NORTHWEST NATURAL GAS CO - FORM 10-Q

Attached files

file	filename
EX-12 - EXHIBIT 12 FIXED CHARGES - NORTHWEST NATURAL GAS CO	nwn-2015x930x10qxexhibit12.htm
EX-32.1 - EXHIBIT 32.1 CEO AND CFO CERTIFICATION - NORTHWEST NATURAL GAS CO	nwn-2015x930x10qxexhibit321.htm
EX-31.1 - EXHIBIT 31.1 CEO CERTIFICATION - NORTHWEST NATURAL GAS CO	nwn-2015x930x10qxexhibit311.htm
EX-31.2 - EXHIBIT 31.2 CFO CERTIFICATION - NORTHWEST NATURAL GAS CO	nwn-2015x930x10qxexhibit312.htm
EX-10.A - EXHIBIT 10.A DEFERRED COMPENSATION PLAN FOR DIRECTORS AND EXECUTIVES - NORTHWEST NATURAL GAS CO	nwn-2015x930x10qxexhibit10a.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, 2015

[ ] 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 23, 2015, 27,371,642 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, 2015

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		Page

PART 1.	FINANCIAL INFORMATION

	Forward-Looking Statements	1

Item 1.	Unaudited Consolidated Financial Statements:

	Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2015 and 2014	2

	Consolidated Balance Sheets at September 30, 2015 and 2014 and December 31, 2014	3

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014	5

	Notes to Unaudited Consolidated Financial Statements	6

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43

Item 4.	Controls and Procedures	43

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	44

Item 1A.	Risk Factors	44

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44

Item 6.	Exhibits	44

	Signature	45

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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,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects”, "predicts", "projects" and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements regarding the following:


•	plans, objectives, goals, and strategies;


•	assumptions and estimates;


•	future events or performance;


•	trends, timing and cyclicality;


•	risks;


•	earnings and dividends;


•	capital structure;


•	growth;


•	customer rates;


•	commodity costs;


•	gas reserves;


•	operational performance and costs;


•	energy policy and preferences;


•	efficacy of derivatives and hedges;


•	liquidity and financial positions;


•	project and program development, expansion, or investment;


•	competition;


•	procurement and development of gas supplies;


•	estimated expenditures;


•	costs of compliance;


•	credit exposures;


•	potential efficiencies;


•	rate or regulatory recovery or refunds;


•	impacts of laws, rules and regulations;


•	tax liabilities or refunds;


•	levels and pricing of gas storage contracts;


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


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


•	projected obligations under retirement plans;


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


•	approval and adequacy of regulatory deferrals;


•	potential regulatory disallowances;


•	effects of regulatory mechanisms; and


•	environmental, regulatory, litigation and insurance costs and recoveries, and the 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 performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements are discussed in our 2014 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	2015			2014			2015		2014

Operating revenues	$	93,128		$	87,199		$	493,073	$	513,754

Operating expenses:
Cost of gas	35,856			32,227			223,737		245,708
Operations and maintenance	32,031			32,968			121,458		103,085
General taxes	6,772			7,143			23,153		22,508
Depreciation and amortization	20,342			19,938			60,683		59,236
Total operating expenses	95,001			92,276			429,031		430,537
Income (loss) from operations	(1,873		)	(5,077		)	64,042		83,217
Other income and expense, net	746			407			6,930		2,052
Interest expense, net	10,111			10,805			31,030		34,024
Income (loss) before income taxes	(11,238		)	(15,475		)	39,942		51,245
Income tax expense (benefit)	(4,553		)	(6,742		)	15,944		21,023
Net income (loss)	(6,685		)	(8,733		)	23,998		30,222
Other comprehensive income:
Amortization of non-qualified employee benefit plan liability, net of taxes of $217 and $108 for the three months ended and $650 and $324 for the nine months ended September 30, 2015 and 2014, respectively	332			166			995		497
Comprehensive income (loss)	$	(6,353	)	$	(8,567	)	$	24,993	$	30,719
Average common shares outstanding:
Basic	27,363			27,189			27,336		27,145
Diluted	27,363			27,189			27,399		27,195
Earnings (loss) per share of common stock:
Basic	$	(0.24	)	$	(0.32	)	$	0.88	$	1.11
Diluted	(0.24		)	(0.32		)	0.88		1.11
Dividends declared per share of common stock	0.465			0.460			1.395		1.380

See Notes to Unaudited Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

In thousands	September 30, 2015			September 30, 2014			December 31, 2014

Assets:
Current assets:
Cash and cash equivalents	$	5,227		$	8,275		$	9,534
Accounts receivable	29,800			30,468			69,818
Accrued unbilled revenue	15,752			12,442			57,963
Allowance for uncollectible accounts	(308		)	(840		)	(969		)
Regulatory assets	82,712			52,250			68,562
Derivative instruments	2,956			5,587			243
Inventories	80,974			86,600			77,832
Gas reserves	17,822			21,455			20,020
Income taxes receivable	—			7,639			1,000
Deferred tax assets	15,663			5,100			23,785
Other current assets	27,313			19,158			34,772
Total current assets	277,911			248,134			362,560
Non-current assets:
Property, plant, and equipment	3,072,998			2,990,662			2,992,560
Less: Accumulated depreciation	905,137			883,568			870,967
Total property, plant, and equipment, net	2,167,861			2,107,094			2,121,593
Gas reserves	117,784			131,745			129,280
Regulatory assets	333,953			263,321			368,908
Derivative instruments	299			602			—
Other investments	68,503			67,980			68,238
Restricted cash	4,500			3,000			3,000
Other non-current assets	7,554			11,648			11,366
Total non-current assets	2,700,454			2,585,390			2,702,385
Total assets	$	2,978,365		$	2,833,524		$	3,064,945

See Notes to Unaudited Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

In thousands	September 30, 2015			September 30, 2014			December 31, 2014

Liabilities and equity:
Current liabilities:
Short-term debt	$	225,200		$	190,000		$	234,700
Current maturities of long-term debt	—			40,000			40,000
Accounts payable	54,425			71,018			91,366
Taxes accrued	11,854			11,876			10,031
Interest accrued	9,800			10,427			6,079
Regulatory liabilities	34,127			23,352			19,105
Derivative instruments	21,949			5,520			29,894
Other current liabilities	27,924			33,481			38,235
Total current liabilities	385,279			385,674			469,410
Long-term debt	621,700			621,700			621,700
Deferred credits and other non-current liabilities:
Deferred tax liabilities	527,336			499,809			530,965
Regulatory liabilities	334,490			312,500			317,205
Pension and other postretirement benefit liabilities	228,861			142,502			236,735
Derivative instruments	3,540			551			3,515
Other non-current liabilities	117,950			118,531			118,094
Total deferred credits and other non-current liabilities	1,212,177			1,073,893			1,206,514
Commitments and contingencies (see Note 13)	—			—			—
Equity:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 27,367, 27,203, and 27,284 at September 30, 2015 and 2014 and December 31, 2014, respectively	380,208			371,657			375,117
Retained earnings	388,082			386,461			402,280
Accumulated other comprehensive loss	(9,081		)	(5,861		)	(10,076		)
Total equity	759,209			752,257			767,321
Total liabilities and equity	$	2,978,365		$	2,833,524		$	3,064,945

See Notes to Unaudited Consolidated Financial Statements

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

	Nine Months Ended
	September 30,
In thousands	2015			2014

Operating activities:
Net income	$	23,998		$	30,222
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	60,683			59,236
Regulatory amortization of gas reserves	13,606			13,795
Deferred tax liabilities, net	7,153			10,721
Non-cash expenses related to qualified defined benefit pension plans	4,238			3,795
Contributions to qualified defined benefit pension plans	(11,780		)	(10,500		)
Deferred environmental (expenditures), net of recoveries	(8,063		)	89,537
Non-cash regulatory disallowance of prior environmental cost deferrals	15,000			—
Non-cash interest income on deferred environmental expenses	(5,322		)	—
Other	669			(1,692		)
Changes in assets and liabilities:
Receivables	82,586			100,931
Inventories	(3,142		)	(25,931		)
Taxes accrued	2,823			(3,085		)
Accounts payable	(36,230		)	(28,762		)
Interest accrued	3,721			3,324
Deferred gas costs	27,042			(22,173		)
Other, net	(4,237		)	(4,554		)
Cash provided by operating activities	172,745			214,864
Investing activities:
Capital expenditures	(86,923		)	(86,552		)
Utility gas reserves	(1,165		)	(21,734		)
Restricted cash	(1,500		)	1,000
Other	1,346			82
Cash used in investing activities	(88,242		)	(107,204		)
Financing activities:
Common stock issued, net	1,252			5,460
Long-term debt retired	(40,000		)	(80,000		)
Change in short-term debt	(9,500		)	1,800
Cash dividend payments on common stock	(38,122		)	(37,442		)
Other	(2,440		)	1,326
Cash used in financing activities	(88,810		)	(108,856		)
Decrease in cash and cash equivalents	(4,307		)	(1,196		)
Cash and cash equivalents, beginning of period	9,534			9,471
Cash and cash equivalents, end of period	$	5,227		$	8,275

Supplemental disclosure of cash flow information:
Interest paid	$	25,264		$	30,701
Income taxes paid (net of refunds)	10,631			14,945

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 unaudited 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 2014 Annual Report on Form 10-K (2014 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.

2. SIGNIFICANT ACCOUNTING POLICIES

Significant accounting policies are described in Note 2 of the 2014 Form 10-K. There were no material changes to those accounting policies during the nine months ended September 30, 2015. The following are current updates to certain critical accounting policy estimates and new accounting standards.

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Regulatory Accounting

In applying regulatory accounting in accordance with generally accepted accounting principles in the United States of America (GAAP), we capitalize or defer certain costs and revenues as regulatory assets and liabilities. These deferrals were as follows:



	Regulatory Assets
	September 30,				December 31,
In thousands	2015		2014		2014
Current:
Unrealized loss on derivatives⁽¹⁾	$	21,949	$	5,520	$	29,889
Gas costs	19,274		23,795		21,794
Environmental costs⁽²⁾	12,364		—		—
Decoupling⁽³⁾	19,391		11,847		2,219
Other⁽³⁾	9,734		11,088		14,660
Total current	$	82,712	$	52,250	$	68,562
Non-current:
Unrealized loss on derivatives⁽¹⁾	$	3,540	$	551	$	3,515
Pension balancing⁽⁴⁾	41,193		30,682		32,541
Income taxes	44,767		49,007		47,427
Pension and other postretirement benefit liabilities	189,111		118,485		201,845
Environmental costs⁽²⁾	37,443		51,861		58,859
Gas costs	2,098		1,936		5,971
Other⁽³⁾	15,801		10,799		18,750
Total non-current	$	333,953	$	263,321	$	368,908



	Regulatory Liabilities
	September 30,				December 31,
In thousands	2015		2014		2014
Current:
Gas costs	$	22,499	$	6,704	$	5,700
Unrealized gain on derivatives⁽¹⁾	2,939		5,320		240
Other⁽³⁾	8,689		11,328		13,165
Total current	$	34,127	$	23,352	$	19,105
Non-current:
Gas costs	$	6,357	$	410	$	2,507
Unrealized gain on derivatives⁽¹⁾	299		602		—
Accrued asset removal costs⁽⁵⁾	324,467		307,815		311,238
Other⁽³⁾	3,367		3,673		3,460
Total non-current	$	334,490	$	312,500	$	317,205


⁽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 Public Utility Commission of Oregon (OPUC) and Washington Utilities and Transportation Commission (WUTC). In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. The current portion of environmental assets represents deferred costs to be recovered in Oregon rates beginning November 1, 2015. See Note 13.


⁽³⁾	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.


⁽⁴⁾	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.


⁽⁵⁾	Estimated costs of removal on certain regulated properties are collected through rates. See Note 2 of the 2014 Form 10-K.

Environmental Regulatory Accounting

On February 20, 2015 the OPUC issued an Order addressing outstanding implementation items related to the Site Remediation and Recovery Mechanism (SRRM). Under the Order, $15 million of $95 million in total environmental remediation expenses deferred through 2012 were disallowed. The OPUC found the $95 million to be prudent but disallowed this amount from rate recovery based on its determination of how an earnings test should apply to years between 2003 and 2012, with adjustments for other factors the OPUC deemed relevant. We recognized the $15 million pre-tax disallowance, or $9.1 million after-tax charge, during the first quarter of 2015. The charge was recorded in operations and maintenance expense. As a result of the order, we recognized $5.3 million pre-tax of interest income related to the equity earnings on our deferred environmental expenses. See Note 13.

New Accounting Standards

Recent Accounting Pronouncements

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.

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 applies to the Company, 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 are effective for the Company beginning January 1, 2016, with early adoption permitted. We will be required to apply the disclosure guidance retrospectively and do not expect the ASU to materially affect our financial statements and disclosures.

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 are effective for the Company beginning January 1, 2016 with retrospective application to all periods presented required and early adoption permitted. We do not expect the ASU to materially affect our financial statements and disclosures.

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 are effective for the Company beginning January 1, 2016. The ASU can be applied prospectively or retrospectively and early adoption is permitted. We intend to apply the guidance prospectively 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 are effective for the Company beginning January 1, 2016. Early adoption is permitted, and the new guidance will be applied on a retrospective basis. We do not expect the ASU to materially affect 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 expected to be entitled to in exchange for those goods or services. The model provides 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

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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 are currently assessing the effect of this standard on our financial statements and disclosures.

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 options are excluded from the calculation of diluted earnings per common share. Diluted earnings (loss) per share are calculated as follows:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per share data	2015			2014			2015		2014
Net income (loss)	$	(6,685	)	$	(8,733	)	$	23,998	$	30,222
Average common shares outstanding - basic	27,363			27,189			27,336		27,145
Additional shares for stock-based compensation plans outstanding	—			—			63		50
Average common shares outstanding - diluted	27,363			27,189			27,399		27,195
Earnings (loss) per share of common stock - basic	$	(0.24	)	$	(0.32	)	$	0.88	$	1.11
Earnings (loss) per share of common stock - diluted	$	(0.24	)	$	(0.32	)	$	0.88	$	1.11
Additional information:
Antidilutive shares	91			80			19		24

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 (Mist) 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 2014 Form 10-K for further discussion of our segments.

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Inter-segment transactions are insignificant. The following table presents summary financial information concerning the reportable segments:



	Three Months Ended September 30,
In thousands	Utility			Gas Storage		Other		Total
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
2014
Operating revenues	$	82,361		$	4,782	$	56	$	87,199
Depreciation and amortization	18,279			1,659		—		19,938
Income (loss) from operations	(6,221		)	926		218		(5,077		)
Net income (loss)	(8,808		)	2		73		(8,733		)
Capital expenditures	33,717			346		—		34,063



	Nine Months Ended September 30,
In thousands	Utility		Gas Storage		Other		Total
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	2,693,953		269,289		15,123		2,978,365
2014
Operating revenues	$	495,931	$	17,655	$	168	$	513,754
Depreciation and amortization	54,333		4,903		—		59,236
Income from operations	78,971		3,994		252		83,217
Net income	29,416		472		334		30,222
Capital expenditures	85,793		759		—		86,552
Total assets at September 30, 2014	2,539,834		277,689		16,001		2,833,524

Total assets at December 31, 2014	$	2,775,011	$	273,813	$	16,121	$	3,064,945

Utility Margin

Utility margin is a financial measure consisting of utility operating revenues, which are reduced by revenue taxes and the associated cost of gas. The cost of gas purchased for utility customers is generally a pass-through cost in the amount of revenues billed to regulated utility customers. By subtracting cost of gas 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.

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The following table presents additional segment information concerning utility margin:



	Three Months Ended September 30,				Nine Months Ended September 30,
In thousands	2015		2014		2015		2014
Utility margin calculation:
Utility operating revenues	$	87,475	$	82,361	$	476,672	$	495,931
Less: Utility cost of gas	35,856		32,227		223,737		245,708
Utility margin	$	51,619	$	50,134	$	252,935	$	250,223

5. STOCK-BASED COMPENSATION

Our stock-based compensation plans include a Long-Term Incentive Plan (LTIP) under which various types of equity awards may be granted. For additional information on our stock-based compensation plans, see Note 6 in the 2014 Form 10-K and the updates provided below.

Long-Term Incentive Plan

Performance-Based Stock Awards

LTIP performance shares incorporate a combination of market, performance, and service-based factors. During the nine months ended September 30, 2015, 47,550 performance-based shares were granted under the LTIP based on target-level awards with a weighted-average grant date fair value of $51.85 per share. As of September 30, 2015, there was $2.6 million of unrecognized compensation cost from LTIP grants, which is expected to be recognized through 2017. 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	$	47.64
Performance term (in years)	3.0
Quarterly dividends paid per share	$	0.465
Expected dividend yield	3.8		%
Dividend discount factor	0.8966

Performance-Based Restricted Stock Units (RSUs)

During the nine months ended September 30, 2015, 37,264 RSUs were granted under the LTIP with a weighted-average grant date fair value of $46.28 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, 2015, there was $2.9 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through 2019. 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. An RSU obligates the Company 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, 2015, our short-term debt consisted of commercial paper notes payable with a maximum maturity of 71 days, an average maturity of 62 days, and an outstanding balance of $225.2 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 2014 Form 10-K for a description of the fair value hierarchy.

Long-Term Debt

At September 30, 2015, our utility segment had long-term debt of $601.7 million. 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%. The utility redeemed $40 million of FMBs with a coupon rate of 4.70% in June 2015.

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At September 30, 2015, our gas storage segment’s long-term debt consisted of $20 million of fixed-rate senior collateralized debt with a maturity date of November 30, 2016 and an interest rate of 7.75%. This debt is collateralized by all of the membership interests in Gill Ranch and is nonrecourse to NW Natural.

On April 28, 2015, Gill Ranch entered into an amendment to the loan agreement under which the earnings before interest, tax, depreciation, and amortization (EBITDA) covenant requirement is suspended through maturity of the loan. Previously, the covenant had been suspended through March 31, 2015, and the debt service reserve was set at $3 million. Under the amendment, the debt service reserve was fixed at $4.5 million as of June 30, 2015 with scheduled increases by contributions of $1.5 million on each of January 30, 2016 and August 30, 2016, respectively. Additionally, Gill Ranch must receive common equity contributions from its parent NWN Gas Storage of at least $2 million by August 31, 2015, which was made on May 19, 2015, and of at least $4 million by August 31, 2016.

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 2014 Form 10-K.

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	2015		2014		2014
Carrying amount	$	621,700	$	661,700	$	661,700
Estimated fair value	697,647		748,902		756,808

See Note 7 in the 2014 Form 10-K for additional information regarding our long-term debt.

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,
							Other Postretirement
	Pension Benefits						Benefits
In thousands	2015			2014			2015			2014
Service cost	$	2,308		$	1,919		$	145		$	136
Interest cost	4,597			4,511			291			309
Expected return on plan assets	(5,174		)	(4,887		)	—			—
Amortization of net actuarial loss	4,561			2,579			125			46
Amortization of prior service costs	57			56			50			50
Net periodic benefit cost	6,349			4,178			611			541
Amount allocated to construction	(2,061		)	(1,242		)	(218		)	(177		)
Amount deferred to regulatory balancing account⁽¹⁾	(2,171		)	(1,107		)	—			—
Net amount charged to expense	$	2,117		$	1,829		$	393		$	364

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	Nine Months Ended September 30,
							Other Postretirement
	Pension Benefits						Benefits
In thousands	2015			2014			2015			2014
Service cost	$	6,926		$	5,755		$	435		$	407
Interest cost	13,787			13,535			874			928
Expected return on plan assets	(15,522		)	(14,659		)	—			—
Amortization of net actuarial loss	13,683			7,739			376			138
Amortization of prior service costs	173			168			148			148
Net periodic benefit cost	19,047			12,538			1,833			1,621
Amount allocated to construction	(5,765		)	(3,644		)	(607		)	(518		)
Amount deferred to regulatory balancing account⁽¹⁾	(6,511		)	(3,331		)	—			—
Net amount charged to expense	$	6,771		$	5,563		$	1,226		$	1,103

⁽¹⁾

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.

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	2015			2014			2015			2014
Beginning balance	$	(9,413	)	$	(6,027	)	$	(10,076	)	$	(6,358	)
Amounts reclassified from AOCL:
Amortization of prior service costs	—			(1		)	—			(5		)
Amortization of actuarial losses	549			275			1,645			826
Total reclassifications before tax	549			274			1,645			821
Tax expense	(217		)	(108		)	(650		)	(324		)
Total reclassifications for the period	332			166			995			497
Ending balance	$	(9,081	)	$	(5,861	)	$	(9,081	)	$	(5,861	)

Employer Contributions to Company-Sponsored Defined Benefit Pension Plan

For the nine months ended September 30, 2015, we made cash contributions totaling $11.8 million to the qualified defined benefit pension plan. We expect further plan contributions of $2.3 million during the remainder of 2015.

Defined Contribution Plan

The Retirement K Savings Plan provided to our employees is a qualified defined contribution plan under Internal Revenue Code Section 401(k). Our contributions to this plan totaled $2.9 million and $2.8 million for the nine months ended September 30, 2015 and 2014, respectively.

See Note 8 in the 2014 Form 10-K for more information concerning these retirement and other postretirement benefit plans.

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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	2015			2014			2015			2014
Income tax at statutory rates (federal and state)	$	(4,473	)	$	(6,161	)	$	15,848		$	20,288
Increase (decrease):
Differences required to be flowed-through by regulatory commissions	(378		)	(310		)	1,036			1,184
Other, net	298			(271		)	(940		)	(449		)
Income tax expense (benefit)	$	(4,553	)	$	(6,742	)	$	15,944		$	21,023
Effective income tax rate	40.5		%	43.6		%	39.9		%	41.0		%

Increases or decreases in income tax expense are correlated with changes in pre-tax income. The effective tax rate for the three and nine months ended September 30, 2015, compared to the same periods in 2014, decreased primarily as a result of depletion deductions from gas reserves activity. Additionally, there was a comparative decrease due to a $0.6 million income tax charge in the first quarter of 2014 due to the revaluation of deferred tax balances related to a higher effective tax rate in Oregon. See Note 9 in the 2014 Form 10-K for more detail on income taxes and effective tax rates.

Our examination under the Internal Revenue Service (IRS) Compliance Assurance Process for the 2013 tax year was completed during the first quarter of 2015. The examination did not result in a material change to the return as originally filed.

9. PROPERTY, PLANT, AND EQUIPMENT

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



	September 30,				December 31,
In thousands	2015		2014		2014
Utility plant in service	$	2,710,658	$	2,655,136	$	2,661,097
Utility construction work in progress	58,280		31,778		24,886
Less: Accumulated depreciation	867,281		850,590		836,510
Utility plant, net	1,901,657		1,836,324		1,849,473
Non-utility plant in service	296,169		297,199		297,295
Non-utility construction work in progress	7,891		6,549		9,282
Less: Accumulated depreciation	37,856		32,978		34,457
Non-utility plant, net	266,204		270,770		272,120
Total property, plant, and equipment	$	2,167,861	$	2,107,094	$	2,121,593

Capital expenditures in accrued liabilities	$	9,700	$	11,834	$	8,757

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10. GAS RESERVES

We have invested $188 million through our gas reserves program in the Jonah Field as of September 30, 2015. Gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. Our investment in gas reserves provides long-term price protection for utility customers and currently incorporates two agreements: 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.

We entered into our original agreements with Encana in 2011 under which we hold working interests in certain sections of the Jonah Field. Gas produced in these sections is sold at prevailing market prices, and revenues from such sales, net of associated operating and production costs and amortization, are credited to the utility's cost of gas. The cost of gas, including a carrying cost for the rate base investment, is included in NW Natural's annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our net investment under the original agreement earns a rate of return.

In March 2014, we amended the original gas reserves agreement in order to facilitate Encana's proposed sale of its interest in the Jonah field to Jonah Energy. Under the amendment, we ended the drilling program with Encana, but increased our working interests in our assigned sections of the Jonah field. We also retained the right to invest in new wells with Jonah Energy. The amended agreements allow us to invest in additional wells on a well-by-well basis with drilling costs and resulting gas volumes shared at our amended proportionate working interest for each well in which we invest. We elected to participate in some of the additional wells drilled in 2014, and may have the opportunity to participate in more wells in the future.

We filed an application requesting regulatory deferral in Oregon for these additional investments, which was granted in April 2015. Accordingly, we filed in 2015 seeking cost recovery for the additional wells drilled in 2014. In September 2015, the OPUC adopted an all-party settlement, under which volumes produced are included in our Oregon PGA beginning November 1, 2015 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 investment in gas reserves:



	September 30,				December 31,
In thousands	2015		2014		2014
Gas reserves, current	$	17,822	$	21,455	$	20,020
Gas reserves, non-current	169,300		164,115		167,190
Less: Accumulated amortization	51,516		32,370		37,910
Total gas reserves⁽¹⁾	135,606		153,200		149,300
Less: Deferred tax liabilities on gas reserves	23,042		33,037		18,551
Net investment in gas reserves⁽¹⁾	$	112,564	$	120,163	$	130,749


⁽¹⁾	Gas reserves include our investments in additional wells with Jonah Energy with the total gross investment of $9.7 million and $8.2 million at September 30, 2015 and 2014, respectively. Net investment in the additional wells was $4.5 million and $6.5 million at September 30, 2015 and 2014, respectively.

11. INVESTMENTS

Equity Method Investments

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 the 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.

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VIE Analysis

TWH is a Variable Interest Entity, 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 investment in TWH and TWP is included in other investments on our balance sheet. If we do not develop this investment, then the maximum loss exposure related to TWH is limited to our equity investment balance, less our share of any cash or other assets available to it as a 50% owner. Our investment balance in TWH was $13.4 million at September 30, 2015 and 2014 and December 31, 2014. See Note 12 in the 2014 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 2014 Form 10-K.

12. DERIVATIVE INSTRUMENTS

We enter into financial derivative contracts to hedge a portion of the 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 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	2015		2014		2014
Natural gas (in therms):
Financial	416,075		368,425		287,475
Physical	521,350		620,550		420,980
Foreign exchange	$	8,023	$	10,296	$	12,230

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. Derivative contracts entered into after the start of the PGA period are subject to our PGA incentive sharing mechanism in Oregon, which provides for either an 80% or 90% deferral of any gains and losses as regulatory assets or liabilities, with the remaining 20% or 10%, respectively, recognized in current income. For the 2014-15 and 2015-16 gas years, we selected the 90% and 80% deferral option, respectively. In general, our commodity hedging for the current gas year is completed prior to the start of the upcoming gas year, and hedge prices are reflected in our weighted-average cost of gas in the PGA filing. As of November 1, 2014, we reached our target hedge percentage of approximately 75% for the 2014-15 gas year. These hedge prices were included in the PGA filings and qualified for regulatory deferral.

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Unrealized 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,
	2015						2014
In thousands	Natural gas commodity			Foreign currency			Natural gas commodity			Foreign currency
Expense to cost of gas	$	(8,415	)	$	(150	)	$	(10,173	)	$	(421	)
Operating revenues	33			—			—			—
Less:
Amounts deferred to regulatory accounts on the balance sheet	8,391			150			10,559			421
Total gain in pre-tax earnings	$	9		$	—		$	386		$	—



	Nine Months Ended September 30,
	2015						2014
In thousands	Natural gas commodity			Foreign currency			Natural gas commodity			Foreign currency
(Expense) benefit to cost of gas	$	(21,876	)	$	(413	)	$	360		$	(242	)
Operating revenues	55			—			—			—
Less:
Amounts deferred to regulatory accounts on the balance sheet	21,838			413			(93		)	242
Total gain in pre-tax earnings	$	17		$	—		$	267		$	—

Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory accounting standards. The cost of foreign currency forward contracts and natural gas derivative contracts are recognized immediately in 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 a net loss of $2.3 million and $24.3 million for the three and nine months ended September 30, 2015 and a net gain of $0.5 million and $13.3 million for the three and nine months ended September 30, 2014, 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, 2015 or 2014. 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 have not been subject to collateral calls in 2014 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 on current financial swap and option contracts outstanding, which reflect net unrealized losses of $23.8 million at September 30, 2015, 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	$	—	$	—	$	—	$	—	$	22,066
Without Adequate Assurance Calls	—		—		—		—		15,937

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Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our statement of financial position. We and our counterparties have the ability to set-off our 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 each counterparty, our net derivative position would result in an asset of $3.1 million and a liability of $25.3 million as of September 30, 2015. As of September 30, 2014, our derivative position would have resulted in an asset of $4.0 million and a liability of $3.9 million, and as of December 31, 2014, our derivative position would have resulted in an asset of $0.2 million and a liability of $33.4 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 natural gas purchases made on behalf of customers. See Note 13 in the 2014 Form 10-K for additional information.

Fair Value

In accordance with fair value accounting, we include nonperformance 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, 2015. As of September 30, 2015 and 2014 and December 31, 2014, the net fair value was a liability of $22.2 million, an asset of $0.1 million, and a liability of $33.2 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, 2015 and 2014.

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. Due to the numerous uncertainties surrounding the course of environmental remediation and the ongoing nature of several site investigations, 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. Unless there is an estimate within a 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 that 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 Oregon, we have a Site Remediation and Recovery Mechanism (SRRM) through which we track and have the ability to recover past deferred and future environmental remediation costs, subject to an earnings test. An Order from the OPUC in February 2015 deemed certain environmental remediation expenses and associated carrying costs deferred through March 31, 2014 prudent. Our settlement with insurance carriers resulting in insurance proceeds received was also deemed prudent in the Order. Under the Order, we were required to forgo the collection of $15 million out of approximately $95 million of environmental remediation expenses and associated carrying costs we had deferred through 2012 under the Order. The OPUC disallowed this amount from rate recovery based on its determination of how an earnings test should apply to amounts deferred from 2003 to 2012, with adjustments for other factors the OPUC deemed relevant. See Note 2 for information regarding the regulatory disallowance of past deferred costs under the Order received from the OPUC in February 2015.

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.

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Under the SRRM, we will recover the first $5 million of annual expense through an amount that will be collected from Oregon customers through a tariff rider. We will apply $5 million of insurance (plus interest) to the next portion of environmental expenses each year. Any expenses and interest on expenses in excess of the annual $10 million (plus interest from insurance) are fully recoverable through the SRRM, to the extent the utility earns at or below our authorized Return On Equity (ROE). To the extent the utility earns more than its authorized ROE in a year, the utility is required to cover environmental expenses and interest on expenses greater than the $10 million (plus interest from insurance proceeds) with those earnings that exceed its authorized ROE.

We submitted the required compliance filing demonstrating the proposed implementation of the Order and SRRM in March 2015. In September 2015, as a result of discussions with the parties, we withdrew our original compliance filing and submitted a revised filing noting the parties could potentially raise two issues with our proposed implementation of the Order. First, we believe the February 2015 Order reflected the Commission’s determination of the total disallowance to be borne by NW Natural for prior periods; however, we anticipate the parties will question whether interest on the $15 million charge should be separately disallowed. This interest would total approximately $3 million. Second, we anticipate discussions concerning how state allocation rates from the Order are applied to our environmental remediation sites. However, we believe the effect on current regulatory deferrals related to the state allocation issue would be insignificant.

We are engaged in the Commission’s process with the parties to resolve issues they have raised regarding the compliance filing and expect resolution of these matters in the first half of 2016. The revised compliance filing is subject to final review and approval by the OPUC and as a consequence thereof, additional or different implementation procedures could be required, which may, among other things, result in additional impacts on earnings.

In addition, we requested clarification from the OPUC regarding the amount of Oregon-allocated insurance proceeds to be held in a secured account. In September 2015, the OPUC resolved the issue by adopting an all-party settlement, which provided that we did not need to obtain a secured account. Instead, under the order insurance proceeds used to offset future environmental expenses will accrue interest at a rate equal to the five-year treasury rate plus 100 basis points. Currently, Oregon-allocated insurance proceeds total approximately $96 million on a pre-tax basis.

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

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Environmental Sites

The following table summarizes information regarding the environmental site liabilities, which are recorded in other current liabilities and other non-current liabilities on the balance sheet:



	Current Liabilities						Non-Current Liabilities
	September 30,				December 31,		September 30,				December 31,
In thousands	2015		2014		2014		2015		2014		2014
Portland Harbor site:
Gasco/Siltronic Sediments	$	1,236	$	686	$	1,767	$	38,533	$	38,593	$	38,019
Other Portland Harbor	1,243		1,060		1,934		4,563		3,198		4,338
Gasco site	4,510		7,399		9,535		36,795		37,748		37,117
Siltronic Uplands site	538		634		957		489		577		348
Central Service Center site	177		70		171		—		173		—
Front Street site	420		804		1,020		215		99		122
Oregon Steel Mills	—		—		—		179		179		179
Total	$	8,124	$	10,653	$	15,384	$	80,774	$	80,567	$	80,123

The following table presents information regarding the total amount of cash paid for environmental sites and the total regulatory asset deferred:



	September 30,				December 31,
In thousands	2015		2014		2014
Cumulative cash paid	$	121,819	$	111,367	$	113,740
Total regulatory asset deferral⁽¹⁾	49,807		51,861		58,859


⁽¹⁾	Includes cash paid, remaining liability, and interest, net of insurance reimbursement and amounts reclassified to utility plant for the water treatment station.

PORTLAND HARBOR SITE. The Portland Harbor is an Environmental Protection Agency (EPA) listed Superfund site that is approximately 10 miles long on the Willamette River and is adjacent to our Gasco uplands and Siltronic uplands sites. We are a potentially responsible party (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). 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 in 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. While the EPA’s Draft FS provides a higher range of costs than the LWG's submission, our potential liability is still a portion of the costs of the remedy the EPA will select for the entire Portland Harbor Superfund site. The cost of the 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 new EPA Draft FS does 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 Engineering Evaluation/Cost Analysis (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 the estimated 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 $39.8 million to $350 million. We have recorded a liability of $39.8 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.

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OTHER PORTLAND HARBOR. We incur costs related to our membership in the LWG, who is performing the RI/FS for the EPA, and also incur costs related to natural resource damages from these sites. NW Natural 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 accrued a liability for these claims 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 EPA Draft FS for the Portland Harbor noted above.

GASCO SITE. We own 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 NW Natural for environmental contamination under the Oregon Department of Environmental Quality (ODEQ) Voluntary Clean-Up Program. 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.

Uplands. In May 2007, we completed a revised Remedial Investigation Report for the uplands portion and it was approved by the ODEQ in March 2010. In 2015, ODEQ approved a risk assessment for the Uplands site, and we are currently working on a feasibility study. We have recognized a liability for the remediation of the uplands portion of the site at the low end of the range of potential liability; the high end of the range cannot be reasonably estimated at this time.

Groundwater Source Control. 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 performance 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 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 will be highly dependent upon 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 million for the Gasco water treatment station were placed into rates with OPUC approval. The OPUC deemed these costs prudent. Beginning November 1, 2014, the OPUC approved the application of $2.5 million from insurance proceeds plus interest to reduce the total amount of Gasco capital costs to be recovered through rate base.

OTHER SITES. In addition to those sites above, we have environmental exposures at four other sites: Siltronic, Central Service Center, Front Street, and Oregon Steel Mills. Due to the uncertainty of the design of remediation, regulation, timing of the liabilities, 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.

Siltronic Upland site. A portion of the Siltronic property was formerly part of the Gasco site. We are currently conducting an investigation of manufactured gas plant wastes on the uplands portion of this site for the ODEQ.

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

Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated. At ODEQs request, we conducted a sediment and source control investigation and provided findings to ODEQ. A Feasibility Study is currently underway.

Oregon Steel Mills site. See “Legal Proceedings,” below.

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Legal Proceedings

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

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

For additional information regarding other commitments and contingencies, see Note 14 in the 2014 Form 10-K.

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

The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural or the Company) financial condition, including the principal factors that affect results of operations. The disclosures contained in this report refer to our consolidated activities for the three and nine months ended September 30, 2015 and 2014. References to “Notes” are to the Notes to Unaudited Consolidated Financial Statements in this report. A significant portion of our business results are seasonal in nature, and, as such, the results of operations for the three and nine month periods are not necessarily indicative of expected fiscal year results. Therefore, this discussion should be read in conjunction with our 2014 Annual Report on Form 10-K (2014 Form 10-K).

The consolidated financial statements include NW Natural, the parent company, and its direct and indirect wholly-owned subsidiaries.

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

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

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EXECUTIVE SUMMARY

Consolidated results for the quarter include:



	Three Months Ended September 30,
	2015						2014
In thousands, except per share data	Amount			Per Share			Amount			Per Share			Change
Consolidated net loss	$	(6,685	)	$	(0.24	)	$	(8,733	)	$	(0.32	)	$	2,048
Utility margin	51,619						50,134						1,485
Gas storage operating revenues	5,596						4,782						814

THREE MONTHS ENDED SEPTEMBER 30, 2015 COMPARED TO SEPTEMBER 30, 2014. Consolidated net loss was $2.0 million lower primarily due to a $1.5 million increase in utility margin, a $0.8 million increase in gas storage operating revenues, a $0.9 million decrease in operations and maintenance expense, and a $0.7 million decrease in interest expense.

Consolidated results for the year include:



	Nine Months Ended September 30,
	2015				2014
In thousands, except per share data	Amount		Per Share		Amount		Per Share		Change
Consolidated net income	$	23,998	$	0.88	$	30,222	$	1.11	$	(6,224	)
Adjustments:
Regulatory environmental disallowance, net of taxes $5,925⁽¹⁾	9,075		0.33		—		—		9,075
Adjusted consolidated net income⁽¹⁾	$	33,073	$	1.21

NORTHWEST NATURAL GAS CO - FORM 10-Q - November 3, 2015

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