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Portland General Electric Co 10-Q 2009

Documents found in this filing:

  1. 10-Q
  2. Ex-3.1
  3. Ex-31.1
  4. Ex-31.2
  5. Ex-32
  6. Ex-32
Form 10-Q
Table of Contents

 

 

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, 2009

OR

¨  

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number: 1-5532-99

PORTLAND GENERAL ELECTRIC COMPANY

(Exact name of registrant as specified in its charter)

 

Oregon   93-0256820

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

121 SW Salmon Street

Portland, Oregon 97204

(503) 464-8000

(Address of principal executive offices, including zip code,

and Registrant’s telephone number, including area code)

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.    x  Yes    ¨  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files).    ¨  Yes    ¨  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer    x   Accelerated filer    ¨   Non-accelerated filer    ¨   Smaller reporting company    ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    x  No

Number of shares of common stock outstanding as of July 31, 2009 is 75,186,813 shares.

 

 

 


Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2009

TABLE OF CONTENTS

 

Definitions

  3
PART I – FINANCIAL INFORMATION   4

Item 1.

 

Financial Statements

  4
 

Condensed Consolidated Statements of Income

  4
 

Condensed Consolidated Balance Sheets

  5
 

Condensed Consolidated Statements of Cash Flows

  7
 

Notes to Condensed Consolidated Financial Statements

  9

Item 2.

 

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

  31

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk.

  57

Item 4.

 

Controls and Procedures.

  58
PART II – OTHER INFORMATION   58

Item 1.

 

Legal Proceedings.

  58

Item 1A.

 

Risk Factors.

  58

Item 4.

 

Submission of Matters to a Vote of Security Holders.

  58

Item 6.

  Exhibits.   59
SIGNATURE   60

 

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DEFINITIONS

The following abbreviations and acronyms are used throughout this document:

 

Abbreviation or
Acronym

  

Definition

AFDC    Allowance for funds used during construction
Biglow Canyon    Biglow Canyon Wind Farm
Boardman    Boardman coal plant
BPA    Bonneville Power Administration
CERS    California Energy Resources Scheduling
Colstrip    Colstrip Units 3 and 4 coal plant
DEQ    Oregon Department of Environmental Quality
EITF    Emerging Issues Task Force of the Financial Accounting Standards Board
EPA    U.S. Environmental Protection Agency
FERC    Federal Energy Regulatory Commission
IRP    Integrated Resource Plan
MW    Megawatts
MWa    Average megawatts
MWh    Megawatt hours
NVPC    Net Variable Power Costs
OPUC    Public Utility Commission of Oregon
PCAM    Power Cost Adjustment Mechanism
SB 408    Oregon Senate Bill 408
SEC    Securities and Exchange Commission
SFAS    Statement of Financial Accounting Standards (issued by the Financial Accounting Standards Board)
Trojan    Trojan Nuclear Plant
URP    Utility Reform Project

 

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PART I – FINANCIAL INFORMATION

 

Item 1. Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in millions, except per share amounts)

(Unaudited)

 

     Three Months Ended June 30,    Six Months Ended June 30,  
     2009    2008    2009     2008  

Revenues

   $ 389    $ 425    $ 874      $ 896   

Operating expenses:

          

Purchased power and fuel

     184      185      439        435   

Production and distribution

     43      46      85        85   

Administrative and other

     46      47      91        94   

Depreciation and amortization

     50      50      107        100   

Taxes other than income taxes

     21      21      44        43   
                              

Total operating expenses

     344      349      766        757   
                              

Income from operations

     45      76      108        139   

Other income (expense):

          

Allowance for equity funds used during construction

     6      2      8        4   

Miscellaneous income (expense), net

     4      1      1        (2
                              

Other income, net

     10      3      9        2   

Interest expense

     26      23      51        46   
                              

Income before income taxes

     29      56      66        95   

Income taxes

     3      17      16        28   
                              

Net income

     26      39      50        67   

Less: net income (loss) attributable to noncontrolling interests

     2      -      (5     -   
                              

Net income attributable to Portland General Electric Company

   $ 24    $ 39    $ 55      $ 67   
                              

Weighted-average shares outstanding (in thousands):

          

Basic

     75,131      62,532      70,352        62,531   
                              

Diluted

     75,235      62,588      70,447        62,580   
                              

Earnings per share - basic and diluted

   $ 0.31    $ 0.63    $ 0.77      $ 1.07   
                              

Dividends declared per common share

   $ 0.255    $ 0.245    $ 0.500      $ 0.480   
                              

 

 

See accompanying notes to condensed consolidated financial statements.

 

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)

 

     June 30,
2009
   December 31,
2008
ASSETS      

Current assets:

     

Cash and cash equivalents

   $ 58    $ 10

Accounts receivable, net

     150      168

Unbilled revenues

     63      96

Assets from price risk management activities - current

     26      31

Inventories

     75      71

Margin deposits

     127      189

Current deferred income taxes

     120      17

Regulatory assets - current

     244      194

Other current assets

     29      44
             

Total current assets

     892      820

Electric utility plant, net

     3,662      3,301

Non-qualified benefit plan trust

     45      46

Nuclear decommissioning trust

     47      46

Regulatory assets - noncurrent

     585      631

Other noncurrent assets

     53      45
             

Total assets

   $ 5,284    $ 4,889
             

 

 

See accompanying notes to condensed consolidated financial statements.

 

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in million)

(Unaudited)

 

     June 30,
2009
    December 31,
2008
 
LIABILITIES AND SHAREHOLDERS’ EQUITY     

Current liabilities:

    

Accounts payable and accrued liabilities

   $ 186      $ 217   

Liabilities from price risk management activities - current

     254        225   

Regulatory liabilities - current

     66        43   

Short-term debt

     -          203   

Current portion of long-term debt

     186        142   

Other current liabilities

     72        59   
                

Total current liabilities

     764        889   

Long-term debt, net of current portion

     1,408        1,164   

Liabilities from price risk management activities - noncurrent

     168        201   

Regulatory liabilities - noncurrent

     645        640   

Noncurrent deferred income taxes

     414        304   

Unfunded status of pension and postretirement plans

     176        174   

Non-qualified benefit plan liabilities

     94        91   

Other noncurrent liabilities

     71        72   
                

Total liabilities

     3,740        3,535   
                

Commitments and contingencies (see notes)

    

Shareholders’ equity:

    

Portland General Electric Company shareholders’ equity:

    

Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of June 30, 2009 and December 31, 2008

     -          -     

Common stock, no par value, 160,000,000 shares authorized; 75,148,908 and 62,575,257 shares issued and outstanding as of June 30, 2009 and December 31, 2008, respectively

     830        659   

Accumulated other comprehensive loss

     (5     (5

Retained earnings

     717        700   
                

Total Portland General Electric Company shareholders’ equity

     1,542        1,354   

Noncontrolling interests’ equity

     2        -     
                

Total shareholders’ equity

     1,544        1,354   
                

Total liabilities and shareholders’ equity

   $ 5,284      $ 4,889   
                

 

 

See accompanying notes to condensed consolidated financial statements.

 

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

 

     Six Months Ended June 30,  
     2009     2008  

Cash flows from operating activities:

    

Net income

   $ 50      $ 67   

Reconciliation of net income to net cash provided by operating activities:

    

Depreciation and amortization

     107        100   

Power cost deferrals

     (9     8   

Deferred income taxes

     8        19   

Allowance for equity funds used during construction

     (8     (4

Increase (decrease) in net liabilities (assets) from price risk management activities

     6        (412

Regulatory deferral - price risk management activities

     (6     412   

Other non-cash income and expenses, net

     14        13   

Changes in working capital:

    

Decrease in margin deposits

     62        147   

Decrease in receivables

     51        53   

Decrease in payables

     (56     (35

Other working capital items, net

     1        (9

Other, net

     -          9   
                

Net cash provided by operating activities

     220        368   
                

Cash flows from investing activities:

    

Capital expenditures

     (395     (206

Sales of nuclear decommissioning trust securities

     17        13   

Purchases of nuclear decommissioning trust securities

     (17     (12

Insurance proceeds

     -          3   

Other, net

     (1     (2
                

Net cash used in investing activities

     (396     (204
                

 

 

See accompanying notes to condensed consolidated financial statements.

 

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)

 

     Six Months Ended June 30,  
     2009     2008  

Cash flows from financing activities:

    

Proceeds from issuance of common stock, net of issuance costs

   $ 170      $ -     

Proceeds from issuance of long-term debt

     430        50   

Debt issuance costs

     (4     -     

Payments on long-term debt

     (142     (56

Borrowings on revolving credit facilities

     82        -     

Payments on revolving credit facilities

     (213     -     

Payments on short-term debt, net

     (72     -     

Dividends paid

     (34     (29

Noncontrolling interests’ cash contributions

     7        -     
                

Net cash provided by (used in) financing activities

     224        (35
                

Change in cash and cash equivalents

     48        129   

Cash and cash equivalents, beginning of period

     10        73   
                

Cash and cash equivalents, end of period

   $ 58      $ 202   
                

Supplemental cash flow information is as follows:

    

Cash paid during the period for:

    

Interest, net of amounts capitalized

   $ 35      $ 39   

Income taxes

     -          3   

Non-cash investing and financing activities:

    

Accrued capital additions

     52        12   

Accrued dividends payable

     20        15   

 

 

See accompanying notes to condensed consolidated financial statements.

 

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon. The Company also sells electricity and natural gas in the wholesale market to utilities, brokers, and power and fuel marketers located throughout the western United States. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters is located in Portland, Oregon and its service area is located entirely within Oregon. The Company served 817,473 retail customers as of June 30, 2009.

As of June 30, 2009, PGE had 2,715 employees, with 878 employees covered under agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers (Local 125). Such agreements cover 843 employees for the five-year period ended February 28, 2009 and 35 employees for the five-year period ending August 1, 2011. PGE is in negotiation with Local 125 for a new agreement to replace the one that expired February 28, 2009. This agreement remains in effect following the expiration date unless either party gives at least 60 days’ written notice of termination. Neither party has given written notice to terminate.

Condensed Consolidated Financial Statements

These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Certain information and footnote disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations, although PGE believes that the disclosures provided are adequate to make the interim information presented not misleading.

The financial information included herein for the three and six month periods ended June 30, 2009 and 2008 is unaudited; however, such information reflects all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary for a fair presentation of the condensed consolidated financial position, condensed consolidated results of operations and condensed consolidated cash flows of the Company for these interim periods. Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas, interim financial results do not necessarily represent those to be expected for the year. The financial information as of December 31, 2008 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2008, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 25, 2009, and should be read in conjunction with such consolidated financial statements.

 

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Use of Estimates

The preparation of condensed consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of contingent liabilities, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results experienced by the Company could differ materially from those estimates.

Reclassifications

During the first quarter of 2009, PGE reconsidered the presentation of its Price risk management assets and liabilities, which previously had all been classified as current, as well as its Regulatory assets and liabilities, which previously had all been classified as noncurrent. The Company determined it was preferable to present such assets and liabilities as either current or noncurrent based on the expected settlement dates of the underlying contracts for Price risk management assets and liabilities and the timing of amortization or the timing of the collection or refund of the respective Regulatory asset or liability. To conform to the 2009 presentation, certain reclassifications have been made to the December 31, 2008 condensed consolidated balance sheet. These reclassifications include the presentation of noncurrent Price risk management assets of $8 million (included in Other noncurrent assets) and noncurrent Price risk management liabilities of $201 million, all of which were previously classified as current, and current portion of Regulatory assets of $194 million and current portion of Regulatory liabilities of $43 million, all of which were previously classified as noncurrent. Deferred taxes associated with these Price risk management assets and liabilities and Regulatory assets and liabilities were also reclassified. As a result of the preceding reclassifications, current deferred income taxes in the amount of $134 million included in the December 31, 2008 condensed consolidated balance sheet have been reclassified as a reduction of Deferred income tax liabilities to conform to the 2009 presentation.

Recent Accounting Pronouncements

Adopted Accounting Pronouncements

On January 1, 2009, PGE adopted Statement of Financial Accounting Standards No. (SFAS) 157, Fair Value Measurements (SFAS 157), for nonfinancial assets and liabilities, in accordance with FASB Staff Position No. (FSP) 157-2, Effective Date of FASB Statement No. 157 (FSP FAS 152-2). SFAS 157 defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not modify any currently existing accounting pronouncements. PGE’s nonfinancial liabilities include asset retirement obligations (AROs), which are accounted for in accordance with SFAS 143, Accounting for Asset Retirement Obligations (SFAS 143), and are initially measured at fair value. In subsequent reporting periods, AROs are not measured at fair value. The application of SFAS 157 is not required for recurring measurement of nonfinancial liabilities accounted for pursuant to SFAS 143 as amounts are only measured at fair value in the initial period and not in subsequent reporting periods. The adoption of SFAS 157 for nonfinancial assets and liabilities had no impact on the Company’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On January 1, 2009, PGE adopted SFAS 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No 51 (SFAS 160), which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary, as well as the deconsolidation of a subsidiary. SFAS 160 clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the deconsolidated entity that should be reported as equity in the consolidated financial statements. It also (1) changes the way the consolidated income statement is presented by requiring consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest, (2) establishes a single method of accounting for changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation, and (3) continues to allocate to a noncontrolling interest its share of losses if ever that attribution results in a deficit noncontrolling interest balance. SFAS 160

 

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shall be applied prospectively, with the exception of the presentation and disclosure requirements, which shall be applied retrospectively for all periods presented. Any noncontrolling interests resulting from the consolidation of a less-than-wholly-owned subsidiary beginning January 1, 2009 is accounted for in accordance with SFAS 160. The adoption of SFAS 160 did not have a material impact on PGE’s consolidated financial position or consolidated results of operation; however, it did have an impact on the presentation of noncontrolling interests, formerly known as “minority interests”, in PGE’s consolidated financial position, consolidated results of operation, and consolidated cash flows.

On January 1, 2009, PGE adopted SFAS 161, Disclosures about Derivative Instruments and Hedging Activities (SFAS 161), which requires enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The adoption of SFAS 161 did not have an impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On January 1, 2009, PGE adopted FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities (FSP EITF 03-6-1), which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in SFAS 128, Earnings per Share. All prior period earnings per share data presented shall be adjusted retrospectively to conform to the provisions of FSP EITF 03-6-1. The adoption of FSP EITF 03-6-1 did not have an impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On June 30, 2009, PGE adopted SFAS 165, Subsequent Events (SFAS 165), which provides guidance on the recognition and disclosure of events that occur after the balance sheet date but before financial statements are issued. The adoption of SFAS 165 did not have an impact on PGE’s consolidated financial position, consolidated results of results of operation, or consolidated cash flows. PGE considered events through July 31, 2009, for purposes of determining whether any event warranted recognition or disclosure in its interim financial statements as of and for the three and six month periods ended June 30, 2009.

On June 30, 2009, PGE adopted FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, which requires disclosures about the fair value of financial instruments in interim financial statements as well as in annual financial statements. The adoption of FSP FAS 107-1 and APB 28-1 did not have an impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On June 30, 2009, PGE adopted FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP FAS 157-4), which requires, among other things, the disclosure in interim and annual periods (1) the inputs and valuation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, during the period, and (2) quantitative disclosures about the fair value measurements separately for each major category of assets and liabilities measured at fair value on a recurring basis. The adoption of FSP FAS 157-4 did not have an impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

 

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New Accounting Pronouncements

On December 30, 2008, the FASB issued FSP FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1), which requires enhanced annual disclosures about plan assets of an employer’s defined benefit pension or other postretirement plans. FSP FAS 132(R)-1 is effective for financial statements for fiscal years ending after December 15, 2009, with earlier application permitted. Upon initial application, the provisions of this FSP are not required for earlier periods that are presented for comparative purposes. The adoption of FSP FAS 132(R)-1 is not expected to have a material impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

On June 12, 2009, the FASB issued SFAS 167, Amendments to FASB Interpretation No. 46(R) (SFAS 167), which is a revision to FIN 46(R) and changes how a company determines when a variable interest entity (VIE) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. SFAS 167 requires a company to provide additional disclosures about its involvement with variable interest entities and what any significant change in risk exposure does to that involvement. A company will be required to disclose how its involvement with a VIE affects the company’s performance. SFAS 167 is effective for fiscal years beginning after November 15, 2009. Earlier application is prohibited. PGE is in the process of determining what impact, if any, that the adoption of SFAS 167 will have on its consolidated financial position, consolidated results of operation, or consolidated cash flows.

On June 29, 2009, the FASB issued SFAS 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles - a replacement of FASB Statement No. 162 (SFAS 168). The new statement modifies the U.S. generally accepted accounting principles (GAAP) hierarchy created by FASB Statement No. 162 by establishing only two levels of GAAP: authoritative and nonauthoritative. This is accomplished by authorizing the FASB Accounting Standards Codification (Codification) to become the single source of authoritative U.S. accounting and reporting standards, except for rules and interpretive releases of the SEC under authority of the federal securities laws, which are sources of authoritative GAAP for SEC registrants. SFAS 168 is effective for financial statements for interim and annual periods ending after September 15, 2009. All existing accounting standard documents are superseded and all other accounting literature not included in the Codification is considered nonauthoritative. The adoption of SFAS 168 is not expected to have a material impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

 

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NOTE 2: BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable is net of an allowance for uncollectible accounts of $5 million as of June 30, 2009 and $4 million as of December 31, 2008.

The following is the change in the allowance for uncollectible accounts (in millions):

 

     Six Months Ended June 30,  
     2009     2008  

Balance at beginning of period

   $ 4      $ 5   

Provision

     5        3   

Amounts written off, less recoveries

     (4     (4
                

Balance at end of period

   $ 5      $ 4   
                

Inventories

Inventories consist primarily of materials, supplies, and fuel. Materials and supplies inventories, used in operations, maintenance and capital activities, are recorded at average cost. Fuel inventories, which may include natural gas, oil, and coal used in the Company’s generating plants, are recorded at the lower of average cost or market.

Electric Utility Plant, Net

Electric utility plant, net consists of the following (in millions):

 

     June 30,
2009
    December 31,
2008
 

Electric utility plant

   $ 5,234      $ 5,066   

Construction work in progress

     531        284   
                

Total cost

     5,765        5,350   

Less: accumulated depreciation and amortization

     (2,103     (2,049
                

Electric utility plant, net

   $ 3,662      $ 3,301   
                

Accumulated depreciation and amortization in the table above includes amortization of intangible assets of $114 million and $109 million as of June 30, 2009 and December 31, 2008, respectively. Amortization expense related to intangible assets was $4 million for the three months ended June 30, 2009 and 2008, and $8 million and $7 million for the six months ended June 30, 2009 and 2008, respectively.

 

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Regulatory Assets and Liabilities

Regulatory assets and liabilities consist of the following (in millions):

 

     June 30, 2009    December 31, 2008
     Current    Noncurrent    Current    Noncurrent

Regulatory Assets:

           

Price risk management

   $ 228    $ 166    $ 194    $ 193

Pension and other postretirement plans

     -        231      -        232

Deferred income taxes

     -        85      -        88

Boardman power cost deferral

     -        36      -        34

Debt reacquisition costs

     -        27      -        28

Utility rate treatment of income taxes

     16      -        -        17

Other

     -        40      -        39
                           

Total regulatory assets

   $ 244    $ 585    $ 194    $ 631
                           

Regulatory liabilities:

           

Asset retirement removal costs

   $ -      $ 518    $ -      $ 494

Utility rate treatment of income taxes

     21      20      24      19

Trojan refund liability

     35      -        -        34

Power Cost Adjustment Mechanism

     10      -        19      -  

Asset retirement obligations

     -        28      -        26

Trojan ISFSI pollution control tax credits

     -        19      -        17

Other

     -        60      -        50
                           

Total regulatory liabilities

   $ 66    $ 645    $ 43    $ 640
                           

Included in Other regulatory liabilities in the preceding table are amounts related to PGE’s Decoupling Mechanism, which became effective on February 1, 2009, pursuant to approval by the Public Utility Commission of Oregon (OPUC). The impact of the mechanism is a reduction to Revenues of $2 million for the six months ended June 30, 2009.

Credit Facilities

PGE has the following unsecured revolving credit facilities:

 

   

A $370 million credit facility with a group of banks, of which $10 million is currently scheduled to terminate in July 2012 and $360 million in July 2013;

 

   

A $125 million credit facility with a group of banks, which is currently scheduled to terminate in December 2009; and

 

   

A $30 million credit facility with a Barclays Bank PLC, which is currently scheduled to terminate in June 2012.

Pursuant to the individual terms of the agreements, these facilities may be used for general corporate purposes and as backup for commercial paper borrowings. The $370 million and $30 million credit facilities permit borrowings and the issuance of standby letters of credit. The $125 million credit facility

 

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permits borrowings only. The credit facility agreements also contain customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreements, to 65% of total capitalization. As of June 30, 2009, PGE was in compliance with this covenant.

As of June 30, 2009, PGE had $201 million in letters of credit outstanding under the credit facilities, and had no borrowings or commercial paper outstanding. As of June 30, 2009, the aggregate amount of unused available credit under the credit facilities was $324 million.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days, limited to the unused amount of credit under the its credit facilities.

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt, including commercial paper, up to $550 million through February 6, 2010.

Long-term Debt

On April 16, 2009, PGE issued $300 million of 6.10% Series First Mortgage Bonds (the Bonds), which are due April 15, 2019. Interest is paid semi-annually at 6.10% per annum on April 15th and October 15th, beginning October 15, 2009. The Bonds are secured by a first mortgage lien on substantially all utility property, other than expressly excepted property, and may be redeemed at the Company’s option upon 30 days notice to holders, in whole or in part, at a redemption price equal to the greater of (i) 100% of the principal amount of the bonds to be redeemed or (ii) the present value of the remaining principal and interest payments due on the bonds discounted at a rate of treasuries plus 50 basis points.

On May 1, 2009, PGE purchased three series of its outstanding Pollution Control Bonds in the amount of $142 million. These instruments are backed by first mortgage bonds. Although these Pollution Control Bonds are currently owned by the Company, the first mortgage bonds that back them reduce the amount of bonds available for issuance under the Mortgage.

 

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Pension and Other Postretirement Benefits

The following table provides the components of net periodic benefit cost (benefit) for the three months ended June 30 (in millions):

 

     Defined Benefit
Pension Plan
    Other Postretirement
Benefits
    Non-Qualified
Benefit Plans
     2009     2008     2009    2008     2009    2008

Service cost

   $ 3      $ 3      $ -      $ 1      $ -      $ -  

Interest cost

     8        8        1      1        -        1

Expected return on

              

plan assets

     (11     (11     -        (1     -        -  

Amortization of prior service cost

     -          -          -        1        -        -  

Amortization of net gain

     -          -          1      -          -        -  
                                            

Net periodic

              

benefit cost

   $ -        $ -        $ 2    $ 2      $ -      $ 1
                                            

The following table provides the components of net periodic benefit cost (benefit) for the six months ended June 30 (in millions):

 

     Defined Benefit
Pension Plan
    Other Postretirement
Benefits
    Non-Qualified
Benefit Plans
     2009     2008     2009    2008     2009    2008

Service cost

   $ 6      $ 6      $ 1    $ 1      $ -      $ -  

Interest cost

     16        15        2      2        1      1

Expected return on

              

plan assets

     (22     (22     -        (1     -        -  

Amortization of prior service cost

     -          -          -        1        -        -  

Amortization of net gain

     -          -          1      -          -        -  
                                            

Net periodic benefit

              

cost (benefit)

   $ -        $ (1   $ 4    $ 3      $ 1    $ 1
                                            

PGE currently expects to contribute approximately $12 million to its defined benefit pension plan in 2010.

NOTE 3: FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of financial instruments, both assets and liabilities recognized and not recognized in PGE’s condensed consolidated balance sheet, for which it is practicable to estimate fair value is as follows as of June 30, 2009 and December 31, 2008:

 

   

The fair value of cash and cash equivalents and short-term debt approximate their carrying amounts due to the short-term nature of these balances;

 

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Derivative instruments are recorded at fair value and are based on published market indices as adjusted for other market factors such as location pricing differences or internally developed models;

 

   

Certain trust assets, consisting of money market funds and fixed income securities included in the Nuclear decommissioning trust and marketable securities included in the Non-qualified benefit plan trust, are recorded at fair value and are based on quoted market prices; and

 

   

The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. As of June 30, 2009, the estimated aggregate fair value of PGE’s long-term debt was $1,617 million, compared to its $1,594 million carrying amount. As of December 31, 2008, the estimated aggregate fair value of PGE’s long-term debt was $1,286 million, compared to its $1,306 million carrying amount.

A fair value hierarchy is used to prioritize the inputs to the valuation techniques used to measure fair value. These three broad levels and application to the Company are discussed below.

Level 1-Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

Level 2-Pricing inputs are other than quoted market prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and swaps.

Level 3-Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. At each balance sheet date, the Company performs an analysis of all instruments subject to fair value measurement and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

 

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The Company’s assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions):

 

     As of June 30, 2009
     Level 1    Level 2    Level 3    Total

Assets:

           

Nuclear decommissioning trust *:

           

Cash equivalents:

           

Cash

   $ 29    $ -      $ -      $ 29

US Treasury securities

     3      -        -        3

Debt securities:

           

Corporate debt securities

     -        7      -        7

Mortgage-backed securities

     -        5      -        5

Municipal securities

     -        2      -        2

Asset-backed securities

     -        1      -        1

Non-qualified benefit plan trust:

           

Equity securities

     20      -        -        20

Debt securities - mutual funds

     4      -        -        4

Assets from price risk management activities *

     -        26      2      28
                           
   $ 56    $ 41    $ 2    $ 99
                           

Liabilities - Liabilities from price risk management activities *

   $ -      $ 264    $ 158    $ 422
                           
     As of December 31, 2008
     Level 1    Level 2    Level 3    Total

Assets:

           

Nuclear decommissioning trust *:

           

Cash

   $ 27    $ -      $ -      $ 27

Debt securities:

           

Mortgaged-backed securities

        7      -        7

Corporate debt securities

     -        4      -        4

Municipal securities

     -        4      -        4

US Treasury securities

     -        2      -        2

US Agency securities

     -        2      -        2

Non-qualified benefit plan trust:

           

Equity securities

     23      -        -        23

Debt securities - mutual funds

     3      -        -        3

Assets from price risk management activities *

     -        33      6      39
                           
   $ 53    $ 52    $ 6    $ 111
                           

Liabilities - Liabilities from price risk management activities *

   $ -      $ 297    $ 129    $ 426
                           

* Activities are subject to regulation and, accordingly, certain gains and losses are deferred pursuant to SFAS 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71), and included in Regulatory assets or Regulatory liabilities as appropriate.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

 

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Nuclear decommissioning trust assets reflect the assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation and consist of money market funds and fixed income securities. Non-qualified benefit plan trust reflects the assets held in trust to cover the obligations of PGE’s non-qualified benefit plans and consist primarily of marketable securities. These assets also include investments recorded at cash surrender value, which are excluded from the table above as they are not measured at fair value. Assets and liabilities from price risk management activities represent derivative transactions entered into by PGE to manage its exposure to commodity price risk and minimize net power costs for service to the Company’s retail customers and may consist of forward, swap, and option contracts for electricity, natural gas, oil, and foreign currency, and futures contracts for natural gas and oil.

Changes in the fair value of assets and liabilities from price risk management activities classified as Level 3 in the fair value hierarchy were as follows (in millions):

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2009     2008     2009     2008  

Balance as of beginning of period

   $ (170   $ 39      $ (123   $ 1   

Net realized and unrealized gains (losses)

     17        115        (34     129   

Purchases and issuances, net

     (3     17        1        41   

Net transfers out of Level 3

     -          (1     -          (1
                                

Balance as of end of period

   $ (156   $ 170      $ (156   $ 170   
                                

Net realized and unrealized gains (losses) are recorded in Purchased power and fuel expense in the condensed consolidated statements of income and include $17 million and $131 million for the three months ended June 30, 2009 and 2008, respectively, and $(29) million and $169 million for the six months ended June 30, 2009 and 2008, respectively, of Level 3 net unrealized gains (losses) that have been fully offset by the effects of regulatory accounting.

NOTE 4: PRICE RISK MANAGEMENT

PGE participates in the wholesale marketplace in order to balance its supply of power, which consists of its own generating resources combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer its existing long-term wholesale contracts. Such activities include power purchases and sales resulting from economic dispatch decisions for its own generation. As a result of this ongoing business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk. PGE utilizes derivative instruments, which may include forward, swap, and option contracts for electricity, natural gas, oil, and foreign currency, and futures contracts for natural gas and oil, in its retail electric utility activities to manage its exposure to commodity price risk and foreign exchange rate risk, mitigate the effects of market fluctuations, and minimize net power costs for service to its retail customers. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. PGE does not engage in trading activities for non-retail purposes.

 

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As of June 30, 2009, net volume related to PGE’s Price risk management assets and liabilities resulting from its derivative activities, which are expected to deliver or settle at various dates through 2013, was as follows (in millions):

 

Type

   Volume

Commodity:

  

Electricity

     12      MWh

Natural gas

   122    Decatherms

Foreign exchange

     $6    Canadian

In connection with the adoption of SFAS 161, PGE reconsidered the presentation of its Price risk management assets and liabilities, which historically have been classified as current. For additional information, see Reclassifications in Note 1. As of June 30, 2009, PGE’s Price risk management assets and liabilities resulting from its derivative activities, offset by regulatory accounting, consist of the following (in millions):

 

     Asset Derivatives     Liability Derivatives
     Balance Sheet
Classification
   Fair
Value
    Balance Sheet
Classification
   Fair
Value

Derivatives not designated as hedging instruments:

          

Commodity contracts:

          

Electricity

   Current assets    $ 21      Current liabilities    $ 123

Natural gas

   Current assets      5      Current liabilities      131
                    

Total current derivative activity

        26           254
                    

Commodity contracts:

          

Electricity

   Noncurrent assets      2      Noncurrent liabilities      48

Natural gas

   Noncurrent assets      -        Noncurrent liabilities      120
                    

Total long-term derivative activity

        2        168
                    

Total derivatives not designated as hedging instruments

      $ 28         $ 422
                    

Total derivatives

      $ 28         $ 422
                    

* The noncurrent asset derivative balance of $2 million is included in Other noncurrent assets on the condensed consolidated balance sheet.

Changes in the fair value of derivative instruments prior to settlement that do not qualify for the normal purchases and normal sales exception, or for hedge accounting, are recorded on a net basis in Purchased power and fuel expense in the statement of income. For derivative instruments that are physically settled, sales are recorded in Revenues, with purchases, natural gas swaps and futures recorded in Purchased power and fuel expense. PGE records the non-physical settlement of electricity derivative instruments on a net basis in Purchased power and fuel expense.

 

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Net realized and unrealized gains (losses) on derivative transactions were recognized in the statement of income for the periods presented (in millions):

 

Derivatives not designated as
hedging instruments

  

Location of net gain (loss)
recognized in net income
on derivative activities

   Net gain (loss) recognized in
net income on derivative
activities *
 
     Three Months Ended
June 30, 2009
    Six Months Ended
June 30, 2009
 

Commodity contracts:

       

Electricity

   Purchased power and fuel expense    $ 12      $ (69

Natural Gas

   Purchased power and fuel expense      5        (83

Oil

   Purchased power and fuel expense      (1     (1

 

* Unrealized gains and losses and certain realized gains and losses are offset by regulatory accounting. Of the net gain (loss) recognized in net income for the three and six month periods ended June 30, 2009, $4 and ($167), respectively, has been offset.

The following table indicates the year in which the net unrealized loss recorded as of June 30, 2009 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

 

     2009    2010    2011    2012    2013    Total

Commodity contracts:

                 

Electricity

   $ 33    $ 100    $ 12    $ 3    $ -      $ 148

Natural gas

     97      67      33      35      14      246
                                         

Net unrealized loss

   $ 130    $ 167    $ 45    $ 38    $ 14    $ 394
                                         

The Company’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and Standard and Poor’s (S&P). Should Moody’s and/or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral based on total portfolio positions with each counterparty, which can be in the form of cash or letters of credit.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of June 30, 2009 was $336 million. As of June 30, 2009, the Company had $190 million in collateral posted associated with such liability positions, which consisted of $8 million in cash, classified as Margin deposits on the condensed consolidated balance sheet, and $182 million in letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered by a dual agency downgrade to below investment grade at June 30, 2009, the additional cash collateral requirement would have been $304 million.

At June 30, 2009, contracts with three different counterparties represent approximately 75% and 43% of PGE’s Price risk management assets and liabilities, respectively. One counterparty represents 75% of Price risk management assets, with two different counterparties representing 19% and 24% of Price risk management liabilities. No other counterparty represents more than 10% of the Price risk management assets and liabilities.

 

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See Note 3 for additional information concerning the determination of fair value for the Company’s Price risk management assets and liabilities.

NOTE 5: EARNINGS PER SHARE

Components of basic and diluted earnings per share were as follows:

 

     Three Months Ended
June 30,
   Six Months Ended
June 30,
     2009    2008    2009    2008

Numerator (in millions):

           

Net income atributable to Portland General Electric

           

Company common shareholders

   $ 24    $ 39    $ 55    $ 67
                           

Denominator (in thousands):

           

Weighted-average common shares outstanding - basic

     75,131      62,532      70,352      62,531

Dilutive effect of unvested restricted stock units and employee stock purchase plan shares

     104      56      95      49
                           

Weighted-average common shares outstanding - diluted

     75,235      62,588      70,447      62,580
                           

Earnings per share - basic and diluted

   $ 0.31    $ 0.63    $ 0.77    $ 1.07
                           

Unvested performance stock units and related dividend equivalent rights are not included in the computation of dilutive securities because vesting of these instruments is dependent upon three-year performance periods.

Basic and diluted earnings per share amounts are calculated based on actual amounts. Accordingly, basic and diluted earnings per share amounts presented in the table above and on the condensed consolidated statements of income may not necessarily recalculate based on the rounded amounts presented for net income and weighted-average shares outstanding.

 

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NOTE 6: SHAREHOLDERS’ EQUITY

On May 13, 2009, the shareholders approved an increase in the number of common stock authorized to 160,000,000 shares.

The activity in shareholders’ equity during the six month periods ended June 30, 2009 and 2008 was as follows (dollars in millions):

 

     Portland General Electric Company
Shareholders’ Equity
            
     Common Stock    Accumulated
Other
Comprehensive
    Retained           Noncontrolling
Interests’
 
     Shares    Amount    Loss     Earnings           Equity  

Balances as of January 1, 2009

   62,575,257    $ 659    $ (5   $ 700           $ -     

Issuance of common stock, net of issuance costs of $6 *

   12,477,500      170      -          -               -     

Vesting of restricted and performance stock units

   81,555      -        -          -               -     

Issuance of shares pursuant to employee stock purchase plan

   14,596      -        -          -               -     

Stock based compensation

   -        1      -          -               -     

Noncontrolling interest capital contributions

   -        -        -          -               7   

Dividends declared

   -        -        -          (38          -     

Net income (loss)

   -        -        -          55             (5
                                         

Balances as of June 30, 2009

   75,148,908    $ 830    $ (5   $ 717           $ 2   
                                         
 

Balances as of January 1, 2008

   62,529,787    $ 646    $ (4   $ 674           $ -     

Vesting of restricted stock units

   7,803      -        -          -               -     

Issuance of shares pursuant to employee stock purchase plan

   11,152      -        -          -               -     

Stock based compensation

   -        2      -          -               -     

Dividends declared

   -        -        -          (30          -     

Net income

   -        -        -          67             -     
                                         

Balances as of June 30, 2008

   62,548,742    $ 648    $ (4   $ 711           $ -     
                                         

* The issuance costs are included in rates over 10 years, including a return on the unamortized balance, beginning January 1, 2009.

 

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NOTE 7: COMPREHENSIVE INCOME

Comprehensive income is as follows (in millions):

 

     Three Months Ended
June 30,
    Six Months Ended
June 30,
 
     2009     2008     2009     2008  

Net income

   $ 26      $ 39      $ 50      $ 67   

Pension and other postretirement plans’ funded position, net of taxes of $(1)

     1        1        1        1   

Reclassification of defined benefit pension plan and other benefits to a regulatory asset, net of taxes of $1

     (1     (1     (1     (1
                                

Comprehensive income

     26        39        50        67   

Less: comprehensive income (loss) attributable to noncontrolling interests

     2        -          (5     -     
                                

Comprehensive income attributable to Portland General Electric Company

   $ 24      $ 39      $ 55      $ 67   
                                

NOTE 8: CONTINGENCIES

Legal Matters

Trojan Investment Recovery

Background. In 1993, PGE closed the Trojan Nuclear Plant as part of the Company’s least cost planning process. PGE sought full recovery of, and a rate of return on, its Trojan plant costs in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs.

Court Proceedings on OPUC Authority to Grant Recovery of Return on Trojan Investment. Numerous challenges, appeals and reviews were subsequently filed in the Marion County Circuit Court (Circuit Court), the Oregon Court of Appeals, and the Oregon Supreme Court on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. The primary plaintiffs in the litigation were the Citizens’ Utility Board (CUB) and the Utility Reform Project (URP). The Oregon Court of Appeals issued an opinion in 1998, which upheld the OPUC’s authorization of PGE’s recovery of the Trojan investment, but stated that the OPUC did not have the authority to allow PGE to recover a return on the Trojan investment and remanded the case to the OPUC.

Settlement of Court Proceedings on OPUC Authority. In 2000, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE’s recovery of, and return on, its investment in the Trojan plant. The URP did not participate in the settlement, which was approved by the OPUC in September 2000. The settlement allowed PGE to remove from its balance sheet the remaining before-tax investment in Trojan of approximately $180 million at September 30, 2000, along with several largely offsetting regulatory liabilities.

 

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Challenge to Settlement of Court Proceeding. The URP filed a complaint with the OPUC challenging the settlement agreements and the OPUC’s September 2000 order. In March 2002, the OPUC issued an order (2002 Order) denying all of the URP’s challenges, and approving the accounting and ratemaking elements of the 2000 settlement. On October 10, 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the 2002 Order to the OPUC for reconsideration.

Remand of 2002 Order. As a result of the Oregon Court of Appeals remand of the 2002 Order, the OPUC considered whether the OPUC has authority to engage in retroactive ratemaking and what prices would have been if, in 1995, the OPUC had interpreted the law to prohibit a return on the Trojan investment. On September 30, 2008, the OPUC issued an order that requires PGE to refund $15.4 million, plus interest at 9.6% from September 30, 2000, to customers who received service from PGE during the period October 1, 2000 to September 30, 2001. The order also provides that the total refund amount will accrue interest at 9.6% from October 1, 2008 until all refunds are issued to customers. The URP and the plaintiffs in the class actions described below have separately appealed the order to the Oregon Court of Appeals.

The $15.4 million amount, plus accrued interest, resulted in a total refund of $33.1 million as of September 30, 2008. As a result of the September 30, 2008 order, PGE recorded, as a regulatory liability, the total refund due to customers of $33.1 million, which reduced 2008 revenues.

Class Actions. In a separate legal proceeding, two class action suits were filed in Circuit Court against PGE on January 17, 2003 on behalf of two classes of electric service customers (the Class Action Plaintiffs). The cases seek to represent PGE customers during the period from April 1, 1995 to October 1, 2000. The suits seek damages of $260 million plus interest as a result of the inclusion of a return on investment of Trojan in the prices PGE charged its customers.

On December 14, 2004, the judge granted the Class Action Plaintiffs’ motion for Class Certification and Partial Summary Judgment and denied PGE’s motion for Summary Judgment. On March 3, 2005 and March 29, 2005, PGE filed two Petitions for an Alternative Writ of Mandamus with the Oregon Supreme Court, asking the Court to take jurisdiction and command the trial judge to dismiss the complaints or to show cause why they should not be dismissed, and seeking to overturn the Class Certification.

On August 31, 2006, the Oregon Supreme Court issued a ruling on PGE’s Petitions for Alternative Writ of Mandamus, abating the class action proceedings until the OPUC responded with respect to the 2002 Order (described above). The Oregon Supreme Court concluded that the OPUC has primary jurisdiction to determine what, if any, remedy it can offer to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment PGE collected in prices for the period from April 1, 1995 through October 1, 2000. The Oregon Supreme Court further stated that if the OPUC determined that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The Oregon Supreme Court further stated that, if the OPUC determined that it cannot provide a remedy, the court system may have a role to play. The Oregon Supreme Court also ruled that the plaintiffs retain the right to return to the Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings.

On October 5, 2006, the Circuit Court issued an Order of Abatement in response to the ruling of the Oregon Supreme Court, abating the class actions, but inviting motions to lift the abatement after one year. On October 17, 2007, the plaintiffs filed a motion to lift the abatement. On February 10, 2009, the Circuit Court judge denied the plaintiffs’ motion to lift the abatement.

 

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Management cannot predict the ultimate outcome of the above matters. However, it believes that these matters will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on the results of operation and cash flows for a future reporting period.

Regulatory Matters

Pacific Northwest Refund Proceeding

On July 25, 2001, the FERC called for a preliminary evidentiary hearing to explore whether there may have been unjust and unreasonable charges for spot market sales of electricity in the Pacific Northwest from December 25, 2000 through June 20, 2001 (Pacific Northwest Refund proceeding). During that period, PGE both sold and purchased electricity in the Pacific Northwest. In September 2001, upon completion of hearings, the appointed administrative law judge issued a recommended order that the claims for refunds be dismissed. In June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. Parties appealed various aspects of the FERC order to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit).

On August 24, 2007, the Ninth Circuit issued its decision, 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 FERC’s ultimate decision to deny refunds. Two requests for rehearing were filed with the court. On April 9, 2009, the Ninth Circuit denied the requests for rehearing. On April 16, 2009, the Ninth Circuit issued a mandate giving immediate effect to its August 24, 2007 order remanding the case to the FERC.

The settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, et seq., approved by the FERC on May 17, 2007, resolves all claims as between PGE and the California parties named in the settlement as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 21, 2001, but does not settle potential claims from other market participants relating to transactions in the Pacific Northwest.

Management cannot predict the outcome of the Pacific Northwest Refund proceeding, or whether the FERC will order refunds in this proceeding, and if so, how such refunds would be calculated. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of operation and cash flows in future reporting periods.

Complaint and Application for Deferral – Income Taxes

On October 5, 2005, the URP and another party (together, the Complainants) filed a Complaint and an Application for Deferred Accounting with the OPUC alleging that, since the September 2, 2005 effective date of Oregon Senate Bill 408 (SB 408), PGE’s rates were not just and reasonable and were in violation of SB 408 because they contained approximately $92.6 million in annual charges for state and federal income taxes that are not being paid to any governmental entity. The Complaint and Application for Deferred Accounting requested that the OPUC order the creation of a deferred account for all amounts charged to customers since September 2, 2005 for state and federal income taxes, less amounts actually paid by or on behalf of PGE to the federal and state governments for income taxes.

 

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On August 14, 2007, the OPUC issued an order granting the Application for Deferred Accounting for the period from October 5, 2005 through December 31, 2005 (Deferral Period). The OPUC’s order also dismissed the Complaint, without prejudice, on grounds that it was superfluous to the Complainants’ request for deferred accounting. The order required that PGE calculate the amounts applicable to the Deferral Period, along with calculations of PGE’s earnings and the effect of the deferral on the Company’s return on equity. The order also provided that the OPUC would review PGE’s earnings at the time it considers amortization of the deferral. PGE understands that the OPUC will consider the potential impact of the deferral on PGE’s earnings over a relevant 12-month period, which will include the Deferral Period.

On December 1, 2007, PGE filed its report as required by the OPUC. In the report, PGE determined that (i) the amount of any deferral would be between zero and $26.6 million; (ii) a relevant 12-month period would be the 12-month period ended September 30, 2006; and (iii) PGE’s earnings over such period would preclude any refund. The OPUC has indicated that it will determine whether any necessary rate adjustment should be made to amortize the deferral granted in its August 14, 2007 order.

On October 15, 2007, PGE filed a petition for judicial review with the Oregon Court of Appeals, seeking review of the OPUC’s August 14, 2007 order. The Court of Appeals has granted PGE’s request to stay the proceedings pending the OPUC decision on amortization of the deferral.

Management cannot predict the ultimate outcome of this matter. However, management believes this matter will not have a material adverse effect on PGE’s financial condition, results of operation or cash flows.

FERC Investigation

In May 2008, PGE received a notice of a preliminary non-public investigation from the FERC Division of Investigations concerning PGE’s compliance with its Open Access Transmission Tariff. The investigation involves certain issues identified during an audit by FERC staff.

Management cannot predict the final outcome of the investigation or what actions, if any, the FERC will take or require the Company to take. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of operation and cash flows in future reporting periods.

Environmental Matters

Portland Harbor

A 1997 investigation by the U.S. Environmental Protection Agency (EPA) of a segment of the Willamette River known as the Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included this segment on the federal National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site and listed sixty-nine Potentially Responsible Parties (PRPs). PGE was included among the PRPs as it has historically owned or operated property near the river.

The Portland Harbor site is currently undergoing a remedial investigation and feasibility study (RI/FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs, not including PGE. In the AOC, the EPA determined that the RI/FS would focus on a segment of the river approximately 5.7 miles in length.

 

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On January 22, 2008, PGE received a Section 104(e) Information Request from the EPA requiring the Company to provide information concerning its properties in or near the segment of the river being examined in the RI/FS, as well as several miles beyond that 5.7 mile segment. PGE has requested, and the EPA granted, an extension until August 2009 for the Company to respond. During 2009, the EPA sent General Notice Letters to 15 additional PRPs.

The EPA will determine the boundaries of the site at the conclusion of the RI/FS in a Record of Decision, now expected in 2012, in which it will document its findings and select a preferred cleanup alternative.

Sufficient information is currently not available to determine the total cost of any required investigation or remediation of the Portland Harbor site or the liability of PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. Management believes that the outcome will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of operation and cash flows in future reporting periods.

The OPUC issued an order authorizing the deferral, for later ratemaking treatment, of incremental investigation and remediation costs related to the Portland Harbor site incurred during the twelve month period ended March 31, 2009. As of June 30, 2009, the Company had not deferred any costs related to Portland Harbor. The OPUC is considering PGE’s request for a second twelve month deferral period. Ratemaking treatment of any costs which may be deferred would be determined in a future regulatory proceeding that includes both a prudency review with respect to the costs incurred and a regulated earnings test. Accordingly, there can be no assurance that recovery of such costs would be granted.

Harbor Oil

Harbor Oil, Inc. (Harbor Oil), located in north Portland, was utilized by PGE to process used oil from the Company’s power plants and electrical distribution system from at least 1990 until 2003. Harbor Oil continues to be utilized by other entities for the processing of used oil and other lubricants.

In 1974 and 1979, major oil spills occurred at the Harbor Oil site. Elevated levels of contaminants, including metals, pesticides, and polychlorinated biphenyls, have been detected at the site. On September 29, 2003, the Harbor Oil facility was included on the federal National Priority List as a federal Superfund site.

PGE received a Special Notice Letter for RI/FS from the EPA, dated June 27, 2005, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site. On May 31, 2007, an Administrative Order on Consent was signed by the EPA and six other parties, including PGE, to implement an RI/FS at the Harbor Oil site. The EPA has approved an RI/FS work plan. On-site sampling commenced in 2008 and has yet to be completed.

Sufficient information is currently not available to determine the total cost of investigation and remediation of the Harbor Oil site or the liability of the PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. Management believes that the outcome of this matter will not have a material adverse impact on the financial condition of the Company, but may have a material adverse impact on PGE’s results of operation and cash flows in future reporting periods.

 

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The OPUC issued an order authorizing the deferral, for later ratemaking treatment, of incremental costs related to RI/FS work and any resulting remediation costs incurred in relation to the Harbor Oil site incurred during the twelve month period ended March 31, 2009. As of June 30, 2009, the Company had not deferred any costs related to Harbor Oil. The OPUC is considering PGE’s request for a second twelve month deferral period. Ratemaking treatment of any costs which may be deferred would be determined in a future regulatory proceeding that includes both a prudency review with respect to the costs incurred and a regulated earnings test. Accordingly, there can be no assurance that recovery of such costs would be granted.

Other Matters

PGE is subject to other regulatory, environmental, and legal proceedings that arise from time to time in the ordinary course of its business, which may result in adverse judgments against the Company. Although management currently believes that resolution of such matters will not have a material adverse effect on its financial position, results of operation, or cash flows, these matters are subject to inherent uncertainties and management’s view of these matters may change in the future.

NOTE 9: GUARANTEES

PGE enters into financial agreements and power purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on PGE’s historical experience and the evaluation of the specific indemnities. As of June 30, 2009, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnifications. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnifications.

NOTE 10: VARIABLE INTEREST ENTITIES

Pursuant to FIN 46(R), Variable Interest Entities [FIN46(R)], PGE has determined it is the primary beneficiary of two VIEs. Both entities are limited liability companies (LLCs) and were formed for the sole purpose of designing, developing, constructing, owning, maintaining, operating and financing photovoltaic solar power facilities located on real property owned by third parties and selling the energy generated by the facilities. Photovoltaic solar power facilities give rise to certain tax benefits, which flow through to the members of the LLCs. PGE is the Managing Member in each of the LLCs, representing less than a 1% equity interest in each entity, and a financial institution is the Investor Member, representing more than a 99% equity interest in each entity. As the primary beneficiary, PGE consolidates the VIEs pursuant to FIN 46(R).

Determining whether PGE is the primary beneficiary of a VIE is complex, subjective and requires the use of judgments and assumptions. Significant judgments and assumptions made by PGE in determining that it is the primary beneficiary of these LLCs include the following: (1) based on projections prepared in accordance with the operating agreement, PGE will absorb a majority of the expected losses of the LLCs; (2) PGE expects to own 100% of the LLCs shortly after five years have elapsed, at which time the facilities will have approximately 75% of their estimated useful life remaining; and (3) PGE has the expertise to own and operate electric generating facilities and is authorized to operate the LLCs pursuant to the operating agreements.

 

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During 2009, impairment losses of $5 million, which are classified in Depreciation and amortization expense, were recognized on the photovoltaic solar power facilities held by the LLCs. Based on PGE’s intent to ultimately acquire 100% of the LLCs and the fact that the capitalized cost of the photovoltaic solar power facilities exceeded the undiscounted cash flows of the facilities over their estimated useful lives, an impairment analysis was performed at the time each facility was completed. Immediately following the completion of the photovoltaic solar power facilities, impairment losses were recognized on these assets. The impairment losses were equal to the excess of the carrying amount over the estimated fair value of these photovoltaic solar power facilities. Estimated fair value was determined using the discounted cash flow method, with the new cost basis of these photovoltaic solar power facilities amortized over their remaining estimated useful lives.

As noted above, PGE has consolidated the LLCs pursuant to FIN 46(R) even though it has less than a 1% ownership interest in the LLCs. The participating members are allocated their proportionate share of the LLCs’ net losses based on the respective members’ ownership percent. Accordingly, the majority of the impairment losses are attributable to the “noncontrolling interests” through the Net losses attributable to noncontrolling interests in PGE’s condensed consolidated statement of income for the six months ended June 30, 2009.

 

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

Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements relate to expectations, beliefs, plans, objectives for future operations, assumptions, business prospects, the outcome of litigation and regulatory proceedings, future capital expenditures, market conditions, future events or performance and other matters. Words or phrases such as “anticipates,” “believes,” “should,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” or similar expressions are intended to identify such forward-looking statements.

Forward-looking statements are not guarantees of future performance and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed. PGE’s expectations, beliefs and projections are expressed in good faith and are believed by PGE to have a reasonable basis including, but not limited to, management’s examination of historical operating trends, data contained in records and other data available from third parties, but there can be no assurance that PGE’s expectations, beliefs or projections will be achieved or accomplished.

In addition to any assumptions and other factors and matters referred to specifically in connection with such forward-looking statements, factors that could cause actual results or outcomes for PGE to differ materially from those discussed in forward-looking statements include:

 

   

governmental policies and regulatory audits, investigations, and actions, including those of the FERC and OPUC with respect to allowed rates of return, financings, electricity pricing and price structures, acquisition and disposal of assets and facilities, operation and construction of plant facilities, transmission of electricity, recovery of power costs and capital investments, and current or prospective wholesale and retail competition;

 

   

the outcome of legal and regulatory proceedings and issues including, but not limited to, the proceedings related to the Trojan Investment Recovery, the Pacific Northwest Refund proceeding, the Portland Harbor investigation, and other matters described in Note 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements;

 

   

the continuing effects of the economic downturn in the state of Oregon, the United States and other parts of the world, including reductions in demand for electricity, sale of excess energy into a declining wholesale market, impaired financial soundness of vendors and service providers and elevated levels of uncollectible customer accounts;

 

   

capital market conditions, including the recent credit crisis, interest rate volatility, reductions in demand for investment-grade commercial paper and the availability and cost of capital, as well as changes in PGE’s credit ratings, which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction costs, and the repayments of maturing debt;

 

   

unseasonable or extreme weather and other natural phenomena, which in addition to affecting PGE’s customers’ demand for power, could significantly affect PGE’s ability and cost to procure adequate supplies of fuel or power to serve its customers, and could increase PGE’s costs to maintain its generating facilities and transmission and distribution system;

 

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operational factors affecting PGE’s power generation facilities, including forced outages, hydro conditions, wind conditions, and disruption of fuel supply, which may cause the Company to incur replacement power costs or repair costs;

 

   

wholesale energy prices and their impact on the availability and price of wholesale power in the western United States;

 

   

declines in wholesale power and natural gas prices, which would require the Company to issue additional letters of credit or post additional cash as collateral to counterparties pursuant to existing purchased power and natural gas agreements;

 

   

residential, commercial, and industrial growth and demographic patterns in PGE’s service territory;

 

   

future laws, regulations, and proceedings that could increase the Company’s costs or affect the operations of the Company’s thermal generating plants by imposing requirements for additional pollution control equipment or significant emissions fees or taxes, particularly with respect to coal-fired generation facilities, in order to mitigate carbon dioxide, mercury, and other gas emissions;

 

   

the effectiveness of PGE’s risk management policies and procedures and the creditworthiness of customers and counterparties;

 

   

the failure to complete capital projects on schedule and within budget;

 

   

the effects of Oregon law related to utility rate treatment of income taxes, which may result in earnings volatility and adversely affect PGE’s results of operation;

 

   

the outcome of efforts to relicense the Company’s hydroelectric projects, as required by the FERC;

 

   

declines in the market prices of equity securities and increased funding requirements for defined benefit pension plans and other benefit plans;

 

   

changes in, and compliance with, environmental and endangered species laws and policies;

 

   

the effects of climate change, including changes in the environment that may affect energy costs or consumption, increase the Company’s costs, or adversely affect its operations;

 

   

new federal, state, and local laws that could have adverse effects on operating results;

 

   

employee workforce factors, including aging, potential strikes, work stoppages, and transitions in senior management;

 

   

general political, economic, and financial market conditions;

 

   

natural disasters and other natural risks, such as earthquake, flood, drought, lightning, wind, and fire;

 

   

acts of war or terrorism; and

 

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financial or regulatory accounting principles or policies imposed by governing bodies.

Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, PGE undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

Overview

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report as well as the consolidated financial statements and disclosures in its Annual Report on Form 10-K for the year ended December 31, 2008, and other periodic and current reports filed with the SEC.

Capital and Financing - PGE has undertaken projects that have required and will continue to require significant capital spending in 2009 and 2010, and has near term debt maturities that will require capital resources as follows:

 

   

In 2009 and 2010, the Company expects to spend $720 million and $521 million, respectively, for capital projects. The majority of these amounts relate to Biglow Canyon Phases II and III, the smart meter project, and ongoing capital expenditures;

 

   

In May 2009, the Company purchased $142 million of Pollution Control Bonds; and

 

   

In 2010, $186 million of the Company’s long-term debt matures.

To fund these projects and debt maturities, the Company has completed the following transactions:

 

   

In January 2009, the Company issued $130 million of First Mortgage Bonds;

 

   

In March 2009, PGE issued 12,477,500 shares of common stock for net proceeds of $170 million. The proceeds were used to substantially repay outstanding short-term debt, with the balance to fund capital expenditures and general corporate purposes; and

 

   

In April 2009, the Company issued $300 million of First Mortgage Bonds in a public offering, in part to purchase the $142 million of its Pollution Control Bonds for which the interest rate and interest period expired May 1, 2009.

In addition, PGE expects cash provided by operations to be approximately $376 million for 2009 and the Company anticipates issuing a total of approximately $375 million of additional debt through 2010, a portion of which will be used to replace $186 million of long-term debt that matures in 2010.

Liquidity - PGE maintains liquidity through revolving credit facilities, with the ability to issue letters of credit and access to the commercial paper market. As of June 30, 2009, the unused available credit under the credit facilities was $324 million, with $296 million available as of July 31, 2009.

Power and natural gas prices have been at considerably lower levels during the first half of 2009 compared to the first half of 2008, which has required the Company to post collateral with counterparties in the form of cash or letters of credit in connection with its price risk management activities. These cash

 

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deposits, which are classified as Margin deposits on PGE’s condensed consolidated balance sheet, are based on contract terms and commodity prices and can vary from period to period. As of June 30, 2009, PGE had posted a total of $309 million of collateral with these counterparties. Provided market prices remain unchanged from June 30, 2009, the Company anticipates that approximately 32% of the current collateral deposits would no longer be required by the end of 2009 as the related contracts are settled, and another 52% are expected to roll off by the end of 2010. The Company has an additional $19 million of letters of credit outstanding under its credit facilities that are not related to price risk management activities.

Management believes that, as of June 30, 2009, the availability of its credit facilities, the expected ability to issue long-term debt and equity securities, and cash generated from operations will provide sufficient liquidity to meet the Company’s anticipated capital and operating requirements for the next 12 months.

Customers - During the six months ended June 30, 2009, PGE served an average of 814,654 retail customers compared to 809,301 during the six months ended June 30, 2008, an increase of 0.7%. Despite this customer growth, retail energy deliveries decreased 5.2% in the first half of 2009 relative to 2008, with residential decreasing 3% and industrial and commercial, including direct access customers, decreasing 6.7%. These decreases were driven by the continued slow-down in Oregon’s economy. Milder weather in the first half of 2009 relative to the first half of 2008 also contributed to the decline in demand. PGE expects retail energy deliveries to be approximately 2.5% below 2008 levels for the remainder of 2009.

As reflected in the table below, seasonally adjusted unemployment rates for the United States, the state of Oregon, and the Portland/Salem metropolitan area for the first two quarters of 2009 have been higher than for the comparable periods in 2008, and the seasonally adjusted unemployment rates for the state of Oregon and the Portland/Salem metropolitan area have been higher than the national average. The Portland/Salem metropolitan area comprises the majority of the Company’s service territory.

 

     United
States
    Oregon     Portland/
Salem
 
2009       

1st quarter average

   8.1   10.8   9.9

2nd quarter average

   9.3      12.1      11.9   
                  

Avg for year-to-date

   8.7      11.4      10.9   
                  
2008       

1st quarter average

   4.9   5.4   5.1

2nd quarter average

   5.3      5.7      5.4   
                  

Avg for year-to-date

   5.1      5.5      5.2   
                  

PGE utilizes sales of excess energy capacity in the wholesale market to optimize its power supply portfolio and to obtain reasonably priced power for its customers. Low natural gas market prices and overall weak electricity demand, a result of the current recession, have kept wholesale prices depressed in 2009. These factors contribute to the variability in PGE’s wholesale revenues. The revenue generated from this activity has decreased substantially in 2009 compared to 2008.

 

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Power Supply - PGE utilizes its own generating resources and wholesale market purchases to meet the energy and capacity needs of its customers. The Company’s generating plants provided approximately 48% of its retail load requirement during the first half of 2009, compared to 58% in the first half of 2008. The decrease was primarily related to extended maintenance outages (discussed below). Overall plant availability was approximately 84% during the first half of 2009, compared to 85% during the first half of 2008. Generation from PGE’s hydroelectric plants provided approximately 11% of the Company’s retail load requirement during the first half of both 2009 and 2008. Current forecasts indicate below normal regional hydro conditions for 2009.

PGE has a 20% ownership interest in Units 3 and 4 of the Colstrip plant, located in southeastern Montana, with each of the units providing approximately 6% (148 MW) of the Company’s total generating capability. During the scheduled 2009 maintenance outage of Unit 4, which began on March 28, two turbine rotors were found to be damaged, with both sent to the manufacturer for repair. It is currently estimated that such repairs will extend the outage from late-May until mid-November 2009. PGE’s incremental replacement power costs are estimated to approximate $11 million, with $1 million incurred in the second quarter of 2009. The Company’s share of repair costs is currently estimated at approximately $2 million.

In addition, the scheduled 2009 maintenance outage at PGE’s Boardman coal plant was extended due to generator rotor issues. Initially expected to resume operation in mid-June, the plant is expected to return to service by mid-August. Incremental replacement power costs related to this plant’s extended outage are estimated to be approximately $5 million. The Company’s repair costs are not expected to be material.

During the second quarter of 2009, the first wind turbines erected for Biglow Canyon Phase II began generating electricity and supplying power on the Pacific Northwest’s electricity grid. As of June 30, 2009, 15 wind turbines had been placed in service, with the remaining 50 wind turbines scheduled for completion by the end of summer 2009. This major capital investment, an important step in helping PGE meet Oregon’s Renewable Energy Standard (RES), continues to move forward on time and on budget. Information regarding cost recovery of Biglow Canyon Phase II is included in “Renewable Resources” below. For further information regarding estimated future capital expenditures, see “Capital Requirements” in “Liquidity and Capital Resources” in this Item 2.

Legal, Regulatory and Environmental Matters - In June 2009, the Oregon Environmental Quality Commission (OEQC) adopted a rule that would require the installation of emission controls at Boardman under a phased-in approach. For further discussion of this matter, see Boardman emissions controls, in “Capital Requirements” under “Liquidity and Capital Resources” in this Item 2.

In June 2008, PGE received a request for information from the EPA under section 114 of the Clean Air Act (CAA), requesting a broad range of information regarding the Boardman coal plant to determine whether the plant is in compliance with the Oregon State Implementation Plan, federal New Source Performance Standards and other CAA requirements. On March 20, 2009, the Company received a follow up request for information relating to the generation, heat input, and emissions of the plant. The Company has responded to both requests. The EPA has not informed the Company of any violations or possible violations of the CAA with respect to the Boardman plant and the Company is not aware of any such violations. As a result, the Company cannot predict the outcome of this matter.

PGE is a party to other proceedings whose ultimate outcome could have a material impact on the results of operations and cash flows in future reporting periods. These include matters related to:

 

   

Recovery of the Company’s investment in its closed Trojan plant;

   

Claims for refunds related to wholesale energy sales in the Pacific Northwest during 2000 - 2001;

   

An audit and subsequent investigation by the FERC related to the Company’s compliance with its Open Access Transmission Tariff; and

   

Investigation of environmental matters at the Portland Harbor site.

For further information regarding the above and other matters, see Note 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements.

 

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Pursuant to an order issued by the OPUC in September 2008, related to litigation involving the closed Trojan nuclear plant, PGE plans to issue refund checks to certain customers totaling $33.1 million, plus accrued interest ($2.5 million as of June 30, 2009), beginning in October 2009. Such refunds are expected to be completed by the end of 2009.

Recent and pending rate actions include, but are not limited to, the following:

 

   

Boardman Deferral Amortization - In October 2007, PGE filed a request with the OPUC to amortize the deferral of $26.4 million of replacement power costs, plus accrued interest ($9.2 million as of June 30, 2009), associated with the forced outage of Boardman from November 18, 2005 through February 5, 2006. In its filing, PGE proposed that the amortization be offset with certain credits due to customers, with no price impact anticipated. PGE’s request is subject to a regulatory proceeding that provides for both a prudency review with respect to the outage and to a regulated earnings test. A decision from the OPUC is pending.

   

Utility Rate Treatment of Income Taxes (SB 408) - On April 10, 2009, the OPUC issued its order on the 2007 reporting year authorizing PGE to collect from customers $14.7 million plus accrued interest. In accordance with the OPUC rules, collections from customers began June 1, 2009. PGE is expected to file its report for the 2008 reporting year by October 15, 2009, and has estimated and recorded a refund due to customers in the amount of $10 million. As of June 30, 2009, the Company has accrued a refund due to customers in the amount of $9 million related to 2009.

   

Power Costs - Under PGE’s Annual Power Cost Update Tariff, the Company’s updated forecast of 2010 power costs submitted to the OPUC in July 2009 reflects an approximate 3% decrease in customer prices. Such forecast will be finalized in November based upon a final forecast, with new prices, as approved by the OPUC, becoming effective January 1, 2010.

   

Renewable Resources - On April 1, 2009, the Company submitted to the OPUC its initial filing under the renewable adjustment clause mechanism. The filing includes three renewable projects - Biglow Canyon Phase II and two solar projects. The filing requests approximately $41 million in revenue requirements, or a 2.4% increase in prices, consisting of approximately $6 million to be deferred in 2009 and a $35 million increase in the Company’s 2010 revenue requirement. These amounts will be partially offset by related power cost savings, currently estimated at about $17 million for 2010 and included in the Company’s Annual Power Cost Update Tariff (described above). The related cost and benefit amounts to be included in rates will be updated by December 1, 2009, with new prices to become effective on January 1, 2010.

   

Selective Water Withdrawal System - Under a stipulation in PGE’s most recent general rate case proceeding, the OPUC provided for a process to recover the cost of the Company’s investment in the Selective Water Withdrawal System at the Pelton/Round Butte generating plant. On April 14, 2009, the Company filed a motion with the OPUC requesting that the procedural schedule be suspended as a result of a delay in construction. The procedural schedule has yet to be reestablished. Completion of the project, which was expected in the second quarter of 2009, is now expected to occur during the first quarter of 2010. PGE’s initial filing in this matter requested an annual revenue increase of $12.9 million related to this project.

   

Decoupling Mechanism - Pursuant to authorization contained in the final order in PGE’s most recent general rate case, the Company filed with the OPUC on January 30, 2009 an application to defer, for later ratemaking treatment, potential revenues associated with a new decoupling

 

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mechanism. One component of the mechanism, which has been implemented under a new two-year tariff, is intended to allow recovery of reduced earnings resulting from a reduction in sales of electricity attributable to energy efficiency and conservation efforts made by residential and small commercial customers. This component allows PGE to defer for future collection the impact of reductions in use per customer for these customer classes. However, if use per customer increases, the impact is deferred for future refund. During 2009, the Company recorded a refund due to customers related to this component, as weather adjusted loads for these customers exceeded those approved in the Company’s most recent general rate case. At the end of this component’s initial two year tariff, PGE is required to submit to the OPUC the Company’s assessment of its effectiveness and may request an extension or revision, which may be included in a general rate case filing.

Another component of the mechanism provides for the deferral of the revenue requirement associated with a return on equity (ROE) refund until it can be reflected in base rates. The ROE refund, estimated at approximately $1.9 million annually, would reduce PGE’s allowed ROE from 10.1%, as approved by the OPUC in the Company’s latest general rate case, to 10.0%, and is intended to reflect an assumed reduction in the Company’s risk associated with the decoupling mechanism.

During the first half of 2009, PGE recorded a refund due to customers in the amount of approximately $2 million related to the decoupling mechanism, which was included in Revenues.

The American Recovery and Reinvestment Act of 2009 - On February 17, 2009, the American Recovery and Reinvestment Act of 2009 (the Act) was enacted. The Act includes provisions for several enhanced tax benefits, many of which are favorable to renewable energy and energy efficiency projects.

For PGE’s renewable energy projects, such as the Biglow Canyon Wind Farm, the Production Tax Credit (PTC) was extended from 2009 through 2012. Also, in lieu of the PTC, a company may elect Investment Tax Credit (ITC) or Treasury Department Grants, meeting certain criteria. PGE has completed an initial assessment of these alternatives and determined that continuing to claim PTC for Biglow Canyon Phase II will provide a larger customer benefit. This is due to the utility tax normalization rules that require that the benefit of the ITC or Treasury Department Grants be spread over the life of the related property, compared to the PTC, under which the benefit would be spread over 10 years. PGE will continue to review the alternatives of PTC, ITC or Treasury Department Grants for Biglow Canyon Phase III, which is expected to be placed in service in 2010.

PGE is also considering opportunities under the Act that would provide funding for smart grid projects and vehicle electrification. PGE expects to complete filing grant applications with the U.S. Department of Energy in August 2009.

While PGE has substantially completed its assessment of options available under the Act, the ultimate determination of benefits under the Act is subject to various factors, including the promulgation of regulations under the Act and the clarification of regulatory treatment of grant funds under the Act. There is no assurance that PGE will receive any grants under the Act.

Critical Accounting Policies

PGE’s critical accounting policies are outlined in Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on February 25, 2009.

 

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Results of Operations

The following table contains certain financial information for the periods presented (dollars in millions):

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2009     2008     2009     2008  
     Amount    As %
of Rev
    Amount    As %
of Rev
    Amount     As %
of Rev
    Amount     As %
of Rev
 

Revenues

   $ 389    100   $ 425    100   $ 874      100   $ 896      100

Operating expenses:

                  

Purchased power and fuel

     184    47        185    43        439      50        435      49   

Production and distribution

     43    11        46    11        85      10        85      9   

Administrative and other

     46    12        47    11        91      10        94      11   

Depreciation and amortization

     50    13        50    12        107      12        100      11   

Taxes other than income taxes

     21    5        21    5        44      5        43      5   
                                                      

Total operating expenses

     344    88        349    82        766      87        757      85   
                                                      

Income from operations

     45    12        76    18        108      13        139      15   

Other income (expense):

                  

Allowance for equity funds used during construction

     6    2        2    -        8      1        4      -   

Miscellaneous income (expense), net

     4    1        1    -        1      -        (2   -   
                                                      

Other income, net

     10    3        3    -        9      1        2      -   

Interest expense

     26    7        23    5        51      6        46      5   
                                                      

Income before income taxes

     29    8        56    13        66      8        95      10   

Income taxes

     3    1        17    4        16      2        28      3   
                                                      

Net income

     26    7        39    9        50      6        67      7   

Less: net income (loss) attributable to noncontrolling interests

     2    1        -    -        (5   -        -      -   
                                                      

Net income attributable to Portland General Electric Company

   $ 24    6   $ 39    9   $ 55      6   $ 67      7
                                                      

Net income attributable to Portland General Electric Company was $24 million, or $0.31 per diluted share, for the second quarter of 2009 compared to $39 million, or $0.63 per diluted share, for the second quarter of 2008. An approximate 8% decrease in retail energy deliveries, resulting from both a slow economy and mild weather, along with the sale of excess power into low-priced wholesale markets, more than offset the effect of higher customer prices in 2009. Also contributing to the decrease was the effect of estimated customer refunds related to SB 408, recorded in the second quarter of 2009, and gains on the sale of fuel oil from the Company’s Beaver plant in 2008. These reductions were partially offset by an increase in the fair market value of non-qualified benefit plan trust assets.

Net income attributable to Portland General Electric Company was $55 million, or $0.77 per diluted share, for the six months ended June 30, 2009 compared to $67 million, or $1.07 per diluted share, for the six months ended June 30, 2008. Both a continued slow economy and mild weather contributed to an approximate 5% decrease in retail energy deliveries in the first half of 2009. Higher power costs, the effect of estimated customer refunds related to SB 408, and gains on the sale of fuel oil from the Company’s Beaver plant in 2008 also contributed to the decrease in net income. These reductions were partially offset by higher customer prices and an increase in the fair market value of non-qualified benefit plan trust assets in the first half of 2009.

 

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Second Quarter of 2009 Compared to the Second Quarter of 2008

Revenues, energy sold and delivered (based in megawatt hours), and average number of retail customers consist of the following:

 

     Three Months Ended June 30,  
     2009     2008  
     Amount    % of
Total
    Amount     % of
Total
 

Revenues (dollars in millions):

         

Retail sales:

         

Residential

   $ 168    43   $ 169      40

Commercial

     149    39        145      34   

Industrial

     39    10        39      9   
                           

Total retail sales

     356    92        353      83   

Direct access customers

     -    -        (2   -   

Other retail revenues

     4    1        12      2   
                           

Total retail revenues

     360    93        363      85   

Wholesale revenues

     21    5        44      11   

Other operating revenues

     8    2        18      4   
                           

Total revenues

   $ 389    100   $ 425      100
                           

Energy sold and delivered (MWh in thousands):

         

Retail energy sales:

         

Residential

     1,646    32     1,764      32

Commercial

     1,718    34        1,739      32   

Industrial

     558    11        640      12   
                           

Total retail energy sales

     3,922    77        4,143      76   

Delivery to direct access customers

     464    9        602      11   
                           

Total retail energy delivieries

     4,386    86        4,745      87   

Wholesale sales

     688    14        681      13   
                           

Total energy sold and delivered

     5,074    100     5,426      100
                           

Average number of retail customers:

         

Residential

     714,309    88     710,588      88

Commercial

     101,470    12        100,233      12   

Industrial

     253    -        216      -   

Direct access

     244    -        421      -   
                           

Average retail customers

     816,276    100     811,458      100
                           

 

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Revenues decreased $36 million, or 8.5%, in the second quarter of 2009 compared to the second quarter of 2008 as a result of the net effect of the following:

Total retail revenues decreased $3 million, or 0.8%, in the second quarter of 2009 compared to the second quarter of 2008 primarily due to the net effect of the following:

 

  o A $32 million increase resulting from a 9% increase in average price, which was primarily driven by the price increases approved by the OPUC pursuant to the Company’s 2009 General Rate Case and became effective January 1, 2009;
  o A $19 million decrease driven by a 5.3% decline in total retail energy sales (volume) to residential, commercial and industrial customers, which resulted from the continued economic slowdown in 2009. Milder weather during the second quarter of 2009 relative to the second quarter of 2008, as indicated in the table below, also contributed to this decline in demand. Partially offsetting this decrease was an increase in the average number of residential, commercial and industrial customers served of 0.6%;
  o A $10 million decrease related to SB 408, resulting from a $9 million customer refund recorded in the second quarter of 2009, compared to a $1 million customer collection recorded in the second quarter of 2008, which is included in Other retail revenues;
  o A $4 million decrease resulting from the accrual of amounts due to customers related to Biglow Canyon Phase II pursuant to PGE’s Renewable Adjustment Clause tariff, which is included in Other retail revenues. As the turbines are placed in service, PGE accrues amounts to be collected from customers for Biglow Canyon Phase II operating expenses, net of any tax credits, plus the return of and on the average rate base. The accrual period began April 1, 2009 and continues through December 31, 2009. For the second quarter of 2009, the tax credits exceeded the operating costs plus the return of and on the average rate base, which resulted in a credit to customers. For 2009, PGE expects the overall amount to be a collection from customers of approximately $6 million related to Biglow Canyon Phase II, which will be reflected in customer prices beginning January 1, 2010 and collected over one year; and
  o A $2 million decrease related to the decoupling mechanism, which went into effect on February 1, 2009 and is included in Other retail revenues. For further information on the decoupling mechanism, see “Legal, Regulatory and Environmental Matters” in “Overview” of this Item 2.

Heating and cooling degree-days are an indication of the likelihood that customers will use heating and cooling, respectively, and is used to measure the effect of weather on the demand for electricity. During the second quarter of 2009, heating and cooling degree-days decreased 32.8% and 8.2%, respectively, compared to the second quarter of 2008. The following table indicates the number of heating and cooling degree-days for the months presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:

 

     Heating Degree-days    Cooling Degree-days
     2009    2008    2009    2008

April

   374    490    -      -  

May

   175    223    34    40

June

   29    147    56    58
                   

2nd quarter

   578    860    90    98
                   

15-year average for the quarter

   683    664    71    67
                   

 

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On a weather adjusted basis, retail energy deliveries decreased 3.0% in the second quarter of 2009 compared to the second quarter of 2008, with deliveries to residential, commercial, and industrial customers increasing (decreasing) by 1.3%, (3.6)%, and (9.0)%, respectively. PGE projects that weather adjusted energy deliveries will decrease approximately 2.5% in 2009 relative to 2008.

In addition to those items listed above as “included in Other retail revenues,” Other retail revenues also includes certain customer credits and refunds. These customer credits and refunds are fully offset within Retail sales, therefore having no impact to total Retail revenues, and primarily consist of the following:

 

  o A $4 million increase related to the PCAM for the year 2007. Customer refunds related to the PCAM for 2007, totaling $17 million (plus interest), began January 1, 2009 and continue over approximately one year;
  o A $2 million increase related to SB 408 for the years 2007 and 2006. Customer collections related to SB 408 for 2007, totaling $15 million (plus interest) began June 1, 2009 and continue over approximately one year. Customer refunds related to SB 408 for 2006, totaling $37 million (plus interest), began June 1, 2008 and continue over approximately two years; and
  o A $2 million increase related to the Residential Exchange Program administered by the BPA. As a result of a decision by the Ninth Circuit, the BPA suspended such benefits in May 2007. In April 2008, benefits were temporarily restored under an Interim Relief agreement with the BPA. The resumption of customer credits, as approved by the OPUC, resulted in an average price reduction of approximately 6.3% for residential and small farm customers, effective April 15, 2008.

Wholesale revenues result from sales of electricity to utilities and power marketers, which are made in conjunction with the Company’s effort to secure reasonably priced power for its retail customers, manage risk and administer its long-term wholesale contracts. Such sales can vary significantly period to period. During the second quarter of 2009, PGE sold electricity originally intended to meet forecasted load into an increasingly depressed market. Accordingly, Wholesale revenues decreased $23 million, or 52%, in the second quarter of 2009 compared to the second quarter of 2008, which was driven by a 51% decrease in average price and slightly offset by a 1% increase in wholesale energy sales.

Other operating revenues decreased $10 million, or 56%, in the second quarter of 2009 compared to the second quarter of 2008, which is due to sales of fuel oil from the Company’s Beaver generating plant in 2008. The sales of this fuel oil resulted in realized gains of approximately $7 million in the second quarter of 2008.

Purchased power and fuel expense decreased $1 million, or less than 1%, in the second quarter of 2009 compared to the second quarter of 2008. The decrease was due primarily to the net effect of the following:

 

   

A $46 million decrease in the cost of thermal production, due to both a 29% reduction in natural gas prices and a 65% reduction in generation, due primarily to extended maintenance outages at Colstrip and Boardman and the economic curtailment of Port Westward and Coyote Springs;

   

A $7 million decrease in the estimated amount recorded for potential future refund to customers under the PCAM. In the second quarter of 2008, PGE recorded a $7 million regulatory liability, with a corresponding increase in power costs. As discussed below, no amount was recorded in the second quarter of 2009;

   

A $49 million increase in the cost of settled electric and natural gas financial contracts entered into in conjunction with PGE’s management of its net power costs. These contracts are among those financial instruments in the Company’s diversified power supply portfolio used to manage market risk, with activities reflected in Wholesale revenues, Purchased power and fuel expense, and Other operating revenues; and

 

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A $3 million increase in the cost of purchased power, with a 24% increase in total energy purchases, partially offset by a 17% decrease in average cost, due to lower prices for natural gas and electricity.

PGE’s sources of energy (based in MWh) for the periods presented are as follows (MWh in thousands):

 

     Three Months Ended June 30,  
     2009     2008  

Generation:

        

Thermal

   501      10   1,432      28

Hydro

   535      11      562      11   

Wind

   126      3      135      3   
                        

Total generation

   1,162      24      2,129      42   
                        

Purchased power:

        

Term purchases

   2,601      54      1,586      31   

Purchased hydro

   936      19      1,001      20   

Spot purchases

   127      3      359      7   
                        

Total purchased power

   3,664      76      2,946      58   
                        

Total system load

   4,826      100   5,075      100
                

Less: wholesale sales

   (688     (681  
                

Retail load requirement

   4,138        4,394     
                

Total system load decreased 5% from the second quarter of 2008 primarily as the result of reduced customer demand, resulting from both the current economic slowdown and milder weather in 2009. A 65% decrease in thermal generation in the second quarter of 2009 resulted from extended maintenance outages at both Colstrip and Boardman (see “Power Supply” in “Overview” of this Item 2 for further information), as well as economic curtailments at the Company’s Port Westward and Coyote Springs natural gas-fired generating plants. Increased term purchases were utilized to replace the reduction in generation. The average variable cost of PGE’s total system load was $38.12 per MWh in the second quarter of 2009 compared to $35.09 per MWh in the second quarter of 2008, an increase of 9%.

Under the PCAM, the Company can adjust future prices to reflect a portion of the difference between each year’s forecasted NVPC included in customer prices (the baseline) and actual NVPC, to the extent that such difference exceeds a pre-determined “deadband.” For 2009, the deadband ranges from approximately $15 million below, to $30 million above, the baseline NVPC. Although PGE expects that actual NVPC for 2009 will be somewhat below the baseline, the difference between actual and baseline NVPC is expected to be within the established deadband; accordingly, no customer refund or collection has been recorded as of June 30, 2009.

 

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Current forecasts indicate that regional hydro conditions in 2009 will be below normal levels. Volumetric water supply forecasts for the Pacific Northwest region are prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies. The following indicates the forecast of the April-to-September 2009 runoff (issued July 8, 2009) compared to the actual runoffs for 2008 (as a percentage of normal):

 

Location

   2009
Forecast
    2008
Actual
 

Columbia River at The Dalles, Oregon

   85   99

Mid-Columbia River at Grand Coulee, Washington

   80      98   

Clackamas River

   122      157   

Deschutes River

   92      112   

Production and distribution expense decreased $3 million, or 7%, in the second quarter of 2009 compared to the second quarter of 2008, primarily due to the net effect of the following:

 

   

A $7 million decrease related to the deferral of certain plant maintenance costs at Boardman, Beaver and Colstrip, as authorized by the OPUC in PGE’s most recent general rate case. During the second quarter of 2009, PGE deferred qualified maintenance costs that exceed those covered in current prices authorized by the OPUC. These deferred plant maintenance costs are amortized over ten years, which began in 2009;

   

A $3 million increase related to higher maintenance costs at Colstrip Unit 4, related primarily to the 2009 scheduled maintenance outage;

   

A $1 million increase for repair and restoration activities related to a June 2009 wind storm; and

   

A $1 million increase resulting from a reserve established for the cost of certain future environmental remediation activities.

Administrative and other expense decreased $1 million, or 2%, in the second quarter of 2009 compared to the second quarter of 2008, primarily due to a decrease in incentive compensation. This decrease was partially offset by an increase in pension costs.

Other income, net increased $7 million in the second quarter of 2009 compared to the second quarter of 2008, primarily due to the net effect of the following:

 

   

A $5 million increase in income from non-qualified benefit plan trust assets, resulting from a $5 million gain in the fair value of the plan assets in 2009 compared to a nominal loss in the second quarter of 2008;

   

A $3 million increase in the allowance for equity funds used during construction as a result of higher construction work in progress balances in 2009 related to Biglow Canyon Phases II and III and the Selective Water Withdrawal project; partially offset by

   

A $1 million decrease related to lower rates on lower average money market account balances.

Interest expense increased $3 million, or 13%, in the second quarter of 2009 compared to the second quarter of 2008. The increase is primarily due to the net effect of the following:

 

   

A $5 million increase resulting from an increase in the average balance of short- and long-term debt outstanding during the second quarter of 2009 compared to the second quarter of 2008. In April 2009, PGE issued $300 million of First Mortgage Bonds, increasing the average balance outstanding of long-term debt to $1,515 million in the second quarter of 2009, compared to $1,281 million in the second quarter of 2008; and

 

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A $2 million increase in the credit to interest expense for the allowance for funds used during construction driven by higher construction work in progress balances during the second quarter of 2009 compared to the second quarter of 2008. The higher construction work in progress balances were driven by the construction of Biglow Canyon Phases II and III and the Selective Water Withdrawal capital project.

Income taxes decreased $14 million in the second quarter of 2009, with an effective tax rate of 11.1%, compared to the second quarter of 2008, with an effective tax rate of 30.4%. The effective tax rate for the three months ended June 30, 2009 was calculated using income before income taxes of $29 million less the net income attributable to the noncontrolling interests of $2 million, for income before income taxes attributable to the Company of $27 million, which compares to income before income taxes of $56 million for the three months ended June 30, 2008. The effective tax rates for both 2009 and 2008 differ from the expected statutory rate due to federal and state tax credits, the majority of which consist of production tax credits. The decrease in the effective tax rate in 2009 compared to 2008 is largely the result of an increase in these tax credits plus lower pretax earnings, which causes these credits to have a greater impact on the effective tax rate.

Net income attributable to noncontrolling interests of $2 million for the second quarter of 2009 represents the noncontrolling interests’ portion of the net income of PGE’s less-than-wholly-owned subsidiaries.

 

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Six Months Ended June 30, 2009 Compared to the Six Months Ended June 30, 2008

Revenues, energy sold and delivered (based in megawatt hours), and average number of retail customers consist of the following:

 

     Six Months Ended June 30,  
     2009     2008  
     Amount     % of
Total
    Amount     % of
Total
 

Revenues (dollars in millions):

        

Retail sales:

        

Residential

   $ 401      46   $ 404      45

Commercial

     298      34        294      33   

Industrial

     81      9        77      8   
                            

Total retail sales

     780      89        775      86   

Direct access customers

     (1   -        (4   -   

Other retail revenues

     33      4        9      1   
                            

Total retail revenues

     812      93        780      87   

Wholesale revenues

     49      6        92      10   

Other operating revenues

     13      1        24      3   
                            

Total revenues

   $ 874      100   $ 896      100
                            

Energy sold and delivered (MWh in thousands):

        

Retail energy sales:

        

Residential

     3,997      36     4,122      36

Commercial

     3,451      32        3,530      31   

Industrial

     1,162      11        1,208      10   
                            

Total retail energy sales

     8,610      79        8,860      77   

Delivery to direct access customers

     914      8        1,189      10   
                            

Total retail energy delivieries

     9,524      87        10,049      87   

Wholesale sales

     1,397      13        1,487      13   
                            

Total energy sold and delivered

     10,921      100     11,536      100
                            

Average number of retail customers:

        

Residential

     714,027      88     709,860      88

Commercial

     100,122      12        98,814      12   

Industrial

     251      -        216      -   

Direct access

     254      -        411      -   
                            

Average retail customers

     814,654      100     809,301      100
                            

 

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Revenues decreased $22 million, or 2.5%, for the six months ended June 30, 2009 compared to the six months ended June 30, 2008 as a result of the net effect of the following:

Total retail revenues increased $32 million, or 4.1%, due primarily to:

 

  o A $67 million increase resulting from a 9% increase in average price, which was primarily driven by the price increases approved by the OPUC pursuant to the Company’s 2009 General Rate Case and became effective January 1, 2009;
  o A $4 million increase resulting from a reduction in the transition adjustment credit provided to Direct Access customers. Transition adjustment credits reflect the difference between the cost and market value of PGE’s power supply, as provided by Oregon’s electricity restructuring law;
  o A $22 million decrease driven by a 2.8% decline in total retail energy sales to residential, commercial and industrial customers, which resulted from the continued economic slowdown in 2009. Milder weather in 2009 relative to 2008, as indicated in the table below, also contributed to this decline in demand. Partially offsetting this decrease was an increase in the average number of residential, commercial and industrial customers served of 0.7%;
  o A $7 million decrease related to SB 408, resulting from a $8 million customer refund recorded for the six months ended June 30, 2009, compared to $1 million for the six months ended June 30, 2008, which is included in Other retail revenues;
  o A $5 million decrease related to supplemental tariffs, which is fully offset in Depreciation and amortization expense;
  o A $4 million decrease resulting from the deferral of revenue related to Biglow Canyon Phase II, which is included in Other retail revenues; and
  o A $2 million decrease related to the decoupling mechanism, which went into effect on February 1, 2009 and is included in Other retail revenues.

During the six months ended June 30, 2009, heating and cooling degree-days decreased 8.5% and 8.2%, respectively, compared to the same period of 2008. The following table indicates the number of heating and cooling degree-days for the periods presented, along with 15-year averages provided by the National Weather Service, as measured at Portland International Airport:

 

     Heating Degree-days    Cooling Degree-days
     2009    2008    2009    2008

1st Quarter

   2,022    1,981    -    -

2nd Quarter

   578    860    90    98
                   

Year-to-date

   2,600    2,841    90    98
                   

15-year average for the year-to-date

   2,514    2,504    71    67
                   

On a weather adjusted basis, retail energy deliveries decreased 2.1% during the six months ended June 30, 2009 compared to the six months ended June 30, 2008, with deliveries to residential, commercial, and industrial customers decreasing by 0.1%, 2.9%, and 4.5%, respectively.

In addition to those items listed above as “included in Other retail revenues,” Other retail revenues also includes certain customer credits and refunds. These customer credits and refunds are fully offset in Retail sales, therefore having no impact to total Retail revenues, and primarily consist of the following:

 

  o An $18 million increase related to the Residential Exchange Program administered by the BPA;
  o A $9 million increase related to the PCAM for the year 2007; and

 

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  o A $9 million increase related to SB 408 for the year 2006.

Wholesale revenues decreased $43 million, or 47%, for the six months ended June 30, 2009 compared to the six months ended June 30, 2008 due to the net effect of the following:

 

  o A $37 million decrease related to a 43% decline in average price, driven by lower natural gas and electricity prices; and
  o A $6 million decrease related to a 6% decline in wholesale energy sales.

Other operating revenues decreased $11 million, or 46%, for the six months ended June 30, 2009 compared to the six months ended June 30, 2008, which is due to sales of fuel oil from the Company’s Beaver generating plant in 2008. The sales of this fuel oil resulted in realized gains of approximately $7 million in 2008.

Purchased power and fuel expense increased $4 million, or 1%, for the six months ended June 30, 2009 compared to the six months ended June 30, 2008. The increase was due primarily to the net effect of the following:

 

   

A $122 million increase in the cost of settled electric and natural gas financial contracts entered into in conjunction with PGE’s management of its net power costs. These contracts are among those financial instruments in the Company’s diversified power supply portfolio used to manage market risk, with activities reflected in Wholesale revenues, Purchased power and fuel expense, and Other operating revenues;

   

A $78 million decrease in the cost of thermal production, due to both a 41% reduction in natural gas prices and a 25% reduction in generation, due primarily to extended maintenance outages at Colstrip and Boardman and the economic curtailment of Port Westward and Coyote Springs;

   

A $33 million decrease in the cost of purchased power, with a 24% reduction in average cost, due to lower prices for natural gas and electricity, partially offset by a 13% increase in total energy purchases; and

   

A $7 million decrease in the estimated amount recorded for potential future refund to customers under the PCAM. In the first half of 2008, PGE recorded a $7 million regulatory liability, with a corresponding increase in power costs. No amount was recorded in the first half of 2009.

 

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PGE’s sources of energy (based in MWh) for the periods presented are as follows (MWh in thousands):

 

     Six Months Ended June 30,  
     2009     2008  

Generation:

        

Thermal

   3,146      29   4,175      38

Hydro

   1,039      10      1,066      10   

Wind

   194      2      217      2   
                        

Total generation

   4,379      41      5,458      50   
                        

Purchased power:

        

Term purchases

   4,241      40      3,097      28   

Purchased hydro

   1,616      15      1,727      16   

Spot purchases

   348      4      664      6   
                        

Total purchased power

   6,205      59      5,488      50   
                        

Total system load

   10,584      100   10,946      100
                

Less: wholesale sales

   (1,397     (1,487  
                

Retail load requirement

   9,187        9,459     
                

Total system load decreased approximately 3% from the first half of 2008 primarily as the result of decreased customer demand, resulting from both the current economic slowdown and milder weather in 2009. A 25% decrease in thermal generation in the first half of 2009 was primarily the result of extended maintenance outages at both Colstrip and Boardman (see “Power Supply” in “Overview” of this Item 2 for further information). Increased term purchases were utilized to replace the reduction in generation. The average variable cost of PGE’s total system load was $41.55 per MWh for the first six months ended June 30, 2009 compared to $39.13 per MWh for the six months ended June 30, 2008, an increase of 6%.

Production and distribution expense for the six months ended June 30, 2009 is comparable to the six months ended June 30, 2008, primarily due to the net effect of the following:

 

   

A $7 million decrease related to the deferral of certain plant maintenance costs at Boardman, Beaver and Colstrip. As authorized by the OPUC in PGE’s most recent general rate case, certain maintenance costs that exceed those covered in current prices are deferred and amortized over ten years, which began in 2009;

   

A $3 million increase for repair and restoration activities related to the December 2008 snow and ice storm, and wind storms in January, March, and June 2009;

   

A $3 million increase related to higher maintenance costs at Colstrip Unit 4, related primarily to the 2009 scheduled maintenance outage; and

   

A $1 million increase resulting from a reserve established for the cost of certain future environmental remediation activities.

Administrative and other expense decreased $3 million, or 3%, for the six months ended June 30, 2009 compared to the six months ended June 30, 2008, primarily due to the net effect of the following:

 

   

A $3 million decrease in incentive compensation;

   

A $3 million decrease in legal settlement expense;

   

A $2 million increase in the provision for uncollectible accounts, which is driven by the state of Oregon’s economy; and

   

A $1 million increase in pension costs.

 

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Depreciation and amortization expense increased $7 million, or 7%, for the six months ended June 30, 2009 compared to the six months ended June 30, 2008, primarily due to the net effect of the following:

 

   

A $5 million increase related to impairment losses recognized on photovoltaic solar power facilities, the majority of which was allocated to noncontrolling interests through the Net losses attributable to the noncontrolling interests. For additional information, see Note 10 to the condensed consolidated financial statements included in Item 1 - “Financial Statements”;

   

A $4 million increase related to accelerated depreciation of existing customer meters that are being replaced as part of the Company’s smart meter project;

   

A $2 million increase related to capital additions in 2009; partially offset by

   

A $5 million decrease related to the amortization of regulatory liabilities (fully offset in Retail sales).

Other income, net increased $7 million for the six months ended June 30, 2009 compared to the six months ended June 30, 2008, primarily due to the net effect of the following:

 

   

A $7 million increase in income from non-qualified benefit plan trust assets, resulting from a gain of $2 million in the fair value of the plan assets in the first half of 2009 compared to a loss of $5 million in the first half of 2008;

   

A $4 million increase in the allowance for equity funds used during construction as a result of higher construction work in progress balances in 2009 related to Biglow Canyon Phases II and III and the Selective Water Withdrawal project; and

   

A $4 million decrease in miscellaneous income, including $2 million decrease related to lower rates on lower average money market account balances.

Interest expense increased $5 million, or 11%, for the six months ended June 30, 2009 compared to the six months ended June 30, 2008, primarily due to the net effect of the following:

 

   

A $7 million increase resulting from an increase in the average balance of short- and long-term debt outstanding during the first half of 2009 compared to the first half of 2008. In January and April 2009, PGE issued $130 million and $300 million, respectively, of First Mortgage Bonds, increasing the average balance outstanding of long-term debt to $1,450 million in the first half of 2009, compared to $1,310 million in the first half of 2008. Additionally, average balances outstanding under short-term borrowing arrangements were higher in the first half of 2009 compared to the first half of 2008, primarily driven by increased collateral requirements pursuant to the Company’s price risk management activities;

   

A $1 million increase in fees related to PGE’s credit facilities; partially offset by

   

A $3 million increase in the credit to interest expense for the allowance for funds used during construction, driven by higher construction work in progress balances during the first half of 2009 compared to the first half of 2008. The higher construction work in progress balances were driven by the construction of Biglow Canyon Phases II and III and the Selective Water Withdrawal capital project.

Income taxes decreased $12 million for the six months ended June 30, 2009, with an effective tax rate of 22.5%, compared to the comparable period of 2008, with an effective tax rate of 29.5%. The effective tax rate for the first half of 2009 was calculated using income before income taxes of $66 million less the net loss attributable to the noncontrolling interests of $5 million, for income before income taxes attributable

 

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to the Company of $71 million, which compares to income before income taxes of $95 million for the first half of 2008. The effective tax rates for both 2009 and 2008 differ from the expected statutory rate due to federal and state tax credits, the majority of which consist of production tax credits. The decrease in the effective tax rate in 2009 compared to 2008 is largely the result of an increase in these tax credits plus lower pretax earnings, which causes these credits to have a greater impact on the effective tax rate.

On July 20, 2009, Oregon House Bill 3405 was enacted and establishes, among other matters, an increase in the state corporate tax rate. PGE is in the process of determining the estimated impact the new state corporate tax rate will have on the income taxes for the Company, but expects any impact to be mitigated by the effects of SB 408.

Net loss attributable to noncontrolling interests of $5 million represents the noncontrolling interests’ portion of the net loss of PGE’s less-than-wholly-owned subsidiaries, the majority of which consists of the impairment losses recognized on the photovoltaic solar power facilities, discussed previously in Depreciation and amortization.

Liquidity and Capital Resources

Capital Requirements

The following table presents PGE’s estimated primary cash requirements for the years indicated (in millions, excluding AFDC):

 

     2009    2010         2011    2012    2013

Ongoing capital expenditures

   $ 226    $ 223         $215 - $235      $245 - $265      $240 - $260

Biglow Canyon Phase II

     230      -         -      -      -

Biglow Canyon Phase III

     176      198         -      -      -

Hydro licensing and construction

     27      24         $55 - $75

Smart meter project

     59      60         -      -      -

Boardman emissions controls *

     2      16         $255 - $295
                         

Total capital expenditures

   $ 720    $ 521            
                         

Long-term debt maturities

   $ 142    $ 186       $ -    $ 100    $ 100
                                     

* Represents 80% of estimated total costs. For further explanation see “Boardman emissions controls” below.

Ongoing capital expenditures - Consists of upgrades to and replacement of transmission, distribution and generation infrastructure, as well as new customer connections.

Biglow Canyon Phases II and III - Construction of Phases II and III continues, with 15 turbines of Phase II placed in service as of June 30, 2009 and the remaining 50 turbines expected to be completed by September 2009. The total cost of Phase II, with an installed capacity of 149 MW, is estimated at $327 million, including $11 million of AFDC. Phase III is expected to be completed by the end of 2010, with an installed capacity of 175 MW and an estimated total cost of $434 million, including $28 million of AFDC.

Hydro licensing and construction - As required under the 50-year license that the FERC issued to PGE in 2005 for its Pelton/Round Butte project on the Deschutes River, PGE began construction of a selective water withdrawal system in late 2007 in an effort to restore fish passage on the upper portion of the river. The system is designed to collect juvenile salmon and steelhead, allowing them to bypass the dam when

 

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migrating to the Pacific Ocean, and will regulate downstream water temperature. As a result of a delay in construction, completion of the system is expected during the first quarter of 2010. The total cost is estimated at $105 million to $110 million, with PGE’s portion of the total cost estimated at $80 million, including AFDC.

The Company filed an application with the FERC in 2004 to relicense the Clackamas River hydroelectric projects. A settlement agreement, resolving most of the issues raised in the licensing proceeding and providing for a 45-year license term, was signed by the thirty-three participating parties in March 2006 and was submitted to the FERC for review and approval. Pending issuance of the new license, the project will operate under annual licenses issued by the FERC. PGE anticipates that the FERC will issue a new license for the Clackamas River projects in 2010.

Smart meter project - PGE began to install approximately 850,000 new customer meters during the second quarter of 2009 that will enable two-way remote communication. Through June 30, 2009, approximately 100,000 new smart meters have been installed within the Company’s service area. It is expected that about 400,000 smart meters will be installed by the end of 2009, with the remainder to be installed in 2010. PGE estimates the capital cost of the smart meter project will range from $130 million to $135 million. The project is expected to provide improved services, operational efficiencies, and a reduction in future operating expenses.

Boardman emissions controls - In accordance with federal regional haze rules aimed at visibility impairment in several federally protected areas, the DEQ conducted an assessment of emission sources that has indicated that Boardman may cause or contribute to visibility impairment in several federally protected areas and would be subject to a Regional Haze Best Available Retrofit Technology (BART) Determination, as required under the Clean Air Act.

In June 2009, the OEQC adopted a rule that would require the installation of controls at Boardman in three phases. The first phase would require installation of controls for nitrogen oxides (NOx), with estimated completion by 2011. The second phase would address mercury and sulfur dioxide removal using a semi-dry scrubber and bag house, with estimated completion by 2014. These first two phases would meet federal requirements for installing BART. The third phase, which would require the installation of Selective Catalytic Reduction for additional NOx control, with estimated completion by 2017, would meet requirements for reasonable progress towards haze emission reduction goals. The OEQC rule has been submitted to the EPA for approval as part of the Oregon Regional Haze State Implementation Plan (SIP). The Company expects the EPA to issue a decision on the SIP in 2010.

Based on requirements outlined in the OEQC’s rule and current market conditions for air quality equipment, PGE now estimates that the approximate cost of the controls required by the OEQC rule would be between $520 million and $560 million (100% of total costs, excluding AFDC). PGE has no commitments in place at this time and cautions that the cost estimates are preliminary and subject to change. The Company believes that, based upon the expected cost relating to (i) carbon, (ii) replacement generation, (iii) coal and natural gas, and (iv) emission controls required to meet the OEQC’s rule, the long term continued operation of Boardman will best meet the economic interests of its customers.

Any additional costs such as taxes, emission fees, and other future costs that may be imposed under any future laws related to climate change, combined with any expenditure for controls, could constitute an investment in excess of what the plant can economically support. The ultimate impact that the above regulatory requirements and emission controls will have on future operations, costs, or generating capacity of Boardman is not yet determinable and will be evaluated as part of the Company’s integrated resource planning process. PGE will seek recovery of its costs through the ratemaking process.

 

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Further capital needs, not included in the table above, could include those related to the following:

 

   

Additional resource requirements identified in the Company’s pending Integrated Resource Plan (IRP), expected to be filed with the OPUC by late 2009. The IRP, which describes the Company’s energy supply strategy, will address resource requirements through the year 2020, with particular focus on acquisition of resources, both supply and transmission, to meet customer demand through 2015. New supply resource needs may be met by the ongoing emphasis on energy efficiency programs, additional renewable resources, new facilities to help meet base load and capacity requirements, and purchase power agreements of various durations. Potential new generation resources the Company is considering include natural gas facilities, to help meet additional base load requirements estimated at 300-500 MW and peak load requirements estimated at 100-200 MW, as well as an additional 300-400 MW of wind or other renewable resources necessary to meet requirements of Oregon’s Renewable Energy Standard by 2015. Following OPUC acknowledgement of the Company’s IRP, these potential resources would be included in a formal bidding process to be conducted in 2010;

   

The Company has determined that it will not fulfill the 218 MWa of renewable energy resources acquisitions targeted in the Request for Proposals (RFP) issued pursuant to the 2007 IRP. This decision was made as a result of several challenges encountered during the RFP bid review and negotiations. These challenges included adverse changes in financial market conditions that impacted bidder costs and ability to execute, transmission and interconnection deficiencies and changes to bid structures that were inconsistent with the Company’s objectives. The Company will address the need for additional renewable resources in the 2009 IRP process described above; and

   

PGE is exploring its options with respect to a 200-mile, 500 kV transmission project referred to as Cascade Crossing Transmission Project (formerly known as “Southern Crossing”), which would help to meet growing demand, interconnect new energy resources in eastern Oregon to the Company’s service territory, and provide improved system reliability while reducing payments to third party transmission providers. The Company is working with other utilities and the Western Electricity Coordinating Council to coordinate the project and is currently exploring possible routes. The total cost of the Cascade Crossing Transmission Project is estimated to range from $600 million to $780 million (current dollars, excluding AFDC), depending on whether a single circuit or double circuit line is constructed.

Liquidity

PGE’s access to short-term debt markets provides necessary liquidity to support the Company’s current operating activities, including power and fuel purchases. Long-term capital requirements are driven largely by capital expenditures for distribution, transmission, and generation facilities to support both new and existing customers, as well as debt refinancing activities. PGE’s liquidity and capital requirements can also be significantly affected by other working capital needs, including margin deposits related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves.

 

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PGE’s cash flows were as follows (in millions):

 

     Six Months Ended June 30,  
     2009     2008  

Cash and cash equivalents, beginning of period

   $ 10      $ 73   

Net cash provided by (used in):

    

Operating activities

     220        368   

Investing activities

     (396     (204

Financing activities

     224        (35
                

Net change in cash and cash equivalents

     48        129   
                

Cash and cash equivalents, end of period

   $ 58      $ 202   
                

Net cash provided by operating activities - The $148 million decrease in cash provided by operating activities in the first half of 2009 compared to the first half of 2008 was primarily attributable to the net effect of the following:

 

   

An $85 million decrease related to changes in margin deposit requirements with certain wholesale customers and brokers, driven primarily by lower power and natural gas prices;

   

A $54 million decrease resulting from higher payments for power and fuel purchases in the first half of 2009;

   

A $9 million decrease due to payments received in 2008 from the sales of fuel oil;

   

A $7 million decrease resulting from higher payments for payroll taxes and other employee benefits;

   

A $6 million decrease resulting from 2009 payments related to a December 2008 storm;

   

A $27 million increase in cash received from retail sales of electricity, due to higher prices; and

   

A $10 million increase due to lower interest payments.

A significant portion of cash provided by operations consists of the recovery in customer prices of non-cash charges for depreciation and amortization. PGE estimates recovery of such charges will approximate $217 million in 2009. Combined with all other sources, cash provided by operations is estimated to be approximately $376 million in 2009, including the reduction of approximately $72 million in margin deposits held by certain wholesale customers and brokers. The estimated reduction of such margin deposits is based on both the timing of contract settlements and projected future energy prices.

Net cash used in investing activities - The $192 million increase in cash used in investing activities in the first half of 2009 compared to the first half of 2008 was primarily attributable to a $196 million increase in construction costs related to Biglow Canyon Phases II and III and a $12 million increase in expenditures for the smart meter project. These increases were partially offset by a $10 million decrease in expenditures for the Selective Water Withdrawal project. See “Capital Requirements” section above for further information.

Net cash provided by financing activities - Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. Net cash provided by such activities was $224 million in the first half of 2009 compared to net cash used of $35 million in the first half of 2008. PGE relies on cash from operations, the issuance of commercial paper, borrowings under its revolving credit facilities, and long-term financing activities to support such requirements. During the first half of 2009, net cash provided by financing activities primarily consisted of net proceeds from the issuance of

 

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long-term debt of $426 million, the issuance of common stock for net proceeds of $170 million, partially offset by the repayment of Pollution Control Bonds of $142 million, net payments on revolving credit facilities of $131 million, payments on short-term debt of $72 million, and the payment of dividends of $34 million. Financing activities in the first half of 2009 also included the receipt of $7 million in cash contributions from noncontrolling interests in the solar projects. During the first half of 2008, net cash used in financing activities consisted of the repayment of long-term debt of $56 million and the payment of dividends of $29 million, partially offset by proceeds received from the issuance of long-term debt of $50 million.

Dividends on Common Stock

While the Company expects to pay regular quarterly dividends on its common stock, the declaration of any dividends is at the discretion of the Company’s Board of Directors. The amount of any dividend declaration will depend upon factors that the Board of Directors deem relevant and may include, but are not limited to, PGE’s results of operations and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.

Common stock dividends declared during 2009 consist of the following:

 

Declaration Date

  

Record Date

  

Payment Date

   Dividends
Declared
per Share
   Total Dividends
Declared
                    (in millions)
February 19, 2009    March 25, 2009    April 15, 2009    $ 0.245    $ 18
May 13, 2009    June 25, 2009    July 15, 2009      0.255      20

Debt and Equity Financings

PGE has approval from the FERC to issue short-term debt up to a total of $550 million through February 6, 2010. PGE has the following unsecured revolving credit facilities:

 

   

A $370 million credit facility with a group of banks, of which $10 million is currently scheduled to terminate in July 2012 and $360 million in July 2013;

   

A $125 million credit facility with a group of banks, which is currently scheduled to terminate in December 2009; and

   

A $30 million credit facility with a Barclays Bank PLC, which is currently scheduled to terminate in June 2012.

These credit facilities supplement operating cash flow and provide a primary source of liquidity. Pursuant to the individual terms of the agreements, these facilities may be used for general corporate purposes and as backup for commercial paper borrowings. The $370 million and $30 million credit facilities permit borrowings and the issuance of standby letters of credit. The $125 million credit facility permits borrowings only. As of June 30, 2009, PGE had no borrowings or commercial paper outstanding and had $201 million of letters of credit outstanding under the credit facilities. As of June 30, 2009, the aggregate amount of unused available credit under the credit facilities was $324 million, with $296 million available as of July 31, 2009. The Company intends to either renew or replace the $125 million credit facility in December 2009.

 

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In the first half of 2009, PGE issued the following First Mortgage Bonds:

 

   

$130 million in January in two series. One series is for $67 million to mature January 15, 2016 at a fixed rate of 6.80%. The second series is for $63 million to mature on January 15, 2014 at a fixed rate of 6.50%; and

   

$300 million of 6.10% Series in April, which mature April 15, 2019.

The Company used a portion of the proceeds from the April bond issuance to purchase $142 million of its Pollution Control Bonds on May 1, 2009. These Pollution Control Bonds are currently owned by the Company and may be remarketed at a later date at the Company’s option. As of June 30, 2009, the total long-term debt outstanding was $1,594 million.

In March 2009, PGE issued 12,477,500 shares of common stock for net proceeds of $170 million. The proceeds were used to substantially repay outstanding short-term debt, with the balance to fund capital expenditures and general corporate purposes.

PGE’s ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, capital expenditure requirements, and alternatives available to investors. The Company’s ability to obtain and renew such financing depends on its credit ratings, as well as on credit markets, both generally and for electric utilities in particular. Management believes that the availability of the credit facilities, the expected ability to issue long-term debt and equity securities, and cash generated from operations will provide sufficient liquidity to meet the Company’s anticipated capital and operating requirements. However, the Company’s ability to issue long-term debt and equity could be adversely affected by changes in capital market conditions. Through 2010, the Company anticipates issuing a total of approximately $375 million of debt, part of which will be used to fund debt maturities of $186 million in 2010.

PGE’s financial objectives include the balancing of debt and equity to maintain a low weighted average cost of capital while retaining sufficient flexibility to meet the Company’s financial obligations. The Company attempts to maintain a common equity ratio (common equity to total consolidated capitalization, including current debt maturities) of approximately 50%. Achievement of this objective while sustaining sufficient cash flow is necessary to maintain favorable credit ratings and allow access to long-term capital at attractive interest rates. PGE’s common equity ratios were 49.2% and 47.3% as of June 30, 2009 and December 31, 2008, respectively.

Credit Ratings and Debt Covenants

PGE’s secured and unsecured debt is rated investment grade by Moody’s Investors Service (Moody’s) and Standard and Poor’s (S&P). PGE’s current credit ratings and outlook are as follows:

 

     Moody’s    S&P

First Mortgage Bonds

   Baa1    A

Senior unsecured debt

   Baa2    BBB+

Commercial paper

   Prime-2    A-2

Outlook

   Positive    Negative

Should Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt to below investment grade, the Company could be subject to requests by its wholesale, commodity and certain transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. These deposits, which are classified as Margin deposits in PGE’s condensed

 

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consolidated balance sheet, are based on the contract terms and commodity prices and can vary from period to period. As of June 30, 2009, PGE had posted approximately $309 million of collateral with these counterparties, consisting of $127 million in cash and $182 million in letters of credit, $38 million of which is affiliated with master netting agreements. Based on the Company’s energy portfolio, estimates of current energy market prices, and the level of collateral outstanding as of June 30, 2009, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $148 million and decreases to approximately $59 million by December 31, 2009. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $214 million at June 30, 2009 and decreases to approximately $93 million by December 31, 2009.

PGE’s financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade.

The issuance of additional First Mortgage Bonds requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimated that on June 30, 2009 it could issue up to approximately $443 million of additional First Mortgage Bonds under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust. Future issuances would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture of Mortgage and Deed of Trust on the basis of property additions, bond retirements, and/or deposits of cash.

PGE’s credit facilities contain customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65% of total capitalization (debt ratio). As of June 30, 2009, the Company’s debt ratio, as calculated under the credit agreements, was 50.8%.

Off-Balance Sheet Arrangements

PGE has no off-balance sheet arrangements that have, or are reasonably likely to have, a material current or future effect on its consolidated financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

 

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Contractual Obligations

PGE’s contractual obligations for 2009 and beyond are included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on February 25, 2009. Obligations for 2009 and beyond, as set forth in Part II, Item 7 of the 2008 Form 10-K, have not increased (decreased) materially as of June 30, 2009, except as presented below (in millions):

 

     Payments Due
     2009 *    2010    2011    2012    2013    There -
after
    Total

Long-term debt

   $ -    $ -    $ -    $ -    $ -    $ 430      $ 430

Interest on long-term debt

     10      19      19      19      19      (38     48

Electricity purchases

     18      99      -      -      -      -        117

Natural gas agreements

     25      -      -      -      -      -        25
                                                 

Total

   $ 53    $ 118    $ 19    $ 19    $ 19    $ 392      $ 620
                                                 

* Represents the period from July 1, 2009 through December 31, 2009.

With respect to the expected required pension plan contributions disclosed in the Company’s 2008 Annual Report on Form 10-K, PGE now estimates it will be required to make the following contributions to its pension plan: $12 million in 2010, $32 million in 2011, $40 million in 2012, and $34 million in 2013.

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The Company is subject to various market risks which include commodity price risk, credit risk, foreign currency exchange rate risk, and interest rate risk. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on February 25, 2009, except as noted below.

The following table presents the credit risk included in accounts receivable and price risk management assets, offset by related accounts payable and price risk management liabilities. As of June 30, 2009, PGE’s credit risk exposure for commodity activities and their subsequent maturity is as follows (dollars in millions):

 

     Credit
Risk
              Maturity of Credit Risk Exposure
     Before
Collateral
   As % of
Total
    Credit
Collateral
   2009 *    2010    2011    2012    2013    There-
after

Externally rated:

                         

Investment grade

   $ 31    95   $ 5    $ 2    $ 2    $ 6    $ 6    $ 6    $ 9

Non-investment grade

     2    5     -      1      1      -      -      -      -
                                                             

Total

   $ 33    100   $ 5    $ 3    $ 3    $ 6    $ 6    $ 6    $ 9
                                                             

* Represents the period from July 1, 2009 through December 31, 2009.

As of June 30, 2009, there was no posted collateral subject to be returned to a counterparty that is affiliated with master netting arrangements.

 

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Item 4. Controls and Procedures.

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of June 30, 2009, these disclosure controls and procedures were effective.

There have been no changes in the Company’s internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

PART II – OTHER INFORMATION

 

Item 1. Legal Proceedings.

For information regarding legal proceedings, see PGE’s Legal Proceedings set forth in Part I, Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on February 25, 2009 and Part II, Item 1 of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2009, filed with the SEC on May 4, 2009.

 

Item 1A. Risk Factors.

There have been no material changes to PGE’s Risk Factors set forth in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on February 25, 2009.

 

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

PGE’s 2009 Annual Meeting of Shareholders was held May 13, 2009 to conduct the following items of business:

 

  1. To elect directors for the coming year;

 

  2. To ratify the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2009; and

 

  3. To approve an amendment to the Company’s Amended and Restated Articles of Incorporation to increase the total number of authorized shares of common stock from 80 million to 160 million.

 

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The following nominees were elected to serve on the board of directors:

 

Nonimee

   For    Withheld

John W. Ballantine

   55,421,819    807,482

Rodney L. Brown Jr.

   55,440,501    788,800

David A. Dietzler

   55,443,984    785,316

Peggy Y. Fowler

   55,415,319    813,982

Mark B. Ganz

   55,442,195    787,106

Corbin A. McNeill, Jr.

   55,412,252    817,048

Neil J. Nelson

   55,422,724    806,577

M. Lee Pelton

   55,428,188    801,103

James J. Piro

   55,647,762    581,539

Robert T.F. Reid

   55,128,372    1,100,929

The proposal to ratify the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2009 was approved and received the following votes: For, 56,023,200; Against, 111,022; and Abstain, 96,079.

The proposal to approve the amendment to the Company’s Amended and Restated Articles of Incorporation to increase the total number of authorized shares of common stock to 160,000,000 shares was approved and received the following votes: For, 48,882,028; Against, 7,250,364; and Abstain, 96,908.

There were no other matters submitted to a vote of shareholders during the second quarter of 2009.

 

Item 6. Exhibits.

 

  3.1    Second Amended and Restated Articles of Incorporation of Portland General Electric Company.
  3.2    Sixth Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed May 15, 2009).
  4.1    Sixty-second Supplemental Indenture dated April 1, 2009 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed April 16, 2009).
31.1    Certification of Chief Executive Officer.
31.2    Certification of Chief Financial Officer.
  32    Certifications of Chief Executive Officer and Chief Financial Officer.

Certain instruments defining the rights of holders of other long-term debt of the Company are omitted pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K because the total amount of securities authorized under each such omitted instrument does not exceed 10% of the total consolidated assets of the Company and its subsidiaries. The Company hereby agrees to furnish a copy of any such instrument to the SEC upon request.

 

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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.

 

      PORTLAND GENERAL ELECTRIC COMPANY
     

(Registrant)

Date: July 31, 2009     By:  

/s/ Maria M. Pope

        Maria M. Pope
       

Senior Vice President,

Chief Financial Officer, and Treasurer

        (duly authorized officer and principal financial officer)

 

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