NORTHWEST NATURAL GAS CO - FORM 10-Q

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EX-12 - EXHIBIT 12 FIXED CHARGES - NORTHWEST NATURAL GAS CO	nwn-2014x630x10qxexhibit12.htm
EX-31.1 - EXHIBIT 31.1 CEO CERTIFICATION - NORTHWEST NATURAL GAS CO	nwn-2014x630x10qxexhibit311.htm
EX-32.1 - EXHIBIT 32.1 CEO AND CFO CERTIFICATION - NORTHWEST NATURAL GAS CO	nwn-2014x630x10qxexhibit321.htm
EXCEL - IDEA: XBRL DOCUMENT - NORTHWEST NATURAL GAS CO	Financial_Report.xls
EX-31.2 - EXHIBIT 31.2 CFO CERTIFICATION - NORTHWEST NATURAL GAS CO	nwn-2014x630x10qxexhibit312.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 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. (Check one):

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 July 25, 2014, 27,179,992 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

NORTHWEST NATURAL GAS COMPANY

For the Quarterly Period Ended June 30, 2014

TABLE OF CONTENTS



		Page

PART 1.	FINANCIAL INFORMATION

	Forward-Looking Statements	1

Item 1.	Unaudited Consolidated Financial Statements:

	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2014 and 2013	2

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

	Consolidated Statements of Cash Flows for the six months ended June 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	39

Item 4.	Controls and Procedures	39

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	40

Item 1A.	Risk Factors	40

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40

Item 6.	Exhibits	40

	Signature	41

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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				Six Months Ended
	June 30,				June 30,
In thousands, except per share data	2014		2013		2014		2013

Operating revenues	$	133,169	$	131,714	$	426,555	$	409,575

Operating expenses:
Cost of gas	58,280		59,142		213,481		201,501
Operations and maintenance	34,731		33,217		70,117		66,974
General taxes	7,183		7,342		15,365		16,074
Depreciation and amortization	19,709		18,930		39,298		37,737
Total operating expenses	119,903		118,631		338,261		322,286
Income from operations	13,266		13,083		88,294		87,289
Other income and expense, net	262		1,450		1,645		1,970
Interest expense, net	11,677		11,069		23,219		22,196
Income before income taxes	1,851		3,464		66,720		67,063
Income tax expense	780		1,338		27,765		27,298
Net income	1,071		2,126		38,955		39,765
Other comprehensive income:
Amortization of non-qualified employee benefit plan liability, net of taxes of $108 and $151 for the three months and $216 and $302 for the six months ended June 30, 2014 and 2013, respectively	166		232		331		465
Comprehensive income	$	1,237	$	2,358	$	39,286	$	40,230
Average common shares outstanding:
Basic	27,139		26,958		27,116		26,943
Diluted	27,182		26,999		27,158		26,991
Earnings per share of common stock:
Basic	$	0.04	$	0.08	$	1.44	$	1.48
Diluted	0.04		0.08		1.43		1.47
Dividends declared per share of common stock	0.460		0.455		0.920		0.910

See Notes to Unaudited Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

Assets:
Current assets:
Cash and cash equivalents	$	17,240		$	12,214		$	9,471
Accounts receivable	38,621			39,061			81,889
Accrued unbilled revenue	14,592			14,692			61,527
Allowance for uncollectible accounts	(1,404		)	(1,189		)	(1,656		)
Regulatory assets	38,265			25,952			22,635
Derivative instruments	11,191			623			5,311
Inventories	60,808			62,412			60,669
Gas reserves	20,373			15,324			20,646
Income taxes receivable	—			1,297			3,534
Deferred tax assets	4,915			—			45,241
Other current assets	14,518			8,781			21,181
Total current assets	219,119			179,167			330,448
Non-current assets:
Property, plant, and equipment	2,965,226			2,833,083			2,918,739
Less: Accumulated depreciation	879,296			833,851			855,865
Total property, plant, and equipment, net	2,085,930			1,999,232			2,062,874
Gas reserves	130,280			113,762			121,998
Regulatory assets	267,248			393,652			369,603
Derivative instruments	1,202			1,054			1,880
Other investments	67,689			67,410			67,851
Restricted cash	3,000			4,000			4,000
Other non-current assets	12,646			14,312			12,257
Total non-current assets	2,567,995			2,593,422			2,640,463
Total assets	$	2,787,114		$	2,772,589		$	2,970,911

See Notes to Unaudited Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

Liabilities and equity:
Current liabilities:
Short-term debt	$	74,200		$	136,000		$	188,200
Current maturities of long-term debt	100,000			—			60,000
Accounts payable	68,973			63,466			96,126
Taxes accrued	15,769			6,798			10,856
Interest accrued	7,053			6,404			7,103
Regulatory liabilities	26,742			16,644			28,335
Derivative instruments	1,490			9,392			1,891
Other current liabilities	34,507			34,446			40,280
Total current liabilities	328,734			273,150			432,791
Long-term debt	621,700			691,700			681,700
Deferred credits and other non-current liabilities:
Deferred tax liabilities	489,892			469,964			532,036
Regulatory liabilities	309,327			294,202			303,485
Pension and other postretirement benefit liabilities	145,861			214,125			149,354
Derivative instruments	191			1,754			615
Other non-current liabilities	120,423			79,145			119,058
Total deferred credits and other non-current liabilities	1,065,694			1,059,190			1,104,548
Commitments and contingencies (see Note 13)	—			—			—
Equity:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 27,147, 26,972, and 27,075 at June 30, 2014 and 2013 and December 31, 2013, respectively	369,315			359,772			364,549
Retained earnings	407,698			397,603			393,681
Accumulated other comprehensive loss	(6,027		)	(8,826		)	(6,358		)
Total equity	770,986			748,549			751,872
Total liabilities and equity	$	2,787,114		$	2,772,589		$	2,970,911

See Notes to Unaudited Consolidated Financial Statements.

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

	Six Months Ended
	June 30,
In thousands	2014			2013

Operating activities:
Net income	$	38,955		$	39,765
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	39,298			37,737
Regulatory amortization of gas reserves	8,680			4,970
Deferred tax liabilities, net	989			28,401
Non-cash expenses related to qualified defined benefit pension plans	2,540			2,773
Contributions to qualified defined benefit pension plans	(6,000		)	(4,200		)
Deferred environmental recoveries, net of (expenditures)	92,104			(2,989		)
Other	1,010			(1,567		)
Changes in assets and liabilities:
Receivables	89,951			63,102
Inventories	(139		)	5,190
Taxes accrued	8,447			(1,535		)
Accounts payable	(24,472		)	(22,155		)
Interest accrued	(50		)	451
Deferred gas costs	(18,812		)	(648		)
Other, net	744			10,847
Cash provided by operating activities	233,245			160,142
Investing activities:
Capital expenditures	(52,489		)	(55,055		)
Utility gas reserves	(18,632		)	(34,397		)
Proceeds from sale of assets	—			6,580
Restricted cash	1,000			—
Other	(1,043		)	1,743
Cash used in investing activities	(71,164		)	(81,129		)
Financing activities:
Common stock issued, net	3,733			2,355
Long-term debt retired	(20,000		)	—
Change in short-term debt	(114,000		)	(54,250		)
Cash dividend payments on common stock	(24,938		)	(24,509		)
Other	893			682
Cash used in financing activities	(154,312		)	(75,722		)
Increase (decrease) in cash and cash equivalents	7,769			3,291
Cash and cash equivalents, beginning of period	9,471			8,923
Cash and cash equivalents, end of period	$	17,240		$	12,214

Supplemental disclosure of cash flow information:
Interest paid	$	23,270		$	21,746
Income taxes paid	14,945			—

See Notes to Unaudited Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ORGANIZATION AND PRINCIPLES OF CONSOLIDATION

The accompanying consolidated financial statements represent the 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 the results for a full year.

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 six months ended June 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
	June 30,				December 31,
In thousands	2014		2013		2013
Current:
Unrealized loss on derivatives⁽¹⁾	$	1,466	$	9,392	$	1,891
Gas costs	19,268		—		4,286
Other⁽²⁾	17,531		16,560		16,458
Total current	$	38,265	$	25,952	$	22,635
Non-current:
Unrealized loss on derivatives⁽¹⁾	$	191	$	1,754	$	615
Pension balancing⁽³⁾	28,997		20,327		25,713
Deferred income taxes	49,007		53,065		51,814
Pension and other postretirement benefit liabilities⁽³⁾	120,942		191,312		125,855
Environmental costs⁽⁴⁾	52,117		120,224		148,389
Gas costs	3,768		5,322		1,105
Other⁽²⁾	12,226		1,648		16,112
Total non-current	$	267,248	$	393,652	$	369,603



	Regulatory Liabilities
	June 30,				December 31,
In thousands	2014		2013		2013
Current:
Gas costs	$	6,423	$	6,353	$	7,510
Unrealized gain on derivatives⁽¹⁾	11,286		547		5,290
Other⁽²⁾	9,033		9,744		15,535
Total current	$	26,742	$	16,644	$	28,335
Non-current:
Gas costs	$	1,057	$	481	$	2,172
Unrealized gain on derivatives⁽¹⁾	1,202		1,054		1,880
Accrued asset removal costs	303,567		289,105		296,294
Other⁽²⁾	3,501		3,562		3,139
Total non-current	$	309,327	$	294,202	$	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 accounting for revenue recognition. 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; (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. Diluted earnings per share are computed in the same manner, except it uses the weighted-average number of common shares outstanding plus the effects of the assumed exercise of stock options, and 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				Six Months Ended
	June 30,				June 30,
In thousands, except per share data	2014		2013		2014		2013
Net income	$	1,071	$	2,126	$	38,955	$	39,765
Average common shares outstanding - basic	27,139		26,958		27,116		26,943
Additional shares for stock-based compensation plans outstanding	43		41		42		48
Average common shares outstanding - diluted	27,182		26,999		27,158		26,991
Earnings per share of common stock - basic	$	0.04	$	0.08	$	1.44	$	1.48
Earnings per share of common stock - diluted	$	0.04	$	0.08	$	1.43	$	1.47
Additional information:
Antidilutive shares excluded from net income per diluted common share calculation	39		43		28		28

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4. SEGMENT INFORMATION

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 also includes 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 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 pipeline project. See Note 4 in our 2013 Form 10-K for further discussion of our segments.

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



	Three Months Ended June 30,
In thousands	Utility		Gas Storage			Other		Total
2014
Operating revenues	$	128,075	$	5,038		$	56	$	133,169
Depreciation and amortization	18,087		1,622			—		19,709
Income from operations	13,735		(485		)	16		13,266
Net income (loss)	2,205		(1,157		)	23		1,071
Capital expenditures	26,726		175			—		26,901
2013
Operating revenues	$	123,943	$	7,715		$	56	$	131,714
Depreciation and amortization	17,311		1,619			—		18,930
Income from operations	9,437		3,625			21		13,083
Net income	657		1,452			17		2,126
Capital expenditures	32,134		247			—		32,381



	Six Months Ended June 30,
In thousands	Utility		Gas Storage		Other			Total
2014
Operating revenues	$	413,570	$	12,873	$	112		$	426,555
Depreciation and amortization	36,054		3,244		—			39,298
Income from operations	85,192		3,068		34			88,294
Net income	38,224		470		261			38,955
Capital expenditures	52,076		413		—			52,489
Total assets at June 30, 2014	2,487,771		282,939		16,404			2,787,114
2013
Operating revenues	$	393,602	$	15,861	$	112		$	409,575
Depreciation and amortization	34,499		3,238		—			37,737
Income from operations	79,665		7,582		42			87,289
Net income (loss)	36,688		3,088		(11		)	39,765
Capital expenditures	54,522		533		—			55,055
Total assets at June 30, 2013	2,469,320		287,341		15,928			2,772,589

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 less 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 commodity cost of sales like the utility and, therefore, use operating revenues and net income to assess performance.



	Three Months Ended June 30,				Six Months Ended June 30,
In thousands	2014		2013		2014		2013
Utility margin calculation:
Utility operating revenues	$	128,075	$	123,943	$	413,570	$	393,602
Less: Utility cost of gas	58,280		59,142		213,481		201,501
Utility margin	$	69,795	$	64,801	$	200,089	$	192,101

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 in 2012. 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 first quarter of 2014, 31,113 performance-based RSUs were granted under the LTIP with a weighted-average grant date fair value of $42.03 per share. As of June 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. The fair value of the RSU is equal to the closing market price of the Company's common stock on the grant date.

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Restated Stock Option Plan

As of June 30, 2014, there was $0.1 million of unrecognized compensation cost from grants of stock options issued in prior years, which is expected to be recognized in 2014. The Restated SOP was terminated for new option 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 six months ended June 30, 2014.

6. DEBT

Short-Term Debt

At June 30, 2014, our short-term debt consisted of commercial paper notes payable with a maximum maturity of 39 days, an average maturity of 28 days, and an outstanding balance of $74.2 million. The carrying cost of our commercial paper approximates fair value using Level 2 inputs due to the short-term nature of the notes. See Note 2 in 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 totaling $100 million, consisting of $50 million of first rate mortgage bonds (FMB) with a coupon rate of 3.95% and maturity in July 2014, $10 million of FMBs with a coupon rate of 8.26% and maturity in September 2014, and $40 million of 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 of $701.7 million, consisting of FMBs at June 30, 2014, with maturity dates ranging from 2014 through 2042, interest rates ranging from 3.176% to 9.05%, and a weighted-average coupon rate of 5.55%.

At June 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%. The debt is secured by all of the membership interests in Gill Ranch and is nonrecourse to NW Natural. Under Gill Ranch’s amended loan agreement with Prudential, $20 million of the variable-rate debt was retired in June 2014. As part of the amended agreement, the EBITDA covenant requirement is suspended through March 31, 2015 with lower EBITDA hurdles thereafter, and the debt service reserve requirement is fixed at $3 million.

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:



	June 30,				December 31,
In thousands	2014		2013		2013
Carrying amount	$	721,700	$	691,700	$	741,700
Estimated fair value	807,617		769,679		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 June 30,
							Other Postretirement
	Pension Benefits						Benefits
In thousands	2014			2013			2014			2013
Service cost	$	1,918		$	2,341		$	136		$	179
Interest cost	4,512			4,104			309			286
Expected return on plan assets	(4,886		)	(4,678		)	—			—
Amortization of net actuarial loss	2,580			4,421			46			169
Amortization of prior service costs	56			55			49			49
Net periodic benefit cost	4,180			6,243			540			683
Amount allocated to construction	(1,201		)	(1,801		)	(171		)	(211		)
Amount deferred to regulatory balancing account⁽¹⁾	(1,123		)	(2,271		)	—			—
Net amount charged to expense	$	1,856		$	2,171		$	369		$	472



	Six Months Ended June 30,
							Other Postretirement
	Pension Benefits						Benefits
In thousands	2014			2013			2014			2013
Service cost	$	3,836		$	4,682		$	271		$	358
Interest cost	9,024			8,207			619			572
Expected return on plan assets	(9,772		)	(9,356		)	—			—
Amortization of net actuarial loss	5,160			8,842			92			338
Amortization of prior service costs	112			111			98			98
Net periodic benefit cost	8,360			12,486			1,080			1,366
Amount allocated to construction	(2,402		)	(3,656		)	(341		)	(430		)
Amount deferred to regulatory balancing account⁽¹⁾	(2,224		)	(4,620		)	—			—
Net amount charged to expense	$	3,734		$	4,210		$	739		$	936

⁽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 June 30,						Six Months Ended June 30,
In thousands	2014			2013			2014			2013
Beginning balance	$	(6,193	)	$	(9,058	)	$	(6,358	)	$	(9,291	)
Amounts reclassified from AOCL:
Amortization of prior service costs	(2		)	(2		)	(4		)	(4		)
Amortization of actuarial losses	276			385			551			771
Total reclassifications before tax	274			383			547			767
Tax expense	(108		)	(151		)	(216		)	(302		)
Total reclassifications for the period	166			232			331			465
Ending balance	$	(6,027	)	$	(8,826	)	$	(6,027	)	$	(8,826	)

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Employer Contributions to Company-Sponsored Defined Benefit Pension Plan

For the six months ended June 30, 2014, we made cash contributions totaling $6.0 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. We expect to contribute up to $15 million to the pension plan during 2014.

Multiemployer Pension Plan

In addition to the Company-sponsored defined benefit pension plan described above, the Company also participated in a multiemployer pension plan for its utility’s union employees known as the Western States Office and Professional Employees International Union Pension Fund (plan's EIN is 94-6076144) prior to December 2013; the Company withdrew from this plan in December 2013. NW Natural's vested participants will be entitled to receive all benefits accrued through the date of the withdrawal. The Company 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 withdrawal liability was deferred to a regulatory account on the balance sheet, and we made our first quarterly payment in June 2014.

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 $1.9 million and $1.6 million for the six months ended June 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 June 30,						Six Months Ended June 30,
Dollars in thousands	2014			2013			2014			2013
Income tax at statutory rates (federal and state)	$	728		$	1,330		$	26,449		$	26,569
Increase (decrease):
Differences required to be flowed-through by regulatory commissions	61			52			1,494			1,564
Other, net	(9		)	(44		)	(178		)	(835		)
Income tax expense	$	780		$	1,338		$	27,765		$	27,298
Effective income tax rate	42.1		%	38.6		%	41.6		%	40.7		%

The change in income tax expense for the three and six months ended June 30, 2014, compared to the same periods in 2013, is primarily due to 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 tax year is subject to examination, and the 2013 and 2014 tax years are subject to review under the Compliance Assurance Process with the IRS.

9. PROPERTY, PLANT, AND EQUIPMENT

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



	June 30,				December 31,
In thousands	2014		2013		2013
Utility plant in service	$	2,624,774	$	2,468,853	$	2,585,901
Utility construction work in progress	36,798		61,283		28,855
Less: Accumulated depreciation	847,828		807,652		827,380
Utility plant, net	1,813,744		1,722,484		1,787,376
Non-utility plant in service	297,269		296,167		297,330
Non-utility construction work in progress	6,385		6,780		6,653
Less: Accumulated depreciation	31,468		26,199		28,485
Non-utility plant, net	272,186		276,748		275,498
Total property, plant, and equipment	$	2,085,930	$	1,999,232	$	2,062,874

Capital expenditures in accrued liabilities	$	9,826	$	7,374	$	10,456

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 net rate base investment, is part of NW Natural's annual Oregon PGA filing, which allows us to recover our costs through customer rates.

On March 28, 2014, we amended the original gas reserve agreements in order to facilitate Encana's proposed sale of its interest in the Jonah field to an affiliate of TPG Capital (TPG). 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. Our investment of $178 million under the original deal earns a rate of return and provides long-term gas price protection for our utility customers.

During the second quarter of 2014, we were notified by TPG's affiliate, 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. At this time, we have agreed to participate in selected wells to be drilled in 2014 and may have the opportunity to participate in additional wells in future years. We are seeking regulatory approval in Oregon for these additional investments and expect to make a formal application to the OPUC in the third quarter with the resulting proceeding resolved either in late 2014 or early 2015. In addition to seeking cost recovery for additional wells already drilled, we are also seeking approval of a general framework, including an annual prudence review, to determine whether we participate in the funding of future wells on a well-by-well basis.

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Gas reserves acted to hedge the cost of gas for approximately 8% and 6% of our utility's gas supplies for the six months ended June 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:



	June 30,				December 31,
In thousands	2014		2013		2013
Gas reserves, current	$	20,373	$	15,324	$	20,646
Gas reserves, non-current	157,535		126,215		140,573
Less: Accumulated amortization	27,255		12,453		18,575
Total gas reserves	150,653		129,086		142,644
Less: Deferred tax liabilities on gas reserves	34,828		39,963		42,117
Net investment in gas reserves	$	115,825	$	89,123	$	100,527

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. 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 both June 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 fair value. See Note 12 in the 2013 Form 10-K.

12. DERIVATIVE INSTRUMENTS

We enter into financial derivative contracts to meet 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.

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 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.

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Notional Amounts

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



	June 30,				December 31,
In thousands	2014		2013		2013
Natural gas (in therms):
Financial	297,925		359,135		389,225
Physical	241,150		322,675		552,500
Foreign exchange	$	10,844	$	17,171	$	15,002

Purchased Gas Adjustment

Derivatives entered into by the utility for the procurement or hedging of natural gas for future gas years and prior to our annual PGA filing receive regulatory deferred accounting treatment. Derivative contracts entered into after the annual PGA rate is set for the current gas contract year are subject to our PGA incentive sharing mechanism, 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 the current gas year we have 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 included 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, and these hedge prices were included in the PGA filing 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 June 30,
	2014						2013
In thousands	Natural gas commodity			Foreign currency			Natural gas commodity			Foreign currency
Benefit (expense) to cost of gas	$	(5,379	)	$	454		$	(16,139	)	$	(274	)
Less:
Amounts deferred to regulatory accounts on the balance sheet	5,223			(454		)	16,069			274
Total loss in pre-tax earnings	$	(156	)	$	—		$	(70	)	$	—



	Six months ended June 30,
	2014						2013
In thousands	Natural gas commodity			Foreign currency			Natural gas commodity			Foreign currency
Benefit (expense) to cost of gas	$	10,533		$	179		$	(8,956	)	$	(513	)
Less:
Amounts deferred to regulatory accounts on the balance sheet	(10,652		)	(179		)	9,032			513
Total gain (loss) in pre-tax earnings	$	(119	)	$	—		$	76		$	—

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.

We realized a net gain of $4.3 million and $12.8 million for the three and six months ended June 30, 2014, compared to net gain of $1.4 million and a net loss of $4.0 million for the three and six months ended June 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.

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Credit Risk Management of Financial Derivatives Instruments

No collateral was posted with or by our counterparties as of June 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 upon current financial derivative contracts outstanding, which reflect unrealized gains of $11.3 million at June 30, 2014, we 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 $11.5 million and a liability of $0.8 million as of June 30, 2014. As of June 30, 2013, our derivative position would have resulted in an asset of $0.2 million and a liability of $9.7 million.

We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of customers. See Note 13 in our 2013 Form 10-K.

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 techniques 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 June 30, 2014. As of June 30, 2014 and 2013 and December 31, 2013, the net fair value was an asset of $10.7 million, a liability of $9.5 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 six months ended June 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.

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 have an established schedule for the docket and expect a decision by the end of 2014.

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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. In February 2014, we settled with all defendant insurance companies in this litigation with the Company to receive additional payments aggregating approximately $102 million. As of June 30, 2014, we have 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
	June 30,				December 31,		June 30,				December 31,
In thousands	2014		2013		2013		2014		2013		2013
Portland Harbor site:
Gasco/Siltronic Sediments	$	799	$	427	$	1,278	$	38,535	$	38,058	$	37,954
Other Portland Harbor	1,317		1,729		1,766		3,080		2,598		3,478
Gasco Uplands site	7,152		11,354		11,010		39,553		8,230		39,508
Siltronic Uplands site	884		496		763		401		392		406
Central Service Center site	70		100		85		190		338		248
Front Street site	1,115		475		1,274		107		178		122
Oregon Steel Mills	—		—		—		179		179		179
Total	$	11,337	$	14,581	$	16,176	$	82,045	$	49,973	$	81,895

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



	June 30,				December 31,
In thousands	2014		2013		2013
Cash paid⁽¹⁾	$	108,783	$	83,936	$	98,817
Total regulatory asset deferral⁽²⁾	52,117		120,224		148,389

⁽¹⁾Includes $20.3 million reclassified to utility plant in 2013 associated with the water treatment station of which a portion was paid in 2012-2014.

⁽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 EPA listed Superfund site that is approximately 11 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands and 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

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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 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 EE/CA range 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. 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. This liability is not included in the range of costs provided in the draft FS for the Portland Harbor.

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 ODEQ Voluntary Clean-Up Program. It is not included in the range of remedial costs for the Portland Harbor site. 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 is 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 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 $19.0 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 costs to be recovered in rates 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, 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 June 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.

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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 a 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 six months ended June 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 six 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). Our equity investments, PGH 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 June 30,
In thousands, except per share data	2014			2013		Change
Consolidated net income	$	1,071		$	2,126	$	(1,055	)
Consolidated EPS	0.04			0.08		(0.04		)

Utility margin	$	69,795		$	64,801	$	4,994
Utility net income	2,205			657		1,548
Gas storage income (loss) from operations	(485		)	3,625		(4,110		)
Gas storage net income (loss)	(1,157		)	1,452		(2,609		)

THREE MONTHS ENDED JUNE 30, 2014 COMPARED TO JUNE 30, 2013. The key metrics and primary factors for the quarter were as follows:


•	consolidated net income decreased $1.1 million primarily due to an increase in utility margin and net income that was more than offset by losses from gas storage operations;


•	utility margin and net income increased $5.0 million and $1.5 million, respectively, primarily due to customer growth and rate-base returns on gas reserve and other investments; and


•	gas storage net income decreased $2.6 million and incurred a net loss of $1.2 million primarily due to lower revenues from historically low contract prices for the new gas storage year, which began on April 1, 2014, and higher operating expenses.

We continue to make progress on several key initiatives. Highlights for the quarter included:


•	the customer growth rate increased to 1.4% at June 30, 2014, compared to 1.0% at June 30, 2013;


•	the receipt of additional proceeds from environmental insurance settlements, bringing total amounts received to $102 million year-to-date in 2014 and approximately $150 million cumulatively; and


•	the amended gas reserves agreement was signed with Jonah Energy, LLC with additional capital expenditures expected in 2014. See Note 10 and "Financial Condition—Cash Flows—Investing Activities” for additional information.

ISSUES AND CHALLENGES

ECONOMY. The local, national, and global economies continue to show signs of improvement as evidenced by increased utility customer growth and business demand for natural gas. Our utility’s customer growth rate, on a trailing 12-month basis, increased from 1.0% at June 30, 2013 to 1.4% at June 30, 2014 as NW Natural neared the 700,000 total customer mark. The unemployment rate in the Portland metropolitan region remained below 7% during the second quarter of 2014, a decline of over 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 continues to improve, regional business projects move forward, and proposed legislation favoring lower carbon emissions 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 hedge gas prices, so we can effectively manage costs, reduce price volatility, and maintain a competitive advantage. Our utility’s annual Purchased Gas Adjustment (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.

In addition to the amount hedged for the current gas contract year, we were hedged at approximately 65% as of June 30, 2014 for the upcoming 2014-15 gas year and between 8% and 22% hedged for annual requirements for the following five gas years. Our hedge levels are subject to change based on actual load volumes, which depend, to a certain extent, on weather and economic conditions, and estimated gas reserve production. Also, our storage

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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 currently low and stable forward gas price curves provide opportunities to manage 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. Consequently, we re-contracted some expiring storage capacity for the 2014-15 gas storage year at lower prices due to the current market environment, which reflects historically low gas storage prices that negatively impacted our financial results. Increases in the demand for natural gas or decreases in supply can result in upward pressure on gas prices and gas price volatility, which could be expected to improve the market value for gas storage. Current storage prices remain very low relative to prior years due to the current flat forward price curve for the 2014-15 gas storage year. As a result, in the short-term we are focused on maintaining our facility, while being ready to capitalize on opportunities in the market 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 Public Utility Commission of Oregon (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 also recover some of our environmental costs from insurance policies and only seek recovery from customers for amounts not covered by insurance. Ultimate recovery of environmental costs from regulated utility rates will depend on our ability to effectively manage these costs and demonstrate that costs were prudently incurred, and the impact of the annual earnings test 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 June 30,				Six Months Ended June 30,				QTR Change			YTD Change
In thousands, except per share data	2014		2013		2014		2013		QTR Change			YTD Change
Consolidated operating revenues	$	133,169	$	131,714	$	426,555	$	409,575	$	1,455		$	16,980
Consolidated operating expenses	119,903		118,631		338,261		322,286		1,272			15,975
Consolidated net income	1,071		2,126		38,955		39,765		(1,055		)	(810		)
Consolidated EPS	0.04		0.08		1.43		1.47		(0.04		)	(0.04		)

THREE AND SIX MONTHS ENDED JUNE 30, 2014 COMPARED TO JUNE 30, 2013. The lower consolidated net income for both periods was due to a $2.6 million decrease in gas storage net income, which was partially offset by a $1.5 million increase in utility net income for both periods. Gas storage results were negatively impacted by lower prices for the new gas storage contracts that replaced expiring higher price contracts from a few years ago and higher operating expenses from additional repair and power costs. Meanwhile, the utility net income results improved with higher margin contributions for both the quarter and year-to-date periods, and the utility also had comparatively stable operations and maintenance expense for the quarter.

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Dividends

Dividend highlights include:



	Three Months Ended June 30,				Six Months Ended June 30,				QTD		YTD
Per common share	2014		2013		2014		2013		Change		Change
Dividends paid	$	0.460	$	0.455	$	0.920	$	0.910	$	0.005	$	0.010

The Board of Directors declared a quarterly dividend on our common stock of $0.46 per share, payable on August 15, 2014, to shareholders of record on July 31, 2014, reflecting an indicated annual dividend rate of $1.84 per share.

REGULATORY MATTERS

Regulation and Rates

UTILITY. Our utility business is subject to regulation by the OPUC, the Washington Utilities and Transportation Commission (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 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% was derived from operations regulated by CPUC.

Regulatory Activities

The following list provides the status of open regulatory dockets and other regulatory activities during the second quarter of 2014:

•

Site Remediation and Recovery Mechanism (SRRM) - A schedule to resolve this docket in 2014 was set earlier this year. The decision 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.


•	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.


•	Prepaid Pension Asset - A schedule was established to resolve this docket in the first half of 2015, which is expected to include a decision by the OPUC on rate-base treatment of pensions on a general basis, not for a specific utility company. The Company has requested that the prepaid pension asset on the balance sheet be included in rate base and allowed a return on the investment.

•

Integrated Resource Plan (IRP) - We expect to file our 2014 Oregon and Washington IRPs in August 2014. The IRP will include analysis of different growth scenarios and corresponding resource acquisition strategies in an effort to develop supply and demand resource requirements, consider uncertainties in the planning process and the need for flexibility to respond to changes, and establish a plan for providing reliable service at the least cost.

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•

Gas Reserves Amendment - We have agreed to participate in certain additional wells in the Jonah field under the amended gas reserves agreement with Jonah Energy, LLC. We are currently seeking regulatory treatment in Oregon for these additional wells and expect to make a formal application to the OPUC in the third quarter, with the resulting proceeding resolved either in late 2014 or early 2015. In addition to seeking cost recovery for wells already drilled under the amended agreement, we are also seeking approval of a general framework, including an annual prudence review, to determine whether we participate in the funding of future wells on a well-by-well basis.


•	PGA - We filed our preliminary PGA in August and plan to file our final PGA with the OPUC and WUTC during the third quarter of 2014 with rates effective November 1, 2014. Currently, gas costs are projected to increase slightly due to current prices across the nation as the industry refills storage, which is at lower levels after the past sustained cold winter, to prepare for the upcoming winter.

Rate Mechanisms

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

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. 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.

NORTHWEST NATURAL GAS CO - FORM 10-Q - August 5, 2014

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