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PACIFICORP /OR/ - Quarter Report: 2007 June (Form 10-Q)

pacificorp6300710q.htm
 



 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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
File Number
 
State or other jurisdiction of incorporation or organization
 
Identification No.
 
1-5152
 
PacifiCorp
 
93-0246090
   
(An Oregon Corporation)
   
   
825 N.E. Multnomah Street
   
   
Portland, Oregon 97232
   
   
503-813-5000
   
 
N/A
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes  T  No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See the definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer  ¨
Accelerated filer  ¨
Non-accelerated filer  T
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes  ¨  No  T

As of July 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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2


PART I – FINANCIAL INFORMATION


Item 1.                 Financial Statements.


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 June 30, 2007, the related consolidated statements of income for the three- and six-month periods ended June 30, 2007 and the three-month period ended June 30, 2006, and the related consolidated statement of cash flows for the six-month periods ended June 30, 2007 and 2006. These interim financial statements are the responsibility of PacifiCorp’s management.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of 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 SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2006 is fairly presented, in all material respects, in relation to the consolidated balance sheet from which it has been derived.






/s/ Deloitte & Touche LLP


Portland, Oregon
July 31, 2007

3


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(Amounts in millions)

   
Three-Month Periods
   
Six-Month Periods
 
   
Ended June 30,
   
Ended June 30,
 
   
2007
   
2006
   
2007
   
2006
 
                         
Revenues
  $
1,026
    $
860
    $
2,053
    $
2,090
 
                                 
Operating expenses:
                               
Energy costs
   
425
     
336
     
840
     
884
 
Operations and maintenance
   
255
     
260
     
517
     
534
 
Depreciation and amortization
   
122
     
116
     
243
     
229
 
Taxes, other than income taxes
   
23
     
26
     
51
     
50
 
Total
   
825
     
738
     
1,651
     
1,697
 
                                 
Income from operations
   
201
     
122
     
402
     
393
 
                                 
Interest and other expense (income):
                               
Interest expense
   
79
     
69
     
154
     
138
 
Interest income
    (4 )     (2 )     (7 )     (4 )
Allowance for borrowed funds
    (9 )     (5 )     (16 )     (10 )
Allowance for equity funds
    (10 )     (6 )     (17 )     (12 )
Other
    (2 )    
-
      (2 )     (2 )
Total
   
54
     
56
     
112
     
110
 
                                 
Income before income tax expense
   
147
     
66
     
290
     
283
 
Income tax expense
   
42
     
23
     
86
     
93
 
Net income
  $
105
    $
43
    $
204
    $
190
 

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




4


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)

   
As of
 
   
June 30,
   
December 31,
 
   
2007
   
2006
 
       
ASSETS
 
             
Current assets:
           
Cash and cash equivalents
  $
56
    $
59
 
Accounts receivable, net
   
319
     
342
 
Unbilled revenue
   
194
     
178
 
Amounts due from affiliates
   
12
     
53
 
Inventories at average costs:
               
Materials and supplies
   
160
     
140
 
Fuel
   
136
     
104
 
Derivative contracts
   
109
     
151
 
Deferred income taxes
   
69
     
28
 
Other
   
44
     
57
 
Total current assets
   
1,099
     
1,112
 
                 
Property, plant and equipment
   
16,201
     
15,843
 
Accumulated depreciation and amortization
    (6,002 )     (5,842 )
     
10,199
     
10,001
 
Construction work-in-progress
   
1,147
     
809
 
Total property, plant and equipment, net
   
11,346
     
10,810
 
                 
Other assets:
               
Regulatory assets
   
1,293
     
1,397
 
Derivative contracts
   
208
     
235
 
Deferred charges and other
   
304
     
298
 
Total other assets
   
1,805
     
1,930
 
                 
Total assets
  $
14,250
    $
13,852
 

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

5


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)

   
As of
 
   
June 30,
   
December 31,
 
   
2007
   
2006
 
   
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
             
Current liabilities:
           
Accounts payable
  $
477
    $
385
 
Amounts due to affiliates
   
2
     
1
 
Accrued employee expenses
   
119
     
85
 
Taxes payable, other than income taxes
   
46
     
30
 
Interest payable
   
66
     
57
 
Derivative contracts
   
116
     
110
 
Long-term debt and capital lease obligations, currently maturing
   
221
     
127
 
Preferred stock subject to mandatory redemption, currently maturing
   
-
     
38
 
Short-term debt
   
30
     
397
 
Other
   
132
     
135
 
Total current liabilities
   
1,209
     
1,365
 
                 
Deferred credits:
               
Deferred income taxes
   
1,646
     
1,641
 
Investment tax credits
   
58
     
62
 
Regulatory liabilities
   
796
     
822
 
Derivative contracts
   
474
     
504
 
Pension and other post employment liabilities
   
523
     
691
 
Other
   
381
     
374
 
Total deferred credits
   
3,878
     
4,094
 
                 
Long-term debt and capital lease obligations, net of current maturities
   
4,366
     
3,967
 
Total liabilities
   
9,453
     
9,426
 
                 
Commitments and contingencies (Note 5)
               
                 
Shareholders’ equity:
               
Preferred stock
   
41
     
41
 
Common equity:
               
Common shareholder’s capital - 750 shares authorized, no par value, 357 shares issued and outstanding
   
3,752
     
3,600
 
Retained earnings
   
1,006
     
789
 
Accumulated other comprehensive loss, net
    (2 )     (4 )
Total common equity
   
4,756
     
4,385
 
Total shareholders’ equity
   
4,797
     
4,426
 
                 
Total liabilities and shareholders’ equity
  $
14,250
    $
13,852
 

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

6


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

   
Six-Month Periods
 
   
Ended June 30,
 
   
2007
   
2006
 
             
Cash flows from operating activities:
           
Net income
  $
204
    $
190
 
    Adjustments to reconcile net income to net cash provided by operating activities:
               
Unrealized loss (gain) on derivative contracts, net
   
2
      (21 )
Depreciation and amortization
   
243
     
229
 
Deferred income taxes and investment tax credits, net
    (1 )     (5 )
Regulatory asset/liability establishment and amortization
    (24 )    
19
 
Other
   
11
     
20
 
Changes in:
               
Accounts receivable, net and other assets
   
2
      (8 )
Inventories
    (52 )     (38 )
Amounts due to/from affiliates - MEHC, net
   
42
      (1 )
Accounts payable and other liabilities
   
34
      (2 )
Net cash provided by operating activities
   
461
     
383
 
                 
Cash flows from investing activities:
               
Capital expenditures
    (731 )     (623 )
Proceeds from sale of assets
   
7
     
-
 
Proceeds from available-for-sale securities
   
19
     
71
 
Purchases of available-for-sale securities
    (17 )     (78 )
Other
   
17
      (1 )
Net cash used in investing activities
    (705 )     (631 )
                 
Cash flows from financing activities:
               
Changes in short-term debt
    (367 )    
90
 
Proceeds from long-term debt, net of issuance costs
   
600
     
-
 
Proceeds from equity contributions
   
150
     
184
 
Dividends paid
    (1 )     (18 )
    Repayments and redemptions on long-term debt, preferred stock subject to mandatory redemption and capital lease obligations
    (145 )     (108 )
Other
   
4
     
9
 
Net cash provided by financing activities
   
241
     
157
 
                 
Change in cash and cash equivalents
    (3 )     (91 )
Cash and cash equivalents at beginning of period
   
59
     
164
 
Cash and cash equivalents at end of period
  $
56
    $
73
 

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


7


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”), which 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 June 30, 2007 and for the three- and six-month periods ended June 30, 2007 and 2006. A portion of PacifiCorp’s business is of a seasonal nature and, therefore, results of operations for the three- and six-month periods ended June 30, 2007 and 2006 are not necessarily indicative of the results for a 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. 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, describes 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 significant accounting policies during the first six months of 2007, except as described in Note 2.

(2)           New Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes–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 as of January 1, 2007, is included in other deferred credits in the Consolidated Balance Sheet.

8



Included in the asset of $22 million is $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. Federal income tax returns.

As of June 30, 2007, PacifiCorp had an asset of $28 million for uncertain tax positions.

In February 2007, 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.

(3)           Recent Debt Transactions

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 2007, PacifiCorp issued $600 million of its 5.75% First Mortgage Bonds due April 1, 2037. The proceeds were used to repay short-term debt and for other general corporate purposes.


9



 (4)           Risk Management and Hedging Activities

PacifiCorp is directly exposed to the impact of market fluctuations in the prices of natural gas and electricity. PacifiCorp is exposed to interest rate risk as a result of the issuance of fixed and variable-rate debt. 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, report and manage 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 June 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 Sheet as of June 30, 2007 (in millions):

                           
Accumulated
 
                     
Regulatory
   
Other
 
   
Derivative Net Assets (Liabilities)
   
Net Assets
   
Comprehensive
 
   
Assets
   
Liabilities
   
Net
   
(Liabilities)
   
(Income) Loss (1)
 
                               
Commodity derivatives
  $
316
    $ (590 )   $ (274 )   $
276
    $ (5 )
Foreign currency contracts
   
1
     
-
     
1
      (1 )    
-
 
Total
  $
317
    $ (590 )   $ (273 )   $
275
    $ (5 )
                                         
Current
  $
109
    $ (116 )   $ (7 )                
Non-current
   
208
      (474 )     (266 )                
Total
  $
317
    $ (590 )   $ (273 )                

(1)
Before income taxes.

The following table summarizes the various derivative mark-to-market positions included in the accompanying Consolidated Balance Sheet as of December 31, 2006 (in millions):

                           
Accumulated
 
                     
Regulatory
   
Other
 
   
Derivative Net Assets (Liabilities)
   
Net Assets
   
Comprehensive
 
   
Assets
   
Liabilities
   
Net
   
(Liabilities)
   
(Income) Loss (1)
 
                               
Commodity derivatives
  $
383
    $ (614 )   $ (231 )   $
233
    $ (3 )
Foreign currency contracts
   
3
     
-
     
3
      (3 )    
-
 
Total
  $
386
    $ (614 )   $ (228 )   $
230
    $ (3 )
                                         
Current
  $
151
    $ (110 )   $
41
                 
Non-current
   
235
      (504 )     (269 )                
Total
  $
386
    $ (614 )   $ (228 )                

(1)
Before income taxes.


10



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
   
Six-Month Periods
 
   
Ended June 30,
   
Ended June 30,
 
   
2007
   
2006
   
2007
   
2006
 
                         
Revenues
  $
19
    $ (26 )   $
25
    $
252
 
Operating expenses:
                               
Energy costs
    (24 )     (7 )     (27 )     (230 )
Operations and maintenance
   
-
     
1
     
-
      (1 )
Total unrealized gain (loss) on derivative contracts
  $ (5 )   $ (32 )   $ (2 )   $
21
 

(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. 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. PacifiCorp believes it is in material compliance with current environmental requirements.

Accrued Environmental Costs

PacifiCorp is fully or partly responsible for environmental remediation 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 June 30, 2007 and December 31, 2006 was $21 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.


11


Hydroelectric Relicensing

PacifiCorp’s hydroelectric portfolio consists of 49 plants with an aggregate plant net owned capacity of 1,160 megawatts (“MW”). The Federal Energy Regulatory Commission (the “FERC”) regulates 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 $83 million and $79 million in costs at June 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. 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 summer 2007. Other federal agencies are also working to complete their endangered species analyses. PacifiCorp will need to obtain water quality certifications from Oregon and California prior to the FERC issuing a final license.

In the relicensing of the Klamath hydroelectric project, PacifiCorp had incurred $45 million and $42 million in costs at June 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.


12


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 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 the Clean Air Act’s opacity standards at PacifiCorp’s Jim Bridger plant in Wyoming. Opacity is an indication of the amount 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. 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 June 21, 2007, the 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, which 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 cash payments to escrows controlled by the California Parties in the amount of $16 million in April 2007, and upon FERC approval of the agreement in June 2007, PacifiCorp allowed the PX to release an additional $12 million to such escrows, which represented PacifiCorp’s estimated unpaid receivable from the transactions in the PX and ISO markets during the Refund Periods, plus interest. The monies held in escrow are for distribution to buyers from the ISO and PX markets that purchased power during the Refund Period. The agreement provides for the release of claims by the California Parties (as well as additional parties that chose to 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.

13



(6)           Employee Benefit Plans

In December 2006, non-bargaining employees were notified that PacifiCorp would switch from a traditional final average pay formula for the PacifiCorp Retirement Plan to a cash balance formula effective June 1, 2007. As a result of the change, benefits under the traditional final average pay formula were frozen as of May 31, 2007, and PacifiCorp’s pension liability and regulatory assets each decreased by $111 million.

The components of net periodic benefit cost for the three- and six-month periods ended June 30 were as follows (in millions):

   
Three-Month Periods
   
Six-Month Periods
 
   
Ended June 30,
   
Ended June 30,
 
   
2007
   
2006
   
2007
   
2006
 
                         
Pension:
                       
Service cost
  $
6
    $
7
    $
14
    $
15
 
Interest cost
   
19
     
19
     
38
     
38
 
Expected return on plan assets
    (17 )     (18 )     (34 )     (37 )
Net amortization and other costs
   
6
     
9
     
14
     
18
 
Net periodic benefit cost
  $
14
    $
17
    $
32
    $
34
 

                         
Other postretirement:
                       
Service cost
  $
2
    $
2
    $
4
    $
4
 
Interest cost
   
9
     
8
     
17
     
16
 
Expected return on plan assets
    (7 )     (6 )     (13 )     (13 )
Net amortization and other costs
   
4
     
5
     
9
     
10
 
Net periodic benefit cost
  $
8
    $
9
    $
17
    $
17
 

Excluded from the tables above are contributions to certain multi-employer and joint trust union plans of $3 million and $2 million for the three-month periods ended June 30, 2007 and 2006, respectively, and $6 million and $4 million for the six-month periods ended June 30, 2007 and 2006, respectively.
 
Employer Contributions

Employer contributions to the pension plans and the other postretirement plan are expected to be approximately $88 million and $34 million, respectively, in 2007. As of June 30, 2007, $63 million and $17 million of contributions had been made to the pension plans and the other postretirement plan, respectively.

Severance

PacifiCorp has reviewed its organization and workforce requirements. As a result, PacifiCorp incurred severance expense of $3 million and $8 million during the three-month periods ended June 30, 2007 and 2006, respectively; and $9 million and $20 million during the six-month periods ended June 30, 2007 and 2006, respectively. In June 2007, PacifiCorp established a regulatory asset of $2 million thereby reducing severance expense to $1 million and $7 million during the three- and six-month periods ended June 30, 2007, respectively. The regulatory asset was established as a result of receiving regulatory approval for recovery of a portion of previously incurred severance costs.

14



(7)           Comprehensive Income and Components of Accumulated Other Comprehensive Income (Loss)

The components of comprehensive income are as follows (in millions):

   
Three-Month Periods
   
Six-Month Periods
 
   
Ended June 30,
   
Ended June 30,
 
   
2007
   
2006
   
2007
   
2006
 
Net income
  $
105
    $
43
    $
204
    $
190
 
Other comprehensive income:
                               
Unrecognized amounts on retirement benefits, net of tax of $-; $-; $-; and $-
   
1
     
-
     
1
     
-
 
Fair value adjustment on cash flow hedges, net of tax of $3; $(3); $1; and $(3)
   
5
      (4 )    
1
      (4 )
Minimum pension liability, net of tax of $-; $-; $-; and $3
   
-
     
-
     
-
     
5
 
Unrealized losses on marketable securities, net of tax of $-; $(1); $-; and $(1)
   
-
      (2 )    
-
      (3 )
Total other comprehensive income (loss)
   
6
      (6 )    
2
      (2 )
                                 
Comprehensive income
  $
111
    $
37
    $
206
    $
188
 

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
 
   
June 30,
   
December 31,
 
   
2007
   
2006
 
             
Unrecognized amounts on retirement benefits, net of tax of $(4) and $(4)
  $ (5 )   $ (6 )
Fair value adjustment on cash flow hedges, net of tax of $2 and $1
   
3
     
2
 
Total accumulated other comprehensive loss, net
  $ (2 )   $ (4 )



15


Item 2.                 Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following is management’s discussion and analysis of certain significant factors which have affected the financial condition and results of operations of 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;
 

16



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

Results of Operations

Overview

PacifiCorp’s net income increased $14 million during the six-month period ended June 30, 2007, to $204 million compared to $190 million for the six-month period ended June 30, 2006, primarily due to higher retail revenues and higher net wholesale sales and purchases, partially offset by higher fuel costs. PacifiCorp’s retail load continues to rise due to growth in the number of retail customers and usage. The improved financial results were primarily due to higher retail prices approved by regulators and higher output at PacifiCorp’s thermal plants serving the higher retail load, partially offset by higher prices of coal and natural gas and lower hydroelectric generation. Output from PacifiCorp’s thermal plants for the six-month period ended June 30, 2007, increased by 2,326,813 megawatt-hours (“MWh”), or 10%, compared to the six-month period ended June 30, 2006, primarily due to the Currant Creek plant becoming fully operational at the end of March 2006. Output from PacifiCorp’s hydroelectric facilities decreased by 634,832 MWh, or 22%, during the six-month period ended June 30, 2007, compared to the six-month period ended June 30, 2006, primarily due to drier than normal conditions in the current period.


17


Three-Month Period Ended June 30, 2007 Compared to Three-Month Period Ended June 30, 2006

Revenues (in millions)

   
Three-Month Periods
       
   
Ended June 30,
   
Favorable/(Unfavorable)
 
   
2007
   
2006
   
$ Change
   
% Change
 
                   
                         
Retail
  $
774
    $
695
    $
79
      11 %
Wholesale sales and other
   
252
     
165
     
87
     
53
 
Total revenues
  $
1,026
    $
860
    $
166
     
19
 
                                 
Retail energy sales (gigawatt - hours)
   
12,790
     
12,167
     
623
     
5
 
Wholesale energy sales (gigawatt - hours)
   
3,492
     
3,202
     
290
     
9
 
Average retail customers (in thousands)
   
1,679
     
1,644
     
35
     
2
 

Retail revenues increased $79 million, or 11%, primarily due to:

 
·
$43 million of increases from higher retail prices approved by regulators;
 
 
·
$27 million of increases due to higher average customer usage resulting from warmer weather and an earlier start of the irrigation season in the current period as compared to the prior period;
 
 
·
$12 million of increases due to growth in the number of customers; partially offset by,
 
 
·
$3 million of decreases primarily due to changes in customer usage at different tariff levels.
 

Wholesale sales and other revenues increased $87 million, or 53%, primarily due to:

 
·
$45 million of increases due to changes in the fair value of derivative contracts;
 
 
·
$35 million of increases in wholesale electric sales primarily due to higher average prices; and
 
 
·
$4 million of increases resulting from higher sales of sulfur dioxide emission allowances in the current period.
 

Operating Expenses (in millions)

   
Three-Month Periods
       
   
Ended June 30,
   
Favorable/(Unfavorable)
 
   
2007
   
2006
   
$ Change
   
% Change
 
                   
                         
Energy costs
  $
425
    $
336
    $ (89 )     (26 )%
Operations and maintenance
   
255
     
260
     
5
     
2
 
Depreciation and amortization
   
122
     
116
      (6 )     (5 )
Taxes, other than income taxes
   
23
     
26
     
3
     
12
 
Total operating expenses
  $
825
    $
738
    $ (87 )     (12 )


18


Energy costs increased $89 million, or 26%, primarily due to:

 
·
$63 million of increases primarily due to higher volumes of natural gas consumed, as well as higher average prices;
 
 
·
$25 million of increases in the cost of coal primarily due to higher average prices;
 
 
·
$17 million of increases due to changes in the fair value of derivative contracts;
 
 
·
$5 million of increases in purchased electricity due to higher average prices, substantially offset by lower volumes; partially offset by,
 
 
·
$12 million of decreases primarily due to the deferral of incurred power costs in accordance with the Wyoming power cost adjustment mechanism; and
 
 
·
$9 million in decreases due to the prior period loss on the streamflow weather derivative contract.
 

 
Operations and maintenance expense decreased $5 million, or 2%, primarily due to:

 
·
$7 million of decreases in employee severance costs;
 
 
·
$7 million of decreases in employee expenses, primarily due to reduced workforce;
 
 
·
$6 million of decreases due to changes in environmental accruals; partially offset by,
 
 
·
$11 million of increases in maintenance costs and related contracts, primarily associated with generation plant overhauls; and
 
 
·
$3 million of increases due to asset write-offs.
 

 
Depreciation and amortization expense increased $6 million, or 5%, primarily due to higher plant in service.

Interest and Other Expense (Income) (in millions)

   
Three-Month Periods
       
   
Ended June 30,
   
Favorable/(Unfavorable)
 
   
2007
   
2006
   
$ Change
   
% Change
 
                   
                         
Interest expense
  $
79
    $
69
    $ (10 )     (14 )%
Interest income
    (4 )     (2 )    
2
     
100
 
Allowance for borrowed funds
    (9 )     (5 )    
4
     
80
 
Allowance for equity funds
    (10 )     (6 )    
4
     
67
 
Other
    (2 )    
-
     
2
     
100
 
Total
  $
54
    $
56
    $
2
     
4
 

Interest expense increased $10 million, or 14%, primarily due to higher average debt balances during the three-month period ended June 30, 2007.

Allowance for borrowed and equity funds increased $8 million, primarily due to higher qualified construction work-in-progress balances during the three-month period ended June 30, 2007.


19


Income Tax Expense

Income tax expense for the three-month period ended June 30, 2007, increased $19 million to $42 million from the comparable period in 2006, primarily due to higher pre-tax earnings, partially offset by increases in tax credits associated with renewable energy. The effective tax rates were 29% and 35% for the three-month periods ended June 30, 2007 and 2006, respectively.

Six-Month Period Ended June 30, 2007 Compared to Six-Month Period Ended June 30, 2006

Revenues (in millions)

   
Six-Month Periods
       
   
Ended June 30,
   
Favorable/(Unfavorable)
 
   
2007
   
2006
   
$ Change
   
% Change
 
                   
                         
Retail
  $
1,551
    $
1,409
    $
142
      10 %
Wholesale sales and other
   
502
     
681
      (179 )     (26 )
Total revenues
  $
2,053
    $
2,090
    $ (37 )     (2 )
                                 
Retail energy sales (gigawatt - hours)
   
25,866
     
24,933
     
933
     
4
 
Wholesale energy sales (gigawatt - hours)
   
6,985
     
6,682
     
303
     
5
 
Average retail customers (in thousands)
   
1,677
     
1,641
     
36
     
2
 

Retail revenues increased $142 million, or 10%, primarily due to:

 
·
$85 million of increases from higher retail prices approved by regulators;
 
 
·
$33 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
 
 
·
$24 million of increases due to growth in the number of customers.
 

Wholesale sales and other revenues decreased $179 million, or 26%, primarily due to:

 
·
$227 million of decreases due to changes in the fair value of derivative contracts;
 
 
·
$7 million of decreases resulting from higher sales of sulfur dioxide emission allowances in the prior period; partially offset by,
 
 
·
$40 million of increases due to higher margins on non-physically settled system-balancing transactions; and
 
 
·
$20 million of increases on wholesale electric sales primarily due to higher volumes.
 

20



Operating Expenses (in millions)

   
Six-Month Periods
       
   
Ended June 30,
   
Favorable/(Unfavorable)
 
   
2007
   
2006
   
$ Change
   
% Change
 
                   
                         
Energy costs
  $
840
    $
884
    $
44
      5 %
Operations and maintenance
   
517
     
534
     
17
     
3
 
Depreciation and amortization
   
243
     
229
      (14 )     (6 )
Taxes, other than income taxes
   
51
     
50
      (1 )     (2 )
Total operating expenses
  $
1,651
    $
1,697
    $
46
     
3
 

Energy costs decreased $44 million, or 5%, primarily due to:

 
·
$203 million of decreases due to changes in the fair value of derivative contracts;
 
 
·
$12 million of decreases primarily due to the deferral of incurred power costs in accordance with the Wyoming power cost adjustment mechanism;
 
 
·
$9 million in decreases due to the prior period loss on the streamflow weather derivative contract; partially offset by,
 
 
·
$96 million of increases due to higher volumes of natural gas consumed and higher average prices;
 
 
·
$44 million of increases in the cost of coal substantially due to higher average prices; and
 
 
·
$37 million of increases in purchased electricity primarily due to higher average prices, partially offset by lower volumes.
 

Operations and maintenance expense decreased $17 million, or 3%, primarily due to:

 
·
$13 million of decreases in employee severance costs;
 
 
·
$13 million of decreases in employee expenses, primarily due to reduced workforce;
 
 
·
$8 million of decreases due to changes in environmental accruals;
 
 
·
$4 million of decreases due to the initial assessment of penalties related to compliance with the FERC standards of conduct for transmission in the prior period; partially offset by,
 
 
·
$19 million of increases in maintenance costs and related contracts, primarily associated with generation plant overhauls; and
 
 
·
$6 million of increases due to asset write-offs.
 

 
Depreciation and amortization expense increased $14 million, or 6%, primarily due to higher plant in service.

21



Interest and Other Expense (Income) (in millions)

   
Six-Month Periods
       
   
Ended June 30,
   
Favorable/(Unfavorable)
 
   
2007
   
2006
   
$ Change
   
% Change
 
                   
                         
Interest expense
  $
154
    $
138
    $ (16 )     (12 )%
Interest income
    (7 )     (4 )    
3
     
75
 
Allowance for borrowed funds
    (16 )     (10 )    
6
     
60
 
Allowance for equity funds
    (17 )     (12 )    
5
     
42
 
Other
    (2 )     (2 )    
-
     
-
 
Total
  $
112
    $
110
    $ (2 )     (2 )

Interest expense increased $16 million, or 12%, primarily due to higher average debt balances during the six-month period ended June 30, 2007.

Allowance for borrowed and equity funds increased $11 million, primarily due to higher qualified construction work-in-progress balances during the six-month period ended June 30, 2007.

Income Tax Expense

Income tax expense for the six-month period ended June 30, 2007, decreased $7 million to $86 million from the comparable period in 2006, partially due to increases in tax credits associated with renewable energy. The effective tax rates were 30% and 33% for the six-month periods ended June 30, 2007 and 2006, respectively.

22



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 contributions from PacifiCorp’s direct parent company, PPW Holdings 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 $78 million to $461 million for the six-month period ended June 30, 2007, compared to $383 million for the six-month period ended June 30, 2006, primarily due to higher retail revenues, higher net wholesale sales and purchases and the timing of cash collections and payments, partially offset by higher fuel costs.

Investing Activities

Net cash used in investing activities increased $74 million to $705 million for the six-month period ended June 30, 2007, compared to $631 million for the six-month period ended June 30, 2006, primarily due to higher capital expenditures compared to the prior period. Capital expenditures totaled $731 million for the six-month period ended June 30, 2007, compared to $623 million for the six-month period ended June 30, 2006. Capital spending increased primarily due to wind generation investments. 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 $63 million and $35 million, excluding non-cash allowance for equity funds used during construction, on emission control environmental projects during the six-month periods ended June 30, 2007 and 2006, respectively. These increases were partially offset by decreases in expenditures for the construction of the Currant Creek plant, which commenced full combined-cycle operation in March 2006, and decreases in expenditures for the construction of the 534 megawatt (“MW”) Lake Side plant, as compared to the previous period.

Financing Activities

Short-Term Debt

PacifiCorp’s short-term debt decreased by $367 million during the six-month period ended June 30, 2007, primarily due to the proceeds from the issuance of long-term debt and the capital contribution received during the period, partially offset by capital expenditures and maturities of long-term securities in excess of net cash provided by operating activities.

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt, of which an aggregate principal amount of $30 million of commercial paper was outstanding at June 30, 2007, with a weighted-average interest rate of 5.4%.

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Revolving Credit and Other Financing Agreements

PacifiCorp has an unsecured revolving credit facility with total bank commitments of $800 million through July 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 varies based on PacifiCorp’s credit ratings for its senior unsecured long-term debt securities. At June 30, 2007, there were no borrowings outstanding under this facility. In addition to this committed bank facility, PacifiCorp had $36 million in money market accounts included in cash and cash equivalents at June 30, 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 June 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 $22 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 June 30, 2007 and expire periodically through 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 June 30, 2007, PacifiCorp was in compliance with the covenants of its revolving credit and other financing agreements.

Long-Term Debt

During the six-month period ended June 30, 2007, PacifiCorp issued $600 million of its 5.75% First Mortgage Bonds due April 1, 2037 and made scheduled long-term debt repayments of $106 million.

At June 30, 2007, PacifiCorp had $900 million available under currently effective SEC shelf registration statements covering future first mortgage bond and unsecured debt issuances. Also at June 30, 2007, PacifiCorp had available state regulatory authority from the Oregon Public Utility Commission (“OPUC”) and the Idaho Public Utility Commission (“IPUC”) to issue up to an additional $900 million of long-term debt. An additional filing would be required by 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

In June 2007, PacifiCorp received capital contributions from PPW of $150 million.

Preferred Stock Redemptions

In June 2007, PacifiCorp redeemed $38 million of outstanding preferred stock subject to 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.

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Capital Expenditure Program

As of June 30, 2007, estimated 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 $1,803 million, which includes $810 million for ongoing operations projects, including new connections related to customer growth, $861 million for generation development and the related transmission projects, and $132 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 $758 million for costs related to wind generation projects as PacifiCorp continues to pursue additional cost-effective wind-powered generation. The estimate also includes the remaining costs to complete the 534-MW Lake Side plant, as well as upgrades of other generation plant equipment. The Lake Side plant is expected to cost approximately $347 million, including non-cash allowance for equity funds used during construction, of which $308 million, including approximately $15 million of non-cash allowance for equity funds used during construction, had been incurred through June 30, 2007. The Lake Side plant is expected to be placed into service in the third quarter of 2007.

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.

Integrated Resource Plans

As required by state regulators, PacifiCorp uses Integrated Resource Plans (“IRP”) to develop a long-term view of prudent future actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. The IRP process identifies the amount and timing of PacifiCorp’s expected future resource needs and an associated optimal future resource mix that accounts for planning uncertainty, risks, reliability impacts and other factors. The IRP is a coordinated effort with stakeholders in each of the six states where PacifiCorp operates. Each state commission that has IRP adequacy rules judges whether the IRP reasonably meets its standards and guidelines at the time the IRP is filed. PacifiCorp requests “acknowledgement” of its IRP filing from the UPSC, the OPUC and the WUTC pursuant to those state’s 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 Integrated Resource Plan. The 2007 Integrated Resource Plan 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 Integrated Resource Plan from state regulators and expects the acknowledgement process to be complete in 2008.

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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 June 30, 2007, were as follows:

 
Moody’s
 
Standard & Poor’s
       
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 June 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 $425 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.

For a further discussion of PacifiCorp’s credit ratings and their effect on PacifiCorp’s business, refer to Item 7 of PacifiCorp’s Transition Report on Form 10-K for the nine-month period ended December 31, 2006.

Contractual Obligations and Commercial Commitments

During the six-month period ended June 30, 2007, there were no material changes outside the ordinary 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, PacifiCorp’s March 2007 issuance of $600 million of its 5.75% First Mortgage Bonds due April 1, 2037.

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Regulatory Matters

In addition to the discussion contained herein regarding updates to regulatory matters based upon material changes that occurred during the six-month period ended June 30, 2007, refer to Note 5 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 2004, PacifiCorp, the BPA and other parties executed an additional agreement 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 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. On 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 include public utilities, cooperatives and federal agencies, part of the costs of the October 2000 settlement the BPA reached with its investor-owned utility customers. As a result of the ruling, on May 21, 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 residential and small farm customers’ electric bills in Oregon, Washington and Idaho. Because the benefit payments from the BPA are passed through to PacifiCorp’s customers, the outcome of this matter is not expected to have a significant effect on PacifiCorp’s consolidated financial results. There are several other lawsuits challenging certain aspects of the BPA’s Residential Exchange Program pending at the United States Ninth Circuit Court of Appeals for which the outcomes remain unknown.

Hydroelectric Decommissioning

Powerdale Hydroelectric Project – (Hood River, Oregon)

In June 2003, PacifiCorp entered into a settlement agreement to remove the 6-MW nameplate-rated Powerdale plant rather than pursue a new license, based 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 and other regulatory approvals, is projected to cost $6 million excluding inflation. Removal of the plant is scheduled to commence in 2010. However, in November 2006, flooding damaged the Powerdale plant and rendered 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 February 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 approved PacifiCorp’s proposed accounting entries, thereby allowing PacifiCorp to reclassify the net book value and the estimated removal costs to a regulatory asset. PacifiCorp has filed with its state commissions to recover these costs.

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State Regulatory Actions

The following discussion provides a state-by-state update based upon significant changes that occurred during the six-month period ended June 30, 2007:
 
        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 April 2007, PacifiCorp filed its annual compliance filing with the OPUC to update forecasted net power costs, requesting an increase of approximately $36 million, or an average price increase of 4%, to take effect January 1, 2008. The annual filing, called the transition adjustment mechanism (“TAM”), is due each April but will be adjusted for new contracts through October 2007 and for other changes to forecasted net power costs, such as coal and natural gas prices, through November 2007. In June 2007, parties to the case filed their responses, recommending smaller increases in the range of $13 million to $19 million. In July 2007, PacifiCorp filed the first of three updates to the TAM, adjusting its requested increase from $36 million to $30 million, as well as filed a rebuttal of the other parties’ positions. PacifiCorp expects a ruling from OPUC this fall.

Wyoming

In June 2007, PacifiCorp filed a general rate case with the Wyoming Public Service Commission 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 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 million, or 10%. As part of the filing, PacifiCorp proposed a Washington-only cost-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 (“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 June 2007, PacifiCorp filed a general rate case with the IPUC 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.

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Environmental Matters

In addition to the discussion contained herein, refer to Note 5 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 renewable portfolio standards (“RPS”) 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 RPS. The WUTC has undertaken a rulemaking proceeding to implement the initiative. Until final action is undertaken to implement the rules, PacifiCorp cannot predict the impact of the Washington RPS on its financial results.

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, a qualifying electric utility 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.

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 California Public Utilities Commission (“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.

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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 several Northeastern states and individual state actions to regulate greenhouse gas emissions are likely to increase. The impact 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 “Initiative”) that directs their respective states to develop a regional target for reducing greenhouse gases by August 2007. By August 2008, they are expected to devise a market-based program, such as a load-based cap-and-trade program to reach the target. The five states also have agreed to participate in a multi-state registry to track and manage greenhouse gas emissions in the region. In May 2007, the Utah governor also signed the Initiative.

The Washington and Oregon legislatures enacted legislation in May 2007 and June 2007, respectively, establishing 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.

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, accounting for the effects of certain types of regulation, derivatives, pension and postretirement obligations, income taxes and revenue recognition - unbilled revenues.
 
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.”
 
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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, except as described below.

Commodity Price Risk

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 June 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 $10 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) for the three- and six-month periods ended June 30, 2007, are as follows (in millions):

Minimum VaR (measured)
  $
9
 
Average VaR (calculated)
   
15
 
Maximum VaR (measured)
   
20
 

PacifiCorp maintained compliance with its VaR limit procedures during the six-month period ended June 30, 2007. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits.

Item 4.                 Controls and Procedures.

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 June 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.


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PART II - OTHER INFORMATION

Item 1.                 Legal Proceedings.

For a description of certain legal proceedings affecting PacifiCorp, refer 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 six-month period ended June 30, 2007, are included in Note 5 of Notes to Consolidated Financial Statements included in Item 1.
 
Item 1A.               Risk Factors.

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.

Item 2.                 Unregistered Sales of Equity Securities and Use of Proceeds.

Not applicable.

Item 3.                 Defaults Upon Senior Securities.

Not applicable.

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

Not applicable.

Item 5.                 Other Information.

Not applicable.

Item 6.                 Exhibits.

The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.

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SIGNATURE


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
PACIFICORP
 
(Registrant)
   
   
   
Date: August 3, 2007
/s/ David J. Mendez
 
David J. Mendez
 
Senior Vice President and Chief Financial Officer

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EXHIBIT INDEX

Exhibit No.
Description
   
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.


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