Edgar Filing: NORTHWEST NATURAL GAS CO

NWN-2014-9.30-10Q

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, 2014

[ ] 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 24, 2014, 27,206,484 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, 2014

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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, 2014 and 2013	2

	Consolidated Balance Sheets at September 30, 2014 and 2013 and December 31, 2013	3

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013	5

	Notes to Unaudited Consolidated Financial Statements	6

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	21

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40

Item 4.	Controls and Procedures	40

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	41

Item 1A.	Risk Factors	41

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

Item 6.	Exhibits	41

	Signature	42

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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” and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements regarding the following:


•	plans;


•	objectives;


•	goals;


•	strategies;


•	assumptions and estimates;


•	future events or performance;


•	trends;


•	timing and cyclicality;


•	earnings and dividends;


•	growth;


•	customer rates;


•	commodity costs;


•	gas reserves;


•	operational performance and costs;


•	projections and efficacy of derivatives and hedges;


•	liquidity and financial positions;


•	project development and expansion;


•	competition;


•	procurement and development of gas supplies;


•	estimated expenditures;


•	costs of compliance;


•	credit exposures;


•	potential efficiencies;


•	rate recovery and refunds;


•	impacts of laws, rules, and regulations;


•	tax liabilities or refunds;


•	levels and pricing of gas storage contracts and gas storage market trends;


•	efficacy of system enhancements;


•	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;


•	effects of regulatory mechanisms;


•	environmental, regulatory, litigation and insurance costs and recoveries; and


•	effects of the new labor contract.

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 2013 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	2014			2013			2014		2013

Operating revenues	$	87,199		$	88,195		$	513,754	$	497,770

Operating expenses:
Cost of gas	32,227			33,655			245,708		235,156
Operations and maintenance	32,968			32,636			103,085		99,610
General taxes	7,143			6,954			22,508		23,028
Depreciation and amortization	19,938			18,737			59,236		56,474
Total operating expenses	92,276			91,982			430,537		414,268
Income (loss) from operations	(5,077		)	(3,787		)	83,217		83,502
Other income and expense, net	407			1,300			2,052		3,270
Interest expense, net	10,805			11,347			34,024		33,543
Income (loss) before income taxes	(15,475		)	(13,834		)	51,245		53,229
Income tax expense (benefit)	(6,742		)	(5,601		)	21,023		21,697
Net income (loss)	(8,733		)	(8,233		)	30,222		31,532
Other comprehensive income:
Amortization of non-qualified employee benefit plan liability, net of taxes of $108 and $152 for the three months and $324 and $454 for the nine months ended September 30, 2014 and 2013, respectively	166			232			497		697
Comprehensive income (loss)	$	(8,567	)	$	(8,001	)	$	30,719	$	32,229
Average common shares outstanding:
Basic	27,189			26,987			27,145		26,962
Diluted	27,189			26,987			27,195		27,013
Earnings (loss) per share of common stock:
Basic	$	(0.32	)	$	(0.31	)	$	1.11	$	1.17
Diluted	(0.32		)	(0.31		)	1.11		1.17
Dividends declared per share of common stock	0.460			0.455			1.380		1.365

See Notes to Unaudited Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

In thousands	September 30, 2014			September 30, 2013			December 31, 2013

Assets:
Current assets:
Cash and cash equivalents	$	8,275		$	16,105		$	9,471
Accounts receivable	30,468			29,821			81,889
Accrued unbilled revenue	12,442			16,493			61,527
Allowance for uncollectible accounts	(840		)	(802		)	(1,656		)
Regulatory assets	52,250			26,293			22,635
Derivative instruments	5,587			1,452			5,311
Inventories	86,600			75,419			60,669
Gas reserves	21,455			18,083			20,646
Income taxes receivable	7,639			909			3,534
Deferred tax assets	5,100			—			45,241
Other current assets	19,158			11,936			21,181
Total current assets	248,134			195,709			330,448
Non-current assets:
Property, plant, and equipment	2,990,662			2,865,860			2,918,739
Less: Accumulated depreciation	883,568			846,346			855,865
Total property, plant, and equipment, net	2,107,094			2,019,514			2,062,874
Gas reserves	131,745			115,218			121,998
Regulatory assets	263,321			387,676			369,603
Derivative instruments	602			1,682			1,880
Other investments	67,980			67,548			67,851
Restricted cash	3,000			4,000			4,000
Other non-current assets	11,648			14,566			12,257
Total non-current assets	2,585,390			2,610,204			2,640,463
Total assets	$	2,833,524		$	2,805,913		$	2,970,911

See Notes to Unaudited Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

In thousands	September 30, 2014			September 30, 2013			December 31, 2013

Liabilities and equity:
Current liabilities:
Short-term debt	$	190,000		$	141,300		$	188,200
Current maturities of long-term debt	40,000			60,000			60,000
Accounts payable	71,018			67,652			96,126
Taxes accrued	11,876			11,302			10,856
Interest accrued	10,427			11,143			7,103
Regulatory liabilities	23,352			16,506			28,335
Derivative instruments	5,520			8,275			1,891
Other current liabilities	33,481			26,289			40,280
Total current liabilities	385,674			342,467			432,791
Long-term debt	621,700			681,700			681,700
Deferred credits and other non-current liabilities:
Deferred tax liabilities	499,809			463,566			532,036
Regulatory liabilities	312,500			298,220			303,485
Pension and other postretirement benefit liabilities	142,502			210,943			149,354
Derivative instruments	551			1,404			615
Other non-current liabilities	118,531			77,322			119,058
Total deferred credits and other non-current liabilities	1,073,893			1,051,455			1,104,548
Commitments and contingencies (see Note 13)	—			—			—
Equity:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 27,203, 27,001, and 27,075 at September 30, 2014 and 2013 and December 31, 2013, respectively	371,657			361,789			364,549
Retained earnings	386,461			377,096			393,681
Accumulated other comprehensive loss	(5,861		)	(8,594		)	(6,358		)
Total equity	752,257			730,291			751,872
Total liabilities and equity	$	2,833,524		$	2,805,913		$	2,970,911

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	2014			2013

Operating activities:
Net income	$	30,222		$	31,532
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	59,236			56,474
Regulatory amortization of gas reserves	13,795			8,132
Deferred tax liabilities, net	10,721			22,003
Non-cash expenses related to qualified defined benefit pension plans	3,795			4,256
Contributions to qualified defined benefit pension plans	(10,500		)	(8,900		)
Deferred environmental recoveries, net of (expenditures)	89,537			(10,805		)
Other	(1,692		)	(2,116		)
Changes in assets and liabilities:
Receivables	100,931			70,154
Inventories	(25,931		)	(7,817		)
Taxes accrued	(3,085		)	3,357
Accounts payable	(28,762		)	(19,860		)
Interest accrued	3,324			5,190
Deferred gas costs	(22,173		)	(4,159		)
Other, net	(4,554		)	9,961
Cash provided by operating activities	214,864			157,402
Investing activities:
Capital expenditures	(86,552		)	(86,287		)
Utility gas reserves	(21,734		)	(41,777		)
Proceeds from sale of assets	—			6,580
Restricted cash	1,000			—
Other	82			2,116
Cash used in investing activities	(107,204		)	(119,368		)
Financing activities:
Common stock issued, net	5,460			3,754
Long-term debt issued	—			50,000
Long-term debt retired	(80,000		)	—
Change in short-term debt	1,800			(48,950		)
Cash dividend payments on common stock	(37,442		)	(36,783		)
Other	1,326			1,127
Cash used in financing activities	(108,856		)	(30,852		)
Increase (decrease) in cash and cash equivalents	(1,196		)	7,182
Cash and cash equivalents, beginning of period	9,471			8,923
Cash and cash equivalents, end of period	$	8,275		$	16,105

Supplemental disclosure of cash flow information:
Interest paid	$	30,701		$	28,353
Income taxes paid	14,945			570

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 consolidation of Northwest Natural Gas Company (NW Natural or the Company) and all companies that 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 that 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 that 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 Palomar Gas Holdings, LLC (PGH) 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 significant 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.

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

Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments that 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 2013 Annual Report on Form 10-K (2013 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

Our significant accounting policies are described in Note 2 of the 2013 Form 10-K. There were no material changes to those accounting policies during the nine months ended September 30, 2014. The following are current updates to certain critical accounting policy estimates and new accounting standards in general.

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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	2014		2013		2013
Current:
Unrealized loss on derivatives⁽¹⁾	$	5,520	$	8,275	$	1,891
Gas costs	23,795		—		4,286
Other⁽²⁾	22,935		18,018		16,458
Total current	$	52,250	$	26,293	$	22,635
Non-current:
Unrealized loss on derivatives⁽¹⁾	$	551	$	1,404	$	615
Pension balancing⁽³⁾	30,682		22,976		25,713
Deferred income taxes	49,007		53,065		51,814
Pension and other postretirement benefit liabilities⁽³⁾	118,485		187,000		125,855
Environmental costs⁽⁴⁾	51,861		118,029		148,389
Gas costs	1,936		—		1,840
Other⁽²⁾	10,799		5,202		15,377
Total non-current	$	263,321	$	387,676	$	369,603



	Regulatory Liabilities
	September 30,				December 31,
In thousands	2014		2013		2013
Current:
Gas costs	$	6,704	$	3,096	$	7,510
Unrealized gain on derivatives⁽¹⁾	5,320		1,386		5,290
Other⁽²⁾	11,328		12,024		15,535
Total current	$	23,352	$	16,506	$	28,335
Non-current:
Gas costs	$	410	$	11	$	2,172
Unrealized gain on derivatives⁽¹⁾	602		1,682		1,880
Accrued asset removal costs	307,815		293,005		296,294
Other⁽²⁾	3,673		3,522		3,139
Total non-current	$	312,500	$	298,220	$	303,485


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


⁽²⁾	These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge.


⁽³⁾	Certain utility pension costs are approved for regulatory deferral, including amounts recorded to the pension balancing account, to mitigate the effects of higher and lower pension expenses. Pension costs that are deferred include an interest component when recognized in net periodic benefit costs; see Note 7 for further information.

⁽⁴⁾

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. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. For further information on environmental matters, see Note 13.

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New Accounting Standards

Recent Accounting Pronouncements

REVENUE RECOGNITION. On May 28, 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 obligation is satisfied. The new requirements are effective beginning January 1, 2017, and an entity may elect either a full retrospective or simplified transition adoption method. Early adoption is not permitted. NW Natural is currently assessing the impact of this standard on its 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. The diluted earnings per share calculation also includes 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. Diluted earnings per share are calculated as follows:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
In thousands, except per share data	2014			2013			2014		2013
Net income (loss)	$	(8,733	)	$	(8,233	)	$	30,222	$	31,532
Average common shares outstanding - basic	27,189			26,987			27,145		26,962
Additional shares for stock-based compensation plans outstanding	—			—			50		51
Average common shares outstanding - diluted	27,189			26,987			27,195		27,013
Earnings (loss) per share of common stock - basic	$	(0.32	)	$	(0.31	)	$	1.11	$	1.17
Earnings (loss) per share of common stock - diluted	$	(0.32	)	$	(0.31	)	$	1.11	$	1.17
Additional information:
Antidilutive shares excluded from net income per diluted common share calculation	80			80			24		26

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 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 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 PGH, which is pursuing development of a cross-Cascades transmission pipeline project. See Note 4 in our 2013 Form 10-K for further discussion of our segments.

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The following table presents summary financial information concerning the reportable segments; inter-segment transactions are insignificant for the periods presented:



	Three Months Ended September 30,
In thousands	Utility			Gas Storage		Other			Total
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
2013
Operating revenues	$	80,705		$	7,434	$	56		$	88,195
Depreciation and amortization	17,118			1,619		—			18,737
Income (loss) from operations	(7,293		)	3,556		(50		)	(3,787		)
Net income (loss)	(9,605		)	1,407		(35		)	(8,233		)
Capital expenditures	30,805			427		—			31,232



	Nine Months Ended September 30,
In thousands	Utility		Gas Storage		Other			Total
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
2013
Operating revenues	$	474,307	$	23,295	$	168		$	497,770
Depreciation and amortization	51,617		4,857		—			56,474
Income (loss) from operations	72,372		11,138		(8		)	83,502
Net income (loss)	27,083		4,495		(46		)	31,532
Capital expenditures	85,327		960		—			86,287
Total assets at September 30, 2013	2,502,688		287,317		15,908			2,805,913

Total assets at December 31, 2013	2,644,367		310,097		16,447			2,970,911

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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 costs 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 following table presents additional segment information concerning utility margin. The gas storage and other segments emphasize growth in operating revenues and net income as opposed to margin because these segments 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 margin information for our utility segment:



	Three Months Ended September 30,				Nine Months Ended September 30,
In thousands	2014		2013		2014		2013
Utility margin calculation:
Utility operating revenues	$	82,361	$	80,705	$	495,931	$	474,307
Less: Utility cost of gas	32,227		33,655		245,708		235,156
Utility margin	$	50,134	$	47,050	$	250,223	$	239,151

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, an Employee Stock Purchase Plan, and a Restated Stock Option Plan (Restated SOP). The Restated SOP was terminated with respect to new grants in 2012; however, options that had been granted before the Restated SOP was terminated will remain outstanding until the earlier of their expiration, forfeiture, or exercise. Any new grants of stock options would be made under the LTIP. No stock options were granted under the LTIP during the nine months ended September 30, 2014. These plans are designed to promote stock ownership in NW Natural by employees and officers. For additional information on our stock-based compensation plans, see Note 6 in the 2013 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 first quarter of 2014, 43,625 performance-based shares were granted under the LTIP based on target-level awards with a weighted-average grant date fair value of $42.43 per share. 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	$	41.78
Performance term (in years)	3.0
Quarterly dividends paid per share	$	0.460
Expected dividend yield	4.3		%
Dividend discount factor	0.8845

Performance-Based Restricted Stock Units (RSUs)

During the nine months ended September 30, 2014, 38,765 RSUs were granted under the LTIP with a weighted-average grant date fair value of $42.19 per share. The fair value of a RSU is equal to the closing market price of the Company's common stock on the grant date. As of September 30, 2014, there was $2.4 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 include a performance-based threshold and 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.

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6. DEBT

Short-Term Debt

At September 30, 2014, our short-term debt consisted of commercial paper notes payable with a maximum maturity of 209 days, an average maturity of 96 days, and an outstanding balance of $190 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 our 2013 Form 10-K for a description of the fair value hierarchy.

Current Maturities of Long-Term Debt

The utility has long-term debt due within the next 12 months consisting of $40 million of first mortgage bonds (FMBs) with a coupon rate of 4.70% and maturity in June 2015.

Long-Term Debt

Our utility segment has long-term debt, including current maturities referred to above, of $641.7 million. Utility long-term debt consists of FMBs with maturity dates ranging from 2015 through 2042, interest rates ranging from 3.176% to 9.05%, and a weighted-average coupon rate of 5.64%.

At September 30, 2014, our gas storage segment’s long-term debt consisted of $20 million of fixed-rate senior secured debt with a maturity date of November 30, 2016 and an interest rate of 7.75%. This debt is secured by all of the membership interests in Gill Ranch and is nonrecourse to NW Natural. Under the amended loan agreement, $20 million of variable-rate debt was retired in June 2014. As part of the amended agreement, the earnings before interest, tax, depreciation, and amortization (EBITDA) covenant requirement was suspended through March 31, 2015 and the EBITDA hurdles thereafter were lowered. The debt service reserve requirement was fixed at $3 million.

Retirements of Long-Term Debt

The utility redeemed $50 million of FMBs with a coupon rate of 3.95% in July 2014 and $10 million in September 2014 with a coupon rate of 8.26%. As noted above, in June 2014 Gill Ranch retired $20 million of variable interest rate debt with a coupon rate of 7.00%.

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 our 2013 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	2014		2013		2013
Carrying amount	$	661,700	$	741,700	$	741,700
Estimated fair value	748,902		828,360		806,359

See Note 7 in our 2013 Form 10-K for more detail on our long-term debt.

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7. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

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



	Three Months Ended September 30,
							Other Postretirement
	Pension Benefits						Benefits
In thousands	2014			2013			2014			2013
Service cost	$	1,919		$	2,341		$	136		$	178
Interest cost	4,511			4,103			309			286
Expected return on plan assets	(4,887		)	(4,678		)	—			—
Amortization of net actuarial loss	2,579			4,421			46			169
Amortization of prior service costs	56			56			50			50
Net periodic benefit cost	4,178			6,243			541			683
Amount allocated to construction	(1,242		)	(1,910		)	(177		)	(226		)
Amount deferred to regulatory balancing account⁽¹⁾	(1,107		)	(2,230		)	—			—
Net amount charged to expense	$	1,829		$	2,103		$	364		$	457



	Nine Months Ended September 30,
							Other Postretirement
	Pension Benefits						Benefits
In thousands	2014			2013			2014			2013
Service cost	$	5,755		$	7,023		$	407		$	536
Interest cost	13,535			12,310			928			858
Expected return on plan assets	(14,659		)	(14,034		)	—			—
Amortization of net actuarial loss	7,739			13,263			138			507
Amortization of prior service costs	168			167			148			148
Net periodic benefit cost	12,538			18,729			1,621			2,049
Amount allocated to construction	(3,644		)	(5,566		)	(518		)	(656		)
Amount deferred to regulatory balancing account⁽¹⁾	(3,331		)	(6,850		)	—			—
Net amount charged to expense	$	5,563		$	6,313		$	1,103		$	1,393

⁽¹⁾

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 actual cost of long-term debt, with deferred revenue in the utility's allocated share of equity to be recognized in a future accounting period when deferred pension expense is collected.

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	2014			2013			2014			2013
Beginning balance	$	(6,027	)	$	(8,826	)	$	(6,358	)	$	(9,291	)
Amounts reclassified from AOCL:
Amortization of prior service costs	(1		)	(1		)	(5		)	(5		)
Amortization of actuarial losses	275			385			826			1,156
Total reclassifications before tax	274			384			821			1,151
Tax expense	(108		)	(152		)	(324		)	(454		)
Total reclassifications for the period	166			232			497			697
Ending balance	$	(5,861	)	$	(8,594	)	$	(5,861	)	$	(8,594	)

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Employer Contributions to Company-Sponsored Defined Benefit Pension Plan

For the nine months ended September 30, 2014, we made cash contributions totaling $10.5 million to our qualified defined benefit pension plan. In 2012, Congress passed the "Moving Ahead for Progress in the 21st Century Act" (MAP-21), which, among other things, includes provisions that reduce the level of minimum required contributions in the near-term but generally increase contributions in the long-run as well as increase the operational costs of running a pension plan. In August 2014, the Highway and Transportation Funding Act of 2014 (HATFA) was signed and extends certain aspects of MAP-21 as well as modifies the phase-out periods for the limitations. Due to the effects of HATFA, we do not currently expect further pension plan contributions during the remainder of 2014 and anticipate a reduction in contributions of over $55 million in the next ten years.

Multiemployer Pension Plan

Prior to December 2013, the Company also participated in a multiemployer pension plan for its utility’s union employees. The Company withdrew from this plan in December 2013 and recorded a withdrawal liability of $8.3 million, which requires NW Natural to pay $0.6 million to the plan each year for the next 20 years. The cost of the withdrawal liability was deferred to a regulatory account on the balance sheet, and as of September 30, 2014 the liability balance was $8.1 million.

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). Company contributions to this plan totaled $2.8 million and $2.3 million for the nine months ended September 30, 2014 and 2013, respectively.

See Note 8 in the 2013 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	2014			2013			2014			2013
Income tax at statutory rates (federal and state)	$	(6,161	)	$	(5,489	)	$	20,288		$	21,080
Increase (decrease):
Differences required to be flowed-through by regulatory commissions	(310		)	(393		)	1,184			1,171
Other, net	(271		)	281			(449		)	(554		)
Income tax expense (benefit)	$	(6,742	)	$	(5,601	)	$	21,023		$	21,697
Effective income tax rate	43.6		%	40.5		%	41.0		%	40.8		%

The increase in the income tax benefit amount and the effective income tax rate for the three months ended September 30, 2014 compared to the same period in 2013 was primarily due to a higher pre-tax loss and the result of estimating a lower annual effective tax rate. The decrease for the nine months ended September 30, 2014 compared to the same periods in 2013 was primarily due to lower pre-tax income and a lower estimated annual effective tax rate. Partially offsetting this was a $0.6 million income tax charge related to a higher effective tax rate in Oregon, which required the revaluation of deferred tax balances in the first quarter of 2014. See Note 9 in the 2013 Form 10-K for more detail on income taxes and effective tax rates.

The Company’s examination by the Internal Revenue Service (IRS) for tax years 2009 through 2011 was completed during the first quarter of 2014. The examination did not result in a material change to the returns as originally filed or previously adjusted for net operating loss carrybacks. The 2012 and 2013 tax year are open and subject to examination, while the 2014 tax year is subject to review under the IRS Compliance Assurance Process.

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	2014		2013		2013
Utility plant in service	$	2,655,136	$	2,482,034	$	2,585,901
Utility construction work in progress	31,778		80,325		28,855
Less: Accumulated depreciation	850,590		818,644		827,380
Utility plant, net	1,836,324		1,743,715		1,787,376
Non-utility plant in service	297,199		296,022		297,330
Non-utility construction work in progress	6,549		7,479		6,653
Less: Accumulated depreciation	32,978		27,702		28,485
Non-utility plant, net	270,770		275,799		275,498
Total property, plant, and equipment	$	2,107,094	$	2,019,514	$	2,062,874

Capital expenditures in accrued liabilities	$	11,834	$	9,265	$	10,691

10. GAS RESERVES

We entered into our original agreements with Encana Oil & Gas (USA) Inc. (Encana) in 2011 to develop and produce physical gas reserves and provide long-term gas price protection for utility customers. Encana began drilling in 2011 under these agreements. Gas produced from working interests in these gas fields is sold at prevailing market prices, with revenues from such sales, less associated production costs, credited to the utility's cost of gas. The cost of gas, including a carrying cost for the rate base investment, is part of NW Natural's annual Oregon PGA filing, which allows us to recover our costs through customer rates. Our net investment under the original agreement earns a rate of return and provides long-term price protection for our utility customers.

On March 28, 2014, we amended the original gas reserve agreement in order to facilitate Encana's proposed sale of its interest in the Jonah field to Jonah Energy LLC. Under the amendment, we ended the drilling program with Encana, but increased our assigned ownership interests in certain sections of the Jonah field and retained the right to invest in additional wells with the new owner.

Since the amendment, we have been notified by Jonah Energy LLC of investment opportunities in the sections of the Jonah field where we have ownership interests. The amended agreement allows us to invest in additional wells on a well-by-well basis with drilling costs and resulting gas volumes shared at our proportionate ownership interest for each well in which we invest. We elected to participate in some of the additional wells drilled in 2014, and we 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. We intend to file seeking cost recovery for the additional wells drilled in 2014. We have also signed a memorandum of understanding with all parties agreeing that individual wells drilled in any year will be reviewed for prudence annually going forward. A decision on the prudence of the wells drilled in 2014 will occur when the parties and Commission review our filing seeking cost recovery and is expected in 2015. Our cumulative investment of approximately $8 million in these additional wells has been accounted for as a utility investment. If regulatory approval is not received, our investment in these additional wells would follow oil and gas accounting.

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Gas reserves acted to hedge the cost of gas for approximately 10% and 6% of our utility's gas supplies for the nine months ended September 30, 2014 and 2013, respectively. Our utility gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. The following table outlines our net investment in gas reserves:



	September 30,				December 31,
In thousands	2014		2013		2013
Gas reserves, current	$	21,455	$	18,083	$	20,646
Gas reserves, non-current	164,115		130,836		140,573
Less: Accumulated amortization	32,370		15,618		18,575
Total gas reserves⁽¹⁾	153,200		133,301		142,644
Less: Deferred tax liabilities on gas reserves	33,037		40,553		42,117
Net investment in gas reserves⁽¹⁾	$	120,163	$	92,748	$	100,527


⁽¹⁾	Total gas reserves includes our investment in additional wells, subject to regulatory deferral approvals, with total gas reserves of $7.8 million and net investment of $6.5 million at September 30, 2014 and no net investment or total gas reserves from additional wells in 2013.

11. INVESTMENTS

Equity Method Investments

Palomar Gas Transmission, LLC (Palomar), a wholly-owned subsidiary of PGH, 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 PGH, and 50% is owned by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation. PGH is a development stage Variable Interest Entity, with our investment in Palomar reported under equity method accounting. We have determined that we are not the primary beneficiary of PGH’s activities, in accordance with the authoritative guidance related to consolidations, 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 PGH and Palomar are included in other investments on our balance sheet. Should this investment not be developed, then our maximum loss exposure related to PGH 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 PGH was $13.4 million at September 30, 2014 and 2013 and December 31, 2013. See Note 12 in our 2013 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 2013 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. The financial derivatives used in order to meet our utility's natural gas requirements qualify for regulatory deferral accounting.

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.

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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.

Notional Amounts

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



	September 30,				December 31,
In thousands	2014		2013		2013
Natural gas (in therms):
Financial	368,425		527,700		389,225
Physical	620,550		572,675		552,500
Foreign exchange	$	10,296	$	13,862	$	15,002

Purchased Gas Adjustment

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 10% or 20% recognized in current income. For both the 2013-14 and 2014-15 gas years, we selected the 90% deferral option. 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 the Company's weighted-average cost of gas in the PGA filing. As of November 1, 2013, we reached our target hedge percentage of approximately 75% for the 2013-14 gas year. These hedge prices were included in the PGA filings and qualified for regulatory deferral.

Unrealized and Realized Gain/Loss

The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments. Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory accounting standards.



	Three Months Ended September 30,
	2014						2013
In thousands	Natural gas commodity			Foreign currency			Natural gas commodity			Foreign currency
Benefit (expense) to cost of gas	$	(10,173	)	$	(421	)	$	2,422		$	502
Less:
Amounts deferred to regulatory accounts on the balance sheet	10,559			421			(2,433		)	(502		)
Total gain (loss) in pre-tax earnings	$	386		$	—		$	(11	)	$	—



	Nine Months Ended September 30,
	2014						2013
In thousands	Natural gas commodity			Foreign currency			Natural gas commodity			Foreign currency
Benefit (expense) to cost of gas	$	360		$	(242	)	$	(6,534	)	$	(11	)
Less:
Amounts deferred to regulatory accounts on the balance sheet	(93		)	242			6,599			11
Total gain in pre-tax earnings	$	267		$	—		$	65		$	—

The cost of foreign currency forward contracts 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.

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We realized a net gain of $0.5 million and $13.3 million for the three and nine months ended September 30, 2014, respectively, compared to a net loss of $2.3 million and $6.3 million for the three and nine months ended September 30, 2013, respectively, from the settlement of natural gas financial derivative contracts. Realized gains are recorded as a reduction to the cost of gas, while realized losses were recorded as increases to the cost of gas.

Credit Risk Management of Financial Derivatives Instruments

No collateral was posted with, or by, our counterparties as of September 30, 2014 or 2013. 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 2013 or 2014. 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 derivative contracts outstanding, which reflect net unrealized gains of $1.7 million at September 30, 2014, we currently do not have any collateral demand exposure.

Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our statement of financial position. The Company and its counterparties have the ability to set-off their obligations to each other under specified circumstances. Such circumstances may include: when there is a defaulting party, or in the event of a credit change due to a merger that affects either party, or any other termination event. If netted by counterparty, our derivative position would result in an asset of $4.0 million and a liability of $3.9 million as of September 30, 2014. As of September 30, 2013, our derivative position would have resulted in an asset of $0.2 million and a liability of $6.7 million, and as of December 31, 2013, our position would have resulted in an asset of $7.2 million and a liability of $2.5 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 2013 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, 2014. As of September 30, 2014 and 2013 and December 31, 2013, the net fair value was an asset of $0.1 million, a liability of $6.5 million, and an asset of $4.7 million, respectively, using significant other observable, or Level 2, inputs. We have used no Level 3 inputs in our derivative valuations. We did not have any transfers between Level 1 or Level 2 during the nine months ended September 30, 2014 and 2013.

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 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. 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.

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In the 2012 Oregon general rate case, the Site Remediation Recovery Mechanism (SRRM) was approved to recover the Company's deferred environmental costs. The Commission ordered a separate docket to determine the prudence of deferred costs, the allocation of insurance proceeds, and an earnings test that would be applied to past and future deferred costs. We are currently awaiting the Commission's decision regarding this matter.

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. We annually review all regulatory assets for recoverability and more often if circumstances warrant. If we should determine that 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.

In December 2010, NW Natural commenced litigation against certain of its historical liability insurers in Multnomah County Circuit Court, State of Oregon (see Part I, Item 3. Legal Proceedings in our 2013 Form 10-K). In the complaint, NW Natural sought damages in excess of the $50 million in losses it had incurred through the date of the complaint, as well as declaratory relief for additional losses it expected to incur in the future. Prior to 2014, we had settled with several defendant insurance companies for payments aggregating approximately $48 million. In February 2014, we settled with all remaining defendant insurance companies in this litigation with the Company to receive additional payments aggregating to approximately $102 million for a total of approximately $150 million. We received these payments, and the Court dismissed the case on July 29, 2014. The settlements are recognized in regulatory accounts with the treatment to be determined in the ongoing docket related to the SRRM.

Environmental Sites

The following table summarizes information regarding liabilities related to environmental sites, 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	2014		2013		2013		2014		2013		2013
Portland Harbor site:
Gasco/Siltronic Sediments	$	686	$	512	$	1,278	$	38,593	$	38,034	$	37,954
Other Portland Harbor	1,060		1,812		1,766		3,198		2,315		3,478
Gasco Uplands site	7,399		2,094		11,010		37,748		7,126		39,508
Siltronic Uplands site	634		405		763		577		434		406
Central Service Center site	70		150		85		173		271		248
Front Street site	804		411		1,274		99		158		122
Oregon Steel Mills	—		—		—		179		179		179
Total	$	10,653	$	5,384	$	16,176	$	80,567	$	48,517	$	81,895

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	2014		2013		2013
Cumulative cash paid⁽¹⁾	$	111,367	$	93,264	$	98,817
Total regulatory asset deferral⁽²⁾	$	51,861	118,029		148,389


⁽¹⁾	Includes $20.4 million reclassified to utility plant on November 1, 2013 associated with the water treatment station of which a portion was paid during 2012 through 2014.


⁽²⁾	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 11 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands and

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Siltronic uplands sites. We have been notified that we are a potentially responsible party to the Superfund site and we have joined with some of the other potentially responsible parties (the Lower Willamette Group or LWG) to develop a Portland Harbor Remedial Investigation/Feasibility Study (RI/FS). The LWG submitted a draft Feasibility Study (FS) to the EPA in March 2012 that provides a range of remedial costs for the entire Portland Harbor Superfund Site, which includes the Gasco/Siltronic Sediment site, discussed below. The range of costs estimated for various remedial alternatives for the entire Portland Harbor, as provided in the draft FS, is $169 million to $1.8 billion. NW Natural's potential liability is a portion of the costs of the remedy the EPA will select for the entire Portland Harbor Superfund site. The cost of that remedy is expected to be allocated among more than 100 potentially responsible parties. NW Natural is participating in a non-binding allocation process in an effort to settle this potential liability. 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. NW Natural 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 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 $39.3 million to $350 million. We have recorded a liability of $39.3 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, which is performing the RI/FS for the EPA. 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 accrued 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 and noted above.

GASCO UPLANDS SITE. NW Natural owns 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 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.

In May 2007, we completed a revised Remedial Investigation Report for the uplands portion and submitted it to ODEQ for review. 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 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 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. During the first quarter of 2014, the OPUC deemed these costs prudent and 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 beginning November 1, 2014.

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,

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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 as of September 30, 2014.

Siltronic Upland site. Siltronic is the location of a manufactured gas plant formerly owned by NW Natural. We are currently conducting an investigation of manufactured gas plant wastes on the uplands at 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, and cleanup is necessary.

Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated. Studies for source control investigation have been presented to ODEQ and a final sampling plan required by ODEQ is currently being developed.

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

Legal Proceedings

NW Natural is subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, NW Natural does 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, NW Natural was served with a third-party complaint by the Port of Portland (the Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants, were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by 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 that 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 commitment and contingencies, see Note 14 in our 2013 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, 2014 and 2013. 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 2013 Annual Report on Form 10-K (2013 Form 10-K).

The consolidated financial statements include NW Natural, the parent company, and its direct and indirect wholly-owned subsidiaries. Selected subsidiaries are depicted and organized as follows:

We operate in two primary reportable business segments: local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as other. We refer to our local gas distribution business as the utility, and our gas storage segment and other as non-utility. Our utility segment includes our NW Natural local gas distribution business, NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp, and the utility portion of our Mist underground storage facility in Oregon (Mist). Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist, and asset management services. Other includes NWN Energy's equity investment in Palomar Gas Holdings, LLC (PGH), which is pursuing the development of a proposed natural gas pipeline through its wholly-owned subsidiary, Palomar Gas Transmission, LLC (Palomar), and NNG Financial's equity investment in Kelso-Beaver Pipeline (KB Pipeline). PGH and our equity investments, Palomar and KB Pipeline, are not depicted in the chart above. 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, which are non-GAAP financial measures. These amounts reflect factors that directly impact earnings. In calculating these financial disclosures, we allocate income tax expense based on the effective tax rate, where applicable. All references in this section to earnings per share (EPS) are on the basis of diluted shares (see Note 3 in our 2013 Form 10-K). We use such non-GAAP measures in analyzing 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

Key financial highlights include:



	Three Months Ended September 30,
In thousands, except per share data	2014			2013			Change
Consolidated net loss	$	(8,733	)	$	(8,233	)	$	(500	)
Consolidated loss per share	(0.32		)	(0.31		)	(0.01		)

Utility margin	$	50,134		$	47,050		$	3,084
Utility net loss	(8,808		)	(9,605		)	797
Gas storage operating revenues	4,782			7,434			(2,652		)
Gas storage net income	2			1,407			(1,405		)
Consolidated other income and expense, net	407			1,300			(893		)

THREE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The primary factors contributing to the $0.5 million increase in consolidated net loss for the quarter were as follows:


•	an increase in utility margin of $3.1 million due to customer growth and rate-base returns on gas reserve and other investments; more than offset by the following variances:


•	a decrease in gas storage operating revenues of $2.7 million due to re-contracting certain expiring capacity at lower prices for the 2014-15 gas storage year; and


•	a decrease in other income and expense, net of $0.9 million due to lower interest income on reduced net deferred regulatory balances.

From a longer-term operational perspective, we continue to make progress on several key strategic initiatives, as evidenced by the following items:


•	increased customer growth rate in the core utility from 1.1% a year ago to 1.3% at September 30, 2014;


•	placed first in residential customer satisfaction among large gas utilities in the West in the 2014 J.D. Power and Associates Study, making 2014 the 13th consecutive year of top three rankings;


•	launched a new online tool for customers and trade allies that enables online ordering services, tracking progress of orders, and managing multiple projects;


•	announced a dividend increase in the fourth quarter, which reflects the 59^thconsecutive year of increases; and


•	received approval from the OPUC for two rate schedules designed to provide no-notice gas storage and transportation services. If the potential expansion of our Mist gas storage facility proceeds, we believe Portland General Electric (PGE) will take service under one of these schedules.

ISSUES AND CHALLENGES

ECONOMY. The local, national, and global economies continue to show signs of improvement. Our utility’s customer growth rate, on a trailing 12-month basis, increased from 1.1% at September 30, 2013 to 1.3% at September 30, 2014 as NW Natural neared the 700,000 total customer mark. On a consecutive quarter basis, the growth rate decreased slightly from the 1.4% rate at June 30, 2014 as warmer weather this fall slowed natural gas conversions and delayed customer re-connections to gas service. Additionally, the unemployment rate in the Portland metropolitan region decreased to under 6% during the third quarter of 2014, a decline of less than 1% from the same period in 2013. We believe our utility is well positioned to add customers and to serve increasing industrial demand as the economy improves, regional business projects move forward, and proposed legislation favoring lower carbon emissions continues to develop.

GAS PRICES, SUPPLIES, AND STORAGE VALUES. Our utility gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our customers and to manage gas prices. Our utility’s annual PGA mechanisms in Oregon and Washington, combined with our gas price hedging strategies, enable us to reduce earnings exposure for the Company and secure more stable gas costs for customers. We typically hedge gas prices on 75% of our utility’s annual sales requirement based on normal weather, including both physical and financial hedges. We entered the 2013-14 gas year (November 1, 2013 – October 31, 2014) hedged at 75% of our forecasted sales volumes, including 31% in financial swap and option contracts and 44% in physical gas supplies. For further discussion see "Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment" below.

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In addition to the amount hedged for the current gas contract year, as of September 30, 2014 we were hedged at approximately 71% for the upcoming 2014-15 gas year and between 6% and 19% for the following five gas years. Our hedge levels are based on estimated sales volumes, which depend, to a certain extent, on weather and economic conditions. Also, our gas storage inventory levels may increase or decrease depending on future storage expansions, changes in storage contracts with third parties, and future storage recall by the utility pursuant to our utility's integrated resource plan.

While low and stable gas prices provide opportunities to lower costs for our utility customers, they also present challenges for our gas storage businesses by lowering the price of, and reducing the demand for, storage services. As an example, earlier this year we re-contracted certain expiring storage customer capacity for the 2014-15 gas storage year at very low prices due to the flat natural gas price curve and generally weak market conditions, which negatively impacted our financial results. However, increases in the demand for natural gas or decreases in supply going forward can result in upward pressure on gas prices and gas price volatility, which could improve the market value for gas storage. As existing contracts expire, we remain focused on managing costs at our storage facilities and capitalizing on market opportunities that fit our business-risk profile.

ENVIRONMENTAL COSTS. We accrue estimates for environmental loss contingencies related to environmental sites for which we are responsible. Due to numerous uncertainties surrounding the nature of environmental investigations and the development of remediation solutions approved by regulatory agencies, actual costs could vary significantly from our loss estimates. As a regulated utility, we have been allowed to defer certain costs pursuant to regulatory orders. In our 2012 general rate case, the OPUC approved the recovery of our environmental costs for investigation and site remediation from customers subject to certain conditions as noted in "Regulatory Matters—Rate Mechanisms" below.

We have received approximately $150 million cumulatively from insurance policies to apply toward environmental costs, and will only seek recovery from customers for amounts in excess of any insurance proceeds. Ultimate recovery of environmental costs from regulated utility rates depends on our ability to effectively manage these costs and demonstrate that costs were prudently incurred, and the outcome of the annual earnings test proceeding in Oregon. Environmental cost recovery and carrying charges on amounts charged to Washington customers will be determined in a future proceeding.

CONSOLIDATED EARNINGS AND DIVIDENDS

Consolidated Earnings

Consolidated highlights include:



	Three Months Ended September 30,						Nine Months Ended September 30,				QTR Change			YTD Change
In thousands, except per share data	2014			2013			2014		2013		QTR Change			YTD Change
Consolidated operating revenues	$	87,199		$	88,195		$	513,754	$	497,770	$	(996	)	$	15,984
Consolidated operating expenses	92,276			91,982			430,537		414,268		294			16,269
Consolidated net income (loss)	(8,733		)	(8,233		)	30,222		31,532		(500		)	(1,310		)
Consolidated EPS	(0.32		)	(0.31		)	1.11		1.17		(0.01		)	(0.06		)

THREE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The increase in net loss was primarily due to a $2.7 million decrease in gas storage operating revenues and a $0.9 million decrease in other income and expense, net, partially offset by a $3.1 million increase in utility margin.

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The decrease in net income was primarily due to a $5.6 million decrease in gas storage operating revenues, a $3.5 million increase in operations and maintenance expense, a $2.8 million increase in depreciation and amortization expense, and a $1.2 million decrease in other income and expense, net. These variances were partially offset by an $11.1 million increase in utility margin.

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Overall gas storage operating revenues were negatively impacted by re-contracting certain expiring firm storage capacity at lower prices, reflecting a historically low gas storage price market. On a year-to-date basis, higher gas storage operations and maintenance expense reflected additional repair and power costs at Gill Ranch and higher utility operations and maintenance expense reflected increased system maintenance and safety program costs. Offsetting these results was an increase in utility margin from customer growth, added industrial margins, and rate-base returns on gas reserves and other investments.

Dividends

Dividend highlights include:



	Three Months Ended September 30,				Nine Months Ended September 30,				QTD		YTD
Per common share	2014		2013		2014		2013		Change		Change
Dividends paid	$	0.460	$	0.455	$	1.380	$	1.365	$	0.005	$	0.015

On October 7, 2014, the Board of Directors declared a quarterly dividend on our common stock of $0.465 per share, payable on November 14, 2014, to shareholders of record on October 31, 2014, reflecting an indicated annual dividend rate of $1.86 per share.

REGULATORY MATTERS

Regulation and Rates

UTILITY. Our utility business is subject to regulation by the OPUC, the WUTC, and Federal Energy Regulatory Commission (FERC) with respect to, among other matters, rates and terms of service. The OPUC and WUTC also regulate the system of accounts and issuance of securities by our utility. Approximately 90% of our utility gas volumes and revenues are derived from Oregon customers, with the remaining 10% from Washington customers. Earnings and cash flows from utility operations are largely determined by rates set in general rate cases and other rate proceedings in Oregon and Washington, but are also affected by the local economies in Oregon and Washington, the pace of customer growth in the residential, commercial, and industrial markets, and our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery of our utility-related costs, including operating expenses and investment costs in utility plant and other regulatory assets. See "Regulatory Activities" below.

GAS STORAGE. Our gas storage businesses are subject to regulation by the OPUC, California Public Utilities Commission (CPUC), and FERC with respect to, among other matters, rates and terms of service. The OPUC and CPUC also regulate the issuance of securities and system of accounts. The OPUC and CPUC regulate intrastate storage services, and the FERC regulates interstate storage services. The OPUC and FERC use a maximum cost of service model which allows for gas storage prices to be set at or below the cost of service as approved by each agency in the latest regulatory filing. The CPUC regulates Gill Ranch under a market-based rate model which allows for the price of storage services to be set by the marketplace. In 2013, approximately 56% of our storage revenues were derived from operations regulated by OPUC and FERC, and approximately 44% were derived from operations regulated by CPUC.

Regulatory Activities

The following list provides the current status of open regulatory dockets and other regulatory activities:


•	Environmental SRRM - The decision to resolve this docket is expected to include a prudence review of deferred environmental costs, the allocation of insurance proceeds, including the proceeds from the recent insurance litigation settlements, and policy matters regarding the application of an earnings test. We anticipate an OPUC decision on this matter in 2014 or early 2015.


•	Interstate Storage Sharing - This docket was opened to review the current revenue sharing arrangement that allocates a portion of the net revenues generated from non-utility Mist storage services and third-party asset management services to utility customers. We anticipate resolution of this docket in 2014 or early 2015.

•

Prepaid Pension Asset - This docket was opened to evaluate pension cost recovery for all utilities in Oregon. The utilities have requested recovery of the financing costs incurred as a result of timing differences between cash contributions made to their pension plans and the recognition of expense. A schedule was established to resolve this docket in the first half of 2015. The Company currently recovers a portion of pension expense in rates and has requested continued recovery of these expenses in the docket. In addition, the Company defers

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the difference between actual expense incurred and the amount in rates into a balancing account. See "Pension Deferral" below.

•

Integrated Resource Plan (IRP) - We filed our 2014 Oregon and Washington IRPs on August 29, 2014 and anticipate acknowledgment of the filings during 2015. The IRP included analysis of different growth scenarios and corresponding resource acquisition strategies. This analysis is needed to develop supply and demand resource requirements, consider uncertainties in the planning process, and to establish a plan for providing reliable and low cost natural gas service.

•

Gas Reserves - We elected to participate in some of the additional wells drilled in the Jonah field under our amended gas reserves agreement with Jonah Energy, LLC 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. We intend to file seeking cost recovery for the additional wells drilled in 2014. We have also signed a memorandum of understanding with all parties agreeing that individual wells drilled in any year will be reviewed for prudence annually going forward. A decision on the prudence of the wells drilled in 2014 will occur when the parties and OPUC review our filing seeking cost recovery and is expected in 2015.

•

North Mist Gas Storage Rate Schedules - We received approval for two new rate schedules from the OPUC in October 2014. These schedules are intended to allow us to provide no-notice gas storage service from Mist and are specifically designed to support services associated with the proposed expansion. The expansion would be supported by a contract with PGE to serve gas-fired electric power generation facilities at Port Westward, which is located approximately 15 miles from Mist. This expansion project is subject to final approval of project costs, as well as notice to proceed from PGE, and the receipt of various other permits, certain regulatory approvals, and other conditions. If we receive final approval of projected costs and a notice to proceed from PGE in the fourth quarter of 2014, we would expect the expansion to proceed with an in-service date of 2017.


•	Senate Bill (SB) 844 - We continue to work closely with the OPUC and intervenor parties to develop new rules for gas utilities to govern the incentive rate-making mechanisms aimed at reducing greenhouse gas emissions. We expect final rules to be issued in 2014.

Rate Mechanisms

PURCHASED GAS ADJUSTMENT. Rate changes are established annually under PGA rate filings in Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases. This includes gas prices under spot purchases as well as contract supplies, gas prices hedged with financial derivatives, gas prices from the withdrawal of storage inventories, the production of gas reserves, interstate pipeline demand costs, a permanent rate adjustment for our System Integrity Program (SIP) program, temporary rate adjustments that amortize balances of deferred regulatory accounts, and the removal of temporary rate adjustments effective for the previous year.

We filed our PGA in September 2014 and received OPUC and WUTC approval in October 2014. PGA rate changes are effective November 1, 2014. The rate changes increased the average monthly bills of residential customers by 1.7% and 6.0% in Oregon and Washington, respectively. The increase in Oregon reflected customers' portion of adjustments for changes in wholesale natural gas costs, offset by credits related to the decoupling mechanism and some additional annual adjustments based on ongoing agreements with the OPUC. Washington rates reflected the full effect of changes in wholesale natural gas costs and some additional annual adjustments based on ongoing agreements with the WUTC.

Wholesale cost increases were primarily related to the colder weather experienced by many parts of the United States for an extended period this past winter. The extreme cold weather nationally resulted in a significant withdrawal of gas from storage and higher gas prices compared to last year. In addition, NW Natural experienced a cold weather event in February that increased gas volumes purchased for that period. These past and current price and volume increases resulted in the rate changes for the 2014-15 PGA period.

Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select each year either an 80% deferral or a 90% deferral of higher or lower actual gas costs compared to estimated PGA prices, such that the impact on current earnings from the incentive sharing is either 20% or 10% of the difference between actual and estimated gas costs, respectively. For the 2014-15 gas year, we selected the 90% deferral option. Under the Washington PGA mechanism, we defer 100% of the higher or lower actual gas costs, and those gas cost differences are passed on to customers through the annual PGA rate adjustment.

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EARNINGS REVIEW. We are subject to an annual earnings review in Oregon to determine if the utility is earning above its authorized return on equity (ROE) threshold. If utility earnings exceed a specific ROE level, then 33% of the amount above that level is required to be deferred for refund to customers. Under this provision, if we select the 80% deferral option, then we retain all of our earnings up to 150 basis points above the currently authorized ROE. If we select the 90% deferral option, then we retain all of our earnings up to 100 basis points above the currently authorized ROE. We selected the 90% deferral option for the 2013-2014 PGA year. The ROE threshold is subject to adjustment annually based on movements in long-term interest rates. For the 2013 calendar year, the ROE threshold was 10.58%, and we were not subject to a refund. For 2014, the ROE threshold is currently 10.68%, and we do not expect to be subject to a refund.

SIP. The OPUC has approved specific accounting treatment and cost recovery for our SIP, which is an integrated safety program that consolidates the bare steel replacement program, the transmission pipeline integrity management program, and the distribution integrity management program related to pipeline safety rules adopted by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA). We record these costs as either capital expenditures or regulatory assets, accumulate the costs over each 12-month period, and recover the revenue requirement associated with these costs, subject to audit, through rate changes effective with the Oregon annual PGA. Our SIP costs are tracked into rates annually, with the first $4 million of capital costs subject to regulatory lag and annual rate-base recovery capped at $12 million. Extraordinary costs above the cap may also be approved with written consent of the OPUC staff and other interested parties and approval of the OPUC.

During 2013, the OPUC approved a temporary two-year extension, beginning in November 2012, of our capital expenditure tracking mechanism to recover capital costs related to SIP and authorized a total increase of $13.7 million in the cap during the extension period. Regulatory authority for SIP expires October 31, 2014. We filed a request to extend the program in the fourth quarter of 2014, with slightly modified program parameters. Specifically, we are seeking to track $8 million of SIP capital expenditures into rates annually, after having the first $1 million of SIP capital spend subject to regulatory lag. Regulatory authority for the bare steel program continues through December 2015. We plan to substantially complete our bare steel replacement by that time as we are precluded from tracking any additional bare steel replacement costs into rates after 2015.

ENVIRONMENTAL COST DEFERRAL. The OPUC authorized the deferral of environmental costs and insurance recoveries associated with certain named sites, plus the accrual of a carrying cost on amounts deferred. The recovery of deferred environmental costs, allocation of insurance proceeds, and application of an earnings test are incorporated in the SRRM open docket with the OPUC. Through a series of annual extensions, the authorized cost deferral and accrual of carrying costs was extended through January 2015. The WUTC also authorized the deferral of environmental costs, if any, that are appropriately allocated to Washington customers. See also Note 13 and "Regulatory Activities" above for information regarding SRRM.

PENSION DEFERRAL. In Oregon, we are allowed to defer annual pension expenses related to the qualified employee defined benefit pension plan. The amount deferred each period represents the difference between the annual accounting expense and the amount included and recovered in customer rates. Recovery of the deferred amounts is through the implementation of a balancing account, which includes the expectation of higher and lower pension expenses in future years. Our recovery of these deferred balances includes accrued interest. Future years’ deferrals will depend on changes in plan assets, projected benefit liabilities based on a number of key assumptions, and pension contributions. Pension expense deferrals were $1.1 million and $3.3 million for the three and nine months ended September 30, 2014, respectively.

CUSTOMER CREDITS FOR GAS STORAGE SHARING. In the second quarter of 2014, the Company received regulatory approval to refund an interstate storage credit of $11.4 million to its Oregon utility customers in their June bills. These customer credits are part of our regulatory incentive sharing mechanism related to non-utility Mist storage and asset management services. The OPUC approved an $8.8 million interstate storage credit to Oregon customers in June of 2013. The Washington portion of these credits is included with the Washington PGA.

For a discussion of other rate mechanisms, see Part II, Item 7, “Results of Operations—Regulatory Matters—Rate Mechanisms” in our 2013 Form 10-K.

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RESULTS OF OPERATIONS

Business Segments - Local Gas Distribution Utility Operations

Utility margin results are primarily affected by customer growth, revenues from rate-base additions, and, to a certain extent, changes in delivered volumes due to weather and customers’ gas usage patterns because a significant portion of our utility margin is derived from natural gas sales to residential and commercial customers. In Oregon, we have a conservation tariff (also called the decoupling mechanism), which adjusts utility margin up or down each month through a deferred regulatory accounting adjustment designed to offset changes resulting from increases or decreases in average use by residential and commercial customers. We also have a weather normalization tariff in Oregon, which adjusts customer bills up or down to offset changes in utility margin resulting from above- or below-average temperatures during the winter heating season. Both mechanisms are designed to reduce the volatility of customer bills and our utility’s earnings. See “Results of Operations—Regulatory Matters—Rate Mechanisms” in our 2013 Form 10-K for more information on our decoupling and weather normalization mechanisms.

Utility segment highlights include:



	Three Months Ended September 30,						Nine Months Ended September 30,				QTR Change			YTD Change
In thousands, except per share data	2014			2013			2014		2013		QTR Change			YTD Change
Utility net income (loss)	$	(8,808	)	$	(9,605	)	$	29,416	$	27,083	$	797		$	2,333
EPS - utility segment	$	(0.32	)	$	(0.36	)	$	1.08	$	1.00	$	0.04		$	0.08
Gas sold and delivered (therms)	152,329			159,133			766,799		771,420		(6,804		)	(4,621		)
Utility margin⁽¹⁾	$	50,134		$	47,050		$	250,223	$	239,151	$	3,084		$	11,072

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

THREE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The primary factors contributing to the decrease in net loss were as follows:


•	a $3.1 million increase in utility margin primarily due to an increase in residential and commercial customer growth, industrial margins, and added rate-base returns on certain investments, including gas reserves; partially offset by


•	a $1.2 million increase in depreciation expense due to additional capital expenditures;


•	a $1.0 million decrease in other income and expense, net primarily due to lower interest income on regulatory deferred account balances; and


•	a $0.4 million increase in operations and maintenance expense.

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The primary factors contributing to the increase in net income were as follows:


•	an $11.1 million increase in utility margin primarily due to:


◦	a $13.0 million increase from customer growth in residential and commercial customers, industrial margins, and added rate-base returns on certain investments, including gas reserves; partially offset by


◦	a $2.6 million increase in loss from gas cost incentive sharing resulting from actual gas prices and volumes that were higher than those estimated in the PGA for the current gas year as compared to the prior year.


•	Partially offsetting the above factors were:


◦	a $2.7 million increase in depreciation expense due to additional capital expenditures;


◦	a $1.8 million increase in operations and maintenance expense;


◦	a $1.1 million decrease in other income and expense, net primarily due to lower interest income on regulatory deferred account balances;


◦	a $0.7 million increase in interest expense due to an additional $50 million of utility debt issued in August 2013, partially offset by $60 million of debt retirements during the third quarter of 2014; and


◦	a $0.6 million increase in tax expense due to a higher Oregon state income tax rate.

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



	Three months ended						Nine months ended
In thousands, except degree day and customer data	September 30,						September 30,						Favorable/(Unfavorable)
	2014			2013			2014			2013			QTR			YTD

Utility volumes (therms):
Residential and commercial sales	49,843			54,052			420,532			426,029			(4,209		)	(5,497		)
Industrial sales and transportation	102,486			105,081			346,267			345,391			(2,595		)	876
Total utility volumes sold and delivered	152,329			159,133			766,799			771,420			(6,804		)	(4,621		)
Utility operating revenues:
Residential and commercial sales	$	68,369		$	67,584		$	451,557		$	434,105		$	785		$	17,452
Industrial sales and transportation	15,588			14,625			53,955			49,373			963			4,582
Other revenues	602			600			3,245			3,371			2			(126		)
Less: Revenue taxes	2,198			2,104			12,826			12,542			94			284
Total utility operating revenues	82,361			80,705			495,931			474,307			1,656			21,624
Less: Cost of gas	32,227			33,655			245,708			235,156			(1,428		)	10,552
Utility margin	$	50,134		$	47,050		$	250,223		$	239,151		$	3,084		$	11,072
Utility margin:⁽¹⁾
Residential and commercial sales	$	42,267		$	39,975		$	226,839		$	214,681		$	2,292		$	12,158
Industrial sales and transportation	6,962			6,502			22,153			20,747			460			1,406
Miscellaneous revenues	684			723			3,550			3,494			(39		)	56
Gain (loss) from gas cost incentive sharing	(84		)	92			(2,345		)	221			(176		)	(2,566		)
Other margin adjustments	305			(242		)	26			8			547			18
Utility margin	$	50,134		$	47,050		$	250,223		$	239,151		$	3,084		$	11,072
Degree days:
Average⁽²⁾	95			95			2,641			2,641			—			—
Actual degree days	18			86			2,438			2,581			(79		)%	(6		)%
Percent colder (warmer) than average weather⁽²⁾	(81		)%	(9		)%	(8		)%	(2		)%
	As of September 30,
Customers - end of period:	2014			2013			Change
Residential customers	629,627			621,625			8,002
Commercial customers	65,337			64,463			874
Industrial customers	938			930			8
Total number of customers	695,902			687,018			8,884


⁽¹⁾	Amounts reported as margin for each category of customer consist of operating revenues, which are net of revenue taxes, less cost of gas.


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

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Residential and Commercial Sales

Residential and commercial sales highlights include:



	Three Months Ended September 30,					Nine Months Ended September 30,					QTR Change			YTD Change
In thousands	2014		2013			2014		2013
Utility volumes (therms):
Residential sales	26,235		28,962			255,471		260,687			(2,727		)	(5,216		)
Commercial sales	23,608		25,090			165,061		165,342			(1,482		)	(281		)
Total volumes	49,843		54,052			420,532		426,029			(4,209		)	(5,497		)
Utility operating revenues:
Residential sales	$	41,907	$	41,751		$	294,119	$	285,661		$	156		$	8,458
Commercial sales	26,462		25,833			157,438		148,444			629			8,994
Total operating revenues	$	68,369	$	67,584		$	451,557	$	434,105		$	785		$	17,452
Utility margin:
Residential:
Sales	$	26,341	$	27,067		$	154,293	$	151,971		$	(726	)	$	2,322
Weather normalization adjustments	—		—			489		(2,731		)	—			3,220
Decoupling adjustments	1,738		(29		)	2,145		1,835			1,767			310
Total residential utility margin	28,079		27,038			156,927		151,075			1,041			5,852
Commercial:
Sales	12,180		11,863			64,487		61,679			317			2,808
Weather normalization adjustments	—		—			296		(1,228		)	—			1,524
Decoupling adjustments	2,008		1,074			5,129		3,155			934			1,974
Total commercial utility margin	14,188		12,937			69,912		63,606			1,251			6,306
Total utility margin	$	42,267	$	39,975		$	226,839	$	214,681		$	2,292		$	12,158

THREE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The primary factors contributing to changes in residential and commercial results were as follows:


•	sales volumes decreased 8% primarily due to warmer weather particularly in September, which delayed fall re-connections to gas service;


•	operating revenues increased $0.8 million primarily due to commercial and residential customer growth as well as higher commercial margin gains; and


•	utility margin increased 6% or $2.3 million primarily due to increases from commercial and residential customer growth, higher commercial margin gains, and added rate-base returns on our gas reserves and other investments. In addition, our decoupling mechanism adjusted margin for changes in average use by residential and commercial customers due to significantly warmer weather.

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The primary factors contributing to changes in residential and commercial sales results were as follows:


•	sales volumes decreased 1% primarily due to warmer weather, which was partially offset by commercial and residential customer growth and a record February cold weather event;


•	operating revenues increased 4% or $17.5 million primarily due to a 4% increase in average gas rates over last year, which was partially offset by the 1% decline in sales volume; and


•	utility margin increased 6% or $12.2 million primarily due to increases from commercial and residential customer growth, added loads under higher commercial rate schedules, and added rate-base returns from our gas reserve and other investments.

Industrial Sales and Transportation

Industrial customers may purchase transportation services from the utility, but may buy the gas commodity either from the utility or directly from a third-party gas marketer or supplier. Our gas commodity cost is primarily a pass-through cost to customers; therefore, our profit margins are not materially affected by an industrial customer's decision to purchase gas from us or from third parties. Industrial and large commercial customers may also select

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between firm and interruptible service levels, with firm services generally providing higher profit margins compared to interruptible services. To help manage gas supplies, our industrial tariffs are designed to provide some certainty regarding industrial customers' volumes by requiring an annual election of services, special charges for changes between elections, and in some cases, meeting a minimum or maximum volume requirement before changing options.

Industrial sales and transportation highlights include:



	Three Months Ended September 30,				Nine Months Ended September 30,				QTR Change			YTD Change
In thousands	2014		2013		2014		2013
Volumes (therms):
Industrial - firm sales	7,469		7,627		25,034		24,693		(158		)	341
Industrial - firm transportation	32,067		30,481		111,893		102,690		1,586			9,203
Industrial - interruptible sales	15,146		11,618		56,829		42,130		3,528			14,699
Industrial - interruptible transportation	47,804		55,355		152,511		175,878		(7,551		)	(23,367		)
Total volumes	102,486		105,081		346,267		345,391		(2,595		)	876
Utility margin:
Industrial - firm and interruptible sales	$	3,179	$	2,755	$	9,775	$	9,209	$	424		$	566
Industrial - firm and interruptible transportation	3,783		3,747		12,378		11,538		36			840
Total utility margin	$	6,962	$	6,502	$	22,153	$	20,747	$	460		$	1,406

THREE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. Total sales and transportation volumes decreased by 2% or 3 million therms, compared to last year, primarily reflecting decreased usage by large volume interruptible transportation customers on lower margin rate schedules but increased usage by lower volume firm deliveries to industrial customers on higher margin rate schedules. We saw utility margin increase 7% over last year due to customer growth under higher margin rate schedules.

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. Total sales and transportation volumes increased by 1 million therms compared to last year primarily reflecting lower usage by large volume interruptible transportation customers on lower margin rate schedules, but increased usage by lower volume firm deliveries to industrial customers on higher margin rate schedules. Total utility margin increased $1.4 million due to customer growth under higher margin rate schedules and other customer charges stemming from the extreme cold weather event in February 2014.

Cost of Gas

Cost of gas as reported by the utility includes gas purchases, gas drawn from storage inventory, gains and losses from commodity hedges, pipeline demand costs, seasonal demand cost balancing adjustments, regulatory gas cost deferrals, production from gas reserves, and company gas use. The OPUC and WUTC generally require natural gas commodity costs to be billed to customers at the actual cost incurred, or expected to be incurred, by the utility. Customer rates are set each year so that if cost estimates were met, we would not expect to earn a profit or incur a loss on the gas commodity purchased for customers; however, in Oregon we have an incentive sharing mechanism which has been described under “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment” above. In addition to the PGA incentive sharing mechanism, gains and losses from hedge contracts entered into after annual PGA rates are set for Oregon customers are also required to be shared and therefore may impact net income. Further, we also have a regulatory agreement whereby we earn a rate of return on our investment in gas reserves, which is also reflected in utility margin. See Part II, Item 7, “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities” and “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment” in our 2013 Form 10-K for additional information, as well as Note 12 in this report.

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Cost of gas highlights include:



	Three Months Ended September 30,					Nine Months Ended September 30,					QTR Change			YTD Change
In thousands, except as noted	2014			2013		2014			2013		QTR Change			YTD Change
Cost of gas	$	32,227		$	33,655	$	245,708		$	235,156	$	(1,428	)	$	10,552
Volumes sold (therms)⁽¹⁾	69,503			73,297		491,214			492,852		(3,794		)	(1,638		)
Average cost of gas (cents per therm)⁽¹⁾	$	0.46		$	0.46	$	0.50		$	0.48	$	—		0.02
Gain (loss) from gas cost incentive sharing	(84		)	92		(2,345		)	221		(176		)	(2,566		)

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

THREE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. Cost of gas decreased $1.4 million or 4% primarily due to a 5% decrease in sales volume due to warmer weather in the quarter, while the average cost of gas collected through rates remained stable.

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The primary factor contributing to the $10.6 million or 4% increase in cost of gas was a 4% increase in average cost of gas collected through rates.

During the first quarter of 2014, many parts of the United States experienced record cold weather for an extended period, while the Pacific Northwest temperatures were closer to normal averages. The extreme cold this past winter resulted in significant withdrawals of gas from storage and higher gas prices compared to last year. In early February 2014, the Pacific Northwest had extreme cold weather for a few days that resulted in a record sendout for our utility. Consequently, higher volumes of gas purchases and higher gas prices this year resulted in a year-to-date margin loss of $2.3 million under our gas cost incentive sharing mechanism, compared to a margin gain of $0.2 million for the same period in 2013. For a discussion of our gas cost incentive sharing mechanism, see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment” above.

Business Segments - Gas Storage

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

Gas storage segment highlights include:



In thousands, except per share data	Three Months Ended September 30,				Nine Months Ended September 30,				QTR Change			YTD Change
In thousands, except per share data	2014		2013		2014		2013		QTR Change			YTD Change
Gas storage net income	$	2	$	1,407	$	472	$	4,495	$	(1,405	)	$	(4,023	)
EPS - gas storage segment	—		0.05		0.02		0.17		(0.05		)	(0.15		)
Operating revenues	4,782		7,434		17,655		23,295		(2,652		)	(5,640		)
Operating expenses	3,856		3,878		13,661		12,157		(22		)	1,504

THREE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The primary factor contributing to lower gas storage income was a $2.7 million decrease in operating revenues. We re-contracted certain expiring firm storage capacity for the 2014-15 gas storage year at lower prices reflecting a historically low gas storage price market.

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The primary factors contributing to the decrease in gas storage income were:


•	a $5.6 million decrease in operating revenues, primarily reflecting certain re-contracted firm storage capacity at lower prices; and


•	a $1.5 million increase in operating expenses primarily due to higher repair and power costs at our Gill Ranch facility. See additional information regarding these expense trends below.

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Over the past few years, market prices for natural gas storage, particularly in California, were negatively affected by the abundant supply of natural gas, low volatility of natural gas prices, and surplus gas storage capacity. In addition, storage prices were further impacted by extreme cold weather this past winter, which resulted in a significant decline in storage levels, a rise in spot gas prices, and lower storage values due to a flatter forward price curve for the 2014-15 gas storage year. We re-contracted certain expiring storage capacity for the 2014-15 gas storage year, which began April 1, 2014, at substantially lower market prices than in previous years, which accounted for most of the decline in gas storage operating revenues.

We incurred an additional $1.7 million of repair and power costs at Gill Ranch during the first nine months of 2014 compared to 2013. The power cost increase is due to higher injections into storage during the second quarter to replenish low storage levels following higher withdrawals this past winter. The repair cost increase is for maintenance work at the Gill Ranch facility, which has now been in operation for three annual cycles. We are developing long-term repair and maintenance plans as well as evaluating potential capital improvements that may be needed to enhance the operations of the facility. See "Financial Condition—Liquidity and Capital Resources" below.

Our gas storage segment financial results have been negatively impacted in the short term by the decline in market conditions and higher than normal repair costs incurred this year. Despite these conditions, we continue to believe in the long-term need for gas storage in California. In the future, we anticipate a rebound in gas storage values and an increase in the demand for natural gas driven by a number of factors, including changes in electric generation triggered by California's renewable portfolio standards, increase in use of alternative fuels to meet carbon reduction targets, recovery of the California economy, growth of domestic industrial manufacturing, potential exports of liquefied natural gas from the West coast, and other favorable market conditions in and around California. These factors would likely result in higher summer/winter natural gas price spreads, gas price volatility, and gas storage values. Refer to Note 2 in our 2013 Form 10-K for more information regarding our accounting for impairment of long-lived assets.

Other

Other business activities of the Company primarily consist of NNG Financial's equity investment in KB Pipeline, an equity investment in PGH, and other miscellaneous non-utility investments. Contributions from our other businesses produced $0.01 per share of net income for the nine months ended September 30, 2014 compared to a small loss in 2013. See Note 4 and Note 11 for further details on our other business segment and our investment in PGH.

Consolidated Operations

Operations and Maintenance

Operations and maintenance highlights include:



	Three Months Ended September 30,				Nine Months Ended September 30,				QTR Change		YTD Change
In thousands	2014		2013		2014		2013		QTR Change		YTD Change
Operations and maintenance	$	32,968	$	32,636	$	103,085	$	99,610	$	332	$	3,475

THREE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The increase in operations and maintenance expense was primarily due to:


•	a $0.9 million increase in utility non-payroll expense, specifically higher professional service costs related to our ongoing growth initiatives; offset by


•	a $0.5 million net decrease from lower incentive compensation accruals due to lower earnings results partially offset by higher compensation costs under the new labor contract, which became effective June 1, 2014. See "Financial Condition—Contractual Obligations" for details on the new labor agreement.

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The increase in operations and maintenance expense was primarily due to:


•	a $2.5 million increase in higher system maintenance and safety program costs and professional service costs related to our ongoing growth initiatives;


•	a $1.7 million increase related to repair and power costs at Gill Ranch storage facility; and


•	a $1.1 million increase in bad debt expense at the utility due to lower comparable amounts in 2013 driven by a decrease in our allowance for uncollectible accounts in the first quarter of 2013 (see paragraph below for further discussion); offset by

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•	a $2.1 million decrease in employee incentive compensation accruals due to lower earnings results offset in part by higher compensation costs under the new labor agreement, which became effective June 1, 2014. See "Financial Condition—Contractual Obligations" for details on the new labor agreement.

Delinquent customer receivable balances have remained low for the several years despite challenging economic conditions during the recession. This sustained favorable trend resulted in a decrease to our allowance for uncollectible accounts in the first quarter of 2013, and bad debt expense continues to remain at historically low levels for the Company. The utility's annualized bad debt expense as a percent of revenues was 0.2% for the nine months ended September 30, 2014 and for several years has remained well below 0.5% of revenues every year since 2007.

In addition to fluctuations in operation and maintenance expense reported above, we have OPUC approval to defer certain utility pension costs in excess of what is currently recovered in customer rates. This pension cost deferral is recorded to a regulatory balancing account, which stabilizes the amount of operations and maintenance expense each year. For the three and nine months ended September 30, 2014, we deferred pension expenses totaling $1.1 million and $3.3 million, respectively. See Note 7 and “Regulatory Matters—Rate Mechanisms—Pension Deferral,” above for further explanation of the pension balancing account.

Other Operating Expenses

General taxes remained relatively flat for the three and nine months ended September 30, 2014 compared to the same periods in 2013, as expected. Depreciation expense increased 6% and 5% for the three and nine months ended September 30, 2014 compared to 2013, respectively, as a result of planned capital expenditures. See "Financial Condition—Cash Flows—Investing Activities" below for additional information.

Other Income and Expense, Net

Other income and expense, net highlights include:



	Three Months Ended September 30,				Nine Months Ended September 30,				QTR Change			YTD Change
In thousands	2014		2013		2014		2013		QTR Change			YTD Change
Other income and expense, net	$	407	$	1,300	$	2,052	$	3,270	$	(893	)	$	(1,218	)

THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The decreases in other income and expense, net for both periods primarily reflects lower interest income on net deferred regulatory balances as a result of insurance proceeds credited to regulatory balances for environmental costs. Our environmental deferred cost account subject to interest accruals changed from a net regulatory asset balance of $56 million at December 31, 2014 to a net regulatory liability balance of approximately $33 million at September 30, 2014.

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Interest Expense

Interest expense highlights include:



	Three Months Ended September 30,				Nine Months Ended September 30,				QTR Change			YTD Change
In thousands	2014		2013		2014		2013		QTR Change			YTD Change
Interest expense	$	10,805	$	11,347	$	34,024	$	33,543	$	(542	)	$	481

THREE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The decrease in interest expense was primarily due to the redemption of $10 million of utility FMBs in July 2014 and $50 million in September 2014, and the retirement of $20 million of debt pursuant to Gill Ranch's amended loan agreement in June 2014.

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The increase in interest expense was primarily due to an additional $50 million of utility debt issued in August 2013 with an interest rate of 3.542%, partially offset by the redemptions of debt in the second and third quarter of 2014 as noted above.

Income Tax Expense (Benefit)

Income tax expense (benefit) highlights include:



	Three Months Ended September 30,						Nine Months Ended September 30,				QTR Change			YTD Change
In thousands	2014			2013			2014		2013		QTR Change			YTD Change
Income tax expense (benefit)	$	(6,742	)	$	(5,601	)	$	21,023	$	21,697	$	(1,141	)	$	(674	)

THREE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The increase in income tax benefit was primarily due to the higher pre-tax loss and the result of estimating a lower annual effective tax rate.

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The decrease in income tax expense was due to lower pre-tax income and the result of estimating a lower estimated annual effective tax rate. Partially offsetting these items was a $0.6 million income tax charge related to a higher effective tax rate in Oregon, which required the revaluation of deferred tax balances in the first quarter of 2014.

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FINANCIAL CONDITION

Capital Structure

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

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



	September 30,				December 31,
	2014		2013		2013
Common stock equity	46.9	%	45.3	%	44.7	%
Long-term debt	38.8		42.2		40.5
Short-term debt, including any current maturities of long-term debt	14.3		12.5		14.8
Total	100.0	%	100.0	%	100.0	%

Liquidity and Capital Resources

At September 30, 2014, we had $8.3 million of cash and cash equivalents compared to $16.1 million at September 30, 2013. We also had $3.0 million and $4.0 million in restricted cash at Gill Ranch at September 30, 2014 and 2013, respectively, which is being held as collateral for outstanding long-term debt. See Note 6 regarding the amended Gill Ranch debt agreement. In order to maintain sufficient liquidity during periods when capital markets are volatile, we may elect to maintain higher cash balances and add to our short-term borrowing capacity. In addition, we may also pre-fund utility capital expenditures when long-term fixed rate environments are attractive. As a regulated entity, our issuance of equity securities and most forms of debt securities are subject to approval by the OPUC and WUTC. Our use of retained earnings is not subject to those same restrictions.

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

Based on our current debt ratings (see “Credit Ratings” below), we have been able to issue commercial paper and long-term debt at attractive rates and have not needed to borrow or issue letters of credit from our back-up credit facility. In the event that we are not able to issue new debt due to adverse market conditions or other reasons, we expect that our near-term liquidity needs can be met using internal cash flows or, for the utility segment, drawing on our committed credit facility. We also have a universal shelf registration filed with the SEC for the issuance of secured and unsecured debt or equity securities, subject to market conditions and certain regulatory approvals. As of September 30, 2014, we have Board authorization to issue up to $325 million of additional FMBs. We also currently have OPUC approval to issue up to $325 million of additional long-term debt for approved purposes.

In the event that our senior unsecured long-term debt credit ratings are downgraded, or our outstanding derivative position exceeds a certain credit threshold, our counterparties under derivative contracts could require us to post cash, a letter of credit, or another form of collateral, which could expose us to additional cash requirements and may trigger increases in short-term borrowings. Based on current financial swap and option contracts outstanding, we do not currently have collateral call exposure as the Company had unrealized gains of $1.7 million at September 30, 2014. See Note 12 and “Credit Ratings” below.

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Other recent developments that may have a significant impact on our liquidity and capital resources include pension contribution requirements, income tax benefits from bonus depreciation and other tax advantaged investments, environmental expenditures and insurance recoveries, and strategic growth initiatives. See "Cash Flows—Operating Activities" below.

Short-term liquidity for the gas storage segment is supported by cash balances, internal cash flow from operations, external financing, and funds from its parent company. Gill Ranch storage has limited operational history, with operations commencing in October 2010. The abundant supply of natural gas, low volatility of natural gas prices, and available gas storage capacity in California have recently resulted in lower storage market prices than we have seen in previous years. As a result, we are anticipating lower earnings and cash flows for Gill Ranch in the near term. The amount and timing of these cash flows from year to year are uncertain as the majority of Gill Ranch's storage contracts are short-term. We contracted for the 2014-15 gas year at prices lower than the prior year and have realized higher repairs and power costs this year, causing negative cash flows from operations in the third quarter and likely for the storage contract year that ends March 31, 2015. While we expect short-term storage prices to be challenging, we do not anticipate material changes in our ability to access sources of cash for short-term liquidity.

In November 2011, Gill Ranch issued $40 million of senior secured debt, with a fixed interest rate of 7.75% on $20 million and a variable interest rate on the remaining $20 million, with an original maturity date of November 30, 2016. Under the debt agreement, Gill Ranch is subject to certain covenants and restrictions. We amended the original agreement in April 2014 to retire the $20 million variable-rate outstanding debt during the second quarter of 2014 and suspend the EBITDA covenant requirement through March 31, 2015 with lower EBITDA hurdles thereafter. The amendment also fixes the debt service reserve at $3 million. Gill Ranch paid $20 million of debt on June 6, 2014 using available cash and cash flows from operations, including cash from intercompany receivables. The remaining $20 million of outstanding debt is secured by all of the membership interests in Gill Ranch and is nonrecourse to NW Natural and other entities of the consolidated group.

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

Contractual Obligations

On May 22, 2014, our union employees, who are members of the Office and Professional Employees International Union (OPEIU), Local No. 11, ratified a new labor agreement (Joint Accord) that expires on November 30, 2019. The Joint Accord includes the following items: an average annualized compensation increase of 4% effective June 1, 2014, which includes a 7.9% wage increase to better reflect current market competitive wages, offset by a reduction in bonus pay opportunities for union employees; and a scheduled 3% wage increase effective December 1 each year thereafter, beginning in 2015 with the potential for up to an additional 3% per year based on wage inflation at or above 4%. The Joint Accord also maintains competitive health benefits, including a 15% to 20% premium cost sharing by employees, job flexibility, and other flexibility provisions for the Company.

Short-Term Debt

Our primary source of utility short-term liquidity is from internal cash flows and the sale of commercial paper. In addition to issuing commercial paper to meet working capital requirements, including seasonal requirements to finance gas purchases and accounts receivable, short-term debt may also be used to temporarily fund utility capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by one or more unsecured revolving credit facilities. See “Credit Agreements” below. At September 30, 2014 and 2013, our utility had commercial paper outstanding of $190.0 million and $141.3 million, respectively. The effective interest rate on the utility’s commercial paper outstanding at both September 30, 2014 and 2013 was 0.3%.

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Credit Agreements

We have a multi-year credit agreement for unsecured revolving loans totaling $300 million with an original maturity date of December 20, 2017 and an available extension of commitments for two additional one-year periods, subject to lender approval. In December 2013, we extended our commitment to December 20, 2018. All lenders under the agreement are major financial institutions with investment grade credit ratings and loan commitments to NW Natural as of September 30, 2014 as follows:



In millions
Lender rating, by category	Loan Commitment
AA/Aa	$	234
A/A1	66
BBB/Baa	—
Total	$	300

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

Our credit agreement allows us to request increases in the total commitment amount, up to a maximum of $450 million. The agreement also permits the issuance of letters of credit in an aggregate amount of up to $200 million. Any principal and unpaid interest amounts owed on borrowings under the credit agreements is due and payable on or before the maturity date. There were no outstanding balances under this credit agreement at September 30, 2014 or 2013. The credit agreement requires us to maintain a consolidated indebtedness to total capitalization ratio of 70% or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at September 30, 2014 and 2013, with consolidated indebtedness to total capitalization ratios of 53.1% and 54.7%, respectively.

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

Credit Ratings

Our credit ratings are a factor of our liquidity, potentially affecting our access to capital markets including the commercial paper market. Our debt credit ratings also have an impact on the cost of funds and the need to post collateral under derivative contracts. In February 2014, Moody's revised our ratings outlook from negative to stable. There were no other changes in our credit ratings. Our credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of or reference to these credit ratings is not a recommendation to buy, sell, or hold NW Natural securities. Each rating should be evaluated independently of any other rating.

Maturity and Redemption of Long-Term Debt

In June 2014 we retired $20 million of variable interest rate debt issued by Gill Ranch with a coupon rate of 7.00%. We redeemed $50 million of FMBs with a coupon rate of 3.95% in July 2014 and $10 million in September 2014 with a coupon rate of 8.26%. See "Liquidity and Capital Resources" above for further discussion. Over the next 12 months, $40 million of FMBs with a coupon rate of 4.70% and maturity in June 2015 are expected to be redeemed.

See Part II, Item 7, "Financial Condition—Contractual Obligations” in our 2013 Form 10-K for long-term debt maturing over the next five years.

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Cash Flows

Operating Activities

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

Operating activity highlights include:



	Nine Months Ended September 30,
In thousands	2014		2013		Change
Cash provided by operating activities	$	214,864	$	157,402	$	57,462

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The significant factors contributing to the increase in operating cash flow were as follows:


•	an increase of $100.3 million in deferred environmental recoveries reflecting insurance settlements totaling $102 million;


•	a decrease of $18.0 million from changes in deferred gas costs balances, which reflected higher actual gas prices than prices embedded in the PGA for the 2013-2014 gas year;


•	a decrease of $11.3 million from changes in deferred tax liabilities due to the tax effect of deferred environmental recoveries received in 2014 and the absence of bonus depreciation in the current year; and


•	a net decrease of $2.0 million from changes in working capital including accounts receivable, inventory, and prepaid assets.

The non-cash pension expense recognized on the income statement for the nine months ended September 30, 2014 was $3.8 million, compared to $4.3 million for the same period in 2013. Although we expect gross non-cash pension expense to increase in the coming years, these increases will be mitigated by our balancing account in Oregon; and therefore, net non-cash pension expenses are expected to remain relatively flat in the coming years.

During the nine months ended September 30, 2014, we contributed $10.5 million to our utility's qualified defined benefit pension plan, compared to $8.9 million for the same period in 2013. We expect contribution amounts will be less in the next ten years than previously anticipated due to the new federal funding requirements under MAP-21 and HATFA. Specifically as a result of HATFA, we do not expect to make further contributions in 2014 and also anticipate a reduction in contributions of over $55 million in the next ten years. The amount and timing of future contributions will depend to a certain extent on market interest rates, investment returns on the plan's assets, and future federal funding requirements.

Also significantly affecting cash flows over the past few years has been income tax legislation, including the American Taxpayer Relief Act of 2012 (2012 Act), which extended 50% bonus depreciation through 2013 for modified accelerated cost recovery system property with a recovery period of 20 years or less. These and other tax benefits resulted in net operating tax losses (NOLs) during 2012 and 2013, which are carried forward and available to offset regular taxable income in 2014. As of September 30, 2014, we had an estimated federal income tax receivable balance of $6.6 million. Oregon conformed to federal bonus depreciation beginning in 2011, resulting in state NOL carry-forwards as well. We anticipate fully using the NOL carry-forwards in future years prior to expiration. The NOLs would otherwise expire in 20 years for federal and 15 years for Oregon.

Final tangible property regulations applicable to all taxpayers were issued by the Treasury Department on September 13, 2013. These regulations are generally effective for taxable years beginning on or after January 1, 2014. Procedural guidance related to the final regulations and unit-of-property guidance applicable to natural gas distribution networks is expected to be issued by the end of 2014. We will further evaluate the effect of the regulations after this guidance is issued, but believe our current method is materially consistent with the new regulations and do not expect these regulations to have a material effect on our financial statements.

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Investing Activities

Investing activity highlights include:



	Nine Months Ended September 30,
In thousands	2014			2013			Change
Total cash provided by (used in) investing activities	$	(107,204	)	$	(119,368	)	$	12,164
Capital expenditures	(86,552		)	(86,287		)	(265		)
Utility gas reserves	(21,734		)	(41,777		)	20,043
Proceeds from sale of assets	—			6,580			(6,580		)

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The decrease in cash used in investing activities was primarily due to lower investments in utility gas reserves, partially offset by proceeds received from the sale of property in 2013 that did not recur in 2014 and higher capital expenditures at the utility.

Under the amended gas reserves agreement, NW Natural ended its original drilling program with Encana, but increased the Company's assigned ownership interests in certain sections of the Jonah field. We continue to evaluate and make decisions whether or not to participate with Jonah Energy LLC in additional wells drilled in 2014. We currently expect to invest approximately $10 million in 2014 under the amended gas reserve agreement with a total expected investment, including amounts invested under the original agreement, of approximately $29 million for 2014. See Note 10 for additional information regarding the amended gas reserve agreement and Part II, Item 7, "Financial Condition—Cash Flows—Investing Activities” in the 2013 Form 10-K for additional information on other expected 2014 capital expenditures.

Financing Activities

Financing activity highlights include:



	Nine Months Ended September 30,
In thousands	2014			2013			Change
Total cash provided by (used in) financing activities	$	(108,856	)	$	(30,852	)	$	(78,004	)
Common stock issued, net	5,460			3,754			1,706
Long-term debt issued	—			50,000			(50,000		)
Long-term debt retired	(80,000		)	—			(80,000		)
Change in short-term debt	1,800			(48,950		)	50,750

NINE MONTHS ENDED SEPTEMBER 30, 2014 COMPARED TO SEPTEMBER 30, 2013. The increase in cash used in financing activities primarily reflected the use of proceeds from our insurance settlements of $102 million to redeem $60 million of long-term utility debt. In addition, Gill Ranch retired $20 million of variable interest rate debt. Partially offsetting these changes was an increase in common stock issued related to stock option exercises.

Ratios of Earnings to Fixed Charges

For the nine and 12 months ended September 30, 2014 and the 12 months ended December 31, 2013, our ratios of earnings to fixed charges computed using the Securities and Exchange Commission method were 2.43, 3.09, and 3.16, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, with fixed charges consisting of interest on all indebtedness, the amortization of debt discount or premium and expense, and the estimated interest portion of rentals charged to income. See Exhibit 12 for the detailed ratio calculation.

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Contingent Liabilities

Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies. See Part II, Item 7, “Application of Critical Accounting Policies and Estimates” in our 2013 Form 10-K. At September 30, 2014, we had a regulatory asset of $51.9 million for deferred environmental costs, which includes $91.2 million for additional costs expected to be paid in the future and $20.1 million of capitalized accrued interest. Additionally, in 2014, a settlement was reached in our environmental insurance recovery litigation, and NW Natural received $102 million for a cumulative total of approximately $150 million. The regulatory asset for deferred environmental costs is calculated net of insurance reimbursements. If it is determined that future customer rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is made. For further discussion of contingent liabilities, see Note 13 and see also "Regulatory Matters—Rate Mechanisms—Environmental Costs".

APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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


•	regulatory cost recovery and amortizations;


•	revenue recognition;


•	derivative instruments and hedging activities;


•	pensions and postretirement benefits;


•	income taxes; and


•	environmental contingencies.

There have been no material changes to the information provided in the 2013 Form 10-K with respect to the application of critical accounting policies and estimates (see Part II, Item 7, “Application of Critical Accounting Policies and Estimates,” in the 2013 Form 10-K).

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including commodity supply risk, commodity price and storage value risk, interest rate risk, foreign currency risk, credit risk, and weather risk. We monitor and manage these financial exposures as an integral part of our overall risk management program. No material changes have occurred related to our disclosures about market risk for the nine month period ending September 30, 2014. See Part II, Item 1A, “Risk Factors” in this report and Part II, Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” in the 2013 Form 10-K for details regarding these risks.

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

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

(b) Changes in Internal Control Over Financial Reporting

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

There have been no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. The statements contained in Exhibit 31.1 and Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this Item 4(b).

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Other than the proceedings disclosed in Note 13 and those proceedings disclosed and incorporated by reference in Part I, Item 3, “Legal Proceedings” in our 2013 Form 10-K, we have only routine nonmaterial litigation that occurs in the ordinary course of our business.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors discussed in Part I, Item 1A, "Risk Factors” in our 2013 Form 10-K. In addition to the other information set forth in this report, you should carefully consider those risk factors, which could materially affect our business, financial condition or results of operations.

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

The following table provides information about purchases of our equity securities that are registered pursuant to Section 12 of the Securities Exchange Act of 1934 during the quarter ended September 30, 2014:

ISSUER PURCHASES OF EQUITY SECURITIES



Period	(a) Total Number of Shares Purchased ⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ⁽²⁾	(d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs ⁽²⁾
Balance forward				2,124,528	$	16,732,648
07/01/14 - 07/31/14	—	$	—	—	—
08/01/14 - 08/31/14	1,793	44.89		—	—
09/01/14 - 09/30/14	—	—		—	—
Total	1,793	$	44.89	2,124,528	$	16,732,648

⁽¹⁾ During the quarter ended September 30, 2014, 1,793 shares of our common stock were purchased on the open market to meet the requirements of our share-based programs. During the quarter ended September 30, 2014, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated SOP.

⁽²⁾ We have a common stock share repurchase program under which we purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 31, 2015 to repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million. During the quarter ended September 30, 2014, no shares of our common stock were purchased pursuant to this program. Since the program’s inception in 2000, we have repurchased approximately 2.1 million shares of common stock at a total cost of approximately $83.3 million.

ITEM 6. EXHIBITS

See Exhibit Index attached hereto.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

NORTHWEST NATURAL GAS COMPANY

(Registrant)



Dated:	November 4, 2014
		/s/ Brody J. Wilson
		Brody J. Wilson
		Principal Accounting Officer
		Controller

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NORTHWEST NATURAL GAS COMPANY

Exhibit Index to Quarterly Report on Form 10-Q

For the Quarter Ended September 30, 2014



Exhibit Number	Document
12	Statement Re: Computation of Ratios of Earnings to Fixed Charges.

31.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101	The following materials from Northwest Natural Gas Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, formatted in Extensible Business Reporting Language (XBRL): (i) Consolidated Statements of Income; (ii) Consolidated Balance Sheets; (iii) Consolidated Statements of Cash Flows; and (iv) Related notes.