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 September 30, 2016

OR

[  ]       TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to____________

Commission file number 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

Oregon	93-0256722
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

220 N.W. Second Avenue, Portland, Oregon 97209

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code:  (503) 226-4211

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  

Yes [ X ]     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).   

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 [    ]

(Do not check if a 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 [   ]     No  [ X ]

At October 21, 2016, 27,557,756 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

NORTHWEST NATURAL GAS COMPANY

For the Quarterly Period Ended September 30, 2016

TABLE OF CONTENTS

		Page
PART 1.	FINANCIAL INFORMATION
	Forward-Looking Statements	3
Item 1.	Unaudited Consolidated Financial Statements:
	Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2016 and 2015	4
	Consolidated Balance Sheets at September 30, 2016 and 2015 and December 31, 2015	5
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015	7
	Notes to Unaudited Consolidated Financial Statements	8
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	45
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	46
Item 1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 6.	Exhibits	46
	Signature	47

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as anticipates, assumes, intends, plans, seeks, believes, estimates, expects, and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements regarding the following:

• plans, projections, forecasts and predictions;

• objectives, goals and strategies;

• assumptions and estimates;

• future events or performance;

• trends, uncertainties, timing and cyclicality;

• risks;

• earnings and dividends;

• capital and other expenditures and allocation;

• capital structure;

• growth and profitability;

• customer rates;

• commodity costs and volumes;

• gas reserves, volumes, investment and recovery;

• operational and maintenance performance and costs;

• energy policy and preferences;

• efficacy of and exposure under derivatives and hedges;

• liquidity, funding sources, and financial positions;

• project and program development, expansion, or investment;

• competition;

• costs of compliance;

• credit exposures;

• regulatory outcomes, prudency or recovery;

• impacts of laws, rules and regulations;

• tax positions, liabilities or refunds;

• levels and pricing of gas storage contracts and gas storage markets;

• outcomes and effects of potential claims, litigation, regulatory actions, and other administrative matters;

• projected obligations and contributions under retirement plans;

• availability, adequacy, and shift in mix, of gas supplies;

• effects of new or anticipated changes in accounting standards or pronouncements;

• approval and adequacy of regulatory deferrals;

• effects and efficacy of regulatory mechanisms;

• local or national disasters, pandemic illness, terrorist activities, including cyber-attacks, explosions, or other extreme events; and

• environmental, regulatory, litigation and insurance costs, allocations and recoveries, and timing thereof.

Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are neither statements of historical fact nor guarantees or assurances of future operational or financial performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements are discussed in our 2015 Annual Report on Form 10-K, Part I, Item 1A “Risk Factors” and Part II, Item 7 and Item 7A, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk,” and in Part I, Items 2 and 3, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk,” and Part II, Item 1A, “Risk Factors,” herein.

Any forward-looking statement made by us in this report speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement, whether as a result of new information, future developments or otherwise, except as may be required by law.

3

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per share data	2016			2015			2016			2015
Operating revenues	$	87,727		$	93,128		$	442,439		$	493,073
Operating expenses:
Cost of gas	28,264			35,856			157,546			223,737
Operations and maintenance	34,870			32,031			109,771			121,458
Environmental remediation	1,191			—			8,113			—
General taxes	7,211			6,772			23,333			23,153
Depreciation and amortization	20,628			20,342			61,435			60,683
Total operating expenses	92,164			95,001			360,198			429,031
Income (loss) from operations	(4,437		)	(1,873		)	82,241			64,042
Other income (expense), net	652			746			(1,144		)	6,930
Interest expense, net	9,729			10,111			29,183			31,030
Income (loss) before income taxes	(13,514		)	(11,238		)	51,914			39,942
Income tax expense (benefit)	(5,474		)	(4,553		)	21,294			15,944
Net income (loss)	(8,040		)	(6,685		)	30,620			23,998
Other comprehensive income (loss):
Change in employee benefit plan liability, net of taxes of $709 for the three and nine months ended September 30, 2016	(1,086		)	—			(1,086		)	—
Amortization of non-qualified employee benefit plan liability, net of taxes of $223 and $217 for the three months ended and $477 and $650 for the nine months ended September 30, 2016 and 2015, respectively	341			332			678			995
Comprehensive income (loss)	$	(8,785	)	$	(6,353	)	$	30,212		$	24,993
Average common shares outstanding:
Basic	27,554			27,363			27,504			27,336
Diluted	27,554			27,363			27,629			27,399
Earnings (loss) per share of common stock:
Basic	$	(0.29	)	$	(0.24	)	$	1.11		$	0.88
Diluted	(0.29		)	(0.24		)	1.11			0.88
Dividends declared per share of common stock	0.470			0.465			1.403			1.395

See Notes to Unaudited Consolidated Financial Statements

4

NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)
	September 30,			September 30,			December 31,
In thousands	2016			2015			2015
Assets:
Current assets:
Cash and cash equivalents	$	6,230		$	5,227		$	4,211
Accounts receivable	25,506			29,800			68,228
Accrued unbilled revenue	15,537			15,752			57,987
Allowance for uncollectible accounts	(289		)	(308		)	(870		)
Regulatory assets	55,280			82,712			69,178
Derivative instruments	4,857			2,956			2,719
Inventories	67,470			80,974			70,868
Gas reserves	16,257			17,822			17,094
Income taxes receivable	2,257			—			7,900
Deferred tax assets	—			15,663			—
Other current assets	17,480			25,972			33,460
Total current assets	210,585			276,570			330,775
Non-current assets:
Property, plant, and equipment	3,177,196			3,072,998			3,089,380
Less: Accumulated depreciation	943,334			905,137			906,717
Total property, plant, and equipment, net	2,233,862			2,167,861			2,182,663
Gas reserves	103,976			117,784			114,552
Regulatory assets	341,188			333,953			370,711
Derivative instruments	1,151			299			27
Other investments	67,853			68,503			68,066
Restricted cash	—			4,500			—
Other non-current assets	1,269			1,248			2,616
Total non-current assets	2,749,299			2,694,148			2,738,635
Total assets	$	2,959,884		$	2,970,718		$	3,069,410

See Notes to Unaudited Consolidated Financial Statements

5

NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)
	September 30,			September 30,			December 31,
In thousands	2016			2015			2015
Liabilities and equity:
Current liabilities:
Short-term debt	$	194,900		$	225,200		$	270,035
Current maturities of long-term debt	64,994			—			24,973
Accounts payable	55,933			54,425			73,219
Taxes accrued	11,954			11,854			10,420
Interest accrued	9,671			9,800			5,873
Regulatory liabilities	27,921			34,127			29,927
Derivative instruments	5,334			21,949			22,092
Other current liabilities	31,997			27,924			41,148
Total current liabilities	402,704			385,279			477,687
Long-term debt	530,219			614,053			569,445
Deferred credits and other non-current liabilities:
Deferred tax liabilities	544,575			527,336			530,021
Regulatory liabilities	342,143			334,490			339,287
Pension and other postretirement benefit liabilities	216,909			228,861			223,105
Derivative instruments	1,682			3,540			3,447
Other non-current liabilities	142,450			117,950			145,446
Total deferred credits and other non-current liabilities	1,247,759			1,212,177			1,241,306
Commitments and contingencies (See Note 13)	—			—			—
Equity:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 27,558, 27,367, and 27,427 at September 30, 2016 and 2015 and December 31, 2015, respectively	389,834			380,208			383,144
Retained earnings	396,938			388,082			404,990
Accumulated other comprehensive loss	(7,570		)	(9,081		)	(7,162		)
Total equity	779,202			759,209			780,972
Total liabilities and equity	$	2,959,884		$	2,970,718		$	3,069,410

See Notes to Unaudited Consolidated Financial Statements

6

NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
	Nine Months Ended
	September 30,
In thousands	2016			2015
Operating activities:
Net income	$	30,620		$	23,998
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	61,435			60,683
Regulatory amortization of gas reserves	11,403			13,606
Deferred tax liabilities, net	17,810			7,153
Qualified defined benefit pension plan expense	3,989			4,238
Contributions to qualified defined benefit pension plans	(11,250		)	(11,780		)
Deferred environmental expenditures	(8,302		)	(8,063		)
Regulatory disallowance of prior environmental cost deferrals	3,287			15,000
Interest income on deferred environmental expenses	—			(5,322		)
Amortization of environmental remediation	8,113			—
Other	4,817			669
Changes in assets and liabilities:
Receivables, net	83,377			82,586
Inventories	3,226			(3,142		)
Taxes accrued	7,170			2,823
Accounts payable	(17,612		)	(36,230		)
Interest accrued	3,798			3,721
Deferred gas costs	(10,470		)	27,042
Other, net	14,988			(4,237		)
Cash provided by operating activities	206,399			172,745
Investing activities:
Capital expenditures	(98,111		)	(86,923		)
Restricted cash	—			(1,500		)
Other	2,868			181
Cash used in investing activities	(95,243		)	(88,242		)
Financing activities:
Common stock issued, net	4,832			1,252
Long-term debt retired	—			(40,000		)
Change in short-term debt	(75,135		)	(9,500		)
Cash dividend payments on common stock	(38,556		)	(38,122		)
Other	(278		)	(2,440		)
Cash used in financing activities	(109,137		)	(88,810		)
Increase (decrease) in cash and cash equivalents	2,019			(4,307		)
Cash and cash equivalents, beginning of period	4,211			9,534
Cash and cash equivalents, end of period	$	6,230		$	5,227
Supplemental disclosure of cash flow information:
Interest paid, net of capitalization	$	23,271		$	25,264
Income taxes paid (refunded), net	(6,900		)	10,631

See Notes to Unaudited Consolidated Financial Statements

7

NORTHWEST NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ORGANIZATION AND PRINCIPLES OF CONSOLIDATION

The accompanying consolidated financial statements represent the consolidated results of Northwest Natural Gas Company (NW Natural or the Company) and all companies we directly or indirectly control, either through majority ownership or otherwise. We have two core businesses: our regulated local gas distribution business, referred to as the utility segment, which serves residential, commercial, and industrial customers in Oregon and southwest Washington; and our gas storage businesses, referred to as the gas storage segment, which provides storage services for utilities, gas marketers, electric generators, and large industrial users from facilities located in Oregon and California. In addition, we have investments and other non-utility activities we aggregate and report as other.

Our core utility business assets and operating activities are largely included in the parent company, NW Natural. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch), NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), and NW Natural Gas Reserves, LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method, which includes NWN Energy’s investment in Trail West Holdings, LLC (TWH) and NNG Financial's investment in Kelso-Beaver (KB) Pipeline. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated financial statements are presented after elimination of all intercompany balances and transactions, except for amounts required to be included under regulatory accounting standards to reflect the effect of such regulation. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage businesses and other non-utility investments and business activities.

Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments management considers necessary for fair presentation of the results for each period reported including normal recurring accruals. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2015 Annual Report on Form 10-K (2015 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of full year results.

Certain prior year balances in our consolidated financial statements and notes have been reclassified to conform with the current period presentation. These reclassifications had no effect on our prior year’s consolidated results of operations, financial condition, or cash flows.

8

2. SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are described in Note 2 of the 2015 Form 10-K. There were no material changes to those accounting policies during the nine months ended September 30, 2016. The following are current updates to certain critical accounting policy estimates and new accounting standards.

Industry Regulation

In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the Public Utility Commission of Oregon (OPUC) or Washington Utilities and Transportation Commission (WUTC), which provide for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a rate of return or a carrying charge in certain cases.

Amounts deferred as regulatory assets and liabilities were as follows:

	Regulatory Assets
	September 30,				December 31,
In thousands	2016		2015		2015
Current:
Unrealized loss on derivatives(1)	$	5,205	$	21,949	$	22,092
Gas costs	10,164		19,274		8,717
Environmental costs(2)	9,734		12,364		9,270
Decoupling(3)	16,028		19,391		18,775
Other(4)	14,149		9,734		10,324
Total current	$	55,280	$	82,712	$	69,178
Non-current:
Unrealized loss on derivatives(1)	$	1,682	$	3,540	$	3,447
Pension balancing(5)	48,637		41,193		43,748
Income taxes	40,106		44,767		43,049
Pension and other postretirement benefit liabilities	174,282		189,111		184,223
Environmental costs(2)	64,279		37,443		76,584
Gas costs	712		2,098		1,949
Decoupling(3)	1,006		4,331		6,349
Other(4)	10,484		11,470		11,362
Total non-current	$	341,188	$	333,953	$	370,711

	Regulatory Liabilities
	September 30,				December 31,
In thousands	2016		2015		2015
Current:
Gas costs	$	12,001	$	22,499	$	14,157
Unrealized gain on derivatives(1)	4,857		2,939		2,659
Other(4)	11,063		8,689		13,111
Total current	$	27,921	$	34,127	$	29,927
Non-current:
Gas costs	$	765	$	6,357	$	8,869
Unrealized gain on derivatives(1)	1,151		299		27
Accrued asset removal costs(6)	336,699		324,467		327,047
Other(4)	3,528		3,367		3,344
Total non-current	$	342,143	$	334,490	$	339,287

⁽¹⁾  Unrealized gains or losses on derivatives are non-cash items and, therefore, do not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the annual Purchased Gas Adjustment (PGA) mechanism when realized at settlement.

9

⁽²⁾  Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, recovery of deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from Oregon customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test. See Note 13.     

⁽³⁾  This deferral represents the margin adjustment resulting from differences between actual and expected volumes. 

⁽⁴⁾  These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge.

⁽⁵⁾  The deferral of certain pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower net periodic benefit costs in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of interest income recognized when amounts are collected in rates.

⁽⁶⁾  Estimated costs of removal on certain regulated properties are collected through rates.

We believe all costs incurred and deferred at September 30, 2016 are prudent. We annually review all regulatory assets and liabilities for recoverability and more often if circumstances warrant. If we should determine that all or a portion of these regulatory assets or liabilities no longer meet the criteria for continued application of regulatory accounting, then we would be required to write-off the net unrecoverable balances in the period such determination is made.

New Accounting Standards

We consider the applicability and impact of all accounting standards updates (ASUs) issued by the Financial

Accounting Standards Board (FASB). Accounting standards updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial position or results of operations.

Recently Adopted Accounting Pronouncements

BENEFIT PLAN ACCOUNTING. On July 31, 2015, the FASB issued ASU 2015-12, "Plan Accounting: Defined Benefit Pension Plans, Defined Contribution Pension Plans, and Health and Welfare Benefit Plans." The ASU outlines a three part update. Only part two of the update is applicable for us, which simplifies the investment disclosure requirements for employee benefit plans by allowing certain disclosures at an aggregated level, reducing the number of ways assets must be grouped and analyzed, and no longer requiring investment strategy disclosures for certain investments. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively in the 2016 Form 10-K, for all periods presented. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosures within our pension and other postretirement benefit plan footnote in our 2016 Form 10-K, for all periods presented.

FAIR VALUE MEASUREMENT. On May 1, 2015, the FASB issued ASU 2015-07, "Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent)." The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosures of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.

INTANGIBLES - GOODWILL AND OTHER INTERNAL-USE SOFTWARE. On April 15, 2015 the FASB issued ASU 2015-05, "Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement." The ASU provides customers guidance on how to determine whether a cloud computing arrangement includes a software license. The new requirements were effective for us beginning January 1, 2016. We will apply the guidance prospectively as contracts arise and do not expect the ASU to materially affect our financial statements and disclosures.

DEBT ISSUANCE COSTS. On April 7, 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," which requires the presentation of debt issuance costs in the balance sheet as a direct deduction from the associated debt liability. The new requirements were effective for us beginning January 1, 2016. The new guidance has been applied on a retrospective basis and is reflected in our consolidated balance sheets and Note 6.

10

Recently Issued Accounting Pronouncements

STATEMENT OF CASH FLOWS. On August 26, 2016, the FASB issued ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments." The ASU adds guidance pertaining to the classification of certain cash receipts and payments on the statement of cash flows. The purpose of the amendment is to clarify issues that have been creating diversity in practice, including the classification of proceeds from the settlement of insurance claims and proceeds from the settlement of corporate-owned life insurance policies. The amendments in this standard are effective for us beginning January 1, 2018. Early adoption is permitted in any interim or annual period. We are currently assessing the effect of this standard and do not expect this standard to materially affect our financial statements and disclosures.

STOCK BASED COMPENSATION. On March 30, 2016, the FASB issued ASU 2016-09, "Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting." The ASU changes how companies account for certain aspects of share-based payment awards to employees, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The amendments in this standard are effective for us beginning January 1, 2017. Early adoption is permitted in any interim or annual period. We do not expect this standard to materially affect our financial statements and disclosures.

LEASES. On February 25, 2016, the FASB issued ASU 2016-02, "Leases," which revises the existing lease accounting guidance. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases that are greater than 12 months at lease commencement, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Lessor accounting will remain substantially the same under the new standard. Quantitative and qualitative disclosures are also required for users of the financial statements to have a clear understanding of the nature of our leasing activities. The standard is effective for us beginning January 1, 2019, and early adoption is permitted. The new standard must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently assessing the effect of this standard on our financial statements and disclosures.

FINANCIAL INSTRUMENTS. On January 5, 2016, the FASB issued ASU 2016-01, "Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities." The ASU enhances the reporting model for financial instruments, which includes amendments to address aspects of recognition, measurement, presentation, and disclosure. The new standard is effective for us beginning January 1, 2018. Upon adoption, we will be required to make a cumulative-effect adjustment to the consolidated balance sheet in the first quarter of 2018. Early adoption is permitted, and we are currently assessing the effect of this standard on our financial statements and disclosures.

REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts the entity is expected to be entitled to in exchange for those goods or services. The ASU also prescribes a five-step approach to revenue recognition: (1) identify the contract(s) with the customer; (2) identify the separate performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to separate performance obligations; and (5) recognize revenue when, or as, each performance obligation is satisfied. The new requirements prescribe either a full retrospective or simplified transition adoption method. On August 12, 2015, the FASB deferred the effective date by one year to January 1, 2018 for annual reporting periods beginning after December 15, 2017. The FASB also permitted early adoption of the standard, but not before the original effective date of January 1, 2017. We plan to adopt the new standard effective January 1, 2018 and are assessing the effect this standard will have on our financial statements and disclosures.

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3. EARNINGS PER SHARE

Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for each period presented. Diluted earnings per share are computed in the same manner, except it uses the weighted average number of common shares outstanding plus the effects of the assumed exercise of stock options and the payment of estimated stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Antidilutive stock awards are excluded from the calculation of diluted earnings per share. Diluted earnings (loss) per share are calculated as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
In thousands, except per share data	2016			2015			2016		2015
Net income (loss)	$	(8,040	)	$	(6,685	)	$	30,620	$	23,998
Average common shares outstanding - basic	27,554			27,363			27,504		27,336
Additional shares for stock-based compensation plans (See Note 5)	—			—			125		63
Average common shares outstanding - diluted	27,554			27,363			27,629		27,399
Earnings (loss) per share of common stock - basic	$	(0.29	)	$	(0.24	)	$	1.11	$	0.88
Earnings (loss) per share of common stock - diluted	$	(0.29	)	$	(0.24	)	$	1.11	$	0.88
Additional information:
Antidilutive shares	159			91			5		19

4. SEGMENT INFORMATION

We primarily operate in two reportable business segments: local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which are aggregated and reported as other. We refer to our local gas distribution business as the utility, and our gas storage segment and other as non-utility. Our utility segment also includes the utility portion of our Mist underground storage facility in Oregon and NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp. Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist, and all third-party asset management services. Other includes NNG Financial and NWN Energy's equity investment in TWH, which is pursuing development of a cross-Cascades transmission pipeline project. See Note 4 in the 2015 Form 10-K for further discussion of our segments.

Inter-segment transactions were insignificant for the periods presented. The following table presents summary financial information concerning the reportable segments:

	Three Months Ended September 30,
In thousands	Utility			Gas Storage		Other			Total
2016
Operating revenues	$	80,378		$	7,293	$	56		$	87,727
Depreciation and amortization	19,173			1,455		—			20,628
Income (loss) from operations	(7,264		)	3,502		(675		)	(4,437		)
Net income (loss)	(9,511		)	1,813		(342		)	(8,040		)
Capital expenditures	36,238			437		—			36,675
2015
Operating revenues	$	87,475		$	5,596	$	57		$	93,128
Depreciation and amortization	18,721			1,621		—			20,342
Income (loss) from operations	(4,088		)	2,204		11			(1,873		)
Net income (loss)	(7,529		)	799		45			(6,685		)
Capital expenditures	28,325			526		—			28,851

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	Nine Months Ended September 30,
In thousands	Utility		Gas Storage		Other			Total
2016
Operating revenues	$	422,617	$	19,654	$	168		$	442,439
Depreciation and amortization	56,894		4,541		—			61,435
Income (loss) from operations	74,745		8,107		(611		)	82,241
Net income (loss)	26,848		3,988		(216		)	30,620
Capital expenditures	96,710		1,401		—			98,111
Total assets at September 30, 2016	2,684,618		259,483		15,783			2,959,884
2015
Operating revenues	476,672		16,232		169			493,073
Depreciation and amortization	55,798		4,885		—			60,683
Income from operations	59,955		3,998		89			64,042
Net income	23,051		827		120			23,998
Capital expenditures	84,598		2,325		—			86,923
Total assets at September 30, 2015	2,686,367		269,228		15,123			2,970,718
Total assets at December 31, 2015	2,792,736		261,750		14,924			3,069,410

Utility Margin

Utility margin is a financial measure consisting of utility operating revenues, which are reduced by revenue taxes, the associated cost of gas, and environmental recovery revenues. The cost of gas purchased for utility customers is generally a pass-through cost in the amount of revenues billed to regulated utility customers. Environmental recovery revenues represent collections received from customers through our environmental recovery mechanism in Oregon. These collections are offset by the amortization of environmental liabilities, which is presented as environmental remediation expense in our operating expenses. By subtracting cost of gas and environmental remediation expense from utility operating revenues, utility margin provides a key metric used by our chief operating decision maker in assessing the performance of the utility segment. The gas storage and other segments emphasize growth in operating revenues as opposed to margin because they do not incur a product cost (i.e. cost of gas sold) like the utility and, therefore, use operating revenues and net income to assess performance.

The following table presents additional segment information concerning utility margin:

	Three Months Ended September 30,				Nine Months Ended September 30,
In thousands	2016		2015		2016		2015
Utility margin calculation:
Utility operating revenues(1)	$	80,378	$	87,475	$	422,617	$	476,672
Less: Utility cost of gas	28,264		35,856		157,546		223,737
Environmental remediation expense	1,191		—		8,113		—
Utility margin	$	50,923	$	51,619	$	256,958	$	252,935

⁽¹⁾   Utility operating revenues include environmental recovery revenues, which are collections received from customers through our environmental recovery mechanism in Oregon, offset by environmental remediation expense. Collections under this mechanism began in November 2015.

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5. STOCK-BASED COMPENSATION

Our stock-based compensation plans are designed to promote stock ownership in NW Natural by employees and officers. These compensation plans include a Long-Term Incentive Plan (LTIP), an Employee Stock Purchase Plan (ESPP), and a Restated Stock Option Plan. For additional information on our stock-based compensation plans, see Note 6 in the 2015 Form 10-K and the updates provided below.

Long-Term Incentive Plan

Performance Shares

LTIP performance shares incorporate a combination of market, performance, and service-based factors. During the nine months ended September 30, 2016, 36,259 performance-based shares were granted under the LTIP based on target-level awards with a weighted-average grant date fair value of $50.13 per share. As of September 30, 2016, there was $2.7 million of unrecognized compensation cost from LTIP grants, which is expected to be recognized through 2018. Fair value for the market based portion of the LTIP was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:

Stock price on valuation date	$	50.15
Performance term (in years)	3.0
Quarterly dividends paid per share	$	0.4675
Expected dividend yield	3.7		%
Dividend discount factor	0.9010

Restricted Stock Units (RSUs)

During the nine months ended September 30, 2016, 36,591 RSUs were granted under the LTIP with a weighted-average grant date fair value of $54.21 per share. The fair value of a RSU is equal to the closing market price of our common stock on the grant date. As of September 30, 2016, there was $3.3 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through 2021. Generally, the RSUs awarded are forfeitable and include a performance-based threshold as well as a vesting period of four years from the grant date. A RSU obligates us, upon vesting, to issue the RSU holder one share of common stock plus a cash payment equal to the total amount of dividends paid per share between the grant date and vesting date of that portion of the RSU. 

6. DEBT

Short-Term Debt

At September 30, 2016, our short-term debt consisted of commercial paper notes payable with a maximum maturity of 55 days and an average maturity of 28 days and an outstanding balance of $194.9 million. The carrying cost of our commercial paper approximates fair value using Level 2 inputs, due to the short-term nature of the notes. See Note 2 in the 2015 Form 10-K for a description of the fair value hierarchy.

Long-Term Debt

At September 30, 2016, we had long-term debt of $595.2 million, which included $6.5 million of unamortized debt issuance costs. Utility long-term debt consists of first mortgage bonds (FMBs) with maturity dates ranging from2016 through 2042, interest rates ranging from 3.176% to 9.05%, and a weighted-average coupon rate of 5.70%.

Fair Value of Long-Term Debt

Our outstanding debt does not trade in active markets. We estimate the fair value of our debt using inputs from utility companies with similar credit ratings, whose debt trades actively in public markets and has terms and remaining maturities comparable to our own debt.These valuations are based on Level 2 inputs as defined in the fair value hierarchy. See Note 2 in the 2015 Form 10-K for a description of the fair value hierarchy.

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The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date:

	September 30,						December 31,
In thousands	2016			2015			2015
Gross long-term debt	$	601,700		$	621,700		$	601,700
Unamortized debt issuance costs	(6,487		)	(7,647		)	(7,282		)
Carrying amount	$	595,213		$	614,053		$	594,418
Estimated fair value(1)	701,183			697,647			667,168

⁽¹⁾  Estimated fair value does not include unamortized debt issuance costs.

7. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

The following table provides the components of net periodic benefit cost for our pension and other postretirement benefit plans:

	Three Months Ended September 30,												Nine Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
In thousands	2016			2015			2016			2015			2016			2015			2016			2015
Service cost	$	1,978		$	2,308		$	119		$	145		$	5,866		$	6,926		$	361		$	435
Interest cost	4,607			4,597			301			291			13,755			13,787			901			874
Expected return on plan assets	(5,017		)	(5,174		)	—			—			(15,051		)	(15,522		)	—			—
Amortization of net actuarial loss	3,555			4,561			192			125			10,559			13,683			575			376
Amortization of prior service costs	57			57			(117		)	50			173			173			(351		)	148
Settlement expense(1)	193			—			—			—			193			—			—			—
Net periodic benefit cost	5,373			6,349			495			611			15,495			19,047			1,486			1,833
Amount allocated to construction	(1,556		)	(2,061		)	(163		)	(218		)	(4,678		)	(5,765		)	(491		)	(607		)
Amount deferred to regulatory balancing account(2)	(1,542		)	(2,171		)	—			—			(4,762		)	(6,511		)	—			—
Net amount charged to expense	$	2,275		$	2,117		$	332		$	393		$	6,055		$	6,771		$	995		$	1,226

⁽¹⁾ During the three months ended September 30, 2016, a participant within the Company's Supplemental Executive Retirement Plan elected to have their benefit paid out in a one-time lump-sum cash payment. Accordingly, this transaction qualified for settlement accounting and a pro rata portion of the associated loss in Accumulated Other Comprehensive Loss was immediately recognized in earnings.

⁽²⁾ The deferral of defined benefit pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account. The balancing account includes the expectation of higher net periodic benefit costs than costs recovered in rates in the near-term with lower net periodic benefit costs than costs recovered in rates expected in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of the interest recognized when amounts are collected in rates. See Note 2 in the 2015 Form 10-K.

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The following table presents amounts recognized in Accumulated Other Comprehensive Loss (AOCL) and the changes in AOCL related to our non-qualified employee benefit plans:

	Three Months Ended September 30,						Nine Months Ended September 30,
In thousands	2016			2015			2016			2015
Beginning balance	$	(6,825	)	$	(9,413	)	$	(7,162	)	$	(10,076	)
Amounts reclassified to AOCL	(1,795		)	—			(1,795		)	—
Amounts reclassified from AOCL:
Amortization of actuarial losses	371			549			962			1,645
Loss from plan settlement	193			—			193			—
Total reclassifications before tax	(1,231		)	549			(640		)	1,645
Tax (benefit) expense	486			(217		)	232			(650		)
Total reclassifications for the period	(745		)	332			(408		)	995
Ending balance	$	(7,570	)	$	(9,081	)	$	(7,570	)	$	(9,081	)

Employer Contributions to Company-Sponsored Defined Benefit Pension Plans

For the nine months ended September 30, 2016, we made cash contributions totaling $11.3 million to our qualified defined benefit pension plan. We expect further plan contributions of $3.2 million during the remainder of 2016.

Defined Contribution Plan

The Retirement K Savings Plan is a qualified defined contribution plan under Internal Revenue Code Section 401(k). Employer contributions totaled $3.6 million and $2.9 million for the nine months ended September 30, 2016 and 2015, respectively.

See Note 8 in the 2015 Form 10-K for more information concerning these retirement and other postretirement benefit plans.

8. INCOME TAX

An estimate of annual income tax expense is made each interim period using estimates for annual pre-tax income, regulatory flow-through adjustments, tax credits, and other items. The estimated annual effective tax rate is applied to year-to-date, pre-tax income to determine income tax expense for the interim period consistent with the annual estimate.

The effective income tax rate varied from the combined federal and state statutory tax rates due to the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
Dollars in thousands	2016			2015			2016			2015
Income taxes at statutory rates (federal and state)	$	(5,339	)	$	(4,473	)	$	20,620		$	15,848
Increase (decrease):
Differences required to be flowed-through by regulatory commissions	(381		)	(378		)	1,202			1,036
Other, net	246			298			(528		)	(940		)
Total provision (benefit) for income taxes	$	(5,474	)	$	(4,553	)	$	21,294		$	15,944
Effective tax rate	40.5		%	40.5		%	41.0		%	39.9		%

The effective tax rate for the three months ended September 30, 2016 and 2015 remained flat. For the nine months endedSeptember 30, 2016, compared to 2015, the effective tax rate increased primarily as a result of lower estimated depletion deductions from gas reserves activity in 2016. The effective tax rate for the nine months endedSeptember 30, 2015 benefited from the realization of deferred depletion benefits from 2013 and 2014. See Note 9 in the 2015 Form 10-K for more detail on income taxes and effective tax rates.

The 2015 tax year is subject to examination under the Internal Revenue Service (IRS) Compliance Assurance Process (CAP). Our 2016 tax year CAP application has been accepted by the IRS.

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9. PROPERTY, PLANT, AND EQUIPMENT

The following table sets forth the major classifications of our property, plant, and equipment and accumulated depreciation:

	September 30,				December 31,
In thousands	2016		2015		2015
Utility plant in service	$	2,815,340	$	2,710,658	$	2,745,485
Utility construction work in progress	58,470		58,280		39,288
Less: Accumulated depreciation	899,851		867,281		867,377
Utility plant, net	1,973,959		1,901,657		1,917,396
Non-utility plant in service	298,586		296,169		296,839
Non-utility construction work in progress	4,800		7,891		7,768
Less: Accumulated depreciation	43,483		37,856		39,340
Non-utility plant, net	259,903		266,204		265,267
Total property, plant, and equipment	$	2,233,862	$	2,167,861	$	2,182,663
Capital expenditures in accrued liabilities	$	8,918	$	9,700	$	8,985

10. GAS RESERVES

We have invested $188 million through our gas reserves program in the Jonah Field located in Wyoming as of September 30, 2016. Gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the consolidated balance sheets. Our investment in gas reserves provides long-term price protection for utility customers through the original agreement with Encana Oil & Gas (USA) Inc. under which we invested $178 million and the amended agreement with Jonah Energy LLC under which an additional $10 million was invested.

The cost of gas, including a carrying cost for the rate base investment made under the original agreement, is included in our annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our investment under the original agreement, less accumulated amortization and deferred taxes, earns a rate of return.

The volumes produced from the wells under the amended agreement with Jonah are included in our Oregon PGA at a fixed rate of $0.4725 per therm.

The following table outlines our net gas reserves investment:

	September 30,				December 31,
In thousands	2016		2015		2015
Gas reserves, current	$	16,257	$	17,822	$	17,094
Gas reserves, non-current	171,280		169,300		170,453
Less: Accumulated amortization	67,304		51,516		55,901
Total gas reserves(1)	120,233		135,606		131,646
Less: Deferred taxes on gas reserves	25,799		23,042		27,203
Net investment in gas reserves	$	94,434	$	112,564	$	104,443

⁽¹⁾ Our investment in additional wells included in total gas reserves was $7.0 million, $9.7 million and $8.0 million at September 30, 2016 and 2015 and December 31, 2015, respectively.

Our investment is included on our consolidated balance sheets under gas reserves with our maximum loss exposure limited to our investment balance.

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11. INVESTMENTS

Investments in Gas Pipeline

Trail West Pipeline, LLC (TWP), a wholly-owned subsidiary of TWH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. NWN Energy, a wholly-owned subsidiary of NW Natural owns 50% of TWH, and 50% is owned by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation.

Variable Interest Entity (VIE) Analysis

TWH is a VIE, with our investment in TWP reported under equity method accounting. We have determined we are not the primary beneficiary of TWH’s activities as we only have a 50% share of the entity and there are no stipulations that allow us a disproportionate amount of influence over it. Our investments in TWH and TWP are included in other investments on our consolidated balance sheets. If we do not develop this investment, our maximum loss exposure related to TWH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50% owner. Our investment balance in TWH was $13.4 million at September 30, 2016 and 2015 and December 31, 2015. See Note 12 in the 2015 Form 10-K.

Other Investments

Other investments include financial investments in life insurance policies, which are accounted for at cash surrender value, net of policy loans. See Note 12 in the 2015 Form 10-K.

12. DERIVATIVE INSTRUMENTS

We enter into financial derivative contracts to hedge a portion of our utility’s natural gas sales requirements. These contracts include swaps, options and combinations of option contracts. We primarily use these derivative financial instruments to manage commodity price variability. A small portion of our derivative hedging strategy involves foreign currency exchange contracts.

We enter into these financial derivatives, up to prescribed limits, primarily to hedge price variability related to our physical gas supply contracts as well as to hedge spot purchases of natural gas. The foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for pipeline demand charges paid in Canadian dollars. In the normal course of business, we also enter into indexed-price physical forward natural gas commodity purchase contracts and options to meet the requirements of utility customers. These contracts qualify for regulatory deferral accounting treatment.

We also enter into exchange contracts related to the third-party asset management of our gas portfolio, some of which are derivatives that do not qualify for hedge accounting or regulatory deferral, but are subject to our regulatory sharing agreement. These derivatives are recognized in operating revenues in our gas storage segment, net of amounts shared with utility customers.

Notional Amounts

The following table presents the absolute notional amounts related to open positions on our derivative instruments:

	September 30,				December 31,
In thousands	2016		2015		2015
Natural gas (in therms):
Financial	537,100		416,075		346,875
Physical	621,230		521,350		404,645
Foreign exchange (in thousands)	$	8,404	$	8,023	$	9,025

Purchased Gas Adjustment (PGA)

Derivatives entered into by the utility for the procurement or hedging of natural gas for future gas years generally receive regulatory deferral accounting treatment. In general, our commodity hedging for the current gas year is completed prior to the start of the gas year, and hedge prices are reflected in our weighted-average cost of gas in the PGA filing. Hedge contracts entered into after the start of the PGA period are subject to our PGA incentive sharing mechanism in Oregon. As of November 1, 2016 and 2015, we reached our target hedge percentage of approximately 75% for both the 2016-17 and 2015-2016 gas years. Hedge contracts entered into prior to our filing,

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in September 2015, were included in the PGA for the 2015-2016 gas year. Hedge contracts entered into after our PGA filing, and related to subsequent gas years, may be included in future PGA filings for and qualify for regulatory deferral.

Unrealized and Realized Gain/Loss

The following table reflects the income statement presentation for the unrealized gains and losses on our derivative instruments:

	Three Months Ended September 30,
	2016						2015
In thousands	Natural gas commodity			Foreign exchange			Natural gas commodity			Foreign exchange
Benefit (expense) to cost of gas	$	(8,045	)	$	(52	)	$	(8,415	)	$	(150	)
Operating (loss) revenues	(110		)	—			33			—
Less:
Amounts deferred to regulatory accounts on balance sheet	8,118			52			8,391			150
Total (loss) gain in pre-tax earnings	$	(37	)	$	—		$	9		$	—

	Nine Months Ended September 30,
	2016						2015
In thousands	Natural gas commodity			Foreign exchange			Natural gas commodity			Foreign exchange
Benefit (expense) to cost of gas	$	5,562		$	5		$	(21,876	)	$	(413	)
Operating (loss) revenues	(266		)	—			55			—
Less:
Amounts deferred to regulatory accounts on balance sheet	(5,385		)	(5		)	21,838			413
Total (loss) gain in pre-tax earnings	$	(89	)	$	—		$	17		$	—

UNREALIZED GAIN/LOSS. Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory accounting standards. The cost of foreign currency forward and natural gas derivative contracts are recognized immediately in the cost of gas; however, costs above or below the amount embedded in the current year PGA are subject to a regulatory deferral tariff and therefore, are recorded as a regulatory asset or liability.

REALIZED GAIN/LOSS. We realized net losses of $1.0 million and $24.1 million for the three and nine months endedSeptember 30, 2016, respectively, and net losses of $2.3 million and $24.3 million for the three and nine months endedSeptember 30, 2015, respectively, from the settlement of natural gas financial derivative contracts. Realized gains and losses are recorded in cost of gas, deferred through our regulatory accounts, and amortized through customer rates in the following year.

Credit Risk Management of Financial Derivative Instruments

No collateral was posted with or by our counterparties as of September 30, 2016 or 2015. We attempt to minimize the potential exposure to collateral calls by counterparties to manage our liquidity risk. Counterparties generally allow a certain credit limit threshold before requiring us to post collateral against loss positions. Given our counterparty credit limits and portfolio diversification, we were not subject to collateral calls in 2016 or 2015. Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We could also be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change.

Based upon current commodity financial swap and option contracts outstanding, which reflect unrealized losses of $2.7 million at September 30, 2016, we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various credit downgrade rating scenarios for NW Natural as follows:

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			Credit Rating Downgrade Scenarios
In thousands	(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3			Speculative
With Adequate Assurance Calls	$	—	$	—	$	—	$	(1,036	)	$	(1,242	)
Without Adequate Assurance Calls	—		—		—		(1,036		)	181

Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our consolidated balance sheets. The Company and its counterparties have the ability to set-off their obligations to each other under specified circumstances. Such circumstances may include a defaulting party, a credit change due to a merger affecting either party, or any other termination event.

If netted by counterparty, our derivative position would result in an asset of $4.1 million and a liability of $5.1 million as of September 30, 2016. As of September 30, 2015, our derivative position would have resulted in an asset of $3.1 million and a liability of $25.3 million. As of December 31, 2015, our derivative position would have resulted in an asset of $2.7 million and a liability of $25.5 million.

We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of customers. See Note 13 in our 2015 Form 10-K for additional information.

Fair Value

In accordance with fair value accounting, we include non-performance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. The inputs in our valuation models include natural gas futures, volatility, credit default swap spreads and interest rates. Additionally, our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at September 30, 2016. As of September 30, 2016, the net fair value was a liability of $1.0 million, using significant other observable, or level 2, inputs. As of September 30, 2015 and December 31, 2015 the net fair values were assets of $22.2 million and $22.8 million, respectively, using significant other observable, or level 2, inputs. No level 3 inputs were used in our derivative valuations, and there were no transfers between level 1 or level 2 during the three months ended September 30, 2016 and 2015. See Note 2 in the 2015 Form 10-K.

13. ENVIRONMENTAL MATTERS

We own, or previously owned, properties that may require environmental remediation or action. We estimate the range of loss for environmental liabilities based on current remediation technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties (PRPs). When amounts are prudently expended related to site remediation, we have a recovery mechanism in place to collect 96.68% of remediation costs from Oregon customers, and we are allowed to defer environmental remediation costs allocated to customers in Washington annually until they are reviewed for prudence at a subsequent proceeding.

Our sites are subject to the remediation process prescribed by the Environmental Protection Agency (EPA) and the Oregon Department of Environmental Quality (ODEQ). The process begins with a remedial investigation (RI) to determine the nature and extent of contamination and then a risk assessment (RA) to establish whether the contamination at the site poses unacceptable risks to humans and the environment. Next, a feasibility study (FS) or an engineering evaluation/cost analysis (EE/CA) evaluates various remedial alternatives. It is at this point in the process when we are able to estimate a range of remediation costs and record a reasonable potential remediation liability, or make an adjustment to our existing liability. From this study, the regulatory agency selects a remedy and issues a Record of Decision (ROD). After the ROD is issued, we seek to negotiate a consent decree or consent judgment for designing and implementing the remedy. We have the ability to further refine estimates of remediation liabilities at that time.

Remediation may include treatment of contaminated media such as sediment, soil, and groundwater, removal and disposal of media, or institutional controls such as legal restrictions on future property use. Following construction of

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the remedy, the EPA and ODEQ also have requirements for ongoing maintenance, monitoring and other post-remediation care that may continue for many years. Where appropriate and reasonably known, we will provide for these costs in our remediation liabilities described above.

Due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases, we have disclosed the nature of the possible loss and the fact that the high end of the range cannot be reasonably estimated where a range of potential loss is available. Unless there is an estimate within the range of possible losses that is more likely than other cost estimates within that range, we record the liability at the low end of this range. It is likely changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to our continued evaluation and clarification concerning our responsibility, the complexity of environmental laws and regulations, and the determination by regulators of remediation alternatives. In addition to remediation costs, we could also be subject to Natural Resource Damages (NRD) claims. We will assess the likelihood and probability of each claim and recognize a liability if deemed appropriate. As of September 30, 2016, we have not received any material NRD claims.

Environmental Sites

The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other current liabilities and other noncurrent liabilities on the consolidated balance sheets:

	Current Liabilities						Non-Current Liabilities
	September 30,				December 31,		September 30,				December 31,
In thousands	2016		2015		2015		2016		2015		2015
Portland Harbor site:
Gasco/Siltronic Sediments	$	1,726	$	1,236	$	2,229	$	42,880	$	38,533	$	42,641
Other Portland Harbor	1,461		1,243		1,972		4,362		4,563		5,073
Gasco Upland site	8,191		4,510		10,599		49,928		36,795		52,117
Siltronic Upland site	—		538		951		—		489		337
Central Service Center site	112		177		25		—		—		—
Front Street site	841		420		1,155		7,818		215		7,748
Oregon Steel Mills	—		—		—		179		179		179
Total	$	12,331	$	8,124	$	16,931	$	105,167	$	80,774	$	108,095

PORTLAND HARBOR SITE. The Portland Harbor is an EPA listed Superfund site that is approximately 10 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands and the Siltronic uplands sites. We are a PRP to the Superfund site and have joined with some of the other PRPs (the Lower Willamette Group or LWG) to develop a Portland Harbor Remedial Investigation/Feasibility Study (RI/FS), which we submitted to the EPA in 2012. In August 2015, the EPA issued its own Draft Feasibility Study (Draft FS) for comment. The EPA Draft FS provides a new range of remedial costs for the entire Portland Harbor Superfund Site, which includes the Gasco/Siltronic Sediment site, discussed below. The range of present value costs estimated by the EPA for various remedial alternatives for the entire Portland Harbor, as provided by the EPA's Draft FS, is $791 million to $2.45 billion. The range provided in the EPA's Draft FS is based on cost alternatives the EPA estimates to have an accuracy between -30% and +50% of actual costs, depending on the scope of work.

In June 2016, the EPA issued their Final Feasibility Study (Final FS) and proposed remediation plan (Proposed Plan) for the Portland Harbor Superfund site. The Proposed Plan presents the EPA’s preferred clean-up alternative, which estimates the present value cost at approximately $746 million with an accuracy between -30% and +50% of actual costs, a significant reduction from prior estimates for this level of cleanup. Along with several members of the LWG, we have filed a dispute with the EPA over concerns that the EPA's Final FS contains factual and technical errors and is insufficient to support remedy selection. We have also submitted comments to the Proposed Plan identifying technical errors and suggesting corrections to the Plan. The EPA is reviewing all public comments andhas stated it intends to release a Record of Decision, the final determination of a cleanup approach for the Portland Harbor site, by the end of January 2017. 

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While the EPA's Final FS and Proposed Plan provides a higher range of costs than the LWG's submission in 2012, our potential liability is still a portion of the costs of the remedy for the entire Portland Harbor Superfund site. The cost of that remedy is expected to be allocated among more than 100 PRPs. We are participating in a non-binding allocation process in an effort to settle this potential liability. The Final FS and Proposed Plan do not provide any additional clarification around allocation of costs.

We manage our liability related to the Superfund site as two distinct remediation projects, the Gasco/Siltronic Sediments and Other Portland Harbor projects.

Gasco/Siltronic Sediments.In 2009, NW Natural and Siltronic Corporation entered into a separate Administrative Order on Consent with the EPA to evaluate and design specific remedies for sediments adjacent to the Gasco uplands and Siltronic uplands sites. We submitted a draft EE/CA to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA as well as costs for the additional studies and design work needed before the clean-up can occur, and for regulatory oversight throughout the clean-up range from $44.6 million to $350 million. We have recorded a liability of $44.6 million for the sediment clean-up, which reflects the low end of the range. At this time, we believe sediments at this site represent the largest portion of our liability related to the Portland Harbor site, discussed above. 

Other Portland Harbor.NW Natural incurs costs related to its membership in the LWG. NW Natural also incurs costs related to natural resource damages from these sites. The Company and other parties have signed a cooperative agreement with the Portland Harbor Natural Resource Trustee council to participate in a phased natural resource damage assessment to estimate liabilities to support an early restoration-based settlement of natural resource damage claims. Natural resource damage claims may arise only after a remedy for clean-up has been settled. We have recorded a liability for these claims which is at the low end of the range of the potential liability; the high end of the range cannot be reasonably estimated at this time. This liability is not included in the range of costs provided in the draft FS for the Portland Harbor or noted above.

GASCO UPLANDS SITE. A predecessor of NW Natural, Portland Gas and Coke Company, owned a former gas manufacturing plant that was closed in 1958 (Gasco site) and is adjacent to the Portland Harbor site described above. The Gasco site has been under investigation by us for environmental contamination under the ODEQ Voluntary Clean-Up Program (VCP). It is not included in the range of remedial costs for the Portland Harbor site noted above. We manage the Gasco site in two parts, the uplands portion and the groundwater source control action.

We submitted a revised Remedial Investigation Report for the uplands to ODEQ in May 2007. In March 2015, ODEQ approved the RA NW Natural submitted in 2010, enabling us to begin work on the FS in 2016. We have recognized a liability for the remediation of the uplands portion of the site which is at the low end of the range of potential liability; the high end of the range cannot be reasonably estimated at this time.

In October 2016, ODEQ and NW Natural agreed to amend their VCP agreement to incorporate a portion of the Siltronic property adjacent to the Gasco site formerly owned by Portland Gas & Coke between 1939 and 1960 into the Gasco RA and FS. Previously, we were conducting an investigation of manufactured gas plant constituents on the entire Siltronic uplands for ODEQ. Siltronic will be working with ODEQ directly on environmental impacts to the remainder of its property.

In September 2013, we completed construction of a groundwater source control system, including a water treatment station, at the Gasco site. We are working with ODEQ on monitoring the effectiveness of the system and at this time it is unclear what, if any, additional actions ODEQ may require subsequent to the initial testing of the system or as part of the final remedy for the uplands portion of the Gasco site. We have estimated the cost associated with the ongoing operation of the system and have recognized a liability which is at the low end of the range of potential cost. We cannot estimate the high end of the range at this time due to the uncertainty associated with the duration of running the water treatment station, which is highly dependent on the remedy determined for both the upland portion as well as the final remedy for our Gasco sediment exposure.

Beginning November 1, 2013, capital asset costs of $19.0 million for the Gasco water treatment station were placed into rates with OPUC approval. The OPUC deemed these costs prudent. Beginning November 1, 2014, the OPUC

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approved the application of $2.5 million from insurance proceeds plus interest to reduce the total amount of Gasco capital costs to be recovered through rate base. A portion of these proceeds was non-cash in 2014.

OTHER SITES. In addition to those sites above, we have environmental exposures at three other sites: Central Service Center, Front Street and Oregon Steel Mills. Due to the uncertainty of the design of remediation, regulation, timing of the remediation and in the case of the Oregon Steel Mills site, pending litigation, liabilities for each of these sites have been recognized at their respective low end of the range of potential liability; the high end of the range could not be reasonably estimated at this time.

Central Service Center site.We are currently performing an environmental investigation of the property under ODEQ's Independent Cleanup Pathway. This site is on ODEQ's list of sites with confirmed releases of hazardous substances, and cleanup is necessary.

Front Street site.The Front Street site was the former location of a gas manufacturing plant we operated (the former Portland Gas Manufacturing site, or PGM). At ODEQ’s request, we conducted a sediment and source control investigation and provided findings to ODEQ. In December 2015, we completed a FS on the former Portland Gas Manufacturing site. The FS provided a range of $7.6 million to $12.9 million for remedial costs. We have recorded a liability at the low end of the range of possible loss as no alternative in the range is considered more likely than another. Further, we have recognized an additional liability of $1.1 million for additional studies and design costs as well as regulatory oversight throughout the clean-up that will be required to assist in ODEQ making a remedy selection and completing a design.

Oregon Steel Mills site.Refer to the “Legal Proceedings,” below.

Site Remediation and Recovery Mechanism (SRRM)

We have a SRRM through which we track and have the ability to recover past deferred and future prudently incurred environmental remediation costs allocable to Oregon, subject to an earnings test.

REGULATORY ACTIVITIES. In February 2015, the OPUC issued an Order addressing outstanding issues related to the SRRM (2015 Order), which required us to forego collection of $15 million out of approximately $95 million in total environmental remediation expenses and associated carrying costs the Company had deferred through 2012 based on the OPUC’s determination of how an earnings test should apply to amounts deferred from 2003 to 2012, with adjustments for other factors the OPUC deemed relevant. As a result, we recognized a $15.0 million non-cash charge in operations and maintenance expense in the first quarter of 2015. Also, as a result of the 2015 Order, we recognized $5.3 million pre-tax of interest income related to the equity earnings on our deferred environmental expenses.

In addition, the OPUC issued a subsequent Order regarding SRRM implementation (2016 Order) in January 2016 in which the OPUC: (1) disallowed the recovery of $2.8 million of interest earned on the previously disallowed environmental expenditure amounts; (2) clarified the state allocation of 96.68% of environmental remediation costs for all environmental sites to Oregon; and (3) confirmed our treatment of $13.8 million of expenses put into the SRRM amortization account was correct and in compliance with prior OPUC orders. As a result of the 2016 Order, we recognized a $3.3 million non-cash charge in the first quarter, of which $2.8 million is reflected in other income and expense, net and $0.5 million is included in operations and maintenance expense.

COLLECTIONS FROM OREGON CUSTOMERS. The SRRM provides us with the ability to recover past deferred and future prudently incurred environmental remediation costs allocable to Oregon, subject to an earnings test. The SRRM created three classes of deferred environmental remediation expense:

• Pre-review - This class of costs represents remediation spend that has not yet been deemed prudent by the OPUC. Carrying costs on these remediation expenses are recorded at our authorized cost of capital. The Company anticipates the prudence review for annual costs and approval of the earnings test prescribed by the OPUC to occur by the end of the third quarter of the following year.

• Post-review - This class of costs represents remediation spend that has been deemed prudent and allowed after applying the earnings test, but is not yet included in amortization. We earn a carrying cost on these amounts at a rate equal to the five-year treasury rate plus 100 basis points.

• Amortization - This class of costs represents amounts included in current customer rates for collection and is generally calculated as one-fifth of the post-review deferred balance. We earn a carrying cost equal to the amortization rate determined annually by the OPUC, which approximates a short-term borrowing rate. We

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included $10.0 million and $8.4 million of deferred remediation expense approved by the OPUC for collection during the 2016-2017 and 2015-2016 PGA years, respectively.

In addition to the collection amount noted above, the Order also provides for the annual collection of $5 million from Oregon customers through a tariff rider. As we collect amounts from customers, we recognize these collections as revenue and separately amortize our deferred regulatory asset balance through operating expense.

We received total environmental insurance proceeds of approximately $150 million as a result of settlements from our litigation that was dismissed in July 2014. Under the OPUC Order, one-third of the Oregon allocated proceeds were applied to costs deferred through 2012, and the remaining two-thirds will be applied to costs over the next 20 years. Annually, the Order provided for the application of $5 million of insurance proceeds plus interest against deferred remediation expense deemed prudent in the same annual period; annual amounts not utilized are carried forward to apply against future prudently incurred costs. We accrue interest on the insurance proceeds in the customer’s favor at a rate equal to the five-year treasury rate plus 100 basis points. As of September 30, 2016, we have applied $63.2 million of insurance proceeds to prudently incurred remediation costs.

The following table presents information regarding the total regulatory asset deferred:

	September 30,						December 31,
In thousands	2016			2015			2015
Deferred costs and interest(1)	$	54,704		$	82,323		$	79,505
Accrued site liabilities(2)	117,202			88,898			125,026
Insurance proceeds and interest	(97,893		)	(121,414		)	(118,677		)
Total regulatory asset deferral(1)	74,013			49,807			85,854
Current regulatory assets(3)	9,734			12,364			9,270
Long-term regulatory assets(3)	64,279			37,443			76,584

⁽¹⁾ Includes pre-review and post-review deferred costs, amounts currently in amortization, and interest, net of amounts collected from customers.

⁽²⁾  Excludes $0.3 million, or 3.32% of the Front Street site liability as the OPUC allows recovery of 96.68% of costs for all sites, including those that historically served only Oregon customers.

⁽³⁾  Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test.

ENVIRONMENTAL EARNINGS TEST. The 2015 Order directed us to implement an annual environmental earnings test for our prudently incurred remediation expense. Prudently incurred Oregon allocated annual remediation expense and interest in excess of the $5 million tariff rider and $5 million insurance proceeds application plus interest on the insurance proceeds are recoverable through the SRRM, to the extent the utility earns at or below our authorized Return On Equity (ROE). To the extent the utility earns more than its authorized ROE in a year, the utility is required to cover environmental expenses and interest on expenses greater than $10 million (plus interest from insurance proceeds) with those earnings that exceed its authorized ROE.

Under the 2015 Order, the OPUC will revisit the deferral and amortization of future remediation expenses, as well as the treatment of remaining insurance proceeds three years from the original Order, or earlier if the Company gains greater certainty about its future remediation costs, to consider whether adjustments to the mechanism may be appropriate.

WASHINGTON DEFERRAL. In Washington, cost recovery and carrying charges on amounts deferred for costs associated with services provided to Washington customers will be determined in a future proceeding. Annually, we review all regulatory assets for recoverability or more often if circumstances warrant. If we should determine all or a portion of these regulatory assets no longer meet the criteria for continued application of regulatory accounting, then we would be required to write-off the net unrecoverable balances against earnings in the period such a determination is made.

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Legal Proceedings

NW Natural is subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, we do not expect that the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations or cash flows. See also Part II, Item 1, “Legal Proceedings.”

OREGON STEEL MILLS SITE.In 2004, NW Natural was served with a third-party complaint by the Port of Portland (the Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants, were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Evraz Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial. Although the final outcome of this proceeding cannot be predicted with certainty, we do not expect the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows.

For additional information regarding other commitments and contingencies, see Note 14 in the 2015 Form 10-K.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural or the Company) financial condition, including the principal factors that affect results of operations. The discussion refers to our consolidated results for the three and nine months ended September 30, 2016 and 2015. References in this discussion to "Notes" are to the Notes to Unaudited Consolidated Financial Statements in this report. A significant portion of our business results are seasonal in nature, and, as such, the results of operations for the three month periods are not necessarily indicative of expected fiscal year results. Therefore, this discussion should be read in conjunction with our 2015 Annual Report on Form 10-K (2015 Form 10-K).

The consolidated financial statements include NW Natural and its direct and indirect wholly-owned subsidiaries including:

• NW Natural Energy, LLC (NWN Energy);

• NW Natural Gas Storage, LLC (NWN Gas Storage);

• Gill Ranch Storage, LLC (Gill Ranch);

• NNG Financial Corporation (NNG Financial);

• Northwest Energy Corporation (Energy Corp); and

• NW Natural Gas Reserves, LLC (NWN Gas Reserves).

We operate in two primary reportable business segments: local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as other. We refer to our local gas distribution business as the utility, and our gas storage segment and other as non-utility. Our utility segment includes our NW Natural local gas distribution business, NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp, and the utility portion of our Mist underground storage facility in Oregon (Mist). Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist, and asset management services. Other includes NWN Energy's equity investment in Trail West Holding, LLC (TWH), which is pursuing the development of a proposed natural gas pipeline through its wholly-owned subsidiary, Trail West Pipeline, LLC (TWP), and NNG Financial's equity investment in Kelso-Beaver Pipeline (KB Pipeline). For a further discussion of our business segments and other, see Note 4.

In addition to presenting the results of operations and earnings amounts in total, certain financial measures are expressed in cents per share or exclude the after-tax regulatory disallowance related to the OPUC's 2015 and 2016 environmental orders, which are non-GAAP financial measures. We present net income and earnings per share (EPS) excluding the regulatory disallowances along with the U.S. GAAP measures to illustrate the magnitude of this disallowance on ongoing business and operational results. Although the excluded amounts are properly included in the determination of net income and earnings per share under U.S. GAAP, we believe the amount and nature of such disallowances make period to period comparisons of operations difficult or potentially confusing. Financial measures are expressed in cents per share as these amounts reflect factors that directly impact earnings, including income taxes. All references in this section to EPS are on the basis of diluted shares (see Note 3). We use such non-GAAP financial measures to analyze our financial performance because we believe they provide useful information to our investors and creditors in evaluating our financial condition and results of operations.

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EXECUTIVE SUMMARY

We manage our business and strategic initiatives with a long-term view of providing natural gas service safely and reliably to customers, working with regulators on key policy initiatives, and remaining focused on growing our business. See "2016 Outlook" in our 2015 Form 10-K for more information. Highlights for the quarter include:

• received Notice to Proceed for the development of our North Mist gas storage expansion project allowing the Company to move the project forward to begin construction this fall. Project costs are estimated to be $128 million with a target in-service date during the winter of 2018-19;

• ranked first in residential customer satisfaction for large gas utilities in the West in the 2016 J.D. Power and Associates study, making 2016 the 15th consecutive year of top three scores;

• reduced residential rates to the lowest level in 15 years with a credit of $19.4 million to customers in June 2016 and an additional rate reduction effective November 1, 2016;

• added over 11,500 customers during the past twelve months for a growth rate of 1.6% at September 30, 2016; and

• delivered increasing dividends for the 61st consecutive year. Our current annual dividend rate is $1.88 per share.

Key financial highlights include:

	Three Months Ended September 30,
	2016						2015
In thousands, except per share data	Amount			Per Share			Amount			Per Share			$ Change
Consolidated net loss	$	(8,040	)	$	(0.29	)	$	(6,685	)	$	(0.24	)	$	(1,355	)
Utility margin	50,923						51,619						(696		)
Gas storage operating revenues	7,293						5,596						1,697

THREE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Consolidated net loss increased $1.4 million primarily due to the following factors:

• an increase of $2.8 million in operating and maintenance expenses primarily due to an increase in non-payroll costs as a result of cost savings initiatives that were implemented in the second half of 2015 that did not re-occur in 2016; and

• a decrease in utility margin of $0.7 million primarily due to lower contributions from our gas reserve investments, which decreased due to regular amortization, and lower gas cost incentive sharing; partially offset by customer growth, and

• an increase in gas storage revenues of $1.7 million largely due to higher revenues from our asset management agreements at both storage facilities, but predominantly at our Mist facility, and higher contract prices at our Gill Ranch facility for the 2016-2017 gas year.

	Nine Months Ended September 30,
	2016				2015
In thousands, except per share data	Amount		Per Share		Amount		Per Share		$ Change
Consolidated net income	$	30,620	$	1.11	$	23,998	$	0.88	$	6,622
Adjustments:
Regulatory environmental disallowance, net of taxes ($1,304 and $5,925)(1)	1,996		0.07		9,075		0.33		(7,079		)
Adjusted consolidated net income(1)	$	32,616	$	1.18	$	33,073	$	1.21	$	(457	)
Utility margin	$	256,958			$	252,935			$	4,023
Gas storage operating revenues	19,654				16,232				3,422

⁽¹⁾ Regulatory environmental disallowance of $3.3 million in 2016 includes $2.8 million recorded in utility other income (expense), net and $0.5 million recorded in utility operations and maintenance expense. Regulatory environmental disallowance of $15.0 million in 2015 is recorded in utility operations and maintenance expense. Adjusted consolidated net income and EPS are non-GAAP financial measures based on the after-tax disallowance using the combined federal and state statutory tax rate of 39.5%. EPS is calculated using 27.6 million and 27.4 million diluted shares for the nine months ended September 30, 2016 and 2015, respectively.

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NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Consolidated net income increased $6.6 million during the nine months ended September 30, 2016 primarily due to the environmental disallowance described in the table above. Excluding the impact of the regulatory environmental orders in 2015 and 2016, adjusted consolidated net income decreased $0.5 million primarily due to the following factors:

• a $5.5 milliondecrease in other income (expense), net primarily related to the recognition of $5.3 million of equity earnings on deferred regulatory asset balances as a result of the OPUC SRRM Order in the first quarter of 2015; and

• a $3.7 million increase in operating and maintenance expenses primarily due to increases in professional services costs and contract work as well as other non-payroll costs as a result of cost savings initiatives that were implemented in the second half of 2015 that did not re-occur in 2016; partially offset by

• a $4.0 million increase in utility margin primarily due to customer growth and gains from gas cost incentive sharing;

• an increase of $3.4 million in gas storage revenues largely due to higher revenues from our asset management agreements at both storage facilities, but predominantly at our Mist facility, and higher contract values at our Gill Ranch facility for the 2016-2017 gas year; and

• a decrease in interest expense of $1.8 million due to the early retirement of $20 million of Gill Ranch's debt in December 2015 and the redemption of $40 million of utility bonds in June 2015.

Dividends

Dividend highlights include:  

	Three Months Ended September 30,				Nine Months Ended September 30,
Per common share	2016		2015		2016		2015		QTR Change		YTD Change
Dividends paid	$	0.4675	$	0.4650	$	1.4025	$	1.3950	$	0.0025	$	0.0075

The Board of Directors declared a quarterly dividend on our common stock of $0.4700 per share, payable on November 15, 2016, to shareholders of record on October 31, 2016, reflecting an indicated annual dividend rate of $1.88 per share.

RESULTS OF OPERATIONS

Regulatory Matters

Regulation and Rates

UTILITY. Our utility business is subject to regulation by the OPUC, WUTC, and FERC with respect to, among other matters, rates and terms of service. The OPUC and WUTC also regulate the system of accounts and issuance of securities by our utility. Approximately 89% of our utility gas customers are located in Oregon, with the remaining 11% in Washington. Earnings and cash flows from utility operations are largely determined by rates set in general rate cases and other proceedings in Oregon and Washington. They are also affected by the local economies in Oregon and Washington, the pace of customer growth in the residential, commercial, and industrial markets, and our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery of our utility-related costs, including operating expenses and investment costs in utility plant and other regulatory assets. See "Regulatory Proceeding Updates" below.

GAS STORAGE. Our gas storage business is subject to regulation by the OPUC, WUTC, CPUC, and FERC with respect to, among other matters, rates and terms of service. The OPUC and CPUC also regulate the issuance of securities and system of accounts, and regulate intrastate storage services. The FERC regulates interstate storage services. The FERC uses a maximum cost of service model which allows for gas storage prices to be set at or below the cost of service as approved by each agency in the last regulatory filing. The OPUC Schedule 80 rates are tied to the FERC rates, and are updated whenever we modify our FERC maximum rates. The CPUC regulates Gill Ranch under a market-based rate model which allows for the price of storage services to be set by the marketplace. In 2015, approximately 72% of our storage revenues were derived from FERC, Oregon, and Washington regulated operations and approximately 28% from California operations. For the nine months ended September 30, 2016, approximately 70% of our storage revenues were derived from FERC, Oregon, and Washington regulated operations and approximately 30% from California operations.

Most Recent General Rate Cases

OREGON.Effective November 1, 2012, the OPUC authorized rates to customers based on an ROE of 9.5%, an overall rate of return of 7.78%, and a capital structure of 50% common equity and 50% long-term debt.

WASHINGTON. Effective January 1, 2009, the WUTC authorized rates to customers based on an ROE of 10.1% and an overall rate of return of 8.4% with a capital structure of 51% common equity, 5% short-term debt, and 44% long-term debt.

FERC.We are required under our Mist interstate storage certificate authority and rate approval orders to file every five years either a petition for rate approval or a cost and revenue study to change or justify maintaining the existing rates for our interstate storage services. In December 2013 we filed a rate petition, which was approved in 2014 and allows for the maximum cost-based rates for our interstate gas storage services. These rates were effective January 1, 2014, with the rate changes having no significant impact on our revenues.

The Company continuously monitors the utility and evaluates the need for a rate case. Currently the Company is contemplating potentially filing an Oregon rate case in 2017 or 2018 with a potential Washington rate case thereafter.

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Regulatory Proceeding Updates

During the nine months ended September 30, 2016, we were involved in the regulatory activities discussed below.

ENVIRONMENTAL COST DEFERRAL AND SITE REMEDIATION AND RECOVERY MECHANISM (SRRM).In February 2015, as part of the implementation of the SRRM, the OPUC issued an Order (2015 Order) requiring us to forego collection of $15 million out of approximately $95 million in total environmental remediation expenses and associated carrying costs we had deferred through 2012 based on the OPUC’s determination of how an earnings test should apply to amounts deferred from 2003 to 2012, with adjustments for other factors the OPUC deemed relevant. As a result, we recognized a $15.0 million non-cash charge in operations and maintenance expense in the first quarter of 2015. Also, as a result of the 2015 Order, we recognized $5.3 million pre-tax of interest income related to the equity earnings on our deferred environmental expenses in the first quarter of 2015.

In addition, the OPUC issued a subsequent Order regarding our SRRM (2016 Order) in January 2016 in which the OPUC: (1) disallowed the recovery of $2.8 million of interest earned on the previously disallowed environmental expenditure amounts; (2) clarified the state allocation of 96.68% of environmental remediation costs for all environmental sites to Oregon; and (3) confirmed our treatment of $13.8 million of expenses put into the SRRM amortization account was correct and in compliance with prior OPUC orders. As a result of the 2016 Order, we recognized a $3.3 million non-cash charge, of which $2.8 million is reflected in other income and expense, net and $0.5 million is included in operations and maintenance expense. Our compliance filing related to the 2016 Order was filed with the OPUC on March 11, 2016. We do not expect any further action by the OPUC related to that filing. See Note 13 regarding our SRRM.

SYSTEM INTEGRITY PROGRAM (SIP). We filed a request to extend the SIP program in the fourth quarter of 2014. The OPUC considered our renewal request at a public meeting in March 2015 and suspended our filing and ordered additional process, including involvement of other gas utilities in the state, before making a final decision. In 2016, we withdrew our request to extend the SIP program and instead focused our efforts on establishing guidelines for future safety cost trackers with the OPUC and an all-party agreement was filed with the commission on October 10, 2016.

HEDGING.In our 2014 Integrated Resource Plan, we proposed to the OPUC that we engage in continued long-term gas hedging. The OPUC is considering long-term hedging along with a general review of overall hedging practices among all gas utilities in the state. The OPUC therefore opened a new docket to discuss broader gas hedging practices across gas utilities in Oregon. Our request for the OPUC to consider long-term hedging practices will be considered as part of this docket. The OPUC established that this docket will follow two phases. The first phase was focused on an analytical review of hedging and hedging practices. We are currently working through the second phase regarding potential hedging guidelines. After the second phase is complete, a status report will be submitted to the OPUC, and the remainder of the process will be determined at that time.

The Washington Utilities and Transportation Commission (WUTC) also is conducting an investigation into the hedging practices of gas utilities operating in Washington, and considering whether it should require gas utilities to implement certain practices related to hedging. The WUTC is reviewing comments received from all parties and will determine next steps in the docket after reviewing those comments. 

INTERSTATE STORAGE AND OPTIMIZATION SHARING.We received an Order from the OPUC in March 2015 on their review of the current revenue sharing arrangement that allocates a portion of the net revenues generated from non-utility Mist storage services and third-party asset management services to utility customers. The Order requires a third-party cost study to be performed and the results of the cost study may initiate a new docket or the re-opening of the original docket. We are continuing to engage with the parties, as directed by the OPUC, to hire a third-party and facilitate completion of the work directed by the OPUC.

CARBON SOLUTIONS PROGRAM.Oregon Senate Bill 844 (SB 844) required the OPUC to develop rules and programs to reduce carbon emissions in Oregon. In June 2015, we submitted our first project related to Combined Heat and Power (CHP) for OPUC approval. The submitted CHP program would pay owners of new commercial- and industrial-scale CHP systems for verified carbon emission reductions. In April 2016, the OPUC issued an order declining our program as submitted and provided guidance on program structure for potential future submissions. We are currently contemplating our next steps for this program.

WEATHER NORMALIZATION MECHANISM (WARM). In Oregon, WARM is applied to residential and commercial customers' bills to adjust for temperature variances from average weather. In 2015, the OPUC initiated a review of

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the WARM mechanism as a result of customer complaints received related to surcharges applied under the WARM mechanism due to the record warm weather in our service territory during the 2014-15 winter. In May of 2016, we filed a stipulation among the parties resolving the issues identified in the review. In June 2016, the OPUC issued an order adopting the stipulation, which included modest changes to the WARM mechanism. The most notable change relates to the timing of collection of any unbilled WARM amounts, due to operation of certain caps on monthly bills in the program. Previously, any unbilled WARM amounts deferred throughout the WARM period were billed to customers in June. Under the adjusted WARM mechanism, the collections of any unbilled WARM amounts will continue to be deferred and will earn a carry charge until collected in the PGA the following year. These changes do not reduce the value WARM provides to us or our customers in mitigating the impact from variations in weather.

INTEGRATED RESOURCE PLAN (IRP). We filed our 2016 Oregon and Washington IRPs on August 26, 2016 and anticipate acknowledgment of the filings during the first quarter of 2017. The IRP included analysis of different growth scenarios and corresponding resource acquisition strategies. This analysis is needed to develop supply and demand resource requirements, consider uncertainties in the planning process, and to establish a plan for providing reliable and low cost natural gas service.

GAS INCIDENT INVESTIGATION. On October 19, 2016, there was a natural gas explosion in Portland, Oregon after a third-party contractor damaged a NW Natural service line. The contractor was not working for NW Natural. NW Natural and local authorities responded to the event and evacuated the necessary buildings prior to the ignition. There were no fatalities or life-threatening injuries. An investigation is open and being led by the OPUC. NW Natural is assisting the Commission and other authorities with the investigation.

Rate Mechanisms

PURCHASED GAS ADJUSTMENT. Rate changes are established for the utility each year under PGA mechanisms in Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases. This includes gas prices under spot purchases as well as contract supplies, gas prices hedged with financial derivatives, gas prices from the withdrawal of storage inventories, the production of gas reserves, interstate pipeline demand costs, temporary rate adjustments, which amortize balances of deferred regulatory accounts, and the removal of temporary rate adjustments effective for the previous year.

We filed our PGA in September 2016 and received OPUC and WUTC approval in October 2016. PGA rate changes are effective November 1, 2016. The rate changes will decrease the average monthly bills of residential customers by approximately 2.6% and 1.5% in Oregon and Washington, respectively. The decrease in Oregon reflected customers' portion of adjustments for changes in wholesale natural gas costs, offset by adjustments related to the decoupling mechanism, environmental costs, and additional annual adjustments based on ongoing orders with the OPUC. Washington rates reflected the full effect of changes in wholesale natural gas costs.

Each year, we typically hedge gas prices on approximately 75% of our utility's annual sales requirement based on normal weather, including both physical and financial hedges. We entered the 2016-17 gas year (November 1, 2016 - October 31, 2017) and 2015-16 gas year (November 1, 2015 - October 31, 2016) hedged at 75% of our forecasted sales volumes, including 48% and 44% in financial swap and option contracts as well as 27% and 31% in physical gas supplies, respectively.

In addition to the amount hedged for the current gas contract year, as of September 30, 2016, we are hedged in future years at approximately 69% for the 2016-17 gas year and between 4% and 23% for annual requirements over the following five gas years. Our hedge levels are subject to change based on actual load volumes, which depend to a certain extent on weather, economic conditions, and estimated gas reserve production. Also, our storage inventory levels may increase or decrease with storage expansion, changes in storage contracts with third parties, and/orstorage recall by the utility.

Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select each year either an 80% deferral or a 90% deferral of higher or lower actual gas costs compared to estimated PGA prices, such that the impact on current earnings from the incentive sharing is either 20% or 10% of the difference between actual and estimated gas costs, respectively. For the 2015-16 and 2016-2017 gas years, we selected the 80% and 90% deferral option, respectively. Under the Washington PGA mechanism, we defer 100% of the higher or lower actual gas costs, and those gas cost differences are passed on to customers through the annual PGA rate adjustment.

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EARNINGS TEST REVIEW. We are subject to an annual earnings review in Oregon to determine if the utility is earning above its authorized ROE threshold. If utility earnings exceed a specific ROE level, then 33% of the amount above that level is required to be deferred or refunded to customers. Under this provision, if we select the 80% deferral gas cost option, then we retain all of our earnings up to 150 basis points above the currently authorized ROE. If we select the 90% deferral option, then we retain all of our earnings up to 100 basis points above the currently authorized ROE. We selected the 80% deferral option for the 2015-16 PGA year, and we selected the 90% deferral option for the 2016-17 PGA year. The ROE threshold is subject to adjustment annually based on movements in long-term interest rates. For the 2015 calendar year, the ROE threshold was 10.60%. We filed our 2015 earnings test in April of 2016 and it was approved by the Commission in July 2016. As a result, we were not subject to a customer refund adjustment for 2015.

GAS RESERVES.The cost of gas, including a carrying cost for the rate base investment made under the original agreement, is included in our annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our net investment under the original agreement earns a rate of return.

Under our amended agreement with Jonah Energy, we have the option to invest in additional wells on a well-by-well basis with drilling costs and resulting gas volumes shared at our amended proportionate working interest for each well in which we invest. We elected to participate in some of the additional wells drilled in 2014, and may have the opportunity to participate in more wells in the future. Volumes produced from the additional wells drilled in 2014 are included in our Oregon PGA at a fixed rate of $0.4725. See Note 10.

DECOUPLING. In Oregon, we have a decoupling mechanism. Decoupling is intended to break the link between utility earnings and the quantity of gas consumed by customers, removing any financial incentive by the utility to discourage customers’ efforts to conserve energy. The Oregon decoupling mechanism was reauthorized and the baseline expected usage per customer was set in the 2012 Oregon general rate case. This mechanism employs a use-per-customer decoupling calculation, which adjusts margin revenues to account for the difference between actual and expected customer volumes. The margin adjustment resulting from differences between actual and expected volumes under the decoupling component is recorded to a deferral account, which is included in the annual PGA filing. In Washington, customer use is not covered by such a tariff. See "Business Segments—Local Gas Distribution Utility Operations" below.

WEATHER NORMALIZATION TARIFF. In Oregon, we have an approved weather normalization mechanism, which is applied to residential and commercial customer bills. This mechanism is designed to help stabilize the collection of fixed costs by adjusting residential and commercial customer billings based on temperature variances from average weather, with rate decreases when the weather is colder than average and rate increases when the weather is warmer than average. The mechanism is applied to bills from December through May of each heating season. The mechanism adjusts the margin component of customers’ rates to reflect average weather, which uses the 25-year average temperature for each day of the billing period. Daily average temperatures and 25-year average temperatures are based on a set point temperature of 59 degrees Fahrenheit for residential customers and 58 degrees Fahrenheit for commercial customers. This weather normalization mechanism was reauthorized in the 2012 Oregon general rate case without an expiration date. Residential and commercial customers in Oregon are allowed to opt out of theweather normalization mechanism, and as ofSeptember 30, 2016, 9% of total customers had opted out. We do not have a weather normalization mechanism approved for residential and commercial Washington customers, which account for about 11% of total customers. See "Business Segments—Local Gas Distribution Utility Operations" below.

INDUSTRIAL TARIFFS. The OPUC and WUTC have approved tariffs covering utility service to our major industrial customers, including terms, which are intended to give us certainty in the level of gas supplies we need to acquire to serve this customer group. The terms include, among other things, an annual election period, special pricing provisions for out-of-cycle changes, and a requirement that industrial customers complete the term of their service election under our annual PGA tariff.

ENVIRONMENTAL COST DEFERRAL AND SRRM.In Oregon, we have a SRRM through which we track and have the ability to recover prudently incurred past deferred and future environmental remediation costs allocable to Oregon, subject to an earnings test.

The SRRM defines three classes of deferred environmental remediation expense:

• Pre-review - This class of costs represents remediation spend that has not yet been deemed prudent by the OPUC. Carrying costs on these remediation expenses are recorded at our authorized cost of capital. We

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anticipate the prudence review for annual costs and approval of the earnings test prescribed by the OPUC to occur by the third quarter of the following year.

• Post-review - This class of costs represents remediation spend that has been deemed prudent and allowed after applying the earnings test, but is not yet included in amortization. We earn a carrying cost on these amounts at a rate equal to the five-year treasury rate plus 100 basis points.

• Amortization - This class of costs represents amounts included in current customer rates for collection and is generally calculated as one-fifth of the post-review deferred balance. We earn a carrying cost equal to the amortization rate determined annually by the OPUC, which approximates a short-term borrowing rate. We included $10.0 million and $8.4 million of deferred remediation expense approved by the OPUC for collection during the 2016-2017 and 2015-2016 PGA years, respectively.

The SRRM earnings test is an annual review of our adjusted utility ROE compared to our authorized utility ROE, which is currently 9.5%. To apply the earnings test first we must determine what, if any, costs are subject to the test through the following calculation:

Annual spend

Less: $5 million tariff rider⁽¹⁾

          Prior year carry-over⁽²⁾

          $5 million insurance + interest on insurance

Total deferred annual spend subject to earnings test

Less: over-earnings adjustment, if any

Add: deferred interest on annual spend⁽³⁾

Total amount transferred to post-review

⁽¹⁾   Tariff rider went into Oregon customer rates beginning November 1, 2015.

⁽²⁾ Prior year carry-over results when the prior year amount transferred to post-review is negative. The negative amount is carried over to offset annual spend in the following year.

⁽³⁾ Deferred interest is added to annual spend to the extent the spend is recoverable.

If the adjusted utility ROE is greater than the authorized utility ROE, then we could be required to expense amounts in excess of the authorized ROE. For 2015, we have performed this test, which was submitted to the OPUC in April 2016, and have concluded there was no earnings test adjustment for 2015.

The WUTC has also previously authorized the deferral of environmental costs, if any, that are appropriately allocated to Washington customers. This Order was effective in January 2011 with cost recovery and a carrying charge to be determined in a future proceeding.

PENSION COST DEFERRAL AND PENSION BALANCING ACCOUNT. Effective January 1, 2011, the OPUC approved our request to defer annual pension expenses above the amount set in rates, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of higher and lower pension expenses in future years. Our recovery of these deferred balances includes accrued interest on the account balance at the utility’s authorized rate of return, which is currently 7.78%. Future years’ deferrals will depend on changes in plan assets and projected benefit liabilities based on a number of key assumptions, and our pension contributions. Pension expense deferrals, including interest, were $4.8 million and $6.5 million as of September 30, 2016 and 2015, respectively.

GAS STORAGE SHARING AND COST OF GAS CUSTOMER CREDITS. In June of 2016 and 2015, we received regulatory approval to provide an interstate storage credit of $9.4 million and $9.6 million, respectively, to our Oregon utility customers, which was reflected in their June bills. These credits are part of our regulatory incentive sharing mechanism related to non-utility Mist storage and asset management service. The Washington portion of these credits will be included in the Washington PGA.

In June 2016, we credited $19.4 million to customers for their portion of the gas cost sharing incentive for the 2015-2016 gas year, resulting from lower than projected gas costs driven by warmer weather, lower volume usage, and lower market prices.

For a discussion of other rate mechanisms, see Part II, Item 7, "Results of Operations—Regulatory Matters—

"Rate Mechanisms" in our 2015 Form 10-K.

Business Segments - Local Gas Distribution Utility Operations

Utility margin results are primarily affected by customer growth, revenues from rate-base additions, and, to a certain extent, by changes in delivered volumes due to weather and customers’ gas usage patterns because a significant portion of our utility margin is derived from natural gas sales to residential and commercial customers. In Oregon, we have a conservation tariff (also called the decoupling mechanism), which adjusts utility margin up or down each month through a deferred regulatory accounting adjustment designed to offset changes resulting from increases or decreases in average use by residential and commercial customers. We also have a weather normalization tariff in Oregon, which adjusts customer bills up or down to offset changes in utility margin resulting from above- or below-average temperatures during the winter heating season. Both mechanisms are designed to reduce the volatility of customer bills and our utility’s earnings. See "Regulatory Matters—Rate Mechanisms" above.

Utility segment highlights include:  

	Three Months Ended September 30,						Nine Months Ended September 30,
Dollars and therms in thousands, except EPS data	2016			2015			2016		2015		QTR Change			YTD Change
Utility net income (loss)	$	(9,511	)	$	(7,529	)	$	26,848	$	23,051	$	(1,982	)	$	3,797
EPS - utility segment	$	(0.35	)	$	(0.28	)	$	0.97	$	0.84	$	(0.07	)	$	0.13
Gas sold and delivered (in therms)	162,205			154,664			727,687		692,527		7,541			35,160
Utility margin(1)	$	50,923		$	51,619		$	256,958	$	252,935	$	(696	)	$	4,023

⁽¹⁾ See Utility Margin Table below for a reconciliation and additional detail.

THREE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. The primary factors contributing to the $2.0 million or $0.07 per share increase in utility net loss were as follows:

• a $0.7 million decrease in utility margin primarily due to:

▪ lower contributions from our gas reserve investments, which decreased due to regular amortization, and a decrease in gas cost incentive sharing; partially offset by

▪ a $0.5 million increase from residential customer growth.

• a $1.6 million increase in operations and maintenance expense primarily due to an increase in non-payroll costs as a result of cost savings initiatives implemented in the second half of 2015 that did not re-occur in 2016.

NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. The primary factors contributing to the $3.8 millionor $0.13 per share increase in utility net income were as follows:

• a $4.0 million increase in utility margin primarily due to:

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▪ a $3.8 million increase from customer growth and added loads under higher commercial rate schedules;

▪ a$2.2 million increase from gains in gas cost incentive sharing resulting from lower gas prices than those estimated in the PGA; partially offset by

▪ a $1.1 million decrease due to lower contributions from our gas reserve investments, which decreased due to regular amortization; and

▪ a decrease of approximately $1.0 million due to lower customer usage from significantly warmer weather during the second quarter of 2016 than in the prior year, which impacts utility margins from our Washington customers where we do not have a weather normalization mechanism in place and from our Oregon customers who opted out of weather normalization.

• a $12.2 million decrease in operations and maintenance expense primarily due to the $15.0 million regulatory disallowance charge taken in the prior year, partially offset by an increase in non-payroll costs as a result of cost savings initiatives implemented in the second half of 2015 that did not re-occur in 2016; partially offset by

• a $1.1 million increase in depreciation expense primarily due to additional capital expenditures; and

• an $8.3 million decrease in other income (expense), net primarily due to a $2.8 million interest write-off as a result of the 2016 Order from the OPUC in the first quarter of 2016 and the recognition of $5.3 million of equity earnings on deferred regulatory asset balances in February 2015.

Total utility volumes sold and delivered in the three months ended September 30, 2016 increased 5% over the same period in 2015 primarily due to greater customer usage and customer growth. Although weather for the nine months ended September 30, 2016 was comparable to the prior year, deliveries increased 5% due to comparatively colder weather in the first quarter of 2016 during our peak heating season. Temperatures for the first nine months of 2016 and 2015 were 22% warmer than average.

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UTILITY MARGIN TABLE. The following table summarizes the composition of utility gas volumes, revenues, and cost of sales:

	Three Months Ended September 30,							Nine Months Ended September 30,						Favorable/(Unfavorable)
In thousands, except degree day and customer data	2016				2015			2016			2015			QTR Change			YTD Change
Utility volumes (therms):
Residential and commercial sales	55,610				53,662			381,109			357,545			1,948			23,564
Industrial sales and transportation	106,595				101,002			346,578			334,982			5,593			11,596
Total utility volumes sold and delivered	162,205				154,664			727,687			692,527			7,541			35,160
Utility operating revenues:
Residential and commercial sales	$	68,508			$	73,236		$	388,689		$	432,067		$	(4,728	)	$	(43,378	)
Industrial sales and transportation	13,412				15,959			42,048			53,623			(2,547		)	(11,575		)
Other revenues	619				651			3,132			3,188			(32		)	(56		)
Less: Revenue taxes	2,161				2,371			11,252			12,206			(210		)	(954		)
Total utility operating revenues	80,378			—	87,475			422,617			476,672			(7,097		)	(54,055		)
Less: Cost of gas	28,264				35,856			157,546			223,737			7,592			66,191
Less: Environmental remediation expense	1,191				—			8,113			—			(1,191		)	(8,113		)
Utility margin	$	50,923			$	51,619		$	256,958		$	252,935		$	(696	)	$	4,023
Utility margin:(1)
Residential and commercial sales	$	43,050			$	43,312		$	227,422		$	225,624		$	(262	)	$	1,798
Industrial sales and transportation	7,173				7,233			22,458			22,065			(60		)	393
Miscellaneous revenues	616				647			3,119			3,186			(31		)	(67		)
Gain from gas cost incentive sharing	85				431			4,151			1,992			(346		)	2,159
Other margin adjustments	(1		)		(4		)	(192		)	68			3			(260		)
Utility margin	$	50,923			$	51,619		$	256,958		$	252,935		$	(696	)	$	4,023
Degree days
Average(2)	95				95			2,657			2,641			—			16
Actual	78				75			2,066			2,068			4		%	—		%
Percent colder (warmer) than average weather(2)	(18		)%		(21		)%	(22		)%	(22		)%
	As of September 30,
Customers - end of period:	2016				2015			Change			% Change
Residential customers	650,950				640,313			10,637			1.7		%
Commercial customers	66,174				65,305			869			1.3		%
Industrial customers	1,015				948			67			7.1		%
Total number of customers	718,139				706,566			11,573			1.6		%

⁽¹⁾  Amounts reported as margin for each category of customers are operating revenues, which are net of revenue taxes, less cost of gas and environmental remediation expense.

⁽²⁾  Average weather represents the 25-year average degree days, as determined in our 2012 Oregon general rate case.

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Residential and Commercial Sales

Residential and commercial sales highlights include:

	Three Months Ended September 30,						Nine Months Ended September 30,
In thousands	2016			2015			2016			2015		QTR Change			YTD Change
Volumes (therms):
Residential sales	29,820			28,303			232,121			215,018		1,517			17,103
Commercial sales	25,790			25,359			148,988			142,527		431			6,461
Total volumes	55,610			53,662			381,109			357,545		1,948			23,564
Operating revenues:
Residential sales	$	43,102		$	44,721		$	257,401		$	281,033	$	(1,619	)	$	(23,632	)
Commercial sales	25,406			28,515			131,288			151,034		(3,109		)	(19,746		)
Total operating revenues	$	68,508		$	73,236		$	388,689		$	432,067	$	(4,728	)	$	(43,378	)
Utility margin:
Residential:
Sales	$	27,943		$	27,647		$	145,033		$	138,187	$	296		$	6,846
Weather normalization	—			—			13,966			12,492		—			1,474
Decoupling	1,325			1,149			(834		)	5,318		176			(6,152		)
Total residential utility margin	29,268		—	28,796			158,165			155,997		472			2,168
Commercial:
Sales	12,472			12,736			58,370			56,997		(264		)	1,373
Weather normalization	—			(2		)	5,483			5,213		2			270
Decoupling	1,310			1,782			5,404			7,417		(472		)	(2,013		)
Total commercial utility margin	13,782			14,516			69,257			69,627		(734		)	(370		)
Total utility margin	$	43,050		$	43,312		$	227,422		$	225,624	$	(262	)	$	1,798

THREE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. The primary factors contributing to changes in the residential and commercial markets were as follows:

• sales volumes increased 1.9 milliontherms, or4%, primarily due to customer usage and growth;

• operating revenues decreased $4.7 milliondue to a 20% decrease in average cost of gas over last year offset by a 4% increase in sales volumes; and

• utility margin decreased $0.3 million primarily due to lower contributions from our gas reserve investments, which decreases due to regular amortization, offset by residential growth.

NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. The primary factors contributing to changes in the residential and commercial markets were as follows:

• sales volumes increased 23.6 million therms, or7%, primarily due to colder weather in the first quarter of 2016 compared to record warm weather in 2015 and customer growth;

• operating revenues decreased $43.4 million due to a 32% decrease in average cost of gas over last year partially offset by a 7% increase in sales volumes; and

• utility margin increased $1.8 million due to both residential and commercial customer growth offset by lower contributions from our gas reserve investments, which decreases due to regular amortization.

Industrial Sales and Transportation

Industrial customers have the option of purchasing sales or transportation services from the utility. Under the sales service, the customer buys the gas commodity from the utility. Under the transportation service, the customer buys the gas commodity directly from a third-party gas marketer or supplier. Our gas commodity cost is primarily a pass-through cost to customers; therefore, our profit margins are not materially affected by an industrial customer's decision to purchase gas from us or from third parties. Industrial and large commercial customers may also select between firm and interruptible service options, with firm services generally providing higher profit margins compared to interruptible services. To help manage gas supplies, our industrial tariffs are designed to provide some certainty regarding industrial customers' volumes by requiring an annual service election on November 1, special charges for changes between elections, and in some cases, a minimum or maximum volume requirement before changing options. 

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Industrial sales and transportation highlights include:

	Three Months Ended September 30,				Nine Months Ended September 30,
In thousands	2016		2015		2016		2015		QTR Change			YTD Change
Volumes (therms):
Industrial - firm sales	7,817		7,352		24,363		23,308		465			1,055
Industrial - firm transportation	32,737		29,149		112,456		104,773		3,588			7,683
Industrial - interruptible sales	9,902		5,423		36,274		42,668		4,479			(6,394		)
Industrial - interruptible transportation	56,139		59,078		173,485		164,233		(2,939		)	9,252
Total volumes	106,595		101,002		346,578		334,982		5,593			11,596
Utility margin:
Industrial - firm and interruptible sales	$	2,703	$	3,259	$	8,479	$	9,641	(556		)	(1,162		)
Industrial - firm and interruptible transportation	4,470		3,974		13,979		12,424		496			1,555
Industrial - sales and transportation	$	7,173	$	7,233	$	22,458	$	22,065	$	(60	)	$	393

THREE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Industrial sales and transportation volumes increased by 5.6 milliontherms, or 6%, while utility margin decreased $0.1 milliondue to higher customer usage on lower margin rate schedules.

NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Industrial sales and transportation volumes increased by 11.6 million therms, or 3%, and utility margin increased $0.4 million due to annual customer service election changes and an increase in usage from a few large customers.

Cost of Gas

Cost of gas as reported by the utility includes gas purchases, gas withdrawn from storage inventory, gains and losses from commodity hedges, pipeline demand costs, seasonal demand cost balancing adjustments, regulatory gas cost deferrals, gas reserves costs, and company gas use. The OPUC and WUTC generally require natural gas commodity costs to be billed to customers at the actual cost incurred, or expected to be incurred, by the utility. Customer rates are set each year so that if cost estimates were met we would not earn a profit or incur a loss on gas commodity purchases; however, in Oregon we have an incentive sharing mechanism which has been described under "Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment" above. In addition to the PGA incentive sharing mechanism, gains and losses from hedge contracts entered into after annual PGA rates are effective for Oregon customers are also required to be shared and therefore may impact net income. Further, we also have a regulatory agreement whereby we earn a rate of return on our investment in the gas reserves acquired under the original agreement with Encana and include gas from our amended gas reserves agreement at a fixed rate of $0.4725 per therm, which are also reflected in utility margin.See "Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities" in our 2015 Form 10-K.

Cost of gas highlights include:

	Three Months Ended September 30,				Nine Months Ended September 30,
Dollars and therms in thousands	2016		2015		2016		2015		QTR Change			YTD Change
Cost of gas	$	28,264	$	35,856	$	157,546	$	223,737	$	(7,592	)	$	(66,191	)
Volumes sold (therms)(1)	73,329		73,028		441,746		423,521		301			18,225
Average cost of gas (cents per therm)	$	0.39	$	0.49	$	0.36	$	0.53	$	(0.10	)	$	(0.17	)
Gain from gas cost incentive sharing(2)	85		431		4,151		1,992		(346		)	2,159

⁽¹⁾  This calculation excludes volumes delivered to transportation only customers.

⁽²⁾  For a discussion of our gas cost incentive sharing mechanism, see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment” above.

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THREE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Cost of gas decreased $7.6 million, or 21%, primarily due to a 20% decrease in average cost of gas reflecting lower market prices for natural gas.

NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Cost of gas decreased $66.2 million, or 30%, primarily due to a 32% decrease in average cost of gas reflecting the $19.4 million credit to customers and lower market prices for natural gas, partially offset by a 4% increase in volumes mainly from comparatively colder weather in the first quarter of 2016.

Business Segments - Gas Storage

Our gas storage segment primarily consists of the non-utility portion of our Mist underground storage facility in Oregon and our 75% undivided ownership interest in the Gill Ranch underground storage facility in California. We also contract with an independent energy marketing company to provide asset management services using our utility and non-utility storage and transportation capacity, the results of which are included in the gas storage businesses segment.

Gas storage segment highlights include:

	Three Months Ended September 30,				Nine Months Ended September 30,
In thousands, except EPS data	2016		2015		2016		2015		QTR Change		YTD Change
Gas storage net income	$	1,813	$	799	$	3,988	$	827	$	1,014	$	3,161
EPS - gas storage segment	0.06		0.04		0.14		0.04		0.02		0.10
Operating revenues	7,293		5,596		19,654		16,232		1,697		3,422
Operating expenses	3,791		3,392		11,547		12,234		399		(687		)

THREE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Our gas storage segment net income increased $1.0 million primarily due to a $1.7 million increase in revenue from asset management agreements at both facilities but predominately at our Mist storage facility, and higher firm contract prices at our Gill Ranch facility for the 2016-17 gas year. This was partially offset by higher operating expenses of $0.4 million primarily due to higher maintenance costs.

NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Our gas storage segment net income increased $3.2 millionprimarily due to a $3.4 million increase in revenue from asset management agreements at both facilities but predominately at our Mist storage facility, and higher firm contract prices at our Gill Ranch facility for the 2016-17 gas year. Further, operating expenses decreased $0.7 million from lower power costs at our Gill Ranch facility and lower general and administrative expenses. In addition, interest expense decreased $1.1 million from the early retirement of $20 million of Gill Ranch debt in December of 2015.

Our Mist gas storage facility benefits from limited competition from other Pacific Northwest storage facilities primarily because of its geographic location. Over the past few years, market prices for natural gas storage, particularly in California, were negatively affected by the abundant supply of natural gas, low volatility of natural gas prices, and surplus gas storage capacity. We have completed our contracting for the 2016-17 gas storage year and have seen a slight improvement in pricing compared to the 2015-16 gas storage year.

Though prices for the 2015-16 and 2016-17 gas years have shown slight improvement at our Gill Ranch facility, they remain low relative to the pricing in our original long-term contracts, which ended primarily in the 2013-14 gas storage year. In the future, we may see continued price improvement or an increase in the demand for natural gas driven by a number of factors, including changes in electric generation triggered by California's renewable portfolio standards, an increase in use of alternative fuels to meet carbon emission reduction targets, recovery of the California economy, growth of domestic industrial manufacturing, potential exports of liquefied natural gas from the west coast, and other favorable storage market conditions in and around California. These factors, if they occur, may contribute to higher summer/winter natural gas price spreads, gas price volatility, and gas storage values. We continue to explore opportunities to increase revenues by identifying higher value customers to provide with enhanced services and also seek to capitalize on opportunities that fit our business-risk profile.

In October 2015 a significant natural gas leak occurred at an unaffiliated southern California gas storage facility that persisted in early 2016. At this time, we do not know the long-term effects of this incident on gas storage prices. In

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September 2016, legislation was passed and signed into law by the Governor of California in response to the incident, which directed the California Department of Oil, Gas and Geothermal Resources to develop regulations for gas storage wells. While the regulations are still under development, and their ultimate impact is unknown, it is likely the pending regulations will result in higher costs for all storage providers. The potential costs of compliance could include one-time capital expenditures and/or ongoing operations and maintenance costs. As a result of the legislation and pending regulations, the nature of, and demand for, future storage contracts, as well as market values in California could be impacted and remain uncertain at this time.

If such new regulation and legislation require significant capital and on-going spending to upgrade or maintain the facility, we are unsuccessful in identifying new higher value customers, future storage values do not improve, an increased demand and other favorable market correlations for natural gas storage does not materialize, and/or volatility does not return to the gas storage market, this could have a negative impact on our future cash flows and could result in impairment of our Gill Ranch gas storage facility, which had a net book value of $197.9 million at September 30, 2016. The Company continues to assess these conditions along with other strategic alternatives and their impact on the value of the asset on an ongoing basis. Refer to Note 2 in our 2015 Form 10-K for more information regarding our accounting policy for impairment of long-lived assets.

Other

Other primarily consists of NNG Financial's equity investment in KB Pipeline, an equity investment in TWH, which has invested in the Trail West pipeline project, and other miscellaneous non-utility investments and business activities. There were no significant changes in our other activities during the three and nine months endedSeptember 30, 2016. See Note 4 and Note 11 for further details on other activities and our investment in TWH.

Consolidated Operations

Operations and Maintenance

Operations and maintenance highlights include:

	Three Months Ended September 30,				Nine Months Ended September 30,
In thousands	2016		2015		2016		2015		QTR Change		YTD Change
Operations and maintenance	$	34,870	$	32,031	$	109,771	$	121,458	$	2,839	$	(11,687	)

THREE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Operations and maintenance expense increased $2.8 million, primarily due to a $2.0 million increase in non-payroll costs mostly from higher contract work as utility operational expenses increased mainly from the timing of system integrity work and other maintenance expense. Both of these variances reflect the Company resuming costs to a more sustainable level in 2016 after implementing cost savings initiatives in the second half of 2015.

NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Operations and maintenance expense decreased $11.7 million, primarily due to the following factors:

• the $15 million pre-tax charge for the regulatory disallowance associated with the February 2015 OPUC Order on the recovery of past environmental cost deferrals recorded in 2015. We also expensed an additional $1 million related to the 2015 Order; partially offset by

• a $3.7 million increase in non-payroll costs to a more sustainable level in 2016, as noted above, reflecting increases in professional services and contract work; and

• a $0.5 million pre-tax charge related to the reserve for the state allocation of environmental sites based on the 2016 Order.

Delinquent customer receivable balances continue to remain at historically low levels. The utility's annualized bad debt expense as a percent of revenues was 0.1% for the nine months ended September 30, 2016 and 2015.

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Other Income (Expense), Net

Other income (expense), net highlights include:

	Three Months Ended September 30,				Nine Months Ended September 30,
In thousands	2016		2015		2016			2015		QTR Change			YTD Change
Other income (expense), net	$	652	$	746	$	(1,144	)	$	6,930	$	(94	)	$	(8,074	)

THREE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Other income (expense), net remained relatively consistent quarter-over-quarter.

NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Other income (expense), net decreased $8.1 million primarily due to the recognition of $5.3 million of the equity component in interest income from our deferred environmental expenses in the prior year, which did not recur in 2016. We recognized the equity earnings of these deferred regulatory asset balances as a result of the OPUC SRRM Order we received in February 2015. In addition, a subsequent Order from the OPUC in the first quarter of 2016 resulted in a write-off of $2.8 million of interest in 2016.

Interest Expense, Net

Interest expense, net highlights include:

	Three Months Ended September 30,				Nine Months Ended September 30,
In thousands	2016		2015		2016		2015		QTR Change			YTD Change
Interest expense, net	$	9,729	$	10,111	$	29,183	$	31,030	$	(382	)	$	(1,847	)

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Interest expense, net of amounts capitalized, decreased $0.4 million for the quarter and $1.8 million for the nine month period primarily due to the redemption of $40 million of utility First Mortgage Bonds (FMBs) in June 2015 and the early retirement of $20 million of Gill Ranch debt in December 2015.

Income Tax Expense

Income tax expense highlights include:

	Three Months Ended September 30,						Nine Months Ended September 30,
In thousands	2016			2015			2016		2015		QTR Change			YTD Change
Income tax expense (benefit)	$	(5,474	)	$	(4,553	)	$	21,294	$	15,944	$	(921	)	$	5,350

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. Increases or decreases in income tax expense (benefit) are correlated with changes in pre-tax income. Additionally, income tax expense during the nine months ended September 30, 2016, as compared to 2015, was higher as 2015 benefited from the realization of deferred depletion benefits from 2013 and 2014.

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FINANCIAL CONDITION

Capital Structure

One of our long-term goals is to maintain a strong consolidated capital structure, generally consisting of 45% to 50% common stock equity and 50% to 55% long-term and short-term debt, and with a target utility capital structure of 50% common stock and 50% long-term debt. When additional capital is required, debt or equity securities are issued depending on both the target capital structure and market conditions. These sources of capital are also used to fund long-term debt retirements and short-term commercial paper maturities. See "Liquidity and Capital Resources" below and Note 6.

Achieving the target capital structure and maintaining sufficient liquidity to meet operating requirements are necessary to maintain attractive credit ratings and provide access to capital markets at reasonable costs. Our consolidated capital structure was as follows:

	September 30,				December 31,
	2016		2015		2015
Common stock equity(1)	49.6	%	47.5	%	47.5	%
Long-term debt(1)	33.8		38.4		34.6
Short-term debt, including current maturities of long-term debt	16.6		14.1		17.9
Total	100.0	%	100.0	%	100.0	%

⁽¹⁾  Ratios reflect debt balances net of any unamortized debt issuance costs.

Liquidity and Capital Resources

At September 30, 2016 we had $6.2 million of cash and cash equivalents compared to $5.2 million at September 30, 2015. We did not have restricted cash at September 30, 2016 compared to $4.5 million in restricted cash at September 30, 2015 held as collateral for the long-term debt outstanding at Gill Ranch, which we retired in December 2015. In order to maintain sufficient liquidity during periods when capital markets are volatile, we may elect to maintain higher cash balances and add short-term borrowing capacity. In addition, we may also pre-fund utility capital expenditures when long-term fixed rate environments are attractive. As a regulated entity, our issuance of equity securities and most forms of debt securities are subject to approval by the OPUC and WUTC. Our use of retained earnings is not subject to those same restrictions.

Utility Segment

For the utility segment, the short-term borrowing requirements typically peak during colder winter months when the utility borrows money to cover the lag between natural gas purchases and bill collections from customers. Our short-term liquidity for the utility is primarily provided by cash balances, internal cash flow from operations, proceeds from the sale of commercial paper notes, as well as available cash from multi-year credit facilities, short-term credit facilities, company-owned life insurance policies, and the sale of long-term debt. Utility long-term debt proceeds are primarily used to finance utility capital expenditures, refinance maturing debt of the utility, and provide temporary funding for other general corporate purposes of the utility. 

Based on our current debt ratings (see "Credit Ratings" below), we have been able to issue commercial paper and long-term debt at attractive rates and have not needed to borrow or issue letters of credit from our back-up credit facility. In the event we are not able to issue new debt due to adverse market conditions or other reasons, we expect our near-term liquidity needs can be met using internal cash flows or, for the utility segment, drawing upon our committed credit facility. We also have a universal shelf registration statement filed with the SEC for the issuance of secured and unsecured debt or equity securities, subject to market conditions, satisfaction of debt instrument requirement, and certain regulatory approvals. As of September 30, 2016, we have Board authorization to issue up to $325 million of additional FMBs. We also have OPUC approval to issue up to $325 million of additional long-term debt for approved purposes.

In the event our senior unsecured long-term debt ratings are downgraded, or our outstanding derivative position exceeds a certain credit threshold, our counterparties under derivative contracts could require us to post cash, a letter of credit, or other forms of collateral, which could expose us to additional cash requirements and may trigger increases in short-term borrowings while we were in a net loss position. We were not near the threshold for posting collateral at September 30, 2016. However, if the credit risk-related contingent features underlying these contracts were triggered on September 30, 2016, assuming our long-term debt ratings dropped to non-investment grade

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levels, we could have been required to post $1.2 million of collateral to our counterparties. See "Credit Ratings" below and Note 12.

Other items that may have a significant impact on our liquidity and capital resources include pension contribution requirements and environmental expenditures.

With respect to pensions, we expect to make significant contributions to our company-sponsored defined benefit plan, which is closed to new employees, over the next several years until we are fully funded under the Pension Protection Act rules, including the new rules issued under the Moving Ahead for Progress in the 21st Century Act (MAP-21) and the Highway and Transportation Funding Act of 2014 (HATFA). See "Application of Critical Accounting Policies—Accounting for Pensions and Postretirement Benefits" in the 2015 Form 10-K.

Gas Storage

Short-term liquidity for the gas storage segment is supported by cash balances, internal cash flow from operations, equity contributions from its parent company, and, if necessary, additional external financing.

The amount and timing of our Gill Ranch facility's cash flows from year to year are uncertain, as the majority of these storage contracts are currently short-term. We have seen slightly higher contract prices for the 2015-16 and 2016-17 storage years, but overall prices are still lower than the long-term contracts that expired at the end of the 2013-14 storage year. While we expect continuing challenges for Gill Ranch in 2016, we do not anticipate material changes in our ability to access sources of cash for short-term liquidity.

Consolidated

Based on several factors, including our current credit ratings, our commercial paper program, current cash reserves, committed credit facilities, and our expected ability to issue long-term debt in the capital markets, we believe our liquidity is sufficient to meet anticipated near-term cash requirements, including all contractual obligations, investing, and financing activities discussed below.

Short-Term Debt

Our primary source of utility short-term liquidity is from the sale of commercial paper and bank loans. In addition to issuing commercial paper or bank loans to meet working capital requirements, including seasonal requirements to finance gas purchases and accounts receivable, short-term debt may also be used to temporarily fund utility capital requirements. Commercial paper and bank loans are periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by one or more unsecured revolving credit facilities. See “Credit Agreements” below.

At September 30, 2016 and 2015, our utility had short-term debt outstanding of $194.9 million and $225.2 million, respectively. The effective interest rate on short-term debt outstanding at September 30, 2016 and 2015 was 0.7% and 0.4%, respectively.

Credit Agreements

We have a $300 million credit agreement, with a feature that allows us to request increases in the total commitment amount, up to a maximum of $450 million. The maturity date of the agreement is December 20, 2019.

All lenders under the agreement are major financial institutions with committed balances and investment grade credit ratings as of September 30, 2016 as follows:

Lender rating, by category, in millions	Loan Commitment
AA/Aa	$	234
A/A1	66
Total	$	300

Based on credit market conditions, it is possible one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency; however, we do not believe this risk to be imminent due to the lenders' strong investment-grade credit ratings.

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Our credit agreement permits the issuance of letters of credit in an aggregate amount of up to $100 million. Any principal and unpaid interest amounts owed on borrowings under the credit agreement is due and payable on or before the maturity date. There were no outstanding balances under this credit agreement at September 30, 2016 or 2015. The credit agreement requires us to maintain a consolidated indebtedness to total capitalization ratio of 70% or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at September 30, 2016 and 2015, with consolidated indebtedness to total capitalization ratios of 50.3% and 52.5%, respectively.

The agreement also requires us to maintain credit ratings with Standard & Poor's (S&P) and Moody's Investors Service, Inc. (Moody’s) and notify the lenders of any change in our senior unsecured debt ratings or senior secured debt ratings, as applicable, by such rating agencies. A change in our debt ratings by S&P or Moody’s is not an event of default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon the credit agreement. Rather, interest rates for any loans outstanding and commitment fees under the credit agreements are tied to debt ratings and therefore, a change in the debt rating would increase or decrease the cost of any loans under the credit agreements when ratings are changed. See "Credit Ratings" below.

Credit Ratings

Our credit ratings are a factor of our liquidity, potentially affecting our access to the capital markets including the commercial paper market. Our credit ratings also have an impact on the cost of funds and the need to post collateral under derivative contracts. The following table summarizes our current debt ratings:

	S&P	Moody's
Commercial paper (short-term debt)	A-1	P-2
Senior secured (long-term debt)	AA-	A1
Senior unsecured (long-term debt)	n/a	A3
Corporate credit rating	A+	n/a
Ratings outlook	Stable	Stable

The above credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of or reference to these credit ratings is not a recommendation to buy, sell or hold NW Natural securities. Each rating should be evaluated independently of any other rating.

Maturity and Redemption of Long-Term Debt

We did not retire any long-term debt in the first nine months of 2016. Over the next twelve months, we expect to redeem the following long-term debt issuances:

• $25 million of FMBs with a coupon rate of 5.15% will be redeemed at maturity in December 2016; and

• $40 million of FMBs with a coupon rate of 7.00% will be redeemed at maturity in August 2017.

See Part II, Item 7, "Financial Condition—Contractual Obligations" in our 2015 Form 10-K for a schedule of long-term debt maturing over the next five years.

Cash Flows

Operating Activities

Changes in our operating cash flows are primarily affected by net income, changes in working capital requirements, and other cash and non-cash adjustments to operating results.

Operating activity highlights include:

	Nine Months Ended September 30,
In thousands	2016		2015		YTD Change
Cash provided by operating activities	$	206,399	$	172,745	$	33,654

NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. The significant factors contributing to the $33.7 million increase in operating cash flows were as follows:

• a net increase of $25.8 million from changes in working capital related to receivables, inventories and accounts payable reflecting lower gas prices in 2016 compared to 2015;

• an increase of $18.6 million primarily due to a federal tax refund and an increase in net deferred tax liabilities primarily due to the enactment of bonus depreciation; and

• an increase of $18.0 from increased cash collections from our decoupling mechanism; and

• an increase of $8.1 million from collections under the SRRM; partially offset by

• a decrease of $37.5 million from changes in deferred gas cost balances primarily due to the early refund of gas cost savings credited to customers in June 2016.

The non-cash qualified defined benefit pension expense recognized on the income statement for the nine months ended September 30, 2016 was $4.0 million, compared to $4.2 million for the same period in 2015. Changes in pension expense are mitigated by our balancing account in Oregon; and therefore, net non-cash pension expenses are expected to remain relatively flat in the coming years.

During the nine months ended September 30, 2016, we contributed $11.3 million to our utility's qualified defined benefit pension plan, compared to $11.8 million for the same period in 2015. The amount and timing of future contributions will depend on market interest rates and investment returns on the plans’ assets. See Note 7.

Bonus income tax depreciation for 2014 and 2015 was not enacted until December 19, 2014 and December 18, 2015, respectively. In both cases it was extended retroactively back to January 1 of the respective year. As a result, estimated income tax payments were made throughout 2014 and 2015 without the benefit of bonus depreciation for the year. This delayed the cash flow benefit of bonus depreciation until refunds could be requested and received. We received refunds of federal income tax overpayments of $7.9 million and $2.0 million in the first quarter of 2016 and the second quarter of 2015, respectively.

The final tangible property regulations applicable to all taxpayers were issued on September 13, 2013 and are generally effective for taxable years beginning on or after January 1, 2014. In addition, procedural guidance related to the regulations was issued under which taxpayers may make accounting method changes to comply with the regulations. We have evaluated the regulations and do not anticipate any material impact. However, unit-of-property guidance applicable to natural gas distribution networks has not yet been issued and is expected in the near future. We will further evaluate the effect of these regulations after this guidance is issued, but believe our current method is materially consistent with the new regulations.

Ballot Measure 97 (Measure 97) was certified by the Oregon Secretary of State’s office in June of 2016 to appear on the November 8, 2016 statewide ballot. If the initiative passes in November, it would become enacted law in the fourth quarter of 2016, and would be effective for the Company’s tax year beginning January 1, 2017.

Under Measure 97, C corporations with Oregon gross receipts greater than $25 million will have a new minimum tax rate applied of 2.5% on gross receipts above $25 million. The income tax rate of 7.6% for taxable income above $1 million remains unchanged.

Oregon C corporations will continue to calculate both the state income tax, and the state corporate minimum gross receipts tax, and then pay the higher of the two each year. For NW Natural, the new Oregon minimum tax is expected to be substantially higher than the income tax going forward.

Specific changes in ratemaking as a result of changes in the state corporate tax structure are difficult to predict. We do expect that the OPUC will treat the gross receipts tax similar to other taxes and allow for recovery. We continue to evaluate the effect this proposed legislation would have on our consolidated financial position and results of operations, if enacted into law.

The Clean Air Rule (CAR) was enacted by the state of Washington's Department of Ecology on September 15, 2016. The Washington rule caps the maximum greenhouse gas emissions allowed from stationary sources such as large manufacturers, as well as petroleum producers and natural gas utilities. Entities that exceed the limit must reduce their emissions, develop projects that would reduce emissions or purchase emission reduction units or renewable credits. We filed legal action jointly with Avista Corporation, Cascade Natural Gas Corp. and Puget Sound Energy in late September to challenge the Washington rule and we are currently pursuing regulatory recovery of such costs and therefore, do not expect this rule to materially affect our consolidated financial position and results of operations.

We have lease and purchase commitments relating to our operating activities that are financed with cash flows from operations. For information on cash flow requirements related to leases and other purchase commitments, see “Financial Condition—Contractual Obligations” and Note 14 in the 2015 Form 10-K.

Investing Activities

Investing activity highlights include:

	Nine Months Ended September 30,
In thousands	2016			2015			YTD Change
Total cash used in investing activities	$	(95,243	)	$	(88,242	)	$	(7,001	)
Capital expenditures	(98,111		)	(86,923		)	(11,188		)
Non-recurring cash outflows	2,868			(1,319		)	$	4,187

NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. The $7.0 million increase in cash used in investing activities was primarily due to higher utility capital expenditures, partially offset by non-recurring cash outflows from investments in gas reserves, restricted cash, and other items in the prior year.

Over the five-year period 2016 through 2020, total utility capital expenditures are estimated to be between $850 million and $950 million. This range includes the estimated cost of our North Mist gas storage facility expansion, which is approximately $128 million. As of September 30, 2016, we have invested $14 million in the expansion and expect to spend an additional $8 million to $10 million in the fourth quarter of 2016. The majority of capital expenditures, $80 million to $90 million, are expected in 2017, with the asset being placed into service during the winter of 2018-19. In addition, the five-year capital expenditure range also includes $25 million related to the refurbishments of an existing liquefied natural gas facility in Oregon through 2018, and $25 million to upgrade distribution infrastructure in Clark County, Washington through 2020. The estimated level of utility capital expenditures through 2020 reflects assumptions for continued customer growth, technology investments, distribution system maintenance and improvements, and gas storage facilities maintenance. Most of the required funds are expected to be internally generated over the five-year period, and any remaining funding will be obtained through a combination of long-term debt and equity security issuances, with short-term debt and bridge financing providing liquidity.

In 2016, utility capital expenditures are estimated to be between $155 million and $175 million, which includes $10 million to $15 million for our Mist expansion project, and non-utility capital investments are estimated to be less than $5 million. Gas storage segment capital expenditures in 2016 are expected to be paid from working capital and additional equity contributions from NW Natural as needed.

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Financing Activities

Financing activity highlights include:

	Nine Months Ended September 30,
In thousands	2016			2015			YTD Change
Total cash used in financing activities	$	(109,137	)	$	(88,810	)	$	(20,327	)
Change in short-term debt	(75,135		)	(9,500		)	(65,635		)
Change in long-term debt	—			(40,000		)	40,000

NINE MONTHS ENDED SEPTEMBER 30, 2016 COMPARED TO SEPTEMBER 30, 2015. The $20.3 million increase in cash used in financing activities was primarily due to higher repayments of short term loans and commercial paper of $65.6 million during the nine months ended September 30, 2016. Partially offsetting the increase was repayment of long-term debt, for which we used $40.0 million in cash during the nine months ended September 30, 2015.

Ratios of Earnings to Fixed Charges

For the nine and twelve months ended September 30, 2016 and the twelve months ended December 31, 2015, our ratios of earnings to fixed charges, computed using the method outlined by the SEC, were 2.67, 3.36, and 3.00, respectively. For this purpose, earnings consist of net income before income taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income. See Exhibit 12 for the detailed ratio calculation.

Contingent Liabilities

Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies. See “Application of Critical Accounting Policies and Estimates” in our 2015 Form 10-K. At September 30, 2016, our total estimated liability related to environmental sites is $117.5 million. See Note 13 and "Results of Operations—Regulatory Matters—Rate Mechanisms—Environmental Costs".

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APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES

In preparing our financial statements in accordance with GAAP, management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and related disclosures in the financial statements. Management considers our critical accounting policies to be those which are most important to the representation of our financial condition and results of operations and which require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if we reported under different conditions or used different assumptions. Our most critical estimates and judgments include accounting for:

• regulatory accounting;

• revenue recognition;

• derivative instruments and hedging activities;

• pensions and postretirement benefits;

• income taxes;

• environmental contingencies; and

• impairment of long-lived assets.

There have been no material changes to the information provided in the 2015 Form 10-K with respect to the application of critical accounting policies and estimates (see Part II, Item 7, "Application of Critical Accounting Policies and Estimates," in the 2015 Form 10-K).

Management has discussed its current estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board. Within the context of our critical accounting policies and estimates, management is not aware of any reasonably likely events or circumstances that would result in materially different amounts being reported. For a description of recent accounting pronouncements that could have an impact on our financial condition, results of operations or cash flows, see Note 2.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including commodity supply risk, commodity price and storage value risk, interest rate risk, foreign currency risk, credit risk, and weather risk. We monitor and manage these financial exposures as an integral part of our overall risk management program. No material changes have occurred related to our disclosures about market risk for the nine month period ended September 30, 2016. See Part II, Item 1A, “Risk Factors” in this report and Part II, Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” in the 2015 Form 10-K for details regarding these risks.

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has completed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)). Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us and included in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission (SEC) rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f).

There have been no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. The statements contained in Exhibit 31.1 and Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this Item 4(b).

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Other than the proceedings disclosed in Note 13 and those proceedings disclosed and incorporated by reference in Part I, Item 3, “Legal Proceedings” in our 2015 Form 10-K, we have only routine nonmaterial litigation that occurs in the ordinary course of our business.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors discussed in Part I, Item 1A, "Risk Factors” in our 2015 Form 10-K. In addition to the other information set forth in this report, you should carefully consider those risk factors, which could materially affect our business, financial condition or results of operations.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table provides information about purchases of our equity securities that are registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended, during the quarter ended September 30, 2016:

Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2)	Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(2)
Balance forward				2,124,528	$	16,732,648
07/01/16-07/31/16	550	$	64.77	—	—
08/01/16-08/31/16	16,094	63.35		—	—
09/01/16-09/30/16	960	59.11		—	—
Total	17,604	63.16		2,124,528	$	16,732,648

⁽¹⁾  During the quarter ended September 30, 2016, 16,484 shares of our common stock were purchased on the open market to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan. In addition, 1,120 shares of our common stock were purchased on the open market to meet the requirements of our share-based programs. During the quarter ended September 30, 2016, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.

⁽²⁾  We have a common stock share repurchase program under which we purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 31, 2017 to repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million. During the quarter ended September 30, 2016, no shares of our common stock were repurchased pursuant to this program. Since the program’s inception in 2000, we have repurchased approximately 2.1 million shares of common stock at a total cost of approximately $83.3 million.

ITEM 6. EXHIBITS

See Exhibit Index attached hereto. 

46

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.

NORTHWEST NATURAL GAS COMPANY

(Registrant)

Dated:	November 2, 2016
		/s/ Brody J. Wilson
		Brody J. Wilson
		Chief Financial Officer, Treasurer, Chief Accounting Officer and
		Controller

47

NORTHWEST NATURAL GAS COMPANY

Exhibit Index to Quarterly Report on Form 10-Q

For the Quarter Ended September 30, 2016

Exhibit Number	Document
4.1	Twenty-Second Supplemental Indenture, providing for, among other things, amendments to the Mortgage, dated as of November 1, 2016, by and between Northwest Natural Gas Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) as Corporate Trustee under the Mortgage and Deed of Trust, dated as of July 1, 1946, of Portland Gas & Coke Company (now Northwest Natural Gas Company).
10.1	Form of Special Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan between the Company and an executive officer, dated as of September 30, 2016.
12	Statement re computation of ratios of earnings to fixed charges.
31.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.	The following materials from Northwest Natural Gas Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2016, formatted in Extensible Business Reporting Language (XBRL): (i) Consolidated Statements of Income; (ii) Consolidated Balance Sheets; (iii) Consolidated Statements of Cash Flows; and (iv) Related notes.

48

EX-4.1

=====================================================================

NORTHWEST NATURAL GAS COMPANY

TO

DEUTSCHE BANK TRUST COMPANY AMERICAS

(FORMERLY KNOWN AS BANKERS TRUST COMPANY),

As Corporate Trustee under the Mortgage and Deed of Trust,

dated as of July 1, 1946, of Portland Gas & Coke Company

(now Northwest Natural Gas Company)

TWENTY-SECOND SUPPLEMENTAL INDENTURE

PROVIDING, AMONG OTHER THINGS, FOR

AMENDMENTS TO THE MORTGAGE

_____________________

DATED AS OF NOVEMBER 1, 2016

=====================================================================

TWENTY-SECOND SUPPLEMENTAL INDENTURE

INDENTURE, dated as of the 1st day of November, 2016, made and entered into by and between NORTHWEST NATURAL GAS COMPANY (formerly Portland Gas & Coke Company), an Oregon corporation, with offices at One Pacific Square, 220 N.W. Second Avenue, Portland, Oregon 97209 (hereinafter sometimes called the Company), and DEUTSCHE BANK TRUST COMPANY AMERICAS (formerly known as BANKERS TRUST COMPANY), a New York banking corporation, with offices at 60 Wall Street, 27th Floor, New York, New York 10005 (hereinafter sometimes called the Corporate Trustee or the Trustee), as Trustee under the Mortgage and Deed of Trust, dated as of July 1, 1946 (hereinafter called the Mortgage), executed and delivered by Portland Gas & Coke Company (now Northwest Natural Gas Company) to secure the payment of bonds issued or to be issued under and in accordance with the provisions of the Mortgage, this indenture (hereinafter called Twenty-second Supplemental Indenture) being supplemental thereto;

WHEREAS the Mortgage was or is to be recorded in the official records of various counties in the States of Oregon and Washington which counties include or will include all counties in which this Twenty-second Supplemental Indenture is to be recorded; and

WHEREAS by the Mortgage the Company covenanted that it would execute and deliver such supplemental indenture or indentures and such further instruments and do such further acts as might be necessary or proper to carry out more effectually the purposes of the Mortgage and to make subject to the lien of the Mortgage any property thereafter acquired, made or constructed and intended to be subject to the lien thereof; and

WHEREAS the Company executed and delivered to the Trustee its First Supplemental Indenture, dated as of June 1, 1949 (hereinafter called its First Supplemental Indenture), its Second Supplemental Indenture, dated as of March 1, 1954 (hereinafter called its Second Supplemental Indenture), its Third Supplemental Indenture, dated as of April 1, 1956 (hereinafter called its Third Supplemental Indenture), its Fourth Supplemental Indenture, dated as of February 1, 1959 (hereinafter called its Fourth Supplemental Indenture), its Fifth Supplemental Indenture, dated as of July 1, 1961 (hereinafter called its Fifth Supplemental Indenture), its Sixth Supplemental Indenture, dated as of January 1, 1964 (hereinafter called its Sixth Supplemental Indenture), its Seventh Supplemental Indenture, dated as of March 1, 1966 (hereinafter called its Seventh Supplemental Indenture), its Eighth Supplemental Indenture, dated as of December 1, 1969 (hereinafter called its Eighth Supplemental Indenture), its Ninth Supplemental Indenture, dated as of April 1, 1971 (hereinafter called its Ninth Supplemental Indenture), its Tenth Supplemental Indenture, dated as of January 1, 1975 (hereinafter called its Tenth Supplemental Indenture), its Eleventh Supplemental Indenture, dated as of December 1, 1975 (hereinafter called its Eleventh Supplemental Indenture), its Twelfth Supplemental Indenture, dated as of July 1, 1981 (hereinafter called its Twelfth Supplemental Indenture), its Thirteenth Supplemental Indenture, dated as of June 1, 1985 (hereinafter called its Thirteenth Supplemental Indenture), its Fourteenth Supplemental Indenture, dated as of November 1, 1985 (hereinafter called its Fourteenth Supplemental Indenture), its Fifteenth Supplemental Indenture, dated as of July 1, 1986 (hereinafter called its Fifteenth Supplemental Indenture), its Sixteenth Supplemental Indenture, dated as of November 1, 1988 (hereinafter called its Sixteenth Supplemental Indenture), its Seventeenth Supplemental Indenture, dated as of October 1, 1989 (hereinafter called its Seventeenth Supplemental Indenture), its Eighteenth Supplemental Indenture, dated as of July 1, 1990 (hereinafter called its Eighteenth Supplemental Indenture), its Nineteenth Supplemental Indenture, dated as of June 1, 1991 (hereinafter called its Nineteenth Supplemental Indenture), and its Twentieth Supplemental Indenture, dated as of June 1, 1993 (hereinafter called its Twentieth Supplemental Indenture); and

WHEREAS the First through Twentieth Supplemental Indentures were filed for record, and were recorded and indexed, as a mortgage of both real and personal property, in the official records of various counties in the States of Oregon and Washington which counties include or will include all counties in which this Twenty-second Supplemental Indenture is to be recorded; and

WHEREAS the Company executed and delivered to the Trustee its Twenty-first Supplemental Indenture, dated as of October 15, 2012 (hereinafter called its Twenty-first Supplemental Indenture); and

WHEREAS said Twenty-first Supplemental Indenture was filed for record, and was recorded and indexed, as a mortgage of both real and personal property, and financing statements were filed, in the official records of the several counties and other offices in the States of Oregon and Washington listed below, as follows:

IN THE STATE OF OREGON

Real Property Mortgage Records

	County	Recordation Date	Document No.
1	Benton	10/29/12	2012-498581
2	Clackamas	10/29/12	2012-070543
3	Clatsop	10/30/12	2012-08835
4	Columbia	10/30/12	2012-008408
5	Coos	10/30/12	2012-9310
6	Douglas	10/29/12	2012-017139
7	Hood River	10/30/12	2012-03785
8	Lane	10/29/12	2012-055545
9	Lincoln	10/30/12	2012-10566
10	Linn	10/30/12	2012-16819
11	Marion	10/30/12	Reel 3439, Page 71
12	Multnomah	10/29/12	2012-138566
13	Polk	10/29/12	2012-011086
14	Tillamook	10/30/12	2012-006117
15	Wasco	10/30/12	2012-004085
16	Washington	10/29/12	2012-091133
17	Yamhill	10/30/12	2012-15633

Filed as a Financing Statement

	Office	Date Filed	File No.
18	Secretary of State	6/23/1993	R61325

IN THE STATE OF WASHINGTON

Real Property Mortgage Records

	County	Recordation Date	Document No.
19	Clark	10/29/12	4906220
20	Klickitat	10/30/12	1100058
21	Skamania	10/30/12	2012181913

WHEREAS an instrument dated as of June 14, 1951, was executed by the Company appointing J. C. KENNEDY as Co-Trustee in succession to said R. G. PAGE (resigned) under the Mortgage and by J. C. KENNEDY accepting the appointment as Co-Trustee under the Mortgage in succession to R. G. PAGE, which instrument was recorded in various counties in the States of Oregon and Washington; and

WHEREAS, in the Ninth Supplemental Indenture STANLEY BURG was appointed by the Company as Co-Trustee under the Mortgage in succession to J. C. KENNEDY (resigned) and in the Ninth Supplemental Indenture STANLEY BURG accepted such appointment as Co-Trustee under the Mortgage in succession to J. C. KENNEDY; and

WHEREAS, Section 103 of the Mortgage provides, among other things, that if for any reason it shall not be necessary, in the opinion of counsel, that there shall be a Co-Trustee and the Company shall file with the Corporate Trustee and also with the Co-Trustee, an Opinion of Counsel to that effect and a written request for the removal of the Co-Trustee, the Co-Trustee shall forthwith cease to be a Trustee under the Mortgage, and all powers of the Co-Trustee shall forthwith terminate, as shall his right, title or interest in and to the trust estate and, unless and until there shall be appointed a new Trustee or successor to the Co-Trustee, all the right, title and powers of the Trustees shall devolve upon the Corporate Trustee and its successors alone; and

WHEREAS, the Company having filed with the Corporate Trustee and the Co-Trustee such Opinion of Counsel and such written request; and

WHEREAS, pursuant to Sections 103 of the Mortgage, the Company and the Corporate Trustee have agreed that Stanley Burg has ceased to be a Trustee under the Mortgage, and all powers of the Co-Trustee have terminated, as has his right, title or interest in and to the trust estate; and, unless and until there shall be appointed a new Trustee or successor to the Co-Trustee, all the right, title and powers of the Trustees has devolved upon the Corporate Trustee and its successors alone; and

WHEREAS in addition to the property described in the Mortgage, as heretofore supplemented, the Company has acquired certain other property, rights and interests in property; and

WHEREAS, the Company has heretofore issued, in accordance with the provisions of the Mortgage, as supplemented, and on the date hereof there remain outstanding, the following series of First Mortgage Bonds:

Series	Principal Amount Outstanding
Secured Medium-Term Notes, Series A	$ 10,000,000
Secured Medium-Term Notes, Series B (bonds of the Twenty-first Series)	$541,700,000
4.00% Series due 2042 (bonds of the Twenty-second Series)	$ 50,000,000

; and

WHEREAS Section 8 of the Mortgage provides that the form of each series of bonds (other than the First Series) issued thereunder shall be established by Resolution of the Board of Directors of the Company; that the form of such series, as established by the Board of Directors, shall specify the descriptive title of the bonds and various other terms thereof; and that such Series may also contain such provisions not inconsistent with the provisions of the Mortgage as the Board of Directors may, in its discretion, cause to be inserted therein expressing or referring to the terms and conditions upon which such bonds are to be issued and/or secured under the Mortgage; and

WHEREAS Section 120 of the Mortgage provides, among other things, that any power, privilege or right expressly or impliedly reserved to or in any way conferred upon the Company by any provision of the Mortgage, whether such power, privilege or right is in any way restricted or is unrestricted, may (to the extent permitted by law) be in whole or in part waived or surrendered or subjected to any restriction if at the time unrestricted or to additional restriction if already restricted, and the Company may enter into any further covenants, limitations or restrictions for the benefit of any one or more series of bonds issued thereunder, or the Company may cure any ambiguity contained therein or in any supplemental indenture or may (in lieu of establishment by Resolution as provided in Section 8 of the Mortgage) establish the terms and provisions of any series of bonds other than said First Series, by an instrument in writing executed and acknowledged by the Company in such manner as would be necessary to entitle a conveyance of real estate to record in all of the states in which any property at the time subject to the lien of the Mortgage shall be situated; and

WHEREAS the Company now desires (pursuant to the provisions of Section 120 of the Mortgage) to add to its covenants and agreements contained in the Mortgage, as heretofore supplemented, certain other covenants and agreements to be observed by it, to cure certain ambiguities contained in the Mortgage or in certain supplemental indentures, and to alter and amend in certain respects the covenants and provisions contained in the Mortgage, as heretofore supplemented and amended; and

WHEREAS the execution and delivery by the Company of this Twenty-second Supplemental Indenture, and the terms of the bonds of the Twenty-first Series hereinafter referred to, have been duly authorized by the Board of Directors of the Company by appropriate resolutions of the Board of Directors;

NOW, THEREFORE, THIS INDENTURE WITNESSETH:

That Northwest Natural Gas Company, in consideration of the above premises and such other valuable consideration, the receipt and sufficiency whereof is hereby acknowledged, and in further assurance of the estate, title and rights of the Trustee, and in order further to secure the payment both of the principal of and interest and premium, if any, on the bonds from time to time issued under the Mortgage, according to their

tenor and effect, and the performance of all the provisions of the Mortgage (including any instruments supplemental thereto and any modification made as in the Mortgage provided) and of said bonds, hereby grants, bargains, sells, releases, conveys, assigns, transfers, mortgages, pledges, sets over and confirms (subject, however, to Excepted Encumbrances, as defined in Section 6 of the Mortgage) to Deutsche Bank Trust Company Americas, as Trustee under the Mortgage, and to its successor or successors in said trust, and to said Trustee and its successors and assigns forever, all property, real, personal and mixed, acquired by the Company after the date of the Mortgage, of the kind or nature specifically mentioned in Article XXI of the Mortgage or of any other kind or nature (except any herein or in the Mortgage expressly excepted) now owned or, subject to the provisions of subsection (I) of Section 87 of the Mortgage, hereafter acquired by the Company (by purchase, consolidation, merger, donation, construction, erection or in any other way) and wheresoever situated, including (without in anywise limiting or impairing by the enumeration of the same the scope and intent of the foregoing) all lands, gas plants, by-product plants, gas holders, gas mains and pipes; all power sites, water rights, reservoirs, canals, raceways, dams, aqueducts, and all other rights or means for appropriating, conveying, storing and supplying water; all rights of way and roads; all plants for the generation of electricity by steam, water and/or other power; all power houses, street lighting systems, standards and other equipment incidental thereto, telephone, radio, television and air-conditioning systems and equipment incidental thereto, water works, water systems, steam heat and hot water plants, substations, lines, service and supply systems, bridges, culverts, tracts, ice or refrigeration plants and equipment, offices, buildings and other structures and the equipment thereof; all machinery, engines, boilers, dynamos, gas, electric and other machines, regulators, meters, transformers, generators, motors, gas, electrical and mechanical appliances, conduits, cables, gas, water, steam heat or other pipes, service pipes, fittings, valves and connections, pole and transmission lines, wires, cables, tools, implements, apparatus, furniture and chattels; all franchises, consents or permits; all lines for the transmission and distribution of gas, electric current, steam heat or water for any purpose including mains, pipes, conduits, towers, poles, wires, cables, ducts and all apparatus for use in connection therewith; all real estate, lands, easements, servitudes, licenses, permits, franchises, privileges, rights of way and other rights in or relating to public or private property, real or personal, or the occupancy of such property and (except as herein or in the Mortgage, as heretofore supplemented, expressly excepted) all right, title and interest the Company may now have or may hereafter acquire in and to any and all property of any kind or nature wheresoever situated.

TOGETHER WITH all and singular the tenements, hereditaments, prescriptions, servitudes and appurtenances belonging or in anywise appertaining to the aforementioned property or any part thereof, with the reversion and reversions, remainder and remainders and (subject to the provisions of Section 57 of the Mortgage) the tolls, rents, revenues, issues, earnings, income, product and profits thereof, and all the estate, right, title and interest and claim whatsoever, at law as well as in equity, which the Company now has or may hereafter acquire in and to the aforementioned property and franchises and every part and parcel thereof.

IT IS HEREBY AGREED by the Company that, subject to the provisions of subsection (I) of Section 87 of the Mortgage, all the property, rights, and franchises acquired by the Company (by purchase, consolidation, merger, donation, construction, erection or in any other way) after the date hereof (other than any Excepted Property) shall be and are as fully granted and conveyed hereby and by the Mortgage, and as fully embraced within the lien hereof and the lien of the Mortgage, as supplemented, as if such property, rights and franchises were now owned by the Company and were specifically described herein or in the Mortgage, as heretofore supplemented, and conveyed hereby or thereby.

TO HAVE AND TO HOLD all such properties, real, personal and mixed, granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged, set over or confirmed by the Company as aforesaid, or intended so to be, to Deutsche Bank Trust Company Americas, as Trustee, and its successors and assigns forever.

IN TRUST NEVERTHELESS, for the same purposes and upon the same terms, trusts and conditions and subject to and with the same provisos and covenants as are set forth in the Mortgage, as heretofore supplemented, this Twenty-second Supplemental Indenture being supplemental thereto.

AND IT IS HEREBY COVENANTED by the Company that all the terms, conditions, provisos, covenants and provisions contained in the Mortgage, as heretofore supplemented, shall affect and apply to the property hereinbefore described and conveyed, and to the estates, rights, obligations and duties of the Company and the Trustee and the beneficiaries of the trust with respect to said property, and to the Trustee and its successors in the trust, in the same manner and with the same effect as if the said property had been owned by the Company at the time of the execution of the Mortgage, and had been specifically and at length described in and conveyed to said Trustee by the Mortgage as a part of the property therein stated to be conveyed.

The Company further covenants and agrees to and with the Trustee and its successors in said trust under the Mortgage, as follows:

ARTICLE I.

AMENDMENTS OF CERTAIN PROVISIONS OF THE MORTGAGE

SECTION 1.01 Meetings and Consents of Bondholders.

Pursuant to the reservation of right in Section 6 of Article III of the Ninth Supplemental Indenture, the Company hereby amends Article XIX of the Mortgage to read as set forth in Section 6 of Article III of the Ninth Supplemental Indenture.

SECTION 1.02 Release and Substitution of Property.

Pursuant to the reservation of right in Section 2.03 of Article II of the Eighteenth Supplemental Indenture, the Company hereby

(A) amends subdivision (1) of Section 59 of the Mortgage to read as follows:

“(1) an Officers’ Certificate describing in reasonable detail the property to be released and requesting such release;”

(B) amends subdivisions (3)(b) and (c) of Section 59 of the Mortgage to read as follows:

“(b) the fair value, and the Cost (or as to Property Additions constituting Funded Property of which the fair value to the Company at the time the same became Funded Property was less than the Cost, then such fair value in lieu of Cost), in the opinion of the signers, of the property (or securities) to be released; (c) the Cost (or as to Property Additions constituting Funded Property of which the fair value to the Company at the time the same became Funded Property was less than the Cost, then such fair value in lieu of Cost), in the opinion of the signers, of any portion thereof that is Funded Property;”

and

(C) amends the first six lines of subdivision (4) of Section 59 of the Mortgage to read as follows:

“(4) an amount in cash, to be held by the Corporate Trustee as part of the Mortgaged and Pledged Property, equivalent to the amount, if any, by which the Cost (or as to Property Additions constituting Funded Property of which the fair value to the Company at the time the same became Funded Property was less than the Cost, then such fair value in lieu of Cost) of the property to be released, as specified in the Engineer’s Certificate provided for in subdivision (3) above, exceeds the aggregate of the following items:”

SECTION 1.03 Net Earning Certificate.

Annual Interest Requirements for Variable Rate Bonds. Pursuant to the reservation of right in Section 2.01 of Article II of the Eighteenth Supplemental Indenture, the Company hereby amends subdivision (B) of Section 7 of the Mortgage and the first paragraph following such subdivision (B) to read as set forth in such Section 2.01.

SECTION 1.04 Bonding Ratio.

Pursuant to the reservation of right in Section 2.02 of Article II of the Eighteenth Supplemental Indenture, the Company hereby amends Sections 25, 26, 59 and 61 of the Mortgage by substituting the phrase “seventy per centum (70%)” for the phrase “sixty per centum (60%)” and substituting the phrase “ten-sevenths (10/7ths)” for the phrase “ten-sixths (10/6ths)” each time such phrase or phrases occur in said Sections.

SECTION 1.05 Deductions for Retired Automotive Equipment.

Pursuant to the reservation of right in Section 3 of the Third Supplemental Indenture, the Company hereby amends the Mortgage, as amended and supplemented, to delete clause (ii) of Section 4(II)(A) of the Mortgage, as amended and supplemented.

SECTION 1.06 Releases of Unfunded Property.

Pursuant to the reservation of right in Section 2.03 of Article II of the Eighteenth Supplemental Indenture, the Company hereby amends (A) Section 60 of the Mortgage as provided in such Section 2.03 and (B) the definition of “Engineer’s Certificate” in Section 3 of the Mortgage to read as provided in such Section 2.03.

SECTION 1.07 Excepted Property.

The term “Excepted Property” shall mean the property described in clauses (1) through (6) of the paragraph on pages 10-11 of the Mortgage, as amended and supplemented from time to time (and the corresponding provision in each supplemental indenture thereto).

Clause (1) of the paragraph on pages 10-11 of the Mortgage (and the corresponding provision in each supplemental indenture thereto) is hereby amended to read:

“(1) all cash on hand or in banks or other financial institutions, deposit accounts, securities accounts, shares of stock, interests in business trusts, general or limited partnerships or limited liability companies, bonds, notes, mortgages, other evidences of indebtedness and other securities, security entitlements, commodities accounts and other investment property of whatsoever kind and nature, not hereafter specifically pledged, paid, deposited, delivered or held hereunder or covenanted so to be;”

Clause (3) of the paragraph on pages 10-11 of the Mortgage (and the corresponding provision in each supplemental indenture thereto) is hereby amended to read:

“(3) bills, notes and accounts receivable, judgments, demands and choses in action (including payment intangibles, commercial tort claims and tax credits), and all contracts, leases and operating agreements (including policies of insurance, chattel paper, cooperative interests, warehouse receipts, and contract rights granted by statute or governmental action, including rights to bill and collect revenues or other amounts from customers or others) not specifically pledged hereunder or hereinafter covenanted so to be;

Clause (6) of the paragraph on pages 10-11 of the Mortgage (and the corresponding provision in each supplemental indenture thereto) is hereby amended to read:

“(6) the Company’s franchise to be a corporation; and all properties, real, personal and mixed, which subsequent to November 1, 2016 have been released from the Lien of this Indenture, and any improvements, extensions and additions to such properties and renewals, replacements and substitutions of or for any parts thereof;”

SECTION 1.08 Additional Definitions.

Section 3 of the Mortgage is hereby amended to add the following definitions:

“The term “Authorized Officer” means the President, any Vice President, the Treasurer, any Assistant Treasurer, or any other officer, manager or agent of the Company duly authorized pursuant to a Resolution to act in respect of matters relating to this Indenture.

The term “Bonding Ratio” shall mean the percentage stated in Section 25 of the Mortgage, as amended and supplemented, and the term “Reciprocal of the Bonding Ratio” shall mean the reciprocal of such percentage.

The term “Business Day”, when used with respect to a place of payment for the bonds or any other particular location specified in the bonds or this Indenture, means any day, other than a Saturday or Sunday, which is not a day on which banking institutions or trust companies in such place of payment or other location are required by law, regulation or executive order to remain closed, or a day on which the corporate trust office of the Corporate Trustee is closed for business.

The term “Company Order” means a written order or request signed in the name of the Company by an Authorized Officer of the Company and delivered to the Corporate Trustee.

The term “corporation” means a corporation, association, company, limited liability company, partnership, limited partnership, joint stock company or business trust, and references to “corporate” and other derivations of “corporation” herein shall be deemed to include appropriate derivations of such entities.

The term “Fair Value”, with respect to property, means the fair value of such property as determined in the reasonable judgment of the Person certifying to such value, such determination to be based on any one or more factors deemed relevant by such Person, including, without limitation, (a) the amount which would be likely to be obtained in an arm’s-length transaction with respect to such property between an informed and willing buyer and an informed and willing seller, under no

compulsion, respectively, to buy or sell, (b) the amount of investment with respect to such property which, together with a reasonable return thereon, would be likely to be recovered through ordinary business operations or otherwise, (c) the Cost, accumulated depreciation, and replacement cost with respect to such property and/or (d) any other relevant factors; provided, however, that (x) the Fair Value of property shall be determined without deduction for any Liens on such property prior to the Lien of this Indenture (except that the Fair Value of property to be released from the Lien of this Indenture shall be determined with deduction for any Liens on such property prior to the Lien of this Indenture) and (y) the Fair Value to the Company of Property Additions may be of less value to a Person which is not the owner or operator of the Mortgaged and Pledged Property or any portion thereof than to a Person which is such owner or operator. Fair Value may be determined, without physical inspection, by the use of accounting and engineering records and other data maintained by the Company or otherwise available to the Engineer certifying the same.

The term “Governmental Authority” means the government of the United States or of any State or Territory thereof or of the District of Columbia or of any county, municipality or other political subdivision of any thereof, or any department, agency, authority or other instrumentality of any of the foregoing.

The term “Holder” means a Person in whose name a bond is registered pursuant to Section 13 of the Mortgage, as amended and supplemented.

The term “Issue Date”, when used with respect to the bonds of the Twenty-first Series, shall have the meaning specified in the Twentieth Supplemental Indenture.

The term “Lien” means any mortgage, deed of trust, pledge, security interest, encumbrance, easement, lease, reservation, restriction, servitude, charge or similar right and any other lien of any kind, including, without limitation, any conditional sale or other title retention agreement, any lease in the nature thereof, and any defect, irregularity, exception or limitation in record title.

The term “Person” means any individual, corporation, joint venture, trust or unincorporated organization or any Governmental Authority.

The term “Permitted Liens” shall mean as of any particular time, any of the following:

(a)Liens for taxes, assessments and other governmental charges or requirements which are not delinquent or which are being contested in good faith by appropriate proceedings or of which at least ten (10) Business Days notice has not been given to the general counsel of the Company or to such other Person designated by the Company to receive such notices;

(b)mechanics’, workmen’s, repairmen’s, materialmen’s, warehousemen’s, and carriers’ Liens, other Liens incident to construction, Liens or privileges of any employees of the Company for salary or wages earned, but not yet payable, and other Liens, including without limitation Liens for worker’s compensation awards, arising in the ordinary course of business for charges or requirements which are not delinquent or which are being contested in good faith and by appropriate proceedings or of which at least ten (10) Business Days notice has not been given to the general counsel of the Company or to such other Person designated by the Company to receive such notices;

(c)Liens in respect of attachments, judgments or awards arising out of judicial or administrative proceedings (i) in an amount not exceeding the greater of (A) Ten Million Dollars ($10,000,000) and (B) three percent (3%) of the principal amount of the bonds then Outstanding or (ii) with respect to which the Company shall (X) in good faith be prosecuting an appeal or other proceeding for review and with respect to which the Company shall have secured a stay of execution pending such appeal or other proceeding or (Y) have the right to prosecute an appeal or other proceeding for review or (Z) have not received at least ten (10) Business Days notice given to the general counsel of the Company or to such other Person designated by the Company to receive such notices;

(d)easements, leases, reservations or other rights of others in, on, over and/or across, and laws, regulations and restrictions affecting, and defects, irregularities, exceptions and limitations in title to, the Mortgaged and Pledged Property or any part thereof; provided, however, that such easements, leases, reservations, rights, laws, regulations, restrictions, defects, irregularities, exceptions and limitations do not in the aggregate materially impair the use by the Company of the Mortgaged and Pledged Property considered as a whole for the purposes for which it is held by the Company;

(e)Liens, defects, irregularities, exceptions and limitations in (i) title to real property subject to rights-of-way in favor of the Company or otherwise or used or to be used by the Company primarily for right-of-way purposes; (ii) real property held under lease, easement, license or similar right; or (iii) the rights-of-way, leases, easements, licenses or similar rights in favor of the Company; provided, however, that (A) the Company shall have obtained from the apparent owner or owners of such real property a sufficient right, by the terms of the instrument granting such right-of-way, lease, easement, license or similar right, to the use thereof for the purposes for which the Company acquired the same; (B) the Company has power under eminent domain or similar statutes to remove or subordinate such Liens, defects, irregularities, exceptions or limitations or (C) such defects, irregularities, exceptions and limitations may be otherwise remedied without undue effort or expense; and defects, irregularities, exceptions and limitations in title to flood lands, flooding rights and/or water rights;

(f)Liens securing indebtedness or other obligations neither created, assumed nor guaranteed by the Company nor on account of which it customarily pays interest upon real property or rights in or relating to real property acquired by the Company for the purpose of the transmission or distribution of electric energy, gas or water, for the purpose of telephonic, telegraphic, radio, wireless or other electronic communication or otherwise for the purpose of obtaining rights-of-way;

(g)leases existing on November 1, 2016 affecting properties owned by the Company at said date and renewals and extensions thereof; and leases affecting such properties entered into after such date or affecting properties acquired by the Company after such date which, in either case, (i) have respective terms of not more than ten (10) years (including extensions or

renewals at the option of the tenant) or (ii) do not materially impair the use by the Company of such properties for the respective purposes for which they are held by the Company;

(h)Liens vested in lessors, licensors, franchisors or permitters for rent or other amounts to become due or for other obligations or acts to be performed, the payment of which rent or the performance of which other obligations or acts is required under leases, subleases, licenses, franchises or permits, so long as the payment of such rent or other amounts or the performance of such other obligations or acts is not delinquent or is being contested in good faith and by appropriate proceedings;

(i)controls, restrictions, obligations, duties and/or other burdens imposed by federal, state, municipal or other law, or by rules, regulations or orders of Governmental Authorities, upon the Mortgaged and Pledged Property or any part thereof or the operation or use thereof or upon the Company with respect to the Mortgaged and Pledged Property or any part thereof or the operation or use thereof or with respect to any franchise, grant, license, permit or public purpose requirement, or any rights reserved to or otherwise vested in Governmental Authorities to impose any such controls, restrictions, obligations, duties and/or other burdens;

(j)rights which Governmental Authorities may have by virtue of franchises, grants, licenses, permits or contracts, or by virtue of law, to purchase, recapture or designate a purchaser of or order the sale of the Mortgaged and Pledged Property or any part thereof, to terminate franchises, grants, licenses, permits, contracts or other rights or to regulate the property and business of the Company; and any and all obligations of the Company correlative to any such rights;

(k)Liens required by law or governmental regulations (i) as a condition to the transaction of any business or the exercise of any privilege or license, (ii) to enable the Company to maintain self-insurance or to participate in any funds established to cover any insurance risks, (iii) in connection with workmen’s compensation, unemployment insurance, social security, any pension or welfare benefit plan or (iv) to share in the privileges or benefits required for companies participating in one or more of the arrangements described in clauses (ii) and (iii) above;

(l)Liens on the Mortgaged and Pledged Property or any part thereof which are granted by the Company to secure duties or public or statutory obligations or to secure, or serve in lieu of, surety, stay or appeal bonds;

(m)rights reserved to or vested in others to take or receive any part of any coal, ore, gas, oil and other minerals, any timber and/or any electric capacity or energy, gas, water, steam and any other products, developed, produced, manufactured, generated, purchased or otherwise acquired by the Company or by others on property of the Company;

(n)(i) rights and interests of Persons other than the Company arising out of contracts, agreements and other instruments to which the Company is a party and which relate to the common ownership or joint use of property; and (ii) all Liens on the interests of Persons other than the Company in property owned in common by such Persons and the Company if and to the extent that the enforcement of such Liens would not adversely affect the interests of the Company in such property in any material respect;

(o)any restrictions on assignment and/or requirements of any assignee to qualify as a permitted assignee and/or public utility or public service corporation;

(p)any Liens which have been bonded for the full amount in dispute or for the payment of which other adequate security arrangements have been made;

(q)any controls, liens, restrictions, regulations, easements, exceptions or reservations of any public authority or unit applying particularly to any form of space satellites (including but not limited to solar power satellites), space stations and other analogous facilities whether or not in the earth’s atmosphere;

(r)easements, ground leases or rights-of-way in, upon, over and/or across the property or rights-of-way of the Company for the purpose of roads, pipe lines, transmission lines, distribution lines, communication lines, railways, removal or transportation of coal, lignite, gas, oil or other minerals or timber, and other like purposes, or for the joint or common use of real property, rights-of-way, facilities and/or equipment; provided, however, that such grant shall not materially impair the use of the property or rights-of-way for the purposes for which such property or rights-of-way are held by the Company;

(s)any Lien of the Trustees granted pursuant to Section 96 of this Indenture; and

(t)any Lien securing indebtedness for the payment of which money in the necessary amount shall have been irrevocably deposited in trust with the trustee or other holder of such Lien; provided, however, that if such indebtedness is to be redeemed or otherwise prepaid prior to the stated maturity thereof, any notice requisite to such redemption or prepayment shall have been given in accordance with the mortgage or other instrument creating such Lien or irrevocable instructions to give such notice shall have been given to such trustee or other holder.”

SECTION 1.09 Governing Law. The Mortgage, as amended and supplemented, shall be governed by and construed in accordance with the law of the State of New York (including without limitation Section 5-1401 of the New York General Obligations Law or any successor to such statute), without giving effect to its conflicts-of-law principles, except to the extent that the Trust Indenture Act shall be applicable and except to the extent that the law of any jurisdiction wherein any portion of the Mortgaged and Pledged Property is

located shall mandatorily govern the creation of a mortgage lien on or security interest in, or perfection, priority or enforcement of the Lien of this Indenture or exercise of remedies with respect to, such portion of the Mortgaged and Pledged Property.

SECTION 1.10 Effective Date. Each of the amendments set forth in this Article I shall be effective as of November 1, 2016.

ARTICLE II.

THE COMPANY RESERVES THE RIGHT TO AMEND

CERTAIN PROVISIONS OF THE MORTGAGE

SECTION 2.01. Delete Earnings Test. The Company reserves the right, without any consent, vote or other action by holders of bonds of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend the Mortgage, as amended and supplemented, to delete all provisions in the Mortgage, as amended and supplemented, which require a Net Earning Certificate, whether as a condition precedent to the authentication and delivery of bonds or otherwise, including Section 27, Section 28(6), the penultimate paragraph of Section 29, and Section 30(3) of the Mortgage, as amended and supplemented.

SECTION 2.02. Delete Requirement for Disposition of Released Property. The Company reserves the right, without any consent, vote or other action by holders of bonds of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend the Mortgage, as amended and supplemented, (A) to delete clause (a) of subdivision (3) of Section 59 of the Mortgage, as amended and supplemented, and (B) to delete clause (b) of subdivision (1) of Section 60(II) of the Mortgage, as amended and supplemented.

SECTION 2.03. Redefine Funded Property. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 5 of the Mortgage, as amended and supplemented, to replace the first two paragraphs thereof with three paragraphs reading substantially as follows:

“The term “Funded Property Certificate” shall mean an Independent Engineer’s Certificate delivered to the Corporate Trustee, within ninety days after the date thereof,

(A) stating the aggregate principal amount of bonds then Outstanding under this Indenture;

(B) stating the aggregate principal amount of bonds which the Company is then entitled to have authenticated and delivered by compliance with the provisions of Section 29 hereof;

(C) stating an amount equal to the sum of the amounts stated in clauses (A) and (B) above divided by the Bonding Ratio;

(D) describing all or any portion of the Mortgaged and Pledged Property which, in the opinion of the signers, has an aggregate Fair Value not less than the amount stated in clause (C) above.

The term “Funded Property” shall mean:

(1) all Mortgaged and Pledged Property described in the most recent Funded Property Certificate delivered to the Corporate Trustee;

(2) all Property Additions to the extent that the same shall have been made the basis of the authentication and delivery of bonds under this Indenture after the date of the most recent Funded Property Certificate delivered to the Corporate Trustee;

(3) all Property Additions to the extent that the same shall have been made the basis of the release of property from the Lien of this Indenture after the date of the most recent Funded Property Certificate delivered to the Corporate Trustee, subject, however, to the provisions of Section 59 hereof;

(4) all Property Additions to the extent that the same shall have been substituted (otherwise than under the release or cash withdrawal provisions hereof) for Funded Property retired after the date of the most recent Funded Property Certificate delivered to the Corporate Trustee; and

(5) all Property Additions to the extent that the same shall have been made the basis of the withdrawal of any Funded Cash as hereinafter defined after the date of the most recent Funded Property Certificate delivered to the Corporate Trustee, except to the extent that any such Property Additions shall no longer be deemed to be Funded Property in accordance with the provisions of other Sections of this Indenture.

In the event that in any certificate filed with the Corporate Trustee in connection with any of the transactions referred to in clauses (2), (3) and (5) of this Section only a part of the Cost or fair value of the Property Additions described in such certificate shall be required for the purposes of such certificate, then such Property Additions shall be deemed to be Funded Property only to the extent so required for the purpose of such certificate.”

The foregoing amendment shall not become effective unless and until the Company elects to deliver, and shall have delivered, a Funded Property Certificate to the Corporate Trustee.

SECTION 2.04. Insurance. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 37 of the Mortgage, as amended and supplemented, to read substantially as follows:

“Section 37. (a) The Company shall (i) keep or cause to be kept all the Mortgaged and Pledged Property insured against loss by fire, to the extent that property of similar character is usually so insured by companies similarly situated and operating like properties, to a reasonable amount, by reputable insurance companies, the proceeds of such insurance (except as to any loss of Excepted Property and except as to any particular loss less than the greater of (A) Twenty Million Dollars ($20,000,000) and (B) three percent (3%) of the principal amount of bonds Outstanding on the date of such particular loss) to be made payable, subject to applicable law, to the Corporate Trustee as the interest of the Corporate Trustee may appear, or to the trustee or other holder of any Lien prior hereto upon property subject to the Lien hereof, if the terms thereof require such payment, or to the agent or representative of the owners of jointly-owned property if the terms of such joint ownership require such payment or (ii) in lieu of or supplementing such insurance in whole or in part, adopt some other method or plan of protection against loss by fire at least equal in protection to the method or plan of protection against loss by fire of companies similarly situated and operating properties subject to

similar fire hazards or properties on which an equal primary fire insurance rate has been set by reputable insurance companies; and if the Company shall adopt such other method or plan of protection, it shall, subject to applicable law (and except as to any loss of Excepted Property and except as to any particular loss less than the greater of (X) Twenty Million Dollars ($20,000,000) and (Y) three percent (3%) of the principal amount of bonds Outstanding on the date of such particular loss) pay to the Corporate Trustee on account of any loss covered by such method or plan an amount in cash equal to the amount of such loss less any amounts otherwise paid to the Corporate Trustee in respect of such loss or paid to the trustee or other holder of any Lien prior hereto upon property subject to the Lien hereof in respect of such loss if the terms thereof require such payment or paid to the agent or representative of the owners of jointly-owned property if the terms of such joint ownership require such payment. Any cash so required to be paid by the Company pursuant to any such method or plan shall for the purposes of this Indenture be deemed to be proceeds of insurance. In case of the adoption of such other method or plan of protection, the Company shall furnish to the Corporate Trustee a certificate of an actuary or other qualified person appointed by the Company with respect to the adequacy of such method or plan.

Anything herein to the contrary notwithstanding, the Company may have fire insurance policies with (i) a deductible provision in a dollar amount per occurrence not exceeding the greater of (A) Twenty Million Dollars ($20,000,000) and (B) three percent (3%) of the principal amount of the bonds Outstanding on the date such policy goes into effect, and/or (ii) co-insurance or self insurance provisions with a dollar amount per occurrence not exceeding thirty percent (30%) of the loss proceeds otherwise payable; provided, however, that the dollar amount described in clause (i) above may be exceeded to the extent such dollar amount per occurrence is below the deductible amount in effect as to fire insurance (X) on property of similar character insured by companies similarly situated and operating like property or (Y) on property as to which an equal primary fire insurance rate has been set by reputable insurance companies.

(b) All moneys paid to the Corporate Trustee by the Company in accordance with this Section or received by the Corporate Trustee as proceeds of any insurance, in either case on account of a loss on or with respect to Funded Property, shall, subject to any Lien prior hereto upon property subject to the Lien hereof, be held by the Corporate Trustee and, subject as aforesaid, shall be paid by it to the Company to reimburse the Company for an equal amount expended or committed for expenditure in the rebuilding, renewal and/or replacement of or substitution for the property destroyed or damaged, upon receipt by the Corporate Trustee of:

(i)a letter signed by an officer of the Company requesting such payment,

(ii)an Engineer’s Certificate:

(A)describing the property so damaged or destroyed;

(B)stating the Cost of such property (or, if the fair value to the Company of such property at the time the same became Funded Property was certified to be an amount less than the Cost thereof, then such fair value, as so certified, in lieu of Cost) or, if such damage or destruction shall have affected only a portion of such property, stating the allocable portion of such Cost or fair value;

(C)stating the amounts so expended or committed for expenditure in the rebuilding, renewal, replacement of and/or substitution for such property; and

(D)stating the fair value to the Company of such property as rebuilt or renewed or as to be rebuilt or renewed and/or of the replacement or substituted property, and if

(a)within six months prior to the date of acquisition thereof by the Company, such property has been used or operated, by a person or persons other than the Company, in a business similar to that in which it has been or is to be used or operated by the Company, and

(b)the fair value to the Company of such property as set forth in such Engineer’s Certificate is not less than Twenty-five Thousand Dollars ($25,000) and not less than one percent (1%) of the aggregate principal amount of the bonds at the time Outstanding,

the Engineer making the statement required by this clause (D) shall be an Independent Engineer, and

(iii)an Opinion of Counsel stating that, in the opinion of the signer, the property so rebuilt or renewed or to be rebuilt or renewed, and/or the replacement property, is or will be subject to the Lien hereof.

Any such moneys not so applied within thirty-six (36) months after its receipt by the Corporate Trustee, or in respect of which notice in writing of intention to apply the same to the work of rebuilding, renewal, replacement or substitution then in progress and uncompleted shall not have been given to the Corporate Trustee by the Company within such thirty-six (36) months, or which the Company shall at any time notify the Corporate Trustee is not to be so applied, shall thereafter be withdrawn, used or applied in the manner, to the extent and for the purposes, and subject to the conditions, provided in Section 61; provided, however, that if the amount of such moneys shall exceed the amount stated pursuant to clause (B) in the Engineer’s Certificate referred to above, the amount of such excess shall not be deemed to be Funded Cash, shall not be subject to Section 61 and shall be remitted to or upon the order of the Company upon the withdrawal, use or application of the balance of such moneys pursuant to Section 61.

Anything in this Indenture to the contrary notwithstanding, if property on or with respect to which a loss occurs constitutes Funded Property in part only, the Company may, at its election, obtain the reimbursement of insurance proceeds attributable to the part of such property which constitutes Funded Property under this subsection (b) and obtain the reimbursement of insurance proceeds attributable to the part of such property which does not constitute Funded Property under subsection (c) of this Section.

(c) All moneys paid to the Corporate Trustee by the Company in accordance with this Section or received by the Corporate Trustee as proceeds of any insurance, in either case on account of a loss on or with respect to property which does not constitute Funded Property, shall, subject to the requirements of any Lien prior hereto upon property subject to the Lien hereof, be held by the Corporate Trustee and, subject as aforesaid, shall be paid by it to the Company upon receipt by the Corporate Trustee of:

(i)a letter from an officer of the Company requesting such payment;

(ii)an Engineer’s Certificate stating:

(A)that such moneys were paid to or received by the Corporate Trustee on account of a loss on or with respect to property which does not constitute Funded Property; and

(B)if true, either (I) that the aggregate amount of the Cost or fair value to the Company (whichever is less) of all Property Additions which do not constitute Funded Property (excluding, to the extent of such loss, the property on or with respect to which such loss was incurred), after making deductions therefrom and additions thereto of the character contemplated by Section 4, is not less than zero (0) or (II) that the amount of such loss does not exceed the aggregate Cost or fair value to the Company (whichever is less) of Property Additions acquired, made or constructed on or after the ninetieth (90th) day prior to the date of the request for such payment; or

(C)if neither of the statements contemplated in subclause (B) above can be made, the amount by which zero (0) exceeds the amount referred to in subclause (B)(I) above (showing in reasonable detail the calculation thereof); and

(iii)if the Engineer’s Certificate required by clause (ii) above contains neither of the statements contemplated in clause (ii)(B) above, an amount in cash, to be held by the Corporate Trustee as part of the Mortgaged and Pledged Property, equal to the amount shown in clause (ii)(C) above.

To the extent that the Company shall be entitled to withdraw proceeds of insurance pursuant to this subsection (c), such proceeds shall be deemed not to constitute Funded Cash.

(d) Whenever under the provisions of this Section the Company is required to deliver moneys to the Corporate Trustee and at the same time shall have satisfied the conditions set forth herein for payment of moneys by the Corporate Trustee to the Company, there shall be paid to or retained by the Corporate Trustee or paid to the Company, as the case may be, only the net amount.”

SECTION 2.05. Property Additions. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend subdivision (I) of Section 4 of the Mortgage, as amended and supplemented, to read substantially as follows:

“(I) The term “Property Additions” shall mean Mortgaged and Pledged Property acquired by the Company by purchase, consolidation, merger, donation, construction, erection or in any way whatsoever, subsequent to March 31, 1946, or in the process of construction or erection in so far as actually constructed or erected subsequent to March 31, 1946, and used or useful in any business that the Company may conduct.

At any time and from time to time, the Company may elect, by supplemental indenture, to subject any property that is Excepted Property to the Lien of the Mortgage, as amended and supplemented, and such property shall thereupon cease to be Excepted Property.

The term ”Natural Gas and Oil Production Property” shall mean all leases, consolidated leases and operating agreements, fee lands and other mineral interest, gas and oil rights, wells, field compressors, equipment and other properties and rights whether producing or non-producing, used

or useful primarily and principally for the production and gathering of natural gas up to the point of connection with any gas transmission or distribution system or used or useful primarily and principally for the production and gathering of oil.

SECTION 2.06. Priority and Authority Opinions. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to restate subdivisions (7) and (9) of Section 28 of the Mortgage, as amended and supplemented, to read substantially as follows:

“(7) either an Opinion of Counsel or an Officers’ Certificate to the effect that:

(a) this Indenture constitutes, or, upon the delivery of, and/or the filing and/or recording in the proper places and manner of, the instruments of conveyance, assignment or transfer, if any, specified in said opinion or certificate, will constitute, a Lien on all the Property Additions to be made the basis of the authentication and delivery of such bonds, subject to no Lien thereon prior to the Lien of this Indenture except Permitted Liens and any other Liens of which the signer of said opinion or certificate has no actual knowledge and which do not appear on a specified lien search report received by said signer not more than five (5) Business Days prior to the date of said opinion or certificate; and

(b) the Company has corporate authority to operate such Property Additions;

(c) that the general nature and extent of Qualified Liens, and the principal amount of the then Outstanding Qualified Lien Bonds secured thereby, if any, mentioned in the accompanying Engineer’s Certificate, are correctly stated;

(9) copies of the instruments of conveyance, assignment and transfer, if any, and the lien search report, if any, specified in the opinion or certificate provided for in clause (7) above.”

SECTION 2.07. Maintenance. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 38 of the Mortgage, as amended and supplemented, to read substantially as follows:

“Section 38. The Company shall cause (or, with respect to property owned in common with others, make reasonable effort to cause) the Mortgaged and Pledged Property, considered as a whole, to be maintained and kept in good condition, repair and working order and shall cause (or, with respect to property owned in common with others, make reasonable effort to cause) to be made such repairs, renewals, replacements, betterments and improvements thereof, as, in the judgment of the Company, may be necessary in order that the operation of the Mortgaged and Pledged Property, considered as a whole, may be conducted in accordance with common industry practice; provided, however, that nothing in this Section shall prevent the Company from discontinuing, or causing the discontinuance of, the operation and maintenance of any portion of the Mortgaged and Pledged Property if such discontinuance is in the judgment of the Company desirable in the conduct of its business; and provided, further, that nothing in this Section shall prevent the Company from selling, transferring or otherwise disposing of, or causing the sale, transfer or other disposition of, any portion of the Mortgaged and Pledged Property in compliance with the other provisions of this Indenture.”

SECTION 2.08. Excepted Property. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend the paragraph on pages 10-11 of the Mortgage (and the corresponding provision in each supplemental indenture thereto) to add any one or more of the following types of property to the list of Excepted Property:

(a) any vessels, boats, barges, and other marine equipment;

(b) any personal property of such character that the perfection of a security interest therein or other Lien thereon is not governed by the Uniform Commercial Code as in effect in the jurisdiction in which the Company is organized or the property is located;

(c) any general intangibles, including computer software;

(d) any patents, patent licenses and other patent rights, patent applications, trade names, trademarks, copyrights and other intellectual property;

(e) any governmental and other licenses, permits and franchises (other than the Company’s franchises, permits and licenses that are transferable and necessary for the operation of the Mortgaged and Pledged Property); or

(f) any unrecorded easements and rights of way.

SECTION 2.09. Mergers into the Company. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 85 of the Mortgage, as amended and supplemented, to add a new paragraph reading substantially as follows:

“Nothing in this Indenture shall be deemed to prevent or restrict any consolidation or merger after the consummation of which the Company would be the surviving or resulting corporation or any conveyance or other transfer, or lease, of any part of the Mortgaged and Pledged Property which does not constitute the entirety or substantially the entirety of the Mortgaged and Pledged Property. Unless, in the case of a consolidation or merger described in the preceding sentence, an indenture supplemental hereto shall otherwise provide, this Indenture shall not become or be, or be required to become or be, a Lien upon any of the properties acquired by the Company in or as a result of such transaction or any improvements, extensions or additions to such properties or any renewals, replacements or substitutions of or for any part or parts thereof.”

SECTION 2.10. Transfer of Less than Substantially All. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 85 of the Mortgage, as amended and supplemented, to add a new paragraph reading substantially as follows:

“A conveyance, transfer or lease by the Company of any part of the Mortgaged and Pledged Property shall not be deemed to constitute the conveyance, transfer or lease of all or substantially all of the Mortgaged and Pledged Property as an entirety for purposes of this Indenture if the Fair Value of the Mortgaged and Pledged Property retained by the Company exceeds the Reciprocal of the Bonding Ratio multiplied by the sum of the aggregate principal amount of all Outstanding bonds and any other outstanding debt of the Company secured by a purchase money lien that ranks equally with, or senior to, the bonds with respect to such Mortgaged and Pledged Property. Such Fair Value shall

be established by the delivery to the Corporate Trustee of an Independent Engineer’s Certificate stating the Independent Engineer’s opinion of such Fair Value as of a date not more than 90 days before or after such conveyance, transfer or lease. This Article XVI is not intended to limit the Company’s conveyances, transfers or leases of less than substantially the entirety of the Mortgaged and Pledged Property or to create an inference that any conveyance, transfer or lease of any part of the Mortgaged and Pledged Property shall necessarily be deemed to constitute a conveyance, transfer or lease of all or substantially all of the Mortgaged and Pledged Property as an entirety for purposes of this Indenture where the Fair Value of the Mortgaged and Pledged Property retained by the Company is less than the Reciprocal of the Bonding Ratio multiplied by the aggregate principal amount of all Outstanding bonds and any other outstanding debt of the Company secured by a purchase money lien that ranks equally with, or senior to, the bonds with respect to such Mortgaged and Pledged Property.”

SECTION 2.11. Corporate Trustee Replacement. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 101 of the Mortgage, as amended and supplemented, to add a new paragraph reading substantially as follows:

“So long as no event which is, or after notice or lapse of time, or both, would become, a Default shall have occurred and be continuing, and except with respect to a Corporate Trustee appointed by the bondholders as provided in Section 102 hereof, if the Company shall have delivered to the Corporate Trustee (i) resolutions of the Board of Directors appointing a successor Corporate Trustee, effective as of a date specified therein, and (ii) an instrument of acceptance of such appointment, effective as of such date, by such successor Corporate Trustee in accordance with Section 104 hereof, the Corporate Trustee shall be deemed to have resigned as contemplated in the first sentence of Section 101 hereof, the successor Corporate Trustee shall be deemed to have been appointed by the Company pursuant to Section 102 hereof and such appointment shall be deemed to have been accepted as contemplated in Section 104 hereof, all as of such date, and all other provisions of Sections 101, 102 and 104 hereof shall be applicable to such resignation, appointment and acceptance except to the extent inconsistent with this paragraph.”

SECTION 2.12. Terms of New Series of Bonds. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 8 of the Mortgage, as amended and supplemented,

(A) to add the words “or an Authorized Officer” after the words “Board of Directors of the Company” in the first sentence of Section 8,

(B) to change the words “Resolution of the Board of Directors of the Company” in the second sentence of Section 8 to “Resolution, supplemental indenture or Officers’ Certificate”,

(C) to change the words “the Board of Directors” in the fifth sentence of Section 8 to “Resolution, supplemental indenture or Officers’ Certificate”,

(D) to add the words “or an Authorized Officer” after the words “Board of Directors” in the sixth sentence of Section 8 and in clause (c) of Section 8.

SECTION 2.13. Investment of Money Held by Corporate Trustee. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 118 of the Mortgage, as amended and supplemented, (A) to delete the parenthetical in the first sentence of Section 118, (B) to delete the words “evidenced by a Resolution” in the first sentence of Section 118, and (C) to add a sentence after the first sentence in Section 118 reading substantially as follows:

“Any money which is held by the Corporate Trustee for the purpose of effecting the purchase, payment or redemption of any bonds issued hereunder, or the payment of any interest on such bonds, shall only be invested in bonds or other obligations maturing on or before the date specified for such purchase, payment or redemption.”

SECTION 2.14. Officer’s Certificates. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, (A) to change the words “Officers’ Certificate” to “Officer’s Certificate” wherever used in the Mortgage and any supplemental indenture thereto, including the amendments described in this Article II, and (B) to restate the definition of “Officers’ Certificate” in Section 3 of the Mortgage, as amended and supplemented, to read substantially as follows:

“The term “Officer’s Certificate” shall mean a certificate signed by an Authorized Officer. If and to the extent required by the provisions of Section 121 hereof, each such certificate shall include the statements provided for in said Section.”

SECTION 2.15. Majority Vote or Consent. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Article XIX of the Mortgage, as amended and supplemented, to read substantially as follows:

“ARTICLE XIX.

Meetings and Consents of Bondholders.

SECTION 107. Modifications and alterations of this Indenture and/or of any indenture supplemental hereto and/or of the rights and obligations of the Company and/or of the rights of the holders of bonds and coupons issued hereunder may be made as provided in this Article XIX.

SECTION 108. The Corporate Trustee may at any time call a meeting of the holders of bonds of one or more, or all, series and it shall call such a meeting on written request of the Company, given pursuant to a Resolution of its Board of Directors, or a resolution of the holders of a majority or more in principal amount of the bonds of such series Outstanding hereunder, considered as one class, at the time of such request. In the event of the Corporate Trustee’s failing for ten (10) days to call a meeting after being thereunto requested by the Company or bondholders as above set forth, holders of Outstanding bonds in the amount above specified in this Section or the Company, pursuant to Resolution of its Board of Directors, may call such meeting. Every such meeting called by and at the instance of the Corporate Trustee shall be held in the Borough of Manhattan, The City of New York, or with the written approval of the Company, at any other place in the United States of America, and written notice thereof, stating the place and time thereof and in general terms the business to be submitted, shall be mailed by the Corporate Trustee not less than thirty (30) days before such meeting (a) to each registered holder of bonds of the series in respect of which such meeting is being called

then Outstanding hereunder addressed to him at his address appearing on the registry books, (b) to all other holders of bonds of such series then Outstanding hereunder the names and addresses of whom are preserved by the Corporate Trustee as required by the provisions of Section 43 hereof and (c) to the Company addressed to it at 220 N.W. Second Avenue, Portland, Oregon 97209 (or at such other address as may be designated by the Company from time to time), and, if any bonds of such series shall not be in fully registered form, shall be published by the Corporate Trustee at least once a week for four (4) successive calendar weeks immediately preceding the meeting, upon any secular day of each such calendar week, which need not be the same day of each week, in a Daily Newspaper, printed in the English language, and published and of general circulation in The City of New York; provided, however, that, if such notice by publication shall have been given, the mailing of such notice to any bondholders shall in no case be a condition precedent to the validity of any action taken at such meeting. Any meeting of holders of the bonds of one or more, or all, series shall be valid without notice if the holders of all bonds of such series then Outstanding hereunder are present in person or by proxy and if the Company and the Corporate Trustee are present by duly authorized representatives, or if notice is waived in writing before or after the meeting by the Company, the holders of all bonds of such series Outstanding hereunder and by the Corporate Trustee, or by such of them as are not present in person or by proxy.

SECTION 109. Officers and nominees of the Corporate Trustee and of the Company or their or its nominees may attend such meeting, but shall not as such be entitled to vote thereat. Attendance by bondholders may be in person or by proxy. In order that the holder of any bond payable to bearer and his proxy may attend and vote without producing his bond, the Corporate Trustee, with respect to any such meeting, may make and from time to time vary such regulations as it shall think fit for deposit of bonds with, (i) any bank or trust or insurance company, or (ii) any trustee, secretary, administrator or other proper officer of any pension, welfare, hospitalization, or similar fund or funds, or (iii) the United States of America, any Territory thereof, the District of Columbia, any State of the United States, any municipality in any State of the United States or any public instrumentality of the United States, any State or Territory, or (iv) any other person or corporation satisfactory to the Corporate Trustee, and for the issue to the persons depositing the same of certificates by such depositaries entitling the holders thereof to be present and vote at any such meeting and to appoint proxies to represent them and vote for them at any such meeting in the same way as if the persons so present and voting, either personally or by proxy, were the actual bearers of the bonds in respect of which such certificates shall have been issued and any regulations so made shall be binding and effective. In lieu of or in addition to providing for such deposit, the Corporate Trustee may, in its discretion, permit such institutions to issue certificates stating that bonds were exhibited to them, which certificates shall entitle the holders thereof to vote at any meeting only if the bonds with respect to which they are issued are not produced at the meeting by any other person and are not at the time of the meeting registered in the name of any other person. Each such certificate shall state the date on which the bond or bonds in respect of which such certificate shall have been issued were deposited with or exhibited to such institution and the series, maturities and serial numbers of such bonds. A bondholder in any of the foregoing categories may sign such a certificate in his own behalf. In the event that two or more such certificates shall be issued with respect to any bond or bonds, the certificate bearing the latest date shall be recognized and be deemed to supersede any certificate or certificates previously issued with respect to such bond or bonds. If any such meeting shall have been called under the provisions of Section 108 hereof, by bondholders or by the Company, and the Corporate Trustee shall fail to make regulations as above authorized, then regulations to like effect for such deposit, or exhibition of bonds and the issue of certificates by (i) any bank or trust or insurance company, or (ii) any trustee, secretary, administrator or other proper officer of any pension, welfare, hospitalization, or similar fund or funds, or (iii) by the United States of America, any Territory thereof,

the District of Columbia, any State of the United States, any municipality in any State of the United States or any public instrumentality of the United States, any State or Territory shall be similarly binding and effective for all purposes hereof if adopted or approved by the bondholders calling such meeting or by the Board of Directors of the Company, if such meeting shall have been called by the Company, provided that in either such case copies of such regulations shall be filed with the Corporate Trustee. A bondholder in any of the foregoing categories may sign such a certificate in his own behalf.

SECTION 110. Subject to the restrictions specified in Sections 109 and 113 hereof, any registered holder of bonds Outstanding hereunder and any holder of a certificate (not superseded) provided for in Section 109 hereof relating to bonds Outstanding hereunder, in either case of the series in respect of which a meeting shall have been called, shall be entitled in person or by proxy to attend and vote at such meeting as a holder of the bonds registered or certified in the name of such holder without producing such bonds. All others seeking to attend or vote at such meeting in person or by proxy must, if required by any authorized representative of the Corporate Trustee or the Company or by any other bondholder, produce the bonds claimed to be owned or represented at such meeting and every one seeking to attend or vote shall, if required as aforesaid, produce such further proof of bond ownership or personal identity as shall be satisfactory to the authorized representative of the Corporate Trustee, or if none be present then to the Inspectors of Votes hereinafter provided for. Proxies shall be witnessed or in the alternative may (a) have the signature guaranteed by a bank or trust company or a registered dealer in securities participating in a recognized signature guarantee medallion program, (b) be acknowledged before a Notary Public or other officer authorized to take acknowledgements, or (c) have their genuineness otherwise established to the satisfaction of the Inspector of Votes. All proxies and certificates presented at any meeting shall be delivered to said Inspectors of Votes and filed with the Corporate Trustee.

SECTION 111. Persons nominated by the Corporate Trustee if it is represented at the meeting shall act as temporary Chairman and Secretary, respectively, of the meeting, but if the Corporate Trustee shall not be represented or shall fail to nominate such persons or if any person so nominated shall not be present, the bondholders and proxies present shall by a majority vote of bonds represented elect another person or other persons from those present to act as temporary Chairman and/or Secretary. A permanent Chairman and a permanent Secretary of such meeting shall be elected from those present by the bondholders and proxies present by a majority vote of bonds represented. The Corporate Trustee, if represented at the meeting, shall appoint two Inspectors of Votes who shall decide as to the right of anyone to vote and shall count all votes cast at such meeting, except votes on the election of a Chairman and Secretary, both temporary and permanent, as aforesaid, and who shall make and file with the permanent Secretary of the meeting their verified written report in duplicate of all such votes so cast at said meeting. If the Corporate Trustee shall not be represented at the meeting or shall fail to nominate such Inspectors of Votes or if either Inspector of Votes fails to attend the meeting, the vacancy shall be filled by appointment by the permanent Chairman of the meeting.

SECTION 112. The holders of a majority in aggregate principal amount of the bonds Outstanding hereunder of the series with respect to which a meeting shall have been called as hereinbefore provided, considered as one class, shall constitute a quorum for a meeting of holders of bonds of such series; provided, that if any action is to be taken at such meeting which this Indenture expressly provides may be taken by the holders of a specified percentage which is less than a majority in principal amount of the bonds of such series Outstanding hereunder, considered as one class, then the holders of such specified percentage in principal amount of the bonds of such series Outstanding hereunder, considered as one class, shall constitute a quorum. In the absence of a quorum within one hour of the time appointed for any such meeting, the meeting shall, if convened at the request of

holders of bonds of such series, be dissolved. In any other case the meeting may be adjourned for such period or periods as may be determined and announced by the chairman of the meeting prior to the adjournment thereof.

SECTION 113. Any modification or alteration of this Indenture and/or of any indenture supplemental hereto and/or of the rights and obligations of the Company and/or the rights of the holders of bonds and/or coupons issued hereunder in any particular may be made at a meeting of bondholders duly convened and held in accordance with the provisions of this Article, but only by resolution duly adopted by the affirmative vote of the holders of a majority in principal amount of the bonds Outstanding hereunder, considered as one class (or, if such modification or alteration shall materially adversely affect the holders of bonds of one or more, but less than all, series then Outstanding hereunder, then the affirmative vote only of the holders of a majority in aggregate principal amount of the bonds of the series adversely affected in any material respect then Outstanding hereunder, considered as one class), when such meeting is held, and in every case approved by Resolution of the Board of Directors of the Company as hereinafter specified; provided, however, that no such modification or alteration shall, without the consent of the holder of any bond issued hereunder affected thereby, permit (1) the extension of the maturity of the principal of, or interest on, such bond, or (2) the reduction in such principal or the rate of interest thereon or any other modification in the terms of payment of such principal or interest, or (3) the creation of any lien ranking prior to, or on a parity with, the Lien of this Indenture with respect to any of the Mortgaged and Pledged Property, or (4) the deprivation of any non-assenting bondholder of a lien upon the Mortgaged and Pledged Property for the security of his bonds (subject only to Excepted Encumbrances) or (5) the reduction of the percentage required by the provisions of this Section for the taking of any action under this Section with respect to any bond Outstanding hereunder. For all purposes of this Article, the Trustees shall be entitled to rely upon an Opinion of Counsel with respect to the extent, if any, as to which any action taken at such meeting affects the rights under this Indenture or under any indenture supplemental hereto of any holders of bonds then Outstanding hereunder.

Bonds owned and/or held by and/or for account of and/or for the benefit or interest of the Company, or any corporation of which the Company shall own twenty-five per centum (25%) or more of the outstanding voting stock, shall not be deemed Outstanding for the purpose of any vote or of any calculation of bonds Outstanding in Article XVI hereof or in this Article XVIII or for the purpose of the quorum provided for in Section 112 of this Article; provided, however, that bonds so owned or held which have been pledged in good faith may be regarded as Outstanding for purposes of this paragraph if the pledgee establishes to the satisfaction of the Corporate Trustee the pledgee’s right to vote or give consents with respect to such bonds and that the pledgee is not the Company or a corporation of which the Company shall own twenty-five per centum (25%) or more of the outstanding voting stock. For all purposes of this Indenture, the Corporate Trustee, the Chairman and Secretary of any meeting held pursuant to the provisions of this Article XIX and the Inspectors of Votes at any such meeting shall (unless the fact is challenged at such meeting by any holder of bonds Outstanding hereunder entitled to vote at such meeting and a contrary fact is established) be entitled conclusively to rely upon a notification in writing by an officer of the Company, specifying the principal amount of bonds Outstanding hereunder owned by or held by or for the account of or for the benefit or interest of the Company or any corporation of which the Company shall own twenty-five per centum (25%) or more of the outstanding voting stock, or stating that no such bonds are so owned or held. In case the meeting shall have been called otherwise than on the written request of the Company, the Corporate Trustee shall be entitled conclusively to assume that none of the bonds Outstanding hereunder is so owned or held unless a notification by the Company is furnished as in

this paragraph provided or unless the fact is challenged at such meeting by any holder of bonds Outstanding hereunder and a contrary fact is established.

SECTION 114. A record in duplicate of the proceedings of each meeting of bondholders shall be prepared by the permanent Secretary of the meeting and shall have attached thereto the original reports of the Inspectors of Votes, and affidavits by one or more persons having knowledge of the facts showing a copy of the notice of the meeting, and showing that said notice was mailed and published as provided in Section 108 hereof. Such record shall be signed and verified by the affidavit of the permanent Chairman and the permanent Secretary of the meeting, and one duplicate thereof shall be delivered to the Company and the other to the Corporate Trustee for preservation by the Corporate Trustee. Any record so signed and verified shall be proof of the matters therein stated, and if such record shall also be signed and verified by the affidavit of a duly authorized representative of the Corporate Trustee, such meeting shall be deemed conclusively to have been duly convened and held and such record shall be conclusive, and any resolution or proceeding stated in such record to have been adopted or taken, shall be deemed conclusively to have been duly adopted or taken by such meeting. A true copy of any resolution adopted by such meeting shall be mailed by the Corporate Trustee (a) to each registered holder of bonds of the series adversely affected in any material respect by such resolution then Outstanding addressed to him at his address appearing on the registry books and (b) to all other holders of bonds then Outstanding hereunder, the names and addresses of whom are then preserved by the Corporate Trustee pursuant to the provisions of Section 43 hereof, and proof of such mailing by the affidavit of some person having knowledge of the fact shall be filed with the Corporate Trustee, but failure to mail copies of such resolution as aforesaid shall not affect the validity thereof. No such resolution shall be binding until and unless such resolution is approved by Resolution of the Board of Directors of the Company, of which such Resolution of approval, if any, it shall be the duty of the Company to file a copy certified by the Secretary or an Assistant Secretary of the Company with the Corporate Trustee, but if such Resolution of the Board of Directors of the Company is adopted and a certified copy thereof is filed with the Corporate Trustee, the resolution so adopted by such meeting shall (to the extent permitted by law) be deemed conclusively to be binding upon the Company, the Trustees and the holders of all bonds and coupons issued hereunder, at the expiration of sixty (60) days after such filing, except in the event of a final decree of a court of competent jurisdiction setting aside such resolution, or annulling the action taken thereby in a legal action or equitable proceeding for such purposes commenced within such sixty (60) day period; provided, however, that no such resolution of the bondholders, or of the Company, shall in any manner be so construed as to change or modify any of the rights, immunities, or obligations of the Trustees or either of them without their, its or his written assent thereto.

SECTION 115. Bonds authenticated and delivered after the date of any bondholders’ meeting may bear a notation in form approved by the Corporate Trustee as to the action taken at meetings of bondholders theretofore held, and upon demand of the holder of any bond Outstanding at the date of any such meeting and presentation of his bond for the purpose at the principal office of the Corporate Trustee, the Company shall cause suitable notation to be made on such bond by endorsement or otherwise as to any action taken at any meeting of bondholders theretofore held. If the Company or the Corporate Trustee shall so determine, new bonds so modified as in the opinion of the Corporate Trustee and the Board of Directors of the Company to conform to such bondholders’ resolution shall be prepared, authenticated and delivered, and upon demand of the holder of any bond then Outstanding and affected thereby shall be exchanged without cost to such bondholders for bonds then Outstanding hereunder upon surrender of such bonds with all unmatured coupons, if any, appertaining thereto. The Company or the Corporate Trustee may require bonds Outstanding to be presented for notation or exchange as aforesaid if either shall see fit to do so. Instruments supplemental to this Indenture

embodying any modification or alteration of this Indenture or of any indenture supplemental hereto made at any bondholders’ meeting and approved by Resolution of the Board of Directors of the Company, as aforesaid, may be executed by the Trustees and the Company and upon demand of the Corporate Trustee, or if so specified in any resolution adopted by any such bondholders’ meeting, shall be executed by the Company and the Trustees.

Any instrument supplemental to this Indenture executed pursuant to the provisions of this Section or otherwise, shall comply with all applicable provisions of the Trust Indenture Act of 1939 as in force on the date of the execution of such supplemental indenture.

SECTION 116. (A) Anything in this Article XIX contained to the contrary notwithstanding, the Corporate Trustee shall receive the written consent (in any number of instruments of similar tenor executed by bondholders or by their attorneys appointed in writing or in the supplemental indenture or supplemental indentures creating such series of bonds) of the holders of a majority in principal amount of the bonds Outstanding hereunder, considered as one class (or, if any action proposed to be taken shall materially adversely affect the holders of bonds of one or more, but less than all, series then Outstanding hereunder, then the consent only of the holders of a majority in aggregate principal amount of bonds of the series so adversely affected in any material respect then Outstanding hereunder, considered as one class), at the time the last such needed consent is delivered to the Corporate Trustee, in lieu of the holding of a meeting pursuant to this Article XIX and in lieu of all action at such a meeting and with the same force and effect as a resolution duly adopted in accordance with the provisions of Section 113 hereof.

(B)Instruments of consent shall be witnessed or in the alternative may (a) have the signature guaranteed by a bank or trust company or a registered dealer in securities participating in a recognized signature guarantee medallion program, (b) be acknowledged before a Notary Public or other officer authorized to take acknowledgments, or (c) have their genuineness otherwise established to the satisfaction of the Corporate Trustee.

The amount of bonds payable to bearer, and the series and serial numbers thereof, held by a person executing an instrument of consent (or whose attorney has executed an instrument of consent in his behalf), and the date of his holding the same, may be proved by exhibiting the bonds to and obtaining a certificate executed by (i) any bank or trust or insurance company organized under the laws of the United States of America or of any State thereof, or (ii) any trustee, secretary, administrator or other proper officer of any pension, welfare, hospitalization or similar fund or funds, or (iii) the United States of America, any Territory thereof, the District of Columbia, any State of the United States, any municipality in any State of the United States or any public instrumentality of the United States, or of any State or of any Territory, or (iv) any other person or corporation satisfactory to the Corporate Trustee. A bondholder in any of the foregoing categories may sign a certificate in his own behalf.

Each such certificate shall be dated and shall state in effect that as of the date thereof a coupon bond or bonds bearing a specified serial number or numbers was exhibited to the signer of such certificate. The holding by the person named in any such certificate of any bonds specified therein shall be presumed to continue unless (1) any certificate bearing a later date issued in respect of the same bond shall be produced, (2) the bond specified in such certificate (or any bond or bonds issued in exchange or substitution for such bond) shall be produced, or (3) the bond specified in such certificate shall be registered as to principal in the name of another holder or shall have been surrendered in exchange or a fully registered bond registered in the name of another holder. The

Corporate Trustee may nevertheless in its discretion require further proof in cases where it deems further proof desirable. The ownership of registered bonds shall be proved by the registry books.

(C)Until such time as the Corporate Trustee shall receive the written consent of the necessary per centum in principal amount of the bonds required by the provisions of subsection (A) above for action contemplated by such consent, any holder of a bond, the serial number of which is shown by the evidence to be included in the bonds the holders of which have consented to such action, may, by filing written notice with the Corporate Trustee at its principal office and upon proof of holding as provided in subsection (B) above, revoke such consent so far as it concerns such bond unless such consent states that it shall be irrevocable or is set forth in the supplemental indenture creating such series of bonds. Except as aforesaid, any such action taken by the holder of any bond shall be conclusive and binding upon such holder and upon all future holders of such bond (and any bond issued in lieu thereof or exchanged therefor), irrespective of whether or not any notation of such consent is made upon such bond, and in any event any action taken by the holders of the percentage in aggregate principal amount of the bonds specified in subsection (A) above in connection with such action shall be conclusively binding upon the Company, the Corporate Trustee and the holders of all the bonds.”

SECTION 2.16. Amendments without the Consent of Bondholders. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 120 of the Mortgage, as amended and supplemented, to read substantially as follows:

“SECTION 120. Anything in this Indenture to the contrary notwithstanding, without the consent of any holders of bonds, the Company and the Trustees, at any time and from time to time, may enter into one or more indentures supplemental hereto, in form satisfactory to the Trustees, for any of the following purposes:

(a)to evidence the succession of another corporation to the Company and the assumption by any such successor of the covenants of the Company herein and in the bonds, all as provided in Article XVI hereof, or

(b)to add one or more covenants of the Company or other provisions for the benefit of all holders of the bonds or for the benefit of the holders of, or to remain in effect only so long as there shall be Outstanding, bonds of one or more specified series, and to make the occurrence of a default in the performance of any of such additional covenants an additional “Default” under Section 65 permitting the enforcement of all or any of the several remedies provided in this Indenture, as herein set forth; provided, however, that in respect of any such additional covenant, such supplemental indenture may provide for a particular period of grace after default (which period may be shorter or longer than those allowed in the case of other defaults) or may provide for an immediate enforcement upon such default, or may (subject to the provisions of applicable law) limit the remedies available to the Trustees upon such default; or to provide that the occurrence of one or more specified events shall constitute additional “Defaults” under Section 65 as if set forth therein, or to surrender any right or power herein conferred upon the Company, which additional “Default” or surrender may be limited so as to remain in effect only so long as bonds of one or more specified series shall remain Outstanding; or

(c)to correct or amplify the description of any property at any time subject to the Lien of this Indenture, or better to assure, convey and confirm unto the Trustees any property

subject or required to be subjected to the Lien of this Indenture, or to subject to the Lien of this Indenture additional property; or

(d)to change or eliminate any provision of this Indenture or to add any new provision to this Indenture; provided, however, that no such change, elimination or addition shall adversely affect the interests of the holders of bonds of any series in any material respect; or

(e)to establish the form or terms of bonds of any series as contemplated by Article II of this Indenture; or

(f)to provide for the procedures required to permit the Company to utilize, at its option, a non-certificated system of registration for all or any series of bonds; or

(g)to change any place or places (within the United States of America) where (1) the principal of and premium, if any, and interest, if any, on all or any series of bonds shall be payable, (2) all or any series of bonds may be surrendered for registration of transfer, (3) all or any series of bonds may be surrendered for exchange and (4) notices and demands to or upon the Company in respect of all or any series of bonds and this Indenture may be served; or

(h)to cure any ambiguity, to correct or supplement any provision herein which may be defective or inconsistent with any other provision herein; or to make any other changes to the provisions hereof or to add other provisions with respect to matters or questions arising under this Indenture, provided that such other changes or additions shall not adversely affect the interests of the holders of bonds of any series in any material respect.

Without limiting the generality of the foregoing, if the Trust Indenture Act of 1939, as in effect at any time and from time to time,

(x)shall require one or more changes to any provisions hereof or the inclusion herein of any additional provisions, or shall by operation of law be deemed to effect such changes or incorporate such provisions by reference or otherwise, this Indenture shall be deemed to have been amended so as to conform to the Trust Indenture Act of 1939 as then in effect, and the Company and the Trustees may, without the consent of any holders of bonds, enter into an indenture supplemental hereto to evidence such amendment hereof; or

(y)shall permit one or more changes to, or the elimination of, any provisions hereof which shall theretofore have been required by the Trust Indenture Act of 1939 to be contained herein or are contained herein to reflect any provisions of the Trust Indenture Act of 1939, this Indenture shall be deemed to have been amended to effect such changes or elimination, and the Company and the Trustees may, without the consent of any holders of bonds, enter into an indenture supplemental hereto to evidence such amendment hereof, provided that the Indenture shall not be amended as provided in this clause (y) so as to adversely affect the interests of the holders of bonds of any series in any material respect.”

SECTION 2.17. Excepted Encumbrances. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, (A) to delete the definition of “Excepted Encumbrances” in Section 6 of the Mortgage, as amended and supplemented, and

(B) to change the words “Excepted Encumbrances” wherever used in the Mortgage or in any supplemental indenture, including the amendments described in this Article II, to “Permitted Liens”.

SECTION 2.18. Release of Company after Transfer of Substantially All of the Mortgaged Property. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 86 of the Mortgage to add a new paragraph reading substantially as follows:

“In case the Company, as permitted by Section 85 hereof, shall convey or transfer, subject to the Lien of this Indenture, all or substantially all of the Mortgaged and Pledged Property as an entirety to a successor corporation, the indenture described above in this Section may also provide for the release and discharge of the Company from all obligations under this Indenture or any bonds issued hereunder which are assumed by such successor corporation.”

SECTION 2.19. Easements, Ground Leases, Rights-of-Way. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 58 of the Mortgage, as amended and supplemented, to restate clause (2) thereof to read substantially as follows:

“(2) (a) cancel or make changes or alterations in or substitutions of any and all right of way grants; (b) sell or otherwise dispose of, free from the Lien of this Indenture, cancel, make changes or alterations in or substitutions of any and all contracts, leases, operating agreements, obligations, securities, accounts receivable, choses in action, and other rights, interests and property not constituting Property Additions; and (c) grant, free from the Lien of this Indenture, easements, ground leases or rights-of-way in, upon, over and/or across the property or rights-of-way of the Company for the purpose of roads, pipe lines, transmission lines, distribution lines, communication lines, railways, removal or transportation of coal, lignite, gas, oil or other minerals or timber, and other like purposes, or for the joint or common use of real property, rights-of-way, facilities and/or equipment; provided, however, that such grant shall not materially impair the use of the property or rights-of-way for the purposes for which such property or rights-of-way are held by the Company; and”

SECTION 2.20. Elimination of Five Year Limit on Property Additions Used for Releases. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend clause (b) of subdivision (4) of Section 59 of the Mortgage, as amended and supplemented, to delete the words “that no such application for release may be based in whole or in part upon Property Additions acquired, made or constructed more than five years prior to the last day of the calendar month immediately preceding the date of such application, and provided, further,”:

SECTION 2.21. Releases Based on Retired Bonds. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend clause (c) of subdivision (4) of Section 59 of the Mortgage, as amended and supplemented, to read substantially as follows:

“(c) the principal amount of each bond or fraction of bond to the authentication and delivery of which the Company shall be entitled under the provisions of Section 26 or the Reciprocal of the Bonding Ratio multiplied by the principal amount of each bond or fraction of bond to the authentication

and delivery of which the Company shall be entitled under the provisions of Section 29 hereof, by virtue of compliance with all applicable provisions of said Section 26 or Section 29, as the case may be (except as hereinafter in this Section otherwise provided); provided, however, that (except as hereinafter in this Section otherwise provided) the application for such release shall operate as a waiver by the Company of such right to the authentication and delivery of each such bond or fraction thereof on the basis of which right such property is released and to such extent no such bond or fraction thereof may thereafter be authenticated and delivered hereunder, and any Corresponding Retired Bonds or Corresponding Qualified Lien Bonds, as hereinafter defined, shall be deemed to have been made the basis of the release of such property; for purposes of this clause (c), the following definitions shall apply:

The term “Corresponding Retired Bond” shall mean the bond or fraction of a bond selected by the Company to serve as the basis under the provisions of Section 29 of the Mortgage for such right to the authentication and delivery of bond(s) or fraction of a bond so waived; and

The term “Corresponding Qualified Lien Bond” shall mean the Qualified Lien Bond selected by the Company to serve as the basis under the provisions of Section 26 of the Mortgage for such right to the authentication and delivery of bond(s) or fraction of a bond so waived.”

SECTION 2.22. Releases Based on Purchase Money Mortgage Obligations. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 59 of the Mortgage, as amended and supplemented, to delete the clause at the end of subdivision (4) beginning with the words “provided, however, that (i) no obligations ....” and ending with the words “... at such time Outstanding under this Indenture” and substituting therefor substantially the following:

“provided, however, that no obligations secured by a purchase money mortgage upon any property being released from the Lien hereof shall be used as a credit in any application for such release unless the Company shall deliver to the Trustees a certificate or opinion of an engineer, appraiser or other expert as to the fair value of such purchase money mortgage obligations to the Company, and provided further, that if the fair value to the Company of such purchase money mortgage obligations and of all other securities (other than bonds authenticated and delivered hereunder) made the basis of any authentication and delivery of bonds hereunder, the withdrawal of any cash constituting part of the trust estate hereunder, or the release of any property or securities from the Lien hereof since the commencement of the then calendar year, as set forth in the certificates or opinions required by this clause, is ten per centum (10%) or more of the aggregate principal amount of the bonds at the time Outstanding under this Indenture, such certificate or opinion shall be made by an independent engineer, appraiser, or other expert; but such a certificate of an independent engineer, appraiser, or other expert shall not be required with respect to any purchase money mortgage obligations so deposited, if the fair value thereof to the Company as set forth in the certificate or opinion required by this clause is less than twenty-five thousand Dollars ($25,000) or less than one per centum (1%) of the aggregate principal amount of bonds at the time Outstanding under this Indenture.”

SECTION 2.23. Mineral Rights. The Company reserves the right, without any consent, vote or other action by holders of any series of bonds subsequent to the Twenty-second Series or by holders of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, to amend Section 3 of the Mortgage, as amended and supplemented, to add the following definition:

The term “mineral rights”, for purposes of the Mortgage, as amended and supplemented, shall mean rights to extract minerals that naturally exist under or on real property (and associated express and implied rights), but shall exclude any rights or other property constructed, acquired or held by the Company primarily for the purpose of storing and withdrawing gas that has been injected into, or may from time to time be injected into, storage reservoirs or other facilities located on or under real property, whether or not such rights or other property constitute “mineral rights” under applicable law, whether or not such storage reservoirs or other facilities are naturally existing or were constructed, and whether or not such storage reservoirs or other facilities contain some gas that naturally exists in such reservoir or facility.

ARTICLE III.

Consent to Amendments.

SECTION 3.01 Each initial and future holder of bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, by its acquisition of an interest in such bonds, irrevocably (a) consents to the amendments set forth in Article II of this Twenty-second Supplemental Indenture, in each case without any other or further action by any holder of such bonds, and (b) designates the Corporate Trustee, and its successors, as its proxy with irrevocable instructions to vote and deliver written consents on behalf of such holder in favor of such amendments at any bondholder meeting, in lieu of any bondholder meeting, in any consent solicitation or otherwise. The terms of the bonds of the Twenty-first Series with an Issue Date subsequent to November 1, 2016, as set forth in the Twentieth Supplemental Indenture, are hereby amended to include such consent and designation.

ARTICLE IV.

Miscellaneous Provisions.

SECTION 4.01 Subject to the amendments provided for in this Twenty-second Supplemental Indenture, the terms defined in the Mortgage, as heretofore supplemented, shall, for all purposes of this Twenty-second Supplemental Indenture, have the meanings specified in the Mortgage, as heretofore supplemented.

SECTION 4.02 The Trustee hereby accepts the trusts hereby declared, provided, created or supplemented, and agree to perform the same upon the terms and conditions herein and in the Mortgage, as heretofore supplemented, set forth, including the following:

The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Twenty-second Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made by the Company solely. In general each and every term and condition contained in Article XVII of the Mortgage shall apply to and form part of this Twenty-second Supplemental Indenture with the same force and effect as if the same were herein set forth in full, with such omissions, variations and insertions, if any, as may be appropriate to make the same conform to the provisions of this Twenty-second Supplemental Indenture.

SECTION 4.03 Whenever in this Twenty-second Supplemental Indenture any of the parties hereto is named or referred to, this shall, subject to the provisions of Articles XVI and XVII of the Mortgage, be deemed to include the successors or assigns of such party, and all the covenants and agreements in this

Twenty-second Supplemental Indenture contained by or on behalf of the Company or by or on behalf of the Trustee shall bind and inure to the benefit of the respective successors and assigns of such parties whether so expressed or not.

SECTION 4.04 Nothing in this Twenty-second Supplemental Indenture, expressed or implied, is intended, or shall be construed, to confer upon, or to give to, any person, firm or corporation, other than the parties hereto and the holders of the bonds and coupons outstanding under the Mortgage, any right, remedy, or claim under or by reason of this Twenty-second Supplemental Indenture or any covenant, condition, stipulation, promise or agreement hereof, and all the covenants, conditions, stipulations, promises and agreements by or on behalf of the Company as set forth in this Twenty-second Supplemental Indenture shall be for the sole and exclusive benefit of the parties hereto, and of the holders of the bonds and of the coupons outstanding under the Mortgage.

SECTION 4.05 Except to the extent specifically provided herein, no provision of this Twenty-second Supplemental Indenture is intended to reinstate any provisions in the Mortgage which were amended and superseded by the amendments to the Trust Indenture Act of 1939 effective as of November 15, 1990.

SECTION 4.06 This Twenty-second Supplemental Indenture has been executed in several identical counterparts, each of which shall be an original and all of which shall constitute but one and the same instrument.

IN WITNESS WHEREOF, Northwest Natural Gas Company, has caused its corporate name to be hereunto affixed, and this instrument to be signed and sealed by its President or one of its Vice Presidents, and its corporate seal to be attested by its Secretary or one of its Assistant Secretaries for and in its behalf on the 1st day of November, 2016, as of November 1, 2016, in Portland, Oregon; Deutsche Bank Trust Company Americas, has caused its corporate name to be hereunto affixed, and this instrument to be signed and sealed by its Vice Presidents or its Assistant Vice Presidents and its corporate seal to be attested by one of its Vice Presidents, Assistant Vice Presidents, one of its Assistant Secretaries or one of its Associates on the 1st day of November, 2016, as of November 1, 2016, in The City of New York.

NORTHWEST NATURAL GAS COMPANY

By/s/ MardiLyn Saathoff

MardiLyn Saathoff

Senior Vice President, Regulation and General Counsel

Attest:

/s/ Shawn M. Filippi

Shawn M. Filippi

Vice President, Chief Compliance Officer

and Corporate Secretary

Executed, sealed and delivered by

NORTHWEST NATURAL GAS COMPANY

in the presence of:

/s/ Chu Lee

Chu Lee

/s/ Elissa Ann Twombly

Elissa Ann Twombly

DEUTSCHE BANK TRUST COMPANY

AMERICAS, as Trustee,

By___________________________

Vice President

By___________________________

Vice President

Attest:

______________________________

Associate

Executed, sealed and delivered by

DEUTSCHE BANK TRUST COMPANY AMERICAS

in the presence of:

______________________________

Associate

______________________________

Associate

EX-10.1

SPECIAL RETENTION RESTRICTED STOCK UNIT AWARD AGREEMENT

This Agreement is entered into as of September 30, 2016, between Northwest Natural Gas Company, an Oregon corporation (the “Company”), and ________________ (“Recipient”).

Effective on September 30, 2016, the Organization and Executive Compensation Committee (the “Committee”) of the Company’s Board of Directors (the “Board”) awarded restricted stock units to Recipient pursuant to Section 6 of the Company’s Long Term Incentive Plan (the “Plan”). Recipient desires to accept the award subject to the terms and conditions of this Agreement.

NOW, THEREFORE, the parties agree as follows:

1.Grant of Restricted Stock Units; Dividend Equivalents. Subject to the terms and conditions of this Agreement, the Company hereby grants to the Recipient 2,580 restricted stock units (the “RSUs”). The grant of RSUs obligates the Company, upon vesting in accordance with this Agreement, to deliver to the Recipient one share of Common Stock of the Company (a “Share”) for each RSU. Upon vesting of each RSU, the Company also agrees to make a dividend equivalent cash payment with respect to each vested RSU in an amount equal to the total amount of dividends paid per share of Company Common Stock for which the dividend record dates occurred after the date of this Agreement and before the date of delivery of the underlying Shares. The RSUs are subject to forfeiture as set forth in Section 2.9 below.

2.Vesting; Forfeiture Restriction.

1.Vesting Schedule. All of the RSUs shall initially be unvested. Subject to Sections 2.2, 2.3, 2.4, 2.9 and 5.2, the RSUs shall vest as follows:

(a)one-fifth of the RSUs shall vest on March 1, 2018;

(b)an additional one-fifth of the RSUs shall vest on March 1, 2019;

(c)an additional one-fifth of the RSUs shall vest on March 1, 2020; and

(d)the final two-fifths of the RSUs shall vest on March 1, 2021.

2.Effect of Death or Disability. If Recipient’s employment by the Company terminates because of death or physical disability (within the meaning of Section 22(e)(3) of the Internal Revenue Code of 1986 (the “Code”)), all outstanding RSUs shall immediately vest.

3.CIC Acceleration if Party to a Severance Agreement. If Recipient is a party to a Change in Control Severance Agreement with the Company, all outstanding RSUs shall immediately vest if Recipient becomes entitled to a Change in Control Severance Benefit (as defined below). A “Change in Control Severance Benefit” means the severance benefit provided for in Recipient’s Change in Control Severance Agreement with the Company; provided, however, that such severance benefit is a “Change in Control Severance Benefit” for purposes of this Agreement only if, under the terms of Recipient’s Change in Control Severance Agreement, Recipient becomes entitled to the severance benefit (a) after a change in control of the Company has occurred, (b) because Recipient’s employment with the Company has been terminated by Recipient for good reason in accordance with the terms and conditions of the Change in Control Severance Agreement or by the Company other than for cause, and (c) because Recipient has satisfied any other conditions or requirements specified in the Change in Control Severance Agreement and necessary for Recipient to become entitled to receive the severance benefit. For purposes of this Section 2.3, the terms “change in control,” “good reason,” “cause” and “disability” shall have the meanings set forth in Recipient’s Change in Control Severance Agreement.

4.CIC Acceleration if Not a Party to a Severance Agreement. If Recipient is not a party to a Change in Control Severance Agreement with the Company, all outstanding RSUs shall immediately vest if a Change in Control (as defined in Section 2.5 below) occurs and at any time after the earlier of Shareholder Approval (as defined in Section 2.6 below), if any, or the Change in Control and on

or before the second anniversary of the Change in Control, (a) Recipient’s employment is terminated by the Company (or its successor) without Cause (as defined in Section 2.7 below), or (b) Recipient’s employment is terminated by Recipient for Good Reason (as defined in Section 2.8 below).

5.Change in Control. For purposes of this Agreement, a “Change in Control” of the Company shall mean the occurrence of any of the following events:

(a)The consummation of:

(1)any consolidation, merger or plan of share exchange involving the Company (a “Merger”) as a result of which the holders of outstanding securities of the Company ordinarily having the right to vote for the election of directors (“Voting Securities”) immediately prior to the Merger do not continue to hold at least 50% of the combined voting power of the outstanding Voting Securities of the surviving corporation or a parent corporation of the surviving corporation immediately after the Merger, disregarding any Voting Securities issued to or retained by such holders in respect of securities of any other party to the Merger; or

(2)any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets of the Company;

(b)At any time during a period of two consecutive years, individuals who at the beginning of such period constituted the Board (“Incumbent Directors”) shall cease for any reason to constitute at least a majority thereof; provided, however, that the term “Incumbent Director” shall also include each new director elected during such two-year period whose nomination or election was approved by two-thirds of the Incumbent Directors then in office; or

(c)Any person (as such term is used in Section 14(d) of the Securities Exchange Act of 1934, other than the Company or any employee benefit plan sponsored by the Company) shall, as a result of a tender or exchange offer, open market purchases or privately negotiated purchases from anyone other than the Company, have become the beneficial owner (within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934), directly or indirectly, of Voting Securities representing twenty percent (20%) or more of the combined voting power of the then outstanding Voting Securities.

6.Shareholder Approval. For purposes of this Agreement, “Shareholder Approval” shall be deemed to have occurred if the shareholders of the Company approve an agreement entered into by the Company, the consummation of which would result in the occurrence of a Change in Control.

7.Cause. For purposes of this Agreement, “Cause” shall mean (a) the willful and continued failure by Recipient to perform substantially Recipient’s assigned duties with the Company (other than any such failure resulting from incapacity due to physical or mental illness) after a demand for substantial performance is delivered to Recipient by the Company which specifically identifies the manner in which Recipient has not substantially performed such duties, (b) willful commission by Recipient of an act of fraud or dishonesty resulting in economic or financial injury to the Company, (c) willful misconduct by Recipient that substantially impairs the Company’s business or reputation, or (d) willful gross negligence by Recipient in the performance of his or her duties.

8.Good Reason. For purposes of this Agreement, “Good Reason” shall mean the occurrence after Shareholder Approval, if applicable, or the Change in Control, of any of the following circumstances, but only if (x) Recipient gives notice to the Company of Recipient’s intent to terminate employment for Good Reason within 30 days after the later of (1) notice to Recipient of such circumstances, or (2) the Change in Control, and (y) such circumstances are not fully corrected by the Company within 90 days after Recipient’s notice:

(a)the assignment to Recipient of a different title, job or responsibilities that results in a decrease in the level of Recipient’s responsibility; provided that Good Reason shall not exist if Recipient continues to have the same or a greater general level of responsibility for the former Company operations after the Change in Control as Recipient had prior to the Change in Control even though such responsibilities have necessarily changed due to the former Company operations becoming a subsidiary or division of the surviving company;

(b)a reduction by the Company in Recipient’s base salary as in effect immediately prior to the earlier of Shareholder Approval, if applicable, or the Change in Control;

(c)the failure by the Company to continue in effect any employee benefit or incentive plan in which Recipient is participating immediately prior to the earlier of Shareholder Approval, if applicable, or the Change in Control (or plans providing Recipient with at least substantially similar benefits) other than as a result of the normal expiration of any such plan in accordance with its terms as in effect immediately prior to the earlier of Shareholder Approval, if applicable, or the Change in Control, or the taking of any action, or the failure to act, by the Company which would adversely affect Recipient’s continued participation in any of such plans on at least as favorable a basis to Recipient as is the case immediately prior to the earlier of Shareholder Approval, if applicable, or the Change in Control or which would materially reduce Recipient’s benefits in the future under any of such plans or deprive Recipient of any material benefit enjoyed by Recipient immediately prior to the earlier of Shareholder Approval, if applicable, or the Change in Control;

(d)the failure by the Company to provide and credit Recipient with the number of paid vacation days to which Recipient is then entitled in accordance with the Company’s normal vacation policy as in effect immediately prior to the earlier of Shareholder Approval, if applicable, or the Change in Control; or

(e)the Company’s requiring Recipient to be based more than 30 miles from where Recipient’s office is located immediately prior to the earlier of Shareholder Approval, if applicable, or the Change in Control except for required travel on the Company’s business to an extent substantially consistent with the business travel obligations which Recipient undertook on behalf of the Company prior to the earlier of Shareholder Approval, if applicable, or the Change in Control.

9.Forfeiture; Possible Restoration. If Recipient ceases to be employed by the Company for any reason or for no reason, with or without cause, other than because of death or physical disability (within the meaning of Section 22(e)(3) of the Code), any RSUs that did not vest pursuant to this Section 2 or Section 5.2 at or prior to the time of such termination of employment shall be forfeited to the Company; provided, however, that if Recipient’s employment is terminated by the Company without Cause or by the Recipient for Good Reason after Shareholder Approval but before a Change in Control, any RSUs that are forfeited under this sentence shall be restored to the Recipient and vested if a Change in Control subsequently occurs within two years.

3.Delivery. Subject to applicable tax withholding, on a date (a “Payment Date”) as soon as practicable after any of the RSUs become vested, the Company shall deliver to Recipient (a) the number of Shares underlying the RSUs that vested (rounded down to the nearest whole share), and (b) the dividend equivalent cash payment determined under Section 1 with respect to the number of Shares that are delivered. Notwithstanding the terms of the Company’s Deferred Compensation Plan for Directors and Executives (the “DCP”), the Shares and dividend equivalent cash payment payable pursuant to this Agreement shall not be eligible for deferral under the DCP.

4.Tax Withholding.

1.Recipient acknowledges that, on any Payment Date when Shares are delivered to Recipient, the Value (as defined below) on that date of the Shares so delivered (as well as the amount of the related dividend equivalent cash payment) will be treated as ordinary compensation income for federal and state income and FICA tax purposes, and that the Company will be required to withhold taxes on these income amounts. To satisfy the required withholding amount, the Company shall first withhold all

or part of the dividend equivalent cash payment, and if that is insufficient, the Company shall withhold the number of Shares having a Value equal to the remaining withholding amount. For purposes of this Section 4, the “Value” of a Share shall be equal to the closing market price for Company Common Stock on the last trading day preceding the Payment Date.

2.Notwithstanding the foregoing, Recipient may elect not to have Shares withheld to cover taxes by giving notice to the Company in writing prior to the Payment Date, in which case the Shares shall be issued or acquired in Recipient’s name on the Payment Date thereby triggering the tax consequences, but the Company shall retain the certificate for the Shares as security until Recipient shall have paid to the Company in cash any required tax withholding not covered by withholding of the dividend equivalent cash payment.

5.Sale of the Company. If there shall occur a merger, consolidation or plan of exchange involving the Company pursuant to which the outstanding shares of Common Stock of the Company are converted into cash or other stock, securities or property, or a sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets of the Company, then either:

1.the unvested RSUs shall be converted into restricted stock units for stock of the surviving or acquiring corporation in the applicable transaction, with the amount and type of shares subject thereto to be conclusively determined by the Committee, taking into account the relative values of the companies involved in the applicable transaction and the exchange rate, if any, used in determining shares of the surviving corporation to be held by the former holders of the Company’s Common Stock following the applicable transaction, and disregarding fractional shares; or

2.all of the unvested RSUs shall immediately vest and the underlying Shares and related dividend equivalent cash payment shall be delivered simultaneously with the closing of the applicable transaction such that Recipient will participate as a shareholder in receiving proceeds from such transaction with respect to those Shares.

6.Changes in Capital Structure.

1.If, prior to the full vesting of all of the RSUs granted under this Agreement, the outstanding Common Stock of the Company is increased or decreased or changed into or exchanged for a different number or kind of shares or other securities of the Company by reason of any stock split, combination of shares or dividend payable in shares, recapitalization or reclassification, appropriate adjustment shall be made by the Committee in the number and kind of shares subject to the unvested RSUs so that Recipient’s proportionate interest before and after the occurrence of the event is maintained. Notwithstanding the foregoing, the Committee shall have no obligation to effect any adjustment that would or might result in the issuance of fractional shares, and any fractional shares resulting from any adjustment may be disregarded or provided for in any manner determined by the Committee. Any such adjustments made by the Committee shall be conclusive.

2.If the outstanding Common Stock of the Company is hereafter converted into or exchanged for all of the outstanding Common Stock of a corporation (the “Parent Successor”) as part of a transaction (the “Transaction”) in which the Company becomes a wholly-owned subsidiary of Parent Successor, then (a) the obligations under this Agreement shall be assumed by Parent Successor and references in this Agreement to the Company shall thereafter generally be deemed to refer to Parent Successor, (b) Common Stock of Parent Successor shall be issued in lieu of Common Stock of the Company under this Agreement, (c) employment by the Company for purposes of Section 2 of this Agreement shall include employment by either the Company or Parent Successor, and (d) the dividend equivalent cash payments under this Agreement shall be based on dividends paid on the Common Stock of the Company prior to the Transaction and Parent Successor after the Transaction.

7.Recoupment On Misconduct.

1.If the Committee determines that Recipient engaged in any Misconduct (as defined below) after the date of this Agreement and prior to a sale of any of the Shares (the “Tainted Shares”), and

this determination is made before a Change in Control and within three years after the vesting of the Tainted Shares, Recipient shall repay to the Company the Excess Proceeds (as defined below). The Committee may, in its sole discretion, reduce the amount of Excess Proceeds to be repaid by Recipient to take into account the tax consequences of such repayment or any other factors. The return of Excess Proceeds is in addition to and separate from any other relief available to the Company due to Recipient’s Misconduct.

2.“Misconduct” shall mean (a) willful commission of an act of fraud or dishonesty resulting in economic or financial injury to the Company, (b) willful misconduct that substantially impairs the Company’s business or reputation, or (c) willful gross negligence in the performance of the person’s duties; provided, however, that such acts shall only constitute Misconduct if the Committee determines that such acts contributed to an obligation to restate the Company’s financial statements for any quarter or year or otherwise had (or will have when publicly disclosed) an adverse impact on the market price of the Company Common Stock.

3.“Excess Proceeds” shall mean the excess of (a) the actual aggregate sales proceeds from Recipient’s sales of Tainted Shares, over (b) the aggregate sales proceeds Recipient would have received from sales of Tainted Shares at a price per share determined appropriate by the Committee in its discretion to reflect what the market price of the Company Common Stock would have been if the restatement had occurred or other Misconduct had been disclosed prior to such sales.

4.The Company may seek direct repayment from Recipient of any Excess Proceeds and may, to the extent permitted by applicable law, offset such amount against any compensation or other amounts owed by the Company to Recipient. In particular, such amount may be recovered by offset against the after-tax proceeds of deferred compensation payouts under the DCP, the Company’s Executive Supplemental Retirement Income Plan or the Company’s Supplemental Executive Retirement Plan at the times such deferred compensation payouts occur under the terms of those plans. Amounts that remain unpaid for more than 60 days after demand by the Company shall accrue interest at the rate used from time to time for crediting interest under the DCP.

8.Approvals. The issuance by the Company of authorized and unissued shares or reacquired shares under this Agreement is subject to the approval of the Oregon Public Utility Commission and the Washington Utilities and Transportation Commission, but no such approvals shall be required for the purchase of shares on the open market for delivery to Recipient in satisfaction of its obligations under this Agreement. The obligations of the Company under this Agreement are otherwise subject to the approval of state and federal authorities or agencies with jurisdiction in the matter. The Company will use its best efforts to take steps required by state or federal law or applicable regulations, including rules and regulations of the Securities and Exchange Commission and any stock exchange on which the Company’s shares may then be listed, in connection with the award under this Agreement. The foregoing notwithstanding, the Company shall not be obligated to issue or deliver Common Stock under this Agreement if such issuance or delivery would violate applicable state or federal law.

9.No Right to Employment. Nothing contained in this Agreement shall confer upon Recipient any right to be employed by the Company or to continue to provide services to the Company or to interfere in any way with the right of the Company to terminate Recipient’s services at any time for any reason, with or without cause.

10.Miscellaneous.

1.Entire Agreement; Amendment. This Agreement constitutes the entire agreement of the parties with regard to the subjects hereof and may be amended only by written agreement between the Company and Recipient.

2.Notices. Any notice required or permitted under this Agreement shall be in writing and shall be deemed sufficient when delivered personally to the party to whom it is addressed or when deposited into the United States Mail as registered or certified mail, return receipt requested, postage prepaid, addressed to the Company, Attention: Corporate Secretary, at its principal executive offices or to

Recipient at the address of Recipient in the Company’s records, or at such other address as such party may designate by ten (10) days’ advance written notice to the other party.

3.Assignment; Rights and Benefits. Recipient shall not assign this Agreement or any rights hereunder to any other party or parties without the prior written consent of the Company. The rights and benefits of this Agreement shall inure to the benefit of and be enforceable by the Company’s successors and assigns and, subject to the foregoing restriction on assignment, be binding upon Recipient’s heirs, executors, administrators, successors and assigns.

4.Further Action. The parties agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of this Agreement.

5.Applicable Law; Attorneys’ Fees. The terms and conditions of this Agreement shall be governed by the laws of the State of Oregon. In the event either party institutes litigation hereunder, the prevailing party shall be entitled to reasonable attorneys’ fees to be set by the trial court and, upon any appeal, the appellate court.

6.Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed an original.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the day and year first above written.

NORTHWEST NATURAL GAS COMPANY

By

TitlePresident and Chief Executive Officer

EX-12

EXHIBIT 12

NORTHWEST NATURAL GAS COMPANY

Ratios of Earnings to Fixed Charges

^(Unaudited) 

	Year Ended December 31,										Twelve Months Ended September 30,		Nine Months Ended September 30,
In thousands, except share data	2015		2014		2013		2012		2011		2016		2016
Fixed Charges, as defined:
Interest on Long-Term Debt	$	37,918	$	40,066	$	40,825	$	39,175	$	37,515	$	35,863	$	25,714
Other Interest	3,173		2,718		2,709		2,314		2,976		3,530		2,576
Amortization of Debt Discount and Expense	1,760		1,963		1,877		1,848		1,729		1,706		1,234
Interest Portion of Rentals	1,976		2,302		1,910		1,864		2,213		1,964		1,492
Total Fixed Charges, as defined	44,827		47,049		47,321		45,201		44,433		43,063		31,016
Earnings, as defined:
Net Income	53,703		58,692		60,538		58,779		63,044		60,325		30,620
Taxes on Income	35,753		41,643		41,705		43,403		42,825		41,103		21,294
Fixed Charges, as above	44,827		47,049		47,321		45,201		44,433		43,064		31,016
Total Earnings, as defined	$	134,283	$	147,384	$	149,564	$	147,383	$	150,302	$	144,492	$	82,930
Ratios of Earnings to Fixed Charges	3.00		3.13		3.16		3.26		3.38		3.36		2.67

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, David H. Anderson, certify that:

1.           I have reviewed this quarterly report on Form 10-Q for the quarterly period ended September 30, 2016 of Northwest Natural Gas Company;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:          November 2, 2016

/s/ David H. Anderson

David H. Anderson

Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Brody J. Wilson, certify that:

1.           I have reviewed this quarterly report on Form 10-Q for the quarterly period ended September 30, 2016 of Northwest Natural Gas Company;

2.           Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.           Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.           The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.           The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:          November 2, 2016

/s/ Brody J. Wilson___

Brody J. Wilson

Chief Financial Officer, Treasurer, Chief Accounting Officer and Controller

EX-32.1

EXHIBIT 32.1

NORTHWEST NATURAL GAS COMPANY

Certificate Pursuant to Section 906

of Sarbanes – Oxley Act of 2002

Each of the undersigned, DAVID H. ANDERSON, Chief Executive Officer, and BRODY J. WILSON, the Chief Financial Officer, Treasurer, Chief Accounting Officer and Controller of NORTHWEST NATURAL GAS COMPANY (the Company), DOES HEREBY CERTIFY that:

1.           The Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016 (the Report) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.           Information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

IN WITNESS WHEREOF, each of the undersigned has caused this instrument to be executed this 2nd day of November 2016.

/s/ David H. Anderson

David H. Anderson

Chief Executive Officer

/s/ Brody J. Wilson__

Brody J. Wilson

Chief Financial Officer,

Treasurer,

Chief Accounting Officer, and

Controller

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to Northwest Natural Gas Company and will be retained by Northwest Natural Gas Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 21, 2016
Document Information [Line Items]
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Central Index Key	0000073020
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Registrant Name	Northwest Natural Gas Co.
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		27,557,756
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3

XML

Consolidated Statements of Comprehensive Income - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Operating revenues [Abstract]
Operating revenues	$ 87,727	$ 93,128	$ 442,439	$ 493,073
Operating expenses: [Abstract]
Cost of Gas	28,264	35,856	157,546	223,737
Operations and maintenance	34,870	32,031	109,771	121,458
Environmental Remediation Expense	1,191	0	8,113	0
General taxes	7,211	6,772	23,333	23,153
Depreciation and amortization	20,628	20,342	61,435	60,683
Operating Costs and Expenses	92,164	95,001	360,198	429,031
Income from operations	(4,437)	(1,873)	82,241	64,042
Other income and expense, net	652	746	(1,144)	6,930
Interest Income (Expense), Nonoperating, Net	9,729	10,111	29,183	31,030
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(13,514)	(11,238)	51,914	39,942
Income tax expense	5,474	4,553	(21,294)	(15,944)
Net Income	(8,040)	(6,685)	30,620	23,998
Other comprehensive income: [Abstract]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax of $709 for the three and nine months ended September 30, 2016	(1,086)	0	(1,086)	0
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax of $223 and $217 for the three months ended and $477 and $650 for the nine months ended September 30, 2016 and 2015, respectively	341	332	678	995
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ (8,785)	$ (6,353)	$ 30,212	$ 24,993
Average common shares outstanding: [Abstract]
Basic	27,554	27,363	27,504	27,336
Diluted	27,554	27,363	27,629	27,399
Earnings per share of common stock: [Abstract]
Basic	$ (0.29)	$ (0.24)	$ 1.11	$ 0.88
Diluted	(0.29)	(0.24)	1.11	0.88
Dividends declared per share of common stock	$ 0.4700	$ 0.4650	$ 1.4025	$ 1.3950

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Consolidated Statements of Comprehensive Income (Parentheticals) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	$ 709	$ 0	$ 709	$ 0
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax	$ 223	$ 217	$ 477	$ 650

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Current assets: [Abstract]
Cash and cash equivalents	$ 6,230	$ 4,211	$ 5,227
Accounts receivable	25,506	68,228	29,800
Accrued unbilled revenue	15,537	57,987	15,752
Allowance for uncollectible accounts	(289)	(870)	(308)
Regulatory Assets, Current	55,280	69,178	82,712
Derivative instruments	4,857	2,719	2,956
Inventories	67,470	70,868	80,974
Deferred Gas Cost	16,257	17,094	17,822
Income taxes receivable	2,257	7,900	0
Deferred tax assets	0	0	15,663
Other current assets	17,480	33,460	25,972
Total current assets	210,585	330,775	276,570
Non-current assets: [Abstract]
Property, plant, and equipment	3,177,196	3,089,380	3,072,998
Less: Accumulated depreciation	943,334	906,717	905,137
Total property, plant, and equipment, net	2,233,862	2,182,663	2,167,861
Inventory, Gas in Storage Underground, Noncurrent	103,976	114,552	117,784
Regulatory assets	341,188	370,711	333,953
Derivative instruments	1,151	27	299
Other investments	67,853	68,066	68,503
Restricted cash	0	0	4,500
Other non-current assets	1,269	2,616	1,248
Total non-current assets	2,749,299	2,738,635	2,694,148
Total assets	2,959,884	3,069,410	2,970,718
Current liabilities: [Abstract]
Short-term Debt	194,900	270,035	225,200
Current maturities of long-term debt	64,994	24,973	0
Accounts payable	55,933	73,219	54,425
Taxes accrued	11,954	10,420	11,854
Interest accrued	9,671	5,873	9,800
Regulatory liabilities	27,921	29,927	34,127
Derivative instruments	5,334	22,092	21,949
Other current liabilities	31,997	41,148	27,924
Total current liabilities	402,704	477,687	385,279
Long-term debt	530,219	569,445	614,053
Deferred credits and other non-current liabilities: [Abstract]
Deferred tax liabilities	544,575	530,021	527,336
Regulatory liabilities	342,143	339,287	334,490
Pension and other postretirement benefit liabilities	216,909	223,105	228,861
Derivative instruments	1,682	3,447	3,540
Other non-current liabilities	142,450	145,446	117,950
Total deferred credits and other non-current liabilities	1,247,759	1,241,306	1,212,177
Commitments and contingencies (see Note 13)	0	0	0
Equity: [Abstract]
Common stock - no par value; authorized 100,000 shares; issued and outstanding 27,558, 27,367, and 27,427 at September 30, 2016 and 2015, and December 31, 2015, respectively	389,834	383,144	380,208
Retained earnings	396,938	404,990	388,082
Accumulated other comprehensive loss	(7,570)	(7,162)	(9,081)
Total equity	779,202	780,972	759,209
Total liabilities and equity	$ 2,959,884	$ 3,069,410	$ 2,970,718

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Consolidated Balance Sheets (Parentheticals) - shares	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Common Stock Shares Authorized	100,000,000	100,000,000	100,000,000
Common Stock, Shares, Outstanding	27,558,000	27,427,000	27,367,000
Common Stock, Shares, Issued	27,558,000	27,427,000	27,367,000

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Consolidated Statement of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Operating activities: [Abstract]
Net Income	$ 30,620	$ 23,998
Adjustments to reconcile net income to cash provided by operations: [Abstract]
Depreciation and amortization	61,435	60,683
Regulatory amortization of gas reserves	11,403	13,606
Deferred Tax Liabilities, net	17,810	7,153
Qualified defined benefit pension plan expense	3,989	4,238
Contributions to qualified defined benefit pension plans	(11,250)	(11,780)
Deferred environmental (expenditures) recoveries, net of recoveries	(8,302)	(8,063)
Regulatory disallowance of prior environmental cost deferrals	3,287	15,000
Interest income on deferred environmental expenses	0	(5,322)
Amortization of environmental remediation	8,113	0
Other	4,817	669
Changes in assets and liabilities: [Abstract]
Receivables, net	83,377	82,586
Inventories	3,226	(3,142)
Taxes Accrued	7,170	2,823
Accounts payable	(17,612)	(36,230)
Interest accrued	3,798	3,721
Deferred gas costs	(10,470)	27,042
Other, net	14,988	(4,237)
Net Cash Provided by (Used in) Operating Activities, Continuing Operations	206,399	172,745
Payments to Acquire Property, Plant, and Equipment [Abstract]
Capital expenditures	(98,111)	(86,923)
Restricted cash	0	1,500
Other	2,868	181
Net Cash Provided by (Used in) Investing Activities, Continuing Operations	(95,243)	(88,242)
Financing activities: [Abstract]
Common Stock Issued, net	4,832	1,252
Long-term debt retired	0	40,000
Change in short-term debt	(75,135)	(9,500)
Cash dividend payments on common stock	(38,556)	(38,122)
Other	(278)	(2,440)
Net Cash Provided by (Used in) Financing Activities, Continuing Operations	(109,137)	(88,810)
Increase in cash and cash equivalents	2,019	(4,307)
Cash and cash equivalents, beginning of period	4,211	9,534
Cash and cash equivalents, end of period	6,230	5,227
Supplemental disclosure of cash flow information: [Abstract]
Interest paid, net of capitalization	23,271	25,264
Income Taxes Paid, Net of refunds	$ (6,900)	$ 10,631

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Organization and Principles of Consolidation

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

1. ORGANIZATION AND PRINCIPLES OF CONSOLIDATION

The accompanying consolidated financial statements represent the consolidated results of Northwest Natural Gas Company (NW Natural or the Company) and all companies we directly or indirectly control, either through majority ownership or otherwise. We have two core businesses: our regulated local gas distribution business, referred to as the utility segment, which serves residential, commercial, and industrial customers in Oregon and southwest Washington; and our gas storage businesses, referred to as the gas storage segment, which provides storage services for utilities, gas marketers, electric generators, and large industrial users from facilities located in Oregon and California. In addition, we have investments and other non-utility activities we aggregate and report as other.

Our core utility business assets and operating activities are largely included in the parent company, NW Natural. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch), NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), and NW Natural Gas Reserves, LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method, which includes NWN Energy’s investment in Trail West Holdings, LLC (TWH) and NNG Financial's investment in Kelso-Beaver (KB) Pipeline. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated financial statements are presented after elimination of all intercompany balances and transactions, except for amounts required to be included under regulatory accounting standards to reflect the effect of such regulation. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage businesses and other non-utility investments and business activities.

Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments management considers necessary for fair presentation of the results for each period reported including normal recurring accruals. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2015 Annual Report on Form 10-K (2015 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of full year results.

Certain prior year balances in our consolidated financial statements and notes have been reclassified to conform with the current period presentation. These reclassifications had no effect on our prior year’s consolidated results of operations, financial condition, or cash flows.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

2. SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are described in Note 2 of the 2015 Form 10-K. There were no material changes to those accounting policies during the nine months ended September 30, 2016. The following are current updates to certain critical accounting policy estimates and new accounting standards.

Industry Regulation

In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the Public Utility Commission of Oregon (OPUC) or Washington Utilities and Transportation Commission (WUTC), which provide for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a rate of return or a carrying charge in certain cases.

Amounts deferred as regulatory assets and liabilities were as follows:

	Regulatory Assets
	September 30,				December 31,
In thousands	2016		2015		2015
Current:
Unrealized loss on derivatives(1)	$	5,205	$	21,949	$	22,092
Gas costs	10,164		19,274		8,717
Environmental costs(2)	9,734		12,364		9,270
Decoupling(3)	16,028		19,391		18,775
Other(4)	14,149		9,734		10,324
Total current	$	55,280	$	82,712	$	69,178
Non-current:
Unrealized loss on derivatives(1)	$	1,682	$	3,540	$	3,447
Pension balancing(5)	48,637		41,193		43,748
Income taxes	40,106		44,767		43,049
Pension and other postretirement benefit liabilities	174,282		189,111		184,223
Environmental costs(2)	64,279		37,443		76,584
Gas costs	712		2,098		1,949
Decoupling(3)	1,006		4,331		6,349
Other(4)	10,484		11,470		11,362
Total non-current	$	341,188	$	333,953	$	370,711

	Regulatory Liabilities
	September 30,				December 31,
In thousands	2016		2015		2015
Current:
Gas costs	$	12,001	$	22,499	$	14,157
Unrealized gain on derivatives(1)	4,857		2,939		2,659
Other(4)	11,063		8,689		13,111
Total current	$	27,921	$	34,127	$	29,927
Non-current:
Gas costs	$	765	$	6,357	$	8,869
Unrealized gain on derivatives(1)	1,151		299		27
Accrued asset removal costs(6)	336,699		324,467		327,047
Other(4)	3,528		3,367		3,344
Total non-current	$	342,143	$	334,490	$	339,287

⁽¹⁾  Unrealized gains or losses on derivatives are non-cash items and, therefore, do not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the annual Purchased Gas Adjustment (PGA) mechanism when realized at settlement.

⁽²⁾  Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, recovery of deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from Oregon customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test. See Note 13.     

⁽³⁾  This deferral represents the margin adjustment resulting from differences between actual and expected volumes. 

⁽⁴⁾  These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge.

⁽⁵⁾  The deferral of certain pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower net periodic benefit costs in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of interest income recognized when amounts are collected in rates.

⁽⁶⁾  Estimated costs of removal on certain regulated properties are collected through rates.

We believe all costs incurred and deferred at September 30, 2016 are prudent. We annually review all regulatory assets and liabilities for recoverability and more often if circumstances warrant. If we should determine that all or a portion of these regulatory assets or liabilities no longer meet the criteria for continued application of regulatory accounting, then we would be required to write-off the net unrecoverable balances in the period such determination is made.

New Accounting Standards

We consider the applicability and impact of all accounting standards updates (ASUs) issued by the Financial

Accounting Standards Board (FASB). Accounting standards updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial position or results of operations.

Recently Adopted Accounting Pronouncements

BENEFIT PLAN ACCOUNTING. On July 31, 2015, the FASB issued ASU 2015-12, "Plan Accounting: Defined Benefit Pension Plans, Defined Contribution Pension Plans, and Health and Welfare Benefit Plans." The ASU outlines a three part update. Only part two of the update is applicable for us, which simplifies the investment disclosure requirements for employee benefit plans by allowing certain disclosures at an aggregated level, reducing the number of ways assets must be grouped and analyzed, and no longer requiring investment strategy disclosures for certain investments. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively in the 2016 Form 10-K, for all periods presented. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosures within our pension and other postretirement benefit plan footnote in our 2016 Form 10-K, for all periods presented.

FAIR VALUE MEASUREMENT. On May 1, 2015, the FASB issued ASU 2015-07, "Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent)." The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosures of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.

INTANGIBLES - GOODWILL AND OTHER INTERNAL-USE SOFTWARE. On April 15, 2015 the FASB issued ASU 2015-05, "Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement." The ASU provides customers guidance on how to determine whether a cloud computing arrangement includes a software license. The new requirements were effective for us beginning January 1, 2016. We will apply the guidance prospectively as contracts arise and do not expect the ASU to materially affect our financial statements and disclosures.

DEBT ISSUANCE COSTS. On April 7, 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," which requires the presentation of debt issuance costs in the balance sheet as a direct deduction from the associated debt liability. The new requirements were effective for us beginning January 1, 2016. The new guidance has been applied on a retrospective basis and is reflected in our consolidated balance sheets and Note 6.

Recently Issued Accounting Pronouncements

STATEMENT OF CASH FLOWS. On August 26, 2016, the FASB issued ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments." The ASU adds guidance pertaining to the classification of certain cash receipts and payments on the statement of cash flows. The purpose of the amendment is to clarify issues that have been creating diversity in practice, including the classification of proceeds from the settlement of insurance claims and proceeds from the settlement of corporate-owned life insurance policies. The amendments in this standard are effective for us beginning January 1, 2018. Early adoption is permitted in any interim or annual period. We are currently assessing the effect of this standard and do not expect this standard to materially affect our financial statements and disclosures.

STOCK BASED COMPENSATION. On March 30, 2016, the FASB issued ASU 2016-09, "Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting." The ASU changes how companies account for certain aspects of share-based payment awards to employees, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The amendments in this standard are effective for us beginning January 1, 2017. Early adoption is permitted in any interim or annual period. We do not expect this standard to materially affect our financial statements and disclosures.

LEASES. On February 25, 2016, the FASB issued ASU 2016-02, "Leases," which revises the existing lease accounting guidance. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases that are greater than 12 months at lease commencement, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Lessor accounting will remain substantially the same under the new standard. Quantitative and qualitative disclosures are also required for users of the financial statements to have a clear understanding of the nature of our leasing activities. The standard is effective for us beginning January 1, 2019, and early adoption is permitted. The new standard must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently assessing the effect of this standard on our financial statements and disclosures.

FINANCIAL INSTRUMENTS. On January 5, 2016, the FASB issued ASU 2016-01, "Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities." The ASU enhances the reporting model for financial instruments, which includes amendments to address aspects of recognition, measurement, presentation, and disclosure. The new standard is effective for us beginning January 1, 2018. Upon adoption, we will be required to make a cumulative-effect adjustment to the consolidated balance sheet in the first quarter of 2018. Early adoption is permitted, and we are currently assessing the effect of this standard on our financial statements and disclosures.

REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts the entity is expected to be entitled to in exchange for those goods or services. The ASU also prescribes a five-step approach to revenue recognition: (1) identify the contract(s) with the customer; (2) identify the separate performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to separate performance obligations; and (5) recognize revenue when, or as, each performance obligation is satisfied. The new requirements prescribe either a full retrospective or simplified transition adoption method. On August 12, 2015, the FASB deferred the effective date by one year to January 1, 2018 for annual reporting periods beginning after December 15, 2017. The FASB also permitted early adoption of the standard, but not before the original effective date of January 1, 2017. We plan to adopt the new standard effective January 1, 2018 and are assessing the effect this standard will have on our financial statements and disclosures.

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Earnings Per Share

9 Months Ended

Sep. 30, 2016

Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]

Earnings Per Share [Text Block]

3. EARNINGS PER SHARE

Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for each period presented. Diluted earnings per share are computed in the same manner, except it uses the weighted average number of common shares outstanding plus the effects of the assumed exercise of stock options and the payment of estimated stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Antidilutive stock awards are excluded from the calculation of diluted earnings per share. Diluted earnings (loss) per share are calculated as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
In thousands, except per share data	2016			2015			2016		2015
Net income (loss)	$	(8,040	)	$	(6,685	)	$	30,620	$	23,998
Average common shares outstanding - basic	27,554			27,363			27,504		27,336
Additional shares for stock-based compensation plans (See Note 5)	—			—			125		63
Average common shares outstanding - diluted	27,554			27,363			27,629		27,399
Earnings (loss) per share of common stock - basic	$	(0.29	)	$	(0.24	)	$	1.11	$	0.88
Earnings (loss) per share of common stock - diluted	$	(0.29	)	$	(0.24	)	$	1.11	$	0.88
Additional information:
Antidilutive shares	159			91			5		19

XML

Segment Information

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Segment Information [Text Block]

4. SEGMENT INFORMATION

We primarily operate in two reportable business segments: local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which are aggregated and reported as other. We refer to our local gas distribution business as the utility, and our gas storage segment and other as non-utility. Our utility segment also includes the utility portion of our Mist underground storage facility in Oregon and NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp. Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist, and all third-party asset management services. Other includes NNG Financial and NWN Energy's equity investment in TWH, which is pursuing development of a cross-Cascades transmission pipeline project. See Note 4 in the 2015 Form 10-K for further discussion of our segments.

Inter-segment transactions were insignificant for the periods presented. The following table presents summary financial information concerning the reportable segments:

	Three Months Ended September 30,
In thousands	Utility			Gas Storage		Other			Total
2016
Operating revenues	$	80,378		$	7,293	$	56		$	87,727
Depreciation and amortization	19,173			1,455		—			20,628
Income (loss) from operations	(7,264		)	3,502		(675		)	(4,437		)
Net income (loss)	(9,511		)	1,813		(342		)	(8,040		)
Capital expenditures	36,238			437		—			36,675
2015
Operating revenues	$	87,475		$	5,596	$	57		$	93,128
Depreciation and amortization	18,721			1,621		—			20,342
Income (loss) from operations	(4,088		)	2,204		11			(1,873		)
Net income (loss)	(7,529		)	799		45			(6,685		)
Capital expenditures	28,325			526		—			28,851

	Nine Months Ended September 30,
In thousands	Utility		Gas Storage		Other			Total
2016
Operating revenues	$	422,617	$	19,654	$	168		$	442,439
Depreciation and amortization	56,894		4,541		—			61,435
Income (loss) from operations	74,745		8,107		(611		)	82,241
Net income (loss)	26,848		3,988		(216		)	30,620
Capital expenditures	96,710		1,401		—			98,111
Total assets at September 30, 2016	2,684,618		259,483		15,783			2,959,884
2015
Operating revenues	476,672		16,232		169			493,073
Depreciation and amortization	55,798		4,885		—			60,683
Income from operations	59,955		3,998		89			64,042
Net income	23,051		827		120			23,998
Capital expenditures	84,598		2,325		—			86,923
Total assets at September 30, 2015	2,686,367		269,228		15,123			2,970,718
Total assets at December 31, 2015	2,792,736		261,750		14,924			3,069,410

Utility Margin

Utility margin is a financial measure consisting of utility operating revenues, which are reduced by revenue taxes, the associated cost of gas, and environmental recovery revenues. The cost of gas purchased for utility customers is generally a pass-through cost in the amount of revenues billed to regulated utility customers. Environmental recovery revenues represent collections received from customers through our environmental recovery mechanism in Oregon. These collections are offset by the amortization of environmental liabilities, which is presented as environmental remediation expense in our operating expenses. By subtracting cost of gas and environmental remediation expense from utility operating revenues, utility margin provides a key metric used by our chief operating decision maker in assessing the performance of the utility segment. The gas storage and other segments emphasize growth in operating revenues as opposed to margin because they do not incur a product cost (i.e. cost of gas sold) like the utility and, therefore, use operating revenues and net income to assess performance.

The following table presents additional segment information concerning utility margin:

	Three Months Ended September 30,				Nine Months Ended September 30,
In thousands	2016		2015		2016		2015
Utility margin calculation:
Utility operating revenues(1)	$	80,378	$	87,475	$	422,617	$	476,672
Less: Utility cost of gas	28,264		35,856		157,546		223,737
Environmental remediation expense	1,191		—		8,113		—
Utility margin	$	50,923	$	51,619	$	256,958	$	252,935

⁽¹⁾   Utility operating revenues include environmental recovery revenues, which are collections received from customers through our environmental recovery mechanism in Oregon, offset by environmental remediation expense. Collections under this mechanism began in November 2015.

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Stock-Based Compensation

9 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock Based Compensation [Text Block]

5. STOCK-BASED COMPENSATION

Our stock-based compensation plans are designed to promote stock ownership in NW Natural by employees and officers. These compensation plans include a Long-Term Incentive Plan (LTIP), an Employee Stock Purchase Plan (ESPP), and a Restated Stock Option Plan. For additional information on our stock-based compensation plans, see Note 6 in the 2015 Form 10-K and the updates provided below.

Long-Term Incentive Plan

Performance Shares

LTIP performance shares incorporate a combination of market, performance, and service-based factors. During the nine months ended September 30, 2016, 36,259 performance-based shares were granted under the LTIP based on target-level awards with a weighted-average grant date fair value of $50.13 per share. As of September 30, 2016, there was $2.7 million of unrecognized compensation cost from LTIP grants, which is expected to be recognized through 2018. Fair value for the market based portion of the LTIP was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:

Stock price on valuation date	$	50.15
Performance term (in years)	3.0
Quarterly dividends paid per share	$	0.4675
Expected dividend yield	3.7		%
Dividend discount factor	0.9010

Restricted Stock Units (RSUs)

During the nine months ended September 30, 2016, 36,591 RSUs were granted under the LTIP with a weighted-average grant date fair value of $54.21 per share. The fair value of a RSU is equal to the closing market price of our common stock on the grant date. As of September 30, 2016, there was $3.3 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through 2021. Generally, the RSUs awarded are forfeitable and include a performance-based threshold as well as a vesting period of four years from the grant date. A RSU obligates us, upon vesting, to issue the RSU holder one share of common stock plus a cash payment equal to the total amount of dividends paid per share between the grant date and vesting date of that portion of the RSU.

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Debt

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Debt [Text Block]

6. DEBT

Short-Term Debt

At September 30, 2016, our short-term debt consisted of commercial paper notes payable with a maximum maturity of 55 days and an average maturity of 28 days and an outstanding balance of $194.9 million. The carrying cost of our commercial paper approximates fair value using Level 2 inputs, due to the short-term nature of the notes. See Note 2 in the 2015 Form 10-K for a description of the fair value hierarchy.

Long-Term Debt

At September 30, 2016, we had long-term debt of $595.2 million, which included $6.5 million of unamortized debt issuance costs. Utility long-term debt consists of first mortgage bonds (FMBs) with maturity dates ranging from2016 through 2042, interest rates ranging from 3.176% to 9.05%, and a weighted-average coupon rate of 5.70%.

Fair Value of Long-Term Debt

Our outstanding debt does not trade in active markets. We estimate the fair value of our debt using inputs from utility companies with similar credit ratings, whose debt trades actively in public markets and has terms and remaining maturities comparable to our own debt.These valuations are based on Level 2 inputs as defined in the fair value hierarchy. See Note 2 in the 2015 Form 10-K for a description of the fair value hierarchy.

The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date:

	September 30,						December 31,
In thousands	2016			2015			2015
Gross long-term debt	$	601,700		$	621,700		$	601,700
Unamortized debt issuance costs	(6,487		)	(7,647		)	(7,282		)
Carrying amount	$	595,213		$	614,053		$	594,418
Estimated fair value(1)	701,183			697,647			667,168

⁽¹⁾  Estimated fair value does not include unamortized debt issuance costs.

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Pension and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2016

Pension and Other Postretirement Benefit Expense [Abstract]

Pension and Other Postretirement Benefits [Text Block]

7. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

The following table provides the components of net periodic benefit cost for our pension and other postretirement benefit plans:

	Three Months Ended September 30,												Nine Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
In thousands	2016			2015			2016			2015			2016			2015			2016			2015
Service cost	$	1,978		$	2,308		$	119		$	145		$	5,866		$	6,926		$	361		$	435
Interest cost	4,607			4,597			301			291			13,755			13,787			901			874
Expected return on plan assets	(5,017		)	(5,174		)	—			—			(15,051		)	(15,522		)	—			—
Amortization of net actuarial loss	3,555			4,561			192			125			10,559			13,683			575			376
Amortization of prior service costs	57			57			(117		)	50			173			173			(351		)	148
Settlement expense(1)	193			—			—			—			193			—			—			—
Net periodic benefit cost	5,373			6,349			495			611			15,495			19,047			1,486			1,833
Amount allocated to construction	(1,556		)	(2,061		)	(163		)	(218		)	(4,678		)	(5,765		)	(491		)	(607		)
Amount deferred to regulatory balancing account(2)	(1,542		)	(2,171		)	—			—			(4,762		)	(6,511		)	—			—
Net amount charged to expense	$	2,275		$	2,117		$	332		$	393		$	6,055		$	6,771		$	995		$	1,226

⁽¹⁾ During the three months ended September 30, 2016, a participant within the Company's Supplemental Executive Retirement Plan elected to have their benefit paid out in a one-time lump-sum cash payment. Accordingly, this transaction qualified for settlement accounting and a pro rata portion of the associated loss in Accumulated Other Comprehensive Loss was immediately recognized in earnings.

⁽²⁾ The deferral of defined benefit pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account. The balancing account includes the expectation of higher net periodic benefit costs than costs recovered in rates in the near-term with lower net periodic benefit costs than costs recovered in rates expected in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of the interest recognized when amounts are collected in rates. See Note 2 in the 2015 Form 10-K.

The following table presents amounts recognized in Accumulated Other Comprehensive Loss (AOCL) and the changes in AOCL related to our non-qualified employee benefit plans:

	Three Months Ended September 30,						Nine Months Ended September 30,
In thousands	2016			2015			2016			2015
Beginning balance	$	(6,825	)	$	(9,413	)	$	(7,162	)	$	(10,076	)
Amounts reclassified to AOCL	(1,795		)	—			(1,795		)	—
Amounts reclassified from AOCL:
Amortization of actuarial losses	371			549			962			1,645
Loss from plan settlement	193			—			193			—
Total reclassifications before tax	(1,231		)	549			(640		)	1,645
Tax (benefit) expense	486			(217		)	232			(650		)
Total reclassifications for the period	(745		)	332			(408		)	995
Ending balance	$	(7,570	)	$	(9,081	)	$	(7,570	)	$	(9,081	)

Employer Contributions to Company-Sponsored Defined Benefit Pension Plans

For the nine months ended September 30, 2016, we made cash contributions totaling $11.3 million to our qualified defined benefit pension plan. We expect further plan contributions of $3.2 million during the remainder of 2016.

Defined Contribution Plan

The Retirement K Savings Plan is a qualified defined contribution plan under Internal Revenue Code Section 401(k). Employer contributions totaled $3.6 million and $2.9 million for the nine months ended September 30, 2016 and 2015, respectively.

See Note 8 in the 2015 Form 10-K for more information concerning these retirement and other postretirement benefit plans.

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Income Tax

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Tax [Text Block]

8. INCOME TAX

An estimate of annual income tax expense is made each interim period using estimates for annual pre-tax income, regulatory flow-through adjustments, tax credits, and other items. The estimated annual effective tax rate is applied to year-to-date, pre-tax income to determine income tax expense for the interim period consistent with the annual estimate.

The effective income tax rate varied from the combined federal and state statutory tax rates due to the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
Dollars in thousands	2016			2015			2016			2015
Income taxes at statutory rates (federal and state)	$	(5,339	)	$	(4,473	)	$	20,620		$	15,848
Increase (decrease):
Differences required to be flowed-through by regulatory commissions	(381		)	(378		)	1,202			1,036
Other, net	246			298			(528		)	(940		)
Total provision (benefit) for income taxes	$	(5,474	)	$	(4,553	)	$	21,294		$	15,944
Effective tax rate	40.5		%	40.5		%	41.0		%	39.9		%

The effective tax rate for the three months ended September 30, 2016 and 2015 remained flat. For the nine months endedSeptember 30, 2016, compared to 2015, the effective tax rate increased primarily as a result of lower estimated depletion deductions from gas reserves activity in 2016. The effective tax rate for the nine months endedSeptember 30, 2015 benefited from the realization of deferred depletion benefits from 2013 and 2014. See Note 9 in the 2015 Form 10-K for more detail on income taxes and effective tax rates.

The 2015 tax year is subject to examination under the Internal Revenue Service (IRS) Compliance Assurance Process (CAP). Our 2016 tax year CAP application has been accepted by the IRS.

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2016

Public Utilities, Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Text Block]

9. PROPERTY, PLANT, AND EQUIPMENT

The following table sets forth the major classifications of our property, plant, and equipment and accumulated depreciation:

	September 30,				December 31,
In thousands	2016		2015		2015
Utility plant in service	$	2,815,340	$	2,710,658	$	2,745,485
Utility construction work in progress	58,470		58,280		39,288
Less: Accumulated depreciation	899,851		867,281		867,377
Utility plant, net	1,973,959		1,901,657		1,917,396
Non-utility plant in service	298,586		296,169		296,839
Non-utility construction work in progress	4,800		7,891		7,768
Less: Accumulated depreciation	43,483		37,856		39,340
Non-utility plant, net	259,903		266,204		265,267
Total property, plant, and equipment	$	2,233,862	$	2,167,861	$	2,182,663
Capital expenditures in accrued liabilities	$	8,918	$	9,700	$	8,985

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Gas Reserves

9 Months Ended

Sep. 30, 2016

Gas Reserves [Abstract]

Gas Reserves [Text Block]

10. GAS RESERVES

We have invested $188 million through our gas reserves program in the Jonah Field located in Wyoming as of September 30, 2016. Gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the consolidated balance sheets. Our investment in gas reserves provides long-term price protection for utility customers through the original agreement with Encana Oil & Gas (USA) Inc. under which we invested $178 million and the amended agreement with Jonah Energy LLC under which an additional $10 million was invested.

The cost of gas, including a carrying cost for the rate base investment made under the original agreement, is included in our annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our investment under the original agreement, less accumulated amortization and deferred taxes, earns a rate of return.

The volumes produced from the wells under the amended agreement with Jonah are included in our Oregon PGA at a fixed rate of $0.4725 per therm.

The following table outlines our net gas reserves investment:

	September 30,				December 31,
In thousands	2016		2015		2015
Gas reserves, current	$	16,257	$	17,822	$	17,094
Gas reserves, non-current	171,280		169,300		170,453
Less: Accumulated amortization	67,304		51,516		55,901
Total gas reserves(1)	120,233		135,606		131,646
Less: Deferred taxes on gas reserves	25,799		23,042		27,203
Net investment in gas reserves	$	94,434	$	112,564	$	104,443

⁽¹⁾ Our investment in additional wells included in total gas reserves was $7.0 million, $9.7 million and $8.0 million at September 30, 2016 and 2015 and December 31, 2015, respectively.

Our investment is included on our consolidated balance sheets under gas reserves with our maximum loss exposure limited to our investment balance.

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Investments

9 Months Ended

Sep. 30, 2016

Investments [Abstract]

Investments [Text Block]

11. INVESTMENTS

Investments in Gas Pipeline

Trail West Pipeline, LLC (TWP), a wholly-owned subsidiary of TWH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. NWN Energy, a wholly-owned subsidiary of NW Natural owns 50% of TWH, and 50% is owned by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation.

Variable Interest Entity (VIE) Analysis

TWH is a VIE, with our investment in TWP reported under equity method accounting. We have determined we are not the primary beneficiary of TWH’s activities as we only have a 50% share of the entity and there are no stipulations that allow us a disproportionate amount of influence over it. Our investments in TWH and TWP are included in other investments on our consolidated balance sheets. If we do not develop this investment, our maximum loss exposure related to TWH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50% owner. Our investment balance in TWH was $13.4 million at September 30, 2016 and 2015 and December 31, 2015. See Note 12 in the 2015 Form 10-K.

Other Investments

Other investments include financial investments in life insurance policies, which are accounted for at cash surrender value, net of policy loans. See Note 12 in the 2015 Form 10-K.

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Derivative Instruments

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments [Text Block]

12. DERIVATIVE INSTRUMENTS

We enter into financial derivative contracts to hedge a portion of our utility’s natural gas sales requirements. These contracts include swaps, options and combinations of option contracts. We primarily use these derivative financial instruments to manage commodity price variability. A small portion of our derivative hedging strategy involves foreign currency exchange contracts.

We enter into these financial derivatives, up to prescribed limits, primarily to hedge price variability related to our physical gas supply contracts as well as to hedge spot purchases of natural gas. The foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for pipeline demand charges paid in Canadian dollars. In the normal course of business, we also enter into indexed-price physical forward natural gas commodity purchase contracts and options to meet the requirements of utility customers. These contracts qualify for regulatory deferral accounting treatment.

We also enter into exchange contracts related to the third-party asset management of our gas portfolio, some of which are derivatives that do not qualify for hedge accounting or regulatory deferral, but are subject to our regulatory sharing agreement. These derivatives are recognized in operating revenues in our gas storage segment, net of amounts shared with utility customers.

Notional Amounts

The following table presents the absolute notional amounts related to open positions on our derivative instruments:

	September 30,				December 31,
In thousands	2016		2015		2015
Natural gas (in therms):
Financial	537,100		416,075		346,875
Physical	621,230		521,350		404,645
Foreign exchange (in thousands)	$	8,404	$	8,023	$	9,025

Purchased Gas Adjustment (PGA)

Derivatives entered into by the utility for the procurement or hedging of natural gas for future gas years generally receive regulatory deferral accounting treatment. In general, our commodity hedging for the current gas year is completed prior to the start of the gas year, and hedge prices are reflected in our weighted-average cost of gas in the PGA filing. Hedge contracts entered into after the start of the PGA period are subject to our PGA incentive sharing mechanism in Oregon. As of November 1, 2016 and 2015, we reached our target hedge percentage of approximately 75% for both the 2016-17 and 2015-2016 gas years. Hedge contracts entered into prior to our filing, in September 2015, were included in the PGA for the 2015-2016 gas year. Hedge contracts entered into after our PGA filing, and related to subsequent gas years, may be included in future PGA filings for and qualify for regulatory deferral.

Unrealized and Realized Gain/Loss

The following table reflects the income statement presentation for the unrealized gains and losses on our derivative instruments:

	Three Months Ended September 30,
	2016						2015
In thousands	Natural gas commodity			Foreign exchange			Natural gas commodity			Foreign exchange
Benefit (expense) to cost of gas	$	(8,045	)	$	(52	)	$	(8,415	)	$	(150	)
Operating (loss) revenues	(110		)	—			33			—
Less:
Amounts deferred to regulatory accounts on balance sheet	8,118			52			8,391			150
Total (loss) gain in pre-tax earnings	$	(37	)	$	—		$	9		$	—

	Nine Months Ended September 30,
	2016						2015
In thousands	Natural gas commodity			Foreign exchange			Natural gas commodity			Foreign exchange
Benefit (expense) to cost of gas	$	5,562		$	5		$	(21,876	)	$	(413	)
Operating (loss) revenues	(266		)	—			55			—
Less:
Amounts deferred to regulatory accounts on balance sheet	(5,385		)	(5		)	21,838			413
Total (loss) gain in pre-tax earnings	$	(89	)	$	—		$	17		$	—

UNREALIZED GAIN/LOSS. Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory accounting standards. The cost of foreign currency forward and natural gas derivative contracts are recognized immediately in the cost of gas; however, costs above or below the amount embedded in the current year PGA are subject to a regulatory deferral tariff and therefore, are recorded as a regulatory asset or liability.

REALIZED GAIN/LOSS. We realized net losses of $1.0 million and $24.1 million for the three and nine months endedSeptember 30, 2016, respectively, and net losses of $2.3 million and $24.3 million for the three and nine months endedSeptember 30, 2015, respectively, from the settlement of natural gas financial derivative contracts. Realized gains and losses are recorded in cost of gas, deferred through our regulatory accounts, and amortized through customer rates in the following year.

Credit Risk Management of Financial Derivative Instruments

No collateral was posted with or by our counterparties as of September 30, 2016 or 2015. We attempt to minimize the potential exposure to collateral calls by counterparties to manage our liquidity risk. Counterparties generally allow a certain credit limit threshold before requiring us to post collateral against loss positions. Given our counterparty credit limits and portfolio diversification, we were not subject to collateral calls in 2016 or 2015. Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We could also be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change.

Based upon current commodity financial swap and option contracts outstanding, which reflect unrealized losses of $2.7 million at September 30, 2016, we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various credit downgrade rating scenarios for NW Natural as follows:

			Credit Rating Downgrade Scenarios
In thousands	(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3			Speculative
With Adequate Assurance Calls	$	—	$	—	$	—	$	(1,036	)	$	(1,242	)
Without Adequate Assurance Calls	—		—		—		(1,036		)	181

Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our consolidated balance sheets. The Company and its counterparties have the ability to set-off their obligations to each other under specified circumstances. Such circumstances may include a defaulting party, a credit change due to a merger affecting either party, or any other termination event.

If netted by counterparty, our derivative position would result in an asset of $4.1 million and a liability of $5.1 million as of September 30, 2016. As of September 30, 2015, our derivative position would have resulted in an asset of $3.1 million and a liability of $25.3 million. As of December 31, 2015, our derivative position would have resulted in an asset of $2.7 million and a liability of $25.5 million.

We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of customers. See Note 13 in our 2015 Form 10-K for additional information.

Fair Value

In accordance with fair value accounting, we include non-performance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. The inputs in our valuation models include natural gas futures, volatility, credit default swap spreads and interest rates. Additionally, our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at September 30, 2016. As of September 30, 2016, the net fair value was a liability of $1.0 million, using significant other observable, or level 2, inputs. As of September 30, 2015 and December 31, 2015 the net fair values were assets of $22.2 million and $22.8 million, respectively, using significant other observable, or level 2, inputs. No level 3 inputs were used in our derivative valuations, and there were no transfers between level 1 or level 2 during the three months ended September 30, 2016 and 2015. See Note 2 in the 2015 Form 10-K.

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Environmental Matters

9 Months Ended

Sep. 30, 2016

Environmental Remediation Obligations [Abstract]

Environmental Matters [Text Block]

13. ENVIRONMENTAL MATTERS

We own, or previously owned, properties that may require environmental remediation or action. We estimate the range of loss for environmental liabilities based on current remediation technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties (PRPs). When amounts are prudently expended related to site remediation, we have a recovery mechanism in place to collect 96.68% of remediation costs from Oregon customers, and we are allowed to defer environmental remediation costs allocated to customers in Washington annually until they are reviewed for prudence at a subsequent proceeding.

Our sites are subject to the remediation process prescribed by the Environmental Protection Agency (EPA) and the Oregon Department of Environmental Quality (ODEQ). The process begins with a remedial investigation (RI) to determine the nature and extent of contamination and then a risk assessment (RA) to establish whether the contamination at the site poses unacceptable risks to humans and the environment. Next, a feasibility study (FS) or an engineering evaluation/cost analysis (EE/CA) evaluates various remedial alternatives. It is at this point in the process when we are able to estimate a range of remediation costs and record a reasonable potential remediation liability, or make an adjustment to our existing liability. From this study, the regulatory agency selects a remedy and issues a Record of Decision (ROD). After the ROD is issued, we seek to negotiate a consent decree or consent judgment for designing and implementing the remedy. We have the ability to further refine estimates of remediation liabilities at that time.

Remediation may include treatment of contaminated media such as sediment, soil, and groundwater, removal and disposal of media, or institutional controls such as legal restrictions on future property use. Following construction of the remedy, the EPA and ODEQ also have requirements for ongoing maintenance, monitoring and other post-remediation care that may continue for many years. Where appropriate and reasonably known, we will provide for these costs in our remediation liabilities described above.

Due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases, we have disclosed the nature of the possible loss and the fact that the high end of the range cannot be reasonably estimated where a range of potential loss is available. Unless there is an estimate within the range of possible losses that is more likely than other cost estimates within that range, we record the liability at the low end of this range. It is likely changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to our continued evaluation and clarification concerning our responsibility, the complexity of environmental laws and regulations, and the determination by regulators of remediation alternatives. In addition to remediation costs, we could also be subject to Natural Resource Damages (NRD) claims. We will assess the likelihood and probability of each claim and recognize a liability if deemed appropriate. As of September 30, 2016, we have not received any material NRD claims.

Environmental Sites

The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other current liabilities and other noncurrent liabilities on the consolidated balance sheets:

	Current Liabilities						Non-Current Liabilities
	September 30,				December 31,		September 30,				December 31,
In thousands	2016		2015		2015		2016		2015		2015
Portland Harbor site:
Gasco/Siltronic Sediments	$	1,726	$	1,236	$	2,229	$	42,880	$	38,533	$	42,641
Other Portland Harbor	1,461		1,243		1,972		4,362		4,563		5,073
Gasco Upland site	8,191		4,510		10,599		49,928		36,795		52,117
Siltronic Upland site	—		538		951		—		489		337
Central Service Center site	112		177		25		—		—		—
Front Street site	841		420		1,155		7,818		215		7,748
Oregon Steel Mills	—		—		—		179		179		179
Total	$	12,331	$	8,124	$	16,931	$	105,167	$	80,774	$	108,095

PORTLAND HARBOR SITE. The Portland Harbor is an EPA listed Superfund site that is approximately 10 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands and the Siltronic uplands sites. We are a PRP to the Superfund site and have joined with some of the other PRPs (the Lower Willamette Group or LWG) to develop a Portland Harbor Remedial Investigation/Feasibility Study (RI/FS), which we submitted to the EPA in 2012. In August 2015, the EPA issued its own Draft Feasibility Study (Draft FS) for comment. The EPA Draft FS provides a new range of remedial costs for the entire Portland Harbor Superfund Site, which includes the Gasco/Siltronic Sediment site, discussed below. The range of present value costs estimated by the EPA for various remedial alternatives for the entire Portland Harbor, as provided by the EPA's Draft FS, is $791 million to $2.45 billion. The range provided in the EPA's Draft FS is based on cost alternatives the EPA estimates to have an accuracy between -30% and +50% of actual costs, depending on the scope of work.

In June 2016, the EPA issued their Final Feasibility Study (Final FS) and proposed remediation plan (Proposed Plan) for the Portland Harbor Superfund site. The Proposed Plan presents the EPA’s preferred clean-up alternative, which estimates the present value cost at approximately $746 million with an accuracy between -30% and +50% of actual costs, a significant reduction from prior estimates for this level of cleanup. Along with several members of the LWG, we have filed a dispute with the EPA over concerns that the EPA's Final FS contains factual and technical errors and is insufficient to support remedy selection. We have also submitted comments to the Proposed Plan identifying technical errors and suggesting corrections to the Plan. The EPA is reviewing all public comments andhas stated it intends to release a Record of Decision, the final determination of a cleanup approach for the Portland Harbor site, by the end of January 2017. 

While the EPA's Final FS and Proposed Plan provides a higher range of costs than the LWG's submission in 2012, our potential liability is still a portion of the costs of the remedy for the entire Portland Harbor Superfund site. The cost of that remedy is expected to be allocated among more than 100 PRPs. We are participating in a non-binding allocation process in an effort to settle this potential liability. The Final FS and Proposed Plan do not provide any additional clarification around allocation of costs.

We manage our liability related to the Superfund site as two distinct remediation projects, the Gasco/Siltronic Sediments and Other Portland Harbor projects.

Gasco/Siltronic Sediments.In 2009, NW Natural and Siltronic Corporation entered into a separate Administrative Order on Consent with the EPA to evaluate and design specific remedies for sediments adjacent to the Gasco uplands and Siltronic uplands sites. We submitted a draft EE/CA to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA as well as costs for the additional studies and design work needed before the clean-up can occur, and for regulatory oversight throughout the clean-up range from $44.6 million to $350 million. We have recorded a liability of $44.6 million for the sediment clean-up, which reflects the low end of the range. At this time, we believe sediments at this site represent the largest portion of our liability related to the Portland Harbor site, discussed above. 

Other Portland Harbor.NW Natural incurs costs related to its membership in the LWG. NW Natural also incurs costs related to natural resource damages from these sites. The Company and other parties have signed a cooperative agreement with the Portland Harbor Natural Resource Trustee council to participate in a phased natural resource damage assessment to estimate liabilities to support an early restoration-based settlement of natural resource damage claims. Natural resource damage claims may arise only after a remedy for clean-up has been settled. We have recorded a liability for these claims which is at the low end of the range of the potential liability; the high end of the range cannot be reasonably estimated at this time. This liability is not included in the range of costs provided in the draft FS for the Portland Harbor or noted above.

GASCO UPLANDS SITE. A predecessor of NW Natural, Portland Gas and Coke Company, owned a former gas manufacturing plant that was closed in 1958 (Gasco site) and is adjacent to the Portland Harbor site described above. The Gasco site has been under investigation by us for environmental contamination under the ODEQ Voluntary Clean-Up Program (VCP). It is not included in the range of remedial costs for the Portland Harbor site noted above. We manage the Gasco site in two parts, the uplands portion and the groundwater source control action.

We submitted a revised Remedial Investigation Report for the uplands to ODEQ in May 2007. In March 2015, ODEQ approved the RA NW Natural submitted in 2010, enabling us to begin work on the FS in 2016. We have recognized a liability for the remediation of the uplands portion of the site which is at the low end of the range of potential liability; the high end of the range cannot be reasonably estimated at this time.

In October 2016, ODEQ and NW Natural agreed to amend their VCP agreement to incorporate a portion of the Siltronic property adjacent to the Gasco site formerly owned by Portland Gas & Coke between 1939 and 1960 into the Gasco RA and FS. Previously, we were conducting an investigation of manufactured gas plant constituents on the entire Siltronic uplands for ODEQ. Siltronic will be working with ODEQ directly on environmental impacts to the remainder of its property.

In September 2013, we completed construction of a groundwater source control system, including a water treatment station, at the Gasco site. We are working with ODEQ on monitoring the effectiveness of the system and at this time it is unclear what, if any, additional actions ODEQ may require subsequent to the initial testing of the system or as part of the final remedy for the uplands portion of the Gasco site. We have estimated the cost associated with the ongoing operation of the system and have recognized a liability which is at the low end of the range of potential cost. We cannot estimate the high end of the range at this time due to the uncertainty associated with the duration of running the water treatment station, which is highly dependent on the remedy determined for both the upland portion as well as the final remedy for our Gasco sediment exposure.

Beginning November 1, 2013, capital asset costs of $19.0 million for the Gasco water treatment station were placed into rates with OPUC approval. The OPUC deemed these costs prudent. Beginning November 1, 2014, the OPUC approved the application of $2.5 million from insurance proceeds plus interest to reduce the total amount of Gasco capital costs to be recovered through rate base. A portion of these proceeds was non-cash in 2014.

OTHER SITES. In addition to those sites above, we have environmental exposures at three other sites: Central Service Center, Front Street and Oregon Steel Mills. Due to the uncertainty of the design of remediation, regulation, timing of the remediation and in the case of the Oregon Steel Mills site, pending litigation, liabilities for each of these sites have been recognized at their respective low end of the range of potential liability; the high end of the range could not be reasonably estimated at this time.

Central Service Center site.We are currently performing an environmental investigation of the property under ODEQ's Independent Cleanup Pathway. This site is on ODEQ's list of sites with confirmed releases of hazardous substances, and cleanup is necessary.

Front Street site.The Front Street site was the former location of a gas manufacturing plant we operated (the former Portland Gas Manufacturing site, or PGM). At ODEQ’s request, we conducted a sediment and source control investigation and provided findings to ODEQ. In December 2015, we completed a FS on the former Portland Gas Manufacturing site. The FS provided a range of $7.6 million to $12.9 million for remedial costs. We have recorded a liability at the low end of the range of possible loss as no alternative in the range is considered more likely than another. Further, we have recognized an additional liability of $1.1 million for additional studies and design costs as well as regulatory oversight throughout the clean-up that will be required to assist in ODEQ making a remedy selection and completing a design.

Oregon Steel Mills site.Refer to the “Legal Proceedings,” below.

Site Remediation and Recovery Mechanism (SRRM)

We have a SRRM through which we track and have the ability to recover past deferred and future prudently incurred environmental remediation costs allocable to Oregon, subject to an earnings test.

REGULATORY ACTIVITIES. In February 2015, the OPUC issued an Order addressing outstanding issues related to the SRRM (2015 Order), which required us to forego collection of $15 million out of approximately $95 million in total environmental remediation expenses and associated carrying costs the Company had deferred through 2012 based on the OPUC’s determination of how an earnings test should apply to amounts deferred from 2003 to 2012, with adjustments for other factors the OPUC deemed relevant. As a result, we recognized a $15.0 million non-cash charge in operations and maintenance expense in the first quarter of 2015. Also, as a result of the 2015 Order, we recognized $5.3 million pre-tax of interest income related to the equity earnings on our deferred environmental expenses.

In addition, the OPUC issued a subsequent Order regarding SRRM implementation (2016 Order) in January 2016 in which the OPUC: (1) disallowed the recovery of $2.8 million of interest earned on the previously disallowed environmental expenditure amounts; (2) clarified the state allocation of 96.68% of environmental remediation costs for all environmental sites to Oregon; and (3) confirmed our treatment of $13.8 million of expenses put into the SRRM amortization account was correct and in compliance with prior OPUC orders. As a result of the 2016 Order, we recognized a $3.3 million non-cash charge in the first quarter, of which $2.8 million is reflected in other income and expense, net and $0.5 million is included in operations and maintenance expense.

COLLECTIONS FROM OREGON CUSTOMERS. The SRRM provides us with the ability to recover past deferred and future prudently incurred environmental remediation costs allocable to Oregon, subject to an earnings test. The SRRM created three classes of deferred environmental remediation expense:

• Pre-review - This class of costs represents remediation spend that has not yet been deemed prudent by the OPUC. Carrying costs on these remediation expenses are recorded at our authorized cost of capital. The Company anticipates the prudence review for annual costs and approval of the earnings test prescribed by the OPUC to occur by the end of the third quarter of the following year.

• Post-review - This class of costs represents remediation spend that has been deemed prudent and allowed after applying the earnings test, but is not yet included in amortization. We earn a carrying cost on these amounts at a rate equal to the five-year treasury rate plus 100 basis points.

• Amortization - This class of costs represents amounts included in current customer rates for collection and is generally calculated as one-fifth of the post-review deferred balance. We earn a carrying cost equal to the amortization rate determined annually by the OPUC, which approximates a short-term borrowing rate. We included $10.0 million and $8.4 million of deferred remediation expense approved by the OPUC for collection during the 2016-2017 and 2015-2016 PGA years, respectively.

In addition to the collection amount noted above, the Order also provides for the annual collection of $5 million from Oregon customers through a tariff rider. As we collect amounts from customers, we recognize these collections as revenue and separately amortize our deferred regulatory asset balance through operating expense.

We received total environmental insurance proceeds of approximately $150 million as a result of settlements from our litigation that was dismissed in July 2014. Under the OPUC Order, one-third of the Oregon allocated proceeds were applied to costs deferred through 2012, and the remaining two-thirds will be applied to costs over the next 20 years. Annually, the Order provided for the application of $5 million of insurance proceeds plus interest against deferred remediation expense deemed prudent in the same annual period; annual amounts not utilized are carried forward to apply against future prudently incurred costs. We accrue interest on the insurance proceeds in the customer’s favor at a rate equal to the five-year treasury rate plus 100 basis points. As of September 30, 2016, we have applied $63.2 million of insurance proceeds to prudently incurred remediation costs.

The following table presents information regarding the total regulatory asset deferred:

	September 30,						December 31,
In thousands	2016			2015			2015
Deferred costs and interest(1)	$	54,704		$	82,323		$	79,505
Accrued site liabilities(2)	117,202			88,898			125,026
Insurance proceeds and interest	(97,893		)	(121,414		)	(118,677		)
Total regulatory asset deferral(1)	74,013			49,807			85,854
Current regulatory assets(3)	9,734			12,364			9,270
Long-term regulatory assets(3)	64,279			37,443			76,584

⁽¹⁾ Includes pre-review and post-review deferred costs, amounts currently in amortization, and interest, net of amounts collected from customers.

⁽²⁾  Excludes $0.3 million, or 3.32% of the Front Street site liability as the OPUC allows recovery of 96.68% of costs for all sites, including those that historically served only Oregon customers.

⁽³⁾  Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test.

ENVIRONMENTAL EARNINGS TEST. The 2015 Order directed us to implement an annual environmental earnings test for our prudently incurred remediation expense. Prudently incurred Oregon allocated annual remediation expense and interest in excess of the $5 million tariff rider and $5 million insurance proceeds application plus interest on the insurance proceeds are recoverable through the SRRM, to the extent the utility earns at or below our authorized Return On Equity (ROE). To the extent the utility earns more than its authorized ROE in a year, the utility is required to cover environmental expenses and interest on expenses greater than $10 million (plus interest from insurance proceeds) with those earnings that exceed its authorized ROE.

Under the 2015 Order, the OPUC will revisit the deferral and amortization of future remediation expenses, as well as the treatment of remaining insurance proceeds three years from the original Order, or earlier if the Company gains greater certainty about its future remediation costs, to consider whether adjustments to the mechanism may be appropriate.

WASHINGTON DEFERRAL. In Washington, cost recovery and carrying charges on amounts deferred for costs associated with services provided to Washington customers will be determined in a future proceeding. Annually, we review all regulatory assets for recoverability or more often if circumstances warrant. If we should determine all or a portion of these regulatory assets no longer meet the criteria for continued application of regulatory accounting, then we would be required to write-off the net unrecoverable balances against earnings in the period such a determination is made.

Legal Proceedings

NW Natural is subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, we do not expect that the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations or cash flows. See also Part II, Item 1, “Legal Proceedings.”

OREGON STEEL MILLS SITE.In 2004, NW Natural was served with a third-party complaint by the Port of Portland (the Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants, were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Evraz Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial. Although the final outcome of this proceeding cannot be predicted with certainty, we do not expect the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows.

For additional information regarding other commitments and contingencies, see Note 14 in the 2015 Form 10-K.

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Consolidation, Policy [Policy Text Block]

Our core utility business assets and operating activities are largely included in the parent company, NW Natural. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch), NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), and NW Natural Gas Reserves, LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method, which includes NWN Energy’s investment in Trail West Holdings, LLC (TWH) and NNG Financial's investment in Kelso-Beaver (KB) Pipeline. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated financial statements are presented after elimination of all intercompany balances and transactions, except for amounts required to be included under regulatory accounting standards to reflect the effect of such regulation. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage businesses and other non-utility investments and business activities.

New Accounting Pronouncements, Policy [Policy Text Block]

Recently Adopted Accounting Pronouncements

BENEFIT PLAN ACCOUNTING. On July 31, 2015, the FASB issued ASU 2015-12, "Plan Accounting: Defined Benefit Pension Plans, Defined Contribution Pension Plans, and Health and Welfare Benefit Plans." The ASU outlines a three part update. Only part two of the update is applicable for us, which simplifies the investment disclosure requirements for employee benefit plans by allowing certain disclosures at an aggregated level, reducing the number of ways assets must be grouped and analyzed, and no longer requiring investment strategy disclosures for certain investments. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively in the 2016 Form 10-K, for all periods presented. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosures within our pension and other postretirement benefit plan footnote in our 2016 Form 10-K, for all periods presented.

FAIR VALUE MEASUREMENT. On May 1, 2015, the FASB issued ASU 2015-07, "Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent)." The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements were effective for us beginning January 1, 2016 and will be applied retrospectively to all periods presented, in our 2016 Form 10-K. This ASU will not materially affect our financial statements and disclosures, but will change certain presentation and disclosures of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.

INTANGIBLES - GOODWILL AND OTHER INTERNAL-USE SOFTWARE. On April 15, 2015 the FASB issued ASU 2015-05, "Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement." The ASU provides customers guidance on how to determine whether a cloud computing arrangement includes a software license. The new requirements were effective for us beginning January 1, 2016. We will apply the guidance prospectively as contracts arise and do not expect the ASU to materially affect our financial statements and disclosures.

DEBT ISSUANCE COSTS. On April 7, 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," which requires the presentation of debt issuance costs in the balance sheet as a direct deduction from the associated debt liability. The new requirements were effective for us beginning January 1, 2016. The new guidance has been applied on a retrospective basis and is reflected in our consolidated balance sheets and Note 6.

Recently Issued Accounting Pronouncements

STATEMENT OF CASH FLOWS. On August 26, 2016, the FASB issued ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments." The ASU adds guidance pertaining to the classification of certain cash receipts and payments on the statement of cash flows. The purpose of the amendment is to clarify issues that have been creating diversity in practice, including the classification of proceeds from the settlement of insurance claims and proceeds from the settlement of corporate-owned life insurance policies. The amendments in this standard are effective for us beginning January 1, 2018. Early adoption is permitted in any interim or annual period. We are currently assessing the effect of this standard and do not expect this standard to materially affect our financial statements and disclosures.

STOCK BASED COMPENSATION. On March 30, 2016, the FASB issued ASU 2016-09, "Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting." The ASU changes how companies account for certain aspects of share-based payment awards to employees, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The amendments in this standard are effective for us beginning January 1, 2017. Early adoption is permitted in any interim or annual period. We do not expect this standard to materially affect our financial statements and disclosures.

LEASES. On February 25, 2016, the FASB issued ASU 2016-02, "Leases," which revises the existing lease accounting guidance. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases that are greater than 12 months at lease commencement, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Lessor accounting will remain substantially the same under the new standard. Quantitative and qualitative disclosures are also required for users of the financial statements to have a clear understanding of the nature of our leasing activities. The standard is effective for us beginning January 1, 2019, and early adoption is permitted. The new standard must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently assessing the effect of this standard on our financial statements and disclosures.

FINANCIAL INSTRUMENTS. On January 5, 2016, the FASB issued ASU 2016-01, "Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities." The ASU enhances the reporting model for financial instruments, which includes amendments to address aspects of recognition, measurement, presentation, and disclosure. The new standard is effective for us beginning January 1, 2018. Upon adoption, we will be required to make a cumulative-effect adjustment to the consolidated balance sheet in the first quarter of 2018. Early adoption is permitted, and we are currently assessing the effect of this standard on our financial statements and disclosures.

REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts the entity is expected to be entitled to in exchange for those goods or services. The ASU also prescribes a five-step approach to revenue recognition: (1) identify the contract(s) with the customer; (2) identify the separate performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to separate performance obligations; and (5) recognize revenue when, or as, each performance obligation is satisfied. The new requirements prescribe either a full retrospective or simplified transition adoption method. On August 12, 2015, the FASB deferred the effective date by one year to January 1, 2018 for annual reporting periods beginning after December 15, 2017. The FASB also permitted early adoption of the standard, but not before the original effective date of January 1, 2017. We plan to adopt the new standard effective January 1, 2018 and are assessing the effect this standard will have on our financial statements and disclosures.

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2016

Accounting Policies [Abstract]

Schedule of Regulatory Assets [Table Text Block]

	Regulatory Assets
	September 30,				December 31,
In thousands	2016		2015		2015
Current:
Unrealized loss on derivatives(1)	$	5,205	$	21,949	$	22,092
Gas costs	10,164		19,274		8,717
Environmental costs(2)	9,734		12,364		9,270
Decoupling(3)	16,028		19,391		18,775
Other(4)	14,149		9,734		10,324
Total current	$	55,280	$	82,712	$	69,178
Non-current:
Unrealized loss on derivatives(1)	$	1,682	$	3,540	$	3,447
Pension balancing(5)	48,637		41,193		43,748
Income taxes	40,106		44,767		43,049
Pension and other postretirement benefit liabilities	174,282		189,111		184,223
Environmental costs(2)	64,279		37,443		76,584
Gas costs	712		2,098		1,949
Decoupling(3)	1,006		4,331		6,349
Other(4)	10,484		11,470		11,362
Total non-current	$	341,188	$	333,953	$	370,711

Schedule of Regulatory Liabilities [Table Text Block]

	Regulatory Liabilities
	September 30,				December 31,
In thousands	2016		2015		2015
Current:
Gas costs	$	12,001	$	22,499	$	14,157
Unrealized gain on derivatives(1)	4,857		2,939		2,659
Other(4)	11,063		8,689		13,111
Total current	$	27,921	$	34,127	$	29,927
Non-current:
Gas costs	$	765	$	6,357	$	8,869
Unrealized gain on derivatives(1)	1,151		299		27
Accrued asset removal costs(6)	336,699		324,467		327,047
Other(4)	3,528		3,367		3,344
Total non-current	$	342,143	$	334,490	$	339,287

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

EPS Calculation [Table Text Block]

	Three Months Ended September 30,						Nine Months Ended September 30,
In thousands, except per share data	2016			2015			2016		2015
Net income (loss)	$	(8,040	)	$	(6,685	)	$	30,620	$	23,998
Average common shares outstanding - basic	27,554			27,363			27,504		27,336
Additional shares for stock-based compensation plans (See Note 5)	—			—			125		63
Average common shares outstanding - diluted	27,554			27,363			27,629		27,399
Earnings (loss) per share of common stock - basic	$	(0.29	)	$	(0.24	)	$	1.11	$	0.88
Earnings (loss) per share of common stock - diluted	$	(0.29	)	$	(0.24	)	$	1.11	$	0.88
Additional information:
Antidilutive shares	159			91			5		19

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Segment Reporting (Tables)

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

	Three Months Ended September 30,
In thousands	Utility			Gas Storage		Other			Total
2016
Operating revenues	$	80,378		$	7,293	$	56		$	87,727
Depreciation and amortization	19,173			1,455		—			20,628
Income (loss) from operations	(7,264		)	3,502		(675		)	(4,437		)
Net income (loss)	(9,511		)	1,813		(342		)	(8,040		)
Capital expenditures	36,238			437		—			36,675
2015
Operating revenues	$	87,475		$	5,596	$	57		$	93,128
Depreciation and amortization	18,721			1,621		—			20,342
Income (loss) from operations	(4,088		)	2,204		11			(1,873		)
Net income (loss)	(7,529		)	799		45			(6,685		)
Capital expenditures	28,325			526		—			28,851

	Nine Months Ended September 30,
In thousands	Utility		Gas Storage		Other			Total
2016
Operating revenues	$	422,617	$	19,654	$	168		$	442,439
Depreciation and amortization	56,894		4,541		—			61,435
Income (loss) from operations	74,745		8,107		(611		)	82,241
Net income (loss)	26,848		3,988		(216		)	30,620
Capital expenditures	96,710		1,401		—			98,111
Total assets at September 30, 2016	2,684,618		259,483		15,783			2,959,884
2015
Operating revenues	476,672		16,232		169			493,073
Depreciation and amortization	55,798		4,885		—			60,683
Income from operations	59,955		3,998		89			64,042
Net income	23,051		827		120			23,998
Capital expenditures	84,598		2,325		—			86,923
Total assets at September 30, 2015	2,686,367		269,228		15,123			2,970,718
Total assets at December 31, 2015	2,792,736		261,750		14,924			3,069,410

Utility Margin [Table Text Block]

	Three Months Ended September 30,				Nine Months Ended September 30,
In thousands	2016		2015		2016		2015
Utility margin calculation:
Utility operating revenues(1)	$	80,378	$	87,475	$	422,617	$	476,672
Less: Utility cost of gas	28,264		35,856		157,546		223,737
Environmental remediation expense	1,191		—		8,113		—
Utility margin	$	50,923	$	51,619	$	256,958	$	252,935

⁽¹⁾   Utility operating revenues include environmental recovery revenues, which are collections received from customers through our environmental recovery mechanism in Oregon, offset by environmental remediation expense. Collections under this mechanism began in November 2015.

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Stock-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

Stock price on valuation date	$	50.15
Performance term (in years)	3.0
Quarterly dividends paid per share	$	0.4675
Expected dividend yield	3.7		%
Dividend discount factor	0.9010

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Debt (Tables)

9 Months Ended

Sep. 30, 2016

Long-term Debt, Current and Noncurrent [Abstract]

Fair Value Of Long Term Debt Table [Text Block]

	September 30,						December 31,
In thousands	2016			2015			2015
Gross long-term debt	$	601,700		$	621,700		$	601,700
Unamortized debt issuance costs	(6,487		)	(7,647		)	(7,282		)
Carrying amount	$	595,213		$	614,053		$	594,418
Estimated fair value(1)	701,183			697,647			667,168

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Pension and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2016

Pension and Other Postretirement Benefit Expense [Abstract]

Schedule of Amounts Recognized in Other Comprehensive Income (Loss) [Table Text Block]

	Three Months Ended September 30,						Nine Months Ended September 30,
In thousands	2016			2015			2016			2015
Beginning balance	$	(6,825	)	$	(9,413	)	$	(7,162	)	$	(10,076	)
Amounts reclassified to AOCL	(1,795		)	—			(1,795		)	—
Amounts reclassified from AOCL:
Amortization of actuarial losses	371			549			962			1,645
Loss from plan settlement	193			—			193			—
Total reclassifications before tax	(1,231		)	549			(640		)	1,645
Tax (benefit) expense	486			(217		)	232			(650		)
Total reclassifications for the period	(745		)	332			(408		)	995
Ending balance	$	(7,570	)	$	(9,081	)	$	(7,570	)	$	(9,081	)

Schedule of Net Benefit Costs [Table Text Block]

	Three Months Ended September 30,												Nine Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
In thousands	2016			2015			2016			2015			2016			2015			2016			2015
Service cost	$	1,978		$	2,308		$	119		$	145		$	5,866		$	6,926		$	361		$	435
Interest cost	4,607			4,597			301			291			13,755			13,787			901			874
Expected return on plan assets	(5,017		)	(5,174		)	—			—			(15,051		)	(15,522		)	—			—
Amortization of net actuarial loss	3,555			4,561			192			125			10,559			13,683			575			376
Amortization of prior service costs	57			57			(117		)	50			173			173			(351		)	148
Settlement expense(1)	193			—			—			—			193			—			—			—
Net periodic benefit cost	5,373			6,349			495			611			15,495			19,047			1,486			1,833
Amount allocated to construction	(1,556		)	(2,061		)	(163		)	(218		)	(4,678		)	(5,765		)	(491		)	(607		)
Amount deferred to regulatory balancing account(2)	(1,542		)	(2,171		)	—			—			(4,762		)	(6,511		)	—			—
Net amount charged to expense	$	2,275		$	2,117		$	332		$	393		$	6,055		$	6,771		$	995		$	1,226

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Income Tax (Tables)

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

	Three Months Ended September 30,						Nine Months Ended September 30,
Dollars in thousands	2016			2015			2016			2015
Income taxes at statutory rates (federal and state)	$	(5,339	)	$	(4,473	)	$	20,620		$	15,848
Increase (decrease):
Differences required to be flowed-through by regulatory commissions	(381		)	(378		)	1,202			1,036
Other, net	246			298			(528		)	(940		)
Total provision (benefit) for income taxes	$	(5,474	)	$	(4,553	)	$	21,294		$	15,944
Effective tax rate	40.5		%	40.5		%	41.0		%	39.9		%

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2016

Public Utilities, Property, Plant and Equipment [Abstract]

Major Classifications Of Property, Plant And Equipment And Accumulated Depreciation [Text Block]

	September 30,				December 31,
In thousands	2016		2015		2015
Utility plant in service	$	2,815,340	$	2,710,658	$	2,745,485
Utility construction work in progress	58,470		58,280		39,288
Less: Accumulated depreciation	899,851		867,281		867,377
Utility plant, net	1,973,959		1,901,657		1,917,396
Non-utility plant in service	298,586		296,169		296,839
Non-utility construction work in progress	4,800		7,891		7,768
Less: Accumulated depreciation	43,483		37,856		39,340
Non-utility plant, net	259,903		266,204		265,267
Total property, plant, and equipment	$	2,233,862	$	2,167,861	$	2,182,663
Capital expenditures in accrued liabilities	$	8,918	$	9,700	$	8,985

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Gas Reserves (Tables)

9 Months Ended

Sep. 30, 2016

Gas Reserves [Abstract]

Gas Reserves Table [Text Block]

	September 30,				December 31,
In thousands	2016		2015		2015
Gas reserves, current	$	16,257	$	17,822	$	17,094
Gas reserves, non-current	171,280		169,300		170,453
Less: Accumulated amortization	67,304		51,516		55,901
Total gas reserves(1)	120,233		135,606		131,646
Less: Deferred taxes on gas reserves	25,799		23,042		27,203
Net investment in gas reserves	$	94,434	$	112,564	$	104,443

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

	September 30,				December 31,
In thousands	2016		2015		2015
Natural gas (in therms):
Financial	537,100		416,075		346,875
Physical	621,230		521,350		404,645
Foreign exchange (in thousands)	$	8,404	$	8,023	$	9,025

Income Statement Presentation of Derivative Instruments [Text Block]

	Three Months Ended September 30,
	2016						2015
In thousands	Natural gas commodity			Foreign exchange			Natural gas commodity			Foreign exchange
Benefit (expense) to cost of gas	$	(8,045	)	$	(52	)	$	(8,415	)	$	(150	)
Operating (loss) revenues	(110		)	—			33			—
Less:
Amounts deferred to regulatory accounts on balance sheet	8,118			52			8,391			150
Total (loss) gain in pre-tax earnings	$	(37	)	$	—		$	9		$	—

	Nine Months Ended September 30,
	2016						2015
In thousands	Natural gas commodity			Foreign exchange			Natural gas commodity			Foreign exchange
Benefit (expense) to cost of gas	$	5,562		$	5		$	(21,876	)	$	(413	)
Operating (loss) revenues	(266		)	—			55			—
Less:
Amounts deferred to regulatory accounts on balance sheet	(5,385		)	(5		)	21,838			413
Total (loss) gain in pre-tax earnings	$	(89	)	$	—		$	17		$	—

Table Of Estimated Collateral Calls Table [Text Block]

			Credit Rating Downgrade Scenarios
In thousands	(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3			Speculative
With Adequate Assurance Calls	$	—	$	—	$	—	$	(1,036	)	$	(1,242	)
Without Adequate Assurance Calls	—		—		—		(1,036		)	181

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Environmental Matters (Tables)

9 Months Ended

Sep. 30, 2016

Environmental Remediation Obligations [Abstract]

Schedule of Environmental Loss Contingencies by Site [Table Text Block]

	Current Liabilities						Non-Current Liabilities
	September 30,				December 31,		September 30,				December 31,
In thousands	2016		2015		2015		2016		2015		2015
Portland Harbor site:
Gasco/Siltronic Sediments	$	1,726	$	1,236	$	2,229	$	42,880	$	38,533	$	42,641
Other Portland Harbor	1,461		1,243		1,972		4,362		4,563		5,073
Gasco Upland site	8,191		4,510		10,599		49,928		36,795		52,117
Siltronic Upland site	—		538		951		—		489		337
Central Service Center site	112		177		25		—		—		—
Front Street site	841		420		1,155		7,818		215		7,748
Oregon Steel Mills	—		—		—		179		179		179
Total	$	12,331	$	8,124	$	16,931	$	105,167	$	80,774	$	108,095

Environmental Regulatory Table [Table Text Block]

	September 30,						December 31,
In thousands	2016			2015			2015
Deferred costs and interest(1)	$	54,704		$	82,323		$	79,505
Accrued site liabilities(2)	117,202			88,898			125,026
Insurance proceeds and interest	(97,893		)	(121,414		)	(118,677		)
Total regulatory asset deferral(1)	74,013			49,807			85,854
Current regulatory assets(3)	9,734			12,364			9,270
Long-term regulatory assets(3)	64,279			37,443			76,584

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Organization and Principles of Consolidation Organization and Principles of Consolidation (Details)	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of Operating Segments	2

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Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2016 USD ($)
Annual tariff rider collection	$ 5,000

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Summary of Significant Accounting Policies Regulatory Asset Disclosure (Details) - USD ($) $ in Thousands		Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Regulatory Assets [Line Items]
Regulatory Assets, Current		$ 55,280	$ 69,178	$ 82,712
Regulatory Assets, Noncurrent		341,188	370,711	333,953
Unrealized Loss On Derivatives [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current	[1]	5,205	22,092	21,949
Regulatory Assets, Noncurrent	[1]	1,682	3,447	3,540
Asset Recoverable Gas Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current		10,164	8,717	19,274
Regulatory Assets, Noncurrent		712	1,949	2,098
Environmental Restoration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current	[2],[3]	9,734	9,270	12,364
Regulatory Assets, Noncurrent	[3]	64,279	76,584	37,443
Environmental Regulatory Assets Noncurrent	[4]	74,013	85,854	49,807
Other Regulatory [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Current	[5]	14,149	10,324	9,734
Regulatory Assets, Noncurrent	[5]	10,484	11,362	11,470
Pension Balancing [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent	[6]	48,637	43,748	41,193
Deferred Income Tax Charge [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent		40,106	43,049	44,767
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, Noncurrent		174,282	184,223	189,111
Decoupling [Domain]
Regulatory Assets [Line Items]
Regulatory Assets, Current	[7]	16,028	18,775	19,391
Regulatory Assets, Noncurrent	[7]	$ 1,006	$ 6,349	$ 4,331

[1] Unrealized gains or losses on derivatives are non-cash items and, therefore, do not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the annual Purchased Gas Adjustment (PGA) mechanism when realized at settlement.

[2] Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test.

[3] Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, recovery of deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from Oregon customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test. See Note 13.

[4] Includes pre-review and post-review deferred costs, amounts currently in amortization, and interest, net of amounts collected from customers

[5] These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge.

[6] The deferral of certain pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower net periodic benefit costs in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of interest income recognized when amounts are collected in rates.

[7] This deferral represents the margin adjustment resulting from differences between actual and expected volumes.

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Summary of Significant Accounting Policies Regulatory Liability Disclosure (Details) - USD ($) $ in Thousands		Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities		$ 27,921	$ 29,927	$ 34,127
Regulatory liabilities		342,143	339,287	334,490
Gas Costs Payable [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities		12,001	14,157	22,499
Regulatory liabilities		765	8,869	6,357
Unrealized Gain On Derivatives [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	[1]	4,857	2,659	2,939
Regulatory liabilities	[1]	1,151	27	299
Other Regulatory [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	[2]	11,063	13,111	8,689
Regulatory liabilities	[2]	3,528	3,344	3,367
Asset Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	[3]	$ 336,699	$ 327,047	$ 324,467

[1] Unrealized gains or losses on derivatives are non-cash items and, therefore, do not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the annual Purchased Gas Adjustment (PGA) mechanism when realized at settlement.

[2] These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge.

[3] Estimated costs of removal on certain regulated properties are collected through rates.

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share [Abstract]
Net Income	$ (8,040)	$ (6,685)	$ 30,620	$ 23,998
Average common shares outstanding - basic	27,554	27,363	27,504	27,336
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	0	0	125	63
Average common shares outstanding - diluted	27,554	27,363	27,629	27,399
Earnings per share of common stock - basic	$ (0.29)	$ (0.24)	$ 1.11	$ 0.88
Earnings per share of common stock - diluted	$ (0.29)	$ (0.24)	$ 1.11	$ 0.88
Antidilutive shares excluded from computation of earnings per share amount	159	91	5	19

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Segment Information (Details) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Segment Reporting Information [Line Items]
Operating revenues		$ 87,727	$ 93,128	$ 442,439	$ 493,073
Cost of Gas		28,264	35,856	157,546	223,737
Environmental Remediation Expense		1,191	0	8,113	0
Depreciation and amortization		20,628	20,342	61,435	60,683
Income from operations		(4,437)	(1,873)	82,241	64,042
Net Income		(8,040)	(6,685)	30,620	23,998
Capital expenditures		36,675	28,851	98,111	86,923
Assets		2,959,884	2,970,718	$ 2,959,884	2,970,718	$ 3,069,410
Operating Segments [Member]
Segment Reporting Information [Line Items]
Number of Reportable Segments				2
Operating Segments [Member] | Utility Segment [Member]
Segment Reporting Information [Line Items]
Operating revenues	[1]	80,378	87,475	$ 422,617	476,672
Cost of Gas		28,264	35,856	157,546	223,737
Environmental Remediation Expense		1,191	0	8,113	0
Gross Profit		50,923	51,619	256,958	252,935
Depreciation and amortization		19,173	18,721	56,894	55,798
Income from operations		(7,264)	(4,088)	74,745	59,955
Net Income		(9,511)	(7,529)	26,848	23,051
Capital expenditures		36,238	28,325	96,710	84,598
Assets		2,684,618	2,686,367	2,684,618	2,686,367	2,792,736
Operating Segments [Member] | Gas Storage Segment [Member]
Segment Reporting Information [Line Items]
Operating revenues		7,293	5,596	19,654	16,232
Depreciation and amortization		1,455	1,621	4,541	4,885
Income from operations		3,502	2,204	8,107	3,998
Net Income		1,813	799	3,988	827
Capital expenditures		437	526	1,401	2,325
Assets		259,483	269,228	259,483	269,228	261,750
Operating Segments [Member] | Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
Operating revenues		56	57	168	169
Depreciation and amortization		0	0	0	0
Income from operations		(675)	11	(611)	89
Net Income		(342)	45	(216)	120
Capital expenditures		0	0	0	0
Assets		$ 15,783	$ 15,123	$ 15,783	$ 15,123	$ 14,924

[1] Utility operating revenues include environmental recovery revenues, which are collections received from customers through our environmental recovery mechanism in Oregon, offset by environmental remediation expense. Collections under this mechanism began in November 2015.

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Stock-Based Compensation (Details) - Long Term Incentive Plan [Member]	9 Months Ended
	Sep. 30, 2016 USD ($) $ / shares shares
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Exercise Price | $ / shares	$ 50.15
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Payments | $	$ 0.4675
Fair Value Assumptions, Expected Dividend Rate	3.70%
Share-based Compensation Arrangement by Share-based Payment Award, Discount from Market Price, Offering Date	90.10%
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted | shares	36,259
Unrecognized compensation expense | $	$ 2,700,000
Unrecognized compensation cost, period for recognition	through 2018
Weighted Average Price Per LTIP
Granted | $ / shares	$ 50.13
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense | $	$ 3,300,000
Unrecognized compensation cost, period for recognition	through 2021
Number of RSUs
Granted | shares	36,591
Weighted Average Price Per LTIP
Granted | $ / shares	$ 54.21

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Debt (Details) - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Short-term Debt [Abstract]
Short-term Debt		$ 194,900	$ 225,200	$ 270,035
Commercial Paper, Maximum Maturity		55 days
Commercial Paper, Average Maturity		28 days
Debt Outstanding
Long-term Debt, Gross		$ 601,700	621,700	601,700
Unamortized Debt Issuance Expense		(6,487)	(7,647)	(7,282)
Long-term Debt		595,213	614,053	594,418
Long-term Debt, Current Maturities		64,994	0	24,973
Long-term debt, noncurrent		$ 530,219	$ 614,053	569,445
Repayments of Long-term Debt [Abstract]
Debt Instrument, Maturity Date Range, Start		Dec. 15, 2016	Oct. 31, 2042
Long-term Debt, Weighted Average Interest Rate		5.70%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum		3.176%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum		9.05%
Liabilities, Fair Value Disclosure [Abstract]
Debt Instrument, Fair Value Disclosure	[1]	$ 701,183	$ 697,647	$ 667,168

[1] Estimated fair value does not include unamortized debt issuance costs.

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Pension and Other Postretirement Benefits (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Accumulated Other Comprehensive loss, beginning of period				$ (7,162)
Accumulated Other Comprehensive loss, end of period		$ (7,570)	$ (9,081)	(7,570)	$ (9,081)
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Defined Contribution Plan, Cost Recognized				3,600	2,900
Pension Plan [Member]
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Defined Benefit Plan, Service Cost		1,978	2,308	5,866	6,926
Defined Benefit Plan, Interest Cost		4,607	4,597	13,755	13,787
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Defined Benefit Plan, Service Cost		1,978	2,308	5,866	6,926
Defined Benefit Plan, Interest Cost		4,607	4,597	13,755	13,787
Defined Benefit Plan, Expected Return on Plan Assets		(5,017)	(5,174)	(15,051)	(15,522)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		3,555	4,561	10,559	13,683
Defined Benefit Plan, Amortization of loss		57	57	173	173
Defined Benefit Plan, Settlements, Benefit Obligation	[1]	193	0	193	0
Defined Benefit Plan Net Periodic Benefit Cost		5,373	6,349	15,495	19,047
Defined Benefit Plan Amount Allocated To Construction		(1,556)	(2,061)	(4,678)	(5,765)
Defined Benefit Plan Net Amount Deferred To Regulatory Balancing Account	[2]	(1,542)	(2,171)	(4,762)	(6,511)
Defined Benefit Plan Net Amount Charged To Expense		2,275	2,117	6,055	6,771
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Defined Benefit Plan, Service Cost		119	145	361	435
Defined Benefit Plan, Interest Cost		301	291	901	874
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Defined Benefit Plan, Service Cost		119	145	361	435
Defined Benefit Plan, Interest Cost		301	291	901	874
Defined Benefit Plan, Expected Return on Plan Assets		0	0	0	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		192	125	575	376
Defined Benefit Plan, Amortization of loss		(117)	50	(351)	148
Defined Benefit Plan, Settlements, Benefit Obligation	[1]	0	0	0	0
Defined Benefit Plan Net Periodic Benefit Cost		495	611	1,486	1,833
Defined Benefit Plan Amount Allocated To Construction		(163)	(218)	(491)	(607)
Defined Benefit Plan Net Amount Deferred To Regulatory Balancing Account	[2]	0	0	0	0
Defined Benefit Plan Net Amount Charged To Expense		332	393	995	1,226
Qualified Pension Plans, Defined Benefit [Member]
Pension and Other Postretirement Benefit Contributions [Abstract]
Qualified Defined Benefit Pension Plan Contributions				11,300
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year				3,200
Non-Qualified Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, before Tax		(1,795)	0	(1,795)	0
Defined Benefit Plan Amounts Recognized In Regulatory Amortization And Other Comprehensive Income Net Prior Service Cost Credit Before Tax [Abstract]
Accumulated Other Comprehensive loss, beginning of period		(6,825)	(9,413)	(7,162)	(10,076)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		371	549	962	1,645
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, before Tax		(1,231)	549	(640)	1,645
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Tax, Portion Attributable to Parent		486	(217)	232	(650)
Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax		(745)	332	(408)	995
Accumulated Other Comprehensive loss, end of period		(7,570)	(9,081)	(7,570)	(9,081)
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Defined Benefit Plan, Settlements, Benefit Obligation		$ 193	$ 0	$ 193	$ 0

[1] During the three months ended September 30, 2016, a participant within the Company's Supplemental Executive Retirement Plan elected to have their benefit paid out in a one-time lump-sum cash payment. Accordingly, this transaction qualified for settlement accounting and a pro rata portion of the associated loss in Accumulated Other Comprehensive Loss was immediately recognized in earnings.

[2] The deferral of defined benefit pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account. The balancing account includes the expectation of higher net periodic benefit costs than costs recovered in rates in the near-term with lower net periodic benefit costs than costs recovered in rates expected in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of the interest recognized when amounts are collected in rates. See Note 2 in the 2015 Form 10-K.

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Income Tax (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income Tax Reconciliation, Income Tax Expense (Benefit), at Federal Statutory Income Tax Rate	$ (5,339)	$ (4,473)	$ 20,620	$ 15,848
Income Tax Reconciliation, Differences Regulatory Commission	(381)	(378)	1,202	1,036
Income Tax Reconciliation, Other Adjustments	246	298	(528)	(940)
Income Tax Expense (Benefit)	$ (5,474)	$ (4,553)	$ 21,294	$ 15,944
Effective Income Tax Rate	40.50%	40.50%	41.00%	39.90%

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Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment, gross	$ 3,177,196	$ 3,089,380	$ 3,072,998
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	943,334	906,717	905,137
Total property, plant, and equipment, net	2,233,862	2,182,663	2,167,861
Property, Plant, Equipment non-cash	8,918	8,985	9,700
Utility Plant [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment, gross	2,815,340	2,745,485	2,710,658
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	58,470	39,288	58,280
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	899,851	867,377	867,281
Total property, plant, and equipment, net	1,973,959	1,917,396	1,901,657
Non Utility Plant [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment, gross	298,586	296,839	296,169
Public Utilities, Property, Plant and Equipment, Construction Work in Progress	4,800	7,768	7,891
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	43,483	39,340	37,856
Total property, plant, and equipment, net	$ 259,903	$ 265,267	$ 266,204

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Gas Reserves (Details) - USD ($)		9 Months Ended
		Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Gas Reserves [Abstract]
Total cumulative gas reserves investment		$ 188,000,000
Encana Gas reserves investment		178,000,000
Cumulative gross investment Jonah Wells		10,000,000
Additional Jonah Wells rate per therm		0.4725
Gas Reserves, Current		16,257,000	$ 17,094,000	$ 17,822,000
Gas Reserves Noncurrent Gross		171,280,000	170,453,000	169,300,000
Gas Reserves Amortization		67,304,000	55,901,000	51,516,000
Total Gas Reserves	[1]	120,233,000	131,646,000	135,606,000
Deferred Taxes Related To Gas Reserves		25,799,000	27,203,000	23,042,000
Net Gas Reserves Investment	[1]	94,434,000	104,443,000	112,564,000
Total gas reserves investment Jonah Wells		$ 7,000,000	$ 8,000,000	$ 9,700,000

[1] Our investment in additional wells included in total gas reserves was $7.0 million, $9.7 million and $8.0 million at September 30, 2016 and 2015 and December 31, 2015, respectively.

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Investments (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Investments [Abstract]
Ownership percentage of TWH	50.00%
Equity Method Investment, Underlying Equity in Net Assets	$ 13.4	$ 13.4	$ 13.4

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Derivative Instruments Gain (Loss) by Hedging Relationship, by Income Statement Location, by Derivative Instrument Risk (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Nov. 01, 2016	Dec. 31, 2015 USD ($)	Nov. 01, 2015
Derivative [Line Items]
Target Hedge for 2015-16 gas year							75.00%
Financial Derivative, Nonmonetary Notional Amount	537,100,000	416,075,000	537,100,000	416,075,000		346,875,000
Derivative, Nonmonetary Notional Amount	621,230,000	521,350,000	621,230,000	521,350,000		404,645,000
Notional Amount of Foreign Currency Derivatives	$ 8,404	$ 8,023	$ 8,404	$ 8,023		$ 9,025
Target Hedge for 2015-16 gas year					75.00%
Operating revenues	87,727	93,128	442,439	493,073
Derivative, Loss on Derivative	975	2,300	24,062	24,300
Unrealized Gain On Derivatives			2,682
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	4,058	3,100	4,058	3,100		2,700
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	5,066	25,300	5,066	25,300		25,500
Derivative Fair Value Of Derivative Net	1,008	22,200	1,008	22,200		$ 22,800
Natural Gas Commodity [Member]
Derivative [Line Items]
Cost of sales	(8,045)	(8,415)	5,562	(21,876)
Operating revenues	(110)	33	(266)	55
Less:Amounts deferred to regulatory accounts on balance sheet	8,118	8,391	(5,385)	21,838
Total Impact On Earnings	(37)	9	(89)	17
Foreign Currency [Member]
Derivative [Line Items]
Cost of sales	(52)	(150)	5	(413)
Operating revenues	0	0	0	0
Less:Amounts deferred to regulatory accounts on balance sheet	52	150	(5)	413
Total Impact On Earnings	$ 0	$ 0	$ 0	$ 0

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Derivative Instruments Credit Rating Downgrade Scenarios (Details) $ in Thousands	Sep. 30, 2016 USD ($)
Moody's, A3 Rating [Member]
Description Of Credit Risk Related Contingent Features [Line Items]
With Adequate Assurance Calls	$ 0
Without Adequate Assurance Calls	0
Moody's, Baa1 Rating [Member]
Description Of Credit Risk Related Contingent Features [Line Items]
With Adequate Assurance Calls	0
Without Adequate Assurance Calls	0
Moody's, Baa2 Rating [Member]
Description Of Credit Risk Related Contingent Features [Line Items]
With Adequate Assurance Calls	0
Without Adequate Assurance Calls	0
Moody's, Baa3 Rating [Member]
Description Of Credit Risk Related Contingent Features [Line Items]
With Adequate Assurance Calls	(1,036)
Without Adequate Assurance Calls	(1,036)
Speculative [Member]
Description Of Credit Risk Related Contingent Features [Line Items]
With Adequate Assurance Calls	(1,242)
Without Adequate Assurance Calls	$ 181

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Environmental Matters (Details) - USD ($)		9 Months Ended
		Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2015
Environmental Activity [Line Items]
Remediation recovery percentage in Oregon		96.68%
Remediation non-recovery percentage for Oregon		3.32%
Loss Contingency Range Of Possible Loss Portland Harbor		$791 million to $2.45 billion
Portland Harbor EPA clean-up present value cost		$ 746,000,000
Portland Harbor Number Of Potentially Responsible Parties		more than 100
Loss Contingency Range Of Possible Loss Gasco Siltronic		$44.6 million to $350 million
Gasco Siltronic Sediments Project Liability		$ 44,600,000.0
Gasco Groundwater Source Control construction costs		19,000,000.0
Gasco Groundwater Source Control Allocated Insurance Proceeds To Constructed Water Treatment Station		2,500,000
Front Street liability for studies and design costs		1,100,000
SRRM pre-tax regulatory disallowance		15,000,000
Deferred environmental charges		95,000,000
After-tax regulatory disallowance on insurance proceeds		5,300,000
SRRM Amortization Expenses		13,800,000
Total SRRM Disallowance from Feb 2016 Order		3,300,000
Interest disallowed on SRRM regulatory disallowance		2,800,000
SRRM Disallowance, Portion attributable to Operations and Maintenance		500,000
Deferred remediation expense to be collected		8,400,000
Annual tariff rider collection		5,000,000
Environmental Settlement Insurance Proceeds Received To Date		150,000,000
Annual insurance proceeds to appy against remediation costs		5,000,000
Insurance proceeds applied to prudently incurred remediation costs		63,200,000
Total Annual remediation expense and interest		10,000,000
Accrual for Environmental Loss Contingencies [Abstract]
Accrued Environmental Loss Contingencies, Current		12,331,000	$ 16,931,000	$ 8,124,000
Accrued Environmental Loss Contingencies, Noncurrent		105,167,000	108,095,000	80,774,000
Environmental Regulatory Table [Abstract]
Regulatory Assets, Current		55,280,000	69,178,000	82,712,000
Regulatory Assets, Noncurrent		341,188,000	370,711,000	333,953,000
Minimum [Member]
Environmental Activity [Line Items]
Portland Harbor EPA clean-up present value cost		(0.30)
Front Street Remedial Costs		7,600,000
Maximum [Member]
Environmental Activity [Line Items]
Portland Harbor EPA clean-up present value cost		0.50
Front Street Remedial Costs		12,900,000
Gasco Siltronic Sediments [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Accrued Environmental Loss Contingencies, Current		1,726,000	2,229,000	1,236,000
Accrued Environmental Loss Contingencies, Noncurrent		42,880,000	42,641,000	38,533,000
Portland Harbor Other [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Accrued Environmental Loss Contingencies, Current		1,461,000	1,972,000	1,243,000
Accrued Environmental Loss Contingencies, Noncurrent		4,362,000	5,073,000	4,563,000
Gasco Upland [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Accrued Environmental Loss Contingencies, Current		8,191,000	10,599,000	4,510,000
Accrued Environmental Loss Contingencies, Noncurrent		49,928,000	52,117,000	36,795,000
Siltronic Upland [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Accrued Environmental Loss Contingencies, Current		0	951,000	538,000
Accrued Environmental Loss Contingencies, Noncurrent		0	337,000	489,000
Central Service Center [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Accrued Environmental Loss Contingencies, Current		112,000	25,000	177,000
Accrued Environmental Loss Contingencies, Noncurrent		0	0	0
Front Street [Member]
Environmental Activity [Line Items]
Remediation non-recovery portion for Oregon		300,000
Accrual for Environmental Loss Contingencies [Abstract]
Accrued Environmental Loss Contingencies, Current		841,000	1,155,000	420,000
Accrued Environmental Loss Contingencies, Noncurrent		7,818,000	7,748,000	215,000
Oregon Steel Mills [Member]
Accrual for Environmental Loss Contingencies [Abstract]
Accrued Environmental Loss Contingencies, Current		0	0	0
Accrued Environmental Loss Contingencies, Noncurrent		179,000	179,000	179,000
Environmental Restoration Costs [Member]
Environmental Regulatory Table [Abstract]
Environmental Regulatory- deferred costs and interest	[1]	54,704,000	79,505,000	82,323,000
Environmental Regulatory accrued site liabilities	[2]	117,202,000	125,026,000	88,898,000
Environmental Regulatory insurance proceeds and interest		(97,893,000)	(118,677,000)	(121,414,000)
Environmental Regulatory Assets Noncurrent	[1]	74,013,000	85,854,000	49,807,000
Regulatory Assets, Current	[3],[4]	9,734,000	9,270,000	12,364,000
Regulatory Assets, Noncurrent	[4]	$ 64,279,000	$ 76,584,000	$ 37,443,000

[1] Includes pre-review and post-review deferred costs, amounts currently in amortization, and interest, net of amounts collected from customers

[2] Excludes $0.3 million, or 3.32% of the Front Street site liability as the OPUC allows recovery of 96.68% of costs for all sites, including those that historically served only Oregon customers.

[3] Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test.

[4] Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, recovery of deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from Oregon customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test. See Note 13.