NORTHWEST NATURAL GAS CO - FORM 10-Q

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file	filename
EX-32.1 - EXHIBIT 32.1 CEO AND CFO CERTIFICATION - NORTHWEST NATURAL GAS CO	ex321q32016.htm
EX-31.2 - EXHIBIT 31.2 CFO CERTIFICATION - NORTHWEST NATURAL GAS CO	ex312q32016.htm
EX-31.1 - EXHIBIT 31.1 CEO CERTIFICATION - NORTHWEST NATURAL GAS CO	ex311q32016.htm
EX-12 - EXHIBIT 12 FIXED CHARGES - NORTHWEST NATURAL GAS CO	ex12q32016.htm
EX-10.1 - EXHIBIT 10.1 FORM OF SPECIAL RSU AWARD AGREEMENT - NORTHWEST NATURAL GAS CO	ex101q32016.htm
EX-4.1 - EXHIBIT 4.1 TWENTY-SECOND SUPPLEMENTAL INDENTURE - NORTHWEST NATURAL GAS CO	ex41q32016.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, 2016

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

For the transition period from ___________ to____________

Commission file number 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

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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. 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.

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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

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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

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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

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

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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 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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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.

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⁽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.

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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 from 2016 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 ended September 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 ended September 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 ended September 30, 2016, respectively, and net losses of $2.3 million and $24.3 million for the three and nine months ended September 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 and has 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.

NORTHWEST NATURAL GAS CO - FORM 10-Q - November 2, 2016

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