POR 20130331 10Q
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 March 31, 2013

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: 001-5532-99

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 for such shorter period that the registrant was required to submit and post such files). [x] Yes x [ ] No
  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the 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 April 25, 2013 is 75,678,110 shares.
 


Table of Contents     

PORTLAND GENERAL ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2013

TABLE OF CONTENTS


 
 
 
 
 
 
Item 1.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
 
 
 
Item 1.
 
 
 
Item 1A.
 
 
 
Item 6.
 
 
 


2

Table of Contents     

DEFINITIONS

The following abbreviations and acronyms are used throughout this document:

Abbreviation or Acronym
 
Definition
AUT
 
Annual Power Cost Update Tariff
Biglow Canyon
 
Biglow Canyon Wind Farm
Cascade Crossing
 
Cascade Crossing Transmission Project
Colstrip
 
Colstrip Steam Electric Station (coal-fired generating plant)
EPA
 
United States Environmental Protection Agency
FERC
 
Federal Energy Regulatory Commission
IRP
 
Integrated Resource Plan
kV
 
Kilovolt = one thousand volts of electricity
Moody’s
 
Moody’s Investors Service
MW
 
Megawatts
MWa
 
Average megawatts
MWh
 
Megawatt hours
NVPC
 
Net Variable Power Costs
OPUC
 
Public Utility Commission of Oregon
PCAM
 
Power Cost Adjustment Mechanism
PW2
 
Port Westward Unit 2 natural gas-fired generating plant
RFP
 
Request for proposal
S&P
 
Standard and Poor’s Ratings Services
SEC
 
United States Securities and Exchange Commission
Trojan
 
Trojan nuclear power plant


3

Table of Contents     

PART I FINANCIAL INFORMATION

Item 1.
Financial Statements.
 
PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Dollars in millions, except per share amounts)
(Unaudited)

 
Three Months Ended
March 31,
 
2013
 
2012
Revenues, net
$
473

 
$
479

Operating expenses:
 
 
 
Purchased power and fuel
192

 
195

Production and distribution
51

 
53

Administrative and other
54

 
54

Depreciation and amortization
62

 
62

Taxes other than income taxes
27

 
27

Total operating expenses
386

 
391

Income from operations
87

 
88

Other income:
 
 
 
Allowance for equity funds used during construction
2

 
1

Miscellaneous income, net
1

 
3

Other income
3

 
4

Interest expense
25

 
28

Income before income taxes
65

 
64

Income taxes
17

 
15

Net income and Comprehensive income
48

 
49

Less: net loss attributable to noncontrolling interests
(1
)
 

Net income and Comprehensive income attributable to Portland General Electric Company
$
49

 
$
49

 
 
 
 
Weighted-average shares outstanding (in thousands):
 
 
 
Basic
75,608

 
75,423

Diluted
75,699

 
75,443

 
 
 

Earnings per share—basic and diluted
$
0.65

 
$
0.65

Dividends declared per common share
$
0.270

 
$
0.265

 
 
 
 
See accompanying notes to condensed consolidated financial statements.
 
 
 
 


4

Table of Contents     

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(Unaudited)

 
March 31,
2013
 
December 31,
2012
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
33

 
$
12

Accounts receivable, net
144

 
152

Unbilled revenues
76

 
97

Inventories
77

 
78

Margin deposits
33

 
46

Regulatory assets—current
96

 
144

Other current assets
105

 
93

Total current assets
564

 
622

Electric utility plant, net
4,449

 
4,392

Regulatory assets—noncurrent
524

 
524

Nuclear decommissioning trust
38

 
38

Non-qualified benefit plan trust
32

 
32

Other noncurrent assets
54

 
62

Total assets
$
5,661

 
$
5,670

 
 
 
 
See accompanying notes to condensed consolidated financial statements.



5

Table of Contents     

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS, continued
(Dollars in millions)
(Unaudited)

 
March 31,
2013
 
December 31,
2012
LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
77

 
$
98

Liabilities from price risk management activities—current
91

 
127

Short-term debt

 
17

Current portion of long-term debt
100

 
100

Accrued expenses and other current liabilities
192

 
179

Total current liabilities
460

 
521

Long-term debt, net of current portion
1,536

 
1,536

Regulatory liabilities—noncurrent
782

 
765

Deferred income taxes
586

 
588

Unfunded status of pension and postretirement plans
249

 
247

Non-qualified benefit plan liabilities
103

 
102

Asset retirement obligations
93

 
94

Liabilities from price risk management activities—noncurrent
78

 
73

Other noncurrent liabilities
16

 
14

Total liabilities
3,903

 
3,940

Commitments and contingencies (see notes)

 

Equity:
 
 
 
Portland General Electric Company shareholders’ equity:
 
 
 
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2013 and December 31, 2012

 

Common stock, no par value, 160,000,000 shares authorized; 75,677,181 and 75,556,272 shares issued and outstanding as of
March 31, 2013 and December 31, 2012, respectively
841

 
841

Accumulated other comprehensive loss
(6
)
 
(6
)
Retained earnings
922

 
893

Total Portland General Electric Company shareholders’ equity
1,757

 
1,728

Noncontrolling interests’ equity
1

 
2

Total equity
1,758

 
1,730

Total liabilities and equity
$
5,661

 
$
5,670

 
See accompanying notes to condensed consolidated financial statements.



6

Table of Contents     

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)

 
Three Months Ended March 31,
 
2013
 
2012
Cash flows from operating activities:
 
 
 
Net income
$
48

 
$
49

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
62

 
62

(Decrease) increase in net liabilities from price risk management activities
(37
)
 
21

Regulatory deferral—price risk management activities
37

 
(22
)
Deferred income taxes
13

 
24

Pension and other postretirement benefits
10

 
7

Regulatory deferral of settled derivative instruments
5

 
2

Decoupling mechanism deferrals, net of amortization
(5
)
 
3

Power cost deferrals, net of amortization
(2
)
 
3

Allowance for equity funds used during construction
(2
)
 
(1
)
Other non-cash income and expenses, net
10

 
7

Changes in working capital:
 
 
 
Decrease in receivables
29

 
9

Decrease (increase) in margin deposits, net
13

 
(18
)
Income tax refund received

 
8

Decrease in payables and accrued liabilities
(4
)
 
(18
)
Other working capital items, net
(12
)
 
(24
)
Other, net

 
(2
)
Net cash provided by operating activities
165

 
110

Cash flows from investing activities:
 
 
 
Capital expenditures
(108
)
 
(69
)
Proceeds from sale of solar power facility

 
10

Sales of nuclear decommissioning trust securities
8

 
7

Purchases of nuclear decommissioning trust securities
(9
)
 
(7
)
Other, net
2

 
1

Net cash used in investing activities
(107
)
 
(58
)
 
 
 
 
See accompanying notes to condensed consolidated financial statements.



7

Table of Contents     

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued
(In millions)
(Unaudited)

 
Three Months Ended March 31,
 
2013
 
2012
Cash flows from financing activities:
 
 
 
Maturities of commercial paper, net
$
(17
)
 
$
(30
)
Dividends paid
(20
)
 
(20
)
Net cash used in financing activities
(37
)
 
(50
)
Increase in cash and cash equivalents
21

 
2

Cash and cash equivalents, beginning of period
12

 
6

Cash and cash equivalents, end of period
$
33

 
$
8

 
 
 
 
Supplemental cash flow information is as follows:
 
 
 
Cash paid for interest, net of amounts capitalized
$
13

 
$
13

Non-cash investing and financing activities:
 
 
 
Accrued dividends payable
20

 
21

Accrued capital additions
11

 
8

Preliminary engineering transferred to Construction work in progress from Other noncurrent assets
4

 

 
See accompanying notes to condensed consolidated financial statements.




8

Table of Contents



PORTLAND GENERAL ELECTRIC COMPANY
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, transmission, distribution, and retail sale of electricity. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in order to obtain reasonably-priced power for its retail customers. 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 are located in Portland, Oregon and its service area is located entirely within the state of Oregon. PGE’s service area includes 52 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of approximately 4,000 square miles. As of March 31, 2013, PGE served 829,898 retail customers with a service area population of approximately 1.7 million, comprising approximately 44% of the state’s population.

Condensed Consolidated Financial Statements

These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States 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 month periods ended March 31, 2013 and 2012 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, 2012 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2012, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 22, 2013, and should be read in conjunction with such condensed consolidated financial statements.

Comprehensive Income

PGE had no material components of other comprehensive income to report for the three month periods ended March 31, 2013 and 2012.

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 gain or loss contingencies, 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.


9

Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


Reclassifications

To conform with the 2013 presentation, PGE has separately presented Pension and other postretirement benefits of $7 million from Other non-cash income and expenses, net, and separately presented Decoupling mechanism deferrals, net of amortization of $3 million and Regulatory deferral of settled derivative instruments of $2 million from Other, net in the operating activities section of the condensed consolidated statement of cash flows for the three months ended March 31, 2012.

Recent Accounting Pronouncements

Accounting Standards Update (ASU) 2011-11, Balance Sheet (Topic 210) - Disclosures about Offsetting Assets and Liabilities (ASU 2011-11), requires an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. In addition, ASU 2013-01, Balance Sheet (Topic 210) - Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2013-01), was issued in January 2013 and clarifies that the scope of ASU 2011-11 applies to financial instruments accounted for in accordance with Topic 815, Derivatives and Hedging. Both ASUs are effective January 1, 2013 for the Company, and require retrospective application. PGE adopted the amendments contained in ASU 2011-11 and ASU 2013-01 on January 1, 2013, which did not have an impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows. See Note 4, Price Risk Management, for the additional disclosures made pursuant to the adoption of these ASUs.

NOTE 2: BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable is net of an allowance for uncollectible accounts of $6 million as of March 31, 2013 and $5 million as of December 31, 2012.

The activity in the allowance for uncollectible accounts is as follows (in millions):

 
Three Months Ended March 31,
 
2013
 
2012
Balance as of beginning of period
$
5

 
$
6

Provision, net
2

 
1

Amounts written off, less recoveries
(1
)
 
(1
)
Balance as of end of period
$
6

 
$
6

 
Inventories

PGE inventories are recorded at average cost and consist primarily of materials and supplies for use in operations, maintenance, and capital activities and fuel for use in generating plants. Fuel inventories include natural gas, coal, and oil. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market.


10

Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


Other Current Assets

Other current assets consist of the following (in millions):

 
March 31,
2013
 
December 31, 2012
Prepaid expenses
$
51

 
$
37

Current deferred income tax asset
38

 
51

Assets from price risk management activities
11

 
4

Other
5

 
1

Other current assets
$
105

 
$
93


Electric Utility Plant, Net

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

 
March 31,
2013
 
December 31,
2012
Electric utility plant
$
6,850

 
$
6,811

Construction work in progress
201

 
140

Total cost
7,051

 
6,951

Less: accumulated depreciation and amortization
(2,602
)
 
(2,559
)
Electric utility plant, net
$
4,449

 
$
4,392


Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $156 million and $151 million as of March 31, 2013 and December 31, 2012, respectively. Amortization expense related to intangible assets was $5 million for the three months ended March 31, 2013 and 2012.

In January 2012, PGE completed construction of a $10 million, 1.75 MW solar powered electric generating facility, which was sold to, and simultaneously leased-back from, a financial institution. The Company operates the facility and receives 100% of the power generated by the facility.


11

Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


Regulatory Assets and Liabilities

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

 
March 31, 2013
 
December 31, 2012
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Regulatory assets:
 
 
 
 
 
 
 
Price risk management
$
80

 
$
77

 
$
123

 
$
71

Pension and other postretirement plans

 
314

 

 
321

Deferred income taxes

 
78

 

 
80

Deferred broker settlements
15

 
1

 
20

 
1

Debt reacquisition costs

 
20

 

 
22

Deferred capital projects

 
19

 

 
16

Other
1

 
15

 
1

 
13

Total regulatory assets
$
96

 
$
524

 
$
144

 
$
524

Regulatory liabilities:
 
 
 
 
 
 
 
Asset retirement removal costs
$

 
$
706

 
$

 
$
692

Asset retirement obligations

 
40

 

 
39

Power cost adjustment mechanism
4

 

 
6

 

Other
7

 
36

 
6

 
34

Total regulatory liabilities
$
11

(1) 
$
782

 
$
12

(1) 
$
765


(1) Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.

Accrued expenses and other current liabilities

Accrued expenses and other current liabilities consist of the following (in millions):

 
March 31,
2013
 
December 31, 2012
Accrued employee compensation and benefits
$
36

 
$
46

Accrued interest payable
33

 
23

Accrued taxes payable
30

 
21

Accrued dividends payable
20

 
21

Regulatory liabilities—current
11

 
12

Other
62

 
56

Total accrued expenses and other current liabilities
$
192

 
$
179



12

Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


Credit Facilities

PGE has the following unsecured revolving credit facilities as of March 31, 2013:

A $400 million syndicated credit facility, which is scheduled to terminate in November 2017; and

A $300 million syndicated credit facility, which is scheduled to terminate in December 2016.

Pursuant to the individual terms of the agreements, both credit facilities may be used for general corporate purposes and as backup for commercial paper borrowings, and also permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. Both credit facilities require annual fees based on PGEs unsecured credit ratings, and 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 March 31, 2013, PGE was in compliance with this requirement with a 48.2% debt to total capital ratio.

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 credit facilities.

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt up to $700 million through February 6, 2014. The authorization provides that if utility assets financed by unsecured debt are divested, then a proportionate share of the unsecured debt must also be divested.
 
PGE classifies borrowings under the revolving credit facilities and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets. As of March 31, 2013, PGE had no borrowings or commercial paper outstanding, $52 million of letters of credit issued, and aggregate unused credit available of $648 million under the credit facilities.

Pension and Other Postretirement Benefits

Components of net periodic benefit cost are as follows (in millions):

 
Three Months Ended March 31,
 
Defined Benefit
Pension Plan
 
Other Postretirement
Benefits
 
Non-Qualified
Benefit Plans
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Service cost
$
4

 
$
3

 
$
1

 
$
1

 
$

 
$

Interest cost
8

 
8

 
1

 
1

 

 
1

Expected return on plan assets
(10
)
 
(10
)
 

 

 

 

Amortization of net actuarial loss
6

 
4

 

 

 

 

Net periodic benefit cost
$
8

 
$
5

 
$
2

 
$
2

 
$

 
$
1



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Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


NOTE 3: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s condensed consolidated balance sheets, for which it is practicable to estimate fair value as of March 31, 2013 and December 31, 2012, and then classifies these financial assets and liabilities based on a fair value hierarchy. The fair value hierarchy, which contains three broad classification levels, is used to prioritize the inputs to the valuation techniques used to measure fair value. The 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.

Level 2
Pricing inputs include those that are directly or indirectly observable in the marketplace as of the reporting date.

Level 3
Pricing inputs include significant inputs that are unobservable for the asset or liability.

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.

PGE recognizes any transfers between levels in the fair value hierarchy as of the end of the reporting period. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were no significant transfers between levels, except those transfers out of Level 3 to Level 2 presented in this note, during the three month periods ended March 31, 2013 and 2012.


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Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


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

 
As of March 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets:
 
 
 
 
 
 
 
Nuclear decommissioning trust: (1)
 
 
 
 
 
 
 
Money market funds
$

 
$
14

 
$

 
$
14

Debt securities:
 
 
 
 
 
 
 
Domestic government
9

 
7

 

 
16

Corporate credit

 
8

 

 
8

Non-qualified benefit plan trust: (2)
 
 
 
 
 
 
 
Equity securities—Domestic
3

 
3

 

 
6

Debt securities—Domestic government
2

 

 

 
2

Assets from price risk management activities: (1) (3)
 
 
 
 
 
 
 
Electricity

 
5

 

 
5

Natural gas

 
6

 
1

 
7

 
$
14

 
$
43

 
$
1

 
$
58

Liabilities from price risk management
activities: (1) (3)
 
 
 
 
 
 
 
Electricity
$

 
$
42

 
$
36

 
$
78

Natural gas

 
81

 
10

 
91

 
$

 
$
123

 
$
46

 
$
169

 
(1)
Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.
(2)
Excludes insurance policies of $24 million, which are recorded at cash surrender value.
(3)
For further information, see Note 4, Price Risk Management.


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Table of Contents
PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


 
As of December 31, 2012
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets:
 
 
 
 
 
 
 
Nuclear decommissioning trust: (1)
 
 
 
 
 
 
 
Money market funds
$

 
$
15

 
$

 
$
15

Debt securities:
 
 
 
 
 
 
 
Domestic government
7

 
8

 

 
15

Corporate credit

 
8

 

 
8

Non-qualified benefit plan trust: (2)
 
 
 
 
 
 
 
Money market funds

 
2

 

 
2

Equity securities:
 
 
 
 
 
 
 
Domestic
2

 
2

 

 
4

International
1

 

 

 
1

Debt securities—Domestic government
2

 

 

 
2

Assets from price risk management activities: (1) (3)
 
 
 
 
 
 
 
Electricity

 
1

 

 
1

Natural gas

 
3

 
2

 
5

 
$
12

 
$
39

 
$
2

 
$
53

Liabilities — Liabilities from price risk management activities: (1) (3)
 
 
 
 
 
 
 
Electricity
$

 
$
72

 
$
10

 
$
82

Natural gas

 
110

 
8

 
118

 
$

 
$
182

 
$
18

 
$
200

 
(1)
Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.
(2)
Excludes insurance policies of $23 million, which are recorded at cash surrender value.
(3)
For further information, see Note 4, Price Risk Management.

Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan trusts are recorded at fair value in PGE’s consolidated balance sheets and invested in securities that are exposed to interest rate, credit and market volatility risks. These assets are classified within Level 1, 2 or 3 based on the following factors:
 
Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. Money market funds are classified as Level 2 in the fair value hierarchy as the securities are traded in active markets of similar securities but are not directly valued using quoted market prices.
 
Debt securities—PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date.
 
Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in

16

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation as applicable.

Equity securities—Certain equity mutual fund and common stock securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE). Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy as pricing inputs are directly or indirectly observable in the marketplace as of the reporting date.

Assets and liabilities from price risk management activities are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of derivative instruments entered into by the Company to manage exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net power costs for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 4, Price Risk Management.
 
For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as quoted forward prices for commodities and interest rates. 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 over-the-counter forwards and swaps.
 
Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term over-the-counter swap derivatives.
Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities as of March 31, 2013 is presented below:

 
 
Fair Value
 
 
 
 
 
Price per Unit
Commodity Contracts
 
Assets
 
Liabilities
 
Valuation Technique
 
Significant Unobservable Input
 
Low
 
High
 
Weighted Average
 
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Natural gas financial swaps
 
$
1

 
$
10

 
Discounted cash flow
 
Natural gas forward price (per Decatherm)
 
$
3.58

 
$
5.02

 
$
4.20

Electricity financial swaps
 

 
12

 
Discounted cash flow
 
Electricity forward price (per MWh)
 
7.32

 
48.59

 
39.65

Electricity physical forward purchase
 

 
24

 
Discounted cash flow
 
Electricity forward price (per MWh)
 
41.22

 
43.74

 
42.60

 
 
$
1

 
$
46

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities as of December 31, 2012 is presented below:
 
 
Fair Value
 
 
 
 
 
Price per Unit
Commodity Contracts
 
Assets
 
Liabilities
 
Valuation Technique
 
Significant Unobservable Input
 
Low
 
High
 
Weighted Average
 
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Natural gas financial swaps
 
$
2

 
$
8

 
Discounted cash flow
 
Natural gas forward price (per Decatherm)
 
$
3.67

 
$
5.21

 
$
4.28

Electricity financial swaps
 

 
10

 
Discounted cash flow
 
Electricity forward price (per MWh)
 
7.12

 
51.72

 
41.14

 
 
$
2

 
$
18

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. These inputs employ the mid-point of the market’s bid-ask spread and are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These inputs are validated against nonbinding quotes from brokers with whom the Company transacts. In addition, changes in the fair value measurement from price risk management assets and liabilities are analyzed and reviewed on a monthly basis by the Company’s Risk Management group. This process includes analytical review of changes in commodity prices as well as procedures to analyze and identify the reasons for the changes over specific reporting periods.

The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and the Company’s position as either the buyer or seller of the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Significant Unobservable Input
 
Position
 
Change to Input
 
Impact on Fair Value Measurement
Market price
 
Buy
 
Increase (decrease)
 
Gain (loss)
Market price
 
Sell
 
Increase (decrease)
 
Loss (gain)
 
 
 
 
 
 
 


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions):
 
 
Three Months Ended March 31,
 
 
2013
 
2012
Balance as of the beginning of the period
 
$
16

 
$
79

Net realized and unrealized losses (1)
 
5

 
18

Purchases
 
24

 

Issuances
 

 
(1
)
Transfers out of Level 3 to Level 2
 

 
(1
)
Balance as of the end of the period
 
$
45

 
$
95

 
(1)
Contains nominal amounts of realized losses, net. Both realized and unrealized (gains) losses are recorded in Purchased power and fuel expense in the condensed consolidated statements of income of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions.

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the three month period ended March 31, 2013, there were no transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its financial instruments. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.
 
Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of long-term debt is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for similar issues or on the current rates offered to PGE for debt of similar remaining maturities. As of March 31, 2013, the estimated aggregate fair value of PGE’s long-term debt was $1,921 million, compared to its $1,636 million carrying amount. As of December 31, 2012, the estimated aggregate fair value of PGE’s long-term debt was $1,949 million, compared to its $1,636 million carrying amount.

NOTE 4: PRICE RISK MANAGEMENT
 
PGE participates in the wholesale marketplace in order to balance its supply of power, which consists of its own generation 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 fuel and power purchases and sales resulting from economic dispatch decisions for Company-owned generation. As a result, PGE is exposed to commodity price risk and foreign currency exchange rate risk, from which changes in prices and/or rates may affect the Company’s financial position, results of operations, or cash flows.

PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign currency exchange rate risk in order to reduce volatility in net power costs for its retail customers. These derivative instruments may include forward, futures, swap, and option contracts for electricity, natural gas, oil, and foreign currency, which are recorded at fair value on the condensed consolidated balance sheets, with changes in fair value recorded in the condensed consolidated statements of income. In accordance with the ratemaking and cost recovery process authorized by the Public Utility Commission of Oregon (OPUC), PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative instruments until realized. This accounting treatment defers the fair value

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


gains and losses on derivative instruments until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as purely economic hedges. The Company does not engage in trading activities for non-retail purposes.

PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions):

 
March 31,
2013
 
December 31,
2012
 
Current assets:
 
 
 
 
Commodity contracts:
 
 
 
 
Electricity
$
5

 
$
1

 
Natural gas
6

 
3

 
Total current derivative assets
11

(1) 
4

(1) 
Noncurrent assets:
 
 
 
 
Commodity contracts—Natural gas
1

(2) 
2

(2) 
Total derivative assets not designated as hedging instruments
$
12

 
$
6

 
Total derivative assets
$
12

 
$
6

 
Current liabilities:
 
 
 
 
Commodity contracts:
 
 
 
 
Electricity
$
31

 
$
44

 
Natural gas
60

 
83

 
Total current derivative liabilities
91

 
127

 
Noncurrent liabilities:
 
 
 
 
Commodity contracts:
 
 
 
 
Electricity
47

 
38

 
Natural gas
31

 
35

 
Total noncurrent derivative liabilities
78

 
73

 
Total derivative liabilities not designated as hedging instruments
$
169

 
$
200

 
Total derivative liabilities
$
169

 
$
200

 
 
(1)
Included in Other current assets on the condensed consolidated balance sheets.
(2)
Included in Other noncurrent assets on the condensed consolidated balance sheet.

PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle through 2016, were as follows (in millions):

 
March 31, 2013
 
December 31, 2012
Commodity contracts:
 
 
 
 
 
Electricity
13

MWh
 
11

MWh
Natural gas
87

Decatherms
 
86

Decatherms
Oil
3

Gallons
 

Gallons
Foreign currency
$
8

Canadian
 
$
7

Canadian


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


PGE has elected to report gross on the balance sheet the positive and negative exposures resulting from derivative instruments with counterparties under agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, these agreements provide for the net settlement of all related contractual obligations with a counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit, which are excluded from the offsetting table presented below.

Information related to Price risk management assets and liabilities subject to master netting agreements is as follows (in millions):

 
 
Gross
 
Gross
 
Net
 
Gross Amounts Not Offset in
 
 
 
 
Amounts
 
Amounts
 
Amounts
 
Consolidated Balance Sheet
 
 
 
 
Recognized
 
Offset
 
Presented
 
Derivatives
 
Cash Collateral(1)
 
Net Amount
As of March 31, 2013:
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
 
 
 
 
 
Electricity(2)
 
$
1

 
$

 
$
1

 
$
(1
)
 
$

 
$

Natural gas(2)
 
1

 

 
1

 
(1
)
 

 


 
$
2

 
$

 
$
2

 
$
(2
)
 
$

 
$

Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
 
 
 
 
 
Electricity(3)
 
$
12

 
$

 
$
12

 
$
(12
)
 
$

 
$

Natural gas(3)
 
5

 

 
5

 
(5
)
 

 

 
 
$
17

 
$

 
$
17

 
$
(17
)
 
$

 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2012:
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity contracts:
 
 
 
 
 
 
 
 
 
 
 
 
Electricity(3)
 
$
20

 
$

 
$
20

 
$
(20
)
 
$

 
$

Natural gas(3)
 
7

 

 
7

 
(7
)
 

 

 
 
$
27

 
$

 
$
27

 
$
(27
)
 
$

 
$


(1)
As of March 31, 2013 and December 31, 2012, the Company had collateral posted of $11 million and $18 million, respectively, which consists entirely of letters of credit.
(2)
Included in Other current assets and Other noncurrent assets on the condensed consolidated balance sheets.
(3)
Included in Liabilities from price risk management activities—current and Liabilities from price risk management activities—noncurrent.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


Net realized and unrealized (gains) losses on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the condensed consolidated statements of income and were as follows (in millions):

 
Three Months Ended March 31,
 
2013
 
2012
Commodity contracts:
 
 
 
Electricity
$
8

 
$
53

Natural Gas
(8
)
 
36

 
Net unrealized and certain net realized (gains) losses presented in the table above are offset within the consolidated statements of income by the effects of regulatory accounting. Of the net (gains) losses recognized in Net income for the three months ended March 31, 2013 and 2012, net losses of $3 million and $81 million, respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 2013 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):

 
2013
 
2014
 
2015
 
2016
 
Total
Commodity contracts:
 
 
 
 
 
 
 
 
 
Electricity
$
20

 
$
30

 
$
18

 
$
5

 
$
73

Natural gas
50

 
25

 
6

 
3

 
84

Net unrealized loss
$
70

 
$
55

 
$
24

 
$
8

 
$
157

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

The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2013 was $145 million, for which PGE has posted $27 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2013, the cash requirement to either post as collateral or settle the instruments immediately would have been $136 million.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


Counterparties representing 10% or more of Assets and Liabilities from price risk management activities as of March 31, 2013 or December 31, 2012 were as follows:

 
March 31,
2013
 
December 31,
2012
Assets from price risk management activities:
 
 
 
Counterparty A
16
%
 
3
%
Counterparty B
15

 
11

Counterparty C
9

 
13

Counterparty D
9

 
21

Counterparty E
3

 
10

 
52
%
 
58
%
Liabilities from price risk management activities:
 
 
 
Counterparty F
20
%
 
24
%
Counterparty G
14

 

Counterparty H
10

 
14

Counterparty I
7

 
10

 
51
%
 
48
%
 
See Note 3 for additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities.

NOTE 5: EARNINGS PER SHARE

Components of basic and diluted earnings per share were as follows:
 
Three Months Ended March 31,
 
2013
 
2012
Numerator (in millions):
 
 
 
Net income attributable to Portland General Electric
Company common shareholders
$
49

 
$
49

Denominator (in thousands):
 
 
 
Weighted-average common shares outstanding—basic
75,608

 
75,423

Dilutive effect of unvested restricted stock units and
 employee stock purchase plan shares
91

 
20

Weighted-average common shares outstanding—diluted
75,699

 
75,443

Earnings per share—basic and diluted
$
0.65

 
$
0.65


In addition to unvested time-based restricted stock units and employee stock purchase plan shares, unvested performance-based restricted stock units and related dividend equivalent rights are included in the computation of dilutive securities when the required performance goals are met at the end of a three-year performance period. For the three months ended March 31, 2013 and 2012, unvested performance-based restricted stock units and related dividend equivalent rights of 430,824 and 462,413, respectively, were excluded from the dilutive calculation because the performance goals had not been met.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


Basic and diluted earnings per share amounts are calculated based on actual amounts rather than the rounded amounts presented in the table above and on the condensed consolidated statements of income. Accordingly, calculations using the rounded amounts presented for net income and weighted average shares outstanding may yield results that vary from the earnings per share amounts presented in the table above.

NOTE 6: EQUITY

The activity in equity during the three month periods ended March 31, 2013 and 2012 is as follows (dollars in millions):
 
Portland General Electric Company
Shareholders’ Equity
 
 
 
 
Common Stock
 
Accumulated
Other
Comprehensive
Loss
 
Retained
Earnings
 
 
Noncontrolling
Interests’
Equity
 
 
 
 
 
 
Shares
 
Amount
 
 
 
 
Balances as of December 31, 2012
75,556,272

 
$
841

 
$
(6
)
 
$
893

 
 
$
2

Issuance of shares pursuant to equity-based plans
120,909

 

 

 

 
 

Dividends declared

 

 

 
(20
)
 
 

Net income (loss)

 

 

 
49

 
 
(1
)
Balances as of March 31, 2013
75,677,181

 
$
841

 
$
(6
)
 
$
922

 
 
$
1

 
 
 
 
 
 
 
 
 
 
 
Balances as of December 31, 2011
75,362,956

 
$
836

 
$
(6
)
 
$
833

 
 
$
3

Issuance of shares pursuant to equity-based plans
141,624

 

 

 

 
 

Dividends declared

 

 

 
(20
)
 
 

Net income

 

 

 
49

 
 

Balances as of March 31, 2012
75,504,580

 
$
836

 
$
(6
)
 
$
862

 
 
$
3


NOTE 7: CONTINGENCIES

PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.

Loss contingencies are accrued, and disclosed if material, when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate.

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company (i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate, or (ii) discloses that an estimate cannot be made.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period.

The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) there are significant facts in dispute; vi) there are a large number of parties (including where it is uncertain how liability, if any, will be shared among multiple defendants); or vii) there is a wide range of potential outcomes. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.  

Trojan Investment Recovery

Regulatory Proceedings. In 1993, PGE closed the Trojan nuclear power plant (Trojan) and sought full recovery of, and a rate of return on, its Trojan 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.

Numerous challenges and appeals were subsequently filed in various state courts on the issue of the OPUC’s authority under Oregon law to grant recovery of, and a return on, the Trojan investment. In 1998, the Oregon Court of Appeals upheld the OPUC’s order authorizing PGE’s recovery of the Trojan investment, but held that the OPUC did not have the authority to allow the Company to recover a return on the Trojan investment and remanded the case to the OPUC for reconsideration.

In 2000, PGE entered into agreements to settle the litigation related to recovery of, and return on, its investment in Trojan. The settlement, which was approved by the OPUC, allowed PGE to remove from its balance sheet the remaining investment in Trojan as of September 30, 2000, along with several largely offsetting regulatory liabilities. After offsetting the investment in Trojan with these liabilities, the remaining Trojan regulatory asset balance of approximately $5 million (after tax) was expensed. As a result of the settlement, PGE’s investment in Trojan was no longer included in prices charged to customers, either through a return of or a return on that investment. The Utility Reform Project (URP) did not participate in the settlement and filed a complaint with the OPUC challenging the settlement agreements. In 2002, the OPUC issued an order (2002 Order) denying all of the URP’s challenges. In 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.

The OPUC then issued an order in 2008 (2008 Order) that required PGE to provide refunds, including interest from September 30, 2000, to customers who received service from the Company during the period from October 1, 2000 to September 30, 2001. The Company recorded a charge of $33.1 million in 2008 related to the refund and accrued additional interest expense on the liability until refunds to customers were completed in the first quarter of 2010. The URP and the plaintiffs in the class actions described below separately appealed the 2008 Order to the Oregon Court of Appeals. On February 6, 2013, the Oregon Court of Appeals issued an opinion that upheld the 2008 Order. However, on April 3, 2013, the plaintiffs filed for reconsideration of the Court of Appeals’ February 6, 2013 decision.


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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


Class Actions. In two separate legal proceedings, lawsuits were filed in Marion County Circuit Court against PGE in 2003 on behalf of two classes of electric service customers. The class action lawsuits seek damages totaling $260 million, plus interest, as a result of the Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan.

In 2006, the Oregon Supreme Court issued a ruling ordering the abatement of the class action proceedings until the OPUC responded to the 2002 Order (described above). The Oregon Supreme Court concluded that the OPUC has primary jurisdiction to determine what, if any, remedy can be offered to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment that the Company collected in prices.

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 added 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 Marion County Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. The Marion County Circuit Court subsequently abated the class actions in response to the ruling of the Oregon Supreme Court.

As noted above, on February 6, 2013, the Oregon Court of Appeals issued an opinion that upheld the 2008 Order. On April 3, 2013, the plaintiffs filed for reconsideration of the Court of Appeals’ February 6, 2013 decision. Because the plaintiffs’ request for reconsideration, and the class actions described above, remain pending, management believes that it is reasonably possible that the regulatory proceedings and class actions could result in a loss to the Company in excess of the amounts previously recorded and discussed above. Because these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine PGE’s potential liability, if any, or to estimate a range of potential loss.

Pacific Northwest Refund Proceeding

In 2001, the FERC called for a 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 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).

In August 2007, the Ninth Circuit issued a 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 the evidence 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. After denying requests for rehearing, the Ninth Circuit in April 2009 issued a mandate giving immediate effect to its August 2007 order remanding the case to the FERC.
 
In October 2011, the FERC issued an Order on Remand, establishing an evidentiary hearing to determine whether any seller had engaged in unlawful market activity in the Pacific Northwest spot markets during the December 25, 2000 through June 20, 2001 period by violating specific contracts or tariffs, and, if so, whether a direct connection existed between the alleged unlawful conduct and the rate charged under the applicable contract. The FERC held that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this

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PORTLAND GENERAL ELECTRIC COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
(Unaudited)


proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome before a refund could be ordered. The FERC directed the presiding judge, if necessary, to determine a refund methodology and to calculate refunds, but held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Certain parties claiming refunds filed requests for rehearing of the Order on Remand.

In December 2012, the FERC issued an order granting an interlocutory appeal of the trial judge’s ruling on the scope of the remand proceeding. In this order, the FERC held that its Order on Remand was not intended to alter the general state of the law regarding the Mobile-Sierra presumption. The FERC clarified that the Mobile-Sierra presumption could be overcome either by: i) a showing that a respondent had violated a contract or tariff and that the violation had a direct connection to the rate charged under the applicable contract; or ii) a showing that the contract rate at issue imposed an excessive burden or seriously harmed the public interest.

On April 5, 2013, and subject to its December 2012 clarification in the interlocutory appeal, the FERC denied rehearing requests from refund proponents that had contested the FERC’s use of the Mobile-Sierra standard in the remand proceeding, its denial of a market-wide remedy, and the restraints in the Order on Remand that limited the types of evidence that could be introduced in the hearing. However, the FERC granted rehearing on the issue of the appropriate refund period, holding that parties could pursue refunds for transactions between January 1, 2000 and December 24, 2000 under Section 309 of the Federal Power Act by showing violations of a filed tariff or rate schedule or of a statutory requirement. On April 11, 2013, the California Attorney General and the California Public Utilities Commission filed an appeal of the Order on Remand and the Order on Rehearing with the Ninth Circuit.

In its October 2011 Order on Remand, the FERC ordered settlement discussions to be convened before a FERC settlement judge. Pursuant to the settlement proceedings, the Company received notice of two claims and has reached agreements to settle both claims for an immaterial amount. The FERC approved both settlements during 2012.

Additionally, the settlement between PGE and certain other parties in the California refund case in Docket No. EL00-95, et seq., approved by the FERC in May 2007, resolved all claims between PGE and the California parties named in the settlement (including CERS) as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 20, 2001, but did not settle potential claims from other market participants relating to transactions in the Pacific Northwest.

The above-referenced settlements resulted in a release for the Company as a named respondent in the ongoing remand proceedings, which are limited to initial and direct claims for refunds, but there remains a possibility that additional claims related to this matter could be asserted against the Company in future proceedings if refunds are ordered against current respondents.

Management believes that this matter could result in a loss to the Company in future proceedings. However, management cannot predict whether the FERC will order refunds, which contracts would be subject to refunds, the basis on which refunds would be ordered, or how such refunds, if any, would be calculated. Due to these uncertainties, sufficient information is currently not available to determine PGE’s liability, if any, or to estimate a range of reasonably possible loss.

EPA Investigation of Portland Harbor

A 1997 investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) as a federal Superfund site and listed 69 Potentially

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Responsible Parties (PRPs). PGE was included among the PRPs as it has historically owned or operated property near the river. In January 2008, the EPA requested information from various parties, including PGE, concerning additional properties in or near the original segment of the river under investigation as well as several miles beyond. Subsequently, the EPA has listed additional PRPs, which now number over one hundred.

The Portland Harbor site is currently undergoing a remedial investigation (RI) and feasibility study (FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs known as the Lower Willamette Group (LWG), which does not include PGE.

In March 2012, the LWG submitted a draft FS to the EPA for review and approval. The draft FS, along with the RI, provide the framework for the EPA to determine a clean-up remedy for Portland Harbor that will be documented in a Record of Decision, which the EPA is expected to issue in 2015 or 2016.

The draft FS evaluates several alternative clean-up approaches. These approaches would take from two to 28 years with costs ranging from $169 million to $1.8 billion, depending on the selected remedial action levels and the choice of remedy. The draft FS does not address responsibility for the costs of clean-up, allocate such costs among PRPs, or define precise boundaries for the clean-up. Responsibility for funding and implementing the EPAs selected clean-up will be determined after the issuance of the Record of Decision.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties discussed above, sufficient information is currently not available to determine PGE’s liability for the cost of any required investigation or remediation of the Portland Harbor site or to estimate a range of potential loss.

DEQ Investigation of Downtown Reach

The Oregon Department of Environmental Quality (DEQ) has executed a memorandum of understanding with the EPA to administer and enforce clean-up activities for portions of the Willamette River that are upriver from the Portland Harbor Superfund site (the Downtown Reach). In January of 2010, the DEQ issued an order requiring PGE to perform an investigation of certain portions of the Downtown Reach. PGE completed this investigation in December 2011 and entered into a consent order with the DEQ in July 2012 to conduct a feasibility study of alternatives for remedial action for the portions of the Downtown Reach that were included within the scope of PGE’s investigation. It is expected that the feasibility study will be completed by the end of 2013 or early 2014.
Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, because the feasibility study continues, sufficient information is currently not available to determine PGE’s liability for the cost of any required investigation or remediation of the Downtown Reach site or to estimate a range of potential loss.

EPA Investigation of Harbor Oil
 
Harbor Oil, Inc. operated an oil reprocessing business on a site located in north Portland (Harbor Oil) until about 1999. Subsequently, other companies have continued to conduct operations on the site. Until 2003, PGE contracted with the operators of the site to provide used oil from the Company’s power plants and electrical distribution system to the operators for use in their reprocessing business. Other entities continue to utilize Harbor Oil for the reprocessing of used oil and other lubricants.

In September 2003, the EPA included the Harbor Oil site on the National Priority List as a federal Superfund site. PGE received a Notice from the EPA in 2005, in which the Company was named as one of fourteen PRPs with

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respect to Harbor Oil. Subsequently, an AOC was signed by the EPA and six other parties, including PGE, to implement an RI/FS at Harbor Oil. In 2011, the final draft of the RI report was submitted to the EPA.

In March 2012, the EPA approved the RI and stated that it intends to recommend no action on the site, based on the conclusions of the risk assessment conducted under the CERCLA. Following a public notice and comment period, the EPA was expected to issue a final Record of Decision in March 2013, although, to date, it has not done so.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, sufficient information is currently not available to determine PGE’s liability for the cost of any remediation of the Harbor Oil site or to estimate a range of potential loss.

Alleged Violation of Environmental Regulations at Colstrip

On July 30, 2012, PGE received a Notice of Intent to Sue (Notice) for violations of the Clean Air Act (CAA) at Colstrip Steam Electric Station (Colstrip) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). The Notice was also addressed to the other Colstrip co-owners, including PPL Montana, LLC - the operator of Colstrip. PGE has a 20% ownership interest in Units 3 and 4 of Colstrip. The Notice alleges certain violations of the CAA, including New Source Review, Title V, and opacity requirements, and states that the Sierra Club and MEIC will: i) request a United States District Court to impose injunctive relief and civil penalties; ii) require a beneficial environmental project in the areas affected by the alleged air pollution; and iii) seek reimbursement of Sierra Club’s and MEIC’s costs of litigation and attorney’s fees.

Since July 2012, the Sierra Club and MEIC have amended their Notice three times. The first amendment, contained in a letter dated August 30, 2012, asserts that the Colstrip owners violated the Title V air quality operating permit during portions of 2008 and 2009. The second amendment, contained in a letter dated September 27, 2012, asserts that the owners have violated the CAA by failing to timely submit a complete air quality operating permit application to the Montana Department of Environmental Quality (MDEQ). The third amendment, received in December 2012, does not materially alter the prior assertions.

On March 6, 2013, the Sierra Club and MEIC sued the Colstrip co-owners, including PGE, for these and additional alleged violations of various environmental related regulations. The plaintiffs are seeking relief that includes an injunction preventing the co-owners from operating Colstrip except in accordance with the CAA, the Montana State Implementation Plan, and the plant’s federally enforceable air quality permits. In addition, plaintiffs are seeking civil penalties against the co-owners including $32,500 per day for each violation occurring through January 12, 2009, and $37,500 per day for each violation occurring thereafter.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties concerning this matter, PGE cannot predict the outcome or determine whether it would have a material impact on the Company.

Challenge to AOC Related to Colstrip Wastewater Facilities

In August 2012, the operator of Colstrip entered into an AOC with the MDEQ, which established a comprehensive process to investigate and remediate groundwater seepage impacts related to the wastewater facilities at Colstrip. Within five years, under this AOC, the operator of Colstrip is required to provide financial assurance to MDEQ for the costs associated with closure of the waste water treatment facilities. This will establish an obligation for asset retirement, but the operator of Colstrip is unable at this time to estimate these costs, which will require both public and agency review. 


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(Unaudited)


In September 2012, Earthjustice filed an affidavit pursuant to Montana’s Major Facility Siting Act (MFSA) that sought review of the AOC by Montana’s Board of Environmental Review (BER), on behalf of environmental groups Sierra Club, the MEIC, and the National Wildlife Federation. In September 2012, the operator of Colstrip filed an election with the BER to have this proceeding conducted in Montana state district court as contemplated by the MFSA. In October 2012, Earthjustice, on behalf of Sierra Club, the MEIC and the National Wildlife Federation, filed with the Montana state district court a petition for a writ of mandamus and a complaint for declaratory relief alleging that the AOC fails to require the necessary actions under the MFSA and the Montana Water Quality Act with respect to groundwater seepage from the wastewater facilities at Colstrip.

Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties concerning this matter, PGE cannot predict the outcome or determine whether it would have a material impact on the Company.

Revenue Bonds

In 2008, PGE repurchased $5.8 million of Pollution Control Revenue Bonds Series 1996 (Bonds) issued through the Port of Morrow, Oregon. In connection with the repurchase, PGE paid the $5.8 million repurchase price to Lehman Brothers Inc. (Lehman) as remarketing agent for the Bonds, who in turn paid off the beneficial owner of the Bonds. As a result of the payment, PGE became the beneficial owner of the Bonds and requested that Lehman safe-keep the Bonds in Lehman’s Depository Trust Company participant account until such time as the Bonds could be remarketed. After repurchase of the Bonds, PGE removed the liability for the Bonds from its financial statements.

In September 2008, Lehman filed for protection under Chapter 11 of the U.S. Bankruptcy Code. PGE subsequently filed a claim for return of the Bonds from Lehman. In November 2009, the trustee appointed to liquidate the assets of Lehman (Trustee) allowed PGE’s claim as a net equity claim for securities.

It is not certain that the Company will receive the full amount of the Bonds but could, along with other claimants, potentially receive a pro-rata share of certain assets. The timing and extent of distributions on claims are subject to the ultimate disposition of numerous claims in the proceedings and certain major contingencies which the Trustee must resolve. PGE cannot currently estimate how much of the value of the Bonds will ultimately be returned to the Company or the timing of the distribution from Lehman.

Oregon Tax Court Ruling

On September 17, 2012, the Oregon Tax Court issued a ruling contrary to an Oregon Department of Revenue interpretation and a current Oregon administrative rule, regarding the treatment of wholesale electricity sales. The underlying issue is whether electricity should be treated as tangible or intangible property for state income tax apportionment purposes. The Oregon Department of Revenue has appealed the ruling of the Oregon Tax Court to the Oregon Supreme Court. It is uncertain whether the ruling will be upheld, or if the ruling would apply retroactively to all open tax years, which, for PGE, include 2006 through 2012.

If the ruling is upheld, PGE estimates that its income tax liability could increase by as much as $12 million due to the impact of the increased assessment of prior years’ liability and an increase in the tax rate at which deferred tax liabilities would be recognized in future years. Due to the uncertainty concerning the resolution of this matter, PGE cannot predict the outcome. The Company may seek regulatory recovery of any incremental tax, although there can be no guarantee that such recovery would be granted.


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(Unaudited)


Complaint Against U.S. Department of Energy

In 2004, the co-owners of Trojan (PGE, Eugene Water & Electric Board, and PacifiCorp, collectively referred to as Plaintiffs) filed a complaint against the U.S. Department of Energy (USDOE) for failure to accept spent nuclear fuel by January 31, 1998. PGE had contracted with the USDOE for the permanent disposal of spent nuclear fuel in order to allow the final decommissioning of Trojan. The Plaintiffs paid for permanent disposal services during the period of plant operation and have met all other conditions precedent. The Plaintiffs were seeking approximately $112 million in damages incurred through 2009.

A trial before the U.S. Court of Federal Claims commenced in the fourth quarter of 2011 and concluded in early 2012. On November 30, 2012, the U.S. Court of Federal Claims issued a judgment awarding certain damages to the Plaintiffs. The judgment does not state the precise amount of the damages award, but directs the parties to consult and propose a final amount for the Plaintiffs’ recovery that is based on certain adjustments specified in the court’s ruling. The parties continue discussions to determine such final amount. PGE estimates that the total amount of the award, as calculated pursuant to the judgment, will range from approximately $65 million to $75 million. Any award amount would be allocated among the Plaintiffs. The judgment includes damages incurred through 2009. The Plaintiffs may seek damages for subsequent years through a separate legal proceeding. Any proceeds received related to this legal matter would flow to the benefit of customers to offset amounts previously collected from customers in relation to Trojan decommissioning activities.

Other Matters

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

NOTE 8: GUARANTEES

PGE enters into financial agreements and power and natural gas 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 the Company’s historical experience and the evaluation of the specific indemnities. As of March 31, 2013, 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 indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

NOTE 9: VARIABLE INTEREST ENTITIES

PGE has determined that it is the primary beneficiary of three variable interest entities (VIEs) and, therefore, consolidates the VIEs within the Company’s condensed consolidated financial statements. All three arrangements 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. PGE is the Managing Member in each of the Limited Liability Companies (LLCs), holding less than 1% equity interest in each entity, and a financial institution is the Investor Member, holding more than 99% equity interest in each entity. PGE has determined that its interests in these VIEs contain the obligation to

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absorb the variability of the entities that could potentially be significant to the VIEs, and the Company has the power to direct the activities that most significantly affect the entities’ economic performance.

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 it is the primary beneficiary of these LLCs include the following: (i) PGE has the expertise to own and operate electric generating facilities and is authorized to operate the LLCs pursuant to the operating agreements, and, therefore, PGE has control over the most significant activities of the LLCs; (ii) 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 (iii) based on projections prepared in accordance with the operating agreements, PGE expects to absorb a majority of any expected losses of the LLCs.

Included in PGE’s condensed consolidated balance sheets are LLC net assets of $5 million as of March 31, 2013, consisting of Electric utility plant, net, and $6 million as of December 31, 2012, consisting of Cash and cash equivalents of $1 million and Electric utility plant, net of $5 million. These assets can only be used to settle the obligations of the consolidated VIEs.

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 include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions and objectives concerning future operations, business prospects, expected changes in future loads, 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,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” 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 and 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 facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs and capital investments, and current or prospective wholesale and retail competition;

economic conditions that result in decreased demand for electricity, reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial stability of vendors and service providers and elevated levels of uncollectible customer accounts;


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the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements; 

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

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

the failure to complete capital projects on schedule and within budget or the abandonment of capital projects, which could result in the Company’s inability to recover project costs;

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

capital market conditions, including access to capital, interest rate volatility, reductions in demand for investment-grade commercial paper, 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;

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 emissions controls 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;

changes in wholesale prices for fuels, including natural gas, coal, and oil, and the impact of such changes on the Company’s power costs, and changes in the availability and price of wholesale power;

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

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

declines in the fair value of debt and equity securities held for the defined benefit pension plans and other benefit plans, which could result in increased funding requirements for such plans;

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

the effects of climate change, including changes in the environment, which 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;

cyber security attacks, data security breaches, or other malicious acts that cause damage to the Company’s generation and transmission facilities or information technology systems, or result in the release of confidential customer and proprietary information;

employee workforce factors, including a significant number of employees approaching retirement, potential strikes, work stoppages, and transitions in senior management;

political, economic, and financial market conditions;

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

financial or regulatory accounting principles or policies imposed by governing bodies; and

acts of war or terrorism.

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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, 2012, and other periodic and current reports filed with the SEC.

Operating Activities—PGE is a vertically integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity, as well as the wholesale purchase and sale of electricity and natural gas. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its service territory.

The impact of seasonal weather conditions on demand for electricity can cause the Company’s revenues and income from operations to fluctuate from period to period. PGE is a winter-peaking utility that typically experiences its highest retail energy sales during the winter heating season, although a slightly lower peak occurs in the summer that generally results from air conditioning demand. Price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues while the availability and price of purchased power and fuel can affect income from operations.

Customers and Demand—The seasonally adjusted unemployment rate for March 2013 was 7.3% in the Portland, Oregon metropolitan area, down from 7.5% for March 2012. Retail energy deliveries for the first quarter of 2013 decreased 1.3% from the comparable period of 2012 largely as a result of 2013 having one less day in the quarter due to the leap year in 2012 and the impact of relatively warmer weather during the first quarter of 2013 compared to the first quarter of 2012 reducing residential and commercial customer demand. The decline was partially offset by an increase of 4,900 in the average number of total retail customers served since the first quarter of 2012. Energy efficiency and conservation efforts by retail customers continue to influence total deliveries, although the financial impacts to the Company of such efforts are mitigated by the decoupling mechanism.

The following table indicates the average number of retail customers, and corresponding energy deliveries, by customer class, for the periods indicated and includes customers purchasing their energy from Electricity Service Suppliers (ESSs):
 
Three Months Ended March 31,
 
 
 
2013
 
2012
 
% Increase
/(Decrease)in Energy
Deliveries
 
Average
Number of
Customers
 
Retail Energy
Deliveries*
 
Average
Number of
Customers
 
Retail Energy
Deliveries*
 
Residential
726,451

 
2,229

 
722,197

 
2,259

 
(1.3
)%
Commercial
102,765

 
1,787

 
102,169

 
1,839

 
(2.8
)
Industrial
272

 
1,024

 
266

 
1,006

 
1.8

Total
829,488

 
5,040

 
824,632

 
5,104

 
(1.3
)
 
 
 
 
 
 
 
 
 
 
____________________
 *
In thousands of MWh.


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The effects of weather had a minimal impact on energy deliveries when comparing first quarter of 2013 to first quarter of 2012. The additional day due to leap year in 2012 had the effect of decreasing retail deliveries in the first quarter of 2013 by slightly over 1% when compared to the comparable period of 2012. PGE expects an increase in retail energy deliveries toward the lower end of 0.5% to 1.0% for 2013 compared to weather adjusted 2012 level. This includes the effects of energy efficiency and conservation efforts.

Power Operations—To meet the energy needs of its retail customers, the Company utilizes a combination of its own generating resources and wholesale market transactions. Based on numerous factors, including plant availability, customer demand, river flows, wind conditions, and current wholesale prices, PGE makes economic dispatch decisions continuously in an effort to obtain reasonably-priced power for its retail customers. In addition, PGE’s thermal generating plants require varying levels of annual maintenance, during which the respective plant is unavailable to provide power. As a result, the amount of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period. During the first quarters of 2013 and 2012, availability of the plants PGE operates approximated 97% and 99%, respectively, with the availability of Colstrip Units 3 and 4, in which PGE has a 20% ownership interest but does not operate, approximating 97% and 96% for the same periods, respectively.

During the first quarter of 2013, the Company’s generating plants provided approximately 62% of its retail load requirement, compared with 59% in the first quarter of 2012. The increase in the relative volume of power generated to meet the Company’s retail load requirement was primarily due to a decrease in the demand for energy. Decreases in energy received from natural gas-fired and hydro generating resources were more than offset by an increase in coal-fired generation.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects decreased 12% in the first quarter of 2013 compared with the first quarter of 2012. These resources provided approximately 18% of the Company’s retail load requirement for the first quarter of 2013, compared with 19% for the first quarter of 2012. Through March, energy received from these sources fell below projections included in the Company’s Annual Power Cost Update Tariff (AUT) by approximately 3% during 2013, compared with exceeding such projections by 6% during the comparable period of 2012. Such projections, which are finalized with the OPUC in November each year, establish the power cost component of retail prices for the following calendar year and are based, in part, on average regional hydro conditions. Any excess in hydro generation from that projected in the AUT generally displaces power from higher cost sources, while any shortfall is generally replaced with power from higher cost sources. Based on recent forecasts of regional hydro conditions for 2013, energy from hydro resources is expected to be below projections included in the AUT for 2013.

Energy expected to be received from PGE-owned wind generating resources (Biglow Canyon) is projected annually in the AUT and is based on wind studies completed in connection with the permitting of the wind farm. Any excess in wind generation from that projected in the AUT generally displaces power from higher cost sources, while any shortfall is generally replaced with power from higher cost sources. Energy received from Biglow Canyon fell short of that projected in PGE’s AUT by 11% and 12% in the first quarters of 2013 and 2012, respectively, and provided approximately 5% of the Company’s retail load requirement for both periods.

Pursuant to the Company’s power cost adjustment mechanism (PCAM), customer prices can be adjusted to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC for the year. To the extent actual NVPC is above or below the deadband, the PCAM provides for 90% of the variance to be collected from or refunded to customers, respectively, subject to a regulated earnings test. Pursuant to the regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE of 10%, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues in the Company’s statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. The deadband range is from $15 million below to $30 million above baseline NVPC.


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For the first quarter of 2013, actual NVPC was approximately $1 million below baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2013 is currently estimated to be below the baseline NVPC, but within the deadband range; accordingly, no estimated refund to customers is expected for 2013.

For the first quarter of 2012, actual NVPC was approximately $5 million below baseline NVPC. For 2012, actual NVPC was $17 million below baseline NVPC, and $2 million below the lower deadband threshold, resulting in a potential refund due to customers. However, based on results of the regulated earnings test, no estimated refund to customers was recorded for 2012.

General Rate Case—On February 15, 2013, PGE filed with the OPUC a general rate case, which is based on a 2014 test year (2014 GRC). PGE requested a $105 million increase in annual revenues, representing an approximate 6% overall increase in customer prices. The requested increase includes improvements to existing power plants and wind forecasting, new Clackamas River fish-sorting facilities, a new disaster-preparedness center, technology investments, employee benefits costs and compliance with new federal regulations. In addition, PGE is proposing a capital structure of 50% debt and 50% equity, a return on equity of 10%, a cost of capital of 7.86%, and an average rate base of approximately $3.1 billion.

Regulatory review of the 2014 GRC will continue throughout 2013, with a final order expected to be issued by the OPUC in mid-December 2013. New customer prices are expected to become effective January 1, 2014.

Capital Requirements and Financing—PGE’s capital requirements for 2013 are related primarily to construction costs for Port Westward Unit 2 and ongoing expenditures for the upgrade, replacement, and expansion of transmission, distribution, and generation infrastructure, as well as technology enhancements and expenditures related to hydro licensing and construction. Capital expenditures are expected to approximate $520 million in 2013, which includes $162 million related to the new natural gas-fired capacity resource, Port Westward Unit 2 (PW2), and $8 million related to the Cascade Crossing Transmission Project (Cascade Crossing). This estimate excludes additional costs, described below, that may be required in connection with the outcome of the Company’s request for proposals (RFPs) for energy and renewable resources:

Power Resources—In accordance with PGE’s Integrated Resource Plan (IRP) and pursuant to the OPUC’s competitive bidding guidelines, the Company issued two RFPs during 2012 for additional generation resources—one for capacity and energy (baseload) resources, and one for renewable resources.

In January 2013, PGE’s PW2 flexible generating resource, with an estimated total cost of $300 million to $310 million, excluding the Allowance for funds used during construction (AFDC), was selected as the successful bid for the capacity resource in the RFP for capacity and energy resources. The RFP for capacity and energy resources is also seeking approximately 300 MW to 500 MW of baseload energy resources. PGE is in the process of negotiations with the top bidder from the final short list for baseload energy resources. The bids on the final short list include power purchase agreements and PGE-ownership options. The final baseload energy resource selection is expected by mid-2013 and the resource is expected to be available in the 2014 to 2017 timeframe.

In addition, the Company is in the process of negotiating power purchase agreements for seasonal peaking capacity, all pursuant to the capacity and energy RFP in accordance with PGE’s IRP.

The RFP for renewable resources is seeking approximately 100 MWa of renewable resources, which is expected to be available to help meet PGE’s 2015 requirements under Oregon’s renewable energy standard. The Company is in the process of negotiations to secure a renewable power resource from the final short list, with the final resource selection expected by mid-2013. The final short list of bids include both power purchase agreements and PGE-ownership options.

Transmission Capacity—Pursuant to the Company’s IRP, PGE has been in the process of developing new transmission capacity from Boardman, Oregon to Salem, Oregon, under a project known as Cascade Crossing. This project was originally proposed as a 215-mile, 500 kV transmission project to help meet

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future electricity demand. As PGE worked with the Bonneville Power Administration (BPA) in the formulation of the project and potential partnerships, the scope of the project has evolved. In January 2013, the Company entered into a Memorandum of Understanding (MOU) with BPA to pursue modifications to PGE’s originally proposed project. Under the MOU proposal, the transmission line would terminate at a new substation called Pine Grove, near Maupin, Oregon (approximately midway between Boardman and Salem), eliminating the need for construction of approximately 101 miles of the originally proposed transmission line. The MOU also provides that the parties will: (i) explore opportunities for PGE to invest in upgrades to BPA’s system; (ii) analyze the possibility of asset exchanges; and (iii) work together to determine the feasibility of additional transmission projects under which PGE could obtain additional capacity between Boardman, Oregon and the Willamette Valley. Subject to the outcome of negotiations with BPA and continued evaluation of regional transmission needs and timing, such investments and conveyances could provide a total of up to 2,600 MWs of transmission capacity that could be staged to come on-line in phases as needed. Because the discussions between PGE and BPA under the MOU are not binding and involve complex issues and the considerations of various options, there is no assurance that the project will be constructed, or will contain all of, or be limited by, the elements described in the MOU.

Construction of the new transmission line from Boardman to the Pine Grove substation could start as early as 2017, with an estimated construction period of at least two years. Because the modified proposal remains under discussion, the estimated total costs and timeline of the project have not yet been determined. However, PGE expects the cost of the full project scope, as described in the MOU, would be at least $800 million. As of March 31, 2013, approximately $50 million is included in Construction work in progress (CWIP) related to this project. For further information related to Cascade Crossing, see “Integrated Resource Plan” within the Liquidity and Capital Resources section this Item 2.

For 2013, PGE expects to fund estimated capital requirements and contractual maturities of $100 million of long-term debt with cash from operations, short-term debt, or long-term financings. Cash from operations is expected to range from $425 million to $435 million for 2013. The Company expects to issue between $50 million and $100 million of First Mortgage Bonds during the second quarter of 2013. The timing and amount of any additional issuances of debt and equity securities will depend primarily on the outcome of the Company’s RFPs for energy and renewable resources, as well as the timing and scope of Cascade Crossing. For further information, see the Capital Requirements section of Liquidity and Capital Resources in this Item 2.

Legal, Regulatory, and Environmental Matters—PGE is a party to certain proceedings, the ultimate outcome of which may have a material impact on the results of operations and cash flows in future reporting periods. Such proceedings include, but are not limited to, the following matters:

Challenges to recovery of the Company’s investment in its closed Trojan plant;

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

An investigation of environmental matters regarding Portland Harbor.

For additional information regarding the above and other matters, see Note 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements.

The following discussion highlights certain regulatory items that have impacted the Company’s revenues, results of operations, or cash flows for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 or affected retail customer prices, as authorized by the OPUC. In some cases, the Company has deferred the related expenses or benefits as regulatory assets or liabilities, respectively, for later amortization and inclusion in customer prices, pending OPUC review and authorization.

Power Costs—Pursuant to the AUT process, PGE files annually an estimate of power costs for the following year. The OPUC issued an order on the 2013 AUT resulting in an estimated 2% decrease in customer prices as a result of expected lower power costs. The new prices became effective January 1, 2013

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and are expected to result in a decrease of approximately $36 million in annual revenues when compared to revenues resulting from prices in effect for 2012.
    
In July 2012, the Company submitted to the OPUC the results of its PCAM for 2011 based on a regulated earnings test, which resulted in a revised refund to customers of approximately $6 million. In October 2012, the OPUC issued an order approving the refund, with the impact to customer prices effective January 1, 2013. For further information, see “Power Operations,” within the Operating Activities section of this Overview, above.

Renewable Resource Costs—Pursuant to a renewable adjustment clause mechanism (RAC), PGE can recover in customer prices prudently incurred costs of renewable resources that are expected to be placed in service in the current year. The Company may submit a filing to the OPUC by April 1st each year, with prices expected to become effective January 1st of the following year. As part of the RAC, the OPUC has authorized the deferral of eligible costs not yet included in customer prices until the January 1st effective date.

In March 2012, PGE submitted a filing for the installation of a small solar facility, which requested a nominal credit to customer prices for a one-year period beginning January 1, 2013, resulting from the gain on the sale and lease-back transaction directly related to the project.

PGE did not submit a RAC filing to the OPUC in 2013 as it is not anticipated that the Company will place renewable resources into service during 2013 beyond any that may result from the still pending Renewable RFP.

Decoupling—The decoupling mechanism is intended to provide for recovery of margin lost as a result of any reduction in electricity sales attributable to energy efficiency and conservation efforts by residential and certain commercial customers. The Company has requested in its 2014 GRC filing that the OPUC extend authorization of the mechanism, which currently expires at the end of 2013, to continue on a permanent basis. The mechanism provides for collection from (or refund to) customers if weather adjusted use per customer is less (or more) than the levels projected in the Company’s most recent general rate case.

For the three months ended March 31, 2013, the Company has recorded an estimated collection of $4 million. Any resulting refund to, or collection from, customers for the 2013 year would begin June 1, 2014.

During 2012, PGE recorded an estimated refund of $1 million that is expected to be provided to customers over a one year period that would begin June 1, 2013, as weather adjusted use per customer was greater than levels projected in the 2011 General Rate Case.

During 2011, PGE recorded an estimated refund of $2 million that is being provided to customers over a one year period that began June 1, 2012, as weather adjusted use per customer was greater than projected levels.

Capital deferral—In the 2011 General Rate Case, the OPUC authorized the Company to defer the costs associated with four capital projects that were not completed at the time the 2011 General Rate Case was approved. A regulatory asset of $15 million was recorded in 2012, for potential recovery in customer prices, subject to an earnings test, with an offsetting credit to Depreciation and amortization expense. The Company expects to submit a filing to the OPUC by mid-2013 for recovery of the deferral, with a resulting tariff effective January 1, 2014. In the first quarter of 2013, the Company deferred an additional $5 million of costs.

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, 2012, filed with the SEC on February 22, 2013.

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Results of Operations

The following table contains condensed consolidated statements of income information for the periods presented (dollars in millions):
 
Three Months Ended
March 31,
 
2013
 
2012
Revenues, net
$
473

 
100
 %
 
$
479

 
100
%
Purchased power and fuel
192

 
41

 
195

 
41

Gross margin
281

 
59

 
284

 
59

Operating expenses:
 
 
 
 
 
 
 
Production and distribution
51

 
11

 
53

 
11

Administrative and other
54

 
11

 
54

 
11

Depreciation and amortization
62

 
13