather; and |
| · | $314 million of increases due to changesgrowth in customer usage at different tariff levels.the number of customers. |
Wholesale sales and other revenues decreased $266$61 million, or 52%21%, primarily due to:
| · | $27284 million of decreases due to changes in the fair value of derivative contracts; partially offset by, |
| · | $20 million of increases in wholesale electric sales primarily due to higher average prices, partially offset by lower volumes. |
Operating Expenses (in millions)
| | Three-Month Periods | | | | |
| | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | | | | |
Energy costs | | $ | 487 | | | $ | 567 | | | $ | 80 | | | | 14 | % |
Operations and maintenance | | | 230 | | | | 253 | | | | 23 | | | | 9 | |
Depreciation and amortization | | | 125 | | | | 118 | | | | (7 | ) | | | (6 | ) |
Taxes, other than income taxes | | | 26 | | | | 27 | | | | 1 | | | | 4 | |
Total operating expenses | | $ | 868 | | | $ | 965 | | | $ | 97 | | | | 10 | |
Energy costs decreased $80 million, or 14%, primarily due to:
| · | $155 million of decreases due to changes in the fair value of derivative contracts; |
| · | $15 million of decreases on wholesale electric sales substantiallyprimarily due to lowerthe deferral of incurred power costs in accordance with established adjustment mechanisms; and |
| · | $3 million of decreases due to the prior period loss on the streamflow weather derivative contract; partially offset by, |
| · | $54 million of increases due to higher volumes of natural gas consumed at higher average prices; |
| · | $1118 million of increases in the cost of coal primarily due to higher average prices; and |
| · | $17 million of increases in purchased electricity due to higher average prices, partially offset by lower volumes. |
Operations and maintenance expense decreased $23 million, or 9%, primarily due to:
| · | $15 million of decreases in employee severance costs; |
| · | $5 million of decreases in employee expenses, primarily due to reduced workforce; and |
| · | $5 million of decreases primarily due to asset write-offs in the prior year; partially offset by, |
| · | $3 million of increases in maintenance costs and related contracts, primarily associated with generation plant overhauls. |
Depreciation and amortization expenseincreased $7 million, or 6%, primarily due to higher plant in service.
Interest and Other Expense (Income) (in millions)
| | Three-Month Periods | | | | |
| | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | | | | |
Interest expense | | $ | 76 | | | $ | 72 | | | $ | (4 | ) | | | (6 | )% |
Interest income | | | (3 | ) | | | (3 | ) | | | - | | | | - | |
Allowance for borrowed funds | | | (8 | ) | | | (6 | ) | | | 2 | | | | 33 | |
Allowance for equity funds | | | (11 | ) | | | (6 | ) | | | 5 | | | | 83 | |
Other | | | 2 | | | | (1 | ) | | | (3 | ) | | | (300 | ) |
Total | | $ | 56 | | | $ | 56 | | | $ | - | | | | - | |
Interest expense increased $4 million, or 6%, primarily due to higher average debt balances during the three-month period ended September 30, 2007.
Allowance for borrowed and equity funds increased $7 million, primarily due to higher average qualified construction work-in-progress balances during the three-month period ended September 30, 2007.
Income Tax Expense
Income tax expense for the three-month period ended September 30, 2007, increased $61 million to $78 million from the comparable period in 2006, primarily due to higher pre-tax earnings and income tax accruals for uncertain tax positions in the current period, compared to prior period benefits attributed to the resolution of certain matters previously outstanding with the Internal Revenue Service. The effective tax rates were 37% and 22% for the three-month periods ended September 30, 2007 and 2006, respectively.
Nine-Month Periods Ended September 30, 2007 and 2006
Revenues (dollars in millions)
| | Nine-Month Periods | | | | |
| | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | | | | |
Retail | | $ | 2,455 | | | $ | 2,212 | | | $ | 243 | | | | 11 | % |
Wholesale sales and other | | | 735 | | | | 975 | | | | (240 | ) | | | (25 | ) |
Total revenues | | $ | 3,190 | | | $ | 3,187 | | | $ | 3 | | | | - | |
| | | | | | | | | | | | | | | | |
Retail energy sales (gigawatt - hours) | | | 40,054 | | | | 38,637 | | | | 1,417 | | | | 4 | |
Wholesale energy sales (gigawatt - hours) | | | 10,117 | | | | 10,083 | | | | 34 | | | | - | |
Average retail customers (in thousands) | | | 1,680 | | | | 1,645 | | | | 35 | | | | 2 | |
Retail revenues increased $243 million, or 11%, primarily due to:
| · | $145 million of increases from higher retail prices approved by regulators; |
| · | $61 million of increases due to higher average customer usage, primarily as a result of more extreme weather conditions and an earlier start to the irrigation season in the current period as compared to the prior period; and |
| · | $38 million of increases due to growth in the number of customers. |
Wholesale sales and other revenues decreased $240 million, or 25%, primarily due to:
| · | $311 million of decreases due to changes in the fair value of derivative contracts; and |
| · | $7 million of decreases resulting from higher sales of sulfur dioxide emission allowances in the prior period; partially offset by, |
| · | $3980 million of increases substantially due to higher margins on non-physically settled system balancing transactions.system-balancing transactions and higher average prices on wholesale electric sales. |
Operating Expenses (in millions)
| | Three-Month Periods | | | |
| | Ended March 31, | | Favorable/(Unfavorable) | |
| | 2007 | | 2006 | | $ Change | | % Change | |
| | | | | | | | |
| | | | | | | | | | | | | |
Energy costs | | $ | 415 | | $ | 548 | | $ | 133 | | | 24 | % |
Operations and maintenance | | | 262 | | | 274 | | | 12 | | | 4 | |
Depreciation and amortization | | | 121 | | | 113 | | | (8 | ) | | (7 | ) |
Taxes, other than income taxes | | | 28 | | | 24 | | | (4 | ) | | (17 | ) |
Total operating expenses | | $ | 826 | | $ | 959 | | $ | 133 | | | 14 | |
Operating Expenses (in millions)
| | Nine-Month Periods | | | | |
| | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | | | | |
Energy costs | | $ | 1,327 | | | $ | 1,451 | | | $ | 124 | | | | 9 | % |
Operations and maintenance | | | 747 | | | | 787 | | | | 40 | | | | 5 | |
Depreciation and amortization | | | 368 | | | | 347 | | | | (21 | ) | | | (6 | ) |
Taxes, other than income taxes | | | 77 | | | | 77 | | | | - | | | | - | |
Total operating expenses | | $ | 2,519 | | | $ | 2,662 | | | $ | 143 | | | | 5 | |
Energy costs decreased $133$124 million, or 24%9%, primarily due to:
| · | $220358 million of decreases due to changes in the fair value of derivative contracts; |
| · | $27 million of decreases primarily due to the deferral of incurred power costs in accordance with established adjustment mechanisms; and |
| · | $12 million of decreases due to the prior period loss on the streamflow weather derivative contract; partially offset by, |
| · | $33150 million of increases relateddue to higher volumes and higher average prices of natural gas consumed primarily due to increased generation;at higher average prices; |
| · | $3262 million of increases in purchased electricitythe cost of coal substantially due to higher volumes and higher average prices; and |
| · | $1954 million of increases in cost of coal substantiallypurchased electricity primarily due to higher prices.average prices, partially offset by lower volumes. |
Operations and maintenance expense decreased $12$40 million, or 4%5%, primarily due to:
| · | $9 million of decreases in annual incentive plan expense; |
· | $628 million of decreases in employee severance costs; |
| · | $18 million of decreases in employee expenses, primarily due to reduced workforce; |
| · | $8 million of decreases due to changes in environmental accruals; and |
| · | $4 million of decreases resulting fromdue to the initial assessment of penalties related to compliance with the FERC standards of conduct for transmission in the prior period; partially offset by, |
| · | $422 million of increases in employee expenses,maintenance costs and related contracts, primarily due to higher pension and other post-retirement benefits costs; andassociated with generation plant overhauls. |
· | $3 million of increases in materials and supplies expense. |
Depreciation and amortization expense increased $8$21 million, or 7%6%, primarily due to higher plant in service.
Interest and Other Expense (Income) Expense (in millions)
| | Three-Month Periods | | | | | Nine-Month Periods | | | | |
| | Ended March 31, | | Favorable/(Unfavorable) | | | | | | | |
| | 2007 | | 2006 | | $ Change | | % Change | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Interest expense | | $ | 75 | | $ | 69 | | $ | (6 | ) | | (9 | )% | | $ | 230 | | | $ | 210 | | | $ | (20 | ) | | (10 | )% |
Interest income | | | (3 | ) | | (2 | ) | | 1 | | | 50 | | | (10 | ) | | (7 | ) | | 3 | | | 43 | |
Allowance for borrowed funds | | | (7 | ) | | (5 | ) | | 2 | | | 40 | | | (24 | ) | | (16 | ) | | 8 | | | 50 | |
Allowance for equity funds | | | (7 | ) | | (6 | ) | | 1 | | | 17 | | | (28 | ) | | (18 | ) | | 10 | | | 56 | |
Other | | | - | | | (2 | ) | | (2 | ) | | (100 | ) | | | - | | | | (3 | ) | | | (3 | ) | | | (100 | ) |
Total | | $ | 58 | | $ | 54 | | $ | (4 | ) | | (7 | ) | | $ | 168 | | | $ | 166 | | | $ | (2 | ) | | | (1 | ) |
Interest expense increased $6$20 million, or 9%10%, primarily due to higher average debt outstanding and higher average variable ratesbalances during the three-monthnine-month period ended March 31,September 30, 2007.
Allowance for borrowed and equity funds increased $3$18 million, primarily due to higher average qualified construction work-in-progress balances during the three-monthnine-month period ended March 31,September 30, 2007.
Income Tax Expense
Income tax expense decreased $26 for the nine-month period ended September 30, 2007, increased $54 million to $164 million from the comparable period in 2006, primarily due to a decrease in income before incomehigher pre-tax earnings. The effective tax expense.rates were 33% and 31% for the nine-month periods ended September 30, 2007 and 2006, respectively.
Liquidity and Capital Resources
Sources and Uses of Cash
PacifiCorp depends on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operating activities are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through long-term debt issuances and through cash capital cash contributions from PacifiCorp’s direct parent company, PPW Holdings LLC.LLC (“PPW”). PacifiCorp expects it will need additional periodic equity contributions from its parent over the next several years. Issuance of long-term securities is influenced by levels of short-term debt, cash from operations, capital expenditures, market conditions, regulatory approvals and other considerations.
Operating Activities
Net cash flows provided by operating activities increased $17decreased $26 million to $338$650 million for the three-monthnine-month period ended March 31,September 30, 2007, compared to $321$676 million for the three-monthnine-month period ended March 31,September 30, 2006, primarily due to higher retail prices approved by regulators and the timing of payments and cash collections and payments,higher fuel costs, partially offset by higher energy costs related to generationretail revenues and purchased electricity.higher net wholesale sales and purchases.
Investing Activities
Net cash used in investing activities increased $24decreased $10 million to $360$1,112 million for the three-monthnine-month period ended March 31,September 30, 2007, compared to $336$1,122 million for the three-monthnine-month period ended March 31, 2006, primarily due to higher capital expenditures compared to the prior year.September 30, 2006. Capital expenditures totaled $376$1,136 million for the three-monthnine-month period ended March 31,September 30, 2007, compared to $333$1,113 million for the three-monthnine-month period ended March 31,September 30, 2006. Capital spending increased primarily due to wind generation investments, including investments in the 140-MW Marengo Wind Project and other wind projects. Otherinvestments. Additional increases resulted from the construction and installation of emission control equipment and various capital projects related to transmission, and distribution and other generation facilities. PacifiCorp spent approximately $33$89 million and $17$73 million, excluding non-cash allowance for equity funds used during construction, on these types ofemission control environmental projects during the three-monthnine-month periods ended March 31,September 30, 2007 and 2006, respectively. These increases were partially offset by decreases in expenditures, as compared to the previous period, for the construction of the Currant Creek Power Plant,plant, which commenced full combined-cycle operation in March 2006, and decreases in expenditures for the construction of the 534-MW534-megawatt (“MW”) Lake Side Power Plant,plant, which were lower than the previous year.commenced full combined-cycle operation in September 2007.
Financing Activities
Short-Term Debt
PacifiCorp’s short-term debt decreased by $181$191 million during the three-monthnine-month period ended March 31,September 30, 2007, to $216 million of commercial paper arrangements, primarily due to the use of a portion of the proceeds from the issuance of long-term debt and the capital contributions received during the period, partially offset by capital expenditures and maturities of long-term securities in excess of net cash from operations.provided by operating activities.
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which an aggregate principal amount of $216$206 million of commercial paper was outstanding at March 31,September 30, 2007, with a weighted-average interest rate of 5.3%.
Revolving Credit and Other Financing Agreements
In October 2007, PacifiCorp has an $800 millionentered into a new unsecured revolving credit facility expiring inwith total bank commitments of $700 million. The facility will support PacifiCorp's commercial paper program and terminates on October 23, 2012. Terms and conditions, including borrowing rates, are substantially similar to PacifiCorp's existing revolving credit facility. Under PacifiCorp’s existing unsecured revolving credit facility, total bank commitments of $800 million are available through July 2011.2011 and $760 million for the subsequent year ending July 2012. The credit facility supports PacifiCorp’s commercial paper program and includes a variable-rate borrowing option based on the London Interbank Offered Rate (LIBOR) plus 0.195% that, which varies based on PacifiCorp’s credit ratings for its senior unsecured long-term debt securities, and which supports PacifiCorp’s commercial paper program. At March 31,securities. As of September 30, 2007, there were no borrowings outstanding under this credit facility. In addition to this committed bank facility, PacifiCorp had $434 million in money market accounts included in cash and cash equivalents at March 31, 2007, available to meet its liquidity needs, as well as provide for future capital expenditures and contractual obligations. See “Future Uses of Cash” below.
At March 31,September 30, 2007, PacifiCorp had $518 million of standby letters of credit and standby bond purchase agreements available to provide credit enhancement and liquidity support for variable-rate pollution-control revenue bond obligations. In addition, PacifiCorp had approximately $21 million of standby letters of credit available to provide credit support for certain transactions as requested by third parties. These committed bank arrangements were all fully available at March 31,September 30, 2007 and expire periodically through February 2011.May 2012.
PacifiCorp’s revolving credit and other financing agreements contain customary covenants and default provisions, including a covenant not to exceed a specified debt-to-capitalization ratio of 0.65 to 1. At March 31,September 30, 2007, PacifiCorp was in compliance with the covenants of its revolving credit and other financing agreements.
Long-Term Debt
During the three-month period endedIn October 2007, PacifiCorp issued $600 million of its 6.25% First Mortgage Bonds due October 15, 2037. The proceeds will be used to repay short-term debt and for general corporate purposes.
In March 31, 2007, PacifiCorp issued $600 million of its 5.75% Series of First Mortgage Bonds due April 1, 2037, and made scheduled long-termused the proceeds to repay short-term debt repayments of $6 million.and for general corporate purposes.
During the three-monthnine-month period ended March 31, 2006,ending September 30, 2007, PacifiCorp made scheduled long-term debt repayments of $100$114 million.
As a result of the October and March 31, 2007 long-term debt issuances, PacifiCorp had $900has $300 million available under currently effective SEC shelf registration statements covering future first mortgage bond and unsecured debt issuances. Also at March 31, 2007, PacifiCorp hadcurrently has available state regulatory authority from the Oregon Public Utility Commission (“OPUC”), Utah Public Service Commission (“UPSC”) and the Idaho Public Utility Commission (“IPUC”) to issue up to an additional $900$300 million of long-term debt. An additional filing would be required bywith the Washington Utilities and Transportation Commission (“WUTC”) prior to any future issuances. In May 2007, PacifiCorp was granted an exemption from obtaining prior written approval from the Utah Public Service Commission (“UPSC”) for additional long-term debt issuances. The exemption generally remains in effect as long as PacifiCorp’s senior secured debt maintains investment grade ratings.
Common Shareholder’s Capital
During the three-monthnine-month period ended March 31, 2006,September 30, 2007, PacifiCorp issued 9,902,728 sharesreceived capital contributions from PPW of common stock to PacifiCorp Holdings, Inc. (“PHI”), its former parent company, at a total price of $110$200 million.
Common DividendsPreferred Stock Redemptions
During the three-month period ended March 31,In June 2007, PacifiCorp did not declare or pay any dividends on common stock. During the three-month period ended March 31, 2006, PacifiCorp declared and paid a commonredeemed $38 million of outstanding preferred stock dividend totaling $17 millionsubject to PHI.mandatory redemption, representing all remaining outstanding shares of PacifiCorp’s $7.48 No Par Serial Preferred Stock series.
Future Uses of Cash
Dividends
PacifiCorp does not currently anticipate that it will declare or pay dividends on common stock during the remainder of the year ending December 31, 2007.
Capital Expenditure Program
As of March 31, 2007, estimatedEstimated capital expenditures, which exclude non-cash allowances for equity funds used during construction, for the year ending December 31, 2007, are expected to be approximately $1,649$1,644 million, which includes $763$797 million for ongoing operations projects, including new connections related to customer growth, $781$737 million for generation development and the related transmission projects, and $105$110 million for emission control equipment to address current and anticipated air quality regulations.
The capital expenditures estimate for generation development projects for the year ending December 31, 2007, includes the 140-MW Marengo I wind plant that was placed into service in August 2007. The estimate also includes construction costs for the development of additional wind generation projects that are expected to increase PacifiCorp’s renewable generation portfolio by 362 MW. These wind generation projects are expected to be placed into service through December 31, 2008. PacifiCorp continues to pursue additional cost-effective wind-powered generation.
The estimated capital expenditures for generation development projects also includes costs to complete the 534-MW Lake Side plant, which was placed into service in September 2007, as well as upgrades of other generation plant equipment. Total costs for the Lake Side plant are expected to be approximately $347 million, including non-cash allowance for equity funds used during construction. As of September 30, 2007, $339 million, including $17 million in non-cash allowance for equity funds used during construction, had been incurred. 20
In funding its capital expenditure program, PacifiCorp expects to obtain funds required for construction and other purposes from sources similar to those used in the past, including cash provided by operating activities, the issuance of new long-term debt and cash capital contributions from PPW. The availability of capital will influence actual expenditures.The capital expenditure estimates are subject to a high degree of variability based on several factors, including, among others highlighted in “Forward-Looking Statements” above, future decisions arising from PacifiCorp’s Integrated Resource Plan process, changes in regulations, laws and market conditions, as well as the outcomes of rate-making proceedings. Additionally, capital expenditure needs are regularly reviewed by management and may change significantly as a result of such reviews.
In funding its capital expenditure program, PacifiCorp expects to obtain funds required for construction and other purposes from sources similar to those used in the past, including operating cash flows, the issuance of new long-term debt and equity contributions from PacifiCorp’s direct parent company, PPW Holdings LLC. The availability of capital will influence actual expenditures.Integrated Resource Plans
The estimate provided above for generation development projects for the year ending December 31, 2007, includes the remaining costsAs required by state regulators, PacifiCorp uses Integrated Resource Plans (“IRP”) to complete the 534-MW Lake Side Power Plant, as well as upgradesdevelop a long-term view of other generation plant equipment. The Lake Side Power Plant is expectedprudent future actions required to cost approximately $347 million, including approximately $13 million of non-cash allowance for equity funds used during construction, of which $295 million, including approximately $12 million of non-cash allowance for equity funds used during construction, had been incurred through March 31, 2007.
Also included in the estimate for generation development projects are the remaining costs for the construction of the 140-MW Marengo Wind Project and other potential wind generation projects.help ensure that PacifiCorp continues to pursue additionalprovide reliable and cost-effective wind-powered generation.electric service to its customers. The IRP process identifies the amount and timing of PacifiCorp’s expected future resource needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts and other factors. The IRP is a coordinated effort with stakeholders in each of the six states where PacifiCorp operates. Each state commission that has IRP adequacy rules judges whether the IRP reasonably meets its standards and guidelines at the time the IRP is filed. PacifiCorp requests “acknowledgement” of its IRP filing from the UPSC, the OPUC, the IPUC and the WUTC pursuant to those states’ IRP adequacy rules. The IRP can be used as evidence by parties in rate-making or other regulatory proceedings. PacifiCorp files its IRP on a biennial basis. Additionally, PacifiCorp is required to file draft requests for proposals with the UPSC and the OPUC prior to issuance to the market.
In May 2007, PacifiCorp released its 2007 IRP. The 2007 IRP identified a need for approximately 3,171 MW of additional resources by summer 2016, to be met with a combination of thermal generation, combined heat and power and load control programs. PacifiCorp also plans to procure economic renewable resources, implement energy conservation programs and to use wholesale electricity transactions to make up for the remaining difference between retail load obligations and available resources. PacifiCorp is currently seeking acknowledgement of its 2007 IRP from state regulators and expects the acknowledgement process to be complete in 2008.
Transmission Investment
In May 2007, PacifiCorp announced plans to build in excess of 1,200 miles of new transmission lines originating in Wyoming and connecting into Utah, Idaho, Oregon and the desert Southwest. The estimated $4 billion investment plan includes projects that will address customers’ increasing electric energy use, improve system reliability and deliver wind and other renewable generation resources to more customers throughout PacifiCorp’s six-state service area and the western region. These transmission lines are expected to be placed into service beginning 2010 through 2014.
Credit Ratings
PacifiCorp’s credit ratings at March 31,September 30, 2007, were as follows:
| | | |
| | | |
Issuer/Corporate | Baa1 | | A- |
Senior secured debt | A3 | | A- |
Senior unsecured debt | Baa1 | | BBB+ |
Preferred stock | Baa3 | | BBB |
Commercial paper | P-2 | | A-1 |
Outlook | Stable | | Stable |
In conjunction with its risk management activities, PacifiCorp must meet credit quality standards as required by counterparties. In accordance with industry practice, contractual agreements that govern PacifiCorp’s energy management activities either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed certain ratings-dependent threshold levels, or provide the right for counterparties to demand “adequate assurances” in the event of a material adverse change in PacifiCorp’s creditworthiness. If one or more of PacifiCorp’s credit ratings decline below investment grade, PacifiCorp would be required to post cash collateral, letters of credit or other similar credit support to facilitate ongoing wholesale energy management activities. At March 31,September 30, 2007, PacifiCorp’s credit ratings from Standard & Poor’s and Moody’s were investment grade; however, if the ratings fell more than one rating below investment grade, PacifiCorp’s estimated potential collateral requirements would total approximately $397$419 million. PacifiCorp’s potential collateral requirements could fluctuate considerably due to seasonality, market prices and their volatility, a loss of key PacifiCorp generating facilities or other related factors.
There has been no change in PacifiCorp’s credit ratings since December 31, 2006. These ratings are subject to change or withdrawal at any time by the respective credit ratings services. Each credit rating should be evaluated independently of any other rating.
For a further discussion of PacifiCorp’s credit ratings and their effect on PacifiCorp’s business, see “Item 7. Management’s Discussion and Analysisrefer to Item 7 of Financial Condition and Results of Operations” in PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006.
Contractual Obligations and Commercial Commitments
During the three-month period ended MarchSubsequent to December 31, 2007,2006, there were no material changes outside the ordinarynormal course of business in the contractual obligations and commercial commitments from the information provided in Item 7 of PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006, other than as described above, inPacifiCorp’s March 2007 PacifiCorp issuedissuance of $600 million of its 5.75% First Mortgage Bonds due April 1, 2037 and October 2007 issuance of $600 million of its 6.25% First Mortgage Bonds due October 15, 2037.
Regulatory Matters
In addition to the discussion contained herein regarding updates to regulatory matters based upon material changes that occurred during the three-month period ended Marchsubsequent to December 31, 2007,2006, refer to Note 65 of Notes to Consolidated Financial Statements included in Item 1 for additional regulatory matter updates.
Federal Regulatory Matters
The Bonneville Power Administration Residential Exchange Program
The Northwest Power Act, through the Residential Exchange Program, provides access to the benefits of low-cost federal hydroelectricity to the residential and small-farm customers of the region’s investor-owned utilities. The program is administered by the Bonneville Power Administration (the “BPA”) in accordance with federal law. Pursuant to agreements between the BPA and PacifiCorp, benefits from the BPA are passed through to PacifiCorp’s Oregon, Washington and Idaho residential and small-farm customers in the form of electricity bill credits. In October 2000, PacifiCorp entered into a settlement agreement with the BPA that provided Residential Exchange Program benefits to PacifiCorp’s customers from October 2001 through September 2006. In May 2001, PacifiCorp entered into a load reduction agreement with the BPA which eliminated the BPA’s obligation to deliver power to PacifiCorp from October 2001 through September 2006 in exchange for cash payments. This agreement also contained a “reduction of risk discount” provision which provided that the BPA would reduce the cash payments to PacifiCorp if by December 1, 2001, PacifiCorp and other utilities were able to negotiate and enter into settlement agreements with the publicly owned utilities and other of the BPA’s preference customers dismissing certain lawsuits. If these parties did not reach settlement by the specified date, the clause would expire and the BPA would make cash payments to PacifiCorp based on the original rate for the October 2002 through September 2006 period. Settlement was not reached and the clause expired obligating the BPA to make the full cash payment to PacifiCorp. In May 2004, PacifiCorp, the BPA and other parties executed an additional agreement which modified both the October 2000 and May 2001 agreements that provides for a guaranteed range of benefits to customers from October 2006 through September 2011.
Several publicly owned utilities, cooperatives and the BPA’s direct-service industry customers filed lawsuits against the BPA with the United States Ninth Circuit Court of Appeals (the “Ninth Circuit”) seeking review of certain aspects of the BPA’s Residential Exchange Program, as well as challenging the level of benefits previously paid to investor-owned utility customers. OnIn May 3, 2007, the United States Ninth Circuit Court of Appeals issued two decisions. The first decision sets aside the October 2000 Residential Exchange Program settlement agreement as being inconsistent with the BPA’s settlement authority. The second decision holds, among other things, that the BPA acted contrary to law when it allocated to its preference customers, which includesinclude public utilities, cooperatives and federal agencies, part of the costs of the October 2000 settlement the BPA reached with its investor-owned utility customers. These United States Ninth Circuit CourtAs a result of Appeals’ decisions could affect the amount of benefits passed onruling, in May 2007, the BPA notified the Pacific Northwest’s six utilities, including PacifiCorp, that it was immediately suspending payments. This has resulted in increases to PacifiCorp’s customers.residential and small farm customers’ electric bills in Oregon, Washington and Idaho. Because these benefitsthe benefit payments from the BPA are passed through to PacifiCorp’s customers, the outcome of this matter is not expected to have a significant effect on PacifiCorp’s consolidated financial results. There are severalIn October 2007, the Ninth Circuit issued one published decision and three unpublished decisions. The published decision remanded the May 2004 agreements modifying the October 2000 and May 2001 agreements to the BPA for further action consistent with the Ninth Circuit’s May 2007 decisions. The other lawsuits challenging certain aspectsthree unpublished decisions dismiss cases in which the publicly owned utilities sought review of the BPA’s Residential Exchange Program pending atdecision to implement the United States Ninth Circuit Courtreduction of Appeals for whichrisk discount provision and make the outcomes remain unknown.full cash payment to PacifiCorp.
Hydroelectric RelicensingDecommissioning
KlamathPowerdale Hydroelectric Project - (Klamath– (Hood River, Oregon and California)
In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 169-MW nameplate-rated Klamath hydroelectric project in anticipation of the March 2006 expiration of the existing license. PacifiCorp is currently operating under an annual license granted by the FERC and expects to continue to operate under annual licenses until the new operating license is issued. As part of the relicensing process, the United States Departments of Interior and Commerce filed proposed licensing terms and conditions with the FERC in March 2006, which proposed that PacifiCorp construct upstream and downstream fish passage facilities at the Klamath hydroelectric project’s four mainstem dams. In April 2006, PacifiCorp filed alternatives to the federal agencies’ proposal and requested an administrative hearing to challenge some of the federal agencies’ factual assumptions supporting their proposal for the construction of the fish passage facilities. A hearing was held in August 2006 before an administrative law judge. The administrative law judge issued a ruling in September 2006 generally supporting the federal agencies’ factual assumptions. In January 2007, the United States Departments of Interior and Commerce filed modified terms and conditions consistent with March 2006 filings and rejected the alternatives proposed by PacifiCorp. PacifiCorp is prepared to meet and implement the federal agencies’ terms and conditions as part of the project’s relicensing. However, PacifiCorp expects to continue in settlement discussions with various parties in the Klamath Basin area who have intervened with the FERC licensing proceeding to try to achieve a mutually acceptable outcome for the project.
Also, as part of the relicensing process, the FERC is required to perform an environmental review. In September 2006, the FERC issued its draft environmental impact statement on the Klamath hydroelectric project license. The public comment period on the draft environmental impact statement closed on December 1, 2006. The FERC is expected to issue its final environmental impact statement in Spring 2007, after which other federal agencies will complete their endangered species analyses. The states of Oregon and California will need to issue water quality certifications prior to the FERC issuing a final license.
Prospect Hydroelectric Project - (Rogue River, Oregon)
In June 2003, PacifiCorp submittedentered into a finalsettlement agreement to remove the 6-MW nameplate-rated Powerdale plant rather than pursue a new license, applicationbased on an analysis of the costs and benefits of relicensing versus decommissioning. Removal of the Powerdale plant and associated project features, which is subject to the FERC forand other regulatory approvals, is projected to cost $6 million excluding inflation. Removal of the Prospect Nos. 1, 2plant is scheduled to commence in 2010. However, in November 2006, flooding damaged the Powerdale plant and 4 hydroelectric projects, whose nameplate ratings total 37-MW. The Oregon Department of Environmental Quality issued a 401 Water Quality Certificate forrendered its generating capabilities inoperable. In February 2007, the FERC granted PacifiCorp’s request to cease generation at the project until decommissioning activities begin. Also in AprilFebruary 2007, PacifiCorp submitted a request to the FERC to allow it to defer the remaining net book value and any additional removal costs of this project as a regulatory asset. In May 2007, the FERC issued an order which effectively concludesapproved PacifiCorp’s proposed accounting entries, thereby allowing PacifiCorp to reclassify the license process. FERC is expectednet book value and the estimated removal costs to issue a new Order before the end of May 2007.regulatory asset. PacifiCorp has filed with its state commissions to recover these costs.
State Regulatory Actions
PacifiCorp is currently pursuing a regulatory program in all states, with the objective of keeping rates closely aligned to ongoing costs. The following discussion provides a state-by-state update based upon significant changes that occurred during the three-month period ended Marchsubsequent to December 31, 2007:2006.
Utah
In June 2007, the second phase of PacifiCorp’s general rate case filed in March 2006 became effective, adjusting the rate increase from $85 million to $115 million. Under the terms of the stipulation in the case, PacifiCorp has agreed not to file another rate case before December 11, 2007, with new rates to become effective no earlier than August 2008.
Oregon
In AprilJuly 2007, PacifiCorp filed itsas part of PacifiCorp’s annual compliance filing with the OPUC to update forecasted net power costs, requesting a 3.9% overallPacifiCorp requested an increase of approximately $30 million, or an average price increase approximately $36 million,of 3%, to take effect January 1, 2008. The annual filing, called the Transition Adjustment Mechanism, is due each April buttransition adjustment mechanism (“TAM”), will be adjusted for new contracts through NovemberOctober 2007 based onand for other changes to forecasted net power costs, such as coal and natural gas prices, and new contracts. PacifiCorp expects a ruling fromthrough November 2007. The OPUC this fall.issued an order on October 17, 2007, which is expected to reduce the requested increase by approximately $9 million. The final net power cost increase under the TAM will be determined in November 2007, after PacifiCorp’s annual filing is updated for the changes to forecasted net power costs.
In August 2007, PacifiCorp filed a renewable cost adjustment clause that will allow for timely recovery of the costs to implement Oregon’s Renewable Portfolio Standard (“RPS”) between rate cases. The RPS requires the OPUC to approve an automatic adjustment clause for timely recovery of these costs by January 1, 2008.
In October 2007, PacifiCorp filed its first tax report under Oregon Senate Bill 408 (“SB 408”), which was enacted in September 2005. The filing indicates that in 2006, PacifiCorp paid $33 million more in federal, state and local taxes than was reflected in rates to its retail customers. SB 408 requires that PacifiCorp and other large regulated, investor-owned utilities that provide electric or natural gas service to Oregon customers file an annual tax report with the OPUC. The filing will be subject to a 180-day procedural schedule with rates potentially effective June 2008.
Wyoming
In June 2007, PacifiCorp filed a general rate case with the Wyoming Public Service Commission (“WPSC”) requesting an increase of $36 million annually, or an average price increase of 8%. In addition, PacifiCorp requested approval of a new renewable resource mechanism and a marginal cost pricing tariff to better reflect the cost of adding new generation. PacifiCorp expects the new rates to become effective by May 2008.
Washington
In October 2006, PacifiCorp filed a general rate case with the WUTC for an annual increase of $23.2$23 million, or 10.2%10%. As part of the filing, PacifiCorp proposed a Washington-only cost allocationcost-allocation methodology, which is based on PacifiCorp’s western resources. The rate case included a five-year pilot period on the proposed allocation methodology and a power cost adjustment mechanism. mechanism (“PCAM”). On June 21, 2007, the WUTC issued an order approving a rate increase of $14 million, or an average price increase of 6%, effective June 27, 2007, and accepted PacifiCorp’s proposed allocation methodology for a five-year pilot period. The WUTC found that PacifiCorp demonstrated the need for a PCAM, but it did not approve the design of the proposal in this case. The order authorized PacifiCorp to file a revised PCAM proposal, with or without a request to file power cost-only rate cases, outside the context of a general rate case within 12 months of the order.
Idaho
In its rebuttal case filed in MarchJune 2007, PacifiCorp reduced its request to $19 million. Hearings were held in March 2007filed a general rate case with the matter to be fully briefed by May 7, 2007. PacifiCorp anticipates thatIPUC for an annual increase of $18 million, or an average price increase of 10%, with a request for an effective date of January 1, 2008. A hearing on the WUTC will issue its order in summergeneral rate case has been scheduled for November 6, 2007.
California
In August 2007, PacifiCorp filed an energy cost adjustment clause application with the California Public Utilities Commission (“CPUC”) to update actual and forecasted net variable power costs, requesting a rate increase of $6 million, or 8% overall, with an effective date of January 1, 2008.
In October 2007, PacifiCorp filed two advice letter filings requesting authority to implement components of the post test-year adjustment mechanism. The combined requested increase would total $2 million, or 2%, and would be effective January 1, 2008.
Depreciation Rate Changes
In August 2007, PacifiCorp filed applications with the respective regulatory commissions in Utah, Oregon, Wyoming, Washington and Idaho to change the rates of depreciation, based on a new depreciation study. PacifiCorp expects that the state regulatory commissions will make the results of the new depreciation study effective beginning January 1, 2008.
Environmental Matters
In addition to the discussion contained herein, refer to Note 65 of Notes to Consolidated Financial Statements included in Item 1 of this report and Item 1 of PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006, for additional information regarding certain environmental matters affecting PacifiCorp’s operations.
Renewable Portfolio Standards
The RPS requirements described below could significantly impact PacifiCorp’s financial results. Resources that meet the qualifying electricity requirements under the RPS vary from state-to-state. Each state’s RPS require some form of compliance reporting and PacifiCorp can be subject to penalties in the event of non-compliance.
In November 2006, Washington voters approved a ballot initiative establishing a RPS requirement for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales in 2012 through 2015, 9% of retail sales in 2016 through 2019 and 15% of retail sales in 2020. The WUTC has undertaken a rulemaking proceeding to implement the initiative. PacifiCorp expects to be able to recover its costs of complying with the RPS, either through rate cases or an adjustment mechanism.
In June 2007, the Oregon Renewable Energy Act (the “Act”) was adopted, providing a comprehensive renewable energy policy for Oregon. Subject to certain exemptions and cost limitations established in the Act, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, 20% in 2020 through 2024, and 25% in 2025 and subsequent years. The Act requires the OPUC to establish an automatic adjustment clause or other timely mechanism to allow the electric utility to recover prudently incurred costs of its investments in renewable energy facilities and associated transmission costs. The OPUC and the Oregon Department of Energy have undertaken rulemaking proceedings to implement the initiative. PacifiCorp expects to be able to recover its costs of complying with the RPS through the automatic adjustment mechanism.
California law requires electric utilities to increase their procurement of renewable resources by at least 1% of their annual retail electricity sales per year so that 20% of their annual electricity sales are procured from renewable resources by no later than December 31, 2010. However, PacifiCorp and other small multi-jurisdictional utilities (“SMJU”) are currently awaiting further guidance from the CPUC on the treatment of SMJUs in the California RPS program. PacifiCorp has filed comments requesting SMJU rules for flexible compliance with annual targets. PacifiCorp expects rules governing the treatment of SMJUs and any specific flexible compliance mechanisms to be released by CPUC staff for public review in 2007. Absent further direction from the CPUC on treatment of SMJUs, PacifiCorp cannot predict the impact of the California RPS on its financial results.
Climate Change
As a result of increased attention to climate change in the United States, numerous bills have been introduced in the current session of the United States Congress that would reduce greenhouse gas emissions in the United States. Congressional leadership has made climate change legislation a priority, and many congressional observers expect to see the passage of climate change legislation within the next several years. In addition, nongovernmental organizations have become more active in initiating citizen suits under existing environmental and other laws. In April 2007, a United States Supreme Court decision concluded that the Environmental Protection Agency (“EPA”) has the authority under the Clean Air Act to regulate emissions of greenhouse gases from motor vehicles. In addition, pending cases that address the potential public nuisance from greenhouse gas emissions from electricity generators and the EPA’s failure to regulate greenhouse gas emissions from new and existing coal-fired plants are expected to become active. Furthermore, while debate continues at the national level over the direction of domestic climate policy, several states have developed state-specific laws or regional legislative initiatives to reduce greenhouse gas emissions, including Oregon, Washington, California and theseveral Northeastern states, and individual state actions to regulate greenhouse gas emissions are likely to increase. The outcomeimpact of any pending judicial proceedings and any pending or enacted federal and state climate change legislation and regulation cannot be determined at this time; however, adoption of stringent limits on greenhouse gas emissions could significantly impact PacifiCorp’s current and future fossil-fueled facilities, and, therefore, its financial results.
In February 2007, the governors of California, Arizona, New Mexico, Oregon and Washington signed the Western Regional Climate Action Initiative (the “Western Climate Initiative”) that directed their respective states to develop a regional target for reducing greenhouse gases by August 2007. Utah joined the Western Climate Initiative in May 2007. The states in the Western Climate Initiative recently announced a target of reducing greenhouse gas emissions by 15% below 2005 levels by 2020, with Utah establishing its reduction goal by August 2008. By August 2008, they are expected to devise a market-based program, such as a load-based cap-and-trade program for the electric sector, to reach the regional target. The Western Climate Initiative participants also have agreed to participate in a multi-state registry to track and manage greenhouse gas emissions in the region.
The Washington and Oregon governors enacted legislation in May 2007 and August 2007, respectively, establishing economy-wide goals for the reduction of greenhouse gas emissions in their respective states. Washington’s goals seek to, (i) by 2020, reduce emissions to 1990 levels; (ii) by 2035, reduce emissions to 25% below 1990 levels; and (iii) by 2050, reduce emissions to 50% below 1990 levels, or 70% below Washington’s forecasted emissions in 2050. Oregon’s goals seek to, (i) by 2010, cease the growth of Oregon greenhouse gas emissions; (ii) by 2020, reduce greenhouse gas levels to 10% below 1990 levels; and (iii) by 2050, reduce greenhouse gas levels to at least 75% below 1990 levels. Each state’s legislation also calls for state government-developed policy recommendations in the future to assist in the monitoring and achievement of these goals. The impact of the enacted legislation on PacifiCorp cannot be determined at this time.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting PacifiCorp, refer to Note 2 of Notes to Consolidated Financial Statements included in Item 1.
Critical Accounting Policies
Certain accounting policies require management to make estimates and judgments concerning transactions that will be settled in the future. Amounts recognized in the financial statements from such estimates are necessarily based on numerous assumptions involving varying and potentially significant degrees of judgment and uncertainty. Accordingly, the amounts currently reflected in the financial statements will likely increase or decrease in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, accrued pension and postretirement expense,obligations, income taxes and revenue recognition - unbilled revenues.revenue.
For additional discussion of PacifiCorp’s critical accounting policies, see Item 7 of PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006. PacifiCorp’s critical accounting policies have not changed materially since December 31, 2006, other than the adoption of Financial Accounting Standards Board Interpretation No. 48, “Accounting for Uncertainty in Income Taxes -– an interpretation of FASB Statement No. 109.”
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
For quantitative and qualitative disclosures about market risk affecting PacifiCorp, see Item 7A of PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006. PacifiCorp’s exposure to market risk has not changed materially since December 31, 2006.2006, except as described below.
PacifiCorp measures the market risk in its electricity and natural gas portfolio daily, utilizing a historical Value-at-Risk ("VaR") approach and other measurements of net position. VaR represents an estimate of possible changes at a given level of confidence in fair value that would be measured on its portfolio assuming hypothetical movements in forward market prices and is not necessarily indicative of actual results that may occur. One of the key assumptions utilized in the VaR computations is expected retail load levels. In May 2007, PacifiCorp completed its periodic update of its estimated long-term retail load levels, which affected the VaR computation. The updated estimate indicates an increase in PacifiCorp’s long-term retail loads due to higher levels of industrial activity, primarily in the natural resource development and manufacturing industries, in several states. The increase also reflects accelerated expected growth rates in the number of retail customers and usage in Oregon and Utah.
As of September 30, 2007, PacifiCorp’s estimated potential one-day unfavorable impact on fair value of the electricity and natural gas commodity portfolio over the next 48 months was $8 million, as measured by the VaR computations described above, compared to $16 million as of December 31, 2006. The minimum, average and maximum daily VaR (one-day holding periods) are as follows (in millions):
| | Three-Month Period | | | Nine-Month Period | |
| | Ended September 30, 2007 | | | Ended September 30, 2007 | |
| | | | | | |
Minimum VaR (measured) | | $ | 8 | | | $ | 8 | |
Average VaR (calculated) | | | 9 | | | | 13 | |
Maximum VaR (measured) | | | 11 | | | | 20 | |
PacifiCorp maintained compliance with its VaR limit procedures during the nine-month period ended September 30, 2007. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.
An evaluation was performed under the supervision and with the participation of PacifiCorp’s management, including the chief executive officer and chief financial officer, regarding the effectiveness of the design and operation of PacifiCorp’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,September 30, 2007. Based on that evaluation, PacifiCorp’s management, including the chief executive officer and chief financial officer, concluded that PacifiCorp’s disclosure controls and procedures were effective. There have been no changes during the quarter covered by this report in PacifiCorp’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, PacifiCorp’s internal control over financial reporting.
Item 1. Legal Proceedings.
For a description of certain legal proceedings affecting PacifiCorp, reviewrefer to Item 3 of PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006. Material developments to these proceedings during the three-monthnine-month period ended March 31,September 30, 2007, are included in Note 65 of the Notes to Consolidated Financial Statements included in Item 1.
There has been no material change to PacifiCorp’s risk factors from those disclosed in Item 1A of PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006.
Not applicable.
Not applicable.
Not applicable.
Not applicable.
The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrantregistrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| (Registrant) |
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Date: May 7,November 2, 2007 | /s/ David J. Mendez |
| David J. Mendez |
| Senior Vice President and Chief Financial Officer and officer duly authorized to sign this report on behalf of registrant |
Exhibit No. | Description |
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4* | Twentieth Supplemental Indenture, dated as of March 1, 2007, to PacifiCorp’s Mortgage and Deed of Trust dated as of January 9, 1989 (Exhibit 4, Current Report on Form 8-K, filed March 14, 2007, File No. 1-5152). |
12.1 | Statements of Computation of Ratio of Earnings to Fixed Charges. |
12.2 | Statements of Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends. |
15 | Letter Re: Unaudited Interim Financial Information. |
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. |
99 | $700,000,000 Credit Agreement dated as of October 23, 2007 among PacifiCorp, The Banks Party thereto, The Royal Bank of Scotland plc, as Syndication Agent, and Union Bank of California, N.A., as Administrative Agent. |
*Incorporated herein by reference.