Edgar Filing: PORTLAND GENERAL ELECTRIC CO /OR/

Significant Unobservable Input

Change to Input

Impact on Fair Value Measurement

Market price

Increase (decrease)

Gain (loss)

Market price

Increase (decrease)

Loss (gain)

10-Q

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, 2016



[ ]	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 15, 2016 is 88,900,756 shares.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED March 31, 2016

TABLE OF CONTENTS



Definitions		3

PART I — FINANCIAL INFORMATION

Item 1.	Financial Statements	4

	Condensed Consolidated Statements of Income and Comprehensive Income	4

	Condensed Consolidated Balance Sheets	5

	Condensed Consolidated Statements of Cash Flows	7

	Notes to Condensed Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50

Item 4.	Controls and Procedures	50

PART II — OTHER INFORMATION

Item 1.	Legal Proceedings	51

Item 1A.	Risk Factors	51

Item 5.	Other Information	54

Item 6.	Exhibits	53

SIGNATURE		55

Table of Contents

DEFINITIONS

The following abbreviations and acronyms are used throughout this document:



Abbreviation or Acronym		Definition
AFDC		Allowance for funds used during construction
AUT		Annual Power Cost Update Tariff
Biglow Canyon		Biglow Canyon Wind Farm
Carty		Carty Generating Station natural gas-fired generating plant
Colstrip		Colstrip Units 3 and 4 coal-fired generating plant
CWIP		Construction work-in-progress
EFSA		Equity forward sale agreement
EPA		United States Environmental Protection Agency
ESS		Electricity Service Supplier
FERC		Federal Energy Regulatory Commission
FMBs		First Mortgage Bonds
GRC		General Rate Case
IRP		Integrated Resource Plan
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
PW1		Port Westward Unit 1 natural gas-fired generating plant
PW2		Port Westward Unit 2 natural gas-fired flexible capacity generating plant
RPS		Renewable Portfolio Standard
S&P		Standard and Poor’s Ratings Services
SEC		United States Securities and Exchange Commission
Tucannon River		Tucannon River Wind Farm
Trojan		Trojan nuclear power plant

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,
	2016			2015
Revenues, net	$	487		$	473
Operating expenses:
Purchased power and fuel	149			161
Generation, transmission and distribution	66			62
Administrative and other	61			60
Depreciation and amortization	82			75
Taxes other than income taxes	30			30
Total operating expenses	388			388
Income from operations	99			85
Interest expense, net	27			30
Other income:
Allowance for equity funds used during construction	7			4
Miscellaneous income (expense), net	(1		)	1
Other income, net	6			5
Income before income tax expense	78			60
Income tax expense	17			10
Net income and Comprehensive income	$	61		$	50

Weighted-average shares outstanding (in thousands):
Basic	88,833			78,271
Diluted	88,833			81,466

Earnings per share:
Basic	$	0.68		$	0.64
Diluted	$	0.68		$	0.62

Dividends declared per common share	$	0.30		$	0.28

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)



	March 31, 2016		December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents	$	4	$	4
Accounts receivable, net	130		158
Unbilled revenues	77		95
Inventories	82		83
Regulatory assets—current	131		129
Other current assets	113		88
Total current assets	537		557
Electric utility plant, net	6,160		6,012
Regulatory assets—noncurrent	526		524
Nuclear decommissioning trust	41		40
Non-qualified benefit plan trust	32		33
Other noncurrent assets	48		44
Total assets	$	7,344	$	7,210

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(In millions)

(Unaudited)



	March 31, 2016			December 31, 2015
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	98		$	98
Liabilities from price risk management activities—current	142			130
Short-term debt	—			6
Current portion of long-term debt	—			133
Accrued expenses and other current liabilities	268			259
Total current liabilities	508			626
Long-term debt, net of current portion	2,199			2,060
Regulatory liabilities—noncurrent	938			928
Deferred income taxes	646			632
Unfunded status of pension and postretirement plans	261			259
Liabilities from price risk management activities—noncurrent	161			161
Asset retirement obligations	152			151
Non-qualified benefit plan liabilities	106			106
Other noncurrent liabilities	82			29
Total liabilities	5,053			4,952
Commitments and contingencies (see notes)
Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2016 and December 31, 2015	—			—
Common stock, no par value, 160,000,000 shares authorized; 88,899,359 and 88,792,751 shares issued and outstanding as of March 31, 2016 and December 31, 2015, respectively	1,195			1,196
Accumulated other comprehensive loss	(8		)	(8		)
Retained earnings	1,104			1,070
Total equity	2,291			2,258
Total liabilities and equity	$	7,344		$	7,210

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)



	Three Months Ended March 31,
	2016			2015
Cash flows from operating activities:
Net income	$	61		$	50
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	82			75
Increase in net liabilities from price risk management activities	2			53
Regulatory deferrals—price risk management activities	(2		)	(53		)
Deferred income taxes	14			10
Pension and other postretirement benefits	7			9
Allowance for equity funds used during construction	(7		)	(4		)
Other non-cash income and expenses, net	4			5
Changes in working capital:
Decrease in accounts receivable and unbilled revenues	46			37
Decrease (increase) in inventories	1			(13		)
Increase in margin deposits, net	(7		)	(9		)
Decrease in accounts payable and accrued liabilities	(11		)	(1		)
Other working capital items, net	(16		)	(20		)
Other, net	(13		)	(5		)
Net cash provided by operating activities	161			134
Cash flows from investing activities:
Capital expenditures	(131		)	(178		)
Sales tax refund received related to Tucannon River Wind Farm	—			12
Sales of Nuclear decommissioning trust securities	6			4
Purchases of Nuclear decommissioning trust securities	(6		)	(5		)
Other, net	(2		)	—
Net cash used in investing activities	(133		)	(167		)

See accompanying notes to condensed consolidated financial statements.

Cash flows from financing activities:
Proceeds from issuance of long-term debt	140			75
Payments on long-term debt	(133		)	(120		)
Change in short-term debt	(6		)	—
Dividends paid	(27		)	(22		)
Payments on capital leases	(1		)	—
Debt issuance costs	(1		)	—
Net cash used in financing activities	(28		)	(67		)
Decrease in cash and cash equivalents	—			(100		)
Cash and cash equivalents, beginning of period	4			127
Cash and cash equivalents, end of period	$	4		$	27

Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	10		$	14
Non-cash investing and financing activities:
Accrued capital additions	49			62
Accrued dividends payable	28			22
Assets obtained under capital lease	54			—

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)

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 in the state of Oregon. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in an effort 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 is located in Portland, Oregon and its approximately 4,000 square mile, state-approved service area allocation is located entirely within the state of Oregon, encompassing 52 incorporated cities, of which Portland and Salem are the largest. As of March 31, 2016, PGE served 855,573 retail customers with a service area population of approximately 1.8 million, comprising approximately 46% 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 note 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.

To conform with the 2016 presentation, PGE has reclassified Regulatory deferral of settled derivative instruments of $2 million and Decoupling mechanism deferrals, net amortization of $(3) million to Other non-cash income and expenses, net within the operating activities section of the condensed consolidated statement of cash flows for the three months ended March 31, 2015. In addition, Cash received pursuant to the Residential Exchange Program of $1 million has been reclassified to Other, net in the operating activities section of the condensed consolidated statement of cash flows, for the three months ended March 31, 2015.

The financial information included herein for the three months ended March 31, 2016 and 2015 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 income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. The financial information as of December 31, 2015 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2015, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 12, 2016, which 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 months ended March 31, 2016 and 2015.

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

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

during the reporting period. Actual results experienced by the Company could differ materially from those estimates.

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.

Recent Accounting Pronouncements

Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), creates a new Topic 606 and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized that consists of: i) identify the contract with the customer; ii) identify the performance obligations in the contract; iii) determine the transaction price; iv) allocate the transaction price to the performance obligations; and v) recognize revenue when or as each performance obligation is satisfied. Companies can transition to the requirements of this ASU either retrospectively or as a cumulative-effect adjustment as of the date of adoption, which was originally January 1, 2017 for the Company. In August 2015, the Financial Accounting Standards Board (FASB) issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (ASU 2014-14) that defers the effective date by one year, although it permits early adoption as of the original effective date. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2014-09.

In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory (ASU 2015-11), which changes the measurement principle for inventory from the lower of cost or market to lower of cost and net realizable value. Net realizable value is defined as the “estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation.” ASU 2015-11 eliminates the guidance that entities consider replacement cost or net realizable value less an approximately normal profit margin in the subsequent measurement of inventory when cost is determined on a first-in, first-out or average cost basis. The provisions of ASU 2015-11 are effective for public entities with fiscal years beginning after December 15, 2016, or January 1, 2017 for PGE, and interim periods within those fiscal years. Early adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows.

In January 2016, the FASB issued ASU 2016-01, Financial Instrument-Overall (Subtopic 825-10), Recognition and Measurement of Financial Assets and Financial Liabilities (ASU 2016-01), which enhances the reporting model for certain financial instruments and related disclosures. The main provisions of this ASU affect the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. This guidance is effective for public entities with fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, in certain circumstances. The Company does not expect the adoption of this guidance to have a material impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which supersedes the current lease accounting requirements for lessees and lessors within Topic 840, Leases. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Accounting for lessors is substantially unchanged from current accounting

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

principles. Lessees will be required to classify leases as either finance (formerly referred to as capital) leases or operating leases. Initial balance sheet measurement is similar for both types of leases; however, expense recognition and amortization of right-of-use assets will differ. Operating leases will reflect lease expense on a straight-line basis, while finance leases will result in the separate presentation of interest expense on the lease liability (as calculated using the effective interest method) and amortization expense of the right-of-use asset. Quantitative and qualitative disclosures will also be required surrounding significant judgments made by management. The provisions of this pronouncement are effective for calendar year-end, public entities on January 1, 2019 and must be applied on a modified retrospective basis as of the beginning of the earliest comparative period presented. The new standard also provides reporting entities the option to elect a package of practical expedients for existing leases that commenced before the effective date. Early adoption is permitted. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2016-02.

In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting (ASU 2016-09), which is designed to simplify the presentation and accounting for certain income tax effects, employer tax withholding requirements, forfeiture assumptions, and statement of cash flows presentation related to share-based payment awards. Under this standard, all excess tax benefits and tax deficiencies should be recognized within the income statement, and excess tax benefits should be recognized regardless of whether the benefit reduces taxes payable in the current period. The update also allows reporting entities to make a policy election regarding its accounting for forfeitures either by estimating the number of awards that are expected to vest or account for forfeitures when they occur. Within the statement of cash flows, this update will now require tax windfalls to be classified along with other income tax cash flows as an operating activity and cash payments made on behalf of employees when directly withholding shares for tax-withholding purposes should be classified as a financing activity. Most of the provisions of this update require transition on a modified retrospective basis by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2017, and interim periods within those annual periods. Early adoption is permitted. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2016-09.

Newly Adopted Accounting Standards

In April 2015, the FASB issued ASU 2015-03, Interest-Imputation of Interest (Subtopic 835-30) (ASU 2015-03), which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The Company has retrospectively adopted the provisions of ASU 2015-03 as of January 1, 2016, which was the original effective date for calendar year-end, public entities. As a result, unamortized debt expense of $12 million and $11 million at March 31, 2016 and December 31, 2015, respectively, have been reclassified from Other noncurrent assets to a deduction of Long-term debt, net of current portion on the condensed consolidated balance sheets. Adoption of this guidance had no impact on the Company’s consolidated results of operations or consolidated cash flows. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30): Presentation of Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements-Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (ASU 2015-15), which clarifies that the SEC staff would “not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement” given the lack of guidance on this topic in ASU 2015-03. Therefore, as allowed under this update, the Company records debt issuance costs associated with its line-of-credit arrangements as an asset within Other current assets, and amortizes the costs over the term of the agreement.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), which removes the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share as a practical expedient. The amendments also remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share as a practical expedient. Instead, such disclosures are restricted only to investments that the entity has decided to measure using the practical expedient. The Company has retrospectively adopted the provisions of this update as of January 1, 2016, which was the original effective date for calendar year-end, public entities. As a result, certain investments have been retrospectively reclassified within the Company’s fair value disclosures of its Nuclear decommissioning trust and Non-qualified benefit plan trust. See Note 3, Fair Value of Financial Instruments for more information. The Company also anticipates that adoption of this standard will require certain benefit plan assets to be reclassified in disclosures made in the Company’s Annual Report on Form 10-K. The adoption of this guidance had no impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

NOTE 2: BALANCE SHEET COMPONENTS

Inventories

PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as 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.

Other Current Assets

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



	March 31, 2016		December 31, 2015
Prepaid expenses	$	55	$	43
Margin deposits	40		33
Assets from price risk management activities	18		10
Other	—		2
Other current assets	$	113	$	88

Electric Utility Plant, Net

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



	March 31, 2016			December 31, 2015
Electric utility plant	$	8,663		$	8,560
Construction work-in-progress	647			545
Total cost	9,310			9,105
Less: accumulated depreciation and amortization	(3,150		)	(3,093		)
Electric utility plant, net	$	6,160		$	6,012

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $238 million and $227 million as of March 31, 2016 and December 31, 2015, respectively. Amortization expense related to intangible assets was $11 million and $9 million for the three months ended March 31, 2016 and 2015, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

Capital Lease—PGE has entered into agreements to purchase natural gas transportation capacity to serve the Carty Generating Station (Carty), a 440 MW natural gas-fired baseload resource under construction in eastern Oregon, located adjacent to the Boardman coal-fired generating plant. A new natural gas pipeline, Carty Lateral, was recently completed and is a 24 mile, 20-inch diameter steel pipe, which extends from Ione, Oregon, and terminates at a connection within the Carty facility. The Company has entered into a 30-year agreement to purchase the entire capacity of Carty Lateral, which is approximately 175,000 decatherms per day. At the end of the initial contract term, the Company has the option to renew the agreement in continuous three-year increments with at least 24-months prior written notice. For accounting purposes, this transportation capacity agreement is treated as a capital lease.

As of March 31, 2016, a capital lease asset of $54 million was reflected within Electric utility plant, and accumulated amortization of such assets of $1 million reflected within Accumulated depreciation and amortization in the table above. The present value of the future minimum lease payments due under the agreement included $2 million within Accrued expenses and other current liabilities and $51 million in Other noncurrent liabilities on the condensed consolidated balance sheets, respectively. For ratemaking purposes capital leases are treated as operating leases; therefore, in accordance with the accounting rules for regulated operations, the amortization of the leased asset is based on the rental payments recovered from customers. Also for ratemaking purposes, such rental payments are capitalized to the project during the construction period. Amortization of the leased asset of $1 million and interest expense of $2 million has been capitalized to Construction work-in-progress (CWIP) during the construction period of Carty.

For the remainder of 2016, PGE expects $5 million in minimum lease payments, with $3 million imputed interest and present value of net minimum lease payments of $2 million. As of March 31, 2016, PGE’s estimated future minimum lease payments for the following five years and thereafter are as follows (in millions):



	Payments Due
	2017		2018		2019		2020		2021		Thereafter		Total
Total minimum lease payments	$	6	$	6	$	6	$	6	$	5	$	73	$	102
Less imputed interest													49
Present value of net minimum lease payments													$	53

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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, 2016					December 31, 2015
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	124		$	159	$	120		$	161
Pension and other postretirement plans	—			235		—			239
Deferred income taxes	—			86		—			86
Debt issuance costs	—			24		—			16
Other	7			22		9			22
Total regulatory assets	$	131		$	526	$	129		$	524
Regulatory liabilities:
Asset retirement removal costs	$	—		$	850	$	—		$	837
Trojan decommissioning activities	21			11		17			15
Asset retirement obligations	—			46		—			45
Other	36			31		38			31
Total regulatory liabilities	$	57	^*	$	938	$	55	^*	$	928


*	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, 2016		December 31, 2015
Regulatory liabilities—current	$	57	$	55
Accrued employee compensation and benefits	42		51
Accrued interest payable	40		25
Accrued dividends payable	28		28
Accrued taxes payable	30		25
Other	71		75
Total accrued expenses and other current liabilities	$	268	$	259

Credit Facilities

As of March 31, 2016, PGE had a $500 million revolving credit facility scheduled to expire in November 2019.

Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, as backup for commercial paper borrowings, and to 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. The revolving credit facility contains provisions for two one-year extensions subject to approval by the banks, requires annual fees based on PGE’s unsecured credit ratings, and contains customary covenants and default provisions, including a

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of March 31, 2016, PGE was in compliance with this covenant with a 49.9% 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 revolving credit facility.

PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets.

Under the revolving credit facility, as of March 31, 2016, PGE had no borrowings, commercial paper, or letters of credit issued. As of March 31, 2016, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

In addition, PGE has four letter of credit facilities that provide a total of $160 million capacity under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these four facilities, $111 million of letters of credit were outstanding, as of March 31, 2016.

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2018.

Long-term Debt

During the three months ended March 31, 2016, PGE had the following long-term debt transactions, all of which occurred in early January:


•	Issued $140 million of 2.51% Series First Mortgage Bonds (FMBs) due 2021;


•	Repaid $75 million of 5.80% Series FMBs, due in 2018; and


•	Repaid $58 million of 3.81% Series FMBs, due in 2017.

Due to the anticipated repayment of the $133 million in early January 2016, this amount of long-term debt was classified as current on the Company’s condensed consolidated balance sheets as of December 31, 2015.

Defined Benefit Pension Plan Costs

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):



	Three Months Ended March 31,
	2016			2015
Service cost	$	4		$	4
Interest cost	8			8
Expected return on plan assets	(10		)	(10		)
Amortization of net actuarial loss	4			5
Net periodic benefit cost	$	6		$	7

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(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, 2016 and December 31, 2015, and then classifies these financial assets and liabilities based on a fair value hierarchy that is applied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy 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. Pursuant to the adoption of ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities that Calculate Net Asset Value per share (or Its Equivalent), as disclosed in Note 1, Basis of Presentation, assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements, and prior period amounts have been retrospectively reclassified to conform to current presentation.

PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all its financial instruments. 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 during the three month periods ended March 31, 2016 and 2015, except those transfers from Level 3 to Level 2 presented in this note.

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(Unaudited)

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



	As of March 31, 2016
	Level 1		Level 2		Level 3		Other⁽²⁾		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	$	5	$	9	$	—	$	—	$	14
Corporate credit	—		8		—		—		8
Money market funds measured at NAV⁽²⁾	—		—		—		19		19
Non-qualified benefit plan trust: ⁽³⁾
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	1		—		—		—		1
Money market funds measured at NAV⁽²⁾	—		—		—		1		1
Collective trust—domestic equity measured at NAV⁽²⁾	—		—		—		2		2
Assets from price risk management activities: ^{(1) (4)}
Electricity	—		11		—		—		11
Natural gas	—		9		—		—		9
	$	9	$	37	$	—	$	22	$	68
Liabilities from price risk management activities: ^{(1) (4)}
Electricity	$	—	$	29	$	117	—		$	146
Natural gas	—		143		14		—		157
	$	—	$	172	$	131	$	—	$	303


(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)	Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.


(3)	Excludes insurance policies of $25 million, which are recorded at cash surrender value.


(4)	For further information, see Note 4, Price Risk Management.

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(Unaudited)



	As of December 31, 2015
	Level 1		Level 2		Level 3		Other⁽²⁾		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	$	6	$	8	$	—	$	—	$	14
Corporate credit	—		8		—		—		8
Money market funds measured at NAV⁽²⁾	—		—		—		18		18
Non-qualified benefit plan trust: ⁽³⁾
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	1		—		—		—		1
Money market funds measured at NAV⁽²⁾	—		—		—		1		1
Collective trust—domestic equity measured at NAV⁽²⁾	—		—		—		2		2
Assets from price risk management activities: ^{(1) (4)}
Electricity	—		7		—		—		7
Natural gas	—		3		—		—		3
	$	10	$	26	$	—	$	21	$	57
Liabilities from price risk management activities: ^{(1) (4)}
Electricity	$	—	$	28	$	105	$	—	$	133
Natural gas	—		144		14		—		158
	$	—	$	172	$	119	$	—	$	291


(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)	Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure, and have been retrospectively reclassified pursuant to the implementation of ASU 2015-07. For further information see Note 1, Basis of Presentation.


(3)	Excludes insurance policies of $26 million, which are recorded at cash surrender value.


(4)	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 condensed 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:

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

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Equity securities—Equity mutual fund and common stock securities are primarily 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.

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 not classified in the fair value hierarchy since they are valued at NAV as a practical expedient. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice.

Common and collective trust funds—PGE invests in common and collective trust funds that invests in equity securities. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value as a practical expedient. A majority of the funds provide for daily liquidity with appropriate written notice. One fund allows for withdrawal from all accounts as of the last day on each calendar month, with at least 10 days’ prior written notice, and provides for a 95% payment to be made within 30 days, and the balance paid after the annual fund audit is complete. Common and collective trusts are not classified in the fair value hierarchy as they are valued at NAV as a practical expedient.

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 its exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net variable power costs (NVPC) 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 forward commodity prices and interest rates. Substantially all of these inputs 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 commodity forwards, futures, 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 commodity forwards and swaps.

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Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:



	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
	(in millions)
As of March 31, 2016:
Electricity physical forwards	$	—	$	117	Discounted cash flow	Electricity forward price (per MWh)	$	4.25	$	73.32	$	29.16
Natural gas financial swaps	—		14		Discounted cash flow	Natural gas forward price (per Decatherm)	0.90		3.61		2.46
	$	—	$	131
As of December 31, 2015:
Electricity physical forwards	$	—	$	105	Discounted cash flow	Electricity forward price (per MWh)	$	8.50	$	84.47	$	30.69
Natural gas financial swaps	—		14		Discounted cash flow	Natural gas forward price (per Decatherm)	2.06		3.70		2.54
	$	—	$	119

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. For shorter term contracts, the Company employs the mid-point of the bid-ask spread of the market and these inputs are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These price inputs are validated against independent market data from multiple sources. For certain long-term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company uses internally-developed price curves, which derive longer term prices and utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a monthly basis by the Company.

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:

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(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,
	2016		2015
Balance as of the beginning of the period	$	119	$	100
Net realized and unrealized losses^*	12		50
Transfers out of Level 3 to Level 2	—		(2		)
Balance as of the end of the period	$	131	$	148


*	Both realized and unrealized losses, of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Purchased power and fuel expense in the condensed consolidated statements of income.

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 months ended March 31, 2016 and 2015, 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 derivative 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 condensed consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Revenue Bonds is classified as a Level 2 fair value measurement and is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. The fair value of PGE’s unsecured term bank loans was classified as Level 3 in the fair value hierarchy and was estimated based on the terms of the loans and the Company’s creditworthiness. The significant unobservable inputs to the Level 3 fair value measurement included the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximated their carrying value.

As of March 31, 2016, the carrying amount of PGE’s long-term debt was $2,199 million, net of $12 million of unamortized debt expense, and its estimated aggregate fair value was $2,617 million, classified as Level 2 in the fair value hierarchy. As of December 31, 2015, the carrying amount of PGE’s long-term debt was $2,193 million, net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $2,455 million classified as Level 2 in the fair value hierarchy.

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 and manage risk. Such activities include purchases and sales of both power and fuel 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.

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(Unaudited)

PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign currency exchange rate risk in order to reduce volatility in NVPC for its retail customers. These derivative instruments may include forwards, futures, swaps, and option contracts, which are recorded at fair value on the condensed consolidated balance sheets, for electricity, natural gas, oil, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income. In accordance with the ratemaking and cost recovery processes 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 settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as 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, 2016			December 31, 2015
Current assets:
Commodity contracts:
Electricity	$	11		$	7
Natural gas	7			3
Total current derivative assets	18		⁽¹⁾	10		⁽¹⁾
Noncurrent assets:
Commodity contracts:
Natural gas	2			—
Total noncurrent derivative assets	2		⁽²⁾	—		⁽²⁾
Total derivative assets not designated as hedging instruments	$	20		$	10
Total derivative assets	$	20		$	10
Current liabilities:
Commodity contracts:
Electricity	$	37		$	36
Natural gas	105			94
Total current derivative liabilities	142			130
Noncurrent liabilities:
Commodity contracts:
Electricity	109			97
Natural gas	52			64
Total noncurrent derivative liabilities	161			161
Total derivative liabilities not designated as hedging instruments	$	303		$	291
Total derivative liabilities	$	303		$	291


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


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

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(Unaudited)

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 2035, were as follows (in millions):



	March 31, 2016			December 31, 2015
Commodity contracts:
Electricity	12		MWh	12		MWh
Natural gas	118		Decatherms	124		Decatherms
Foreign currency	$	21	Canadian	$	7	Canadian

PGE has elected to report gross on the condensed consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to 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. As of March 31, 2016 and December 31, 2015, gross amounts included as Price risk management liabilities subject to master netting agreements were $123 million and $111 million, respectively, for which PGE posted collateral of $14 million, which consisted primarily of letters of credit and a nominal amount of cash. As of March 31, 2016, of the gross amounts recognized, $117 million was for electricity and $6 million was for natural gas compared to $104 million for electricity and $7 million for natural gas recognized as of December 31, 2015.

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



	Three Months Ended March 31,
	2016			2015
Commodity contracts:
Electricity	$	25		$	41
Natural Gas	17			44
Foreign currency exchange	$	(1	)	$	—

Net unrealized and certain net realized losses (gains) presented in the preceding table are offset within the condensed consolidated statements of income by the effects of regulatory accounting. Of the net losses (gains) recognized in Net income for the three month periods ended March 31, 2016 and 2015, net losses of $34 million and $83 million have been offset, respectively.

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, 2016 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):



	2016		2017		2018		2019		2020		Thereafter		Total
Commodity contracts:
Electricity	$	24	$	8	$	8	$	8	$	7	$	80	$	135
Natural gas	85		50		11		2		—		—		148
Net unrealized loss	$	109	$	58	$	19	$	10	$	7	$	80	$	283

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(Unaudited)

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 derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2016 was $287 million, for which PGE has posted $88 million in collateral, consisting of $64 million in letters of credit and $24 million in cash. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2016, the cash requirement to either post as collateral or settle the instruments immediately would have been $256 million. As of March 31, 2016, PGE had posted an additional $15 million in cash collateral for derivative instruments with no credit-risk related contingent features. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s condensed consolidated balance sheet.

Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows:



	March 31, 2016		December 31, 2015
Assets from price risk management activities:
Counterparty A	48	%	59	%
Counterparty B	11		8
Counterparty C	9		10
	68	%	77	%
Liabilities from price risk management activities:
Counterparty D	38	%	36	%
Counterparty B	10		10
Counterparty E	9		10
	57	%	56	%

See Note 3, Fair Value of Financial Instruments, 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

Basic earnings per share are computed based on the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Potential common shares consist of: i) unvested employee stock purchase plan shares; ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights; and iii) shares issuable pursuant to an equity forward sale agreement (EFSA). See Note 6, Equity, for additional information on the EFSA and its impact on earnings per share. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

For the three month periods ended March 31, 2016 and 2015 unvested performance-based restricted stock units and related dividend equivalent rights of approximately 304,000 and 303,000, respectively, were excluded from the dilutive calculation because the performance goals had not been met.

Net income is the same for both the basic and diluted earnings per share computations. The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands):



	Three Months Ended March 31,
	2016	2015
Weighted-average common shares outstanding—basic	88,833	78,271
Dilutive effect of potential common shares	—	3,195
Weighted-average common shares outstanding—diluted	88,833	81,466

NOTE 6: EQUITY

The activity in equity during the three months ended March 31, 2016 and 2015 is as follows (dollars in millions):



	Common Stock				Accumulated Other Comprehensive Loss			Retained Earnings
	Common Stock
	Shares	Amount									Total
Balances as of December 31, 2015	88,792,751	$	1,196		$	(8	)	$	1,070		$	2,258
Issuances of shares pursuant to equity-based plans	106,608	—			—			—			—
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(27		)	(27		)
Net income	—	—			—			61			61
Balances as of March 31, 2016	88,899,359	$	1,195		$	(8	)	$	1,104		$	2,291

Balances as of December 31, 2014	78,228,339	$	918		$	(7	)	$	1,000		$	1,911
Issuances of shares pursuant to equity-based plans	116,352	1			—			—			1
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(22		)	(22		)
Net income	—	—			—			50			50
Balances as of March 31, 2015	78,344,691	$	918		$	(7	)	$	1,028		$	1,939

During the second quarter of 2015, PGE physically settled in full the EFSA, with the issuance of 10,400,000 shares of common stock in exchange for net proceeds of $271 million. Prior to settlement, the potentially issuable shares pursuant to the EFSA were reflected in PGE’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PGE’s common stock used in calculating diluted earnings per share for a reporting period are increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could be purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period).

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(Unaudited)

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 and the reasons.

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 circumstances in which it is uncertain how liability, if any, will be shared among multiple defendants); or vii) there are 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 Class Actions

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 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the matter to the OPUC for reconsideration.

In 2008, the OPUC issued an order (2008 Order) that required PGE to provide refunds of $33 million, including interest, which were completed in 2010. Following appeals, the 2008 Order was upheld by the Oregon Court of Appeals in February 2013 and by the Oregon Supreme Court (OSC) in October 2014.

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(Unaudited)

In 2003, in two separate legal proceedings, lawsuits were filed in Marion County Circuit Court (Circuit Court) against PGE 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 August 2006, the OSC issued a ruling ordering the abatement of the class action proceedings. The OSC concluded that the OPUC had primary jurisdiction to determine what, if any, remedy could 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 OSC 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 OSC added that, if the OPUC determined that it cannot provide a remedy, the court system may have a role to play. The OSC also ruled that the plaintiffs retain the right to return to the Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. In October 2006, the Circuit Court abated the class actions in response to the ruling of the OSC.

In June 2015, based on a motion filed by PGE, the Circuit Court lifted the abatement and in July 2015, the Circuit Court heard oral argument on the Company’s motion for Summary Judgment. Following oral argument on PGE’s motion for summary judgment, the plaintiffs moved to amend the complaints. PGE opposed the request to amend. On February 22, 2016, the Circuit Court denied the plaintiff’s motion to amend the complaint and on March 16, 2016, the Circuit Court entered a general judgment that granted the Company’s motion for summary judgment and dismissed all claims by the plaintiffs. However, on April 14, 2016, the plaintiffs appealed the Circuit Court dismissal to the Court of Appeals for the State of Oregon.

PGE believes that the October 2, 2014 OSC decision and the recent Circuit Court decisions have reduced the risk of a loss to the Company in excess of the amounts previously recorded and discussed above. However, because the class actions remain subject to appeal, management believes that it is reasonably possible that such a loss to the Company could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss.

Pacific Northwest Refund Proceeding

In response to the Western energy crisis of 2000-2001, the FERC initiated, beginning in 2001, a series of proceedings to determine whether refunds are warranted for bilateral sales of electricity in the Pacific Northwest wholesale spot market during the period December 25, 2000 through June 20, 2001. In an order issued in 2003, the FERC denied refunds. Various parties appealed the order to the Ninth Circuit Court of Appeals (Ninth Circuit) and, on appeal, the Ninth Circuit remanded the issue of refunds to the FERC for further consideration.

On remand, in 2011 and thereafter, the FERC issued several procedural orders that established an evidentiary hearing, defined the scope of the hearing, expanded the refund period to include January 1, 2000 through December 24, 2000 for certain types of claims, and described the burden of proof that must be met to justify abrogation of the contracts at issue and the imposition of refunds. Those orders included a finding by the FERC that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this 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 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. The FERC also held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Refund proponents appealed these procedural orders at the Ninth Circuit. On December 17, 2015, the

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Ninth Circuit held that the FERC reasonably applied the Mobile-Sierra presumption to the class of contracts at issue in the proceedings and dismissed evidentiary challenges related to the scope of the proceeding. Plaintiffs on behalf of the California Energy Resources Scheduling division of the California Department of Water Resources filed a request for rehearing on February 1, 2016. By order issued April 18, 2016, the Ninth Circuit denied plaintiffs’ request for panel rehearing of its decision regarding application of the Mobile-Sierra presumption.

In response to the evidence and arguments presented during the hearing, in May 2015, the FERC issued an order finding that the refund proponents had failed to meet the Mobile-Sierra burden with respect to all but one respondent. In December 2015, the FERC denied all requests for rehearing of its order. With respect to the remaining respondent, FERC ordered additional proceedings, and a January 2016 revised initial decision has now recommended that certain contracts by such respondent be subject to refund.

The Company has settled all of the direct claims asserted against it in the proceedings for an immaterial amount. The settlements and associated FERC orders have not fully eliminated the potential for so-called “ripple claims,” which have been described by the FERC as “sequential claims against a succession of sellers in a chain of purchases that are triggered if the last wholesale purchaser in the chain is entitled to a refund.” However, the remaining respondent subject to the revised initial decision has stated on the record that it will not pursue ripple claims, and on February 1, 2016, the Acting Chief Administrative Law Judge issued an order holding that the issue of ripple claims is terminated for purposes of Phase II of these proceedings. Therefore, unless the current FERC orders are overturned or modified on appeal, the Company does not believe that it will incur any material loss in connection with this matter.

Management cannot predict the outcome of the various pending appeals and remands concerning this matter. If, on rehearing, appeal, or subsequent remand, the Ninth Circuit or the FERC were to reverse previous FERC rulings on liability or find that a market-wide remedy is appropriate, it is possible that additional refund claims could be asserted against the Company. However, management cannot predict, under such circumstances, which contracts would be subject to refunds, the basis on which refunds would be ordered, or how such refunds, if any, would be calculated. Further, management cannot predict whether any current respondents, if ordered to make refunds, would pursue additional refund claims against their suppliers, and, if so, what the basis or amounts of such potential refund claims against the Company would be. 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 as a federal Superfund site and listed 69 Potentially Responsible Parties (PRPs). PGE was included among the PRPs as it has historically owned or operated property near the river. In 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 remedial investigation (RI) has been completed pursuant to an Administrative Order on Consent between the EPA and several PRPs known as the Lower Willamette Group (LWG), which does not include PGE.

In 2012, the LWG submitted a draft feasibility study (FS) to the EPA for review and approval. In August 2015, the EPA substantially revised the draft FS, as submitted by the LWG, and issued its own draft FS, which is currently in

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the process of undergoing further consideration and comment. The draft FS, along with the RI, is expected to provide the framework for the EPA to determine a clean-up remedy for Portland Harbor that will be documented in a Record of Decision (ROD).

The EPA’s draft FS evaluates several alternative clean-up approaches, which would take from four to 18 years with the present value of estimated costs ranging from $800 million to $2.4 billion, depending on the selected remedial action levels and the choice of remedy. While the revised draft FS aids in the development of a proposed plan to remediate Portland Harbor, 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. In November 2015, the EPA proposed its preferred alternative remedy to the National Remedy Review Board for comment. The EPA’s preferred alternative has an estimated present value cost of $1.5 billion and would take approximately seven years to complete. The EPA anticipates it will release, for public review and comment, a Proposed Cleanup Plan in the second quarter of 2016. The Company currently expects the EPA to issue a determination of its preferred remedy in a final ROD in late 2016; however, responsibility for funding and implementing the EPA’s selected remedy is not expected to be known for some time. PGE is participating in a voluntary process to develop a method for allocation of costs.

Where injuries to natural resources have occurred as a result of releases of hazardous substances, federal and state natural resource trustees may seek to recover for damages at such sites, which is referred to as natural resource damages. As it relates to the Portland Harbor, PGE has been participating in the Portland Harbor Natural Resource Damages assessment (NRDA) process. The EPA does not manage NRDA activities, but provides claims information and coordination support to the Natural Resource Damages (NRD) trustees. Damage assessment activities are typically conducted by a Trustee Council made up of the trustee entities for the site, and claims are not concluded until a final remedy for clean-up has been settled. The Portland Harbor NRD trustees are the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the state of Oregon, and certain tribal entities.

After the claimed damages at a site are assessed, the NRD trustees may seek to negotiate legal settlements or take other legal actions against the parties responsible for the damages. Funds from such settlements must be used to restore injured resources and may also compensate the trustees for costs incurred in assessing the damages. It is uncertain what portion, if any, PGE may be held responsible related to Portland Harbor.

As discussed above, significant uncertainties still remain concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, the amount of natural resource damages, and the method of allocation of costs amongst PRPs. Although it is probable that the Company’s share of these costs could be material, the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of the Portland Harbor site and NRDA. The Company plans to seek recovery of any costs resulting from the Portland Harbor proceeding through regulatory recovery in customer prices and through claims under insurance policies.

Alleged Violation of Environmental Regulations at Colstrip

In July 2012, PGE received a Notice of Intent to Sue (Notice) for violations of the Clean Air Act (CAA) at Colstrip Steam Electric Station (CSES) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). The Notice was also addressed to the other CSES co-owners, including Talen Montana, LLC, the operator of CSES. PGE has a 20% ownership interest in Units 3 and 4 of CSES. The Notice alleged certain violations of the CAA, including New Source Review, Title V, and opacity requirements, and stated that the Sierra Club and MEIC would: 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.

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The Sierra Club and MEIC asserted that the CSES owners violated the Title V air quality operating permit during portions of 2008 and 2009 and 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 Sierra Club and MEIC also asserted violations of opacity provisions of the CAA.

On March 6, 2013, the Sierra Club and MEIC sued the CSES 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 CSES 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.

In May 2013, the defendants filed a motion to dismiss 36 of 39 claims alleged in the complaint. In September 2013, the plaintiffs filed a motion for partial summary judgment regarding the appropriate method of calculating emission increases. Also in September 2013, the plaintiffs filed an amended complaint that withdrew Title V and opacity claims, added claims associated with two 2011 projects, and expanded the scope of certain claims to encompass approximately 40 additional projects. In July 2014, the court denied both the defendants’ motion to dismiss and the plaintiffs’ motion for partial summary judgment.

In August 2014, the plaintiffs filed a second amended complaint to which the defendants’ response was filed in September 2014. The second amended complaint continues to seek injunctive relief, declaratory relief, and civil penalties for alleged violations of the federal Clean Air Act. The plaintiffs state in the second amended complaint that it was filed, in part, to comply with the court’s ruling on the defendants’ motion to dismiss and plaintiffs’ motion for partial summary judgment. The parties filed various summary judgment motions during the summer of 2015 andon or about December 31, 2015, the Magistrate Judge issued Findings and Recommendations that, if adopted by the trial court, would result in dismissal of several of the plaintiffs’ claims.

The parties have reached a preliminary agreement on key terms of a settlement that would resolve the claims raised in this litigation, and accordingly, on April 26, 2016, filed a joint motion to vacate the trial date and stay all deadlines in this case in order to provide the parties a reasonable period of time to develop and finalize appropriate settlement documents. On April 27, 2016, the Court granted the stay until June 28, 2016. In the event the case does not settle by June 28, 2016, the parties shall either move to extend the stay or propose a revised bench trial schedule. The parties anticipate that a final agreement will be reached sometime in the second quarter of 2016.

Management believes that it is reasonably possible that this litigation could result in a loss to the Company. However, due to the uncertainties concerning this litigation, including the outcome of the foregoing settlement discussions, PGE cannot predict the outcome or estimate a range of potential loss.

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 that may result in judgments against the Company. Although management currently believes that resolution of such matters, individually and in the aggregate, 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, 2016, 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: CARTY GENERATING STATION

The Company is constructing the Carty Generating Station (Carty), a 440 MW baseload natural gas-fired generating plant in Eastern Oregon, located adjacent to the Boardman coal plant. As of March 31, 2016, PGE had $501 million, including $50 million of AFDC, included in CWIP for the project as compared to $424 million, including $41 million of AFDC, as of December 31, 2015. The final order issued by the OPUC on November 3, 2015 in connection with the Company’s 2016 GRC, authorized the inclusion in customer prices of capital costs for Carty of up to $514 million, including AFDC, as well as Carty’s operating costs, at such time that the plant is placed in service, provided that occurs by July 31, 2016.

In 2013, the Company entered into an agreement (Construction Agreement) for engineering, procurement and construction of Carty with Abeinsa Abener Teyma General Partnership (Contractor or Abeinsa). On December 18, 2015, the Company declared Abeinsa in default under multiple provisions of the Construction Agreement and terminated the Construction Agreement. Liberty Mutual Insurance Company and Zurich American Insurance Company (hereinafter referred to collectively as the Sureties) have provided a performance bond (Performance Bond) of $145.6 million under the Construction Agreement. Following termination of the Construction Agreement, PGE, in consultation with the Sureties, brought on new contractors and construction resumed during the week of December 21, 2015.

On January 28, 2016, PGE received notice from the International Court of Arbitration that Abengoa S.A., the parent company of the Contractor, had submitted a Request for Arbitration in which it alleged that the Company’s termination of the Construction Agreement was wrongful and in breach of the agreement terms and does not give rise to liability of Abengoa S.A. under the terms of a guaranty in favor of PGE pursuant to which Abengoa S.A. agreed to guaranty certain obligations of the Contractor under the Construction Agreement. PGE disagrees with the assertions in the Request for Arbitration and on February 29, 2016 filed a Complaint and Motion for Preliminary Injunction in the U.S. District Court for the District of Oregon seeking to have the arbitration claim dismissed on the grounds that the Company has not made a demand under the Abengoa S.A. guaranty, and therefore the matter is not ripe for arbitration. On March 28, 2016, Abengoa S.A. and several of its foreign affiliates filed petitions for recognition under Chapter 15 of the U.S. Bankruptcy Code requesting interim relief, including an injunction precluding the prosecution of any proceedings against the Chapter 15 debtors. On March 29, 2016, a number of Abengoa S.A.’s U.S. subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code, including the four entities that collectively comprise the Contractor. On March 31, 2016, the Delaware Bankruptcy Court granted the petition for interim relief. As a result, on April 5, 2016, the U.S. District Court issued an order stating that the District Court action was stayed.

On March 9, 2016, the Sureties delivered a letter to the Company denying liability in whole under the Performance Bond. In the letter, the Sureties made the following assertions in support of their determination:

1. that, because the Contractor and its parent company, Abengoa S.A. have alleged that PGE wrongfully terminated the Construction Agreement and have requested arbitration of the claim, PGE must disprove such claim as a condition precedent to recovery under the Performance Bond; and

2. that, irrespective of the outcome of the foregoing wrongful termination claim, the Sureties have various contractual and equitable defenses to payment and are not liable to PGE for any amount under the Performance Bond.

The Company disagrees with the Sureties’ assertions and on March 23, 2016 filed a breach of contract action against the Sureties in the U.S. District Court for the District of Oregon. The Company’s complaint disputes the Sureties’ assertion that the Company wrongfully terminated the Construction Agreement and asserts that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Sureties’ breach of contract, including damages in excess of the $145.6 million stated amount of the Performance Bond. Such damages include additional costs incurred by PGE to complete Carty. On April 15, 2016, the Sureties filed a motion to stay the proceeding, alleging that PGE’s claims should be addressed in the arbitration proceeding initiated by Abengoa S.A. in January, 2016 and referenced above because PGE’s claims are intertwined with the issues involved in such arbitration and all parties necessary to resolve PGE’s claims are parties to the arbitration. PGE disagrees with this assertion and will oppose the Sureties’ motion to stay the proceeding.

As a result of the termination of the Construction Agreement, the transition to a new construction team, and related matters, additional costs have been and are expected to be incurred to complete construction of Carty. PGE currently expects the total cost of Carty could range from $635 million to $670 million, including AFDC. The Company is targeting an in service date in July 2016. However, due to uncertainties relating to the work performed by the Contractor and the work necessary to correct defects and complete construction, the costs and completion date for Carty could vary from the Company’s current projection.

In the event the total project costs incurred by PGE, net of any amounts received from the Sureties, Abengoa S.A. or the Contractor, exceed the OPUC’s approved amount of $514 million, including AFDC, the Company intends to seek approval to recover the excess amounts in customer prices. The Company will also likely seek a regulatory deferral of the revenue requirements associated with any costs in excess of the $514 million approved by the OPUC from Carty’s in service date until such amounts are approved in a subsequent GRC proceeding. However, there is no assurance that such recovery would be allowed by the OPUC. In accordance with GAAP and the Company’s accounting policies, these costs would be charged to expense at the time disallowance of recovery becomes probable and a reasonable estimate of the amount of such disallowance can be made. As of the date of this report, the Company has concluded that the likelihood that a portion of the cost of Carty will be disallowed for recovery in customer prices is less than probable. Accordingly, no loss has been recorded to date related to the project. If the in service date for Carty were to be delayed beyond July 31, 2016, PGE intends to pursue one or more alternative avenues to obtain OPUC approval for the inclusion of Carty costs in customer prices. Under such circumstance, the Company might not be able to recover some, or all, of the net revenue requirements for Carty from the date Carty is placed into service until the time approved prices go in effect.



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 results of operations, business prospects, 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 the Company to have a reasonable basis including, but not limited to, management’s examination of historical operating trends and data contained either in internal records or 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;


•	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 the 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 generating facilities, including forced outages, hydro, and wind conditions, and disruptions of fuel supply, any of which may cause the Company to incur repair costs or purchase replacement power at increased costs;


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


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

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

•

capital market conditions, including availability of capital, volatility of interest rates, reductions in demand for investment-grade commercial paper, as well as changes in PGE’s credit ratings, any of 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 of capital projects, and the repayments of maturing debt;


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


•	changes in, and compliance with, environmental laws and policies, including those related to threatened and endangered species, fish, and wildlife;


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


•	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;


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


•	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 potential strikes, work stoppages, transitions in senior management, and the number of employees approaching retirement;


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


•	political and economic conditions;


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


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


•	acts of war or terrorism.

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 or 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. This MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in

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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, 2015, and other periodic and current reports filed with the SEC.

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 in order to meet the needs of its retail customers. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory.

The Company is in the process of preparing its 2016 IRP, which will address resource needs over the next 20 years. The areas of focus for the plan include, among other topics, additional resources that may be needed in order to meet Oregon’s Renewable Portfolio Standard (RPS) requirements and to replace energy from Boardman, which is scheduled to cease coal-fired operations at the end of 2020. In March 2016, the State of Oregon passed a new law referred to as the Oregon Clean Electricity and Coal Transition Plan (OCEP), which, among other things, increased the renewable energy thresholds under the RPS. For further information on the OCEP, see the “Legal, Regulatory, and Environmental Matters” section of this Overview.

Pursuant to the Action Plan included in the Company’s 2009 Integrated Resource Plan (IRP), PGE has undertaken to increase its generation capacity to meet growing customer demand, comply with the requirements of the RPS, limit exposure to market price volatility, and maintain system reliability. As part of the Action Plan, construction continues on Carty Generating Station (Carty), a 440 MW natural gas-fired baseload resource located in Eastern Oregon adjacent to Boardman.

In November 2015, the OPUC issued an order in the Company’s 2016 General Rate Case, intended primarily to allow recovery of costs associated with the construction and operation of Carty. Customer price changes were effective January 1, 2016, with further changes to occur when Carty is placed in-service, provided that occurs by July 31, 2016. Management continues to evaluate potential investments to improve the reliability and efficiency of the Company’s operating systems, as well as potential investments in fuel supply opportunities that would provide value to customers.

The discussion that follows in this MD&A more fully describes these and other operating activities and provides additional information related to the Company’s legal, regulatory, and environmental matters, results of operations, and liquidity and financing activities.

General Rate Case—On January 1, 2016, new customer prices went into effect pursuant to the OPUC order issued on PGE’s 2016 General Rate Case (2016 GRC), which was based on a 2016 test year and includes costs related to Carty. The expected net increase in annual revenue requirements of $12 million represents an increase of approximately 0.7% in overall customer prices and reflects:


•	A capital structure of 50% debt and 50% equity;


•	A return on equity of 9.6%;


•	A cost of capital of 7.51%; and


•	An average rate base of $4.4 billion.

The net annual revenue requirement increase will be effective in two phases. A $44 million decrease, representing a 2.5% decrease in customer prices effective January 1, 2016, consisting of a reduction in base business costs of $15 million and a decrease of $30 million related to the amortization and recognition of certain customer credits through supplemental tariffs. A $57 million annualized revenue increase will be effective when Carty is placed in service, provided that occurs by July 31, 2016. The increase will consist of an $85 million annualized increase related to the cost recovery of Carty and a $28 million annualized decrease related to the amortization of certain customer credits through supplemental tariffs. If Carty is not completed and in service by July 31, 2016, PGE will need to file a new

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ratemaking request seeking the inclusion of the Carty costs in customer prices. For further discussion on Carty, see “Carty Generating Station” in this Overview section of Item 2.

The general rate case filings, as well as copies of the orders, direct testimony, exhibits, and stipulations are available on the OPUC website at www.oregon.gov/puc.

Carty Generating Station—During the first quarter of 2016, construction continued on Carty, a 440 MW natural gas-fired baseload resource in Eastern Oregon, located adjacent to the Boardman coal plant. On December 18, 2015, the Company declared its engineering, procurement and construction contractor, Abeinsa Abener Teyma General Partnership, an affiliate of Abengoa S.A., and affiliates of Abeinsa Abener Teyma General Partnership (Contractor) in default under the construction agreement (Construction Agreement) and terminated the Construction Agreement. Liberty Mutual Insurance Company and Zurich American Insurance Company (hereinafter referred to collectively as the Sureties), have provided a performance bond of $145.6 million (Performance Bond) under the Construction Agreement.

On January 28, 2016, the Company received notice from the International Chamber of Commerce International Court of Arbitration that Abengoa S.A. had submitted a Request for Arbitration in which it alleged that the Company’s termination of the Construction Agreement was wrongful and in breach of the agreement terms and does not give rise to any liability of Abengoa S.A. under the terms of a guaranty in favor of PGE pursuant to which Abengoa S.A. agreed to guaranty certain obligations of the Contractor under the Construction Agreement. PGE disagrees with the assertions in the Request for Arbitration and on February 29, 2016 filed a Complaint and Motion for Preliminary Injunction in the U.S. District Court for the District of Oregon seeking to have the arbitration claim dismissed on the grounds that the Company has not made a demand under the Abengoa S.A. guaranty, and therefore the matter is not ripe for arbitration. On March 28, 2016, Abengoa S.A. and several of its foreign affiliates filed petitions for recognition under Chapter 15 of the U.S. Bankruptcy Code requesting interim relief, including an injunction precluding the prosecution of any proceedings against the Chapter 15 debtors. On March 29, 2016, a number of Abengoa S.A.’s U.S. subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code, including the four entities that collectively comprise the Contractor. On March 31, 2016, the Delaware Bankruptcy Court granted the petition for interim relief. As a result, on April 5, 2016, the U.S. District Court issued an order stating that the District Court action was stayed.

On March 9, 2016, the Sureties delivered a letter to the Company denying liability in whole under the Performance Bond. In the letter, the Sureties make the following assertions in support of their determination:


1.	that, because the Contractor and its parent company, Abengoa S.A., have alleged that PGE wrongfully terminated the Construction Agreement and have requested arbitration of the claim, PGE must disprove such claim as a condition precedent to recovery under the Performance Bond; and


2.	that, irrespective of the outcome of the foregoing wrongful termination claim, the Sureties have various contractual and equitable defenses to payment and are not liable to PGE for any amount under the Performance Bond.

The Company disagrees with the foregoing assertions and on March 23, 2016 filed a breach of contract action against the Sureties in the U.S. District Court for the District of Oregon. The Company’s complaint disputes the Sureties’ assertion that the Company wrongfully terminated the Construction Agreement and asserts that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Sureties' breach of contract, including damages in excess of the $145.6 million stated amount of the Performance Bond. Such damages include additional costs incurred by PGE to complete Carty.

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On April 15, 2016 the Sureties filed a motion to stay the proceeding, alleging that PGE’s claims should be addressed in the arbitration proceeding initiated by Abengoa S.A. in January, 2016 and referenced above because PGE’s claims are intertwined with the issues involved in such arbitration and all parties necessary to resolve PGE’s claims are parties to the arbitration. PGE disagrees with this assertion and will oppose the Sureties’ motion to stay the proceeding.

As of March 31, 2016, PGE had $501 million, including $50 million of AFDC, included in CWIP for the project. The Company currently estimates that the total capital expenditures for Carty, including AFDC, will be approximately $635 million to $670 million, before considering any amount that may be received from the Sureties pursuant to the Performance Bond or from the Contractor or Abengoa S.A.

The Company is targeting an in service date in July 2016. However, due to uncertainties relating to the work performed to date by the Contractor and the work necessary to correct defects and complete construction, the costs and completion date for Carty could vary from the Company’s current projection.

Increased costs and delay of the targeted in service date could also impact the timing and amount of the Company’s recovery of Carty costs in customer prices. The final order issued on November 3, 2015 by the Public Utility Commission of Oregon (OPUC) in connection with the Company’s 2016 General Rate Case filing authorized the inclusion in customer prices of capital costs for Carty of up to $514 million, including AFDC, as well as Carty’s operating costs, at such time that the plant is placed into service, provided that occurs by July 31, 2016. If the costs incurred by PGE to complete Carty (less any amounts that may be received from the Sureties, Abengoa S.A. or the Contractor) exceed this amount, PGE intends to seek recovery of the excess amount in customer prices. However, there is no assurance that such recovery would be granted by the OPUC. If the expected date of completion of construction of Carty were to be delayed beyond July 31, 2016, PGE intends to pursue one or more alternative avenues to obtain OPUC approval for the inclusion of Carty costs in customer prices. Under such circumstance, the Company might not be able to recover some or all of the net revenue requirements for Carty from the date Carty is placed into service until the time when new approved customer prices, including the costs for Carty, become effective.

Capital Requirements and Financing—In total, the Company’s 2016 capital expenditures are expected to approximate $649 million, which includes the high end of the estimated range of capital expenditures to complete Carty of $189 million to $224 million, excluding AFDC.

For additional information regarding estimated capital expenditures, see “Capital Requirements” in the Liquidity and Capital Resources section of this Item 2.

PGE plans to fund the 2016 capital requirements with cash from operations during 2016, which is expected to range from $450 million to $490 million, and the issuance of short- and long-term debt securities. These amounts do not include any estimated proceeds to be received from the Sureties pursuant to the Company’s breach of contract complaint against the Sureties as issued on March 23, 2016. For additional information, see “Liquidity” and “Debt and Equity Financings” in the Liquidity and Capital Resources section of this Item 2.

Operating Activities—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. Retail customer price changes and customer usage patterns, which can be affected by the economy, also have an effect on revenues while wholesale power availability and price, hydro and wind generation, and fuel costs for thermal and gas plants can also affect income from operations.

Customers and Demand—The 2.7% increase in retail energy deliveries for the three months ended March 31, 2016 compared with the three months ended March 31, 2015 was driven by an increase in residential energy deliveries combined with an increase in commercial deliveries, offset to a large extent by a decrease in industrial energy deliveries. The increases in residential and commercial energy deliveries were driven by winter weather that was colder than the prior year.

During the first quarter of 2016, heating degree-days, an indication of the extent to which customers are likely to have used electricity for heating, although 15% below average, were 7% above the first quarter of 2015. According to the National Oceanic and Atmospheric Administration’s climatological rankings, for the three month period of January through March, the State of Oregon experienced the warmest average temperatures on record during 2015. As a result of the historic warm weather in the prior year, residential energy deliveries, which are weather sensitive, for the first quarter of 2016, were 8.9% higher than the first quarter of 2015.

The Company experienced a 1.3% and 1.0% increase in the average number of residential and commercial customers served, respectively, which also contributed to higher deliveries. One additional day in the first quarter 2016 due to leap year also provided an increase of approximately 1.1% in retail energy deliveries. The decrease in industrial demand was primarily due to the closure of a large paper customer that ceased operations in late 2015. PGE’s 2016 GRC took the loss of this customer into consideration and incorporated its effects into prices and load forecasts. As a result, minimal earnings impact is expected.

The following table, which includes direct access customers purchasing their energy from Electricity Service Suppliers (ESSs), presents the average number of retail customers by customer class, and corresponding energy deliveries, for the periods indicated:



	Three Months Ended March 31,
	2016		2015		% Increase (Decrease)in Energy Deliveries
	Average Number of Customers	Retail Energy Deliveries*	Average Number of Customers	Retail Energy Deliveries*	% Increase (Decrease)in Energy Deliveries
Residential	749,287	2,103	739,531	1,931	8.9	%

Commercial (PGE sales only)	104,872	1,702	103,824	1,631	4.4	%
Direct access	319	129	342	129	—	%
Total Commercial	105,191	1,831	104,166	1,760	4.0	%

Industrial (PGE sales only)	187	697	201	822	(15.2	)%
Direct access	63	283	61	272	4.0	%
Total Industrial	250	980	262	1,094	(10.4	)%

Total (PGE sales only)	854,346	4,502	843,556	4,384	2.7	%
Total Direct access	382	412	403	401	2.7	%
Total	854,728	4,914	843,959	4,785	2.7	%


*	In thousands of MWh.

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Energy efficiency and conservation efforts by retail customers continue to influence total energy deliveries, although to the extent average usage per customer varies from expectations established in the latest GRC, the financial impacts to the Company of any such reduction in usage is largely mitigated by the decoupling mechanism.

Power Operations—To meet the energy needs of its retail customers, the Company utilizes a combination of its own generating resources and power purchases in the wholesale market. In an effort to obtain reasonably-priced power for its retail customers, PGE makes economic dispatch decisions continuously based on numerous factors including plant availability, customer demand, river flows, wind conditions, and current wholesale prices.

PGE’s thermal generating plants require varying levels of annual maintenance, during which the respective plants are unavailable to provide power. As a result, the amount of power generated to meet the Company’s retail load requirement can vary from period to period. Plant availability approximated 93% and 98% during the three months ended March 31, 2016 and 2015, respectively, for those plants PGE operates. Plant availability of Colstrip Units 3 and 4, of which the Company has a 20% ownership interest and does not operate, in total, approximated 96% and 94% during the three months ended March 31, 2016 and 2015, respectively.

During the three months ended March 31, 2016, the Company’s generating plants provided approximately 56% of its retail load requirement compared with 41% in the three months ended March 31, 2015. The increase in the proportion of power generated to meet the Company’s retail load requirement was largely the result of increased production from the Company’s thermal generation facilities during the three months ended March 31, 2016 relative to the three months ended March 31, 2015.

Energy expected to be received from PGE-owned hydroelectric plants and under contracts from mid-Columbia hydroelectric projects is projected annually in the Annual Power Cost Update Tariff (AUT). Any excess in such hydro generation from that projected in the AUT normally displaces power from higher cost sources, while any shortfall is normally replaced with power from higher cost sources. Energy received from these hydro resources exceeded projected levels included in PGE’s AUT by 11% for the three months ended March 31, 2016 and exceeded

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projected levels by 10% for the three months ended March 31, 2015, and provided 21% and 22% of the Company’s retail load requirement for the three months ended March 31, 2016 and 2015, respectively. Energy from hydro resources is expected to approximate levels projected in the AUT for 2016.

Energy expected to be received from PGE-owned wind generating resources (Biglow Canyon and Tucannon River) is projected annually in the AUT. Any excess in wind generation from that projected in the AUT normally displaces power from higher cost sources, while any shortfall is normally replaced with power from higher cost sources. Energy received from these wind generating resources fell short of that projected in PGE’s AUT by 21% for the three months ended March 31, 2016 and 36% for the three months ended March 31, 2015, and provided approximately 8% and 6% of the Company’s retail load requirement during the three months ended March 31, 2016 and 2015, respectively.

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. NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts (all classified as Purchased power and fuel expense in the Company’s condensed consolidated statements of income) and is net of wholesale revenues, which are classified as Revenues, net in the condensed consolidated statements of income. To the extent actual annual NVPC, subject to certain adjustments, is above or below the deadband, which is a defined range from $15 million below to $30 million above baseline NVPC, the PCAM provides for 90% of the variance beyond the deadband to be collected from or refunded to customers, respectively, subject to a regulated earnings test.

Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in the Company’s condensed consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense.

For the three months ended March 31, 2016, actual NVPC was $1 million above baseline NVPC. Based on forecast data, NVPC for the year ending December 31, 2016 is currently estimated to be below baseline NVPC, but within the deadband range. Accordingly, no estimated collection from, or refund to, customers is expected under the PCAM for 2016.

For the three months ended March 31, 2015, actual NVPC was $2 million below baseline NVPC. For the year ended December 31, 2015, actual NVPC was $3 million below baseline NVPC, which was within the established deadband range. Accordingly, no estimated refund to customers was recorded pursuant to PCAM for 2015.

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:


•	An investigation of environmental matters regarding Portland Harbor;


•	Claims pertaining to the default by the original contractor constructing Carty.

For additional information regarding the above and other matters, see Note 7, Contingencies and Note 9, Carty Generating Station, in the Notes to Condensed Consolidated Financial Statements.

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The State of Oregon passed Senate Bill 1547, effective March 8, 2016, a law referred to as the Oregon Clean Electricity and Coal Transition Plan, that will impact PGE in a variety of ways. The legislation prevents large utilities from including the costs and benefits associated with coal-fired generation in their Oregon retail rates after 2030 (subject to an exception that extends this date until 2035 for the Company’s output from the Colstrip facility), increases the RPS percentages in certain future years, changes the life of certain renewable energy certificates, requires the development of community solar programs, seeks the development of transportation electrification programs, and requires that a portion of electricity come from small scale renewable or certain biomass projects.

Under the new law, PGE will be required to:


•	fully depreciate its portion of the Colstrip facility by 2030, with the potential to utilize the output of the facility in Oregon until 2035;


•	meet RPS thresholds of 27% by 2025, 35% by 2030, 45% by 2035, and 50% by 2040;


•	limit the life of renewable energy certificates (RECs) generated from facilities that become operational after 2022 to five years, but maintain the unlimited lifespan of all existing RECs and allow for the generation of additional unlimited RECs for a period of 5 years for projects on line before December 31, 2022;


•	include projected production tax credits (PTCs) in prices through any variable power cost forecasting process established by the OPUC, the first of which applies to the AUT filing for 2017; and


•	include energy storage costs in its RAC filings.

The Company is in the process of evaluating the impacts and incorporating the effects of the legislation into its 2016 Integrated Resource Plan (2016 IRP), which is anticipated to be filed with the OPUC in the second half of 2016.

On August 3, 2015, the EPA released a final rule, which it calls the “Clean Power Plan.” Under the final rule, each state would have to reduce the carbon intensity of its power sector on a state-wide basis by an amount specified by the EPA. The rule establishes state-specific goals in terms of pounds of carbon dioxide emitted per MWh of energy produced. The rule is intended to result in a reduction of carbon emissions from existing power plants across all states to approximately 32% below 2005 levels by 2030.

The target amount was determined based on the EPA’s view of the options for each state, including: i) making efficiency upgrades at fossil fuel-fired power plants; ii) shifting generation from coal-fired plants to natural gas-fired plants; and iii) expanding use of zero- and low-carbon emitting generation (such as renewable energy and nuclear energy). The final goal would need to be met by 2030 and interim goals for each state would need to be met from 2022 to 2029. Under the rule, states have flexibility in designing programs to meet their emission reduction targets, including the three approaches noted above and any other measures the states choose to adopt (such as carbon tax and cap-and-trade) that would result in verified emission reductions.

States have until September 6, 2016 to submit plans to implement the rule (subject to extension). PGE cannot predict how the states in which the Company’s thermal generation facilities are located (Oregon and Montana) will implement the rule or how the rule may impact the Company’s operations. The Company continues to monitor the developments around the implementation of the rule and efforts by state regulators to develop state plans. On February 9, 2016, the United States Supreme Court granted a stay, halting implementation and enforcement of the Clean Power Plan pending the resolution of legal challenges to the rule. The Company cannot predict the impact of the stay, the ultimate outcome of the legal challenges, or whether Oregon and Montana will continue to develop implementation plans for the rule’s previously required September 6, 2016 deadline.

In December 2014, the EPA signed a final rule, which became effective October 19, 2015, to regulate Coal Combustion Residuals (CCRs) under the Resource Conservation and Recovery Act. Boardman produces dry CCRs

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as a by-product that has historically been disposed of at an on-site landfill, which is permitted and regulated by the State of Oregon under requirements similar to the new EPA rule. PGE has determined that it will continue use of the on-site landfill in compliance with the new rule, and the Company believes the new EPA rule will not have a material effect on operations at Boardman. The Company has been informed by the operator of Colstrip, however, that this rule will have an effect on operations at Colstrip, which produces wet CCRs as a by-product. As a result, PGE recorded an increase to the existing Colstrip asset retirement obligation in the amount of $17 million, with a corresponding increase in the cost basis of the plant, in 2015.

The following discussion highlights certain regulatory items that have impacted the Company’s revenues, results of operations, or cash flows for the first quarter of 2016 compared to the first quarter of 2015, or have 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. As part of its 2016 GRC, PGE included a projected $31 million reduction in power costs that was approved and included in the overall $12 million annual revenue increase, as authorized by the OPUC, with new prices effective January 1, 2016.

Under the PCAM for 2015, NVPC was within the limits of the deadband, thus no potential refund or collection was recorded. The OPUC will review the results of the PCAM for 2015 during the latter half of 2016 with a decision expected in the fourth quarter of 2016. Any resulting refund to or collection from customers would occur during 2017.

As a result of the OCEP legislation described above, PGE has submitted its 2017 AUT filing with the inclusion of projected PTCs for the 2017 calendar year. Any adjustment in customer prices would be expected to occur January 1, 2017.

Renewable Resource Costs—Pursuant to its 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.

On April 1, 2015, PGE submitted to the OPUC a RAC filing that requested revenue requirements related to a new, 1.2 MW solar facility. Concurrent with this filing, PGE also requested authorization to engage in a property sale as part of a sale-leaseback agreement for the facility. The Company estimates that overall annual impact to customer prices of this RAC filing will be an approximately $2 million reduction in revenues over a one year period beginning January 1, 2016. On October 2, 2015, the OPUC issued an order approving the deferral of costs associated with the facility. On March 30, 2016, PGE submitted to the OPUC a RAC filing that requested no significant additions or deferrals for 2016.

Decoupling—The decoupling mechanism, which the OPUC has authorized through 2016, is intended to provide for recovery of margin lost as a result of a reduction in electricity sales attributable to energy efficiency and conservation efforts by residential and certain commercial customers. In March 2016, PGE filed a request with the OPUC to have the mechanism extended through 2019. The mechanism provides for collection from (or refund to) customers if weather adjusted use per customer is less (or more) than that projected in the Company’s most recent approved general rate case.

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Accordingly, collection of the estimated $5 million recorded during 2013 occurred during 2015. Refund of the $5 million recorded during 2014, is expected to occur over a one year period, which began January 1, 2016. The $9 million refund recorded in 2015 that resulted from variances between actual weather adjusted use per customer and that projected in the 2015 GRC, subject to OPUC approval, is expected to occur over a one year period, which would begin January 1, 2017.

For the three months ended March 31, 2016, the Company has recorded an estimated collection of $3 million. Any resulting collection from (or refund to) customers for the 2016 year would begin January 1, 2018.

Integrated Resource Plan—PGE’s latest IRP (2013 IRP), outlines the Company’s expectations for resource needs and resource portfolio performance over the next 20 years. As acknowledged by the OPUC in December 2014, and updated in December 2015, the 2013 IRP includes an “Action Plan,” which covers PGE’s proposed actions through 2017. Over this period of time, the Company projects energy requirements and energy availability through its generating resources and long-term power purchase agreements to be in approximate balance.

The Action Plan includes the following, among other items, to be undertaken through 2017:


•	Seek renewal, or partial renewal, of expiring power purchase agreements for energy generated from hydroelectric projects, if available and cost-effective for customers;


•	Acquire a total of 114 MWa of energy efficiency through continuation of Energy Trust of Oregon programs, with a target increase of 124 MWa, if legislation and regulation allow;


•	Acquire an additional 25 MW of demand response and 23 MW of dispatchable standby generation from customers to help manage peak load conditions and other supply contingencies; and

•

Perform various research and studies related to load forecast and energy efficiency projections, distributed generation resources within PGE’s service territory, the viability of large-scale biomass operations, fuel supply, operational flexibility requirements and analytical tools, cost-benefit analysis of Energy Imbalance Market (EIM) participation, RPS compliance strategies, and potential impacts of compliance with the EPA’s Clean Power Plan rules concerning reductions in carbon dioxide emissions from existing fossil fuel-fired power plants in preparation for the next IRP.

The 2013 IRP, an update to which was filed with the OPUC in December 2015, also incorporates PW2 and Tucannon River, both of which were placed into service in December 2014, and Carty, which is under construction and expected to be placed in service in by July 31, 2016. For additional information on Carty, see “Capital Requirements and Financing” in the Overview section of this Item 2.

In accordance with the Action Plan, PGE has evaluated its participation in an EIM. In September 2015, the Company announced plans to explore participation in the western EIM, which was launched in 2014 by the California Independent System Operator. The western EIM is a real-time energy wholesale market that automatically dispatches the lowest-cost electricity resources available to meet utility customer needs, while optimizing use of renewable energy over a large geographic area. PGE has signed an agreement, which was approved by the FERC in January 2016, to join the western EIM. The agreement outlines a schedule of activities and milestones over the next two years with the Company’s participation in the EIM targeted to begin in the fall of 2017.

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PGE’s next IRP filing with the OPUC, anticipated in the latter half of 2016, will address needs that include additional resources in order to meet the 2020 RPS requirements and to replace energy and capacity from Boardman, which is scheduled to cease coal-fired operations at the end of 2020. Further actions through 2020 are expected to be identified that would offset expiring power purchase agreements and integrate variable energy resources, such as wind or solar generation facilities. The 2016 IRP will also consider the OCEP, which, among other things, increased the RPS requirements for 2025 and future years. For further information, see the “Legal, Regulatory and Environmental” section of this Item 2.

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, 2015, filed with the SEC on February 12, 2016.

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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,
	2016					2015
Revenues, net	$	487		100	%	$	473	100	%
Purchased power and fuel	149			31		161		34
Gross margin	338			69		312		66
Other operating expenses:
Generation, transmission and distribution	66			14		62		13
Administrative and other	61			12		60		13
Depreciation and amortization	82			17		75		16
Taxes other than income taxes	30			6		30		6
Total other operating expenses	239			49		227		48
Income from operations	99			20		85		18
Interest expense*	27			5		30		6
Other income:
Allowance for equity funds used during construction	7			1		4		1
Miscellaneous income (expense), net	(1		)	—		1		—
Other income, net	6			1		5		1
Income before income tax expense	78			16		60		13
Income tax expense	17			3		10		2
Net income	$	61		13	%	$	50	11	%

* Net of an allowance for borrowed funds used during construction of $4 million and $3 million for the three months ended March 31, 2016 and 2015, respectively.

Net income attributable to PGE was $61 million, or $0.68 per diluted share, for the three months ended March 31, 2016, compared with $50 million, or $0.62 per diluted share, for the three months ended March 31, 2015. The increase in Net income was driven by an 8.9% increase in residential energy deliveries resulting from weather, which, although warmer than average, was cooler than in the first quarter of 2015. Overall retail deliveries were up 2.7% in the three months ended March 31, 2016, compared with the three months ended March 31, 2015. The earnings per share amounts reflect, in part, the impact of an additional 10.4 million common shares issued in June 2015.

Three Months Ended March 31, 2016 Compared with the Three Months Ended March 31, 2015

Revenues, energy deliveries (presented in MWh), and the average number of retail customers consist of the following for the periods presented:



	Three Months Ended March 31,
	2016				2015
Revenues ⁽¹⁾ (dollars in millions):
Retail:
Residential	$	254	52	%	$	234	49	%
Commercial	160		33		155		33
Industrial	49		10		56		12
Subtotal	463		95		445		94
Other retail revenues, net	3		1		2		—
Total retail revenues	466		96		447		95
Wholesale revenues	12		2		19		4
Other operating revenues	9		2		7		1
Total revenues	$	487	100	%	$	473	100	%
Energy deliveries (MWh in thousands):
Retail:
Residential	2,103		39	%	1,931		36	%
Commercial	1,702		32		1,631		30
Industrial	697		13		822		15
Subtotal	4,502		84		4,384		81
Direct access:
Commercial	129		2		129		3
Industrial	283		5		272		5
Subtotal	412		7		401		8
Total retail energy deliveries	4,914		91		4,785		89
Wholesale energy deliveries	488		9		580		11
Total energy deliveries	5,402		100	%	5,365		100	%
Average number of retail customers:
Residential	749,287		88	%	739,531		88	%
Commercial	104,872		12		103,824		12
Industrial	187		—		201		—
Direct access	382		—		403		—
Total	854,728		100	%	843,959		100	%


(1)	Includes revenues from customers who purchase their energy from the Company as well as $7 million in revenues for each of 2016 and 2015 from Direct access customers for transmission and delivery charges only.

Total revenues for the three months ended March 31, 2016 increased $14 million compared to the three months ended March 31, 2015, as a $19 million increase in Retail revenues was partially offset by a reduction in Wholesale revenues.

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The change in Retail revenues resulted from the following:

•

A $12 million increase related to 2.7% higher volumes of retail energy delivered, with increases of 8.9% from residential customers and 4.0% from commercial customers, partially offset by a 10.4% decrease in deliveries to industrial customers. After adjusting for the effects of weather, total retail energy deliveries were up 0.6% for the three months ended March 31, 2016 compared with the three months ended March 31, 2015; and


•	An $8 million increase attributed to a slight rise in the overall average system delivery price as a higher percentage of the Company’s retail deliveries were to residential customers, 43% in 2016 versus 40% in 2015, while deliveries to industrial customers, at somewhat lower prices, declined; partially offset by

•

A $1 million decrease related to various supplemental tariff changes, including the discontinuance of $5 million collection for the four capital project deferrals in 2015 partially offset by the refund of $3 million to customers in the first three months of 2015 of proceeds received in connection with the settlement of a legal matter related to the operation of the ISFSI at the Trojan nuclear power plant, which was closed in 1993 (offset in Depreciation and amortization). A number of additional small supplemental tariff adjustments occurred that reduced revenues in total by $1 million.

Total heating degree-days for the three months ended March 31, 2016 were 7% higher than the three months ended March 31, 2015 although 15% below average. The following table indicates the number of heating degree-days for the three months ended March 31, 2016 and 2015, along with 15-year averages based on weather data provided by the National Weather Service, as measured at Portland International Airport:



	Heating Degree-days
	2016	2015	Avg.
January	688	662	734
February	448	437	599
March	449	382	533
Year-to-date	1,585	1,481	1,866

Wholesale revenues for the three months ended March 31, 2016 decreased $7 million, or 37%, from the three months ended March 31, 2015, and consisted of $4 million related to a 23% decrease in average wholesale price combined with $3 million related to a 16% decrease in wholesale sales volume.

Purchased power and fuel expense decreased $12 million, or 7%, for the three months ended March 31, 2016 compared with the three months ended March 31, 2015, and consisted of $13 million related to an 8% decrease in the average variable power cost per MWh, partially offset by $1 million related to a 1% increase in total system load.

The decrease in the average variable power cost to $28.13 per MWh in the three months ended March 31, 2016 from $30.59 per MWh in the three months ended March 31, 2015 was driven by a 40% increase in MWhs generated from Company sources with a 9% decrease in the average variable power cost per MWh. This decrease was due in large part to a 49% increase in MWhs generated from the Company’s natural gas fired facilities that experienced a 25% decrease in the average variable power cost per MWh primarily due to lower natural gas prices. An increase in energy received from the Company’s wind and hydro generating resources also contributed to the decrease in the average variable power cost per MWh due to more favorable weather conditions. The overall decrease was slightly offset by a 2% increase in average variable power cost per MWh from purchased power.

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The sources of energy for PGE’s total system load, as well as its retail load requirement, were as follows for the periods presented:



	Three Months Ended March 31,
	2016				2015
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal	757		14	%	484		9	%
Natural gas	1,002		19		670		13
Total thermal	1,759		33		1,154		22
Hydro	568		11		478		9
Wind	361		7		288		6
Total generation	2,688		51		1,920		37
Purchased power:
Term	1,486		28		1,500		28
Hydro	445		9		530		10
Wind	59		1		57		1
Spot	602		11		1,240		24
Total purchased power	2,592		49		3,327		63
Total system load	5,280		100	%	5,247		100	%
Less: wholesale sales	(488	)			(580	)
Retail load requirement	4,792				4,667

Energy received from PGE-owned wind generating resources increased 25% in the three months ended March 31, 2016 compared with the same period of 2015 as a result of more favorable wind conditions. Energy received from these wind generating resources represented 8% and 6% of the Company’s retail load requirements for the three months ended March 31, 2016 and 2015, respectively. Due to comparable hydroelectric conditions, energy received from hydro resources during the three months ended March 31, 2016, from both PGE-owned generating plants and purchased from mid-Columbia projects, increased 1% compared with the same period of 2015, and represented 21% and 22% of the Company’s retail load requirement for the three months ended March 31, 2016 and 2015, respectively.

The following table presents the forecast of the April-to-September 2016 runoff (issued April 21, 2016), along with actual for 2015, at particular points of major rivers relevant to PGE’s hydro resources (as a percentage of normal, as measured over the 30-year period from 1981 through 2010):



	Runoff as a Percent of Normal*
Location	2016 Forecast		2015 Actual
Columbia River at The Dalles, Oregon	105	%	69	%
Mid-Columbia River at Grand Coulee, Washington	106		77
Clackamas River at Estacada, Oregon	82		53
Deschutes River at Moody, Oregon	92		85

* Volumetric water supply forecasts and historical 30-year averages for the Pacific Northwest region are prepared by the Northwest River Forecast Center in conjunction with the Natural Resources Conservation Service and other cooperating agencies.

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Actual NVPC for the three months ended March 31, 2016 decreased $5 million when compared with the three months ended March 31, 2015. The decrease was driven by an 8% decline in the average variable power cost per MWh. Partially offsetting the decrease to NVPC was a 1% increase in total system load combined with a 23% decrease in the average wholesale sales price and a 16% decrease in wholesale sales volume. For the three months ended March 31, 2016 and 2015, actual NVPC was $1 million above and $2 million below baseline NVPC, respectively.

Generation, transmission and distribution expense increased $4 million, or 6%, in the three months ended March 31, 2016 compared with the three months ended March 31, 2015 driven primarily by $2 million higher labor costs, $1 million more service restoration expenses, and $1 million higher information technology expenses, offset by a $1 million decrease due to the timing of the annual planned outage at Boardman.

Administrative and other expense increased $1 million, or 2%, in the three months ended March 31, 2016 compared with the three months ended March 31, 2015. The increase was primarily due to a $2 million increase in compensation and benefits expense, offset by a $1 million decrease due to a reduction in the reserve for customer receivables.

Depreciation and amortization expense increased $7 million in the three months ended March 31, 2016 compared with the three months ended March 31, 2015. The increase was primarily driven by $4 million additional expense due to capital additions, $4 million due to the temporary discontinuance of amortization of credits for the regulatory liability for the Trojan spent fuel settlement, and $4 million resulting from a combination of gains recorded on the sale of assets and other minor items, offset by a $5 million decrease that resulted from the completion of the amortization of the regulatory asset for four capital project deferrals as authorized in the Company’s 2011 GRC. Increases or decreases in expense resulting from amortization of regulatory assets or liabilities are directly offset in revenues.

Interest expense decreased $3 million, or 10%, in the three months ended March 31, 2016 compared with the three months ended March 31, 2015, with $2 million related to an 11% decrease in the average balance of debt outstanding and $1 million related to a higher allowance for borrowed funds used during construction.

Other income, net was $6 million in the three months ended March 31, 2016 compared with $5 million in the three months ended March 31, 2015. The change was due to a $3 million increase in the allowance for equity funds used during construction resulting from higher average CWIP balances, offset by a $2 million decrease in earnings on the non-qualified benefit plan trust assets.

Income tax expense was $17 million in the three months ended March 31, 2016 compared with $10 million in the three months ended March 31, 2015, with effective tax rates of 21.8% and 16.7%, respectively. The increase in income tax expense was primarily due to higher pre-tax income.

Liquidity and Capital Resources

Capital Requirements

The following table presents PGE’s estimated capital expenditures and contractual maturities of long-term debt for 2016 through 2020 (in millions, excluding AFDC):



	2016			2017		2018		2019		2020
Ongoing capital expenditures ⁽¹⁾	$	425		$	347	$	301	$	282	$	301
Carty Generating Station⁽²⁾	224			—		—		—		—
Total capital expenditures	$	649	⁽³⁾	$	347	$	301	$	282	$	301
Long-term debt maturities	$	—		$	—	$	—	$	300	$	—


(1)	Consists primarily of upgrades to, and replacement of, generation, transmission, and distribution infrastructure, as well as new customer connections. In the 2016 through 2018 years, $110 million relates to the implementation of the Company’s new customer information and meter data management systems.


(2)	Amount shown for 2016 reflects the high end of the estimated range of capital expenditures to complete Carty, which is $189 million to $224 million, before considering any amount that may be received from the Sureties pursuant to the Performance Bond.


(3)	Includes preliminary engineering and removal costs, which are included in other net operating activities in the condensed consolidated statements of cash flows.

For additional information on Carty, see “Carty Generating Station” in the Overview section of this Item 2. For a discussion concerning PGE’s ability to fund its future capital requirements, see “Debt and Equity Financings” in this Item 2.

Liquidity

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

The following summarizes PGE’s cash flows for the periods presented (in millions):



	Three Months Ended March 31,
	2016			2015
Cash and cash equivalents, beginning of period	$	4		$	127
Net cash provided by (used in):
Operating activities	161			134
Investing activities	(133		)	(167		)
Financing activities	(28		)	(67		)
Decrease in cash and cash equivalents	—			(100		)
Cash and cash equivalents, end of period	$	4		$	27

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Cash Flows from Operating Activities—Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, with adjustments for certain non-cash items, such as depreciation and amortization, deferred income taxes, and pension and other postretirement benefit costs included in net income during a given period. Net cash flows from operating activities for the three months ended March 31, 2016 increased $27 million when compared with the three months ended March 31, 2015. Such increase was largely due to an increase in net income adjusted for the increase in depreciation and amortization and deferred tax expense, and other changes in working capital items as a result of amount and timing of transactions.

Cash provided by operations includes the recovery in customer prices of non-cash charges for depreciation and amortization. PGE estimates that such charges in 2016 will range from $315 million to $325 million. Combined with other sources, total cash expected to be provided by operations is estimated to range from $450 million to $490 million.

Cash Flows from Investing Activities—Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s generation facilities and transmission and distribution systems. Net cash used in investing activities for the three months ended March 31, 2016 decreased $34 million when compared with the three months ended March 31, 2015. Such decrease was largely due to a $47 million decrease in capital expenditures, partially offset by a $12 million collection of a sales tax refund related to Tucannon River in the three months ended March 31, 2015.

The Company plans approximately $649 million of capital expenditures for 2016, including $224 million related to the construction of Carty. PGE plans to fund the 2016 capital expenditures with cash expected to be generated from operations during 2016, as discussed above, as well as with proceeds received from the issuances debt securities. For additional information, see “Capital Requirements” and “Debt and Equity Financings” in this Liquidity and Capital Resources section of Item 2.

Cash Flows from Financing Activities—Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the three months ended March 31, 2016, net cash used in financing activities consisted primarily of the repayment of long-term debt of $133 million and the payment of dividends of $27 million, partially offset by proceeds received from the issuances of FMBs of $140 million. During the three months ended March 31, 2015, net cash used in financing activities consisted of the repayment of FMBs of $120 million and the payment of dividends of $22 million, partially offset by proceeds received from the issuance of FMBs of $75 million.

Dividends on Common Stock

While PGE expects to pay regular quarterly dividends on its common stock, the declaration of any dividends is at the discretion of the Company’s Board of Directors. The amount of any dividend declaration will depend upon factors that the Board of Directors deems relevant, which may include, among other things, PGE’s results of operations and financial condition, future capital expenditures and investments, and applicable regulatory and contractual restrictions.

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Common stock dividends declared during 2016 consist of the following:



			Dividends
			Declared Per
Declaration Date	Record Date	Payment Date	Common Share
February 17, 2016	March 25, 2016	April 15, 2016	$0.30
April 27, 2016	June 27, 2016	July 15, 2016	$0.32

Debt and Equity Financings

PGE’s ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, its credit ratings, its capital expenditure requirements, alternatives available to investors, market conditions, and other factors. Management believes that the availability of its revolving credit facility, the expected ability to issue long-term debt and equity securities, and cash expected to be generated from operations provide sufficient cash flow and liquidity to meet the Company’s anticipated capital and operating requirements for the foreseeable future. However, the Company’s ability to issue long-term debt and equity could be adversely affected by changes in capital market conditions. For 2016, PGE expects to fund estimated capital expenditures and maturities of long-term debt with cash from operations (which is expected to range from $450 million to $490 million), issuances of debt securities of up to $500 million, including $140 million FMBs issued in January 2016, and the issuance of commercial paper, as needed. The actual timing and amount of any such issuances of debt and commercial paper will be dependent upon the timing and amount of capital expenditures.

Short-term Debt. PGE has approval from the FERC to issue short-term debt up to a total of $900 million through February 6, 2018.

As of March 31, 2016, PGE had a $500 million credit facility scheduled to expire in November 2019. The revolving credit facility supplements operating cash flows and provides a primary source of liquidity. Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, as backup for commercial paper borrowings, and to 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.

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 facility.

Under the revolving credit facility, as of March 31, 2016, PGE had no borrowings, commercial paper outstanding, or letters of credit issued. As of March 31, 2016, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

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In addition, PGE has four letter of credit facilities under which the Company can request letters of credit for original terms not to exceed one year. These facilities provide for a total capacity of $160 million. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these facilities, letters of credit for a total of $111 million were outstanding as of March 31, 2016.

Long-term Debt. During the three months ended March 31, 2016, PGE had the following long-term debt transactions, all of which occurred in early January:


•	Issued $140 million of 2.51% Series First Mortgage Bonds (FMBs) due 2021;


•	Repaid $75 million of 5.80% Series FMBs, due in 2018; and


•	Repaid $58 million of 3.81% Series FMBs, due in 2017.

As of March 31, 2016, total long-term debt outstanding, net of $12 million of unamortized debt expense, was $2,199 million, with no scheduled maturities classified as current.

Capital Structure. PGE’s financial objectives include maintaining a common equity ratio (common equity to total consolidated capitalization, including any current debt maturities) of approximately 50% over time. Achievement of this objective helps the Company maintain investment grade credit ratings and facilitates access to long-term capital at favorable interest rates. The Company’s common equity ratios were 50.4% and 50.7% as of March 31, 2016 and December 31, 2015, respectively.

Credit Ratings and Debt Covenants

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



	Moody’s	S&P
First Mortgage Bonds	A1	A-
Issuer rating	A3	BBB
Commercial paper	Prime-2	A-2
Outlook	Stable	Stable

Should Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt below investment grade, the Company could be subject to requests by certain of its wholesale, commodity, and transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, are based on the contract terms and commodity prices, and can vary from period to period. Cash deposits provided as collateral are classified as Margin deposits, which is included in Other current assets on PGE’s condensed consolidated balance sheets, while any letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

As of March 31, 2016, PGE had posted approximately $105 million of collateral with these counterparties, consisting of $39 million in cash and $66 million in letters of credit. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of March 31, 2016, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade was approximately $99 million, and decreases to approximately $44 million by December 31, 2016 and $19 million by December 31, 2017. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade was approximately $179 million at March 31, 2016, and decreases to approximately $87 million by December 31, 2016 and $60 million by December 31, 2017.

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PGE’s financing arrangements do not contain ratings triggers that would result in the acceleration of required interest and principal payments in the event of a ratings downgrade. However, the cost of borrowing and issuing letters of credit under the credit facility would increase.

The issuance of FMBs requires that PGE meet earnings coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust (Indenture) securing the bonds. PGE estimates that on March 31, 2016, under the most restrictive issuance test in the Indenture, the Company could have issued up to approximately $1,082 million of additional FMBs. Any issuances of FMBs would be subject to market conditions and amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE also has the ability to release property from the lien of the Indenture under certain circumstances, including bond credits, deposits of cash, or certain sales, exchanges, or other dispositions of property.

PGE’s credit facility contains customary covenants and credit provisions, including a requirement that limits consolidated indebtedness, as defined in the credit agreements, to 65.0% of total capitalization (debt-to-total capital ratio). As of March 31, 2016, the Company’s debt-to-total capital ratio, as calculated under the credit agreement, was 49.9%.

Off-Balance Sheet Arrangements

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

Contractual Obligations

PGE’s contractual obligations for 2016 and beyond are set forth in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 12, 2016. Such obligations have not changed materially as of March 31, 2016.



Item 3.	Quantitative and Qualitative Disclosures About Market Risk.

PGE is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, foreign currency exchange rates, and interest rates, as well as credit risk. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 12, 2016.



Item 4.	Controls and Procedures.

Disclosure Controls and Procedures

PGE’s management, under the supervision and with the participation of its Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures as required by Exchange Act Rule 13a-15(b) as of the end of the period covered by this report. Based on that evaluation, PGE’s Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2016, these disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

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

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PART II - OTHER INFORMATION



Item 1.	Legal Proceedings.

For further information regarding PGE’s legal proceedings, see “Legal Proceedings” set forth in Part I, Item 3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 12, 2016.

Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court; and Morgan v. Portland General Electric Company, Marion County Circuit Court.

On February 22, 2016, the Marion County Circuit Court denied the plaintiff’s motion to amend the Complaint. On March 16, 2016, the Marion County Circuit Court entered a general judgment that granted the Company’s motion for summary judgment and dismissed all claims by the plaintiffs. On April 14, 2016, the plaintiffs appealed the general judgment of the Circuit Court in the Court of Appeals for the State of Oregon.

Sierra Club and Montana Environmental Information Center v. PPL Montana LLC, Avista Corporation, Puget Sound Energy, Portland General Electric Company, Northwestern Corporation, and PacifiCorp, U.S. District Court for the District of Montana.

Portland General Electric Company v Liberty Mutual Insurance Company and Zurich American Insurance Company, U.S. District Court of the District of Oregon.

For a discussion on this matter, see “Carty Generating Station” set forth in the Overview section of Part I, Item 2 of this Quarterly Report on Form 10-Q.



Item 1A.	Risk Factors.

There have been no material changes to PGE’s risk factors set forth in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 12, 2016.

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Item 5.	Other Information.

Portland General Electric Company held its 2016 annual meeting of shareholders on April 27, 2016 in Portland, Oregon. The following proposals were voted on at the meeting by the Company’s shareholders:


1.	The election of directors;


2.	The ratification of the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2016; and


3.	An advisory, non-binding vote to approve the compensation of the Company’s named executive officers.

There were 88,887,865 shares of common stock issued and outstanding as of February 29, 2016, the record date for the meeting, with 85,109,609 shares represented at the annual meeting.

Each of the director nominees listed below was elected and the voting results were as follows:



Nominee	For	Against	Abstain	Broker Non-votes
John W. Ballantine	79,183,712	444,576	126,976	5,354,345
Rodney L. Brown, Jr.	79,551,969	79,864	123,431	5,354,345
Jack E. Davis	79,551,202	80,025	124,037	5,354,345
David A. Dietzler	79,532,018	96,967	126,279	5,354,345
Kirby A. Dyess	79,543,020	82,947	129,297	5,354,345
Mark B. Ganz	79,561,474	65,796	127,994	5,354,345
Kathryn J. Jackson	79,568,673	62,866	123,725	5,354,345
Neil J. Nelson	79,561,709	65,572	127,983	5,354,345
M. Lee Pelton	79,199,689	430,228	125,347	5,354,345
James J. Piro	79,557,347	73,213	124,704	5,354,345
Charles W. Shivery	79,547,970	81,244	126,050	5,354,345

Our shareholders ratified the appointment of Deloitte & Touche LLP as the Company’s independent registered public accounting firm for the year ending December 31, 2016. There were 84,539,680 votes cast for the proposal, 479,448 votes cast against the proposal and 90,481 abstentions.

Our shareholders approved, on an advisory, non-binding basis, the compensation of the Company’s named executive officers. There were 78,940,289 votes cast for the proposal, 645,556 votes cast against the proposal, 169,419 abstentions and 5,354,345 broker non-votes.

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Item 6.	Exhibits.

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Exhibit Number	Description
3.1	Third Amended and Restated Articles of Incorporation of Portland General Electric Company (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed May 9, 2014).
3.2	Tenth Amended and Restated Bylaws of Portland General Electric Company (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed May 9, 2014).
10.1	Portland General Electric Company 2006 Stock Incentive Plan, as amended effective February 16, 2016.
10.2	Portland General Electric Company 2008 Annual Cash Incentive Master Plan for Executive Officers, as amended effective February 17, 2016.
10.3	Form of Officers’ and Key Employees’ Performance Stock Unit Agreement.
31.1	Certification of Chief Executive Officer.
31.2	Certification of Chief Financial Officer.
32	Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

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

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SIGNATURE

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



		PORTLAND GENERAL ELECTRIC COMPANY
		(Registrant)


Date:	April 28, 2016	By:	/s/ James F. Lobdell
			James F. Lobdell
			Senior Vice President of Finance, Chief Financial Officer and Treasurer
			(duly authorized officer and principal financial officer)