SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

For the transition period from ___________ to____________

Commission file number 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

220 N.W. Second Avenue, Portland, Oregon 97209

(Address of principal executive offices) (Zip Code)

NORTHWEST NATURAL GAS COMPANY

FORWARD-LOOKING STATEMENTS

This report contains ~~“forward-looking statements”~~forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as ~~“anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects”, "predicts", "projects"~~anticipates, assumes, intends, plans, seeks, believes, estimates, expects, and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements regarding the following:

Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are neither statements of historical fact nor guarantees or assurances of future operational or financial performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements are discussed in our ~~2014~~2015 Annual Report on Form 10-K, Part I, Item 1A “Risk Factors” and Part II, Item 7 and Item 7A, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk,” and in Part I, Items 2 and 3, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk,” and Part II, Item 1A, “Risk Factors,” herein.

Any forward-looking statement made by us in this report speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement, whether as a result of new information, future developments or otherwise, except as may be required by law.

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ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

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

		Three Months Ended						Nine Months Ended					Three Months Ended
		September 30,						September 30,					March 31,
In thousands, except per share data		2015			2014			2015		2014			2016			2015

Operating revenues		$	93,128		$	87,199		$	493,073	$	513,754		$	255,529		$	261,665

Operating expenses:
Cost of gas		35,856			32,227			223,737		245,708			108,411			125,705
Operations and maintenance		32,031			32,968			121,458		103,085			38,939			54,116
Environmental remediation													5,029			—
General taxes		6,772			7,143			23,153		22,508			8,684			8,732
Depreciation and amortization		20,342			19,938			60,683		59,236			20,394			20,111
Total operating expenses		95,001			92,276			429,031		430,537			181,457			208,664
Income (loss) from operations		(1,873		)	(5,077		)	64,042		83,217
Other income and expense, net		746			407			6,930		2,052
Income from operations													74,072			53,001
Other income (expense), net													(2,309		)	5,049
Interest expense, net		10,111			10,805			31,030		34,024			9,736			10,481
Income (loss) before income taxes		(11,238		)	(15,475		)	39,942		51,245
Income tax expense (benefit)		(4,553		)	(6,742		)	15,944		21,023
Net income (loss)		(6,685		)	(8,733		)	23,998		30,222
Income before income taxes													62,027			47,569
Income tax expense													25,386			19,083
Net income													36,641			28,486
Other comprehensive income:
Amortization of non-qualified employee benefit plan liability, net of taxes of $217 and $108 for the three months ended and $650 and $324 for the nine months ended September 30, 2015 and 2014, respectively		332			166			995		497
Comprehensive income (loss)		$	(6,353	)	$	(8,567	)	$	24,993	$	30,719
Amortization of non-qualified employee benefit plan liability, net of taxes of $127 and $216 for the three months ended March 31, 2016 and 2015, respectively													194			332
Comprehensive income													$	36,835		$	28,818
Average common shares outstanding:
Basic		27,363			27,189			27,336		27,145			27,448			27,301
Diluted		27,363			27,189			27,399		27,195			27,560			27,369
Earnings (loss) per share of common stock:
Earnings per share of common stock:
Basic		$	(0.24	)	$	(0.32	)	$	0.88	$	1.11		$	1.33		$	1.04
Diluted		(0.24		)	(0.32		)	0.88		1.11			1.33			1.04
Dividends declared per share of common stock		0.465			0.460			1.395		1.380			0.4675			0.4650

See Notes to Unaudited Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)	NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)										NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

												March 31,			March 31,			December 31,
In thousands		September 30, 2015			September 30, 2014			December 31, 2014				2016			2015			2015

Assets:
Current assets:
Cash and cash equivalents		$	5,227		$	8,275		$	9,534			$	4,321		$	5,218		$	4,211
Accounts receivable		29,800			30,468			69,818				69,066			68,531			68,228
Accrued unbilled revenue		15,752			12,442			57,963				36,393			30,076			57,987
Allowance for uncollectible accounts		(308		)	(840		)	(969		)		(1,376		)	(1,363		)	(870		)
Regulatory assets		82,712			52,250			68,562				61,524			67,702			69,178
Derivative instruments		2,956			5,587			243				1,960			658			2,719
Inventories		80,974			86,600			77,832				60,581			69,289			70,868
Gas reserves		17,822			21,455			20,020				16,420			19,112			17,094
Income taxes receivable		—			7,639			1,000				—			2,000			7,900
Deferred tax assets		15,663			5,100			23,785				—			13,491			—
Other current assets		27,313			19,158			34,772				23,311			15,921			33,460
Total current assets		277,911			248,134			362,560				272,200			290,635			330,775
Non-current assets:
Property, plant, and equipment		3,072,998			2,990,662			2,992,560				3,115,854			3,017,754			3,089,380
Less: Accumulated depreciation		905,137			883,568			870,967				919,187			883,254			906,717
Total property, plant, and equipment, net		2,167,861			2,107,094			2,121,593				2,196,667			2,134,500			2,182,663
Gas reserves		117,784			131,745			129,280				111,145			125,187			114,552
Regulatory assets		333,953			263,321			368,908				351,390			348,421			370,711
Derivative instruments		299			602			—				452			117			27
Other investments		68,503			67,980			68,238				67,490			68,614			68,066
Restricted cash		4,500			3,000			3,000				—			3,000			—
Other non-current assets		7,554			11,648			11,366				2,689			3,638			2,616
Total non-current assets		2,700,454			2,585,390			2,702,385				2,729,833			2,683,477			2,738,635
Total assets		$	2,978,365		$	2,833,524		$	3,064,945			$	3,002,033		$	2,974,112		$	3,069,410

See Notes to Unaudited Consolidated Financial Statements

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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	March 31,			March 31,			December 31,
In thousands	2016			2015			2015

Liabilities and equity:
Current liabilities:
Short-term debt	$	164,900		$	156,200		$	270,035
Current maturities of long-term debt	24,980			39,994			24,973
Accounts payable	57,407			62,904			73,219
Taxes accrued	10,256			17,755			10,420
Interest accrued	9,671			10,427			5,873
Regulatory liabilities	35,596			24,263			29,927
Derivative instruments	17,313			23,242			22,092
Other current liabilities	42,100			35,950			41,148
Total current liabilities	362,223			370,735			477,687
Long-term debt	569,745			613,417			569,445
Deferred credits and other non-current liabilities:
Deferred tax liabilities	550,731			523,929			530,021
Regulatory liabilities	346,761			326,424			339,287
Pension and other postretirement benefit liabilities	221,291			235,516			223,105
Derivative instruments	1,237			1,117			3,447
Other non-current liabilities	143,090			118,059			145,446
Total deferred credits and other non-current liabilities	1,263,110			1,205,045			1,241,306
Commitments and contingencies (See Note 13)	—			—			—
Equity:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 27,493, 27,332, and 27,427 at March 31, 2016 and 2015 and December 31, 2015, respectively	385,232			376,656			383,144
Retained earnings	428,691			418,003			404,990
Accumulated other comprehensive loss	(6,968		)	(9,744		)	(7,162		)
Total equity	806,955			784,915			780,972
Total liabilities and equity	$	3,002,033		$	2,974,112		$	3,069,410

See Notes to Unaudited Consolidated Financial Statements

~~Table of Contents~~

NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS (UNAUDITED)

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

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

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

	Three Months Ended
	March 31,
In thousands	2016			2015

Operating activities:
Net income	$	36,641		$	28,486
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	20,394			20,111
Regulatory amortization of gas reserves	4,075			5,255
Deferred tax liabilities, net	23,353			5,918
Qualified defined benefit pension plan expense	1,311			1,509
Contributions to qualified defined benefit pension plans	(2,900		)	(2,630		)
Deferred environmental expenditures	(2,665		)	(3,315		)
Regulatory disallowance of prior environmental cost deferrals	3,273			15,000
Interest income on deferred environmental expenses	—			(5,322		)
Amortization of environmental remediation	5,029			—
Other	1,169			900
Changes in assets and liabilities:
Receivables, net	22,242			29,193
Inventories	10,115			8,543
Taxes accrued	7,729			6,724
Accounts payable	(14,537		)	(26,550		)
Interest accrued	3,798			4,348
Deferred gas costs	8,519			13,074
Other, net	18,592			17,005
Cash provided by operating activities	146,138			118,249
Investing activities:
Capital expenditures	(30,054		)	(27,135		)
Other	24			(1,811		)
Cash used in investing activities	(30,030		)	(28,946		)
Financing activities:
Common stock issued, net	1,999			700
Change in short-term debt	(105,135		)	(78,500		)
Cash dividend payments on common stock	(12,823		)	(12,688		)
Other	(39		)	(3,131		)
Cash used in financing activities	(115,998		)	(93,619		)
Increase (decrease) in cash and cash equivalents	110			(4,316		)
Cash and cash equivalents, beginning of period	4,211			9,534
Cash and cash equivalents, end of period	$	4,321		$	5,218

Supplemental disclosure of cash flow information:
Interest paid, net of capitalization	$	5,232		$	5,399
Income taxes paid, net of refunds	(7,900		)	—

See Notes to Unaudited Consolidated Financial Statements

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

Nine Months Ended
September 30,
In thousands 2015 2014

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

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

~~See Notes to Unaudited Consolidated Financial Statements~~

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NORTHWEST NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ORGANIZATION AND PRINCIPLES OF CONSOLIDATION

The accompanying consolidated financial statements represent the consolidated results of Northwest Natural Gas Company (NW Natural or the Company) and all companies we directly or indirectly control, either through majority ownership or otherwise. We have two core businesses: our regulated local gas distribution business, referred to as the utility segment, which serves residential, commercial, and industrial customers in Oregon and southwest Washington; and our gas storage businesses, referred to as the gas storage segment, which provides storage services for utilities, gas marketers, electric generators, and large industrial users from facilities located in Oregon and California. In addition, we have investments and other non-utility activities we aggregate and report as ~~other.~~other.

Our core utility business assets and operating activities are largely included in the parent company, NW Natural. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch), NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), and NW Natural Gas Reserves, LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method, which includes NWN Energy’s investment in Trail West Holdings, LLC (TWH) and NNG Financial's investment in Kelso-Beaver (KB) Pipeline. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated ~~unaudited~~ financial statements are presented after elimination of all intercompany balances and transactions, except for amounts required to be included under regulatory accounting standards to reflect the effect of such regulation. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage businesses and other non-utility investments and business activities.

Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments management considers necessary for fair presentation of the results for each period reported including normal recurring accruals. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our ~~2014~~2015 Annual Report on Form 10-K (~~2014~~(2015 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of full year results.

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

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2. SIGNIFICANT ACCOUNTING POLICIES

~~Significant~~Our significant accounting policies are described in Note 2 of the ~~2014~~2015 Form 10-K. There were no material changes to those accounting policies during the ~~nine~~three months ended ~~September 30, 2015~~.March 31, 2016. The following are current updates to certain critical accounting policy estimates and new accounting standards.

6Industry Regulation

~~Table of Contents~~

~~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~~liabilities pursuant to orders of the OPUC Public Utility Commission of Oregon (OPUC) or Washington Utilities and Transportation Committee (WUTC), which provide for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a rate of return or a carrying charge in certain cases.

Amounts deferred as regulatory assets and liabilities were as follows:


	Regulatory Assets						Regulatory Assets
	September 30,				December 31,		March 31,				December 31,
In thousands	2015		2014		2014		2016		2015		2015
Current:
Unrealized loss on derivatives⁽¹⁾	$	21,949	$	5,520	$	29,889	$	17,313	$	23,242	$	22,092
Gas costs	19,274		23,795		21,794		7,978		19,653		8,717
Environmental costs⁽²⁾	12,364		—		—		9,096		—		9,270
Decoupling⁽³⁾	19,391		11,847		2,219		13,235		11,696		18,775
Other⁽³⁾	9,734		11,088		14,660
Other⁽⁴⁾							13,902		13,111		10,324
Total current	$	82,712	$	52,250	$	68,562	$	61,524	$	67,702	$	69,178
Non-current:
Unrealized loss on derivatives⁽¹⁾	$	3,540	$	551	$	3,515	$	1,237	$	1,117	$	3,447
Pension balancing⁽⁴⁾⁽⁵⁾	41,193		30,682		32,541		46,247		35,374		43,748
Income taxes	44,767		49,007		47,427		40,106		44,767		43,049
Pension and other postretirement benefit liabilities	189,111		118,485		201,845		180,909		197,601		184,223
Environmental costs⁽²⁾	37,443		51,861		58,859		67,999		50,175		76,584
Gas costs	2,098		1,936		5,971		2,462		4,334		1,949
Other⁽³⁾	15,801		10,799		18,750
Decoupling⁽³⁾							2,641		4,370		6,349
Other⁽⁴⁾							9,789		10,683		11,362
Total non-current	$	333,953	$	263,321	$	368,908	$	351,390	$	348,421	$	370,711


	Regulatory Liabilities						Regulatory Liabilities
	September 30,				December 31,		March 31,				December 31,
In thousands	2015		2014		2014		2016		2015		2015
Current:
Gas costs	$	22,499	$	6,704	$	5,700	$	22,098	$	12,774	$	14,157
Unrealized gain on derivatives⁽¹⁾	2,939		5,320		240		1,960		436		2,659
Other⁽³⁾	8,689		11,328		13,165
Other⁽⁴⁾							11,538		11,053		13,111
Total current	$	34,127	$	23,352	$	19,105	$	35,596	$	24,263	$	29,927
Non-current:
Gas costs	$	6,357	$	410	$	2,507	$	9,221	$	4,729	$	8,869
Unrealized gain on derivatives⁽¹⁾	299		602		—		452		117		27
Accrued asset removal costs⁽⁵⁾⁽⁶⁾	324,467		307,815		311,238		331,000		315,946		327,047
Other⁽³⁾	3,367		3,673		3,460
Other⁽⁴⁾							6,088		5,632		3,344
Total non-current	$	334,490	$	312,500	$	317,205	$	346,761	$	326,424	$	339,287


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

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⁽²⁾

Environmental costs relate to specific sites approved for regulatory deferral by the ~~Public Utility Commission of Oregon (OPUC)~~OPUC and ~~Washington Utilities and Transportation Commission (WUTC).~~WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, ~~a carrying charge related to~~recovery of deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from Oregon customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The ~~current portion of environmental assets represents deferred costs~~amounts allocable to ~~be recovered in~~ Oregon ~~rates beginning November 1, 2015.~~are subject to an earnings test. See Note 13.


⁽³⁾	This deferral represents the margin adjustment resulting from differences between actual and expected volumes.


⁽⁴⁾	These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge.

⁽⁴⁾⁽⁵⁾

The deferral of certain pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower net periodic benefit costs in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of interest income recognized when amounts are collected in rates.

~~Table of Contents~~

periodic benefit costs in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of interest income recognized when amounts are collected in rates.


^{(5) (6)}	Estimated costs of removal on certain regulated properties are collected through rates. ~~See Note 2 of the 2014 Form 10-K.~~

~~Environmental Regulatory Accounting~~

~~On February 20, 2015~~We believe all costs incurred and deferred at March 31, 2016 are prudent. We annually review all regulatory assets and liabilities for recoverability and more often if circumstances warrant. If we should determine that all or a portion of these regulatory assets or liabilities no longer meet the ~~OPUC issued an Order addressing outstanding implementation items related~~criteria for continued application of regulatory accounting, then we would be required to write-off the ~~Site Remediation and Recovery Mechanism (SRRM). Under~~net unrecoverable balances in the Order, $15 million of $95 million in total environmental remediation expenses deferred through 2012 were disallowed. The OPUC found the $95 million to be prudent but disallowed this amount from rate recovery based on itsperiod such determination of how an earnings test should apply to years between 2003 and 2012, with adjustments for other factors the OPUC deemed relevant. We recognized the $15 million pre-tax disallowance, or $9.1 million after-tax charge, during the first quarter of 2015. The charge was recorded in operations and maintenance expense. As a result of the order, we recognized $5.3 million pre-tax of interest income related to the equity earnings on our deferred environmental expenses. See Note 13.is made.

New Accounting Standards

~~Recent Accounting Pronouncements~~

We consider the applicability and impact of all accounting standards updates (ASUs) issued by the Financial

Accounting Standards Board (FASB). Accounting standards updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial position or results of operations.

Recently Adopted Accounting Pronouncements

BENEFIT PLAN ACCOUNTING. On July 31, 2015, the FASB issued ASU 2015-12, ~~Plan~~"Plan Accounting: Defined Benefit Pension Plans, Defined Contribution Pension Plans, and Health and Welfare Benefit Plans." The ASU outlines a three part update. Only part two of the update ~~applies to the Company,~~is applicable for us, which simplifies the investment disclosure requirements for employee benefit plans by allowing certain disclosures at an aggregated level, reducing the number of ways assets must be grouped and analyzed, and no longer requiring investment strategy disclosures for certain investments. The new requirements ~~are~~were effective for ~~the Company~~us beginning January 1, 2016 ~~with early adoption permitted. We~~and will be ~~required to apply~~applied retrospectively in the ~~disclosure guidance retrospectively and do~~2016 Form 10-K, for all periods presented. This ASU will not ~~expect the ASU to~~ materially affect our financial statements and ~~disclosures.~~disclosures, but will change certain presentation and disclosure within our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.

FAIR VALUE MEASUREMENT. On May 1, 2015, the FASB issued ASU 2015-07, ~~Disclosures~~"Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or its Equivalent)." The ASU removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements ~~are~~were effective for ~~the Company~~us beginning January 1, 2016 ~~with retrospective application~~and will be applied retrospectively to all periods presented, ~~required and early adoption permitted. We do~~in our 2016 Form 10-K. This ASU will not ~~expect the ASU to~~ materially affect our financial statements and ~~disclosures.~~disclosures, but will change certain presentation and disclosure of the fair value of certain plan assets in our pension and other postretirement benefit plan disclosures in our 2016 Form 10-K, for all periods presented.

INTANGIBLES - GOODWILL AND OTHER - INTERNAL-USE SOFTWARE. On April 15, 2015 the FASB issued ASU 2015-05, ~~Customer’s~~"Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement." The ASU provides customers guidance on how to determine whether a cloud computing arrangement includes a software license. The new requirements ~~are~~were effective for ~~the Company~~us beginning January 1, 2016. ~~The ASU can be applied prospectively or retrospectively and early adoption is permitted.~~ We ~~intend to~~will apply the guidance prospectively as contracts arise and do not expect the ASU to materially affect our financial statements and disclosures.

DEBT ISSUANCE COSTS. On April 7, 2015, the FASB issued ASU 2015-03, ~~Simplifying~~"Simplifying the Presentation of Debt Issuance Costs," which requires the presentation of debt issuance costs in the balance sheet as a direct deduction from the associated debt liability. The new requirements ~~are~~were effective for ~~the Company~~us beginning January 1, 2016. The new guidance has been applied on a retrospective basis and is reflected in our consolidated balance sheets and Note 6.

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Recently Issued Accounting Pronouncements

STOCK BASED COMPENSATION. On March 30, 2016, the FASB issued ASU 2016-09, "Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting." The ASU changes how companies account for certain aspects of share-based payment awards to employees, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. The amendments in this standard are effective for us beginning January 1, 2017. Early adoption is permitted in any interim or annual period. We are currently assessing the effect of this standard and do not expect this standard to materially affect our financial statements and disclosures.

LEASES. On February 25, 2016, the FASB issued ASU 2016-02, "Leases," which revises the existing lease accounting guidance. This ASU prescribes new disclosure rules for leasing arrangements. The standard is effective for public companies beginning January 1, 2019, and early adoption is permitted. The new standard must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently assessing the effect of this standard on our financial statements and disclosures.

FINANCIAL INSTRUMENTS. On January 5, 2016, the FASB issued ASU 2016-01, "Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities." The ASU enhances the reporting model for financial instruments, which includes amendments to address aspects of recognition, measurement, presentation and disclosure. The new standard is effective for us beginning January 1, 2018. Upon adoption, we will be ~~applied~~required to make a cumulative-effect adjustment to the statement of financial position in the first quarter of 2018. Early adoption is permitted. We are currently assessing the effect of this standard on ~~a retrospective basis. We do not expect the ASU to materially affect~~ our financial statements and disclosures.

REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 ~~Revenue~~"Revenue From Contracts with Customers." The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts the entity is expected to be entitled to in exchange for those goods or services. The ~~model provides~~ASU also prescribes a five-step approach to revenue recognition: (1) identify the contract(s) with the customer; (2) identify the separate performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to separate performance obligations; and (5) recognize revenue when, or as, each performance

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obligation is satisfied. The new requirements prescribe either a full retrospective or simplified transition adoption method. On August 12, 2015, the FASB deferred the effective date by one year to January 1, 2018 for annual reporting periods beginning after December 15, 2017. The FASB also permitted early adoption of the standard, but not before the original effective date of January 1, 2017. We are currently assessing the effect of this standard on our financial statements and disclosures.

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3. EARNINGS PER SHARE

Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for each period presented. Diluted earnings per share are computed in the same manner, except it uses the weighted average number of common shares outstanding plus the effects of the assumed exercise of stock options and the payment of estimated stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Antidilutive stock ~~options~~awards are excluded from the calculation of diluted earnings per common share. Diluted earnings ~~(loss)~~ per share are calculated as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,				Three Months Ended March 31,
In thousands, except per share data	2015			2014			2015		2014		2016		2015
Net income (loss)	$	(6,685	)	$	(8,733	)	$	23,998	$	30,222
Net income											$	36,641	$	28,486
Average common shares outstanding - basic	27,363			27,189			27,336		27,145		27,448		27,301
Additional shares for stock-based compensation plans outstanding	—			—			63		50
Additional shares for stock-based compensation plans (See Note 5)											112		68
Average common shares outstanding - diluted	27,363			27,189			27,399		27,195		27,560		27,369
Earnings (loss) per share of common stock - basic	$	(0.24	)	$	(0.32	)	$	0.88	$	1.11
Earnings (loss) per share of common stock - diluted	$	(0.24	)	$	(0.32	)	$	0.88	$	1.11
Earnings per share of common stock - basic											$	1.33	$	1.04
Earnings per share of common stock - diluted											$	1.33	$	1.04
Additional information:
Antidilutive shares	91			80			19		24		22		28

4. SEGMENT INFORMATION

We primarily operate in two reportable business segments: local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which are aggregated and reported as other. We refer to our local gas distribution business as the utility, and our gas storage segment and other as non-utility. Our utility segment also includes the utility portion of our Mist underground storage facility in Oregon ~~(Mist)~~ and NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp. Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist, and all third-party asset management services. Other includes NNG Financial and NWN Energy's equity investment in TWH, which is pursuing development of a cross-Cascades transmission pipeline project. See Note 4 in the ~~2014~~2015 Form 10-K for further discussion of our segments.

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Inter-segment transactions ~~are insignificant.~~were insignificant for the periods presented. The following table presents summary financial information concerning the reportable segments:


	Three Months Ended September 30,										Three Months Ended March 31,
In thousands	Utility			Gas Storage		Other		Total			Utility		Gas Storage		Other		Total
2016
Operating revenues											$	250,104	$	5,369	$	56	$	255,529
Depreciation and amortization											18,760		1,634		—		20,394
Income from operations											72,295		1,726		51		74,072
Net income											35,852		736		53		36,641
Capital expenditures											29,177		877		—		30,054
Total assets at March 31, 2016											2,726,696		260,535		14,802		3,002,033
2015
Operating revenues	$	87,475		$	5,596	$	57	$	93,128		$	256,306	$	5,303	$	56	$	261,665
Depreciation and amortization	18,721			1,621		—		20,342			18,475		1,636		—		20,111
Income (loss) from operations	(4,088		)	2,204		11		(1,873		)
Net income (loss)	(7,529		)	799		45		(6,685		)
Income from operations											51,880		1,055		66		53,001
Net income											28,335		114		37		28,486
Capital expenditures	28,325			526		—		28,851			25,809		1,326		—		27,135
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
Total assets at March 31, 2015											2,688,304		270,905		14,903		2,974,112

Total assets at December 31, 2015											2,792,736		261,750		14,924		3,069,410

Nine Months Ended September 30,
In thousands Utility Gas Storage Other Total
2015
Operating revenues $ 476,672
$ 16,232
$ 169
$ 493,073
Depreciation and amortization 55,798
4,885
—
60,683
Income from operations 59,955
3,998
89
64,042
Net income 23,051
827
120
23,998
Capital expenditures 84,598
2,325
—
86,923
Total assets at September 30, 2015 2,693,953
269,289
15,123
2,978,365
2014
Operating revenues $ 495,931
$ 17,655
$ 168
$ 513,754
Depreciation and amortization 54,333
4,903
—
59,236
Income from operations 78,971
3,994
252
83,217
Net income 29,416
472
334
30,222
Capital expenditures 85,793
759
—
86,552
Total assets at September 30, 2014 2,539,834
277,689
16,001
2,833,524

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

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Utility margin is a financial measure consisting of utility operating revenues, which are reduced by revenue taxes, ~~and~~ the associated cost of ~~gas.~~gas, and environmental recovery revenues. The cost of gas purchased for utility customers is generally a pass-through cost in the amount of revenues billed to regulated utility customers. Environmental recovery revenues represent collections received from customers through our environmental recovery mechanism in Oregon. These collections are offset by the amortization of environmental liabilities, which is presented as environmental remediation expense in our operating expenses. By subtracting cost of gas and environmental remediation expense from utility operating revenues, utility margin provides a key metric used by our chief operating decision maker in assessing the performance of the utility segment. The gas storage ~~segment~~ and other segments emphasize growth in operating revenues as opposed to margin because they do not incur a product cost (i.e. cost of gas sold) like the utility and, therefore, use operating revenues and net income to assess performance.

The following table presents additional segment information concerning utility margin:

5. STOCK-BASED COMPENSATION

Our stock-based compensation plans are designed to promote stock ownership in NW Natural by employees and officers. These compensation plans include a Long-Term Incentive Plan (LTIP) ~~under which various types of equity awards may be granted.~~, an Employee Stock Purchase Plan (ESPP), and a Restated Stock Option Plan. For additional information on our stock-based compensation plans, see Note 6 in the ~~2014~~2015 Form 10-K and the updates provided below.

Long-Term Incentive Plan

~~Performance-Based Stock Awards~~Performance Shares

LTIP performance shares incorporate a combination of market, performance, and service-based factors. During the ~~nine~~three months ended ~~September 30, 2015, 47,550~~March 31, 2016, 36,259 performance-based shares were granted under the LTIP based on target-level awards with a weighted-average grant date fair value of ~~$51.85~~$50.13 per share. As of ~~September 30, 2015,~~March 31, 2016, there was ~~$2.6~~$3.5 million of unrecognized compensation cost from LTIP grants, which is expected to be recognized through ~~2017.~~2018. Fair value for the market based portion of the LTIP was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:

~~Performance-Based~~ Restricted Stock Units (RSUs)

During the ~~nine~~three months ended ~~September 30, 2015, 37,264~~March 31, 2016, 29,486 RSUs were granted under the LTIP with a weighted-average grant date fair value of ~~$46.28~~$52.45 per share. The fair value of a RSU is equal to the closing market price of our common stock on the grant date. As of ~~September 30, 2015~~,March 31, 2016, there was ~~$2.9~~$3.2 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through ~~2019.~~2020. Generally, the RSUs awarded are forfeitable and include a performance-based threshold as well as a vesting period of four years from the grant date. AnA 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.

At ~~September 30, 2015~~,March 31, 2016, our short-term debt consisted of commercial paper notes payable with a maximum maturity of 7143 days and an average maturity of 6221 days and an outstanding balance of ~~$225.2 million~~.$164.9 million. The carrying cost of our commercial paper approximates fair value using Level 2 inputs, due to the short-term nature of the notes. See Note 2 in the ~~2014~~2015 Form 10-K for a description of the fair value hierarchy.

In the fourth quarter of 2015, we entered into a short-term credit facility loan totaling $50 million, as a short-term bridge through our peak heating season, which was repaid on February 4, 2016.

At ~~September 30, 2015, our utility segment~~March 31, 2016, we had long-term debt of $~~601.7~~$594.7 million,. which included $7.0 million of unamortized debt issuance costs. Utility long-term debt consists of first mortgage bonds (FMBs) with maturity dates ranging from 2016 through 2042,, interest rates ranging from ~~3.176~~%3.176% to ~~9.05~~%9.05%, and a weighted-average coupon rate of 5.70%.~~5.70%. The utility redeemed $40 million of FMBs with a coupon rate of 4.70% in June 2015.~~

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

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

Fair Value of Long-Term Debt

Our outstanding debt does not trade in active markets. We estimate the fair value of our debt using utility companies with similar credit ratings, terms, and remaining maturities to our debt that actively trade in public markets. These valuations are based on Level 2 inputs as defined in the fair value hierarchy. See Note 2 in the ~~2014~~2015 Form ~~10-K.~~10-K for a description of the fair value hierarchy.

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:

Estimated fair value⁽¹⁾

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

7. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

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

Three Months Ended September 30,
Other Postretirement
Pension Benefits Benefits
In thousands 2015 2014 2015 2014
Service cost $ 2,308
$ 1,919
$ 145
$ 136
Interest cost 4,597
4,511
291
309
Expected return on plan assets (5,174 ) (4,887 ) —
—
Amortization of net actuarial loss 4,561
2,579
125
46
Amortization of prior service costs 57
56
50
50
Net periodic benefit cost 6,349
4,178
611
541
Amount allocated to construction (2,061 ) (1,242 ) (218 ) (177 )
Amount deferred to regulatory balancing account⁽¹⁾
(2,171 ) (1,107 ) —
—
Net amount charged to expense $ 2,117
$ 1,829
$ 393
$ 364


	Nine Months Ended September 30,
							Other Postretirement						Three Months Ended March 31,
	Pension Benefits						Benefits						Pension Benefits						Other Postretirement Benefits
In thousands	2015			2014			2015			2014			2016			2015			2016			2015
Service cost	$	6,926		$	5,755		$	435		$	407		$	1,944		$	2,308		$	121		$	145
Interest cost	13,787			13,535			874			928			4,574			4,596			300			291
Expected return on plan assets	(15,522		)	(14,659		)	—			—			(5,017		)	(5,174		)	—			—
Amortization of net actuarial loss	13,683			7,739			376			138			3,502			4,561			192			126
Amortization of prior service costs	173			168			148			148			58			58			(117		)	49
Net periodic benefit cost	19,047			12,538			1,833			1,621			5,061			6,349			496			611
Amount allocated to construction	(5,765		)	(3,644		)	(607		)	(518		)	(1,548		)	(1,825		)	(164		)	(191		)
Amount deferred to regulatory balancing account⁽¹⁾	(6,511		)	(3,331		)	—			—			(1,627		)	(2,175		)	—			—
Net amount charged to expense	$	6,771		$	5,563		$	1,226		$	1,103		$	1,886		$	2,349		$	332		$	420

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:

Employer Contributions to Company-Sponsored Defined Benefit Pension ~~Plan~~Plans

For the ~~nine~~three months ended ~~September 30, 2015~~,March 31, 2016, we made cash contributions totaling ~~$11.8~~$2.9 million to ~~the~~our qualified defined benefit pension plan. We expect further plan contributions of ~~$2.3~~$11.6 million during the remainder of ~~2015.~~2016.

Defined Contribution Plan

The Retirement K Savings Plan ~~provided to our employees~~ is a qualified defined contribution plan under Internal Revenue Code Section 401(k). ~~Our~~Employer contributions ~~to this plan~~ totaled ~~$2.9~~$1.4 million and ~~$2.8~~$1.1 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and~~ ~~2014~~, respectively.

See Note 8 in the ~~2014~~2015 Form 10-K for more information concerning these retirement and other postretirement benefit plans.

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8. INCOME TAX

An estimate of annual income tax expense is made each interim period using estimates for annual pre-tax income, regulatory flow-through adjustments, tax credits, and other items. The estimated annual effective tax rate is applied to year-to-date, pre-tax income to determine income tax expense for the interim period consistent with the annual estimate.

The effective income tax rate varied from the combined federal and state statutory tax rates due to the following:


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
Dollars in thousands	2015			2014			2015			2014			2016			2015
Income tax at statutory rates (federal and state)	$	(4,473	)	$	(6,161	)	$	15,848		$	20,288
Income taxes at statutory rates (federal and state)													$	24,608		$	18,892
Increase (decrease):
Differences required to be flowed-through by regulatory commissions	(378		)	(310		)	1,036			1,184			1,518			1,329
Other, net	298			(271		)	(940		)	(449		)	(740		)	(1,138		)
Income tax expense (benefit)	$	(4,553	)	$	(6,742	)	$	15,944		$	21,023
Effective income tax rate	40.5		%	43.6		%	39.9		%	41.0		%
Total provision for income taxes													$	25,386		$	19,083
Effective tax rate													40.9		%	40.1		%

~~Increases or decreases in income tax expense are correlated with changes in pre-tax income.~~ The effective tax rate for the three ~~and nine~~ months ended ~~September 30, 2015,~~March 31, 2016, compared to the same ~~periods~~period in ~~2014, decreased~~2015, increased primarily as a result of lower estimated depletion deductions from gas reserves ~~activity. Additionally, there was a comparative decrease due to a $0.6 million income tax charge~~activity in ~~the first quarter of 2014 due to the revaluation of deferred tax balances related to a higher~~2016. The effective tax rate ~~in Oregon.~~for the three months ended March 31, 2015 benefited from the realization of deferred depletion benefits from 2013 and 2014. See Note 9 in the ~~2014~~2015 Form 10-K for more detail on income taxes and effective tax rates.

~~Our~~The 2015 tax year is subject to examination under the Internal Revenue Service (IRS) Compliance Assurance Process ~~for the 2013~~(CAP). The Company’s 2016 tax year ~~was completed during~~CAP application has been accepted by the ~~first quarter of 2015. The examination did not result in a material change to the return as originally filed.~~IRS.

9. PROPERTY, PLANT, AND EQUIPMENT

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

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

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



	March 31,				December 31,
In thousands	2016		2015		2015
Utility plant in service	$	2,760,188	$	2,676,280	$	2,745,485
Utility construction work in progress	51,014		34,048		39,288
Less: Accumulated depreciation	878,364		847,278		867,377
Utility plant, net	1,932,838		1,863,050		1,917,396
Non-utility plant in service	296,826		299,969		296,839
Non-utility construction work in progress	7,826		7,457		7,768
Less: Accumulated depreciation	40,823		35,976		39,340
Non-utility plant, net	263,829		271,450		265,267
Total property, plant, and equipment	$	2,196,667	$	2,134,500	$	2,182,663

Capital expenditures in accrued liabilities	$	8,424	$	8,451	$	8,985

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10. GAS RESERVES

We have invested $188 million through our gas reserves program in the Jonah Field located in Wyoming as of ~~September 30, 2015.~~March 31, 2016. Gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. Our investment in gas reserves provides long-term price protection for utility customers and currently incorporates two agreements: the original agreement with Encana Oil & Gas (USA) Inc. under which we invested $178 million and the amended agreement with Jonah Energy LLC under which an additional $10 million was invested.

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

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

~~We filed an application requesting regulatory deferral in Oregon for~~ Volumes produced from these ~~additional investments, which was granted in April 2015. Accordingly, we filed in 2015 seeking cost recovery for the additional~~ wells ~~drilled in 2014. In September 2015, the OPUC adopted an all-party settlement, under which volumes produced~~ are included in our Oregon PGA ~~beginning November 1, 2015~~ at a fixed rate of $0.4725 per therm, which approximates the 10-year hedge rate plus financing costs at the inception of the investment.

The following table outlines our net ~~investment in~~ gas ~~reserves:~~reserves investment:


	September 30,				December 31,		March 31,				December 31,
In thousands	2015		2014		2014		2016		2015		2015
Gas reserves, current	$	17,822	$	21,455	$	20,020	$	16,420	$	19,112	$	17,094
Gas reserves, non-current	169,300		164,115		167,190		171,121		168,352		170,453
Less: Accumulated amortization	51,516		32,370		37,910		59,976		43,165		55,901
Total gas reserves⁽¹⁾	135,606		153,200		149,300		127,565		144,299		131,646
Less: Deferred tax liabilities on gas reserves	23,042		33,037		18,551
Less: Deferred taxes on gas reserves							28,547		28,383		27,203
Net investment in gas reserves⁽¹⁾	$	112,564	$	120,163	$	130,749	$	99,018	$	115,916	$	104,443

⁽¹⁾

~~Gas reserves include our investments~~Our investment in additional wells ~~with Jonah Energy with the~~included in total ~~gross investment~~gas reserves was $7.6 million ($3.4 million net of ~~$9.7~~deferred taxes), $9.2 million ($8.3 million net of deferred taxes) and ~~$8.2~~$8.0 million ($4.3 million net of deferred taxes) at ~~September 30,~~March 31, 2016 and 2015 and ~~2014, respectively. Net investment in the additional wells was $4.5 million and $6.5 million at September 30,~~December 31, 2015, ~~and 2014,~~ respectively.

Our investment is included on our balance sheet under gas reserves with our maximum loss exposure limited to our current investment balance.

11. INVESTMENTS

~~Equity Method~~ Investments in Gas Pipeline

Trail West Pipeline, LLC (TWP), a wholly-owned subsidiary of TWH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with ~~the~~our utility distribution system. NWN Energy, a wholly-owned subsidiary of NW Natural owns 50% of TWH, and 50% is owned by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation.

~~Table of Contents~~

~~VIE~~Variable Interest Entity (VIE) Analysis

TWH is a ~~Variable Interest Entity,~~VIE, with our investment in TWP reported under equity method accounting. We have determined we are not the primary beneficiary of TWH’s activities as we only have a 50% share of the entity and there are no stipulations that allow us a disproportionate influence over it. Our ~~investment~~investments in TWH and TWP isare included in other investments on our balance sheet. If we do not develop this investment, then ~~the~~our maximum loss exposure related to TWH is limited to our equity investment balance, less our share of any cash or other assets available to itus as a 50% owner. Our investment balance in TWH was $13.4 million at ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~ and December 31, ~~2014.~~2015. See Note 12 in the ~~2014~~2015 Form 10-K.

Other Investments

Other investments include financial investments in life insurance policies, which are accounted for at cash surrender value, net of policy loans. See Note 12 in the ~~2014~~2015 Form 10-K.

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12. DERIVATIVE INSTRUMENTS

We enter into financial derivative contracts to hedge a portion of ~~the~~our utility’s natural gas sales requirements. These contracts include swaps, options and combinations of option contracts. We primarily use these derivative financial instruments to manage commodity price variability. A small portion of our derivative hedging strategy involves foreign currency exchange contracts.

We enter into these financial derivatives, up to prescribed limits, primarily to hedge price variability related to our physical gas supply contracts as well as to hedge spot purchases of natural gas. The foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for pipeline demand charges paid in Canadian dollars.

In the normal course of business, we also enter into indexed-price physical forward natural gas commodity purchase contracts and options to meet the requirements of utility customers. These contracts qualify for regulatory deferral accounting treatment.

We also enter into exchange contracts related to the third-party asset management of our gas portfolio, some of which are derivatives that do not qualify for hedge accounting or regulatory deferral, but are subject to our regulatory sharing agreement. These derivatives are recognized in operating revenues in our gas storage segment, net of amounts shared with utility customers.

Notional Amounts

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


	September 30,				December 31,		March 31,				December 31,
In thousands	2015		2014		2014		2016		2015		2015
Natural gas (in therms):
Financial	416,075		368,425		287,475		317,100		229,925		346,875
Physical	521,350		620,550		420,980		169,978		250,250		404,645
Foreign exchange	$	8,023	$	10,296	$	12,230	$	6,852	$	8,690	$	9,025

Purchased Gas Adjustment (PGA)

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

~~Table of Contents~~

Unrealized and Realized Gain/Loss

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

Three Months Ended September 30,
2015
2014
In thousands Natural gas commodity Foreign currency Natural gas commodity Foreign currency
Expense to cost of gas $ (8,415 ) $ (150 ) $ (10,173 ) $ (421 )
Operating revenues 33
—
—
—
Less:

Amounts deferred to regulatory accounts on the balance sheet 8,391
150
10,559
421
Total gain in pre-tax earnings $ 9
$ —
$ 386
$ —


	Nine Months Ended September 30,												Three Months Ended March 31,
	2015						2014						2016						2015
In thousands	Natural gas commodity			Foreign currency			Natural gas commodity			Foreign currency			Natural gas commodity			Foreign exchange			Natural gas commodity			Foreign exchange
(Expense) benefit to cost of gas	$	(21,876	)	$	(413	)	$	360		$	(242	)	$	(16,379	)	$	241		$	(23,481	)	$	(741	)
Operating revenues	55			—			—			—			—			—			638			—
Less:
Amounts deferred to regulatory accounts on the balance sheet	21,838			413			(93		)	242
Amounts deferred to regulatory accounts on balance sheet													16,379			(241		)	23,065			741
Total gain in pre-tax earnings	$	17		$	—		$	267		$	—		$	—		$	—		$	222		$	—

UNREALIZED GAIN/LOSS.Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory accounting standards. The cost of foreign currency forward ~~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.

~~Realized Gain/Loss~~

REALIZED GAIN/LOSS. We realized a net ~~loss~~losses of ~~$2.3~~$15.5 million and ~~$24.3~~$14.1 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015, ~~and a net gain of $0.5 million and $13.3 million for the~~ ~~three and nine months ended~~ ~~September 30,2014~~, respectively, from the settlement of natural gas financial derivative contracts. Realized gains and losses are recorded in cost of gas, deferred through our regulatory accounts, and amortized through customer rates in the following year.

Credit Risk Management of Financial ~~Derivative~~Derivatives Instruments

No collateral was posted with or by our counterparties as of ~~September 30, 2015~~March 31, 2016 or ~~2014.~~2015. We attempt to minimize the potential exposure to collateral calls by counterparties to manage our liquidity risk. Counterparties generally allow a certain credit limit threshold before requiring us to post collateral against loss positions. Given our counterparty credit limits and portfolio diversification, we ~~have~~were not ~~been~~ subject to collateral calls in ~~2014~~2016 or ~~2015~~.2015. Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We could also be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change.

Based onupon current commodity financial swap and option contracts outstanding, which reflect ~~net~~ unrealized losses of ~~$23.8~~$17.2 million at ~~September 30, 2015,~~March 31, 2016, we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various credit downgrade rating scenarios for NW Natural as follows:

Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our statement of financial position. WeThe Company and ~~our~~its counterparties have the ability to set-off ~~our~~their obligations to each other under specified circumstances. Such circumstances may include a defaulting party, a credit change due to a merger affecting either party, or any other termination event.

If netted by ~~each~~ counterparty, our ~~net~~ derivative position would result in an asset of ~~$3.1~~$1.8 million and a liability of ~~$25.3~~$17.9 million as of ~~September 30, 2015~~.March 31, 2016. As of ~~September 30, 2014~~,March 31, 2015, our derivative position would have resulted in an asset of ~~$4.0~~$0.6 million and a liability of ~~$3.9 million, and as~~$24.2 million. As of December 31, ~~2014,~~2015, our derivative position would have resulted in an asset of ~~$0.2~~$2.7 million and a liability of ~~$33.4~~$25.5 million.

We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of customers. See Note 13 in ~~the~~ ~~2014~~our 2015 Form 10-K for additional information.

In accordance with fair value accounting, we include ~~nonperformance~~non-performance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. The inputs in our valuation models include natural gas futures, volatility, credit default swap spreads and interest rates. Additionally, our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at ~~September 30, 2015.~~March 31, 2016. As of ~~September 30,~~March 31, 2016 and 2015, ~~and 2014~~ and December 31, ~~2014,~~2015, the net fair value was a liability of ~~$22.2~~$16.1 million, ~~an asset of $0.1~~$23.6 million, and ~~a liability of $33.2~~$22.8 million, respectively, using significant other observable, or ~~Level~~level 2, inputs. No ~~Level~~level 3 inputs were used in our derivative valuations, and there were no transfers between ~~Level~~level 1 or ~~Level~~level 2 during the ~~nine months~~quarters ended ~~September 30,~~March 31, 2016 and 2015. See Note 2 in the 2015 ~~and 2014.~~Form 10-K.

13. ENVIRONMENTAL MATTERS

We own, or previously owned, properties that may require environmental remediation or action. We estimate the range of loss for environmental liabilities based on current remediation technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible ~~parties.~~ parties (PRPs). When amounts are prudently expended related to site remediation, we have a recovery mechanism in place to collect 96.68% of remediation costs from Oregon customers, and we are allowed to defer environmental remediation costs allocated to customers in Washington annually until they are reviewed for prudence at a subsequent proceeding.

Our sites are subject to the remediation process prescribed by the Environmental Protection Agency (EPA) and the Oregon Department of Environmental Quality (ODEQ). The process begins with a remedial investigation (RI) to determine the nature and extent of contamination and then a risk assessment (RA) to establish whether the contamination at the site poses unacceptable risks to humans and the environment. Next, a feasibility study (FS) or an engineering evaluation/cost analysis (EE/CA) evaluates various remedial alternatives. It is at this point in the process when we are able to estimate a range of remediation costs and record a reasonable potential remediation liability, or make an adjustment to our existing liability. From this study, the regulatory agency selects a remedy and issues a Record of Decision (ROD). After the ROD is issued, we seek to negotiate a consent decree or consent judgment for designing and implementing the remedy. We have the ability to further refine estimates of remediation liabilities at that time.

Remediation may include treatment of contaminated media such as sediment, soil and groundwater, removal and disposal of media, or institutional controls such as legal restrictions on future property use. Following construction of the remedy, the EPA and ODEQ also have requirements for ongoing maintenance, monitoring and other post-remediation care that may continue for many years. Where appropriate and reasonably known, we will provide for these costs in our remediation liabilities described above.

Due to the numerous uncertainties surrounding the course of environmental remediation and the ~~ongoing~~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.~~estimated where a range of potential loss is available. Unless there is an estimate within athe 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 addition to remediation costs, we could also be subject to Natural Resource Damages (NRD) claims. We will assess the likelihood and probability of each claim and recognize a liability if deemed appropriate. As of March 31, 2016, we have not received any material NRD claims.

The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other current liabilities and other noncurrent liabilities on the balance sheet:



	Current Liabilities						Non-Current Liabilities
	March 31,				December 31,		March 31,				December 31,
In thousands	2016		2015		2015		2016		2015		2015
Portland Harbor site:
Gasco/Siltronic Sediments	$	2,747	$	1,572	$	2,229	$	42,079	$	38,379	$	42,641
Other Portland Harbor	1,655		1,308		1,972		4,775		5,186		5,073
Gasco Upland site	10,405		8,205		10,599		51,070		36,833		52,117
Siltronic Upland site	221		750		951		333		405		337
Central Service Center site	25		170		25		—		—		—
Front Street site	1,071		755		1,155		7,746		115		7,748
Oregon Steel Mills	—		—		—		179		179		179
Total	$	16,124	$	12,760	$	16,931	$	106,182	$	81,097	$	108,095

PORTLAND HARBOR SITE. The Portland Harbor is an EPA listed Superfund site that is approximately 10 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands and the Siltronic uplands sites. We are a PRP to the Superfund site and have joined with some of the other PRPs (the Lower Willamette Group or LWG) to develop a Portland Harbor Remedial Investigation/Feasibility Study (RI/FS), which we submitted to the EPA in 2012. In August 2015, the EPA issued its own Draft Feasibility Study (Draft FS) for comment. The EPA Draft FS provides a new range of remedial costs for the entire Portland Harbor Superfund Site, which includes the Gasco/Siltronic Sediment site, discussed below. The range of present value costs estimated by the EPA for various remedial alternatives for the entire Portland Harbor, as provided by the EPA's Draft FS, is $791 million to $2.45 billion. The range provided in the EPA's Draft FS is based on cost alternatives the EPA estimates to have an accuracy between -30% and +50% of actual costs, depending on the scope of work. While the EPA's Draft FS provides a higher range of costs than the LWG's submission in 2012, our potential liability is still a portion of the costs of the remedy 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 PRPs. We are participating in a non-binding allocation process in an effort to settle this potential liability. The new EPA Draft FS does not provide any additional clarification around allocation of costs.

We manage our liability related to the Superfund site as two distinct remediation projects, the Gasco/Siltronic Sediments and Other Portland Harbor projects.

Gasco/Siltronic Sediments.In 2009, NW Natural and Siltronic Corporation entered into a separate Administrative Order on Consent with the EPA to evaluate and design specific remedies for sediments adjacent to the Gasco uplands and Siltronic uplands sites. We submitted a draft EE/CA to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA as well as costs for the additional studies and design work needed before the clean-up can occur, and for regulatory oversight throughout the clean-up range from $44.8 million to $350 million. We have recorded a liability of $44.8 million for the sediment clean-up, which reflects the low end of the range. At this time, we believe sediments at this site represent the largest portion of our liability related to the Portland Harbor site, discussed above.

Other Portland Harbor.NW Natural incurs costs related to its membership in the LWG. NW Natural also incurs costs related to natural resource damages from these sites. The Company and other parties have signed a cooperative agreement with the Portland Harbor Natural Resource Trustee council to participate in a phased natural resource damage assessment to estimate liabilities to support an early restoration-based settlement of natural resource damage claims. Natural resource damage claims may arise only after a remedy for clean-up has been settled. We have recorded a liability for these claims which is at the low end of the range of the potential liability; the high end of the range cannot be reasonably estimated at this time. This liability is not included in the range of costs provided in the draft FS for the Portland Harbor or noted above.

GASCO UPLANDS SITE. A predecessor of NW Natural owned a former gas manufacturing plant that was closed in 1958 (Gasco site) and is adjacent to the Portland Harbor site described above. The Gasco site has been under investigation by us for environmental contamination under the ODEQ Voluntary Clean-Up Program. It is not included in the range of remedial costs for the Portland Harbor site noted above. We manage the Gasco site in two parts, the uplands portion and the groundwater source control action.

We submitted a revised Remedial Investigation Report for the uplands to ODEQ in May 2007. In March 2015, ODEQ approved the RA NW Natural submitted in 2010, enabling us to begin work on the FS in 2016. We have recognized a liability for the remediation of the uplands portion of the site which is at the low end of the range of potential liability; the high end of the range cannot be reasonably estimated at this time.

In ~~Oregon,~~September 2013, we completed construction of a groundwater source control system, including a water treatment station, at the Gasco site. We are working with ODEQ on monitoring the effectiveness of the system and at this time it is unclear what, if any, additional actions ODEQ may require subsequent to the initial testing of the system or as part of the final remedy for the uplands portion of the Gasco site. We have estimated the cost associated with the ongoing operation of the system and have recognized a liability which is at the low end of the range of potential cost. We cannot estimate the high end of the range at this time due to the uncertainty associated with the duration of running the water treatment station, which is highly dependent on the remedy determined for both the upland portion as well as the final remedy for our Gasco sediment exposure.

Beginning November 1, 2013, capital asset costs of $19.0 million for the Gasco water treatment station were placed into rates with OPUC approval. The OPUC deemed these costs prudent. Beginning November 1, 2014, the OPUC approved the application of $2.5 million from insurance proceeds plus interest to reduce the total amount of Gasco capital costs to be recovered through rate base. A portion of these proceeds was non-cash in 2014.

OTHER SITES. In addition to those sites above, we have environmental exposures at 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 remediation and in the case of the Oregon Steel Mills site, pending litigation, liabilities for each of these sites have been recognized at their respective low end of the range of potential liability; the high end of the range could not be reasonably estimated at this time.

Siltronic Upland. A portion of the Siltronic property adjacent to the Gasco site was formerly owned by Portland Gas and Coke, NW Natural's predecessor. We are currently conducting an investigation of manufactured gas plant wastes on the uplands at this site for ODEQ.

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

Front Street site.The Front Street site was the former location of a gas manufacturing plant we operated (the former Portland Gas Manufacturing site, or PGM). At ODEQ’s request, we conducted a sediment and source control investigation and provided findings to ODEQ. In December 2015, we completed a FS on the former Portland Gas Manufacturing site. The FS provided a range of $7.6 million to $12.9 million for remedial costs. We have recorded a liability at the low end of the range of possible loss as no alternative in the range is considered more likely than another. Further, we have recognized an additional liability of $1.2 million for additional studies and design costs as well as regulatory oversight throughout the clean-up that will be required to assist in ODEQ making a remedy selection and completing a design.

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

Site Remediation and Recovery Mechanism (SRRM)

We have a SRRM through which we track and have the ability to recover past deferred and future prudently incurred environmental remediation costs allocable to Oregon, subject to an earnings test. ~~An Order from~~

REGULATORY ACTIVITIES. In February 2015, the OPUC in February 2015 deemed certain environmental remediation expenses and associated carrying costs deferred through March 31, 2014 prudent. Our settlement with insurance carriers resulting in insurance proceeds received was also deemed prudent inissued an Order addressing outstanding issues related to the ~~Order. Under the Order, we were~~SRRM (2015 Order), which required us to ~~forgo the~~forego collection of $15 million out of approximately $95 million ofin total environmental remediation expenses and associated carrying costs wethe Company had deferred through 2012 ~~under the Order. The OPUC disallowed this amount from rate recovery~~ based on ~~its~~the OPUC’s determination of how an earnings test should apply to amounts deferred from 2003 to 2012,

with adjustments for other factors the OPUC deemed relevant. ~~See Note 2~~As a result, we recognized a $15.0 million non-cash charge in operations and maintenance expense in the first quarter of 2015. Also, as a result of the 2015 Order, we recognized $5.3 million pre-tax of interest income related to the equity earnings on our deferred environmental expenses.

In addition, the OPUC issued a subsequent Order regarding SRRM implementation (2016 Order) in January 2016 in which the OPUC: (1) disallowed the recovery of $2.8 million of interest earned on the previously disallowed environmental expenditure amounts; (2) clarified the state allocation of 96.68% of environmental remediation costs for ~~information regarding~~all environmental sites to Oregon; and (3) confirmed our treatment of $13.8 million of expenses put into the ~~regulatory disallowance~~SRRM amortization account was correct and in compliance with prior OPUC orders. As a result of the 2016 Order, we recognized a $3.3 million non-cash charge in the first quarter, of which $2.8 million is reflected in other income and expense, net and $0.5 million is included in operations and maintenance expense.

COLLECTIONS FROM OREGON CUSTOMERS. The SRRM provides us with the ability to recover past deferred and future prudently incurred environmental remediation costs ~~under~~allocable to Oregon, subject to an earnings test. The SRRM created three classes of deferred environmental remediation expense:

In addition to the collection amount noted above, the Order ~~received~~also provides for the annual collection of $5 million from ~~the OPUC in February 2015.~~Oregon customers through a tariff rider. As we collect amounts from customers, we recognize these collections as revenue and separately amortize our deferred regulatory asset balance through operating expense.

We received total environmental insurance proceeds of approximately $150 million as a result of settlements from our litigation that was dismissed in July 2014. Under the OPUC Order, one-third of the Oregon allocated proceeds were applied to costs deferred through 2012, and the remaining two-thirds will be applied to costs over the next 20 years.

18 Annually, the Order provided for the application of $5 million of insurance proceeds plus interest against deferred remediation expense deemed prudent in the same annual period; annual amounts not utilized are carried forward to apply against future prudently incurred costs. We accrue interest on the insurance proceeds in the customer’s favor at a rate equal to the five-year treasury rate plus 100 basis points. As of March 31, 2016, we have applied $58.2 million of insurance proceeds to prudently incurred remediation costs.

The following table presents information regarding the total regulatory asset deferred:



	March 31,						December 31,
In thousands	2016			2015			2015
Deferred costs and interest⁽¹⁾	$	57,359		$	76,790		$	79,505
Accrued site liabilities	122,306			93,858			125,026
Insurance proceeds and interest	(102,570		)	(120,473		)	(118,677		)
Total regulatory asset deferral⁽¹⁾	77,095			50,175			85,854
Current regulatory assets⁽²⁾	9,096			—			9,270
Long-term regulatory assets	67,999			50,175			76,584


⁽¹⁾	Includes pre-review and post-review deferred costs, amounts currently in amortization and interest, net of amounts collected from customers.


⁽²⁾	Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and WUTC. In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until

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~~Under~~expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from customers in the ~~SRRM, we will recover~~next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the ~~first~~OPUC and do not include the $5 million ~~of annual expense through an amount that will be collected from Oregon customers through a~~ tariff rider. ~~We will apply $5 million of insurance (plus interest)~~The amounts allocable to ~~the next portion of~~Oregon are recoverable through utility rates, subject to an earnings test.

ENVIRONMENTAL EARNINGS TEST. The 2015 Order directed us to implement an annual environmental ~~expenses each year. Any expenses~~earnings test for our prudently incurred remediation expense. Prudently incurred Oregon allocated annual remediation expense and interest ~~on expenses~~ in excess of the ~~annual $10~~$5 million ~~(plus~~tariff rider and $5 million insurance proceeds application plus interest ~~from insurance)~~on the insurance proceeds are ~~fully~~ recoverable through the SRRM, to the extent the utility earns at or below our authorized Return On Equity (ROE). To the extent the utility earns more than its authorized ROE in a year, the utility is required to cover environmental expenses and interest on expenses greater than the $10 million (plus interest from insurance proceeds) with those earnings that exceed its authorized ROE.

~~We submitted~~Under the required compliance filing demonstrating the proposed implementation of the Order and SRRM in March 2015. In September 2015, as a result of discussions with the parties, we withdrew our original compliance filing and submitted a revised filing noting the parties could potentially raise two issues with our proposed implementation of the Order. First, we believe the February 2015 Order, ~~reflected~~ the ~~Commission’s determination~~OPUC will revisit the deferral and amortization of future remediation expenses, as well as the total disallowance to be borne by NW Natural for prior periods; however, we anticipate the parties will question whether interest on the $15 million charge should be separately disallowed. This interest would total approximately $3 million. Second, we anticipate discussions concerning how state allocation ratestreatment of remaining insurance proceeds three years from the original Order, ~~are applied~~or earlier if the Company gains greater certainty about its future remediation costs, to ~~our environmental remediation sites. However, we believe the effect on current regulatory deferrals related~~consider whether adjustments to the ~~state allocation issue would~~mechanism may be ~~insignificant.~~appropriate.

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

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

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

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~~Environmental Sites~~

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

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

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

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


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

~~PORTLAND HARBOR SITE.~~ The Portland Harbor is an Environmental Protection Agency (EPA) listed Superfund site that is approximately 10 miles long on the Willamette River and is adjacent to our Gasco uplands and Siltronic uplands sites. We are a potentially responsible party (PRP) to the Superfund site and have joined with some of the other PRPs (the Lower Willamette Group or LWG) to develop a Portland Harbor Remedial Investigation/Feasibility Study (RI/FS). In August 2015, the EPA issued its own Draft Feasibility Study (Draft FS) for comment. The EPA Draft FS provides a new range of remedial costs for the entire Portland Harbor Superfund Site, which includes the Gasco/Siltronic Sediment site, discussed below. The range of present value costs estimated by the EPA for various remedial alternatives for the entire Portland Harbor, as provided in the EPA’s Draft FS, is $791 million to $2.45 billion. The range provided in the EPA’s Draft FS is based on cost alternatives the EPA estimates to have an accuracy between -30% and +50% of actual costs, depending on the scope of work. While the EPA’s Draft FS provides a higher range of costs than the LWG's submission, our potential liability is still a portion of the costs of the remedy the EPA will select for the entire Portland Harbor Superfund site. The cost of the remedy is expected to be allocated among more than 100 PRPs. We are participating in a non-binding allocation process in an effort to settle this potential liability. The new EPA Draft FS does not provide any additional clarification around allocation of costs. We manage our liability related to the Superfund site as two distinct remediation projects, the Gasco/Siltronic Sediments and Other Portland Harbor projects.

~~GASCO/SILTRONIC SEDIMENTS.~~ In 2009, NW Natural and Siltronic Corporation entered into a separate Administrative Order on Consent with the EPA to evaluate and design specific remedies for sediments adjacent to the Gasco uplands and Siltronic uplands sites. We submitted a draft Engineering Evaluation/Cost Analysis (EE/CA) to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA, as well as the estimated costs for the additional studies and design work needed before the clean-up can occur, and for regulatory oversight throughout the clean-up, range from $39.8 million to $350 million. We have recorded a liability of $39.8 million for the sediment clean-up, which reflects the low end of the range. At this time, we believe sediments at this site represent the largest portion of our liability related to the Portland Harbor site, discussed above.

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~~OTHER PORTLAND HARBOR.~~ We incur costs related to our membership in the LWG, who is performing the RI/FS for the EPA, and also incur costs related to natural resource damages from these sites. NW Natural and other parties have signed a cooperative agreement with the Portland Harbor Natural Resource Trustee council to participate in a phased natural resource damage assessment to estimate liabilities to support an early restoration-based settlement of natural resource damage claims. Natural resource damage claims may arise only after a remedy for clean-up has been settled. We have accrued a liability for these claims at the low end of the range of the potential liability; the high end of the range cannot be reasonably estimated at this time. This liability is not included in the range of costs provided in the EPA Draft FS for the Portland Harbor noted above.

~~GASCO SITE.~~ We own a former gas manufacturing plant that was closed in 1958 (Gasco site) and is adjacent to the Portland Harbor site described above. The Gasco site has been under investigation by NW Natural for environmental contamination under the Oregon Department of Environmental Quality (ODEQ) Voluntary Clean-Up Program. It is not included in the range of remedial costs for the Portland Harbor site noted above. We manage the Gasco site in two parts, the uplands portion and the groundwater source control action.

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

~~Groundwater Source Control.~~ In September 2013, we completed construction of a groundwater source control system, including a water treatment station, at the Gasco site. We are working with ODEQ on monitoring the effectiveness of the system and at this time it is unclear what, if any, additional actions ODEQ may require subsequent to the performance testing of the system or as part of the final remedy for the uplands portion of the Gasco site. We have estimated the cost associated with the ongoing operation of the system and have recognized a liability at the low end of the range of potential cost. We cannot estimate the high end of the range at this time due to the uncertainty associated with the duration of running the water treatment station, which will be highly dependent upon the remedy determined for both the upland portion as well as the final remedy for our Gasco sediment exposure.

Beginning November 1, 2013, capital asset costs of $19 million for the Gasco water treatment station were placed into rates with OPUC approval. The OPUC deemed these costs prudent. Beginning November 1, 2014, the OPUC approved the application of $2.5 million from insurance proceeds plus interest to reduce the total amount of Gasco capital costs to be recovered through rate base.

~~OTHER SITES.~~ In addition to those sites above, we have environmental exposures at four other sites: Siltronic, Central Service Center, Front Street, and Oregon Steel Mills. Due to the uncertainty of the design of remediation, regulation, timing of the liabilities, and in the case of the Oregon Steel Mills site, pending litigation, liabilities for each of these sites have been recognized at their respective low end of the range of potential liability; the high end of the range could not be reasonably estimated at this time.

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

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

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

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

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Legal Proceedings

~~We are~~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, we do not expect that the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations or cash flows. See also Part II, Item 1, “Legal Proceedings.”

OREGON STEEL MILLS SITE. In 2004, ~~we were~~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 Evraz Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial. Although the final outcome of this proceeding cannot be predicted with certainty, we do not expect the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows.

For additional information regarding other commitments and ~~contingencies, see~~contingencies. See Note 14 in the ~~2014~~2015 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~~discussion refers to our consolidated ~~activities~~results for the ~~three~~quarters ended March 31, 2016 and ~~nine months ended September 30, 2015~~ ~~and~~ ~~2014~~.2015. References in this discussion to ~~“Notes”~~"Notes" are to the Notes to Unaudited Consolidated Financial Statements in this report. A significant portion of our business results are seasonal in nature, and, as such, the results of operations for the three ~~and nine~~ month periods are not necessarily indicative of expected fiscal year results. Therefore, this discussion should be read in conjunction with our ~~2014~~2015 Annual Report on Form 10-K (~~2014~~(2015 Form 10-K).

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

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).

We operate in two primary reportable business segments: local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as other. We refer to our local gas distribution business as the utility, and our gas storage segment and other as non-utility. Our utility segment includes our NW Natural local gas distribution business, NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp, and the utility portion of our Mist underground storage facility in Oregon (Mist). Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist, ~~(NWN's storage facility in Oregon),~~ and asset management services. Other includes NWN Energy's equity investment in Trail West ~~Holdings,~~Holding, LLC (TWH), which is pursuing the development of a proposed natural gas pipeline through its wholly-owned subsidiary, Trail West Pipeline, LLC (TWP), and NNG Financial's equity investment in Kelso-Beaver Pipeline (KB Pipeline). For a further discussion of our business segments and other, see Note 4.4.

In addition to presenting the results of operations and earnings amounts in total, certain financial measures are expressed in cents per share or exclude the after-tax regulatory disallowance related to the OPUC's 2015 and 2016 environmental ~~order,~~orders, which are non-GAAP financial measures. We present net income and earnings per share (EPS) excluding the regulatory ~~disallowance~~disallowances along with the U.S. GAAP measures to illustrate the magnitude of this disallowance on ongoing business and operational results. Although the excluded amounts are properly included in the determination of net income and earnings per share under U.S. GAAP, we believe the amount and nature of such ~~disallowance~~disallowances make period to period comparisons of operations difficult or potentially confusing. Financial measures are expressed in cents per share as these amounts reflect factors that directly impact earnings, including income taxes. All references in this section to EPS are on the basis of diluted shares (see Note 3). We use such non-GAAP financial measures to analyze our financial performance because we believe they provide useful information to our investors and creditors in evaluating our financial condition and results of operations.

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EXECUTIVE SUMMARY

~~Consolidated results~~We manage our business and strategic initiatives with a long-term view of providing natural gas service safely and reliably to customers, working with regulators on key policy initiatives, and remaining focused on growing our business. See "2016 Outlook" in our 2015 Form 10-K for more information. Highlights for the quarter include:

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

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

~~Consolidated results for the year include:~~

Nine Months Ended September 30,
2015 2014
In thousands, except per share data Amount Per Share Amount Per Share Change
Consolidated net income $ 23,998
$ 0.88
$ 30,222
$ 1.11
$ (6,224 )
Adjustments:
Regulatory environmental disallowance, net of taxes $5,925⁽¹⁾
9,075
0.33
—
—
9,075
Adjusted consolidated net income⁽¹⁾
$ 33,073
$ 1.21
$ 30,222
$ 1.11
$ 2,851
Utility margin $ 252,935
$ 250,223
$ 2,712
Gas storage operating revenues 16,232
17,655
(1,423 )


⁽¹⁾	Regulatory environmental disallowance of $15 million is recorded in utility operations and maintenance expense. Adjusted EPS and net income are non-GAAP measures based on the after-tax disallowance. EPS is calculated using the combined federal and state statutory tax rate of 39.5% and 27.4 million dilutive shares for the first nine months of 2015.

~~NINE MONTHS ENDED SEPTEMBER 30, 2015 COMPARED TO SEPTEMBER 30, 2014.~~ Consolidated net income decreased $6.2 million primarily due to the $9.1 million after-tax charge related to the regulatory disallowance associated with a February 2015 OPUC Order in our SRRM docket. Under the Order, we were required to forego collection of $15 million, pre-tax, out of the approximate $95 million of environmental expenditures and associated carrying costs deferred through 2012. This charge is reflected in operations and maintenance expense. Excluding the charge, other factors affecting net income were a $2.7 million increase in utility margin, a $4.9 million increase in other income, and a $3.0 million decrease in interest expense, offset by a $1.4 million decrease in gas storage revenues and a $3.4 million increase in operations and maintenance expense.

~~We continued to make progress on several key strategic metrics and initiatives, as evidenced by the following items:~~

~~added more than 10,500~~1.5% at March 31, 2016, adding over 10,000 customers over the past twelve ~~months ended September 30, 2015~~months;

collected $5.0 million through our SRRM and ~~increased~~submitted our ~~customer growth rate in~~final compliance filing to the ~~core utility to 1.5%~~OPUC; and

received final amendment and permit from ~~1.3% at September 30, 2014;~~

~~ranked first in residential customer satisfaction~~the Energy Facility Siting Council for ~~large gas utilities in the West in the 2015 J.D. Power and Associates Study, making 2015 the 14th consecutive year of top three scores;~~

~~decreased residential customer rates approximately 7% in Oregon and 14% in Washington with the 2015-16 PGA effective November 1, 2015;~~

~~announced a dividend increase in the fourth quarter, which reflects the 60th consecutive year of increases; and~~

~~continued land permitting and acquisition work to further the~~our North Mist gas storage expansion project.

24Key financial highlights include:



	Three Months Ended March 31,
	2016				2015
In millions, except per share data	Amount		Per Share		Amount		Per Share		$ Change
Consolidated net income	$	36,641	$	1.33	$	28,486	$	1.04	$	8,155
Adjustments:
Regulatory environmental disallowance, net of taxes ($1,304 and $5,925)⁽¹⁾	1,996		0.07		9,075		0.33		(7,079		)
Adjusted consolidated net income⁽¹⁾	$	38,637	$	1.40	$	37,561	$	1.37	$	1,076
Utility margin	$	136,664			$	130,601			$	6,063
Gas storage operating revenues	5,369				5,303				66

⁽¹⁾Regulatory environmental disallowance of $3.3 million in 2016 is recorded in utility other income and expense, net ($2.8 million) and utility operations and maintenance expense ($0.5 million). Regulatory environmental disallowance of $15.0 million in 2015 is recorded in utility operations and maintenance expense. Adjusted EPS and net income are non-GAAP financial measures based on the after-tax disallowance. EPS is calculated using the combined federal and state statutory tax rate of 39.5% and 27.6 million and 27.4 million diluted shares for the quarters ended March 31, 2016 and 2015, respectively.

THREE MONTHS ENDED MARCH 31, 2016 COMPARED TO MARCH 31, 2015. Excluding the impact of the regulatory environmental orders in 2015 and 2016 noted in the table above, net income increased $1.1 million primarily due to the following factors:

a $6.1 million increase in utility margin primarily due to customer growth and gas cost sharing; offset by

a $4.6 million decrease in other income and expense, net related to the recognition of $5.3 million of equity earnings on deferred regulatory asset balances as a result of the OPUC SRRM Order in the first quarter of 2015.

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Dividends

Dividend highlights include:


	Three Months Ended September 30,				Nine Months Ended September 30,				QTR		YTD		Three Months Ended March 31,
Per common share	2015		2014		2015		2014		Change				2016		2015		QTR Change
Dividends paid	$	0.465	$	0.460	$	1.395	$	1.380	$	0.005	$	0.015	$	0.4675	$	0.4650	$	0.0025

The Board of Directors declared a quarterly dividend on our common stock of $0.4675 cents per share, payable on ~~November~~May 13, ~~2015,~~2016, to shareholders of record on ~~October 30, 2015,~~April 29, 2016, reflecting an indicated annual dividend rate of $1.87 per share.

~~ISSUES AND CHALLENGES~~RESULTS OF OPERATIONS

~~ECONOMY.~~ The local, national, and global economies continue to show signs of improvement. The unemployment rate in the Portland metropolitan region decreased to just over 5% during the third quarter of 2015, a decrease of about 1% from the same period in 2014. The utility’s customer base is approximately 707,000 customers, reflecting a growth rate of 1.5% on a trailing 12-month basis at September 30, 2015, up from 1.3% at September 30, 2014. We continue to believe our utility is well positioned to add customers and serve increasing demand as the economy improves and gas prices remain low, as regional business projects move forward, and legislation focused on lowering carbon emissions continues to develop.Regulatory Matters

~~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 and secure more stable gas costs for customers. We typically hedge gas prices on approximately 75% of our utility’s annual sales requirement based on normal weather, including both physical and financial hedges. We entered the 2014-15 gas year (November 1, 2014 – October 31, 2015) hedged at approximately 75% of our forecasted sales volumes, including 41% in financial swap and option contracts, 22% in physical gas supplies, and 12% in gas reserves. 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 70% for the upcoming 2015-16 gas year and between 6% and 15% for the following five gas years as of September 30, 2015. Our hedge levels are based on estimated sales volumes, which depend, to a certain extent, on weather and economic conditions. Our gas reserves amounts may increase or decrease depending on production and investment levels. 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 business by lowering the price of, and reducing the demand for, storage services, particularly at our Gill Ranch facility. Our Mist facility benefits from a more constrained regional supply system in the Pacific Northwest region and is impacted, to a lesser extent, by market fluctuations. Despite current market conditions, we continue to believe in the long-term need for gas storage in and around California and anticipate improvement in gas storage values driven by California's renewable portfolio standards and carbon reduction targets.

Gill Ranch storage contracts for the 2014-15 gas storage year were at historically low prices due to the flat natural gas price curve and generally weak market conditions, which negatively impacted our financial results. While prices for the 2015-16 gas year showed some improvement; they still remain low relative to the pricing in our original long-term contracts. We will begin contracting for the 2016-17 storage year in the fourth quarter of 2015 and continue to expect shorter contract lengths and prices reflecting current market trends. We are continuing to focus on lowering our operating costs, finding opportunities in the market to increase revenues through enhanced services for storage customers, and capitalizing on market opportunities that fit our business-risk profile. Future increases in the demand for natural gas or a decrease in supply could improve the market value for gas storage. Similarly, a decrease in future demand and an increase in supply could cause downward pressure on storage prices. See "Results of Operations—Business Segments—~~Gas Storage"~~.

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~~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 and recover certain costs pursuant to regulatory orders, including our SRRM, as noted in "Regulatory Matters—Rate Mechanisms—~~Environmental Cost Deferral" below. In addition, environmental cost recovery and carrying charges on amounts charged to Washington customers will be determined in a future proceeding.~~

~~REGULATORY MATTERS~~

Regulation and Rates

UTILITY. Our utility business is subject to regulation by the OPUC, ~~the~~ WUTC, and ~~the Federal Energy Regulatory Commission (FERC)~~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. ~~At December 31, 2014, approximately~~Approximately 89% of our utility gas volumes and revenues ~~are~~were derived from Oregon customers, with the remaining 11% from Washington customers. Earnings and cash flows from utility operations are

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largely determined by rates set in general rate cases and other ~~rate~~ proceedings in Oregon and ~~Washington, but~~Washington. They 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~~Proceeding Updates"" below.

GAS STORAGE. Our gas storage ~~businesses are~~business is subject to regulation by the OPUC, ~~California Public Utilities Commission (CPUC),~~WUTC, 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~~accounts, and ~~CPUC~~ regulate intrastate storage ~~services, and the~~services. The FERC regulates interstate storage services. The ~~OPUC and~~ FERC ~~use~~uses 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~~last regulatory filing. The OPUC Schedule 80 rates are tied to the FERC rates, and are updated whenever we modify our FERC maximum rates. 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 ~~2014,~~2015, approximately ~~69%~~72% of our storage revenues were derived from ~~operations~~FERC, Oregon, and Washington regulated ~~by OPUC and FERC,~~operations and approximately ~~31% were derived~~28% from ~~operations regulated by CPUC.~~California operations.

~~Ongoing Regulatory Activities~~Most Recent General Rate Cases

~~The following provides a list of significant regulatory activities:~~

~~Environmental Cost Deferral and Site Remediation and Recovery Mechanism~~OREGON. ~~(SRRM)~~ Effective November 1, 2012, the OPUC authorized rates to customers based on an ROE of 9.5%, an overall rate of return of 7.78%, and a capital structure of 50% common equity and 50% long-term debt.

WASHINGTON- . Effective January 1, 2009, the WUTC authorized rates to customers based on an ROE of 10.1% and an overall rate of return of 8.4% with a capital structure of 51% common equity, 5% short-term debt, and 44% long-term debt.

FERC.We are required under our Mist interstate storage certificate authority and rate approval orders to file every five years either a petition for rate approval or a cost and revenue study to change or justify maintaining the existing rates for our interstate storage services. In December 2013 we filed a rate petition, which was approved in 2014 and allows for the maximum cost-based rates for our interstate gas storage services. These rates were effective January 1, 2014, with the rate changes having no significant impact on our revenues.

Regulatory Proceeding Updates

During the first quarter of 2016, we were involved in the regulatory activity discussed below.

ENVIRONMENTAL COST DEFERRAL AND SITE REMEDIATION AND RECOVERY MECHANISM (SRRM).In February 2015, as part of the implementation of the SRRM, the OPUC issued an ~~order regarding~~Order (2015 Order) requiring us to forego collection of $15 million out of approximately $95 million in total environmental remediation expenses and associated carrying costs the ~~SRRM for recovering prudently incurred environmental site remediation costs~~Company had deferred through ~~customer billings, subject to~~2012 based on the OPUC’s determination of how an earnings ~~test. We submitted~~test should apply to amounts deferred from 2003 to 2012, with adjustments for other factors the ~~required compliance filing~~OPUC deemed relevant. As a result, we recognized a $15.0 million non-cash charge in ~~March~~operations and maintenance expense in the first quarter of 2015. Also, as a result of the 2015 ~~and also filed a motion for clarification regarding~~Order, we recognized $5.3 million pre-tax of interest income related to the ~~amount~~equity earnings on our deferred environmental expenses in the first quarter of ~~insurance proceeds to be held in a secured account, and in September 2015,~~2015.

In addition, the OPUC issued ~~an order adopting an all-party settlement~~a subsequent Order regarding our SRRM (2016 Order) in January 2016 in which the ~~secured account. In September 2015,~~OPUC: (1) disallowed the recovery of $2.8 million of interest earned on the previously disallowed environmental expenditure amounts; (2) clarified the state allocation of 96.68% of environmental remediation costs for all environmental sites to Oregon; and (3) confirmed our treatment of $13.8 million of expenses put into the SRRM amortization account was correct and in compliance with prior OPUC orders. As a result of the 2016 Order, we ~~withdrew~~recognized a $3.3 million non-cash charge, of which $2.8 million is reflected in other income and expense, net and $0.5 million is included in operations and maintenance expense. See Note 13 regarding our ~~original filing after discussions with parties and submitted a revised compliance filing. The revised compliance filing is subject to review and approval by the OPUC. See "Rate Mechanisms—~~SRRM.

SYSTEM INTEGRITY PROGRAM (SIP).~~Environmental Cost Deferral and SRRM."~~

~~System Integrity Program (SIP)~~ - We filed a request to extend the SIP program in the fourth quarter of 2014. The OPUC considered our renewal request at a public meeting in March 2015 and suspended our filing and ordered additional process, including involvement of other gas utilities in the state, before making a final decision. In 2016, we withdrew our request to extend the SIP program, which is pending OPUC approval, and remain focused on establishing guidelines for future safety cost trackers with the OPUC. See "Rate Mechanisms—System Integrity Program" below.

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~~Hedging~~HEDGING. - In our most recent Integrated Resource Plan, we proposed to the OPUC that we engage in continued long-term gas hedging. The OPUC ~~determined it wanted to consider~~is considering long-term hedging along with a general review of overall hedging practices among all gas utilities in the state. The OPUC therefore opened a new docket to discuss broader gas hedging practices across gas utilities in Oregon. Our request for the OPUC to consider long-term hedging practices will be considered as part of this docket. The ~~scope~~OPUC established that this docket will follow two phases. The first phase will be focused on an analytical review of hedging and hedging practices, followed by a second phase regarding potential hedging guidelines. After these phases, a status report will be submitted to the OPUC, and the remainder of the ~~proceeding, and the~~ process ~~through which it~~ will be ~~accomplished~~determined at that time.

The Washington Utilities and Transportation Commission (WUTC) also is ~~being developed at this time through meetings among~~conducting an investigation into the hedging practices of gas utilities operating in Washington, and considering whether it should require gas utilities to implement certain practices related to hedging. The WUTC has asked for comments from all parties by May of 2016, and will determine next steps in the ~~involvement of the OPUC.~~

docket after reviewing those comments.

~~Interstate Storage Sharing~~ INTERSTATE STORAGE AND OPTIMIZATION SHARING- .We received an ~~order~~Order from the OPUC in March 2015 on their review of 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. The ~~order~~Order requires a third-party cost study to be performed and the results of the cost study may initiate a new docket or the re-opening of the original docket.

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~~Carbon Solutions Program~~ CARBON SOLUTIONS PROGRAM.- Oregon Senate Bill 844 (SB 844) required the OPUC to develop rules and programs to reduce carbon emissions in Oregon. In June 2015, we submitted our first project related to Combined Heat and Power (CHP) for OPUC approval. The submitted CHP program would pay owners of new commercial- and industrial-scale CHP systems for verified carbon emission reductions. ~~SB 844 establishes a six-month review process~~In April 2016, the OPUC issued an order declining our program as submitted and provided guidance on program structure for ~~these programs or allows for a longer review process if agreed upon. A final decision regarding CHP is expected in the first quarter of 2016.~~potential future submissions.

~~Weather Normalization Mechanism~~WEATHER NORMALIZATION MECHANISM (WARM). - In Oregon, WARM is applied to residential and commercial customers' bills to adjust for temperature variances from average weather. In 2015, the OPUC initiated a review of the WARM mechanism as a result of customer complaints received this year related to surcharges applied under the WARM mechanism due to the record warm weather in our service territory during the 2014-15 winter. The OPUC review is focused on ensuring the calculations were done correctly, and to assess whether any modifications to the mechanism are ~~warranted. We~~necessary. Based on the scope of this proceeding established by the Commission, we do not ~~currently~~ expect this proceeding to significantly reduce the value WARM provides to us or our customers in mitigating the impact ~~to the Company and customers~~ from variations in weather, based on the scope of the proceeding that has been established by the Commission. Since its inception, WARM has resulted in a net benefit to customers, providing bill savings of approximately $9.9 million as of September 30, 2015.weather.

Rate Mechanisms

PURCHASED GAS ADJUSTMENT. Rate changes are established ~~annually~~for the utility each year under PGA ~~rate filings~~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 bare steel recovery program,~~ temporary rate adjustments, ~~that~~which amortize balances of deferred regulatory accounts, and the removal of temporary rate adjustments effective for the previous year.

Each year, we typically hedge gas prices on approximately 75% of our utility's annual sales requirement based on normal weather, including both physical and financial hedges. We ~~filed~~entered the 2015-16 gas year (November 1, 2015 - October 31, 2016) hedged at 75% of our ~~PGA~~forecasted sales volumes, including 44% in ~~September 2015~~financial swap and ~~received OPUC~~option contracts and ~~WUTC approval~~31% in ~~October 2015. PGA rate changes~~physical gas supplies.

In addition to the amount hedged for the current gas contract year, we are ~~effective November 1, 2015. The rate changes decreased~~also hedged in future years at approximately 43% for the ~~average monthly bills~~2016-17 gas year and between 5% and 16% for annual requirements over the following five gas years as of ~~residential customers by approximately 7%~~March 31, 2016. Our hedge levels are subject to change based on actual load volumes, which depend to a certain extent on weather, economic conditions, and ~~14% in Oregon and Washington, respectively. The~~estimated gas reserve production. Also, our storage inventory levels may increase or decrease ~~in Oregon reflected customers' portion of adjustments for~~with storage expansion, changes in ~~wholesale natural gas costs, offset~~storage contracts with third parties, and/orstorage recall by ~~adjustments related to~~ the decoupling mechanism, environmental costs, and additional annual adjustments based on ongoing orders with the OPUC. Washington rates reflected the full effect of changes in wholesale natural gas costs and some additional annual adjustments based on ongoing orders with the WUTC.utility.

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 and 2015-16 gas years, we

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selected the 90% and 80% deferral option, 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.

EARNINGS TEST REVIEW. We are subject to an annual earnings review in Oregon to determine if the utility is earning above its authorized ROE ~~threshold; this is a separate earnings review from the environmental earnings test.~~threshold. If utility earnings exceed a specific ROE ~~threshold,~~level, then 33% of the amount above that level is required to be deferred ~~for refund~~or refunded to customers. Under this provision, if we select the 80% deferral gas cost option, ~~under the PGA,~~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 ~~2014-2015~~2014-15 PGA year, and we selected the 80% deferral option for the 2015-16 PGA year. The ROE threshold is subject to adjustment annually based on movements in long-term interest rates. For ~~the~~calendar years 2014 ~~calendar year,~~and 2015, the ROE threshold was 10.66%. and 10.60%, respectively. There were no refunds required for 2013 and 2014. We ~~filed~~do not expect a refund for 2015 based on our results and anticipate filing the ~~2014~~2015 earnings test in ~~April 2015, which was approved by the Commission in July 2015, and we were not subject to a customer refund adjustment.~~May 2016.

GAS RESERVES.In 2011 the OPUC approved the Encana gas reserve transaction to provide long-term gas price protection for our utility customers and determined our costs under the agreement would be recovered, on an ongoing basis through our annual PGA mechanism. Gas produced from our interests is sold at then prevailing market prices, and revenues from such sales, net of associated operating and production costs and amortization, are credited to our cost of gas. The cost of gas, including a carrying cost for the rate base investment made under the original agreement, is included in

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our annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our net investment under the original agreement earns a rate of ~~return and provides long-term price protection for our utility customers.~~return.

In March 2014, we amended the original gas ~~reserve~~reserves agreement in order to facilitate Encana's proposed sale of its interest in the Jonah field to Jonah Energy. Under the amendment, we ended the drilling program with Encana, but increased our working interests in our assigned sections of the Jonah ~~field and we~~field. We also retained the right to invest in new wells with Jonah Energy.

~~In 2014~~ Under the amended agreement we have the option to invest in additional wells on a well-by-well basis with drilling costs and resulting gas volumes shared at our amended proportionate working interest for each well in which we invest. We elected to participate in some of the additional wells drilled in ~~the Jonah field under our amended gas reserves agreement with Jonah Energy~~2014, and may have the opportunity to participate in more wells in the future. ~~We filed an application requesting regulatory deferral in Oregon for~~Volumes produced from these ~~additional investments, which was granted in April 2015. In September 2015, the OPUC adopted an all-party settlement, under which volumes produced under the amended agreement~~wells are included in our Oregon PGA ~~beginning November 1, 2015~~ at a fixed rate of $0.4725 per therm, which approximates the 10-year hedge rate plus financing costs at the inception of the investment. See Note 10.

DECOUPLING. In Oregon, we have a decoupling mechanism. Decoupling is intended to break the link between utility earnings and the quantity of gas consumed by customers, removing any financial incentive by the utility to discourage customers’ efforts to conserve energy. The Oregon decoupling mechanism was reauthorized and the baseline expected usage per customer was set in the 2012 Oregon general rate case. This mechanism employs a use-per-customer decoupling calculation, which adjusts margin revenues to account for the difference between actual and expected customer volumes. The margin adjustment resulting from differences between actual and expected volumes under the decoupling component is recorded to a deferral account, which is included in the annual PGA filing. In Washington, customer use is not covered by such a tariff. See "Business Segments—Local Gas Distribution Utility Operations" below.

WEATHER NORMALIZATION TARIFF. In Oregon, we have an approved weather normalization mechanism, which is applied to residential and commercial customer bills. This mechanism is designed to help stabilize the collection of fixed costs by adjusting residential and commercial customer billings based on temperature variances from average weather, with rate decreases when the weather is colder than average and rate increases when the weather is warmer than average. The mechanism is applied to bills from December through May of each heating season. The mechanism adjusts the margin component of customers’ rates to reflect average weather, which uses the 25-year average temperature for each day of the billing period. Daily average temperatures and 25-year average temperatures are based on a set point temperature of 59 degrees Fahrenheit for residential customers and 58 degrees Fahrenheit for commercial customers. This weather normalization mechanism was reauthorized in the 2012 Oregon general rate case without an expiration date. Residential and commercial customers in Oregon are allowed to opt out of the weather normalization mechanism, and as of March 31, 2016,9% of total customers had opted out. We do not have a weather normalization mechanism approved for residential and commercial Washington customers, which account for about 11% of total customers. See "Business Segments—Local Gas Distribution Utility Operations" below.

INDUSTRIAL TARIFFS. The OPUC and WUTC have approved tariffs covering utility service to our major industrial customers, including terms, which are intended to give us certainty in the level of gas supplies we need to acquire to serve this customer group. The terms include, among other things, an annual election period, special pricing provisions for out-of-cycle changes, and a requirement that industrial customers complete the term of their service election under our annual PGA tariff.

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SYSTEM INTEGRITY ~~PROGRAM.~~ PROGRAM (SIP).Until November of 2014, we had the approval of the OPUC for 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 recorded these costs as either capital expenditures, accumulated the costs over each 12-month period, and recovered the revenue requirement associated with these costs, subject to audit, through rate changes effective with the Oregon annual PGA. Our SIP costs were 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 could 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 above the cap during the extension period. Regulatory authority for SIP expired October 31, 2014, although the bare steel replacement portion of the mechanism ~~remains~~remained in place until the end of 2015. We filed a request to extend the SIP program in the fourth quarter of 2014 and ~~upon consideration of~~subsequently submitted a request to withdraw our request in ~~March~~the first quarter of ~~2015, the OPUC ordered an additional process and evaluation with other gas utilities in the state before making a final decision. In the interim, we~~2016. We will recover our remaining bare steel replacement costs through the 2015-16 PGA, and we expect system integrity capital costs not tracked through anour SIP mechanism would be included in rate base in our next rate case.

ENVIRONMENTAL COST DEFERRAL AND SRRM.~~On February 20, 2015,~~In Oregon, we have a SRRM through which we track and have the ~~OPUC issued an Order regarding the SRRM for recovering~~ability to recover prudently incurred past deferred and future environmental ~~site~~ remediation costs ~~through customer billings,~~allocable to Oregon, subject to an earnings test. The OPUC Order addressed a number of key issues including: (1) prudence of all but $33 thousand of costs incurred through March 31, 2014; (2) insurance settlements of approximately $150 million were deemed prudent with one-third of the Oregon-allocated proceeds applied to costs prior to December 31, 2012 and two-thirds to offset future environmental expenses; and (3) disallowed recovery of expenses totaling $15 million based on the OPUC's determination of how an earnings test should apply to costs for the years between 2003 and 2012, with adjustments for other factors the OPUC deemed relevant.

~~With respect to recovery~~The SRRM defines three classes of deferred environmental remediation expense:

Pre-review - This class of costs represents remediation spend that has not yet been deemed prudent by the OPUC. Carrying costs on these remediation expenses ~~deferred after 2012: (1)~~are recorded at our authorized cost of capital. We ~~will recover~~anticipate the ~~first $5 million~~prudence review for annual costs and approval of annual expense through a tariff rider from Oregon customers; (2) we will apply $5 million of insurance proceeds plus interest to environmental expenses each year; and (3) any expenditures and interest on expenditures above the $10 million (plus interest) described above would be fully recoverable through the SRRM, to the extent the utility earns at or below its authorized ROE. To the extent the utility earns more than its authorized ROE in a year, the utility is required to cover environmental expenses and interest on expenses greater than the $10 million (plus interest from insurance proceeds) with those earnings ~~that exceed its authorized ROE.~~

In any year environmental expenses are less than $10 million (plus the interest on insurance), any unused tariff rider amount will offset deferred amounts otherwise collected through the SRRM and any unused insurance proceeds (plus interest) will roll forward to offset the next year’s expenses. Under the Order,test prescribed by the OPUC ~~will revisit~~to occur by the deferral and amortization of future remediation expenses, as well as the treatment of remaining insurance proceeds three years from February 2015 or earlier if we gain greater certainty about our future remediation costs.

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~~We submitted the required compliance filing in March 2015 with the OPUC demonstrating the proposed implementation~~third quarter of the ~~Order~~following year.

Post-review - This class of costs represents remediation spend that has been deemed prudent and ~~SRRM. In September 2015, as~~allowed after applying the earnings test, but is not yet included in amortization. We earn a ~~result of discussions with the parties, we withdrew our original compliance filing and submitted~~carrying cost on these amounts at a revised filing noting the parties could potentially raise two issues with our proposed implementation of the Order. First, we believe the February 2015 Order reflected the Commission’s determination of the total disallowance to be borne by NW Natural for prior periods; however, we anticipate the parties will question whether interest on the $15 million charge should be separately disallowed. This interest would total approximately $3 million. Second, we anticipate discussions concerning how state allocation rates from the Order are applied to our environmental remediation sites. However, we believe the effect on current regulatory deferrals related to the state allocation issue would be insignificant.

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

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

Amortization - This class of costs represents amounts included in current customer rates for collection and is generally calculated as one-fifth of the post-review deferred balance. We earn a carrying cost equal to the amortization rate determined annually by the OPUC, which approximates a short-term borrowing rate. We included $8.4 million ~~on a pre-tax basis.~~of deferred remediation expense approved by the OPUC for collection during the 2015-2016 PGA year.

The SRRM earnings test is an annual review of our adjusted Utility ROE compared to our authorized Utility ROE, which is currently 9.5%. To apply the earnings test first we must determine what, if any, costs are subject to the test through the following calculation:

Annual spend

Less: $5 million tariff rider⁽¹⁾

Prior year carry-over⁽²⁾

$5 million insurance + interest on insurance

Total deferred annual spend subject to earnings test

Less: over-earnings adjustment, if any

Add: deferred interest on annual spend⁽³⁾

Total amount transferred to post-review


⁽¹⁾	Tariff rider went into Oregon customer rates beginning November 1, 2015.


⁽²⁾	Prior year carry-over results when the prior year amount transferred to post-review is negative. The negative amount is carried over to offset annual spend in the following year.


⁽³⁾	Deferred interest is added to annual spend to the extent the spend is recoverable.

If the adjusted Utility ROE is greater than the authorized Utility ROE, then we could be required to expense up to the amount that results in the Utility earning its authorized ROE. For 2015, we have performed this test, which will be submitted to the OPUC in May 2016, and have concluded there is no earnings test adjustment for 2015.

The WUTC has also previously authorized the deferral of environmental costs, if any, that are appropriately allocated to Washington customers. This ~~order~~Order was effective in January 2011 with cost recovery and a carrying charge to be determined in a future proceeding.

PENSION COST DEFERRAL AND ~~PREPAID~~ PENSION ~~ASSET.~~BALANCING ACCOUNT. ~~In Oregon, we are allowed~~Effective January 1, 2011, the OPUC approved our request 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~~above the amount ~~included and recovered~~set in ~~customer rates. Recovery~~rates, with recovery of ~~the~~these 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.~~interest on the account balance at the utility’s authorized rate of return, which is currently 7.78%. Future years’ deferrals will

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depend on changes in plan assets and projected benefit liabilities based on a number of key assumptions, and our pension contributions. Pension expense deferrals, including interest, were $1.6 million and $2.2 million as of March 31, 2016 and ~~$6.5 million for the~~ ~~three and nine months endedSeptember 30, 2015, respectively.~~

A prepaid pension asset docket was opened in 2013 to evaluate pension cost recovery for all utilities in Oregon. The utilities 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. In August 2015, the OPUC issued the final Order, which confirmed the use of accounting expense for recovery of pension expense, but denied the utilities' request to include prepaid pension assets in rates. Although we will not recover the financing costs associated with the prepaid asset, we will continue collecting pension expense based on the amounts set in our 2003 Oregon general rate case and will continue deferring the difference between actual pension expense and collected expense in our pension balancing account.respectively.

CUSTOMER CREDITS FOR GAS STORAGE ~~AND ASSET MANAGEMENT~~ SHARING. In ~~the second quarter of 2015,~~2016, we ~~received~~filed for regulatory approval to ~~provide~~refund an interstate storage credit of ~~$9.6~~$9.7 million to ~~our~~ Oregon utility ~~customers, which was reflected in their June bills.~~customers. These ~~customer~~ credits are part of our regulatory incentive sharing mechanism related to non-utility Mist storage and asset management ~~services.~~service. The OPUC approved ~~and we provided an $11.4~~a $9.6 million interstate storage credit to Oregon customers in June ~~of 2014.~~2015. The Washington portion of these credits is included ~~with~~in the Washington PGA.

For a discussion of other rate mechanisms, see Part II, Item 7, ~~“Results~~"Results of Operations—Regulatory Matters—

"Rate Mechanisms”" in our ~~2014~~2015 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, by 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~~"Regulatory Matters—Rate ~~Mechanisms” in our~~ ~~2014~~Mechanisms" ~~Form 10-K for more information on our decoupling and weather normalization mechanisms.~~above.

Utility segment highlights include:

Three Months Ended September 30, Nine Months Ended September 30, QTR Change YTD Change
In thousands, except per share data 2015 2014 2015 2014
Utility net income (loss) $ (7,529 ) $ (8,808 ) $ 23,051
$ 29,416
$ 1,279
$ (6,365 )
EPS - utility segment $ (0.28 ) $ (0.32 ) $ 0.84
$ 1.08
$ 0.04
$ (0.24 )
Gas sold and delivered (therms) 154,664
152,329
692,527
766,799
2,335
(74,272 )
Utility margin⁽¹⁾
$ 51,619
$ 50,134
$ 252,935
$ 250,223
$ 1,485
$ 2,712



	Three Months Ended March 31,
Dollars and therms in thousands, except EPS data	2016		2015		QTR Change
Utility net income	$	35,852	$	28,335	$	7,517
EPS - utility segment	1.30		1.04		0.26
Gas sold and delivered (in therms)	372,549		329,977		42,572
Utility margin⁽¹⁾	$	136,664	$	130,601	$	6,063


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

THREE MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~MARCH 31, 2015. ~~Utility net loss was $1.3 million lower due~~The primary factors contributing to the ~~following:~~$7.5 million or $0.26 per share increase in utility net income were as follows:

a ~~$1.5~~$6.1 million increase in utility margin primarily due to:


◦▪	a ~~$0.9~~$3.4 million increase from customer growth, added loads under higher commercial rate schedules, and added rate-base returns on certain investments; and


◦▪	a ~~$0.5~~$2.4 million increase from gas cost incentive sharing resulting from lower gas prices than those estimated in the PGA.

a ~~$0.6~~$7.8 million decrease in other income and expense, net primarily due to a $2.8 million interest write-off as a result of the 2016 Order from the OPUC in the first quarter of 2016 and the recognition of $5.3 million of equity earnings on deferred regulatory asset balances in February 2015; and

a $14.7 million decrease in operations and maintenance expense, primarily due to ~~less contract work expense;~~

~~a $0.7~~the $15.0 million ~~decrease in interest expense due to the redemption of long-term utility debt totaling $50 million since the beginning of September 2014; and~~

~~a $0.3 million net negative impact from the following offsetting items: an increase in depreciation expense, a decrease in other income, and a decrease in general tax expense.~~

~~NINE MONTHS ENDED SEPTEMBER 30, 2015 COMPARED TO SEPTEMBER 30, 2014.~~ ~~Utility net income decreased $6.4 million due to the following:~~

~~the $15 million pre-tax charge, or $9.1 million after-tax charge, for the~~ regulatory disallowance ~~associated with~~charge taken in the ~~February 2015 OPUC Order on the recovery of past environmental cost deferrals. This charge is reflected in operations and maintenance expense;~~

~~a $2.7 million increase in utility margin primarily due to:~~


◦	~~a $4.0 million increase from customer growth in residential and commercial customers, added loads under higher commercial rate schedules, and rate-base returns on certain investments;~~


◦	~~a $4.3 million increase from gas cost incentive sharing resulting from lower gas prices than those estimated in the PGA; offset by~~


◦	an approximate $4 million decrease due to lower customer usage from warmer weather, which impacts utility margins from our Washington customers where we do not have a weather normalization mechanism in place, and from our Oregon customers who opted out of weather normalization; and


◦	~~a $1.7 million decrease from a number of other items primarily related to cost deferrals.~~

~~a $4.8 million increase in other income primarily due to the recognition of the equity earnings on deferred environmental expenditures as a result of the February order;~~

~~a $2.1 million decrease in interest expense due to the redemption of long-term utility debt;~~

30prior year.

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~~a $4.7 million increase in operations and maintenance expense primarily due to an increase in compensation and benefit expense;~~

~~a $1.5 million increase in depreciation expense primarily due to planned capital expenditures; and~~

~~a $0.7 million increase in general tax expense primarily due to increases in Oregon property tax expense.~~

Total utility volumes sold and delivered in the ~~three months ended September 30, 2015~~first quarter of 2016 increased ~~2% due to greater customer usage and customer growth compared to~~13% over the same period in ~~2014. For the nine months ended September 30,~~ 2015 ~~volumes decreased 10% compared to the nine months ended September 30, 2014~~primarily due to the impact of relatively colder weather quarter over quarter. Weather in the first quarter of 2016 was 15% warmer ~~weather.~~than average, compared to the record warm weather in 2015, which was 20% warmer than average.

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


	Three months ended						Nine months ended						Favorable/						Three Months Ended March 31,						Favorable/(Unfavorable)
In thousands, except degree day and customer data	September 30,						September 30,						(Unfavorable)						2016			2015			QTR Change
	2015			2014			2015			2014			QTD			YTD

Utility volumes (therms):
Residential and commercial sales	53,662			49,843			357,545			420,532			3,819			(62,987		)	242,874			206,817			36,057
Industrial sales and transportation	101,002			102,486			334,982			346,267			(1,484		)	(11,285		)	129,675			123,160			6,515
Total utility volumes sold and delivered	154,664			152,329			692,527			766,799			2,335			(74,272		)	372,549			329,977			42,572
Utility operating revenues:
Residential and commercial sales	$	73,236		$	68,369		$	432,067		$	451,557		$	4,867		$	(19,490	)	$	237,672		$	240,912		$	(3,240	)
Industrial sales and transportation	15,959			15,588			53,623			53,955			371			(332		)	17,664			20,526			(2,862		)
Other revenues	651			602			3,188			3,245			49			(57		)	1,411			1,406			5
Less: Revenue taxes	2,371			2,198			12,206			12,826			173			(620		)	6,643			6,538			105
Total utility operating revenues	87,475			82,361			476,672			495,931			5,114			(19,259		)	250,104			256,306			(6,202		)
Less: Cost of gas	35,856			32,227			223,737			245,708			3,629			(21,971		)	108,411			125,705			17,294
Less: Environmental remediation expense																			5,029			—			(5,029		)
Utility margin	$	51,619		$	50,134		$	252,935		$	250,223		$	1,485		$	2,712		$	136,664		$	130,601		$	6,063
Utility margin:⁽¹⁾
Residential and commercial sales	$	43,312		$	42,267		$	225,624		$	226,839		$	1,045		$	(1,215	)	$	123,484		$	120,372		$	3,112
Industrial sales and transportation	7,233			6,962			22,065			22,153			271			(88		)	8,201			7,574			627
Miscellaneous revenues	647			684			3,186			3,550			(37		)	(364		)	1,406			1,406			—
Gain (loss) from gas cost incentive sharing	431			(84		)	1,992			(2,345		)	515			4,337
Gain from gas cost incentive sharing																			3,654			1,221			2,433
Other margin adjustments	(4		)	305			68			26			(309		)	42			(81		)	28			(109		)
Utility margin	$	51,619		$	50,134		$	252,935		$	250,223		$	1,485		$	2,712		$	136,664		$	130,601		$	6,063
Degree days:
Degree days
Average⁽²⁾	95			95			2,641			2,641			—			—			1,871			1,855			16
Actual degree days	75			18			2,068			2,438			317		%	(15		)%
Percent colder (warmer) than average weather⁽²⁾	(21		)%	(81		)%	(22		)%	(8		)%
Actual																			1,585			1,481			7		%
Percent warmer than average weather⁽²⁾																			(15		)%	(20		)%

	As of September 30,																		As of March 31,
Customers - end of period:	2015			2014			Change			% Change									2016			2015			Change
Residential customers	640,313			629,627			10,686			1.7		%							650,268			640,235			10,033
Commercial customers	65,305			65,337			(32		)	—									66,748			66,314			434
Industrial customers	948			938			10			1.1									993			923			70
Total number of customers	706,566			695,902			10,664			1.5		%							718,009			707,472			10,537
Customer growth:
Residential customers																			1.6		%
Commercial customers																			0.7		%
Industrial customers																			7.6		%
Total customer growth																			1.5		%


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


⁽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			Three Months Ended March 31,
In thousands	2015			2014		2015		2014								2016			2015		QTR Change
Utility volumes (therms):
Volumes (therms):
Residential sales	28,303			26,235		215,018		255,471		2,068			(40,453		)	155,232			130,060		25,172
Commercial sales	25,359			23,608		142,527		165,061		1,751			(22,534		)	87,642			76,757		10,885
Total volumes	53,662			49,843		357,545		420,532		3,819			(62,987		)	242,874			206,817		36,057
Utility operating revenues:
Operating revenues:
Residential sales	$	44,721		$	41,907	$	281,033	$	294,119	$	2,814		$	(13,086	)	$	160,700		$	160,537	$	163
Commercial sales	28,515			26,462		151,034		157,438		2,053			(6,404		)	76,972			80,375		(3,403		)
Total operating revenues	$	73,236		$	68,369	$	432,067	$	451,557	$	4,867		$	(19,490	)	$	237,672		$	240,912	$	(3,240	)
Utility margin:
Residential:
Sales	$	27,647		$	26,341	$	138,187	$	154,293	$	1,306		$	(16,106	)	$	81,661		$	70,776	$	10,885
Weather normalization adjustments	—			—		12,492		489		—			12,003
Decoupling adjustments	1,149			1,738		5,318		2,145		(589		)	3,173
Weather normalization																9,231			12,353		(3,122		)
Decoupling																(3,935		)	1,205		(5,140		)
Total residential utility margin	28,796			28,079		155,997		156,927		717			(930		)	86,957			84,334		2,623
Commercial:
Sales	12,736			12,180		56,997		64,487		556			(7,490		)	30,905			27,755		3,150
Weather normalization adjustments	(2		)	—		5,213		296		(2		)	4,917
Decoupling adjustments	1,782			2,008		7,417		5,129		(226		)	2,288
Weather normalization																3,746			5,244		(1,498		)
Decoupling																1,876			3,039		(1,163		)
Total commercial utility margin	14,516			14,188		69,627		69,912		328			(285		)	36,527			36,038		489
Total utility margin	$	43,312		$	42,267	$	225,624	$	226,839	$	1,045		$	(1,215	)	$	123,484		$	120,372	$	3,112

THREE MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~MARCH 31, 2015. ~~Residential~~The primary factors contributing to changes in the residential and commercial ~~utility variances~~markets were as follows:

sales volumes increased ~~3.8~~36.1 million therms, or17%, primarily ~~due to greater customer usage~~reflecting 7% colder weather and customer ~~growth during the quarter;~~growth;

operating revenues ~~increased $4.9~~decreased $3.2 million ~~primarily~~ due to a ~~7% increase~~24% decrease in average cost of ~~gas;~~gas over last year, partially offset by a 17% increase in sales volumes; and

utility margin increased ~~$1.0~~$3.1 million due to ~~increases from commercial and~~both residential ~~customer growth, added loads under higher commercial rate schedules, and added rate-base returns on certain investments.~~

~~NINE MONTHS ENDED SEPTEMBER 30, 2015 COMPARED TO SEPTEMBER 30, 2014.~~ ~~Residential~~ and commercial ~~utility variances were as follows:~~

~~sales volumes decreased 63.0 million therms primarily due to 15% warmer weather compared to prior year;~~

~~operating revenues decreased $19.5 million primarily due to 15% warmer weather, partially offset by a 6% increase in average cost of gas; and~~

utility margin decreased $1.2 million primarily due to the effects of warmer weather on customers not covered by a weather normalization mechanism. The effect of weather was partially offset by increases from commercial and residential customer ~~growth, added loads under higher commercial rate schedules, and added rate-base returns on certain investments.~~growth.

Industrial Sales and Transportation

Industrial customers have the option of purchasing sales or transportation services from the utility. Under the sales service, the customer buys the gas commodity from the utility. Under the transportation service, the customer buys the gas commodity 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

~~Table of Contents~~

decision to purchase gas from us or from third parties. Industrial and large commercial customers may also select between firm and interruptible service options, 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 service election on November 1, special charges for changes between elections, and in some cases, ~~meeting~~ a minimum or maximum volume requirement before changing options.

Table of Contents

Industrial sales and transportation highlights include:


	Three Months Ended September 30,				Nine Months Ended September 30,				QTR Change			YTD Change			Three Months Ended March 31,
In thousands	2015		2014		2015		2014								2016		2015		QTR Change
Volumes (therms):
Industrial - firm sales	7,352		7,469		23,308		25,034		(117		)	(1,726		)	9,424		8,651		773
Industrial - firm transportation	29,149		32,067		104,773		111,893		(2,918		)	(7,120		)	44,201		40,828		3,373
Industrial - interruptible sales	14,739		15,146		51,984		56,829		(407		)	(4,845		)	15,050		16,392		(1,342	)
Industrial - interruptible transportation	49,762		47,804		154,917		152,511		1,958			2,406			61,000		57,289		3,711
Total volumes	101,002		102,486		334,982		346,267		(1,484		)	(11,285		)	129,675		123,160		6,515
Utility margin:
Industrial - firm and interruptible sales	$	3,259	$	3,179	$	9,641	$	9,775	$	80		$	(134	)	$	3,163	$	3,217	(54	)
Industrial - firm and interruptible transportation	3,974		3,783		12,424		12,378		191			46			5,038		4,357		681
Total utility margin	$	7,233	$	6,962	$	22,065	$	22,153	$	271		$	(88	)
Industrial - sales and transportation															8,201		7,574		627

THREE MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~MARCH 31, 2015. ~~Industrial~~ The primary factors contributing to changes in the industrial sales and transportation markets were as follows:

utility margin ~~increase was largely~~increased $0.6 millionprimarily due to an increase in industrial customers under higher margin rate schedules.

~~NINE MONTHS ENDED SEPTEMBER 30, 2015 COMPARED TO SEPTEMBER 30, 2014.~~ Industrial sales and transportation volumes decreased 11.3 million therms primarily due to lower usage from warmer weather and lower demand from a few large volume transportation customers on lower margin rate schedules. Margin decreased $0.1 million due to higher fee revenues in the prior year from increased usage from the cold weather event in February 2014, partially offset by an increase in industrial customers under higher margin rate schedules.

Cost of gas as reported by the utility includes gas purchases, gas withdrawn from storage inventory, gains and losses from commodity hedges, pipeline demand costs, seasonal demand cost balancing adjustments, regulatory gas cost deferrals, gas reserves costs, 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;~~purchases; however, in Oregon we have an incentive sharing mechanism which has been described under ~~“Regulatory~~"Regulatory Matters—Rate Mechanisms—Purchased Gas ~~Adjustment~~Adjustment" ” above. In addition to the PGA incentive sharing mechanism, gains and losses from hedge contracts entered into after annual PGA rates are effective 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 the gas reserves acquired under the original agreement with Encana and include gas from our amended gas reserves agreement at a fixed rate of $0.4725 per therm, which are also reflected in utility margin.See ~~Part II, Item 7, “Application~~"Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging ~~Activities~~Activities" ~~” and “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment~~” in our ~~2014~~2015 Form ~~10-K for additional information, as well as~~ ~~Note 12~~ ~~in this report.~~

Cost of gas highlights include:

Volumes sold (therms)⁽¹⁾

Average cost of gas (cents per therm)⁽¹⁾

Gain from gas cost incentive sharing⁽²⁾

THREE MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~ ~~Cost of gas increased $3.6 million or 11% primarily due to a 7% increase in average cost of gas.~~

~~NINE MONTHS ENDED SEPTEMBER 30, 2015 COMPARED TO SEPTEMBER 30, 2014.~~MARCH 31, 2015. Cost of gas decreased ~~$22.0~~$17.3 million,or 9%14% primarily due to a ~~14%~~24% decrease in ~~sales volume due to warmer weather, partially~~average cost of gas reflecting lower market prices for natural gas, offset by a 6%15% increase ~~average cost of gas.~~in volumes from colder weather compared to the prior year.

Due to the extreme cold weather event in February 2014, we experienced a record sendout and consequently, the higher volumes of gas purchased at higher gas prices at that time resulted in a margin loss in 2014 compared to a margin gain thus far in 2015 as prices were lower due to the record warmer weather. 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% undivided 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 our utility and non-utility storage and transportation capacity, the results of which are included in ~~this~~the gas storage businesses segment.

Gas storage segment highlights include:

THREE MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~MARCH 31, 2015. ~~Gas~~Our gas storage segment net income increased ~~$0.8~~$0.6 million primarily due to a $0.8 million increase in operating revenues from slightly higher contract prices for the 2015-16 gas storage year and a $0.5 million decrease in operating expenses due to lower compensation expenses and property taxes at our Gill Ranch facility.

~~NINE MONTHS ENDED SEPTEMBER 30, 2015 COMPARED TO SEPTEMBER 30, 2014.~~ ~~Gas storage net income increased $0.4 million due to a $1.4~~$0.6 million decrease in operating expenses from lower ~~repair~~general, administrative, and power costs at our Gill Ranch facility and a ~~$0.9~~$0.4 million decrease in interest expense ~~related to~~from the early retirement of $20 million of Gill Ranch's debt in ~~June of 2014. These decreases were offset by a $1.4 million reduction in operating revenues mainly due to lower contract prices for the 2014-15~~December 2015.

Our Mist gas storage ~~year.~~facility benefits from limited competition from other Pacific Northwest storage facilities primarily because of its geographic location. 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. We ~~contracted capacity~~have completed our contracting for the ~~2014-15~~2016-17 gas storage year ~~with shorter-term contracts at lower market prices than~~and have seen a slight improvement in ~~previous years, which contributed~~pricing compared to the ~~decline in~~2015-16 gas storage ~~operating revenues.~~

~~Our gas storage segment financial results have been negatively impacted by the decline in market conditions, particularly at~~For our Gill Ranch ~~facility. Our Mist~~ facility, benefits from a more constrained regional supply system in the Pacific Northwest region and is impacted to a lesser extent from market fluctuations. Despite current market conditions, we continue to believe in the long-term need for gas storage in California and anticipate improvement in gas storage values driven by California's renewable portfolio standards and carbon reduction targets.

~~Prices~~prices for the 2015-16 and 2016-17 gas ~~year showed~~years have shown improvement, and may continue to show improvement in future years, however ~~remained~~they remain low relative to the pricing in our original long-term ~~contracts.~~contracts, which ended primarily in the 2013-14 gas storage year. In the future, we may also see ~~an improvement 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, an increase in use of alternative fuels to meet carbon emission 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 storage market conditions in and around California. These factors, if they occur, may contribute to higher summer/winter natural gas price spreads, gas price volatility, and gas storage values. We are continuing to explore opportunities to increase revenues through enhanced services for storage customers and capitalizing on opportunities that fit our business-risk profile. Should storage values not improve in the future, this could have a negative impact on our future cash flows and could result in impairment of our Gill Ranch gas storage facility. Refer to Note 2 in our ~~2014~~2015 Form 10-K for more information regarding our accounting policy for impairment of long-lived assets.

In addition, in October 2015 a significant natural gas leak occurred at a southern California gas storage facility that persisted in early 2016. At this time, we do not know the long-term effects of this incident on gas storage prices. Regulatory proceedings at both the national and California state level have been opened in response to the incident, and it is likely additional regulations will result in increased costs for all storage providers.

Other ~~business activities~~ primarily ~~consist~~consists of NNG Financial's equity investment in KB Pipeline, an equity investment in TWH, which has invested in the Trail West pipeline project, and other miscellaneous non-utility ~~investments. Contributions from~~investments and business activities. There were no significant changes in our other ~~businesses produced less than $0.1 million~~activities in the first quarter of net income for the three months ended September 30, 2015 and 2014. For the nine months ended September 30, 2015 our other businesses produced just over $0.1 million compared to $0.3 million for the same period in 2014.2016. See Note 4 and Note 11 for further details on ~~our~~ other activities and our investment in TWH.

Consolidated Operations

Operations and Maintenance

Operations and maintenance highlights include:

THREE MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~MARCH 31, 2015. Operations and maintenance expense decreased ~~$0.9~~$15.2 million, primarily due to the ~~following:~~

~~NINE MONTHS ENDED SEPTEMBER 30, 2015 COMPARED TO SEPTEMBER 30, 2014.~~ ~~Operations and maintenance expense increased $18.4 million due to the following:~~following factors:

Delinquent customer receivable balances ~~and bad debt expense~~ continue to remain at historically low levels. The utility's annualized bad debt expense as a ~~percentage~~percent of revenues was ~~0.1%~~0.2% for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 and has remained well below 0.5% of revenues ~~every year~~ since 2007.

Other Income and ~~Expense,~~(Expense), Net

Other income and ~~expense,~~(expense), net highlights include:

THREE MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~MARCH 31, 2015. Other income ~~increased $0.3~~and expense, net, decreased $7.4 million primarily due to a decrease in regulatory interest expense from the application of insurance proceeds under the SRRM, partially offset by a decrease in interest income from environmental assets accruing interest at a lower rate under the SRRM.

~~NINE MONTHS ENDED SEPTEMBER 30, 2015 COMPARED TO SEPTEMBER 30, 2014.~~ ~~Other income increased $4.9 million~~ due to the recognition of ~~a net~~ $5.3 million ~~related to~~of the equity ~~earnings included~~component in interest income from our deferred environmental ~~expenses.~~expenses in the prior year which did not recur in 2016. We ~~realized~~recognized the equity earnings onof these deferred regulatory asset balances as a result of the OPUC SRRM Order we received in February 2015. ~~Offsetting the $5.3 million was~~In addition, a ~~$0.4 million decrease in interest income primarily from environmental assets accruing interest at a lower rate under the SRRM offset in part by a decrease in regulatory interest expense~~subsequent Order from the ~~application~~OPUC in the first quarter of ~~insurance proceeds under the SRRM.~~2016 resulted in a write-off of $2.8 million of interest in 2016.

Interest Expense, Net

Interest expense, net highlights include:

THREE ~~AND NINE~~ MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~MARCH 31, 2015. Interest expense, net of amounts capitalized, decreased ~~$0.7~~$0.8 million ~~for the quarter and $3.0 million for the nine month period~~primarily due to the redemption of $40 million of utility ~~FMBs~~First Mortgage Bonds (FMBs) in June 2015 ~~$60 million of utility FMBs in 2014,~~ and the early retirement of $20 million of Gill Ranch's debt in ~~June 2014.~~December 2015.

Income tax expense highlights include:

THREE ~~AND NINE~~ MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~ MARCH 31, 2015.Increases or decreases in income tax expense are correlated with changes in pre-tax income. Additionally, ~~there was a $0.6 million income~~2015 tax ~~charge in~~expense benefited from the ~~first quarter of 2014 due to the revaluation~~realization of deferred ~~tax balances related to a higher effective tax rate in Oregon.~~depletion benefits from 2013 and 2014.

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, and with a target utility capital structure of 50% common stock and 50% long-term debt. When additional capital 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~~Resources"” below and Note 6.6.

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

Liquidity and Capital Resources

At ~~September 30, 2015~~,March 31, 2016 we had ~~$5.2~~$4.3 million of cash and cash equivalents compared to ~~$8.3~~$5.2 million at ~~September 30, 2014~~.March 31, 2015. We ~~also had $4.5 million and~~did not have restricted cash at March 31, 2016 compared to $3.0 million in restricted cash at ~~Gill Ranch at~~ ~~September 30,~~March 31, 2015 ~~and~~ ~~2014, respectively, which is~~ held as collateral for the long-term debt ~~outstanding.~~outstanding at Gill Ranch, which we retired in December 2015. In order to maintain sufficient liquidity during periods when capital markets are volatile, we may elect to maintain higher cash balances and add 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.

For the utility segment, the short-term borrowing requirements typically peak during colder winter months when the utility borrows money to cover the lag between natural gas purchases and bill collections from customers. Our 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, short-term 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~~"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 we are not able to issue new debt due to adverse market conditions or other reasons, we expect our ~~near term~~near-term liquidity needs can be met using internal cash flows or, for the utility segment, drawing upon our committed credit facility. We also have a universal shelf registration statement 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, 2015,~~March 31, 2016, we have Board authorization to issue up to $325 million of additional ~~FMB's.~~FMBs. We also have OPUC approval to issue up to $325 million of additional long-term debt for approved purposes.

In the event 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~~other forms of collateral, which could expose us to additional cash requirements and may trigger increases in short-term borrowings while we were in a net loss position. We were not near the threshold for posting collateral at ~~September 30, 2015.~~March 31, 2016. However, if the credit risk-related contingent features underlying these contracts were triggered on ~~September 30, 2015,~~March 31, 2016, assuming our long-term debt ratings dropped to non-investment

grade levels, we could have been required to post ~~$22.1~~$15.6 million of collateral to our counterparties. See ~~"Credit Ratings"~~"Credit Ratings" below and Note 12.

Other items that may have a significant impact on our liquidity and capital resources include pension contribution requirements, expiration of bonus tax depreciation and environmental ~~expenditures and insurance recoveries. See "Cash Flows—Operating Activities" below.~~expenditures.

With respect to pensions, we expect to make significant contributions to our company-sponsored defined benefit plan, which is closed to new employees, over the next several years until we are fully funded under the Pension Protection Act rules, including the new rules issued under the Moving Ahead for Progress in the 21st Century Act (MAP-21) and the Highway and Transportation Funding Act of 2014 (HATFA). See ~~"Cash Flows—~~"Application of Critical Accounting Policies—~~Operating Activities~~Accounting for Pensions and Postretirement Benefits" ~~below for expected contribution amounts.~~in the 2015 Form 10-K.

Gas Storage ~~Segment~~

Short-term liquidity for the gas storage segment is supported by cash balances, internal cash flow from operations, ~~external financing, and funds~~equity contributions from its parent ~~company. The abundant supply of natural gas, low volatility of natural gas prices,~~company, and, ~~available gas storage capacity, particularly in California, have recently resulted in lower storage market prices than we have seen in previous years.~~ if necessary, additional external financing.

The amount and timing of our Gill Ranch facility's cash flows from year to year are uncertain, as the majority of these storage contracts are currently short-term. We have seen slightly higher contract prices for the 2015-16 and 2016-17 storage ~~year,~~years, but overall prices are still ~~significantly~~ lower than the long-term contracts that expired at the end of the 2013-14 storage year. ~~As such,~~While we expect continuing challenges for Gill Ranch in ~~2015 causing negative cash flows from operations in 2015. We~~2016, 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 collateralized debt, with a fixed interest rate of 7.75% on $20 million and a variable interest rate on the remaining $20 million, with a maturity date of November 30, 2016. Under the debt agreement, Gill Ranch was subject to certain covenants and restrictions. We have amended this agreement twice, which resulted in repayment of the $20 million variable-rate outstanding debt during the second quarter of 2014, suspension of the EBITDA covenant requirement through the maturity date, and maintenance of a debt reserve account, which was fixed at $4.5 million as of June 30, 2015, and is required to increase by $1.5 million on each of January 30, 2016 and August 30, 2016. In addition, under the amended agreement, Gill Ranch was required to receive common equity contributions from its parent NWN Gas Storage of at least $2 million by August 31, 2015 and complied with this requirement. Additionally, Gill Ranch is required to receive equity contributions from its parent of at least $4 million by August 31, 2016. The senior collateralized debt is secured by all of the membership interests in Gill Ranch and is nonrecourse to us and other entities in 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 our liquidity is sufficient to meet anticipated near-term cash requirements, including all contractual obligations, investing, and financing activities discussed below.

Our primary source of utility short-term liquidity is from ~~internal cash flows and~~ the sale of commercial ~~paper.~~paper and bank loans. In addition to issuing commercial paper or bank loans 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 isand bank loans are 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. In the fourth quarter of 2015, we entered into a short-term credit facility totaling $50 million, as a short-term bridge through our peak heating season, which was repaid on February 4, 2016.

At ~~September 30,~~March 31, 2016 and 2015, ~~and~~ ~~2014~~, our utility had ~~commercial paper~~short-term debt outstanding of ~~$225.2~~$164.9 million and ~~$190.0~~$156.2 million,, respectively. The effective interest rate on ~~the utility’s commercial paper~~short-term debt outstanding at ~~September 30,~~March 31, 2016 and 2015 was 0.8% and ~~2014~~ ~~was~~ 0.4% ~~and 0.3%~~, respectively.

We have a $300 million ~~revolving~~ credit ~~facility,~~agreement, with a feature that allows usthe Company to request increases in the total commitment amount, up to a maximum of $450 million. The ~~final~~ maturity date of the agreement is in December 20, 2019.

All lenders under the agreement are major financial institutions with committed balances and investment grade credit ratings as of ~~September 30, 2015~~March 31, 2016 as follows:

Lender rating, by category, in millions

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

Our credit agreement permits the issuance of letters of credit in an aggregate amount of up to $100 million. Any principal and unpaid interest amounts owed on borrowings under the credit ~~agreements~~agreement is due and payable on or before the maturity date. There were no outstanding balances under this credit agreement at ~~September 30, 2015~~March 31, 2016 or ~~2014~~.2015. 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,~~March 31, 2016 and 2015, ~~and~~ ~~2014~~, with consolidated indebtedness to total capitalization ratios of ~~52.7~~%48.5% and ~~53.1%~~50.8%, 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~~”"Credit Ratings" below.

Our credit ratings are a factor of our liquidity, potentially affecting our access to the capital markets including the commercial paper market. Our credit ratings also have an impact on the cost of funds and the need to post collateral under derivative contracts. ~~There were no changes in our credit ratings during the quarter.~~ The following table summarizes our current debt ~~ratings from S&P and Moody’s:~~



	S&P	Moody's
Commercial paper (short-term debt)	A-1	P-2
Senior secured (long-term debt)	AA-	A1
Senior unsecured (long-term debt)	n/a	A3
Corporate credit rating	A+	n/a
Ratings outlook	Stable	Stable

The above 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

We ~~redeemed $40~~did not retire any debt in the first quarter of 2016. Over the next twelve months, $25 million of ~~FMB's~~FMBs with a coupon rate of ~~4.70%~~5.15% and maturity in ~~June 2015. There~~December 2016 are ~~no scheduled redemptions in the coming twelve months.~~expected to be redeemed.

See Part II, Item 7, "Financial Condition—Contractual Obligations”" in our ~~2014~~2015 Form 10-K for long-term debt maturing over the next five years.

Operating Activities

~~Year-over-year changes~~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~~THREE MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~MARCH 31, 2015. ~~Cash provided by~~The significant factors contributing to the $27.9 million increase in operating ~~activities decreased $42.1~~cash flows were as follows:

The non-cash pension expense recognized on the income statement for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 was ~~$4.2~~$1.3 million, compared to ~~$3.8~~$1.5 million for the same period in ~~2014.~~2015. Changes in pension expense are 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~~three months ended ~~September 30, 2015,~~March 31, 2016, we contributed ~~$11.8~~$2.9 million to our utility's qualified defined benefit pension plan, compared to ~~$10.5~~$2.6 million for the same period in ~~2014. We plan to make $2.3 million in contributions during the remainder of~~ 2015. The amount and timing of future contributions will depend ~~to a certain extent,~~ on market interest rates and investment returns on the ~~plan's assets, and future federal funding requirements.~~plans’ assets. See Note 7.

Bonus income tax depreciation of 50 percent has been available in recent years, resulting in net operating loss (NOL) carryforwards that are available to reduce current year taxable income. Bonus tax depreciation expired at the end offor 2014 and ~~has~~2015 was not ~~yet been~~ enacted ~~for 2015. We anticipate taxable income for~~until December 19, 2014 and December 17, 2015, ~~will be in excess~~respectively. In both cases it was extended retroactively back to January 1 of the ~~available NOL carryforwards, and as of~~ ~~September 30, 2015, an~~respective year. As a result, estimated income tax ~~prepaid balance~~payments were made throughout 2014 and 2015 without the benefit of ~~$8.8~~bonus depreciation for the year. This delayed the cash flow benefit of bonus depreciation until refunds could be requested and received. We received refunds of federal income tax overpayments of $2.0 million ~~has been recorded.~~and $7.9 million in the second quarter of 2015 and the first quarter of 2016, respectively.

The final tangible property regulations applicable to all taxpayers were issued on September 13, 2013 and are generally effective for taxable years beginning on or after January 1, 2014. In addition, procedural guidance related to the regulations was issued under which taxpayers may make accounting method changes to comply with the regulations. We have evaluated the regulations and do not anticipate any material impact. However, unit-of-property guidance applicable to natural gas distribution networks has not yet been issued and is expected byin the ~~end of 2015.~~near future. We will further evaluate the effect of these 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.~~regulations.

40We have lease and purchase commitments relating to our operating activities that are financed with cash flows from operations. For information on cash flow requirements related to leases and other purchase commitments, see “Financial Condition—Contractual Obligations” and Note 14 in the 2015 Form 10-K.

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Investing Activities

Investing activity highlights include:


	Nine Months Ended September 30,									Three Months Ended March 31,
In thousands	2015			2014			Change			2016			2015			QTR Change
Total cash used in investing activities	$	(88,242	)	$	(107,204	)	$	18,962		$	(30,030	)	$	(28,946	)	$	(1,084	)
Capital expenditures	(86,923		)	(86,552		)	(371		)	(30,054		)	(27,135		)	(2,919		)
Utility gas reserves	(1,165		)	(21,734		)	20,569

~~NINE~~THREE MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~MARCH 31, 2015. ~~Cash~~The $1.1 million increase in cash used in investing activities ~~decreased $19.0 million~~was primarily due to ~~lower investments in utility gas reserves, partially offset by~~ higher capital ~~expenditures at the utility.~~expenditures.

~~Under~~Over the ~~amended gas reserves agreement, we ended our original drilling program with Encana, but increased our assigned working interests~~five-year period 2016 through 2020, total utility capital expenditures are estimated to be between $850 and $950 million, including the Company's proposed investment in certain sections of the Jonah field. We continue to evaluate and make decisions whether or not to participate with Jonah Energy in additional wells drilled, and currently we do not expect to drill any additional wells in 2015. See Note 10 for additional information regarding the amended gas reserve agreement.

~~We received acknowledgment~~an expansion of our recently filed Integrated Resource Plan (IRP), which outlines long-term capital investments based on projected customer and infrastructure needs. Among other things, the IRP included projected infrastructure projects suchMist gas storage facility of approximately $125 million as well as continued refurbishments of the Newport Liquefied Natural Gas (LNG) facility in Oregon over the next three years with an expected investment of ~~ranging from $20 to~~approximately $25 million, and upgrading distribution infrastructure in Clark County, Washington, which could total approximately $25 million over the next five years. ~~In addition,~~We are currently rebidding the ~~IRP also included recall of non-utility~~engineering and construction contracts for our Mist expansion project, which could increase or decrease our estimated capital expenditures related to the Mist gas storage ~~capacity of 0.3 million therms per day of deliverability and 0.7 Bcf of associated storage capacity to serve core utility customer needs, which occurred on May 1, 2015. Finally,~~facility expansion. The full capital expenditure for the IRP discusses various changes to the resource portfolio and preserves the optionality of participating in both the Trail West and Pacific Connector interstate connector pipeline projects. These and other investments are included in our expected capital expenditures in Part II, Item 7, "Financial Condition—Cash Flows—~~Investing Activities” in the 2014 Form 10-K.~~

~~The utility plans to expand its North~~ Mist facility, supported by a contract with PGE to serve their gas-fired electric power generation facilities at Port Westward, which is located approximately 15 miles from Mist. In early 2015, the utility received authorization from PGE to begin permitting and land acquisition work. The estimated cost of the expansion is ~~approximately $125 million with a potential in-service date in 2018 or 2019. This project is subject to PGE's final approval of estimated projected costs and~~dependent upon receiving a notice to proceed from Portland General Electric, which we expect in the second half of 2016. The estimated level of utility capital expenditures over the next five years reflects assumptions for continued customer growth, technology investments, distribution system maintenance and improvements, and gas storage facilities maintenance. Most of the required funds are expected to be internally generated over the five-year period, and any remaining funding will be obtained through a combination of long-term debt and equity security issuances, with short-term debt and bridge financing providing liquidity.

In 2016, utility capital expenditures are estimated to be between $155 and $175 million, which includes $10 million to $15 million for our Mist expansion project, of which a significant portion is dependent upon receiving a notice to proceed from the project customer, and non-utility capital investments are estimated to be less than $5 million. Gas storage segment capital expenditures in 2016 are expected to be paid from working capital and additional equity contributions from NW Natural as ~~well as the utility's receipt of permits and certain land rights needed for the project.~~needed.

Financing Activities

Financing activity highlights include:

~~NINE~~THREE MONTHS ENDED ~~SEPTEMBER 30, 2015~~MARCH 31, 2016 COMPARED TO ~~SEPTEMBER 30, 2014.~~MARCH 31, 2015. ~~Cash~~The $22.4 million increase in cash used in financing activities ~~decreased $20.0 million~~was primarily due to the ~~receipt~~issuance of ~~approximately $91~~$26.6 million ~~of proceeds from our insurance settlements, which was used to reduce our short-term debt balance~~additional net commercial paper and short term loans in ~~the same period of 2014. In addition, we retired $40 million of utility FMBs during the first nine months of 2015~~2016 compared to ~~$80 million retired for the same period of 2014.~~2015.

Ratios of Earnings to Fixed Charges

For the ~~nine~~three and twelve months ended ~~September 30, 2015~~March 31, 2016 and the twelve months ended December 31, ~~2014~~,2015, our ratios of earnings to fixed charges, computed using the method ~~set forth in Item 503(d) of~~outlined by the ~~SEC's Regulation S-K,~~SEC, were ~~2.22~~, ~~3.02~~,7.02, 3.36, and ~~3.13~~,3.00, respectively. For this purpose, earnings consist of net income before income taxes plus fixed charges, ~~with~~and fixed charges ~~consisting~~consist of interest on all indebtedness, the amortization of debt expense and discount or premium ~~and expense,~~ and the estimated interest portion of rentals charged to income. See Exhibit 12 for the detailed ratio calculation.

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~~Application of Critical Accounting Policies and ~~Estimates”~~Estimates” in our ~~2014~~2015 Form 10-K. At ~~September 30, 2015, we had a net regulatory asset~~March 31, 2016, our total estimated liability related to environmental sites is $122.3 million. See Note 13 and "Results of $49.8 million for deferred environmental costs, which includes deferred payments and interest of $60.6 million and $88.9 million for additional costs expected to be paid in the future, partially offset by $99.7 million of insurance recoveries. 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~~Operations—Regulatory Matters—Rate Mechanisms—Environmental Costs".

APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES

In preparing our financial statements ~~using U.S.~~in accordance with 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:

~~See Note 2 for a discussion of the $15 million regulatory disallowance related to the SRRM Order received in February 2015.~~ There have been no material changes to the information provided in the ~~2014~~2015 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 ~~2014~~2015 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.

422.

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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~~three month period ended ~~September 30, 2015~~.March 31, 2016. See Part II, Item 1A, “Risk Factors” in this report and Part II, Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” in the ~~2014~~2015 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 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, 2015~~March 31, 2016 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 ~~2014~~2015 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 ~~2014~~2015 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, as amended, during the quarter ended ~~September 30, 2015~~:

~~ISSUER PURCHASES OF EQUITY SECURITIES~~March 31, 2016:


Issuer Purchases of Equity Securities							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⁾			Total Number of Shares Purchased⁽¹⁾	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽²⁾	Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs⁽²⁾
Balance forward				2,124,528	$	16,732,648					2,124,528	$	16,732,648
07/01/15 - 07/31/15	1,405	$	43.82	—	—
08/01/15 - 08/31/15	22,799	45.11		—	—
09/01/15 - 09/30/15	3,487	43.45		—	—
01/01/16-01/31/16								677	$	50.11	—	—
02/01/16-02/29/16								17,539	52.48		—	—
03/01/16-03/31/16								30,439	49.95		—	—
Total	27,691	$	44.84	2,124,528	$	16,732,648		48,655	50.87		2,124,528	$	16,732,648

⁽¹⁾

During the quarter ended ~~September 30, 2015, 24,298~~March 31, 2016, 20,725 shares of our common stock were purchased on the open market to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan. In addition, ~~3,393~~27,930 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, 2015~~,March 31, 2016, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.

⁽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, 2016 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, 2015~~,March 31, 2016, no shares of our common stock were ~~purchased~~repurchased 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~~May 3, ~~2015~~2016
		/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, 2015~~March 31, 2016



Exhibit Number	Document
~~10a~~	~~Deferred Compensation Plan for Directors and Executives effective January 1, 2005, restated effective as~~
10a.	Form of ~~September 24, 2015.~~ Director Restricted Stock Unit Award Agreement under the Long-Term Incentive Plan.

12	Statement ~~Re: Computation~~re computation of ~~Ratios~~ratios of ~~Earnings~~earnings to ~~Fixed Charges.~~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~~101.	The following materials from Northwest Natural Gas Company's Quarterly Report on Form 10-Q for the quarter ended ~~September 30, 2015,~~March 31, 2016, 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.



Oregon	93-0256722
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)



		Page

PART 1.	FINANCIAL INFORMATION

	Forward-Looking Statements	13

Item 1.	Unaudited Consolidated Financial Statements:

	Consolidated Statements of Comprehensive Income for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~	24

	Consolidated Balance Sheets at ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~ and December 31, ~~2014~~2015	35

	Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~	57

	Notes to Unaudited Consolidated Financial Statements	68

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	2325

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43

Item 4.	Controls and Procedures	43

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	44

Item 1A.	Risk Factors	44

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

Item 6.	Exhibits	44

	Signature	45


Stock price on valuation date	$	47.64		$	50.15
Performance term (in years)	3.0			3.0
Quarterly dividends paid per share	$	0.465		$	0.4675
Expected dividend yield	3.8		%	3.7		%
Dividend discount factor	0.8966			0.9010


	September 30,				December 31,		March 31,						December 31,
In thousands	2015		2014		2014		2016			2015			2015
Gross long-term debt							$	601,700		$	661,700		$	601,700
Unamortized debt issuance costs							(6,975		)	(8,289		)	(7,282		)
Carrying amount	$	621,700	$	661,700	$	661,700	$	594,725		$	653,411		$	594,418
Estimated fair value	697,647		748,902		756,808
Estimated fair value⁽¹⁾							686,159			762,554			667,168


			Credit Rating Downgrade Scenarios										Credit Rating Downgrade Scenarios
In thousands	(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3		Speculative		(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3		Speculative
With Adequate Assurance Calls	$	—	$	—	$	—	$	—	$	22,066	$	—	$	—	$	—	$	2,341	$	15,600
Without Adequate Assurance Calls	—		—		—		—		15,937		—		—		—		2,341		13,381


⁽¹⁾	Utility operating revenues include environmental recovery revenues, which are collections received from customers through our environmental recovery mechanism in Oregon, offset by environmental remediation expense.


⁽¹⁾	Estimated fair value does not include unamortized debt issuance costs.


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


⁽²⁾	For a discussion of our gas cost incentive sharing mechanism, see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment” above.


⁽¹⁾	Ratios reflect debt balances net of any unamortized debt issuance costs.


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