Document and Entity Information
9 Months Ended
Sep. 30, 2017
Oct. 17, 2017
Entity Information [Line Items]
 
 
Entity Registrant Name
PORTLAND GENERAL ELECTRIC CO /OR/ 
 
Entity Central Index Key
0000784977 
 
Document Type
10-Q 
 
Document Period End Date
Sep. 30, 2017 
 
Amendment Flag
false 
 
Document Fiscal Year Focus
2017 
 
Document Fiscal Period Focus
Q3 
 
Current Fiscal Year End Date
--12-31 
 
Entity Filer Category
Large Accelerated Filer 
 
Entity Common Stock, Shares Outstanding
 
89,092,325 
Trading Symbol
POR 
 
Condensed Consolidated Statements of Income and Comprehensive Income (Unaudited) (USD $)
In Millions, except Share data in Thousands, unless otherwise specified
3 Months Ended 9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Sep. 30, 2017
Sep. 30, 2016
Revenues, net
$ 515 
$ 484 
$ 1,494 
$ 1,399 
Operating expenses:
 
 
 
 
Purchased power and fuel
184 
180 
443 
455 
Generation, transmission and distribution
73 
69 
235 
199 
Administrative and other
64 
63 
197 
185 
Depreciation and amortization
87 
79 
257 
244 
Taxes other than income taxes
30 
29 
94 
89 
Total operating expenses
438 
420 
1,226 
1,172 
Income from operations
77 
64 
268 
227 
Interest expense, net
30 
28 
90 
82 
Other income:
 
 
 
 
Allowance for equity funds used during construction
19 
Miscellaneous income, net
Other income, net
13 
19 
Income before income tax expense
53 
40 
191 
164 
Income tax expense
13 
46 
32 
Net income and Comprehensive income
$ 40 
$ 34 
$ 145 
$ 132 
Weighted-average shares outstanding-basic and diluted (in thousands)
89,065 
88,921 
89,044 
88,885 
Earnings per share-basic and diluted
$ 0.44 
$ 0.38 
$ 1.62 
$ 1.49 
Dividends declared per common share
$ 0.34 
$ 0.32 
$ 1.00 
$ 0.94 
Condensed Consolidated Balance Sheets (Unaudited) (USD $)
In Millions, unless otherwise specified
Sep. 30, 2017
Dec. 31, 2016
Current assets:
 
 
Cash and cash equivalents
$ 89 
$ 6 
Accounts receivable, net
151 
155 
Unbilled revenues
71 
107 
Inventories
70 
82 
Regulatory assets - current
42 
36 
Other current assets
43 
77 
Total current assets
466 
463 
Electric utility plant, net
6,638 
6,434 
Regulatory assets - noncurrent
526 
498 
Nuclear decommissioning trust
41 
41 
Non-qualified benefit plan trust
37 
34 
Other noncurrent assets
51 
57 
Total assets
7,759 
7,527 
Current liabilities
 
 
Accounts payable
100 
129 
Liabilities from price risk mangement activities - current
43 
44 
Current portion of long-term debt
100 
150 
Accrued expenses and other current liabilities
248 
254 
Total current liabilities
491 
577 
Long-term debt, net of current portion
2,277 
2,200 
Regulatory liabilities-noncurrent
1,002 
958 
Deferred income taxes
701 
669 
Unfunded status of pension and postretirement plans
288 
281 
Liabilities from price risk management activities-noncurrent
150 
125 
Asset retirement obligations
166 
161 
Non-qualified benefit plan liabilities
105 
105 
Other noncurrent liabilities
177 
107 
Total liabilities
5,357 
5,183 
Commitments and contingencies (see notes)
   
   
Equity:
 
 
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of September 30, 2017 and December 31, 2016
Common stock, no par value, 160,000,000 shares authorized; 89,091,955 and 88,946,704 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively
1,204 
1,201 
Accumulated other comprehensive loss
(7)
(7)
Retained earnings
1,205 
1,150 
Total equity
2,402 
2,344 
Total liabilities and equity
$ 7,759 
$ 7,527 
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)
Sep. 30, 2017
Dec. 31, 2016
Preferred stock, no par value
$ 0 
$ 0 
Preferred stock, shares authorized
30,000,000 
30,000,000 
Preferred stock, issued
Preferred stock, outstanding
Common stock, no par value
$ 0 
$ 0 
Common stock, shares authorized
160,000,000 
160,000,000 
Common stock, shares issued
89,091,955 
88,946,704 
Common stock, shares outstanding
89,091,955 
88,946,704 
Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)
In Millions, unless otherwise specified
9 Months Ended
Sep. 30, 2017
Sep. 30, 2016
Cash flows from operating activities:
 
 
Net income
$ 145 
$ 132 
Adjustments to reconcile net income to net cash provided by operating activities:
 
 
Depreciation and amortization
257 
244 
Deferred income taxes
35 
18 
Pension and other postretirement benefits
19 
21 
Allowance for equity funds used during construction
(9)
(19)
Decoupling mechanism deferrals, net of amortization
(15)
(4)
Other non-cash income and expenses, net
18 
12 
Changes in working capital:
 
 
Decrease in accounts receivable and unbilled revenues
40 
53 
Decrease in inventories
12 
Decrease in margin deposits, net
25 
Increase in accounts payable and accrued liabilities
14 
31 
Other working capital items, net
20 
12 
Other, net
(21)
(29)
Net cash provided by operating activities
519 
497 
Cash flows from investing activities:
 
 
Capital expenditures
(369)
(454)
Sales of Nuclear decommissioning trust securities
14 
17 
Purchases of Nuclear decommissioning trust securities
(12)
(16)
Other, net
(2)
(1)
Net cash used in investing activities
(369)
(454)
Cash flows from financing activities:
 
 
Proceeds from issuance of long-term debt
75 
265 
Payments on long-term debt
(50)
(133)
Change in short-term debt
(6)
Dividends paid
(87)
(82)
Other
(5)
(3)
Net cash (used in) provided by financing activities
(67)
41 
Increase in cash and cash equivalents
83 
84 
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
89 
88 
Supplemental cash flow information is as follows:
 
 
Cash paid for interest, net of amounts capitalized
68 
61 
Cash paid for income taxes
16 
12 
Non-cash investing and financing activities:
 
 
Assets obtained under capital lease
$ 73 
$ 57 
Basis of Presentation (Notes)
BASIS OF PRESENTATION
BASIS OF PRESENTATION

Nature of Business

Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company also 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. The Company’s corporate headquarters is located in Portland, Oregon and its approximately 4,000 square mile, state-approved service area allocation, located entirely within the State of Oregon, encompasses 51 incorporated cities, of which Portland and Salem are the largest. As of September 30, 2017, PGE served approximately 873,000 retail customers with a service area population of approximately 1.9 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 to the 2017 presentation, PGE has reclassified Decoupling mechanism deferrals, net of amortization of $(4) million from Other non-cash income and expenses, net within the operating activities section of the condensed consolidated statement of cash flows for the nine months ended September 30, 2016.

The financial information included herein for the three and nine months ended September 30, 2017 and 2016 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, 2016 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2016, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 17, 2017, which should be read in conjunction with such condensed consolidated financial statements.

Comprehensive Income
PGE had an immaterial amount of Other comprehensive income during the three and nine month periods ended September 30, 2017 and 2016.

Use of Estimates

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

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 (full retrospective method) or as a cumulative-effect adjustment as of the effective date (modified retrospective method), which is January 1, 2018 for calendar year-end public entities. The Company plans to elect the modified retrospective transition method for implementation. PGE does not anticipate any material changes to its revenue policy for tariff-based revenues, which comprises a majority of PGE’s retail revenues, as performance obligations are expected to be satisfied in a similar recognition pattern. PGE continues to evaluate the impacts the new guidance may have on its consolidated financial position, consolidated results of operations, and consolidated cash flows, particularly related to certain matters of presentation of alternative revenue programs (such as decoupling), wholesale, and other operating revenue contracts.

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 principles. Lessees will be required to classify leases as either finance 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 2017, the FASB issued ASU 2017-07, Compensation-Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (ASU 2017-07). Pursuant to this ASU, only the service cost component of net periodic pension and postretirement benefit costs will be eligible for capitalization and should be applied on a prospective basis upon implementation. Also, the non-service components are required to be presented in the income statement separately from the service cost component and outside the subtotal of income from operations and should be applied on a retrospective basis upon implementation. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2018. The Company does not plan to early adopt. For ratemaking purposes, the Company will continue to be allowed to recover this portion of the non-service costs as a component of rate base, however such amounts will be recorded as Regulatory assets on the Company’s condensed consolidated balance sheets, instead of Utility plant, and amortized in a systematic and rational manner and reflected as expense in a line item outside the subtotal of income from operations on the condensed consolidated statements of income and other comprehensive income. PGE estimates the portion of the non-service components of net periodic pension and postretirement benefit costs that is eligible for capitalization for ratemaking purposes, to be $2 million for the twelve month period ending December 31, 2018, and is deemed to have an immaterial impact on the Company’s consolidated financial position and consolidated results of operations.
Balance Sheet Components (Notes)
BALANCE SHEET COMPONENTS
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, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that inventory is recorded at the lower of average cost or net realizable value.

Other Current Assets

Other current assets consist of the following (in millions):
 
September 30, 2017
 
December 31, 2016
Prepaid expenses
$
27

 
$
48

Assets from price risk management activities
4

 
18

Margin deposits
4

 
8

Other
8

 
3

Other current assets
$
43

 
$
77



Electric Utility Plant, Net

Electric utility plant, net consists of the following (in millions):
 
September 30, 2017
 
December 31,
2016
Electric utility plant
$
9,766

 
$
9,534

Construction work-in-progress
386

 
213

Total cost
10,152

 
9,747

Less: accumulated depreciation and amortization
(3,514
)
 
(3,313
)
Electric utility plant, net
$
6,638

 
$
6,434


Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $288 million and $257 million as of September 30, 2017 and December 31, 2016, respectively. Amortization expense related to intangible assets was $11 million for the three months ended September 30, 2017 and 2016, and $34 million and $33 million for the nine months ended September 30, 2017 and 2016, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

Regulatory Assets and Liabilities

Regulatory assets and liabilities consist of the following (in millions):
 
September 30, 2017
 
December 31, 2016
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Regulatory assets:
 
 
 
 
 
 
 
Price risk management
$
39

 
$
150

 
$
26

 
$
120

Pension and other postretirement plans

 
225

 

 
235

Deferred income taxes

 
83

 

 
86

Debt issuance costs

 
20

 

 
22

Other
3

 
48

 
10

 
35

Total regulatory assets
$
42

 
$
526

 
$
36

 
$
498

Regulatory liabilities:
 
 
 
 
 
 
 
Asset retirement removal costs
$

 
$
921

 
$

 
$
887

Trojan decommissioning activities
4

 

 
18

 

Asset retirement obligations

 
52

 

 
49

Other
16

 
29

 
33

 
22

Total regulatory liabilities
$
20

* 
$
1,002

 
$
51

* 
$
958



* 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):
 
September 30, 2017
 
December 31, 2016
Accrued employee compensation and benefits
$
51

 
$
52

Accrued taxes payable
46

 
25

Accrued interest payable
40

 
25

Accrued dividends payable
31

 
30

Regulatory liabilities—current
20

 
51

Other
60

 
71

Total accrued expenses and other current liabilities
$
248

 
$
254



Credit Facilities

As of September 30, 2017, PGE had a $500 million revolving credit facility scheduled to expire in November 2020.

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 credit facility. During the first quarter of 2017, PGE exercised one of the two one-year extensions available under the terms of the credit facility. Such action resulted in an updated expiration date of November 2020. The facility also contains a provision that requires annual fees based on PGEs unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of September 30, 2017, PGE was in compliance with this covenant with a 51.3% 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 September 30, 2017, since PGE had no borrowings outstanding, and no commercial paper or letters of credit issued, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

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 a total capacity of $220 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 $54 million were outstanding as of September 30, 2017. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets.

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

On August 2, 2017, PGE entered into a bond purchase agreement to issue First Mortgage Bonds (FMBs) in the amount of $225 million at an interest rate of 3.98%. The first tranche of $75 million, with a maturity in 2048, was issued on August 2, 2017. The second tranche of $150 million, with a maturity in 2047, is expected to be issued and funded on or about November 21, 2017.

In May 2016, PGE entered into an unsecured credit agreement with certain financial institutions, under which the Company had the opportunity to obtain three separate term loans in an aggregate principal amount of up to $200 million by October 31, 2016. Under the agreement, PGE obtained three separate loans totaling $150 million. On August 21, 2017, the Company repaid one of the loans in the amount of $50 million. The credit agreement expires November 30, 2017, at which time any amounts outstanding under the term loans become due and payable.

The term loan interest rates on the remaining loans are set at the beginning of the interest period for periods of one, three, or six months, as selected by PGE, and are based on the London Interbank Offered Rate plus 63 basis points, and was 1.9% as of September 30, 2017, with no other fees.

Upon the occurrence of certain events of default, the Company’s obligations under the credit agreement may be accelerated. Such events of default include payment defaults to lenders under the credit agreement, covenant defaults, and other customary defaults for financings of this type.

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 September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Service cost
$
4

 
$
4

 
$
12

 
$
12

Interest cost
8

 
9

 
25

 
25

Expected return on plan assets
(10
)
 
(10
)
 
(30
)
 
(30
)
Amortization of net actuarial loss
3

 
3

 
9

 
11

Net periodic benefit cost
$
5

 
$
6

 
$
16

 
$
18

Fair Value of Financial Instruments (Notes)
FAIR VALUE OF FINANCIAL INSTRUMENTS
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 September 30, 2017 and December 31, 2016, 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 measurement date.

Level 2
Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement 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. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy; instead these assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

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 and nine month periods ended September 30, 2017 and 2016, except those presented in this note.

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 September 30, 2017
 
Level 1
 
Level 2
 
Level 3
 
Other(2)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trust: (1)
 
 
 
 
 
 
 
 
 
Debt securities:
 
 
 
 
 
 
 
 
 
Domestic government
$
3

 
$
8

 
$

 
$

 
$
11

Corporate credit

 
7

 

 

 
7

Money market funds measured at NAV (2)

 

 

 
23

 
23

Non-qualified benefit plan trust: (3)
 
 
 
 
 
 
 
 
 
Money market funds
2

 

 

 

 
2

Equity securities—domestic
6

 

 

 

 
6

Debt securities—domestic government
1

 

 

 

 
1

Collective trust—domestic equity measured at NAV (2)

 

 

 

 

Assets from price risk management activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity

 
3

 

 

 
3

Natural gas

 
1

 

 

 
1

 
$
12

 
$
19

 
$

 
$
23

 
$
54

Liabilities from price risk management
activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity
$

 
$
3

 
$
140

 
$

 
$
143

Natural gas

 
37

 
13

 

 
50

 
$

 
$
40

 
$
153

 
$

 
$
193

 
(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 $28 million, which are recorded at cash surrender value.
(4)
For further information, see Note 4, Price Risk Management.

 
As of December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Other (2)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trust: (1)
 
 
 
 
 
 
 
 
 
Debt securities:
 
 
 
 
 
 
 
 
 
Domestic government
$
2

 
$
10

 
$

 
$

 
$
12

Corporate credit

 
8

 

 

 
8

Money market funds measured at NAV (2)

 

 

 
21

 
21

Non-qualified benefit plan trust: (3)
 
 
 
 
 
 
 
 
 
Money market funds
1

 

 

 

 
1

Equity securities—domestic
4

 

 

 

 
4

Debt securities—domestic government
1

 

 

 

 
1

Collective trust—domestic equity measured at NAV (2)

 

 

 
2

 
2

Assets from price risk management activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity

 
6

 
1

 

 
7

Natural gas

 
15

 
1

 

 
16

 
$
8

 
$
39

 
$
2

 
$
23

 
$
72

Liabilities from price risk management
activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity
$

 
$
6

 
$
112

 
$

 
$
118

Natural gas

 
42

 
9

 

 
51

 
$

 
$
48

 
$
121

 
$

 
$
169

 
(1)
Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.
(2)
Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.
(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 (NQ 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 measurement 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.

Equity securities—Equity mutual fund and common stock securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement 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. 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 invest 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 to be 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, futures, and swaps.

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
 
 
 
Low
 
High
 
Weighted Average
 
 
(in millions)
 
 
 
 
 
 
 
 
 
 
As of September 30, 2017:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electricity physical forwards
 
$

 
$
140

 
Discounted cash flow
 
Electricity forward price (per MWh)
 
$
8.20

 
$
37.15

 
$
28.36

Natural gas financial swaps
 

 
13

 
Discounted cash flow
 
Natural gas forward price (per Decatherm)
 
1.59

 
3.22

 
2.07

Electricity financial futures
 

 

 
Discounted cash flow
 
Electricity forward price (per MWh)
 
8.20

 
29.50

 
23.05

 
 
$

 
$
153

 
 
 
 
 
 
 
 
 
 
As of December 31, 2016:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electricity physical forwards
 
$

 
$
112

 
Discounted cash flow
 
Electricity forward price (per MWh)
 
$
14.25

 
$
54.73

 
$
38.18

Natural gas financial swaps
 
1

 
9

 
Discounted cash flow
 
Natural gas forward price (per Decatherm)
 
1.85

 
4.92

 
2.64

Electricity financial futures
 
1

 

 
Discounted cash flow
 
Electricity forward price (per MWh)
 
8.57

 
33.60

 
25.10

 
 
$
2

 
$
121

 
 
 
 
 
 
 
 
 
 


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, PGE 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 quarterly 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 PGE’s position as either the buyer or seller under the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Significant Unobservable Input
 
Position
 
Change to Input
 
Impact on Fair Value Measurement
Market price
 
Buy
 
Increase (decrease)
 
Gain (loss)
Market price
 
Sell
 
Increase (decrease)
 
Loss (gain)
 
 
 
 
 
 
 

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
September 30,
 
Nine Months Ended
September 30,
 
2017

2016
 
2017
 
2016
Balance as of the beginning of the period
153

 
158

 
$
119

 
$
119

Net realized and unrealized (gains)/losses*
(1
)
 

 
34

 
40

Transfers out of Level 3 to Level 2
1

 
2

 

 
1

Balance as of the end of the period
$
153

 
$
160

 
$
153

 
$
160

 

* Both realized and unrealized (gains)/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 and nine months ended September 30, 2017 and 2016, 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 a Level 3 fair value measurement 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 September 30, 2017, the carrying amount of PGE’s long-term debt was $2,377 million, net of $9 million of unamortized debt expense, and its estimated aggregate fair value was $2,763 million, consisting of $2,663 million and $100 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy.

As of December 31, 2016, the carrying amount of PGE’s long-term debt was $2,350 million, net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $2,693 million, consisting of $2,543 million and $150 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy.
Price Risk Management (Notes)
PRICE RISK MANAGEMENT
PRICE RISK MANAGEMENT

PGE participates in the wholesale marketplace in order to balance its supply of power, which consists of its own generation combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer its existing long-term wholesale contracts. Such activities include purchases and sales of both power and fuel resulting from economic dispatch decisions for Company-owned generation resources. As a result of this ongoing business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk, from which changes in prices and/or rates may affect the Company’s financial position, results of operations, or cash flows.

PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign currency rate risk in order to reduce volatility in NVPC for its retail customers. Such derivative instruments may include forward, futures, swaps, and option contracts, which are recorded at fair value on the condensed consolidated balance sheets, for electricity, natural gas, 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), the Company 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):
 
September 30, 2017
 
December 31,
2016
 
Current assets:
 
 
 
 
Commodity contracts:
 
 
 
 
Electricity
$
3

 
$
6

 
Natural gas
1

 
12

 
Total current derivative assets
4

(1) 
18

(1) 
Noncurrent assets:
 
 
 
 
Commodity contracts:
 
 
 
 
Electricity

 
1

 
Natural gas

 
4

 
Total noncurrent derivative assets

 
5

(2) 
Total derivative assets not designated as hedging instruments
$
4

 
$
23

 
Total derivative assets
$
4

 
$
23

 
Current liabilities:
 
 
 
 
Commodity contracts:
 
 
 
 
Electricity
$
11

 
$
12

 
Natural gas
32

 
32

 
Total current derivative liabilities
43

 
44

 
Noncurrent liabilities:
 
 
 
 
Commodity contracts:
 
 
 
 
Electricity
132

 
106

 
Natural gas
18

 
19

 
Total noncurrent derivative liabilities
150

 
125

 
Total derivative liabilities not designated as hedging instruments
$
193

 
$
169

 
Total derivative liabilities
$
193

 
$
169

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

PGE’s net purchase 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):
 
September 30, 2017
 
December 31, 2016
Commodity contracts:
 
 
 
 
 
Electricity
6

MWh
 
8

MWh
Natural gas
114

Decatherms
 
107

Decatherms
Foreign currency
$
21

Canadian
 
$
22

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 given 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 September 30, 2017, and December 31, 2016, gross amounts included as Price risk management liabilities subject to master netting agreements were $143 million and $115 million, respectively, for which PGE posted collateral of $11 million, which consisted entirely of letters of credit. As of September 30, 2017, of the gross amounts recognized, $140 million was for electricity and $3 million was for natural gas compared to $112 million for electricity and $3 million for natural gas recognized as of December 31, 2016.

Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the condensed consolidated statements of income and were as follows (in millions):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2017
 
2016
 
2017
 
2016
Commodity contracts:
 
 
 
 
 
 
 
Electricity
$
1

 
$
8

 
$
50

 
$
60

Natural Gas
7

 
10

 
48

 
(14
)
Foreign currency exchange

 

 
(1
)
 
(1
)

Net unrealized and certain net realized losses (gains) presented in the table above are offset within the condensed consolidated statements of income by the effects of regulatory accounting. None of the net losses recognized in Net income for the three month period ended September 30, 2017 was offset, while net losses of $20 million were offset for the three month period ended September 30, 2016. Net losses of $65 million and $36 million have been offset for the nine month periods ended September 30, 2017 and 2016, 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 September 30, 2017 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Total
Commodity contracts:
 
 
 
 
 
 
 
 
 
 
 
 
 
Electricity
$

 
$
9

 
$
8

 
$
8

 
$
8

 
$
107

 
$
140

Natural gas
14

 
22

 
9

 
4

 

 

 
49

Net unrealized loss
$
14

 
$
31

 
$
17

 
$
12

 
$
8

 
$
107

 
$
189



PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (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 September 30, 2017 was $191 million, for which PGE has posted $18 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at September 30, 2017, the cash requirement to either post as collateral or settle the instruments immediately would have been $190 million. 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:
 
September 30, 2017
December 31,
2016
Assets from price risk management activities:
 
 
 
Counterparty A
53
%
 
22
%
Counterparty B
3

 
17

Counterparty C
1

 
12

Counterparty D
15

 
%
Counterparty E
10

 
%
 
82
%
 
51
%
Liabilities from price risk management activities:
 
 
 
Counterparty F
72
%
 
66
%
 
72
%
 
66
%


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.
Earnings Per Share (Notes)
EARNINGS PER SHARE
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) employee stock purchase plan shares; and ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights. 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.

For the three and nine month periods ended September 30, 2017, unvested performance-based restricted stock units and related dividend equivalent rights in the total amount of 267 thousand were excluded from the dilutive calculation because the performance goals had not been met, with 306 thousand excluded for the three and nine month periods ended September 30, 2016.

Net income is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2017
 
2016
 
2017
 
2016
Weighted-average common shares outstanding—basic and diluted
89,065

 
88,921

 
89,044

 
88,885

Equity (Notes)
Equity
EQUITY

The activity in equity during the nine months ended September 30, 2017 and 2016 is as follows (dollars in millions):
 
Common Stock
 
Accumulated
Other
Comprehensive
Loss
 
Retained
Earnings
 
 
 
 
 
 
 
 
Shares
 
Amount
 
 
 
Total
Balances as of December 31, 2016
88,946,704

 
$
1,201

 
$
(7
)
 
$
1,150

 
$
2,344

Issuances of shares pursuant to equity-based plans
145,251

 
1

 

 

 
1

Stock-based compensation

 
2

 

 

 
2

Dividends declared

 

 

 
(90
)
 
(90
)
Net income

 

 

 
145

 
145

Balances as of September 30, 2017
89,091,955

 
$
1,204

 
$
(7
)
 
$
1,205

 
$
2,402

 
 
 
 
 
 
 
 
 
 
Balances as of December 31, 2015
88,792,751

 
$
1,196

 
$
(8
)
 
$
1,070

 
$
2,258

Issuances of shares pursuant to equity-based plans
133,875

 
1

 

 

 
1

Stock-based compensation

 
2

 

 

 
2

Dividends declared

 

 

 
(84
)
 
(84
)
Other comprehensive income
 
 

 
1

 

 
1

Net income

 

 

 
132

 
132

Balances as of September 30, 2016
88,926,626

 
$
1,199

 
$
(7
)
 
$
1,118

 
$
2,310

Contingencies (Notes)
CONTINGENCIES
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 condensed 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 determined, 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) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, will be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

Carty

In 2013, PGE entered into an agreement (Construction Agreement) with an engineering, procurement, and construction contractor - Abeinsa EPC LLC, Abener Construction Services, LLC, Teyma Construction USA, LLC, and Abeinsa Abener Teyma General Partnership, an affiliate of Abengoa S.A. (collectively, the “Contractor”) - for the construction of the Carty natural gas-fired generating plant (Carty) located in Eastern Oregon. Liberty Mutual Insurance Company and Zurich American Insurance Company (collectively, the “Sureties”) provided a performance bond of $145.6 million (Performance Bond) under the Construction Agreement.

In December 2015, the Company declared the Contractor in default under the Construction Agreement and terminated the Construction Agreement. Following termination of the Construction Agreement, PGE, in consultation with the Sureties, brought on new contractors and construction resumed.

Carty was placed into service on July 29, 2016 and the Company began collecting its revenue requirement in customer prices on August 1, 2016, as authorized by the OPUC, based on the approved cost of $514 million. Actual costs for the construction of Carty exceeded the approved amount and, as of September 30, 2017, PGE has capitalized $637 million to Electric utility plant.

As the final construction cost exceeded the amount authorized by the OPUC, higher interest and depreciation expense than allowed in the Company’s revenue requirement has resulted. These incremental expenses are recognized in the Company’s current results of operations, as a deferral for such amounts would not be considered probable of recovery at this time, in accordance with GAAP.

Actual costs do not reflect any offsetting amounts that may be received from the Sureties, pursuant to the Performance Bond. The amounts recorded also exclude $8 million of liens and claims filed for goods and services provided under contracts with the former Contractor that remain in dispute. The Company believes these liens are invalid and is contesting the claims in the courts.

The incremental costs resulted from various matters relating to the resumption of construction activities following the termination of the Construction Agreement, including, among other things, correcting latent defects in work performed by the former Contractor, determining the remaining scope of construction, preparing work plans for contractors, identifying new contractors, negotiating contracts, and procuring additional materials.

Other items contributing to the increase include costs relating to the removal of certain liens filed on the property for goods and services provided under contracts with the former Contractor, and costs to repair equipment damage that resulted from poor storage and maintenance on the part of the former Contractor.

The Company is involved in several litigation proceedings concerning the termination of the construction agreement and the payment obligations of the Sureties. PGE is seeking recovery of incremental construction costs and other damages pursuant to breach of contract claims against the contractor and claims against the Sureties pursuant to the performance bond. The Sureties have denied liability in whole under the Performance Bond.

Various actions relating to this matter have been filed in the U.S. District Court for the District of Oregon (U.S. District Court), in the Ninth Circuit Court of Appeals (Ninth Circuit), and in an arbitration proceeding before the International Chamber of Commerce International Court of Arbitration (ICC arbitration), involving the following:

A breach of contract claim brought by PGE against the Sureties in U.S. District Court asserting that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Contractor’s breach of contract;

A claim brought by PGE in U.S. District Court against the Contractor for failure to satisfy its obligations under the Construction Agreement;

A claim by Abengoa S.A. in the ICC arbitration proceeding alleging that the Company’s termination of the Construction Agreement was wrongful and in breach of the agreement terms and did not give rise to any liability of Abengoa S.A.; and

A claim by the Contractor against PGE in the ICC arbitration proceeding seeking damages of $117 million based on a claim that PGE wrongfully terminated the Construction Agreement and $44 million based on a claim that PGE failed to disclose certain information to the Contractor, in connection with the Contractor’s bid submitted pursuant to the Company’s request for proposals.

Following various procedural arguments in the ICC arbitration and the U.S. District Court, in July 2017, the Ninth Circuit held that the ICC arbitration had jurisdiction to determine what parties and what claims could be presented in the ICC arbitration. Oral argument before the ICC arbitration is expected to take place in the spring of 2018. The decision of the ICC arbitration is expected to determine the forum in which the above referenced claims will be heard. Further detail on the various proceedings is presented in Item1. Legal Proceedings in Part II - Other Information, of this Quarterly Report on Form 10-Q.

In July 2016, the Company requested from the OPUC a regulatory deferral for the recovery of the revenue requirement associated with the incremental capital costs for Carty starting from its in service date to the date that such amounts are approved in a subsequent regulatory proceeding. The Company has requested that the OPUC delay its review of this deferral request until all legal actions with respect to this matter, including PGE’s actions against the Sureties, have been resolved.

Any amounts approved by the OPUC for recovery under the deferral filing would be recognized in earnings in the period of such approval, however there is no assurance that such recovery would be granted by the OPUC. The Company believes that costs incurred to date and capitalized in Electric utility plant, net, in the condensed consolidated balance sheet, were prudently incurred. There have been no settlement discussions with regulators related to such costs.

After exhausting all remedies against the aforementioned parties, the Company intends to seek approval to recover any remaining excess amounts in customer prices in a subsequent regulatory 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, any such excess costs may be charged to expense at the time recovery becomes less than 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 is less than probable that a portion of the cost of Carty will be disallowed for recovery in customer prices. Accordingly, no loss has been recorded to date related to the project.

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 100.

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. The LWG has funded the RI and feasibility study (FS) and has stated that it had incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy.

The EPA has finalized the FS, along with the RI, and these documents provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued on January 6, 2017. The ROD outlines the EPA’s selected remediation alternative to clean-up for Portland Harbor which has an estimated total cost of $1.7 billion, comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance costs, for a combined discounted present value of $1.05 billion. As stated within the ROD, such cost ranges were estimated with accuracy between -30% and +50% of actual costs. Remediation construction costs are estimated to be incurred over a 13 year period, with long-term operation and maintenance costs estimated to be incurred over a 30 year period from the start of construction. The EPA acknowledges the estimated costs are based on data that is now outdated and that a period of pre-remedial design sampling is necessary to gather updated baseline data to better refine the remedial design and estimated cost. The EPA has prepared a Draft Sampling Plan to encourage PRPs to enter into an Administrative Order on Consent with the agency and begin the sampling process before the end of 2017.

PGE is participating in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, including a final allocation methodology and data with regard to property specific activities and history of ownership of sites within Portland Harbor. Based on the above facts and remaining uncertainties, PGE cannot reasonably estimate its potential liability or determine an allocation percentage that represents PGE’s portion of the liability to clean-up Portland Harbor.

Where damage to natural resources has 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 are 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. 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.

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 damaged resources and may also compensate the trustees for costs incurred in assessing the damages. The NRD trustees are in the process of negotiating NRDA liability with several PRPs, including PGE. PGE believes that the Company’s portion of NRDA liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows.

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, results of resampling efforts, and the method of allocation of costs amongst PRPs. It is probable that PGE will share in a portion of these costs. However, 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, although such costs could be material. The Company plans to seek recovery of any costs resulting from the Portland Harbor proceeding through claims under insurance policies and regulatory recovery in customer prices.

In July 2016, the Company filed a deferral application with the OPUC seeking the deferral of the future environmental remediation costs, as well as, seeking authorization to establish a regulatory cost recovery mechanism for such environmental costs. The Company reached an agreement with OPUC Staff and other parties regarding the details of the recovery mechanism, which the OPUC approved in the first quarter of 2017. The mechanism will allow the Company to defer and recover incurred environmental expenditures through a combination of third-party proceeds, such as insurance recoveries, and through customer prices, as necessary. The mechanism establishes annual prudency reviews of environmental expenditures and is subject to an annual earnings test.

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 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 Oregon Supreme Court (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. The OSC also ruled that the plaintiffs retained the right to return to the Circuit Court for disposition of whatever issues remained 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 2008, the OPUC issued an order that required PGE to provide refunds of $33 million, including interest, which refunds were completed in 2010. Following appeals, the order was upheld by the Oregon Court of Appeals in February 2013 and by the OSC in October 2014.

In June 2015, at PGE’s request, the Circuit Court lifted the abatement and in July 2015, the Circuit Court heard oral argument on the Company’s motion for Summary Judgment. In March 2016, the 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 Circuit Court dismissal to the Court of Appeals for the State of Oregon. Briefing on the appeal is now complete, with a Court of Appeals decision pending.

PGE believes that the October 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 a decision in the appeal, management believes that it is reasonably possible that such a loss in excess of amounts previously recorded 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.

Deschutes River Alliance Clean Water Act Claims

In August 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company in the U.S. District Court of the District of Oregon. DRA’s claims seek injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claims PGE has violated certain conditions contained in PGE’s Water Quality Certification for the Pelton/Round Butte Hydroelectric Project (Project) related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. DRA alleges the violations are related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project.

The SWW, located above Round Butte Dam, is, among other things, designed to blend water from the surface of the reservoir with water near the bottom of the reservoir and was constructed and placed into service in 2010, as part of the FERC license requirements for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA has alleged that PGE’s operation of the SWW has caused the above-referenced violations of the CWA, which in turn have degraded the Deschutes River’s fish and wildlife habitat below the Project and harmed the economic and personal interests of DRA’s members and supporters.

In September 2016, PGE filed a motion to dismiss, which asserted that the CWA does not allow citizen suits of this nature, and that FERC has jurisdiction over all licensing issues, including the alleged CWA violations. On March 27, 2017, the court denied PGE’s motion to dismiss. On April 6, 2017, PGE filed a motion with the District Court for certification to file an interlocutory appeal with the Ninth Circuit and for a stay of the District Court proceeding. On April 7, 2017, the court granted an unopposed motion filed by the Confederated Tribes of Warm Springs (the Tribes) to appear in the case as a friend of the court. The Tribes share ownership of the Project with PGE, but have not been named as a defendant. The District Court granted PGE’s request on May 19, 2017, but the Ninth Circuit denied the appeal on August 14, 2017. The parties are engaged in settlement discussions and filed a joint motion, which was granted September 11, 2017, to extend the stay of the District Court proceedings until either party finds the settlement negotiations unproductive.

The Company cannot predict the outcome of this matter, but believes that it has strong defenses to DRA’s claims and intends to defend against them. Because i) this matter involves novel issues of law and ii) the mechanism and costs for achieving the relief sought in DRA’s claims have not yet been determined, the Company cannot, at this time, determine the likelihood of whether the outcome of this matter will result in a material 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.
Guarantees (Notes)
GUARANTEES
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 September 30, 2017, 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.
Basis of Presentation (Policies)
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
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, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that inventory is recorded at the lower of average cost or net realizable value.
PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets.
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 a Level 3 fair value measurement 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.

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. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy; instead these assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

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.
Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan (NQ 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 measurement 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.

Equity securities—Equity mutual fund and common stock securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement 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. 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 invest 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 to be 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.
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.

PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign currency rate risk in order to reduce volatility in NVPC for its retail customers. Such derivative instruments may include forward, futures, swaps, and option contracts, which are recorded at fair value on the condensed consolidated balance sheets, for electricity, natural gas, 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), the Company 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 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 condensed 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 determined, 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) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, will be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.
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.
Balance Sheet Components (Tables)
Other current assets consist of the following (in millions):
 
September 30, 2017
 
December 31, 2016
Prepaid expenses
$
27

 
$
48

Assets from price risk management activities
4

 
18

Margin deposits
4

 
8

Other
8

 
3

Other current assets
$
43

 
$
77

Electric utility plant, net consists of the following (in millions):
 
September 30, 2017
 
December 31,
2016
Electric utility plant
$
9,766

 
$
9,534

Construction work-in-progress
386

 
213

Total cost
10,152

 
9,747

Less: accumulated depreciation and amortization
(3,514
)
 
(3,313
)
Electric utility plant, net
$
6,638

 
$
6,434


Regulatory assets and liabilities consist of the following (in millions):
 
September 30, 2017
 
December 31, 2016
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Regulatory assets:
 
 
 
 
 
 
 
Price risk management
$
39

 
$
150

 
$
26

 
$
120

Pension and other postretirement plans

 
225

 

 
235

Deferred income taxes

 
83

 

 
86

Debt issuance costs

 
20

 

 
22

Other
3

 
48

 
10

 
35

Total regulatory assets
$
42

 
$
526

 
$
36

 
$
498

Regulatory liabilities:
 
 
 
 
 
 
 
Asset retirement removal costs
$

 
$
921

 
$

 
$
887

Trojan decommissioning activities
4

 

 
18

 

Asset retirement obligations

 
52

 

 
49

Other
16

 
29

 
33

 
22

Total regulatory liabilities
$
20

* 
$
1,002

 
$
51

* 
$
958



* Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.
Accrued expenses and other current liabilities consist of the following (in millions):
 
September 30, 2017
 
December 31, 2016
Accrued employee compensation and benefits
$
51

 
$
52

Accrued taxes payable
46

 
25

Accrued interest payable
40

 
25

Accrued dividends payable
31

 
30

Regulatory liabilities—current
20

 
51

Other
60

 
71

Total accrued expenses and other current liabilities
$
248

 
$
254

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2017
 
2016
 
2017
 
2016
Service cost
$
4

 
$
4

 
$
12

 
$
12

Interest cost
8

 
9

 
25

 
25

Expected return on plan assets
(10
)
 
(10
)
 
(30
)
 
(30
)
Amortization of net actuarial loss
3

 
3

 
9

 
11

Net periodic benefit cost
$
5

 
$
6

 
$
16

 
$
18

Fair Value of Financial Instruments (Tables)
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 September 30, 2017
 
Level 1
 
Level 2
 
Level 3
 
Other(2)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trust: (1)
 
 
 
 
 
 
 
 
 
Debt securities:
 
 
 
 
 
 
 
 
 
Domestic government
$
3

 
$
8

 
$

 
$

 
$
11

Corporate credit

 
7

 

 

 
7

Money market funds measured at NAV (2)

 

 

 
23

 
23

Non-qualified benefit plan trust: (3)
 
 
 
 
 
 
 
 
 
Money market funds
2

 

 

 

 
2

Equity securities—domestic
6

 

 

 

 
6

Debt securities—domestic government
1

 

 

 

 
1

Collective trust—domestic equity measured at NAV (2)

 

 

 

 

Assets from price risk management activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity

 
3

 

 

 
3

Natural gas

 
1

 

 

 
1

 
$
12

 
$
19

 
$

 
$
23

 
$
54

Liabilities from price risk management
activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity
$

 
$
3

 
$
140

 
$

 
$
143

Natural gas

 
37

 
13

 

 
50

 
$

 
$
40

 
$
153

 
$

 
$
193

 
(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 $28 million, which are recorded at cash surrender value.
(4)
For further information, see Note 4, Price Risk Management.

 
As of December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Other (2)
 
Total
Assets:
 
 
 
 
 
 
 
 
 
Nuclear decommissioning trust: (1)
 
 
 
 
 
 
 
 
 
Debt securities:
 
 
 
 
 
 
 
 
 
Domestic government
$
2

 
$
10

 
$

 
$

 
$
12

Corporate credit

 
8

 

 

 
8

Money market funds measured at NAV (2)

 

 

 
21

 
21

Non-qualified benefit plan trust: (3)
 
 
 
 
 
 
 
 
 
Money market funds
1

 

 

 

 
1

Equity securities—domestic
4

 

 

 

 
4

Debt securities—domestic government
1

 

 

 

 
1

Collective trust—domestic equity measured at NAV (2)

 

 

 
2

 
2

Assets from price risk management activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity

 
6

 
1

 

 
7

Natural gas

 
15

 
1

 

 
16

 
$
8

 
$
39

 
$
2

 
$
23

 
$
72

Liabilities from price risk management
activities: (1) (4)
 
 
 
 
 
 
 
 
 
Electricity
$

 
$
6