NORTHWEST NATURAL GAS CO - FORM 10-Q

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EX-32.1 - EXHIBIT 32.1 CEO AND CFO CERTIFICATION - NORTHWEST NATURAL GAS CO	ex321q32017.htm
EX-31.2 - EXHIBIT 31.2 CFO CERTIFICATION - NORTHWEST NATURAL GAS CO	ex312q32017.htm
EX-31.1 - EXHIBIT 31.1 CEO CERTIFICATION - NORTHWEST NATURAL GAS CO	ex311q32017.htm
EX-12 - EXHIBIT 12 FIXED CHARGES - NORTHWEST NATURAL GAS CO	ex12q32017.htm

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, 2017

[ ] 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", "smaller reporting company" and "emerging growth 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) Emerging Growth Company [ ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

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 27, 2017, 28,713,052 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, 2017

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		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, 2017 and 2016	5

	Consolidated Balance Sheets at September 30, 2017 and 2016 and December 31, 2016	6

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016	8

	Notes to Unaudited Consolidated Financial Statements	9

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48

Item 4.	Controls and Procedures	48

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	49

Item 1A.	Risk Factors	49

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49

Item 6.	Exhibits	49

	Signature	50

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FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, which are subject to the safe harbors created by such Act. Forward-looking statements can be identified by words such as anticipates, assumes, intends, plans, seeks, projects, believes, predicts, 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;


•	ongoing continuation of past practices or patterns;


•	future events or performance;


•	trends, uncertainties, timing and cyclicality;


•	weather conditions;


•	risks;


•	earnings and dividends;


•	capital and other expenditures and allocation;


•	capital or organizational structure;


•	climate change and our role in a low carbon future;


•	growth and profitability;


•	customer rates or incentives;


•	labor relations;


•	workforce succession;


•	commodity costs and volumes;


•	gas reserves, volumes, investment and recovery;


•	operational and maintenance performance and costs;


•	energy policy infrastructure and preferences;


•	efficacy of and exposure under derivatives and hedges;


•	liquidity, funding sources, and financial positions;


•	valuations;


•	project and program development, expansion, or investment;


•	pipeline capacity demand, location, and reliability;


•	adequacy of property rights;


•	procurement and development of gas supplies;


•	estimated expenditures;


•	competition;


•	costs of compliance;


•	credit exposures or collateral calls;


•	rate or regulatory outcomes, prudency, recovery or refunds;


•	impacts of, or changes in, laws, rules and regulations;


•	tax positions, liabilities or refunds;


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


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


•	projected obligations, contributions, expectations and treatment under retirement plans;


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


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


•	approval and adequacy of regulatory deferrals;


•	effects and efficacy of regulatory mechanisms;


•	local or national disasters, pandemic illness, terrorist activities, including cyber-attacks, data breaches, 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

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assurances of future operational, economic or financial performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements are discussed in our 2016 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.

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ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
In thousands, except per share data	2017			2016			2017		2016

Operating revenues	$	88,190		$	87,727		$	521,751	$	442,439

Operating expenses:
Cost of gas	27,239			28,264			223,855		157,546
Operations and maintenance	36,867			34,870			115,833		109,771
Environmental remediation	1,355			1,191			10,920		8,113
General taxes	7,901			7,211			24,490		23,333
Depreciation and amortization	21,484			20,628			63,924		61,435
Total operating expenses	94,846			92,164			439,022		360,198
Income (loss) from operations	(6,656		)	(4,437		)	82,729		82,241
Other income (expense), net	1,493			652			3,332		(1,144		)
Interest expense, net	9,451			9,729			29,044		29,183
Income (loss) before income taxes	(14,614		)	(13,514		)	57,017		51,914
Income tax expense (benefit)	(6,119		)	(5,474		)	22,473		21,294
Net income (loss)	(8,495		)	(8,040		)	34,544		30,620
Other comprehensive income (loss):
Change in employee benefit plan liability, net of tax benefits 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 $98 and $223 for the three months ended and $275 and $477 for the nine months ended September 30, 2017 and 2016, respectively	150			341			423		678
Comprehensive income (loss)	$	(8,345	)	$	(8,785	)	$	34,967	$	30,212
Average common shares outstanding:
Basic	28,678			27,554			28,653		27,504
Diluted	28,678			27,554			28,734		27,629
Earnings (loss) per share of common stock:
Basic	$	(0.30	)	$	(0.29	)	$	1.21	$	1.11
Diluted	(0.30		)	(0.29		)	1.20		1.11
Dividends declared per share of common stock	0.4700			0.4675			1.4100		1.4025

See Notes to Unaudited Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	September 30,			September 30,			December 31,
In thousands	2017			2016			2016

Assets:
Current assets:
Cash and cash equivalents	$	15,780		$	6,230		$	3,521
Accounts receivable	23,450			25,506			66,700
Accrued unbilled revenue	15,974			15,537			64,946
Allowance for uncollectible accounts	(459		)	(289		)	(1,290		)
Regulatory assets	49,504			55,280			42,362
Derivative instruments	2,073			4,857			17,031
Inventories	59,549			67,470			54,129
Gas reserves	16,218			16,257			15,926
Income taxes receivable	—			2,257			—
Other current assets	17,457			17,480			24,728
Total current assets	199,546			210,585			288,053
Non-current assets:
Property, plant, and equipment	3,384,122			3,177,196			3,208,816
Less: Accumulated depreciation	986,332			943,334			947,916
Total property, plant, and equipment, net	2,397,790			2,233,862			2,260,900
Gas reserves	87,876			103,976			100,184
Regulatory assets	345,352			341,188			357,530
Derivative instruments	1,555			1,151			3,265
Other investments	69,245			67,853			68,376
Other non-current assets	4,243			1,269			1,493
Total non-current assets	2,906,061			2,749,299			2,791,748
Total assets	$	3,105,607		$	2,959,884		$	3,079,801

See Notes to Unaudited Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	September 30,			September 30,			December 31,
In thousands	2017			2016			2016

Liabilities and equity:
Current liabilities:
Short-term debt	$	—		$	194,900		$	53,300
Current maturities of long-term debt	21,995			64,994			39,989
Accounts payable	87,475			55,933			85,664
Taxes accrued	12,295			11,954			12,149
Interest accrued	9,854			9,671			5,966
Regulatory liabilities	34,659			27,921			40,290
Derivative instruments	8,968			5,334			1,315
Other current liabilities	27,705			31,997			35,844
Total current liabilities	202,951			402,704			274,517
Long-term debt	757,429			530,219			679,334
Deferred credits and other non-current liabilities:
Deferred tax liabilities	572,293			544,575			557,085
Regulatory liabilities	363,838			342,143			349,319
Pension and other postretirement benefit liabilities	212,259			216,909			225,725
Derivative instruments	3,926			1,682			913
Other non-current liabilities	146,229			142,450			142,411
Total deferred credits and other non-current liabilities	1,298,545			1,247,759			1,275,453
Commitments and contingencies (see Note 13 and Note 14)
Equity:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 28,713, 27,558, and 28,630 at September 30, 2017 and 2016, and December 31, 2016, respectively	447,129			389,834			445,187
Retained earnings	406,081			396,938			412,261
Accumulated other comprehensive loss	(6,528		)	(7,570		)	(6,951		)
Total equity	846,682			779,202			850,497
Total liabilities and equity	$	3,105,607		$	2,959,884		$	3,079,801

See Notes to Unaudited Consolidated Financial Statements

NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended September 30,
In thousands	2017			2016

Operating activities:
Net income	$	34,544		$	30,620
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	63,924			61,435
Regulatory amortization of gas reserves	12,036			11,403
Deferred income taxes	17,287			17,810
Qualified defined benefit pension plan expense	3,923			3,989
Contributions to qualified defined benefit pension plans	(15,400		)	(11,250		)
Deferred environmental expenditures, net	(10,468		)	(8,302		)
Regulatory disallowance of prior environmental cost deferrals	—			3,287
Amortization of environmental remediation	10,920			8,113
Other	2,605			4,817
Changes in assets and liabilities:
Receivables, net	90,735			83,377
Inventories	(5,420		)	3,226
Income taxes	146			7,170
Accounts payable	(29,726		)	(17,612		)
Interest accrued	3,888			3,798
Deferred gas costs	13,419			(10,470		)
Other, net	443			14,988
Cash provided by operating activities	192,856			206,399
Investing activities:
Capital expenditures	(145,441		)	(98,111		)
Other	(1,131		)	2,868
Cash used in investing activities	(146,572		)	(95,243		)
Financing activities:
Repurchases related to stock-based compensation	(2,034		)	(1,042		)
Proceeds from stock options exercised	3,711			5,874
Long-term debt issued	100,000			—
Long-term debt retired	(40,000		)	—
Change in short-term debt	(53,300		)	(75,135		)
Cash dividend payments on common stock	(40,390		)	(38,556		)
Other	(2,012		)	(278		)
Cash used in financing activities	(34,025		)	(109,137		)
Increase in cash and cash equivalents	12,259			2,019
Cash and cash equivalents, beginning of period	3,521			4,211
Cash and cash equivalents, end of period	$	15,780		$	6,230

Supplemental disclosure of cash flow information:
Interest paid, net of capitalization	$	22,859		$	23,271
Income taxes paid (refunded)	11,581			(6,900		)

See Notes to Unaudited Consolidated Financial Statements

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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 NWN 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. 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 a fair statement 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 2016 Annual Report on Form 10-K (2016 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 presentation. These reclassifications had no effect on our prior year’s consolidated results of operations, financial condition, or cash flows.

2. SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are described in Note 2 of the 2016 Form 10-K. There were no material changes to those accounting policies during the nine months ended September 30, 2017. 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 return or a carrying charge in certain cases.

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Amounts deferred as regulatory assets and liabilities were as follows:



	Regulatory Assets
	September 30,				December 31,
In thousands	2017		2016		2016
Current:
Unrealized loss on derivatives⁽¹⁾	$	8,887	$	5,205	$	1,315
Gas costs	1,851		10,164		6,830
Environmental costs⁽²⁾	6,362		9,734		9,989
Decoupling⁽³⁾	15,663		16,028		13,067
Other⁽⁴⁾	16,741		14,149		11,161
Total current	$	49,504	$	55,280	$	42,362
Non-current:
Unrealized loss on derivatives⁽¹⁾	$	3,926	$	1,682	$	913
Pension balancing⁽⁵⁾	57,599		48,637		50,863
Income taxes	36,591		40,106		38,670
Pension and other postretirement benefit liabilities	172,687		174,282		183,035
Environmental costs⁽²⁾	63,339		64,279		63,970
Gas costs	48		712		89
Decoupling⁽³⁾	1,025		1,006		5,860
Other⁽⁴⁾	10,137		10,484		14,130
Total non-current	$	345,352	$	341,188	$	357,530



	Regulatory Liabilities
	September 30,				December 31,
In thousands	2017		2016		2016
Current:
Gas costs	$	16,459	$	12,001	$	8,054
Unrealized gain on derivatives⁽¹⁾	2,020		4,857		16,624
Decoupling⁽³⁾	314		—		—
Other⁽⁴⁾	15,866		11,063		15,612
Total current	$	34,659	$	27,921	$	40,290
Non-current:
Gas costs	$	1,015	$	765	$	1,021
Unrealized gain on derivatives⁽¹⁾	1,555		1,151		3,265
Accrued asset removal costs⁽⁶⁾	356,106		336,699		341,107
Other⁽⁴⁾	5,162		3,528		3,926
Total non-current	$	363,838	$	342,143	$	349,319


⁽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 the aforementioned 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

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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, 2017 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

There were no material changes to the recently adopted accounting policies described in Note 2 of the 2016 Form 10-K during the nine months ended September 30, 2017.

Recently Issued Accounting Pronouncements

DERIVATIVES AND HEDGING. On August 28, 2017, the FASB issued ASU 2017-12, "Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities." The purpose of the amendment is to more closely align hedge accounting with companies’ risk management strategies. The ASU amends the accounting for risk component hedging, the hedged item in fair value hedges of interest rate risk, and amounts excluded from the assessment of hedge effectiveness. The guidance also amends the recognition and presentation of the effect of hedging instruments and includes other simplifications of hedge accounting. The amendments in this update are effective for us beginning January 1, 2019. Early adoption is permitted. The amended presentation and disclosure guidance is required prospectively. We are currently assessing the effect of this standard on our financial statements and disclosures.

STOCK COMPENSATION. On May 10, 2017, the FASB issued ASU 2017-09, "Stock Compensation - Scope of Modification Accounting." The purpose of the amendment is to provide clarity, reduce diversity in practice and reduce the cost and complexity when applying the guidance in Topic 718, related to a change to the terms or conditions of a share-based payment award. The ASU amends the scope of modification accounting for share-based payment arrangements and provides guidance on the types of changes to the terms or conditions of share-based payment awards to which an entity would be required to apply modification accounting under ASC 718. Specifically, an entity would not apply modification accounting if the fair value, vesting conditions and classification of the awards are the same immediately before and after the modification. The amendments in this update are effective for us beginning January 1, 2018. The amendments in this update should be applied prospectively to an award modified on or after the adoption date. We do not expect this standard to materially affect our financial statements and disclosures.

RETIREMENT BENEFITS. On March 10, 2017, the FASB issued ASU 2017-07, "Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost." The ASU requires entities to disaggregate current service cost from the other components of net periodic benefit cost and present it with other current compensation costs for related employees in the income statement and to present the other components elsewhere in the income statement and outside of income from operations if that subtotal is presented. Only the service cost component of the net periodic benefit cost is eligible for capitalization. The amendments in this update are effective for us beginning January 1, 2018. Upon adoption, the ASU requires that changes to the income statement presentation of net periodic benefit cost be applied retrospectively, while changes to amounts capitalized must be applied prospectively. During the third quarter 2017, the FERC indicated that it will allow entities to change their capitalization policy for regulatory accounting and reporting purposes to be consistent with the new US GAAP requirements. This change will be allowed as a one-time policy election upon adoption of the guidance. We are currently evaluating whether or not to adopt the new ASU for FERC regulatory accounting and reporting purposes and assessing the effect of this standard on our financial statements and disclosures.

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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.

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. Refer to Note 14 herein and Note 14 of the 2016 Form 10-K for our current lease commitments.

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. We do not expect this standard to have a material impact to our financial statements and disclosures.

REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." Subsequently, the FASB issued additional, clarifying amendments to address issues and questions regarding implementation of the new revenue recognition standard. 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 guidance also requires additional disclosures, both qualitative and quantitative, regarding the nature, amount, timing and uncertainty of revenue and cash flows. The new requirements prescribe either a full retrospective or simplified transition adoption method. We are currently analyzing our revenue streams, material contracts with customers, and the expanded disclosure requirements under the new standard and do not believe the standard will have a material impact on our financial position, net income or cash flows. We are also evaluating our method of adoption and potential changes to our accounting policies, processes, systems and internal controls that may be required under the new standard. The new standard is effective for us beginning January 1, 2018.

Accounting Policies

Subsequent Events

We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. See Note 14.

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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 common 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	2017			2016			2017		2016
Net income (loss)	$	(8,495	)	$	(8,040	)	$	34,544	$	30,620
Average common shares outstanding - basic	28,678			27,554			28,653		27,504
Additional shares for stock-based compensation plans (See Note 5)	—			—			81		125
Average common shares outstanding - diluted	28,678			27,554			28,734		27,629
Earnings (loss) per share of common stock - basic	$	(0.30	)	$	(0.29	)	$	1.21	$	1.11
Earnings (loss) per share of common stock - diluted	$	(0.30	)	$	(0.29	)	$	1.20	$	1.11
Additional information:
Antidilutive shares	96			159			15		5

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 and our North Mist gas storage expansion 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 2016 Form 10-K for further discussion of our segments.

Inter-segment transactions were immaterial 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
2017
Operating revenues	$	81,126		$	7,006	$	58		$	88,190
Depreciation and amortization	20,023			1,461		—			21,484
Income (loss) from operations	(9,977		)	3,543		(222		)	(6,656		)
Net income (loss)	(10,349		)	1,899		(45		)	(8,495		)
Capital expenditures	50,009			164		950			51,123
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

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	Nine Months Ended September 30,
In thousands	Utility		Gas Storage		Other			Total
2017
Operating revenues	$	503,947	$	17,635	$	169		$	521,751
Depreciation and amortization	59,541		4,383		—			63,924
Income (loss) from operations	77,706		5,748		(725		)	82,729
Net income (loss)	31,980		2,716		(152		)	34,544
Capital expenditures	143,128		1,363		950			145,441
Total assets at September 30, 2017	2,835,860		252,041		17,706			3,105,607
2016
Operating revenues	$	422,617	$	19,654	$	168		$	442,439
Depreciation and amortization	56,894		4,541		—			61,435
Income from operations	74,745		8,107		(611		)	82,241
Net income	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

Total assets at December 31, 2016	2,806,627		256,333		16,841			3,079,801

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 segment and other 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	2017		2016		2017		2016
Utility margin calculation:
Utility operating revenues ⁽¹⁾	$	81,126	$	80,378	$	503,947	$	422,617
Less: Utility cost of gas	27,239		28,264		223,855		157,546
Environmental remediation expense	1,355		1,191		10,920		8,113
Utility margin	$	52,532	$	50,923	$	269,172	$	256,958


⁽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.

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 2016 Form 10-K and the updates provided below.

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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, 2017, 34,340 performance-based shares were granted under the LTIP based on target-level awards with a weighted-average grant date fair value of $57.05 per share. Award share payouts range from a threshold of 0% to a maximum of 200% based on achievement of EPS and Return on Invested Capital (ROIC) factors, which can be modified by a total shareholder return factor (TSR factor) relative to the performance of the Russell 2500 Utilities Index over the three-year performance period and a growth modifier based on a cumulative EBITDA measure. Fair value for the shares granted during the nine months ended September 30, 2017 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	$	59.90
Performance term (in years)	3.0
Quarterly dividends paid per share⁽¹⁾	$	0.4700
Expected dividend yield	3.09		%
Dividend discount factor	0.9156


⁽¹⁾	In addition to common stock shares, a participant also receives a dividend equivalent cash payment equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share during the performance period.

As of September 30, 2017, there was $2.5 million of unrecognized compensation cost from LTIP grants, which is expected to be recognized through 2019.

Restricted Stock Units

During the nine months ended September 30, 2017, 32,168 RSUs were granted under the LTIP with a weighted-average grant date fair value of $60.51 per share. 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. The fair value of an RSU is equal to the closing market price of our common stock on the grant date. As of September 30, 2017, there was $3.3 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through 2022.

6. DEBT

Short-Term Debt

At September 30, 2017, we had no outstanding short-term debt.

Long-Term Debt

At September 30, 2017, we had long-term debt of $779.4 million, which included $7.3 million of unamortized debt issuance costs. Utility long-term debt consists of first mortgage bonds (FMBs) with maturity dates ranging from 2018 through 2047, interest rates ranging from 1.545% to 9.05%, and a weighted-average coupon rate of 4.780%. In August 2017, we retired $40 million of FMBs with a coupon rate of 7.00%, and in September 2017, we issued $100 million of FMBs. The FMBs issued in September 2017, consisted of $25 million at 2.822%, due in 2027 and $75 million at 3.685%, due in 2047.

Fair Value of Long-Term Debt

Our outstanding debt does not trade in active markets. We estimate the fair value of our debt using utility companies with similar credit ratings, terms, and remaining maturities to our debt that actively trade in public markets. These valuations are based on Level 2 inputs as defined in the fair value hierarchy. See Note 2 in the 2016 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	2017			2016			2016
Gross long-term debt	$	786,700		$	601,700		$	726,700
Unamortized debt issuance costs	(7,276		)	(6,487		)	(7,377		)
Carrying amount	$	779,424		$	595,213		$	719,323
Estimated fair value⁽¹⁾	$	847,068		$	701,183		$	793,339

⁽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	2017			2016			2017			2016			2017			2016			2017			2016
Service cost	$	1,881		$	1,978		$	98		$	119		$	5,621		$	5,866		$	295		$	361
Interest cost	4,484			4,607			274			301			13,428			13,755			822			901
Expected return on plan assets	(5,112		)	(5,017		)	—			—			(15,337		)	(15,051		)	—			—
Amortization of prior service costs	32			57			(117		)	(117		)	95			173			(351		)	(351		)
Amortization of net actuarial loss	3,656			3,555			138			192			10,899			10,559			415			575
Settlement expense	—			193			—			—			—			193			—			—
Net periodic benefit cost	4,941			5,373			393			495			14,706			15,495			1,181			1,486
Amount allocated to construction	(1,581		)	(1,556		)	(136		)	(163		)	(4,660		)	(4,678		)	(403		)	(491		)
Amount deferred to regulatory balancing account⁽¹⁾	(1,484		)	(1,542		)	—			—			(4,519		)	(4,762		)	—			—
Net amount charged to expense	$	1,876		$	2,275		$	257		$	332		$	5,527		$	6,055		$	778		$	995

⁽¹⁾

The deferral of defined benefit pension plan 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 2016 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	2017			2016			2017			2016
Beginning balance	$	(6,678	)	$	(6,825	)	$	(6,951	)	$	(7,162	)
Amounts reclassified to AOCL	—			(1,795		)	—			(1,795		)
Amounts reclassified from AOCL:
Amortization of actuarial losses	248			371			698			962
Loss from plan settlement	—			193			—			193
Total reclassifications before tax	248			(1,231		)	698			(640		)
Tax (benefit) expense	(98		)	486			(275		)	232
Total reclassifications for the period	150			(745		)	423			(408		)
Ending balance	$	(6,528	)	$	(7,570	)	$	(6,528	)	$	(7,570	)

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Employer Contributions to Company-Sponsored Defined Benefit Pension Plans

For the nine months ended September 30, 2017, we made cash contributions totaling $15.4 million to our qualified defined benefit pension plans. We expect further plan contributions of $4.0 million during the remainder of 2017.

Defined Contribution Plan

The Retirement K Savings Plan is a qualified defined contribution plan under Internal Revenue Code Sections 401(a) and 401(k). Employer contributions totaled $4.1 million and $3.6 million for the nine months ended September 30, 2017 and 2016, respectively.

See Note 8 in the 2016 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	2017			2016			2017			2016
Income taxes at statutory rates (federal and state)	$	(5,838	)	$	(5,339	)	$	22,487		$	20,620
Increase (decrease):
Differences required to be flowed-through by regulatory commissions	(302		)	(381		)	1,282			1,202
Other, net	21			246			(1,296		)	(528		)
Total provision for income taxes	$	(6,119	)	$	(5,474	)	$	22,473		$	21,294
Effective tax rate	41.9		%	40.5		%	39.4		%	41.0		%

The effective income tax rate for the three months ended September 30, 2017 compared to the same period in 2016 increased primarily as a result of increased stock-based compensation deductions in 2017. The effective income tax rate for the nine months ended September 30, 2017, compared to the same period in 2016, decreased primarily as a result of AFUDC equity income and increased stock-based compensation deductions in 2017. See Note 9 in the 2016 Form 10-K for more detail on income taxes and effective tax rates.

The IRS Compliance Assurance Process (CAP) examination of the 2015 tax year was completed during the first quarter of 2017. There were no material changes to the return as filed. The 2016 tax year is subject to examination under CAP and the 2017 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	2017		2016		2016
Utility plant in service	$	2,934,424	$	2,815,340	$	2,843,243
Utility construction work in progress	145,148		58,470		62,264
Less: Accumulated depreciation	937,498		899,851		903,096
Utility plant, net	2,142,074		1,973,959		2,002,411
Non-utility plant in service	300,224		298,586		299,378
Non-utility construction work in progress	4,326		4,800		3,931
Less: Accumulated depreciation	48,834		43,483		44,820
Non-utility plant, net	255,716		259,903		258,489
Total property, plant, and equipment	$	2,397,790	$	2,233,862	$	2,260,900

Capital expenditures in accrued liabilities	$	41,732	$	8,918	$	9,547

10. GAS RESERVES

We have invested $188 million through our gas reserves program in the Jonah Field located in Wyoming as of September 30, 2017. 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, which approximates the 10-year hedge rate plus financing costs at the inception of the investment.

The following table outlines our net gas reserves investment:



	September 30,				December 31,
In thousands	2017		2016		2016
Gas reserves, current	$	16,218	$	16,257	$	15,926
Gas reserves, non-current	171,318		171,280		171,610
Less: Accumulated amortization	83,442		67,304		71,426
Total gas reserves⁽¹⁾	104,094		120,233		116,110
Less: Deferred taxes on gas reserves	29,298		25,799		28,119
Net investment in gas reserves	$	74,796	$	94,434	$	87,991


⁽¹⁾	Our net investment in additional wells included in total gas reserves was $6.0 million, $7.0 million and $6.7 million at September 30, 2017 and 2016 and December 31, 2016, respectively.

Our investment is included in 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 influence over it. Our investments in TWH and TWP are included in other investments on our balance sheet. If we do not develop this investment, then 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, 2017 and 2016 and December 31, 2016. See Note 12 in the 2016 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 2016 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	2017		2016		2016
Natural gas (in therms):
Financial	521,080		537,100		477,430
Physical	750,650		621,230		535,450
Foreign exchange	$	6,933	$	8,404	$	7,497

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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 the 2016-17 and 2015-16 gas years. Hedge contracts entered into prior to our PGA filing, in September 2016, were included in the PGA for the 2016-17 gas year. Hedge contracts entered into after our PGA filing, and related to subsequent gas years, may be included in future PGA filings and qualify for regulatory deferral.

Unrealized and Realized Gain/Loss

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



	Three Months Ended September 30,
	2017						2016
In thousands	Natural gas commodity			Foreign exchange			Natural gas commodity			Foreign exchange
Benefit (expense) to cost of gas	$	(2,566	)	$	51		$	(8,045	)	$	(52	)
Operating gain (loss)	28			—			(110		)	—

Amounts deferred to regulatory accounts on balance sheet	2,548			(51		)	8,118			52
Total gain (loss) in pre-tax earnings	$	10		$	—		$	(37	)	$	—



	Nine Months Ended September 30,
	2017						2016
In thousands	Natural gas commodity			Foreign exchange			Natural gas commodity			Foreign exchange
Benefit (expense) to cost of gas	$	(19,081	)	$	275		$	5,562		$	5
Operating loss	(1,249		)	—			(266		)	—

Amounts deferred to regulatory accounts on balance sheet	19,895			(275		)	(5,385		)	(5		)
Total loss in pre-tax earnings	$	(435	)	$	—		$	(89	)	$	—

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 gains of $1.0 million for the three and nine months ended September 30, 2017 from the settlement of natural gas financial derivative contracts. Whereas, we realized net losses of $1.0 million and $24.1 million for the three and nine months ended September 30, 2016, respectively. 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 Derivatives Instruments

No collateral was posted with or by our counterparties as of September 30, 2017 or 2016. 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 2017 or 2016. 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.

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Based upon current commodity financial swap and option contracts outstanding, which reflect unrealized losses of $12.0 million at September 30, 2017, 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	$	—	$	—	$	—	$	(3,138	)	$	(9,146	)
Without Adequate Assurance Calls	—		—		—		(3,138		)	(7,113		)

Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our consolidated balance sheets. We and our counterparties have the ability to set-off 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 $3.3 million and a liability of $12.6 million as of September 30, 2017. As of September 30, 2016, our derivative position would have resulted in an asset of $4.1 million and a liability of $5.1 million. As of December 31, 2016, our derivative position would have resulted in an asset of $18.8 million and a liability of $0.7 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 2016 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, 2017. As of September 30, 2017 and 2016, and December 31, 2016, the net fair value was a liability of $9.3 million, a liability of $1.0 million, and an asset $18.1 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 nine months ended September 30, 2017 and 2016. See Note 2 in the 2016 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, of those sites described herein, 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 a ROD is issued, we would seek to negotiate a consent decree or consent

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judgment for designing and implementing the remedy. We would 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, institutional controls such as legal restrictions on future property use, or natural recovery. 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 below.

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. In 2017, we received a claim made by the Yakama Nation against us and 29 other potentially responsible parties. Refer to "Other Portland Harbor" below.

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 balance sheet:



	Current Liabilities						Non-Current Liabilities
	September 30,				December 31,		September 30,				December 31,
In thousands	2017		2016		2016		2017		2016		2016
Portland Harbor site:
Gasco/Siltronic Sediments	$	860	$	1,726	$	869	$	43,796	$	42,880	$	43,972
Other Portland Harbor	1,379		1,461		1,970		3,618		4,362		4,148
Gasco/Siltronic Upland site	7,537		8,191		10,657		48,758		49,928		49,183
Central Service Center site	31		112		73		—		—		—
Front Street site	846		841		906		10,788		7,818		7,786
Oregon Steel Mills	—		—		—		179		179		179
Total	$	10,653	$	12,331	$	14,475	$	107,139	$	105,167	$	105,268

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 sites. We are one of over one hundred PRPs to the Superfund site. In January 2017, the EPA issued its Record of Decision, which outlines its determination of a cleanup approach for the Portland Harbor site (Portland Harbor ROD). The Portland Harbor ROD presents the EPA's decision on remedial alternatives and outlines the clean-up plan for the entire Portland Harbor. The Portland Harbor ROD estimates the present value total cost at approximately $1.05 billion with an accuracy between -30% and +50% of actual costs.

Our potential liability is 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. In addition, we are actively pursuing clarification and flexibility under the ROD in order to better understand our obligation under the clean-up. We are also participating in a non-binding allocation process with the other PRPs in an effort to resolve our potential liability. The Portland Harbor ROD does not provide any additional clarification around allocation of costs among PRPs and, as a result of issuance of the Portland Harbor ROD, we have not modified any of our recorded liabilities at this time.

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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 cleanup can occur, and for regulatory oversight throughout the clean-up range from $44.7 million to $350 million. We have recorded a liability of $44.7 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. While we still believe liabilities associated with the Gasco/Siltronic sediments site represent our largest exposure, we do have other potential exposures associated with the Portland Harbor ROD, including NRD costs and harborwide clean-up costs (including downstream petroleum contamination), for which the allocations among the PRPs have not yet been determined.

The Company and other parties have signed a cooperative agreement with the Portland Harbor Natural Resource Trustee council to participate in a phased NRD assessment to estimate liabilities to support an early restoration-based settlement of NRD claims. One member of this Trustee council, the Yakama Nation, withdrew from the council in 2009, and in 2017, filed suit against the Company and 29 other parties seeking remedial costs and NRD assessment costs associated with the Portland Harbor, set forth in the complaint. The complaint seeks recovery of alleged costs totaling $0.3 million in connection with the selection of a remedial action for the Portland Harbor as well as declaratory judgment for unspecified future remedial action costs and for costs to assess the injury, loss or destruction of natural resources resulting from the release of hazardous substances at and from the Portland Harbor site. The Yakama Nation filed an amended complaint on June 20, 2017 addressing certain pleading defects and dismissing the State of Oregon, and filed a second amended complaint on August 18, 2017. We have recorded a liability for NRD 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. The NRD liability is not included in the aforementioned range of costs provided in the Portland Harbor ROD.

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, 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, excluding the uplands for Siltronic. 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 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.

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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. We may have exposure at other sites that have not been identified at this time. 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.

In July 2017, ODEQ issued the PGM ROD. The ROD specifies the selected remedy, which requires a combination of dredging, capping, treatment, and natural recovery. In addition, the selected remedy also requires institutional controls and long-term inspection and maintenance. We revised the liability in the second quarter of 2017 to incorporate the estimated undiscounted cost of approximately $10.5 million for the selected remedy. 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. We plan to begin remedial design this fall and expect to complete dredging and installation during 2019.

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

Site Remediation and Recovery Mechanism (SRRM)

We have an 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, for those sites identified herein. In the February 2015 Order establishing the SRRM (2015 Order), the OPUC addressed outstanding issues related to the SRRM, which required us to forego the collection of $15 million out of approximately $95 million in total environmental remediation expenses and associated carrying costs. As a follow-up to the 2015 Order, the OPUC issued an additional Order in January 2016 (2016 Order) regarding the SRRM implementation which resulted in a $3.3 million non-cash charge primarily due to the disallowance of interest earned on the original allowance.

COLLECTIONS FROM OREGON CUSTOMERS. Under the SRRM collection process there are three types 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 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.

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 an equal and offsetting amount of our deferred regulatory asset balance through the environmental remediation operating expense line shown separately in the operating expense section of the income statement.

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 2015 OPUC Order, one-third of the Oregon allocated proceeds were applied to costs deferred through 2012 with the remaining two-thirds applied to costs at a rate of $5

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million per year plus interest over the following 20 years. 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, 2017, 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	2017		2016		2016
Deferred costs and interest ⁽¹⁾	$	52,888	$	54,704	$	53,039
Accrued site liabilities ⁽²⁾	117,388		117,202		119,443
Insurance proceeds and interest

NORTHWEST NATURAL GAS CO - FORM 10-Q - November 3, 2017

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