UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



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

For the quarterly period ended ~~September 30, 2012~~March 31, 2013



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

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

For the transition period from ~~_______ to _______~~

___________ to____________

Commission ~~File No.~~file number 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)



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

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

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (503) 226-4211

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes [ X ] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes [ X ] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer [ X ] Accelerated Filer [ ]



~~Large accelerated filer [ X ]~~	~~Accelerated filer [ ]~~
~~Non-accelerated filer [ ]~~	~~Smaller reporting company [ ]~~

Non-accelerated Filer [ ] Smaller Reporting Company [ ]

(Do not check if a ~~smaller reporting company)~~Smaller Reporting Company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [ ] No [ X ]

At ~~October~~April 26, ~~2012~~2013, ~~26,874,412~~26,948,572 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

NORTHWEST NATURAL GAS COMPANY

For the Quarterly Period Ended ~~September 30, 2012~~March 31, 2013

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		Page

PART I. 1.	FINANCIAL INFORMATION	~~Page Number~~

	Forward-Looking Statements	1

Item 1.	Consolidated Financial Statements:

	Consolidated Statements of Comprehensive Income for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2013 and 2012 ~~and 2011~~	2

	Consolidated Balance Sheets at ~~September 30,~~March 31, 2013 and 2012 ~~and 2011~~ and December 31, ~~2011~~2012	3

	Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2013 and 2012 ~~and 2011~~	5

	Notes to Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2022

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4140

Item 4.	Controls and Procedures	41

	PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	42

Item 1A.	Risk Factors	42

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42

Item 6.	Exhibits	42

	Signature	43

Table of Contents

~~Forward-Looking Statements~~FORWARD-LOOKING STATEMENTS

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

plans;

objectives;

goals;

strategies;

assumptions and estimates;

future events or performance;

trends;

timing and cyclicality;

earnings and dividends;

growth;

customer rates;

commodity costs;

gas reserves;

operational performance and costs;

efficacy of derivatives and hedges;

liquidity and financial positions;

project development and expansion;

competition;

~~storage levels~~procurement and ~~values;~~

~~procurement,~~ development ~~and production levels~~ of gas ~~supplies and reserves;~~supplies;

estimated ~~expenditures and investments;~~expenditures;

costs of compliance;

credit exposures;

potential efficiencies;

rate recovery and refunds;

impacts of laws, rules and regulations;

tax liabilities or refunds;

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

projected ~~status and~~ obligations under retirement plans;

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

approval and adequacy of regulatory deferrals; and

environmental, regulatory, litigation and insurance costs and recoveries.

Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks, and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are neither statements of historical fact nor guarantees or assurances of future performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements are discussed in our ~~2011~~2012 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.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Statements of Comprehensive Income
(Unaudited)

Three Months Ended Nine Months Ended

September 30, September 30,
Thousands, except per share amounts 2012 2011 2012 2011
Operating revenues:

Gross operating revenues $ 89,756
$ 93,313
$ 513,819
$ 577,598
Less: Cost of sales 37,586
43,133
241,869
313,880
Revenue taxes 2,255
2,397
12,688
14,195
Net operating revenues 49,915
47,783
259,262
249,523
Operating expenses:

Operations and maintenance 28,957
28,372
95,497
89,918
General taxes 7,473
7,514
23,726
22,338
Depreciation and amortization 18,281
17,449
54,330
52,304
Total operating expenses 54,711
53,335
173,553
164,560
Income (loss) from operations (4,796 ) (5,552 ) 85,709
84,963
Other income and expense - net 1,710
1,781
3,636
4,117
Interest expense - net 10,508
10,241
32,163
30,956
Income (loss) before income taxes (13,594 ) (14,012 ) 57,182
58,124
Income tax expense (benefit) (3,036 ) (5,700 ) 25,724
23,470
Net income (loss) (10,558 ) (8,312 ) 31,458
34,654
Other comprehensive income:

Amortization of non-qualified employee benefit plan liability, net of taxes of $108 and $95 for the three months and $325 and $287 for the nine months ended September 30, 2012 and 2011, respectively 167
146
499
438
Comprehensive income (loss) $ (10,391 ) $ (8,166 ) $ 31,957
$ 35,092
Average common shares outstanding:

Basic 26,847
26,686
26,813
26,676
Diluted 26,847
26,686
26,902
26,730
Earnings (loss) per share of common stock:

Basic $ (0.39 ) $ (0.31 ) $ 1.17
$ 1.30
Diluted $ (0.39 ) $ (0.31 ) $ 1.17
$ 1.30
Dividends declared per share of common stock $ 0.445
$ 0.435
$ 1.335
$ 1.305

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended
	March 31,
In thousands, except per share data	2013		2012

Operating revenues	$	277,861	$	309,639

Operating expenses:
Cost of gas	142,359		169,755
Operations and maintenance	33,757		34,432
General taxes	8,732		8,836
Depreciation and amortization	18,807		17,950
Total operating expenses	203,655		230,973
Income from operations	74,206		78,666
Other income and expense, net	520		472
Interest expense, net	11,127		11,191
Income before income taxes	63,599		67,947
Income tax expense	25,960		27,663
Net income	37,639		40,284
Other comprehensive income:
Amortization of non-qualified employee benefit plan liability, net of taxes of $151 for 2013 and $108 for 2012	233		166
Comprehensive income	$	37,872	$	40,450
Average common shares outstanding:
Basic	26,929		26,781
Diluted	26,973		26,862
Earnings per share of common stock:
Basic	$	1.40	$	1.50
Diluted	1.40		1.50
Dividends declared per share of common stock	0.455		0.445

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets (Unaudited)
CONSOLIDATED BALANCE SHEETS (UNAUDITED)										CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Thousands	September 30, 2012			September 30, 2011			December 31, 2011
In thousands											March 31, 2013			March 31, 2012			December 31, 2012

Assets:
Current assets:
Cash and cash equivalents	$	5,718		$	25,862		$	5,833			$	8,337		$	4,031		$	8,923
Accounts receivable	23,382			25,628			77,449				84,346			90,817			61,229
Accrued unbilled revenue	11,184			14,287			61,925				29,633			44,444			56,955
Allowance for uncollectible accounts	(1,985		)	(1,733		)	(2,895		)		(2,116		)	(3,694		)	(2,518		)
Regulatory assets	53,891			76,734			94,673				39,001			90,490			52,448
Derivative instruments	6,771			3,932			2,853				8,200			1,824			1,950
Inventories	73,188			83,581			74,363				52,004			61,436			67,602
Gas reserves	13,140			2,366			4,463				14,286			6,732			14,966
Income taxes receivable	1,787			5,019			7,045				2,033			1,735			2,552
Other current assets	10,825			14,871			22,980				12,441			13,075			19,592
Total current assets	197,901			250,547			348,689				248,165			310,890			283,699
Non-current assets:
Property, plant and equipment	2,755,729			2,632,498			2,661,102
Property, plant, and equipment											2,808,673			2,680,537			2,786,008
Less: Accumulated depreciation	798,510			756,592			767,226				824,561			779,683			812,396
Total property, plant and equipment - net	1,957,219			1,875,906			1,893,876
Total property, plant, and equipment, net											1,984,112			1,900,854			1,973,612
Gas reserves	75,925			28,125			47,451				100,169			61,106			84,693
Regulatory assets	367,692			328,757			371,392				384,453			364,132			382,255
Derivative instruments	5,608			227			—				2,836			52			3,639
Other investments	67,333			69,022			68,263				68,029			67,648			67,667
Restricted cash	4,000			—			4,000				4,000			4,000			4,000
Other non-current assets	14,690			15,256			12,903				14,735			14,191			13,555
Total non-current assets	2,492,467			2,317,293			2,397,885				2,558,334			2,411,983			2,529,421
Total assets	$	2,690,368		$	2,567,840		$	2,746,574			$	2,806,499		$	2,722,873		$	2,813,120

See Notes to Consolidated Financial Statements.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets (Unaudited)
CONSOLIDATED BALANCE SHEETS (UNAUDITED)										CONSOLIDATED BALANCE SHEETS (UNAUDITED)

Thousands	September 30, 2012			September 30, 2011			December 31, 2011
Capitalization and liabilities:
Capitalization:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,866, 26,703, and 26,756 at September 30, 2012 and 2011 and December 31, 2011, respectively	$	355,276		$	346,197		$	348,383
Retained earnings	369,584			356,574			373,905
Accumulated other comprehensive loss	(7,301		)	(6,166		)	(7,800		)
Total common stock equity	717,559			696,605			714,488
Long-term debt	641,700			601,700			641,700
Total capitalization	1,359,259			1,298,305			1,356,188
In thousands											March 31, 2013			March 31, 2012			December 31, 2012

Liabilities and equity:
Current liabilities:
Short-term debt	175,800			181,200			141,600				$	130,750		$	113,700		$	190,250
Current maturities of long-term debt	—			40,000			40,000
Accounts payable	61,327			50,117			86,300				77,007			60,165			85,613
Taxes accrued	10,269			11,117			10,747				10,262			10,509			9,588
Interest accrued	10,593			11,321			5,857				10,952			10,648			5,953
Regulatory liabilities	24,810			28,593			31,046				28,239			50,341			20,792
Derivative instruments	17,156			46,651			57,317				3,450			53,697			10,796
Other current liabilities	45,425			33,609			41,597				41,445			41,503			45,444
Total current liabilities	345,380			402,608			414,464				302,105			340,563			368,436
Long-term debt											691,700			641,700			691,700
Deferred credits and other non-current liabilities:
Deferred tax liabilities	430,885			394,217			413,209				467,360			436,750			444,377
Regulatory liabilities	288,097			266,907			278,382				293,135			288,131			288,113
Pension and other postretirement benefit liabilities	182,069			129,669			201,530				215,808			189,003			215,792
Derivative instruments	615			7,429			6,536				642			3,947			578
Other non-current liabilities	84,063			68,705			76,265				79,112			79,461			74,497
Total deferred credits and other non-current liabilities	985,729			866,927			975,922				1,056,057			997,292			1,023,357
Commitments and contingencies (see Note 13)											—			—			—
Total capitalization and liabilities	$	2,690,368		$	2,567,840		$	2,746,574
Equity:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,948, 26,798, and 26,917 at March 31, 2013 and 2012 and December 31, 2012, respectively											357,957			351,005			356,571
Retained earnings											407,738			399,946			382,347
Accumulated other comprehensive loss											(9,058		)	(7,633		)	(9,291		)
Total equity											756,637			743,318			729,627
Total liabilities and equity											$	2,806,499		$	2,722,873		$	2,813,120

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Cash Flows (Unaudited)
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)							CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended							Three Months Ended
	September 30,							March 31,
Thousands	2012			2011
In thousands								2013			2012

Operating activities:
Net income	$	31,458		$	34,654			$	37,639		$	40,284
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization	54,330			52,304				18,807			17,950
Deferred tax liabilities								25,797			26,879
Non-cash expenses related to qualified defined benefit pension plans	4,334			5,491				1,476			2,007
Contributions to qualified defined benefit pension plans	(23,500		)	(19,245		)		(1,400		)	(13,800		)
Deferred environmental expenditures - net of recoveries	(6,500		)	(7,018		)
Deferred environmental expenditures, net of recoveries								(4,482		)	(827		)
Other	2,612			(615		)		1,836			476
Changes in assets and liabilities:
Receivables	106,620			92,840				5,281			6,378
Inventories	1,175			(3,196		)		15,598			12,927
Taxes accrued	4,780			36,585				1,193			5,072
Accounts payable	(24,888		)	(33,369		)		(13,781		)	(26,050		)
Interest accrued	4,736			6,139				4,999			4,791
Deferred gas costs	(15,406		)	370				1,966			23,663
Deferred tax liabilities	24,503			22,908
Other - net	13,808			3,440
Other, net								11,189			14,304
Cash provided by operating activities	178,062			191,288				106,118			114,054
Investing activities:
Capital expenditures	(100,880		)	(70,036		)		(22,674		)	(20,447		)
Utility gas reserves	(41,775		)	(30,917		)		(12,257		)	(17,220		)
Restricted cash	—			924
Other	107			(192		)		(1,335		)	(68		)
Cash used in investing activities	(142,548		)	(100,221		)		(36,266		)	(37,735		)
Financing activities:
Common stock issued - net, including common stock expense	4,858			1,320
Long-term debt issued	—			50,000
Long-term debt redeemed	(40,000		)	(10,000		)
Common stock issued, net								1,115			1,458
Long-term debt retired								—			(40,000		)
Change in short-term debt	34,200			(76,235		)		(59,500		)	(27,900		)
Cash dividend payments on common stock	(35,779		)	(34,807		)		(12,248		)	(11,913		)
Other	1,092			1,060				195			234
Cash used in financing activities	(35,629		)	(68,662		)		(70,438		)	(78,121		)
Increase (decrease) in cash and cash equivalents	(115		)	22,405
Cash and cash equivalents - beginning of period	5,833			3,457
Cash and cash equivalents - end of period	$	5,718		$	25,862
Decrease in cash and cash equivalents								(586		)	(1,802		)
Cash and cash equivalents, beginning of period								8,923			5,833
Cash and cash equivalents, end of period								$	8,337		$	4,031

Supplemental disclosure of cash flow information:
Interest paid	$	27,427		$	24,817			$	6,128		$	6,148
Income taxes paid	$	2,333		$	1,522			—			101

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

~~PART I.~~NOTES TO CONSOLIDATED FINANCIAL ~~INFORMATION~~STATEMENTS (UNAUDITED)

~~Notes to Consolidated Financial Statements~~1. ORGANIZATION AND PRINCIPLES OF CONSOLIDATION

~~(Unaudited)~~


1.	~~Organization and Principles of Consolidation~~

The accompanying consolidated financial statements represent the consolidation of Northwest Natural Gas Company (NW Natural or the ~~Company or we)~~Company) and all companies that we directly or indirectly control, either through majority ownership or otherwise. 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) ~~and~~, NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), and NW Natural Gas Reserves, LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships that we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method or the cost method, which includes NWN Energy’s investment in Palomar Gas Holdings, LLC (PGH). and NNG Financial's investment in Kelso-Beaver (KB) Pipeline. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated financial statements are presented after elimination of all significant intercompany balances and transactions, except for amounts required to be included under regulatory accounting standards to reflect the effect of such regulation. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage business and other non-utility investments and business activities.

During the first quarter of 2013, we identified an error in the rate used to calculate interest on regulatory assets. We assessed the materiality of this error on prior period financial statements and concluded it was not material to any prior annual or interim periods; however, the cumulative impact would have been material to the interim period ending March 31, 2013, if corrected in 2013. As a result, in accordance with accounting standards, we have revised our prior period financial statements as shown in Note 14 to correct for this error.

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

Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments that management considers necessary for a fair statement 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 ~~2011~~2012 Annual Report on Form 10-K (~~2011~~2012 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.


2.	~~Significant Accounting Policies Update~~

2. SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are described in Note 2 of the ~~2011~~2012 Form 10-K. There were no material changes to those accounting policies during the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013. The following are current updates to certain critical accounting policy estimates and accounting standards in general. ~~See Note 14 for disclosures of subsequent events that occurred after September 30, 2012 but prior to issuance of this report.~~

Table of Contents

Regulatory Accounting

In applying regulatory accounting ~~principles~~ in accordance with generally accepted accounting principles in the United States of America ~~(U.S. GAAP)~~(GAAP), we capitalize or defer certain costs and revenues as regulatory assets and liabilities. At ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012 and at December 31, ~~2011~~2012, the amounts deferred as regulatory assets and liabilities were as follows:

~~Table of Contents~~

~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~


Regulatory Assets
Thousands	September 30, 2012		September 30, 2011		December 31, 2011
							Regulatory Assets
							March 31,				December 31,
In thousands							2013		2012		2012
Current:
Unrealized loss on derivatives⁽¹⁾	$	17,156	$	46,651	$	57,317	$	3,450	$	53,697	$	10,796
Pension and other postretirement benefit liabilities⁽²⁾	15,491		10,988		15,491		17,247		15,491		17,247
Other⁽³⁾	21,244		19,095		21,865		18,304		21,302		24,405
Total current	$	53,891	$	76,734	$	94,673	$	39,001	$	90,490	$	52,448
Non-current:
Unrealized loss on derivatives⁽¹⁾	$	615	$	7,429	$	6,536	$	642	$	3,947	$	578
Pension balancing⁽²⁾	13,134		3,989		6,008		17,322		8,367		14,727
Income tax asset	58,437		70,241		65,264		53,065		63,452		55,879
Pension and other postretirement benefit liabilities⁽²⁾	158,894		110,007		170,512		178,377		166,639		182,688
Environmental costs⁽⁴⁾	128,173		122,454		105,670		125,671		108,007		121,144
Other⁽³⁾	8,439		14,637		17,402		9,376		13,720		7,239
Total non-current	$	367,692	$	328,757	$	371,392	$	384,453	$	364,132	$	382,255


Regulatory Liabilities
Thousands	September 30, 2012		September 30, 2011		December 31, 2011
							Regulatory Liabilities
							March 31,				December 31,
In thousands							2013		2012		2012
Current:
Gas costs	$	10,069	$	16,991	$	17,994	$	8,694	$	35,584	$	9,100
Unrealized gain on derivatives⁽¹⁾	6,771		3,932		2,853		8,054		1,824		1,950
Other⁽³⁾	7,970		7,670		10,199		11,491		12,933		9,742
Total current	$	24,810	$	28,593	$	31,046	$	28,239	$	50,341	$	20,792
Non-current:
Gas costs	$	596	$	1,250	$	8,420	$	1,407	$	14,462	$	—
Unrealized gain on derivatives⁽¹⁾	5,608		227		—		2,836		52		3,639
Accrued asset removal costs	278,897		263,123		267,355		285,437		270,837		281,213
Other⁽³⁾	2,996		2,307		2,607		3,455		2,780		3,261
Total non-current	$	288,097	$	266,907	$	278,382	$	293,135	$	288,131	$	288,113


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


⁽²⁾	Certain utility pension costs ~~of the utility~~ are approved for regulatory deferral, including amounts recorded to the pension balancing account, to mitigate the effects of higher and lower pension expenses. Pension costs that are deferred include an interest component when recognized in net periodic benefit ~~costs or earn a rate of return or carrying charge (see~~ costs. See Note 8)7.


⁽³⁾	Other primarily consists of several deferrals and amortizations under other approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge.

⁽⁴⁾

Environmental costs ~~are related~~relate to ~~those~~specific sites ~~that are~~ approved for regulatory ~~deferral.~~deferral by the Public Utility Commission of Oregon (OPUC) and Washington Utilities and Transportation Commission (WUTC). In Oregon, we earn a ~~rate of return~~carrying charge on amounts paid, whereas amounts accrued but not yet paid do not earn a ~~rate of return or a~~ carrying charge until expended. ~~Environmental costs related to~~In Washington, ~~were deferred beginning in 2011, with cost recovery and~~ a carrying charge related to deferred amounts will be determined in a future proceeding. In the 2012 Oregon general rate case, the OPUC authorized a Site Remediation and Recovery Mechanism (SRRM) that allows the Company to recover prudently incurred environmental costs, subject to an earnings test that will be defined in a rate proceeding that is currently underway. See Note 13.

Table of Contents

~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~

New Accounting Standards

Adopted Standards

~~There were no new accounting standards adopted during the third quarter of 2012.~~

~~Recent Accounting Pronouncements~~

~~Balance Sheet Offsetting.~~BALANCE SHEET OFFSETTING. In December 2011, the Financial Accounting Standards Board (FASB) issued authoritative guidance regarding the offsetting of assets and liabilities on the balance sheet. The standard is intended to provide more comparable guidance between the ~~U.S.~~ GAAP and international accounting standards by requiring entities to disclose both gross and net amounts for assets and liabilities offset on the balance sheet as well as other disclosures concerning their enforceable master netting arrangements. This guidance is effective for annual reporting periods beginning on or after January 1, ~~2013, and we do not expect~~2013. The adoption of this standard todid not have a material effect on our financial statement disclosures. See Note 12 for our full disclosure.

RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME. In February 2013, FASB issued authoritative guidance, which requires an entity to present significant amounts reclassified from each component of accumulated other comprehensive income (AOCI). This standard is intended to improve the reporting of these reclassifications by consolidating the information concerning amounts reclassified into net income from AOCI, which has been presented throughout the financial statements. This guidance is effective for reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material effect on our financial statement disclosures. See Note 7 for our full disclosures.

Recent Accounting Pronouncements

There were no significant accounting standards issued during the first quarter of 2013.

Subsequent Events

There are no subsequent events to report for the period ended March 31, 2013.


3.	~~Earnings Per Share~~

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 ~~using~~in the same manner, except it uses the weighted-average number of common shares outstanding plus the ~~potential~~ effects of the assumed exercise of stock options, and payment of estimated stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Diluted earnings per share are calculated as follows:


	Three Months Ended						Nine Months Ended				Three Months Ended
	September 30,						September 30,				March 31,
Thousands, except per share amounts	2012			2011			2012		2011
In thousands, except per share data											2013		2012
Net income	$	(10,558	)	$	(8,312	)	$	31,458	$	34,654	$	37,639	$	40,284
Average common shares outstanding - basic	26,847			26,686			26,813		26,676		26,929		26,781
Additional shares for stock-based compensation plans outstanding (See Note 6)	—			—			89		54
Additional shares for stock-based compensation plans outstanding											44		81
Average common shares outstanding - diluted	26,847			26,686			26,902		26,730		26,973		26,862
Earnings per share of common stock - basic	$	(0.39	)	$	(0.31	)	$	1.17	$	1.30	$	1.40	$	1.50
Earnings per share of common stock - diluted	$	(0.39	)	$	(0.31	)	$	1.17	$	1.30	$	1.40	$	1.50

Additional information:
Anti-dilutive shares excluded from net income per diluted common share calculation	107			63			—		3		32		1


4.	~~Segment Information~~

4. SEGMENT INFORMATION

We operate in two primary reportable business segments, local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which we ~~refer to~~aggregate and report as ~~“utility” and “gas storage.~~“other.” We refer to our local gas ~~storage~~distribution business as the “utility,” and ~~other~~our “gas storage” and “other” business segments as “non-utility.” Our utility segment includes NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp and the utility portion of our Mist facility. Our gas storage segment ~~includes:~~includes NWN Gas ~~Storage;~~Storage, which is a wholly-owned subsidiary of NWN Energy, Gill ~~Ranch;~~Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility ~~portions~~portion of our Mist underground storage facility in Oregon (Mist);, and ~~revenues from~~all third-party asset management services. ~~Other investments and business activities, which we refer to as~~Our “other”~~, primarily~~ segment includes NNG Financial and ~~our~~NWN Energy's equity ~~investment in PGH. For the periods presented, intersegment transactions were insignificant. For further discussion of our segments, see Note 4 in our~~ ~~2011~~ ~~Form 10-K.~~

Table of Contents

~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~investment in PGH, which is pursuing development of a cross-Cascades pipeline project. See Note 4 in our 2012 Form 10-K for further discussion of our segments.

The following table presents summary financial information ~~about~~concerning the reportable ~~segments for the~~ ~~three and nine months endedSeptember 30, 2012~~ ~~and~~ ~~2011~~:

segments. Inter-segment transactions are insignificant:

Three Months Ended Three Months Ended September 30,

Non-Utility
Thousands Utility Gas Storage Other Total
2012

Net operating revenues $ 42,331
$ 7,544
$ 40
$ 49,915
Depreciation and amortization 16,661
1,620
—
18,281
Income (loss) from operations (8,439 ) 3,624
19
(4,796 )
Net income (loss) (11,853 ) 1,255
40
(10,558 )
2011

Net operating revenues $ 41,034
$ 6,710
$ 39
$ 47,783
Depreciation and amortization 15,875
1,574
—
17,449
Income (loss) from operations (8,029 ) 2,458
19
(5,552 )
Net income (loss) (9,518 ) 1,160
46
(8,312 )



	Three Months Ended Three Months Ended March 31,
In thousands	Utility		Gas Storage		Other			Total
2013
Operating revenues	$	269,659	$	8,146	$	56		$	277,861
Depreciation and amortization	17,188		1,619		—			18,807
Income from operations	70,228		3,957		21			74,206
Net income (loss)	36,031		1,636		(28		)	37,639
Capital expenditures	22,388		286		—			22,674
Total assets at March 31, 2013	2,501,724		288,795		15,980			2,806,499
2012
Operating revenues	$	302,905	$	6,679	$	55		$	309,639
Depreciation and amortization	16,338		1,612		—			17,950
Income from operations	75,964		2,679		23			78,666
Net income	39,468		806		10			40,284
Capital expenditures	19,656		791		—			20,447
Total assets at March 31, 2012	2,420,194		286,756		15,923			2,722,873

Total assets at December 31, 2012	2,505,655		291,568		15,897			2,813,120

Utility margin is a financial measure consisting of utility operating revenues less the associated cost of gas. By netting fluctuating costs of gas from utility operating revenues, utility margin provides a key metric used by our chief operating decision maker in assessing the performance of the utility segment. The following table presents additional segment information concerning utility margin. The gas storage and other segments emphasize growth in operating revenues and net income as opposed to margin because these segments do not incur cost of sales like the utility and, therefore, use operating revenues and net income to assess performance.

Six Months Ended Nine Months Ended September 30,

Non-Utility

Thousands Utility Gas Storage Other Total
2012

Net operating revenues $ 236,921
$ 22,219
$ 122
$ 259,262
Depreciation and amortization 49,477
4,853
—
54,330
Income from operations 76,072
9,567
70
85,709
Net income 28,250
3,185
23
31,458
Total assets at September 30, 2012 2,386,879
287,687
15,802
2,690,368
2011

Net operating revenues $ 230,244
$ 19,211
$ 68
$ 249,523
Depreciation and amortization 47,735
4,569
—
52,304
Income from operations 77,762
7,191
10
84,963
Net income (loss) 31,702
3,163
(211 ) 34,654
Total assets at September 30, 2011 2,291,531
253,478
22,831
2,567,840

Total assets at December 31, 2011 $ 2,435,888
$ 294,637
$ 16,049
$ 2,746,574



	Three Months Ended March 31,
In thousands	2013		2012
Utility margin calculation:
Utility operating revenues	$	269,659	$	302,905
Less: Utility cost of gas	142,359		169,755
Utility margin	$	127,300	$	133,150


5.	~~Common Stock~~

5. STOCK-BASED COMPENSATION

~~We have a share repurchase program under which we may purchase our common shares on the open market or through privately negotiated transactions. We currently have Board authorization through~~ ~~May 2013~~ ~~to repurchase up to an aggregate of~~ ~~2.8 million~~ ~~shares, but not to exceed~~ ~~$100 million. No shares of common stock were repurchased pursuant to this program during the~~ ~~nine months ended September 30, 2012. Since the plan’s inception in 2000 a total of~~ ~~2.1 million~~ ~~shares have been repurchased at a total cost of $83.3 million~~.


6.	~~Stock-Based Compensation~~

Our stock-based compensation plans include a Long-Term Incentive Plan (LTIP), under which various types of equity awards may be granted, an Employee Stock Purchase Plan, and a Restated Stock Option Plan (Restated SOP). ~~The Restated SOP was terminated in the second quarter of 2012. Shareholders approved the amended LTIP and authorized an additional~~ ~~250,000~~ ~~shares for the plan. A variety of equity vehicles may be granted under the LTIP. Together these~~These plans are designed to promote stock ownership in NW Natural by employees and officers. For additional information on our stock-based compensation plans, see Note 6 in the ~~2011~~2012 Form 10-K and ~~current~~ updates provided below.

Table of Contents

~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~

Long-Term Incentive Plan

~~In the second quarter of 2012, shares available for issuance under the LTIP were increased from~~ ~~600,000~~ ~~shares to~~ ~~850,000~~ ~~shares. The additional~~ ~~250,000~~ ~~shares may only be used for option grants under the LTIP and not for full-value awards such as Restricted Stock Units (RSUs) or performance shares.~~

Performance-Based Stock ~~Awards.~~Awards

LTIP performance shares incorporate market, performance, and service-based factors. On On February ~~22, 2012,~~ 27, 2013~~35,340~~, 37,300 performance-based shares were granted under the LTIP ~~which include a market condition,~~ based on target-level awards and a weighted-average grant date fair value of $~~53.92~~38.96 per share. Fair value was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:


Stock price on valuation date	$	48.00		$	45.38
Performance term (in years)	3.0			3.0
Quarterly dividends paid per share	$	0.445		$	0.455
Expected dividend yield	3.6		%	3.9		%
Dividend discount factor	0.9012			0.8943

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

On February 27, 2013, 25,748 ~~During the nine months ended September 30, 2012, the company~~performance-based RSUs were granted~~22,220~~ ~~RSUs~~ under the LTIP with a grant date fair ~~values ranging from~~value of $~~48.00~~ ~~to $48.25~~45.38 per share. The RSUs awarded include a ~~performance based~~performance-based threshold and a vesting period of four years from the grant date. ~~The~~An RSU obligates the Company ~~is obligated~~ upon vesting ~~of an RSU~~ 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.

Restated Stock Option Plan

As of ~~September 30, 2012~~March 31, 2013, there was $~~0.6~~0.4 million of unrecognized compensation cost from grants of stock options in prior years, which is expected to be recognized over a period extending through 2014. The Restated SOP was terminated for new option grants in ~~the second quarter of~~ 2012; however, options that had been granted before the Restated SOP was terminated will remain outstanding ~~options may still be exercised through~~until the earlier of their expiration, ~~dates.~~forfeiture, or exercise. Any new grants of stock options would be made under the LTIP. No ~~new~~ stock options were granted in the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013.


7.	~~Cost and Fair Value of Debt~~

6. DEBT

~~Cost and Fair Value of~~

Short-Term Debt

~~Our~~At March 31, 2013, our short-term debt ~~at September 30, 2012~~ consisted of commercial paper notes payable with a maximum maturity of 254 days, an average maturity of 8861 days, and an outstanding balance of $~~175.8~~130.8 million. The carrying cost of our commercial paper approximates a fair value using Level 2 inputs due to the short-term nature of the notes. See ~~description of fair value hierarchy in~~ Note 2 in our ~~2011~~2012 Form ~~10-K.~~10-K for a description of the fair value hierarchy.

~~Cost and Fair Value of~~ Long-Term Debt

~~Our utility’s~~At March 31, 2013, our utility's long-term debt ~~consists~~consisted of $~~601.7~~651.7 million of first mortgage bonds (FMBs) with maturity dates ranging from 2014 through ~~2035~~2042, interest rates ranging from 3.176 ~~percent~~% to 9.05 ~~percent,~~%, and a weighted-average coupon rate of ~~5.85~~5.71 ~~percent. In~~%. During the three months ended March of31, 2012, we ~~redeemed $40 million~~ ~~of first mortgage bonds. In July of 2012, we entered into a bond purchase agreement to sell $50 million~~ ~~of first mortgage bonds with a coupon rate of~~ ~~4.00 percent~~ ~~and a 30-year maturity, which closed on~~ ~~October 30, 2012~~ ~~(see Note 14). The proceeds of the issuance will be used to reduce short-term debt and for other general corporate purposes.~~did not issue or redeem any FMBs.

~~Our~~At March 31, 2013, our gas storage segment’s long-term debt ~~consists~~consisted of $40 million of senior secured ~~notes~~debt with a maturity date of November 30, 2016. ~~These senior secured notes consist~~This debt consists of $20 million of fixed rate ~~notes, which have~~debt with an interest rate of ~~7.75 percent~~7.75% and of $20 million of variable interest rate ~~notes,~~debt, which currently ~~have~~has an interest rate of ~~7.00 percent~~7.00%. The ~~notes are~~debt is secured by ~~our~~all of the membership interests in Gill Ranch ~~Storage, LLC~~ and ~~are~~is nonrecourse to NW Natural. ~~See Note 7 in our~~ ~~2011~~ ~~Form 10-K for more detail on our long-term debt.~~

~~Table of Contents~~

~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~

As our outstanding debt does not trade in active markets, we ~~estimated the~~estimate the fair value of our outstanding long-term debt using interest rates of other companies’ outstanding debt issuances that actively trade in public markets and have similar credit ratings, terms, and remaining maturities to our debt. These valuations are based on Level 2 inputs as defined in the fair value ~~hierarchy (see description of fair value hierarchy in~~ hierarchy. See Note 2 in our ~~2011~~2012 Form ~~10-K).~~ 10-K.

Table of Contents

The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date:


	September 30,				December 31,		March 31,				December 31,
Thousands	2012		2011		2011
In thousands							2013		2012		2012
Carrying amount	$	641,700	$	641,700	$	681,700	$	691,700	$	641,700	$	691,700
Estimated fair value	$	786,496	$	774,186	$	808,724	825,038		742,852		834,664

See Note 7 in our 2012 Form 10-K for more detail on our long-term debt.


8.	~~Pension and Other Postretirement Benefit Costs~~

7. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

The following ~~tables provide~~table provides the components of net periodic benefit cost for ~~our company-sponsored qualified and non-qualified defined benefit~~the Company's pension ~~plans~~ and other postretirement benefit plans:


	Three Months Ended Three Months Ended September 30,												Three Months Ended Three Months Ended March 31,
							Other Postretirement												Other Postretirement
	Pension Benefits						Benefits						Pension Benefits						Benefits
Thousands	2012			2011			2012			2011
In thousands													2013			2012			2013			2012
Service cost	$	2,130		$	1,839		$	177		$	168		$	2,341		$	2,130		$	179		$	177
Interest cost	4,303			4,503			314			344			4,103			4,304			286			314
Expected return on plan assets	(4,637		)	(4,455		)	—			—			(4,678		)	(4,638		)	—			—
Amortization of net actuarial loss	3,844			2,683			103			68			4,421			3,843			169			103
Amortization of prior service costs	48			88			50			50			56			49			49			49
Amortization of transition obligations	—			—			103			103			—			—			—			103
Net periodic benefit cost	5,688			4,658			747			733			6,243			5,688			683			746
Amount allocated to construction	(1,676		)	(1,279		)	(252		)	(234		)	(1,855		)	(1,418		)	(219		)	(214		)
Amount deferred to regulatory balancing account⁽¹⁾	(2,111		)	(1,330		)	—			—			(2,349		)	(2,068		)	—			—
Net amount charged to expense	$	1,901		$	2,049		$	495		$	499		$	2,039		$	2,202		$	464		$	532

Six Months Ended Nine Months Ended September 30,

Other Postretirement

Pension Benefits Benefits
Thousands
2012 2011 2012 2011
Service cost $ 6,390
$ 5,638
$ 531
$ 504
Interest cost 12,911
13,556
943
1,031
Expected return on plan assets (13,914 ) (13,367 ) —
—
Amortization of net actuarial loss 11,531
8,067
309
204
Amortization of prior service costs 146
264
148
148
Amortization of transition obligations —
—
309
309
Net periodic benefit cost 17,064
14,158
2,240
2,196
Amount allocated to construction (4,522 ) (3,765 ) (681 ) (689 )
Amount deferred to regulatory balancing account⁽¹⁾
(6,273 ) (3,989 ) —
—
Net amount charged to expense $ 6,269
$ 6,404
$ 1,559
$ 1,507

⁽¹⁾ Effective January 1, 2011, the ~~Oregon Public Utility Commission (OPUC)~~OPUC approved the deferral of certain pension expenses above or below the amount set in rates, 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~~accrue interest at the utility’s ~~authorized rate~~actual cost of ~~return.~~long-term debt. See ~~"Regulatory Accounting" in~~ Note 2.

The following table presents amounts recognized in accumulated other comprehensive loss (AOCL) and the changes in AOCL related to our non-qualified employee benefit plan:



In thousands
Beginning balance at December 31, 2012	$	(9,291	)
Amounts reclassified into AOCL	—
Amounts reclassified from AOCL:
Amortization of prior service costs	(2		)
Amortization of actuarial gains (losses)	386
Total reclassifications before tax	384
Tax expense	(151		)
Total reclassifications for the period	233
Ending balance at March 31, 2013	$	(9,058	)

Table of Contents

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

Plan

In the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013, we made cash contributions totaling $~~23.5~~1.4 million to our qualified defined benefit pension ~~plans.~~plan. In ~~July~~ 2012, Congress passed the "Moving Ahead for Progress in the 21st Century Act" (MAP-21), which among other things, includes ~~a method~~provisions that reduce the level of ~~stabilizing interest rate assumptions and has~~minimum required contributions in the ~~effect of reducing short-term minimum funding requirements~~near-term but ~~increasing~~generally increase contributions in the long-run as well as increase the operational costs of running a pension plan. ~~We are evaluating~~Including the ~~impact~~impacts of MAP-21, ~~on contribution requirements~~we expect to ~~our qualified~~make approximately $10 million in additional pension ~~plans and will update our funding estimates in future filings.~~contributions during 2013.

Multiemployer Pension Plan

In addition to the ~~company-sponsored~~Company-sponsored defined benefit pension ~~plans~~plan referred to above, we contribute to a ~~defined benefit~~ multiemployer pension plan ~~(EIN 94-6076144)~~ for our utility’s ~~bargaining unit~~union employees known as the Western States Office and Professional Employees International Union Pension Fund (Western States Plan). in accordance with our collective bargaining agreement. The employer identification number of the plan is 94-6076144. The cost of this plan, isand corresponding future liabilities, are in addition to pension expense presented in the table above. Our contributions to the Western States Plan amounted to $~~0.3~~0.1 million for the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012. Under the terms of our current collective bargaining agreement, we can withdraw from the Western States Plan at any time. However, if ~~we withdraw and~~ the plan is underfunded at the time we ~~could~~withdraw, we would be assessed a withdrawal liability. ~~We do~~In accordance with accounting rules for multiemployer plans, we have not ~~recognize a liability currently for~~recognized these potential withdrawal liabilities on the ~~Western States Plan because~~balance sheet. Currently, we have made no decision to withdraw from the plan. We continue to monitor the financial condition of the plan and consider options with respect thereto.

Defined Contribution Plan

The Retirement K Savings Plan provided to our employees is a qualified defined contribution plan under Internal Revenue Code Section 401(k). Our contributions to this plan totaled $~~1.7~~0.5 million and $~~1.8~~0.7 million for the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012, respectively.

See Note 98 in the ~~2011~~2012 Form 10-K for more information about these retirement and other postretirement benefit plans.


9.	~~Income Tax~~

8. INCOME TAX

The effective income tax rate for the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012 varied from the combined federal and state statutory tax rates principally due to the following:


	September 30,				March 31,
	2012		2011		2013		2012
Federal statutory tax rate	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease):
Current state income tax, net of federal tax benefit	4.7	%	4.5	%	4.7		4.6
Amortization of investment and energy tax credits	(0.3	)%	(0.4	)%	(0.3	)	(0.3	)
Differences required to be flowed-through by regulatory commissions	1.4	%	1.5	%	2.4		1.6
Gains on company and trust-owned life insurance	(1.2	)%	(0.9	)%	(0.3	)	(0.4	)
One-time state tax adjustment, net of federal benefit	4.7	%	—	%
Other - net	0.7	%	0.7	%
Other, net					(0.7	)	0.2
Effective income tax rate	45.0	%	40.4	%	40.8	%	40.7	%

~~The increase in the effective income tax rate for the~~See ~~nine months ended September 30, 2012~~ ~~compared to the same period in~~ ~~2011~~ ~~was primarily due to a one-time, after-tax charge of $2.7 million~~Note 9 in the third quarter of 2012 related to the OPUC's rate case order that the Company cannot recover deferred amounts resulting from the 2009 Oregon tax rate change. See Note 14 in this filing for more information on the one-time, tax charge and Note 10 in our ~~2011~~2012 Form 10-K for more detail on income taxes and effective tax rates.

~~Table of Contents~~9. PROPERTY, PLANT, AND EQUIPMENT

~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~


~~10.~~	~~Property, Plant and Equipment~~

The following table sets forth the major classifications of our property, plant, and equipment and related accumulated depreciation ~~as of~~at ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012 and December 31, ~~2011~~2012:


	September 30,				December 31,		March 31,				December 31,
Thousands	2012		2011		2011
In thousands							2013		2012		2012
Utility plant in service	$	2,399,600	$	2,296,788	$	2,323,467	$	2,452,419	$	2,342,681	$	2,435,886
Utility construction work in progress	53,017		36,459		36,051		53,474		34,903		46,831
Less: Accumulated depreciation	776,812		740,378		749,603		799,864		760,566		789,201
Utility plant-net	1,675,805		1,592,869		1,609,915
Utility plant, net							1,706,029		1,617,018		1,693,516
Non-utility plant in service	296,486		290,075		293,205		296,228		297,164		296,781
Non-utility construction work in progress	6,626		9,176		8,379		6,552		5,789		6,510
Less: Accumulated depreciation	21,698		16,214		17,623		24,697		19,117		23,195
Non-utility plant-net	281,414		283,037		283,961
Total property, plant and equipment	$	1,957,219	$	1,875,906	$	1,893,876
Non-utility plant, net							278,083		283,836		280,096
Total property, plant, and equipment							$	1,984,112	$	1,900,854	$	1,973,612


~~11.~~	~~Gas Reserves and Other Investments~~

10. GAS RESERVES

Our utility gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet. Other investments include financial investments in life insurance policies, which are accounted for at cash surrender value, and equity investments in certain partnerships and limited liability companies, which are accounted for under the equity or cost methods. See Note 12 in the ~~2011~~ ~~Form 10-K for more detail on our investments.~~

~~Gas Reserves~~

We entered into agreements with Encana Oil & Gas (USA) Inc. (Encana) to develop ~~and produce~~ physical gas reserves. These agreements are intended to provide long-term gas price protection for our utility ~~customers.~~customers rather than serving as a source of gas supply. Encana began drilling in 2011 under these agreements, and ~~we are~~gas which is currently ~~producing gas~~being produced from our working interests in these gas ~~fields. Our~~fields is sold by Encana at then prevailing market prices, with revenues from such sales, net of associated production costs, credited to our cost of gas. The cost of gas, including a carrying cost for the net rate base investment, ~~are~~is part of our annual Oregon ~~Purchased Gas Adjustment (PGA)~~PGA filing, which allows us to recover our costs through customer rates in a manner previously approved by the OPUC. This transaction ~~accounted~~acted to hedge the cost of gas for approximately 4%3% of our gas supplies for the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013. The following table outlines our net investment at ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012 and December 31, ~~2011~~2012:


	September 30,				December 31,		March 31,				December 31,
Thousands	2012		2011		2011
In thousands							2013		2012		2012
Gas reserves, current	$	13,140	$	2,366	$	4,463	$	14,286	$	6,732	$	14,966
Gas reserves, non-current	81,692		28,551		48,597		110,033		63,546		92,179
Less: Accumulated amortization	5,767		426		1,146		9,864		2,440		7,486
Total gas reserves	89,065		30,491		51,914		114,455		67,838		99,659
Less: Deferred taxes on gas reserves	23,940		10,090		15,630		32,907		22,047		28,329
Net investment in gas reserves	$	65,125	$	20,401	$	36,284	$	81,548	$	45,791	$	71,330

~~Variable Interest Entity (VIE) Analysis.~~ We concluded that the arrangements with Encana qualify as a VIE, but that we are not the primary beneficiary of these activities as defined by the authoritative guidance related to consolidations. We account for our investment in the VIE on the cost basis, and the asset is included as gas reserves on our balance sheet. Our maximum loss exposure related to the VIE is limited to our investment balance.11. INVESTMENTS

Equity Method Investments

~~PGH is a development stage VIE.~~ Palomar, a wholly-owned subsidiary of PGH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. PGH is owned 50 ~~percent~~% by NWN Energy and 50 ~~percent~~% by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation.

~~Table of Contents~~

~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~

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

PGH is a development stage VIE. As of ~~September 30, 2012~~March 31, 2013, there were no changes to our VIE analysis and, as such, we continue to report Palomar under equity method accounting based on the determination that we are not the primary beneficiary of PGH’s activities, as defined by the authoritative guidance related to consolidations, due to the fact that we have a 50 ~~percent~~% share and there are no stipulations that allow disproportionate influence over the entity. Our investment in PGH and Palomar are included in other investments on our balance sheet. Our maximum

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loss exposure related to PGH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50 ~~percent~~% owner.

Impairment ~~Analysis.~~Analysis

Our investments in nonconsolidated entities accounted for under the equity method ~~including Palomar,~~ are reviewed for impairment at each reporting period and following updates to our corporate planning assumptions. When it is determined that a loss in value is other than temporary, a charge is recognized for the difference between the investment’s carrying value and its estimated fair value. Fair value is based on quoted market prices when available, or on the present value of expected future cash flows. Differing assumptions could affect the timing and amount of a charge recorded in any period. There have been no significant changes in carrying value or estimated fair value since ~~yearend.~~year end.

Our investment balance in ~~Palomar~~PGH was $13.4 million at ~~September 30, 2012~~March 31, 2013. ~~Palomar~~PGH is continuing to work on development of commercial support for the ~~project and expects to file a~~project. A new Federal Energy Regulatory Commission (FERC) ~~certification~~certificate application is expected to be filed to reflect a revised scope based on regional needs for the proposed pipeline. If we learn ~~later~~ that the project is not viable or will not go forward in the future, we could be required to recognize a maximum charge of up to approximately $13.2 million ~~as of September 30, 2012~~ based on the current amount of our equity investment, net of cash, and working capital at ~~Palomar.~~PGH. We will continue to monitor and update our impairment analysis as required. See Note 12 in our ~~2011~~2012 Form 10-K for more detail.

Other Investments

Other investments include financial investments in life insurance policies, which are accounted for at fair value. See Note 12 in the 2012 Form 10-K for more detail on ~~Palomar and our annual impairment analysis.~~other investments.


~~12.~~	~~Derivative Instruments~~

12. DERIVATIVE INSTRUMENTS

We enter into swap, option, and combinations of option contracts for the purpose of hedging natural gas. We primarily use these derivative financial instruments to manage commodity price variability related to our natural gas purchase requirements. A small portion of our derivative hedging strategy involves foreign currency exchange transactions related to purchases of natural gas from Canadian suppliers.

In the normal course of business, we enter into indexed-price physical forward natural gas commodity purchase (gas supply) contracts to meet the requirements of ~~core~~ utility customers. We also enter into financial derivatives, up to prescribed limits, to hedge price variability related to these physical gas supply contracts. The following table presents the absolute notional amounts related to open positions on financial derivative instruments:



	March 31,				December 31,
Dollars in thousands	2013		2012		2012
Open position absolute notional amount:
Natural gas (millions of therms)	30.2		32.8		39.5
Foreign exchange	$	16,322	$	12,954	$	13,231

Derivatives entered into prudently by the utility for future gas years prior to our annual PGA filing receive regulatory deferred accounting treatment. Derivative contracts entered into after the annual PGA rate is set for the current gas contract year are subject to our PGA incentive sharing mechanism, which provides for either an 8080% or ~~a 90 percent~~90% deferral of any gains and losses as regulatory assets or liabilities, with the remaining 1010% or ~~20 percent~~20% recognized in current income. All of our commodity hedging for the ~~2011-12~~2012-13 gas year was completed prior to the start of the gas year, and these hedge prices were included in ~~our~~the Company's PGA filing.

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The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments for the three ~~and nine~~ months ended ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012. ~~All of our currently~~Our outstanding derivative instruments are primarily related to regulated utility operations as illustrated by the unrealized derivative gains and losses being deferred ~~to balance sheet accounts~~ in accordance with regulatory accounting standards. We also enter into exchange contracts related to the optimization of our gas portfolio, which may qualify as derivatives but do not qualify for hedge accounting or regulatory deferral, but are subject to our regulatory sharing agreement.

Three Months Ended

September 30, 2012 September 30, 2011
Thousands

Natural gas commodity⁽¹⁾

Foreign currency ⁽²⁾

Natural gas commodity⁽¹⁾

Foreign currency ⁽²⁾
Cost of sales
$ 22,558
$ —
$ (18,987 ) $ —
Other comprehensive income (loss)
—
273
—
(1,221 )
Less:

Amounts deferred to regulatory accounts on balance sheet
(22,558 ) (273 ) 18,987
1,221
Total impact on earnings $ —
$ —
$ —
$ —

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~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~

Nine Months Ended

September 30, 2012 September 30, 2011
Thousands

Natural gas commodity⁽¹⁾

Foreign currency ⁽²⁾

Natural gas commodity⁽¹⁾

Foreign currency ⁽²⁾
Cost of sales
$ (5,556 ) $ —
$ (49,106 ) $ —
Other comprehensive income (loss)
—
162
—
(815 )
Less:

Amounts deferred to regulatory accounts on balance sheet
5,556
(162 ) 49,106
815
Total impact on earnings $ —
$ —
$ —
$ —

⁽¹⁾~~Unrealized gain (loss) from natural gas commodity hedge contracts is recorded in cost of sales and reclassified to regulatory deferral accounts on the balance sheet.~~

⁽²⁾~~Unrealized gain (loss) from foreign currency exchange contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet.~~



	Three Months Ended
	March 31, 2013						March 31, 2012
In thousands	Natural gas commodity			Foreign currency			Natural gas commodity			Foreign currency
Cost of sales	$	7,183		$	—		$	(55,894	)	$	—
Other comprehensive income (loss)	—			(239		)	—			126
Less:
Amounts deferred to regulatory accounts	(7,037		)	239			55,894			(126		)
Total gain in pre-tax earnings	$	146		$	—		$	—		$	—

No collateral was posted with or by our counterparties as of ~~September 30, 2012~~March 31, 2013 or ~~2011~~2012. We attempt to minimize the potential exposure to collateral calls by counterparties to manage our liquidity risk. Counterparties generally allow a certain credit limit threshold before requiring us to post collateral against loss positions. Given our counterparty credit limits and portfolio diversification, we have not been subject to collateral calls in ~~2011~~2012 or ~~2012~~2013. Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We could also be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change. Based upon current contracts outstanding, which reflect unrealized losses of $~~5.4~~0.2 million at ~~September 30, 2012~~March 31, 2013, we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various credit downgrade rating scenarios for NW Natural as follows:


			Credit Rating Downgrade Scenarios										Credit Rating Downgrade Scenarios
Thousands	(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3		Speculative
In thousands											(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3		Speculative
With Adequate Assurance Calls	$	—	$	—	$	—	$	—	$	585	$	—	$	—	$	—	$	—	$	8,290
Without Adequate Assurance Calls	$	—	$	—	$	—	$	—	$	522	—		—		—		—		5,516

Our derivative financial instruments are subject to master netting arrangements; however, they are presented on a gross basis on the face of our statement of financial position. If netted by counterparty, our derivative position would result in an asset of $8.3 million and a liability of $1.4 million as of March 31, 2013.

In the three ~~and nine~~ months ended ~~September 30,~~ March 31, 2013 and 2012, we realized net losses of $~~12.7~~5.4 million and $~~63.3~~29.4 million, respectively, from the settlement of natural gas hedge contracts at maturity, which were recorded as increases to the cost of ~~gas, compared to net losses of $6.6 million~~ ~~and $36.2 million, respectively, for the~~ ~~three and nine months endedSeptember 30, 2011~~.gas. The currency exchange rate in all foreign currency forward purchase contracts is included in our purchased cost of gas at settlement; therefore, no gain or loss is recorded from the settlement of those contracts.

We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of customers. See Note 13 in our ~~customers. For~~2012 Form 10-K for more information on our derivative ~~instruments, see Note 13 in our~~ ~~2011~~ ~~Form 10-K.~~instruments.

Fair Value

In accordance with fair value accounting, we include nonperformance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. The inputs in our valuation techniques include natural gas futures, volatility, credit default swap spreads and interest rates. Additionally, our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at ~~September 30, 2012~~March 31, 2013. As of ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012 and December 31, ~~2011~~2012, the fair value was an

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asset of $~~5.4~~6.9 million, and a liability of $~~49.9~~55.8 million, and a liability of $~~61.0~~5.8 million, respectively, using significant other observable, or Level 2, inputs. We have used no Level 3 inputs in our derivative valuations. We did not have any transfers between Level 1 or Level 2 during the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012.

~~Table of Contents~~13. ENVIRONMENTAL MATTERS

~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~


~~13.~~	~~Commitments and Contingencies~~

~~Environmental Matters~~

We own, or previously owned, properties that may require environmental remediation or action. We ~~accrue all material~~estimate the range of loss ~~contingencies relating to these properties that we believe to be probable of assertion and reasonably estimable. We continue to study and evaluate the extent of our potential~~for environmental liabilities ~~but due~~based on current remediation technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several site investigations, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases, we have disclosed the nature of the possible loss and the fact that the high end of the range cannot be reasonably estimated.

We regularly review our environmental liability for each site where we may be exposed to remediation responsibilities, but the costs are difficult to estimate. A number of steps are involved in each environmental remediation effort, including site investigations, remediation, operations and maintenance, monitoring and site closure. Site investigations and remediation efforts often develop slowly over many years. Each of these steps may, over time, involve a number of alternative actions, each of which can change the course and scope of the effort and ultimately also the cost. Many of these steps are dependent upon the approval and direction of federal and state environmental regulators whose policies, determinations and directions may change over time creating further uncertainty as to the timing and scope of remediation activities. In certain cases there are a number of other potentially responsible parties in addition to us, each of which may influence the course and scope of the remediation effort. The allocation of liability among the potentially responsible parties is subject to dispute and uncertainty at this time with respect to the sites noted below. These disputes could lead to adversarial administrative proceedings or litigation, with uncertain outcomes.

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. Unless there is an estimate within a range of possible losses that is more likely than other cost estimates within that range, we record the liability at the low end of this range. It is likely that changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to our continued evaluation and clarification concerning our responsibility, the complexity of environmental laws and regulations and the determination by regulators of remediation alternatives. ~~The status~~

Environmental site remediation costs are deferred under regulatory approval from the OPUC and WUTC. In addition, the OPUC authorized a mechanism (SRRM) that allows the Company to recover prudently incurred environmental site remediation costs, subject to an earnings test that will be defined in a current proceeding. Actual cost recovery under SRRM will depend upon future insurance recoveries, future expenditures, annual prudence reviews, and the impacts of ~~each~~any earnings test the OPUC may adopt in our currently open docket. Cost recovery and carrying charges on amounts deferred for costs associated with services provided to Washington customers will be determined in a future proceeding. We annually review all regulatory assets for recoverability and more often if circumstances warrant. If we should determine that all or a portion of these regulatory assets no longer meet the ~~sites currently under investigation~~criteria for continued application of regulatory accounting, then we would be required to write off the net unrecoverable balances against earnings in the period such determination is ~~provided below.~~made.

In December 2010, NW Natural commenced litigation against certain of its historical liability insurers in Multnomah County Circuit Court, State of Oregon (see Item 3. Legal Proceedings). NW Natural seeks damages in excess of $50 million in losses it has incurred to date, as well as declaratory relief for additional losses it expects to incur in the future.

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



	Current Liabilities						Non-Current Liabilities
	March 31,				December 31,		March 31,				December 31,
In thousands	2013		2012		2012		2013		2012		2012
Portland Harbor site:
Gasco/Siltronic Sediments	$	389	$	2,459	$	2,207	$	38,050	$	43,655	$	36,087
Other Portland Harbor	1,678		1,400		1,767		2,793		3,547		3,160
Gasco Uplands site	15,411		13,197		18,722		8,365		7,689		5,028
Siltronic Uplands site	556		478		637		414		588		379
Central Service Center site	80		—		140		386		424		396
Front Street site	760		1,131		993		199		395		—
Oregon Steel Mills	—		—		—		179		116		185
Total	$	18,874	$	18,665	$	24,466	$	50,386	$	56,414	$	45,235

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



	March 31,				December 31,
In thousands	2013		2012		2012
Cash paid	$	75,620	$	58,989	$	71,124
Total regulatory asset deferral⁽¹⁾	125,671		108,007		121,144

⁽¹⁾ Total regulatory asset deferral includes cash paid, remaining liability, interest, and insurance reimbursement.

PORTLAND HARBOR SITE. The Portland Harbor ~~site.~~ ~~In 1998, the Oregon Department of Environmental Quality (ODEQ) and the Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of~~is an EPA listed Superfund site that is approximately 11 miles long on the Willamette River ~~(Portland Harbor). Since then, EPA has extended the Portland Harbor site to approximately 11 miles of the Willamette River. The Portland Harbor site~~and is adjacent to ~~two upland sites owned by~~ NW ~~Natural that are discussed below as the~~Natural's Gasco ~~upland~~uplands and Siltronic ~~upland~~uplands sites. ~~The Portland Harbor was listed by the EPA as a Superfund site in 2000, and we were~~We have been notified that we are a potentially responsible ~~party. We then~~party to the Superfund site and we have joined with other potentially responsible parties (the Lower Willamette Group or LWG) to ~~fund the~~develop a Portland Harbor Remedial Investigation/Feasibility Study (RI/FS)~~, as discussed below.~~. The LWG submitted ~~the draft Final Portland Harbor Remedial Investigation (RI) to EPA in 2011. The LWG submitted the~~a draft Feasibility Study (FS) to EPA in March ~~2012. The EPA will use the information in the RI/FS to select a cleanup plan for the Portland Harbor Superfund Site. The draft FS~~2012 that provides a range of remedial costs for the entire Portland Harbor Superfund Site, which includes the Gasco/Siltronic Sediment site, discussed below. The range of costs estimated for various remedial alternatives for the entire Portland Harbor, as provided in the draft FS, is $169 million to $1.8 billion. NW Natural's potential liability is a portion of the costs of the remedy EPA will select for the entire Portland Harbor Superfund site. The cost of that remedy is expected to be allocated among more than 100 potentially responsible parties. NW Natural is participating in a non-binding allocation process in an effort to settle this potential liability. ~~On June 22, 2012, EPA delivered a notice of non-compliance~~We manage our liability related to the ~~LWG with respect to~~Superfund site as two distinct remediation projects, the Baseline Human Health Risk Assessment the LWG submitted to EPA in May 2011 (BHHRA), as a component of the RI. The LWG has disputed the EPA’s claims that the BHHRA is in any way deficient or noncompliantGasco/Siltronic Sediments and ~~has initiated formal dispute resolution under the 2001 Administrative Settlement Agreement and Order on Consent issued by EPA to LWG.~~Other Portland Harbor projects.

Gasco/Siltronic Sediments. In 2009, NW Natural and Siltronic Corporation entered into a separate Administrative Order on Consent with EPA to evaluate and design specific remedies for sediments adjacent to the Gasco ~~upland~~uplands and Siltronic ~~upland~~uplands sites. ~~The Gasco/Siltronic Sediments is part of the Portland Harbor Superfund site.~~ NW Natural submitted a draft Engineering Evaluation/Cost Analysis (EE/CA) to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. The EE/CA will provide a variety of remedial alternatives for the sediments at this site. The alternatives provided in the EE/CA are based on EPA requirements to develop costs for the various remedies described therein. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA range from $3438.4 million to $350 million. ~~After the EPA determines an appropriate alternative from the EE/CA, a remedial design will be~~

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~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~

~~produced.~~ We have recorded a liability of $34.0 million for the sediment clean-up, which reflects the low end of the EE/CA range. We have recorded an additional liability of $~~11.4~~4.4 million for the additional studies and design work needed before the clean-up can occur, and for regulatory oversight throughout the clean-up. At this time, we believe ~~the~~ sediments at this site represent the largest portion of our liability related to the Portland Harbor site, discussed above. ~~We accrued at the low end because no amount within the range is considered to be more likely than another.~~

Other Portland Harbor. NW Natural incurs costs related to its membership in the ~~Lower Willamette Group~~LWG which is performing the RI/FS for EPA. NW Natural may also ~~incurs~~incur costs related to natural resource damages. In 2008, the Portland Harbor Natural Resource Trustee Council advised a number of potentially responsible parties that it intended to pursue natural resource damage claims at the Portland Harbor Superfund site. The Company and other parties have signed a cooperative agreement with the Natural Resource Trustees to participate in a phased natural resource damage assessment to estimate liabilities to support an early restoration-based settlement of natural resource damage claims. ~~As of~~ ~~September 30, 2012, we~~We have an accrued a liability ~~of $4.4 million~~ for these claims which is at the low end of the range of the potential ~~liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated at this time.~~liability. This liability is not included in the range of costs provided in the draft FS for the Portland Harbor.

~~Gasco upland site.~~GASCO UPLANDS SITE. ~~We own property in Multnomah County, Oregon that is the site of~~NW Natural owns a former gas manufacturing plant that was closed in 1956 (Gasco site)~~. The Gasco upland site~~ and is adjacent to the Portland Harbor site described ~~above and~~above. The Gasco site has been under investigation by us for environmental contamination under the ~~ODEQ~~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. ~~In June 2003, we filed a Feasibility Scoping Plan which outlined a range of remedial alternatives for the most contaminated portion of~~We manage the Gasco ~~upland site. In December 2004, we submitted an Ecological~~site in two parts, the uplands portion and ~~Human Health Risk Assessment to ODEQ, and in~~the groundwater source control action.

In May 2007, we completed a revised Remedial Investigation Report for the uplands portion and submitted it to ODEQ for review. ~~The~~We have recognized a liability ~~accrued at~~ ~~September 30, 2012~~for this portion of the ~~Gasco upland~~ site ~~is $8.7 million~~,remediation which is at the low end of the range of potential ~~liability because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.~~liability.

In ~~2007, we also submitted~~2012, ODEQ approved our final design remediation plan for a ~~Focused Feasibility Study (FFS) for the~~ groundwater source control ~~portion of the Gasco site,~~system on which ~~ODEQ conditionally approved in March 2008. We submitted our final design for source control in January 2012. ODEQ approved~~we began construction ~~of the designed system but subsequently requested another component for source control outside the original design. Construction began~~ in October 2012. Based on the information currently available for groundwater source control at the Gasco site and our current assumptions regarding the effectiveness of the source control system, we have estimated a range of liability between $~~16.8~~14.5 million and ~~$30~~$25 million, for which we have recorded an accrued liability

Table of $~~16.8 million~~ at ~~September 30, 2012~~, Contents

which is at the low end of the range of the potential ~~liability because no amount within the range is considered to be more likely than another.~~liability. We are uncertain about the range due to potential additional ODEQ requirements and actions needed to meet those requirements, including uncertainty about how to meet the agreed standards set by ODEQ subsequent to the initial testing of the system and as part of the final remedy for the ~~unpland~~uplands portion of the Gasco site.

OTHER SITES. In addition to those sites above, we have environmental exposures at four other sites, Siltronic, ~~upland site.We previously owned property adjacent~~Central Service Center, Front Street, and Oregon Steel Mills. Due to the ~~Gasco site that now is~~uncertainty of the ~~location~~design of ~~a manufacturing plant owned by Siltronic Corporation (the Siltronic upland site). The Siltronic upland site is also adjacent to~~remediation, regulation, timing of the ~~Portland Harbor site, but not included~~liabilities, and in the ~~range~~case of ~~remedial costs~~the Oregon Steel Mills site, pending litigation, liabilities for ~~the Portland Harbor site. We are currently conducting an investigation~~each of ~~manufactured gas plant wastes on the uplands~~these sites has been recognized at ~~this site for the ODEQ. The liability accrued at~~ ~~September 30, 2012~~ ~~for the Siltronic site is $1.1 million, which is at the~~their respective low end of the range of potential liability ~~because no amount within the range is considered to be more likely than another,~~ and the high end of the range cannot be reasonably be estimated.

~~Central Service Center site.~~ See “ In 2006, we received notice from the ODEQ that our Central Service Center in southeast Portland (Central Service Center site) was assigned a high priority for further environmental investigation. Previously there were three manufactured gas storage tanks on the premises. The ODEQ believes there could be site contamination associated with releases of condensate from stored manufactured gas as a result of historic gas handling practices. In the early 1990s, we excavated waste piles and much of the contaminated surface soils and removed accessible waste from some of the abandoned piping. In early 2008, we received notice that this site was added to the ODEQ’s list of sites in which releases of hazardous substances have been confirmed. ODEQ has also added this site to its list of sites where cleanup is necessary. We are currently performing an environmental investigation of the property under the ODEQ’s Independent Cleanup Pathway. As of Legal Proceedings~~September 30, 2012, we have a liability accrued of $0.5 million~~ for investigation at this site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

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~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~

~~Front Street site.~~ The Front Street site was the former location of a gas manufacturing plant we operated. It is near but outside the geographic scope of the current Portland Harbor site sediment studies. The EPA directed the LWG to collect a series of surface and subsurface sediment samples off the river bank adjacent to where that facility was located. Based on the results of that sampling, the EPA notified the LWG that additional sampling would be required. As the Front Street site is upstream from the Portland Harbor site, the EPA agreed that it could be managed separately from the Portland Harbor site under ODEQ authority. Work plans for source control investigation and a historical report were submitted to ODEQ and initial studies were completed. In 2010, ODEQ required additional studies which were completed in 2012. The results of those studies have been presented to ODEQ and a final sampling plan required by ODEQ is currently being developed. As of ~~September 30, 2012, we have an estimated liability accrued of $1.4 million~~ for the study of the sediments and riverbank groundwater and soils at the site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

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

~~Accrued Liabilities Relating to Environmental Sites.~~ ~~The following table summarizes the accrued liabilities relating to environmental sites at~~ ~~September 30, 2012~~ ~~and~~ ~~2011~~ ~~and~~ ~~December 31, 2011, which are recorded in other current liabilities and other noncurrent liabilities on the balance sheet:~~

Current Liabilities Non-Current Liabilities

September 30, September 30, December 31, September 30, September 30, December 31,
Thousands 2012 2011 2011 2012 2011 2011
Portland Harbor site:

Gasco/Siltronic Sediments $ 1,748
$ 1,490
$ 1,614
$ 43,628
$ 30,604
$ 35,797
Other Portland Harbor 1,188
2,174
1,893
3,186
5,122
7,066
Gasco upland site 18,018
8,899
14,092
7,453
7,447
8,900
Siltronic upland site 511
721
887
592
114
128
Central Service Center site 100
5
—
445
530
495
Front Street site 942
—
1,697
452
765
—
Oregon Steel Mills —
—
—
185
129
120
Total $ 22,507
$ 13,289
$ 20,183
$ 55,941
$ 44,711
$ 52,506

~~Regulatory and Insurance Recovery for Environmental Costs.~~ In May 2003, the OPUC approved our request to defer unreimbursed environmental costs associated with certain named sites, including those described above. Beginning in 2006, the OPUC granted us additional authorization to accrue interest on deferred environmental cost balances, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. In October 2012, the OPUC authorized a new mechanism for environmental cost recovery through rates. This Site Remediation Recovery Mechanism (SRRM) allows the Company to recover prudently incurred environmental site remediation costs. The rate case also establishes an earnings review related to this mechanism, which will be further defined in a future proceeding. The ultimate amounts we recover under SRRM will depend upon future insurance recoveries, future expenditures, prudency reviews, and the impacts of any earnings review the OPUC may adopt in a subsequent proceeding.

Beginning in 2011, the Washington Utilities and Transportation Commission (WUTC) authorized the deferral of certain environmental costs associated with services provided to Washington customers. Environmental costs related to Washington are being deferred as of ~~January 26, 2011~~ ~~with cost recovery and a carrying charge to be determined in a future proceeding.~~

~~On a cumulative basis, we have paid $69.6 million~~ ~~for environmental costs, including legal, investigation, monitoring and remediation costs, of which $4.9 million~~ ~~was paid and expensed prior to regulatory deferral order approval. At~~ ~~September 30, 2012, we had a regulatory asset of $128.2 million, which represents those amounts accrued, paid subsequent to regulatory deferral, and interest on those projects.~~

~~Table of Contents~~

~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~

~~In December 2010, NW Natural commenced litigation against certain of its historical liability insurers in Multnomah County Circuit Court, State of Oregon (see Item 3. Legal Proceedings in the~~ ~~2011~~ ~~Form 10-K). NW Natural seeks damages in excess of $50 million~~ in losses it has incurred to date, as well as declaratory relief for additional losses it expects to incur in the future. In December 2011, NW Natural reached a settlement with Associated Electric and Gas Insurance Services Limited and dismissed its claims against that insurer in the litigation.

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~~NW Natural does 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 as we would expect to receive insurance recovery or rate recovery. See also Part II, Item ~~1., “Legal Proceedings.~~1, “Legal Proceedings.”

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


~~14.~~	~~Subsequent Events~~

14. REVISION OF PRIOR PERIOD FINANCIAL STATEMENTS

During the first quarter of 2013, we identified an error in the rate used to calculate interest on certain regulatory assets. Accounting standards allow for the capitalization of all or part of an incurred cost that would otherwise be charged to expense if the regulator provides orders that create probable recovery of past costs through future revenues. We have accrued interest as specified by regulatory order on certain regulatory balances at our authorized rate of return (ROR). This ROR includes both a debt and equity component, which we are allowed to recover from customers in the form of a carrying cost on regulatory deferred account balances. As the equity component of our ROR is not an incurred cost that would otherwise be charged to expense, this portion of the carrying cost should not have been capitalized for financial reporting purposes.

~~Commission Decision~~We assessed the materiality of this error on ~~Oregon General Rate Case~~prior period financial statements and concluded it was not material to any prior annual or interim periods; however, the cumulative impact would have been material to the interim period ending March 31, 2013, if corrected in 2013. As a result, in accordance with accounting standards, we have revised our prior period financial statements as described below to correct for this error. The revision had no effect on reported cash flows.

~~In October~~The adjustment impacted years 2003 through 2012 the OPUC authorized an annual Oregon revenue increase of $8.7 million, equivalent to a rate increase of 1.2 percent, effective November 1, 2012. This annual increase included an authorized return on equity of 9.5 percent and an overall rate of return on rate base of 7.78 percent, with a ~~capital structure~~cumulative pre-tax decrease over that period of ~~50 percent equity~~$5.6 million to regulatory assets and ~~50 percent long-term debt. This increase includes~~other income and expense. The revision decreased net income by $1.1 million, $0.9 million and $0.7 million for the ~~recovery of amounts that had previously been deferred through the company's decoupling mechanism of about $15 million. As~~years ended December 31, 2012, 2011 and 2010, respectively. The cumulative decrease to January 1, 2010 retained earnings was $0.7 million as a result of the ~~overall effect on~~revision.

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The following table presents the ~~Company is a decline in net operating revenues (utility margin) of approximately $6 million on an annualized basis. In addition~~income statement effects related to ~~our decoupling mechanism,~~this revision for the OPUC also approved the retention of our weather normalization mechanism. Our system integrity program was extended for two years. They also authorized a SRRM that allows the Company to recover prudently incurred environmental site remediation costs, with a separate earnings review which will be further defined in a future proceeding. The OPUC denied recovery of deferred amounts that represent the increase in deferred income taxes caused by the 2009 Oregon tax rate change, resulting in a one-time, after-tax charge of $2.7 million in the third quarter of 2012.years ended December 31:



	2012							2011							2010
In thousands, except per share data	Reported Balance		Adjust- ment			Adjusted Balance		Reported Balance		Adjust- ment			Adjusted Balance		Reported Balance		Adjust- ment			Adjusted Balance
Other income and expense, net	$	4,936	$	(1,777	)	$	3,159	$	4,523	$	(1,411	)	$	3,112	$	7,102	$	(1,083	)	$	6,019
Income before income taxes	103,959		(1,777		)	102,182		107,280		(1,411		)	105,869		122,129		(1,083		)	121,046
Income tax expense	44,104		(701		)	43,403		43,382		(557		)	42,825		49,462		(429		)	49,033
Net Income	59,855		(1,076		)	58,779		63,898		(854		)	63,044		72,667		(654		)	72,013
Comprehensive income	58,364		(1,076		)	57,288		62,702		(854		)	61,848		72,031		(654		)	71,377
Basic EPS	2.23		(0.04		)	2.19		2.39		(0.03		)	2.36		2.73		(0.02		)	2.71
Diluted EPS	2.22		(0.04		)	2.18		2.39		(0.03		)	2.36		2.73		(0.03		)	2.70

The ~~OPUC deferred various items for future resolution in separate proceedings including~~following table presents the ~~Commission's review~~balance sheet effects of ~~the Company's recovery~~this revision as of its working gas inventory carrying costs, the decision regarding whether prepaid pension asset should be included in rate base, and the Commission's review of the Company's revenue-sharing arrangement on its interstate storage activities.December 31:

~~Issuance of Long-Term Debt~~

In July 2012, we signed a bond purchase agreement with investors which closed on October 30, 2012, whereby we issued $50 million of NW Natural first mortgage bonds with a coupon rate of 4.00 percent and a 30-year maturity. The proceeds of the issuance will be used to reduce short-term debt and for other general corporate purposes.



	2012							2011
In thousands	Reported Balance		Adjustment			Adjusted Balance		Reported Balance		Adjustment			Adjusted Balance
Non-current assets:
Regulatory assets	$	387,888	$	(5,633	)	$	382,255	$	371,392	$	(3,856	)	$	367,536
Total non-current assets	2,535,054		(5,633		)	2,529,421		2,397,885		(3,856		)	2,394,029
Total assets	2,818,753		(5,633		)	2,813,120		2,746,574		(3,856		)	2,742,718
Liabilities and equity:
Deferred credits and other non-current liabilities:
Deferred tax liabilities	$	446,604	$	(2,227	)	$	444,377	$	413,209	$	(1,526	)	$	411,683
Total deferred credits and other non-current liabilities	1,025,584		(2,227		)	1,023,357		975,922		(1,526		)	974,396
Equity:
Retained earnings	385,753		(3,406		)	382,347		373,905		(2,330		)	371,575
Total equity	733,033		(3,406		)	729,627		714,488		(2,330		)	712,158
Total liabilities and equity	2,818,753		(5,633		)	2,813,120		2,746,574		(3,856		)	2,742,718

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The following tables present the income statement and balance sheet corrections for the following quarters:



	2012
	First Quarter				Second Quarter				Third Quarter						Fourth Quarter
In thousands, except per share data	Reported Balance		Adjusted Balance		Reported Balance		Adjusted Balance		Reported Balance			Adjusted Balance			Reported Balance		Adjusted Balance
Other income and expense, net	$	1,005	$	472	$	921	$	620	$	1,710		$	1,180		$	1,300	$	887
Income (loss) before income taxes	68,480		67,947		2,296		1,995		(13,594		)	(14,124		)	46,777		46,364
Income tax expense (benefit)	27,873		27,663		887		768		(3,036		)	(3,245		)	18,380		18,217
Net income (loss)	40,607		40,284		1,409		1,227		(10,558		)	(10,879		)	28,397		28,147
Comprehensive income (loss)	40,773		40,450		1,575		1,393		(10,391		)	(10,712		)	26,407		26,157
Basic EPS	1.52		1.50		0.05		0.05		(0.39		)	(0.41		)	1.06		1.05
Diluted EPS	1.51		1.50		0.05		0.05		(0.39		)	(0.41		)	1.05		1.04

Non-current assets:
Regulatory assets	$	368,521	$	364,132	$	366,981	$	362,290	$	367,692		$	362,472		$	387,888	$	382,255
Total non-current assets	2,416,372		2,411,983		2,448,359		2,443,668		2,492,467			2,487,247			2,535,054		2,529,421
Total assets	2,727,262		2,722,873		2,635,141		2,630,450		2,690,368			2,685,148			2,818,753		2,813,120
Liabilities and equity:
Deferred credits and other non-current liabilities:
Deferred tax liabilities	$	438,486	$	436,750	$	440,073	$	438,217	$	430,885		$	428,821		$	446,604	$	444,377
Total deferred credits and other non-current liabilities	999,028		997,292		991,007		989,151		985,729			983,665			1,025,584		1,023,357
Equity:
Retained earnings	402,599		399,946		392,082		389,247		369,584			366,428			385,753		382,347
Total equity	745,971		743,318		737,570		734,735		717,559			714,403			733,033		729,627
Total liabilities and equity	2,727,262		2,722,873		2,635,141		2,630,450		2,690,368			2,685,148			2,818,753		2,813,120

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	2011
	First Quarter				Second Quarter				Third Quarter						Fourth Quarter
In thousands, except per share data	Reported Balance		Adjusted Balance		Reported Balance		Adjusted Balance		Reported Balance			Adjusted Balance			Reported Balance		Adjusted Balance
Other income and expense, net	$	1,214	$	1,291	$	1,122	$	779	$	1,781		$	1,426		$	406	$	(384	)
Income (loss) before income taxes	68,627		68,704		3,509		3,166		(14,012		)	(14,367		)	49,156		48,366
Income tax expense (benefit)	27,854		27,884		1,316		1,181		(5,700		)	(5,840		)	19,912		19,600
Net income (loss)	40,773		40,820		2,193		1,985		(8,312		)	(8,527		)	29,244		28,766
Comprehensive income (loss)	40,919		40,966		2,339		2,131		(8,166		)	(8,381		)	27,610		27,132
Basic EPS	1.53		1.53		0.08		0.07		(0.31		)	(0.32		)	1.09		1.08
Diluted EPS	1.53		1.53		0.08		0.07		(0.31		)	(0.32		)	1.09		1.07

Non-current assets:
Regulatory assets	$	345,452	$	343,085	$	326,081	$	323,371	$	328,757		$	325,692		$	371,392	$	367,536
Total non-current assets	2,290,848		2,288,481		2,294,100		2,291,390		2,317,293			2,314,228			2,397,885		2,394,029
Total assets	2,571,553		2,569,186		2,521,994		2,519,284		2,567,840			2,564,775			2,746,574		2,742,718
Liabilities and equity:
Deferred credits and other non-current liabilities:
Deferred tax liabilities	$	396,357	$	395,419	$	398,825	$	397,751	$	394,217		$	393,003		$	413,209	$	411,683
Total deferred credits and other non-current liabilities	873,714		872,776		874,842		873,768		866,927			865,713			975,922		974,396
Equity:
Retained earnings	385,899		384,470		376,489		374,853		356,574			354,723			373,905		371,575
Total equity	723,228		721,799		714,628		712,992		696,605			694,754			714,488		712,158
Total liabilities and equity	2,571,553		2,569,186		2,521,994		2,519,284		2,567,840			2,564,775			2,746,574		2,742,718



	Six months ended June 30, 2012				Nine months ended September 30, 2012
In thousands, except per share data	Reported Balance		Adjusted Balance		Reported Balance		Adjusted Balance
Other income and expense, net	$	1,926	$	1,092	$	3,636	$	2,272
Income before income taxes	70,776		69,942		57,182		55,818
Income tax expense	28,760		28,431		25,724		25,186
Net Income	42,016		41,511		31,458		30,632
Comprehensive income	42,348		41,843		31,957		31,131
Basic EPS	1.57		1.55		1.17		1.14
Diluted EPS	1.56		1.54		1.17		1.14

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

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 or we)~~Company) financial condition, including the principal factors that affect results of operations. The disclosures contained in this report refer to our consolidated activities for the three ~~and nine~~ months ended ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012. Unless otherwise indicated, references below to “Notes” are to the Notes to 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 these three ~~and nine~~ month periods are not necessarily indicative of expected fiscal year results. Therefore, this discussion should be read in conjunction with our ~~2011~~2012 Annual Report on Form 10-K ~~(2011~~(2012 Form 10-K).

The consolidated financial statements include ~~the accounts of~~ NW Natural, the parent company, and its direct and indirect wholly-owned subsidiaries, which ~~include: NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch)~~include and ~~NNG Financial Corporation (NNG Financial). These~~are organized as follows:

We operate in two primary reportable business segments, local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as “other.” We refer to our local gas distribution business as the “utility,” and our “gas storage” and “other” business segments as “non-utility.” In addition, our statements also include ~~accounts related to~~ our equity investment in Palomar Gas Holdings, LLC (PGH), which is pursuing the development of a proposed natural gas pipeline through its wholly-owned subsidiary, Palomar Gas Transmission, LLC (Palomar). These accounts make up our regulated local gas distribution business, our regulated gas storage businesses, and other regulated and non-regulated investments primarily engaged in energy-related businesses. In this report, the term “utility” is used to describe our regulated gas distribution business (local distribution company), and ~~the term “non-utility” is used to describe our gas storage businesses (gas storage) and other business segments. Our gas storage segment includes NWN Gas Storage, Gill Ranch, non-utility portions~~NNG Financial's investment in KB Pipeline. For a further discussion of our underground storage facility in Oregon (Mist), and revenues from third-party asset management services. The term “other” is used to describe our other regulated and non-regulated investments and business activities (other). For further information on our business segments, see Note 4.

In addition to presenting results of operations and earnings amounts in total, certain financial measures are expressed in cents per ~~share.~~share, which is a non-GAAP financial measure. These amounts reflect factors that directly impact earnings. ~~We believe this per share information is useful because it enables readers to better understand~~In calculating these financial disclosures, we allocate income tax expense based on the ~~impact of these factors on consolidated earnings.~~effective tax rate, where applicable. All references in this section to earnings per share (EPS) are on the basis of diluted shares (see Part II, Item 8., Note 3, “Earnings Per Share,” in our ~~2011~~2012 Form 10-K). We use such non-GAAP measures ~~(i.e. measures not based on generally accepted accounting principles)~~ in analyzing our financial performance ~~and~~because we believe ~~that~~ they provide useful information to our investors and creditors in evaluating our financial condition and results of operations.

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EXECUTIVE SUMMARY

Key financial highlights include:



	Three Months Ended March 31,
In thousands, except per share data	2013		2012		Change
Consolidated net income	$	37,639	$	40,284	$	(2,645	)
Consolidated EPS	1.40		1.50		(0.10		)
Utility margin	127,300		133,150		(5,850		)

~~Executive Summary~~

~~Summary of consolidated results~~Results for the ~~third~~first quarter of ~~2012~~ as 2013 compared to the ~~same period~~first quarter of 2012 include:

a decrease in ~~2011~~ ~~include:~~

~~Consolidated~~consolidated net ~~loss~~ of ~~$10.6 million~~ or 39 ~~cents per share in~~ ~~2012, compared~~income and EPS primarily due to ~~a net loss of~~ ~~$8.3 million~~ or 31 ~~cents per share in 2011;~~

~~Net loss from~~lower utility margin, partially offset by lower utility operations ~~increased~~ ~~$2.3 million~~ to ~~$11.9 million~~ in ~~2012, which included a one-time, after-tax charge of $2.7 million related to the general rate case;~~

~~Net~~and maintenance expenses, and higher net income from gas storage ~~operations increased~~ ~~$0.1 million~~,operations;

a decrease in utility margin primarily related to the revenue timing impacts in this first year following the 2012 Oregon General Rate Case. In addition, lower gains from ~~$1.2 million~~gas cost savings decreased utility margin due to larger decreases in ~~2011~~actual gas prices compared to ~~$1.3 million~~ in ~~2012~~;

~~Cash flow from operating activities decreased~~ ~~$13.2 million, from~~ ~~$191.3 million~~ ~~in 2011 to~~ ~~$178.1 million~~Purchased Gas Adjustment (PGA) rates in 2012 ~~which included~~versus 2013; and

increases in utility margin from customer growth and the rate-base return on our gas reserve investments.

In addition to our financial results for the first quarter of 2013, we also continue to make progress on several key initiatives including:

customer growth opportunities through regulatory and legislative efforts for natural gas in the vehicle transportation market, as well as marketing efforts in our traditional customer groups;

planning work on the next gas storage expansion at our Mist facility; and

resolving regulatory dockets that remained open from the 2012 Oregon general rate case.

Our progress on, and commitment to, these initiatives are a ~~$39 million refund credited to customers for their share~~part of ~~the current year's gas cost savings;~~our core business objectives and

~~Utility customer count increased by approximately~~ long-term strategic plan. See Part II, Item 7, “~~6,900~~2013 Outlook ~~over the last 12 months, for an annual growth rate of~~ ” in our 2012 Form 10-K and "~~1.0 percent~~Strategic Opportunities ~~compared to 0.8 percent a year ago.~~" below.

Issues, Challenges and Performance Measures

~~Economic environment.~~ECONOMY. ~~Continued weakness in the~~The local, national, and global economies ~~have impacted utility customer~~showed some signs of growth ~~business demand for natural gas and market prices for gas storage.~~during the first quarter of 2013. Our utility’s annual customer growth rate was ~~1.0 percent~~1.1% at ~~September 30, 2012~~March 31, 2013, as compared to ~~0.9 percent at June 30, 2012 and 0.8 percent~~0.8% at ~~September 30, 2011~~March 31, 2012. The ~~local economy is showing signs of a slow recovery, with~~ unemployment rates in our region have declined to approximately 8% from over 11% in 2009, and new housing permits in Oregon ~~and southwest Washington declining from 2011~~have increased. We will continue to ~~2012 and industrial customers adding natural gas equipment in certain market sectors. We~~monitor the economy, but believe our utility business is well positioned to continue adding customers and to serve increasing ~~industrial~~energy demand as the economy recovers because of low, stable natural gas prices, our relatively low market penetration, and our ongoing focus on converting homes and businesses to natural ~~gas, and the potential for~~gas. In addition, environmental initiatives ~~favoring~~that favor lower carbon emissions and lower cost energy alternatives such as natural gas ~~use~~could increase demand for our services in ~~our region.~~the future.

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~~Managing gas prices and supplies.~~GAS PRICES AND SUPPLIES. Our gas acquisition ~~and management~~ strategy is to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices so we can effectively manage costs, reduce price volatility, ~~for customers~~ and maintain a competitive advantage. With recent developments in drilling technologies and substantial access to ~~gas~~ supplies ~~from shale formations~~ around the U.S. and in Canada, the current outlook for North American natural gas supply is strong and is projected to remain this way well into the future. The continuation of low and stable gas prices in the future depends on a combination of supply outlook and demand factors as well as a regulatory environment that continues to support hydraulic fracturing and other drilling technologies.

Our utility’s annual ~~Purchased Gas Adjustment (PGA)~~PGA mechanisms in Oregon and Washington, combined with our gas price hedging strategies, enable us to reduce earnings exposure for the Company and ~~reduce price volatility~~secure low, stable gas costs for our customers. These lower gas prices, coupled with our focus on customer service and cost-effective energy efficiency programs, help strengthen natural gas’ competitive advantage over other energy sources in our key markets.See "Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment" below.

We typically hedge gas prices for approximately ~~75 percent~~75% of our utility’s annual sales requirement based on ~~normal~~average weather, including both physical and financial hedges. AtWe entered the ~~beginning of the November~~2012-13 gas year (November 1, ~~2011~~2012 – October 31, ~~2012 gas contract year, we were 51 percent~~2013) hedged ~~with~~at 75% of our forecasted sales volumes, including 47% in financial ~~swap~~swaps and option contracts and ~~24 percent hedged with~~28% in physical gas supplies. The physical ~~supplies~~hedges consisted of a combination of gas inventories in

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storage, ~~gas~~local production from the Mist area, ~~where we buy at pre-determined prices based on the Company's weighted average cost of gas,~~ and ~~gas~~supply region production from utility gas reserves we invested in with Encana Oil & Gas (USA) Inc. (Encana). Our investment in gas reserves with Encana began in 2011. We own working interests in certain leases in Encana’s Jonah gas field located in Rock Springs, Wyoming.reserve investments. For a further discussion of gas reserves, see ~~“Investments in~~ “Strategic Opportunities—Gas ~~Reserves” under “Strategic Opportunities” below and “Gas Reserves” under “Rate Mechanisms”~~Reserves” below.

In addition to the amount hedged for the current gas contract year, we ~~estimate our hedge levels~~are also hedged at ~~72 percent~~approximately 25% for the ~~upcoming 2012-13~~2013-14 gas year ~~as of~~ ~~September 30, 2012. We have also entered into~~and between 8% and 23% hedged for annual requirements over the following five gas ~~reserve purchases and financial hedge transactions to cover periods beyond this upcoming gas contract year.~~years. Our hedge levels are subject to change based on actual load volumes, which depend to a certain extent on weather and economic conditions. ~~In addition,~~Also, our storage inventory levels may increase or decrease based on storage expansion, storage contracts with third parties, or storage recall by the utility. We expect recovery of our utility storage costs, including demand charges and other operating costs, through the normal PGA mechanism. As for gas reserve purchases and Mist area gas production, we include estimates in our hedge levels, which are subject to change based on possible unforeseen events including the impact from the pace of drilling activity and the volume of production from each well.

Although less expensive and more stable gas prices provide opportunities to manage costs for our utility customers, they also present challenges for our gas storage businesses by lowering the price of, and reducing the demand for, storage services. Consequently, our ability to sign ~~longer-term~~ storage contracts with customers at favorable prices affects our ~~ability~~financial results. However, if there is an increase in demand for natural gas or a decrease in drilling activity, there may be upward pressure on gas prices or an increase in gas price volatility, which may result in increased demand or prices for storage services. In the short-term, we strive to ~~improve financial results, but we remain committed to finding~~find opportunities for increasing revenues, lowering costs, and developing enhanced services for storage customers.

~~Environmental clean-up costs.~~ENVIRONMENTAL COSTS. We ~~continue to~~ accrue all ~~material~~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 or remediation solutions approved by regulatory agencies, actual costs could vary significantly from our loss estimates. As a regulated utility, we have been allowed to defer certain costs pursuant to regulatory actions. In our most recent general rate case, the ~~OPUC~~Public Utility Commission of Oregon (OPUC) approved the recovery of costs from environmental site remediation subject to certain conditions as noted in "Results of Operations—Regulatory Matters—Rate ~~Mechanisms"~~Mechanisms" below.

We ~~pursue~~are pursuing recovery from insurance policies through litigation and only seek recovery from customers ~~only~~ for amounts not ~~recovered from~~covered by insurance. Ultimate recovery of environmental costs ~~either~~ from regulated utility rates ~~or from insurance,~~ will depend on our ability to effectively manage these costs, demonstrate that costs were prudently incurred, and the impact of any earnings ~~review~~test the OPUC ~~may adopt~~adopts as a result of a currently open proceeding. Environmental cost recovery and carrying charges on amounts charged to Washington customers will be determined in a ~~subsequent~~future proceeding. ~~Recovery~~Based on these proceedings, recovery may vary significantly from amounts currently recorded as regulatory assets, and amounts not recovered would be required to be charged to income in the period they were deemed to be unrecoverable. See Note 13 in this report and Note 15 in our ~~2011~~2012 Form 10-K.

~~Performance measures.~~PERFORMANCE MEASURES. In order to deal with the ~~issues and~~ challenges affecting our businesses, we annually review and update our strategic plan to map out a course ~~over~~for the next several years. Our plan ~~includes: further improving~~includes strategies for:

growing our utility ~~gas distribution system; enhancing utility and gas storage~~ services and operations;

exploring new service opportunities in the natural gas industry;

optimizing and growing our ~~utility and~~ non-utility gas storage businesses;

investing in natural gas infrastructure ~~projects when necessary~~as needed to support the energy needs of our region; and

maintaining a leadership role ~~within~~in the gas utility industry by ~~addressing~~advancing long-term energy ~~policies~~policies.

See Part II, Item 7, “Issues, Challenges, and ~~pursuing business opportunities that support clean energy technologies. We intend to measure~~Performance Measures” in our 2012 Form 10-K for a discussion of our performance ~~and monitor progress on relevant metrics including, but not limited to: earnings per share growth; total shareholder return; return on invested capital;~~metrics.

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utility return on equity; utility customer satisfaction ratings; utility margin; utility capital and operations and maintenance expense per customer; and earnings before interest, taxes, depreciation and amortization (EBITDA).

Strategic Opportunities

~~Safety, reliability and service.~~SAFETY, RELIABILITY, AND SERVICE. ~~To optimally respond~~We are continually committed to ~~new federal pipeline~~customer and employee safety, ~~legislation~~operational effectiveness, service quality, and ~~system~~leveraging our competitive position. We have several ongoing initiatives designed to improve the quality, effectiveness, and integrity ~~requirements as well as increasing customer expectations for service responsiveness,~~of our utility and non-utility business operations, and we have upgraded several facilities to enhance business continuity, employee training, safety, productivity, and energy efficiency. In particular, our initiatives in 2013 will further enhance our commitment to safety. For example, the Company has increased staffing levels in the areas of pipeline safety, emergency response, regulatory compliance, field training, and customer ~~service. We have several ongoing initiatives designed~~service to ~~improve the quality~~respond to new federal pipeline safety legislation and system integrity of our pipeline infrastructure, and to upgrade several facilities to enhance business continuity, employee training and safety, productivity and energy efficiency. We are committed to continued improvement in operational effectiveness and capitalizing on our competitive position andrequirements as well as customer expectations for service ~~quality.~~responsiveness.

~~Gas storage.~~GAS STORAGE. We ~~currently~~ own and operate two underground gas storage facilities—the Mist facility in Oregon and the Gill Ranch facility innear Fresno, California. ~~Our Mist facility currently consists of 16 Bcf of available storage capacity, with 10 Bcf allocated to the utility business~~Storage operations benefit from seasonal swings in commodity pricing and 6 Bcf allocated to the gas storage business. Our wholly-owned subsidiary, Gill Ranch, holds a 75 percent undivided ownership interest in the Gill Ranch facility; Pacific Gas and Electric Company (PG&E) owns the other 25 percent interest. Our interest in the Gill Ranch facility currently consists of 15 Bcf of available storage capacity. Future expansion is possible at both the Mist and Gill Ranch storage facilities to serve increasing demand should the market ~~for gas storage improve. For more information, see~~ ~~Note 4~~ ~~in this report and Part II, Item 7., “2012 Outlook—Strategic Opportunities,” in our 2011 Form 10-K.~~

Due to an abundant supply of natural gas and lower, more stable prices in North America, storage values are expected to remain relatively low in the near term, which will likely affect the prices at which Gill Ranch is able to contract. Gas prices hit a 10-year low in early 2012, and this has resulted in certain natural gas producers reducing their levels of exploration and production. At the same time, we expect lower gas prices to increase demand for natural gas because lower pricing provides a competitive advantage over alternative energy sources, such as switching coal plants to natural gas and increasing demand for exporting natural gas. Combined, these demand forces, and reduced drilling activity, may ultimately result in upward pressure on gas prices and return some price volatility to natural gas markets.

volatility. Our storage facilities position us ~~well~~ to capitalize on rising demand for natural gas, higher gas

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prices, or increased market volatility. Currently natural gas prices remain relatively low and stable; however, if there is an increase in demand for natural gas, a decrease in drilling activity, or other factors, including weather, there may be upward pressure on gas prices or price volatility because storage operations benefit from seasonal swings in commodity prices and market volatility. Additionally, if market demand increases and we are able to obtain regulatory permits and project financing, wemay return. We have the ability to expand ~~the Mist and Gill Ranch~~both facilities beyond their current capacities. We estimate that the current Gill Ranch storage facility could support an additional 20 Bcf of storage capacity, bringing total capacity up to 40 Bcf with certain infrastructure modifications, but with no further expansion of our gas transmission pipeline, of which we would have the rights to an additional 5 Bcf or ultimately 50 percent of the total capacity.

The Pacific Northwest storage ~~markets are~~market has also been impacted by lower gas prices and lack of gas price volatility, although less than in California ~~markets primarily because of fewer regional competitors. Nevertheless, we continue~~due to ~~plan for expansion of our gas storage facilities at Mist in anticipation of increased natural gas demand for electric~~greater seasonal price differentials. In addition, new flexible gas-fired generation is needed in the ~~Pacific Northwest. Earlier this year,~~region to integrate intermittent wind resources into the power system, thereby increasing the associated need for gas storage. As a ~~request for proposals (RFP) to provide additional energy generation was sent out~~result, we are at the beginning stage of a new expansion at Mist. This expansion is anchored by ~~Portland General Electric (PGE). As part of the RFP process, PGE submitted its own “benchmark” bids that other third party bids must compete with. The Company has~~ an agreement to provide gas storage services to PGE ~~should their bid be selected.~~

~~As discussed above, we continue to evaluate future storage expansion~~for gas-fired generation facilities at ~~Gill Ranch and Mist; however, we do not currently have a set timeline for these developments. We believe the earliest timeframe for completing the next~~Port Westward, Oregon. Our Mist expansion project is ~~2016, and no timeline is currently set for Gill Ranch. In the meantime, we expect~~subject to ~~continue working on preliminary design and scope of the next Mist~~several conditions, including NW Natural receiving regulatory approval. This expansion ~~which~~ will likely include the development of new storage wells, a ~~second compression~~compressor station, and additional pipeline ~~gathering facilities.~~facilities that would enable more storage expansions in the future. Our goal is to have the additional storage capacity in service during 2016.

In addition, we currently estimate that the Gill Ranch storage facility could support an additional 25 Bcf of storage capacity, bringing the total storage capacity to approximately 45 Bcf, of which our current rights would give us up to an additional 6.25 Bcf or ownership of a total of approximately 22.5 Bcf. An expansion at the Gill Ranch storage facility would require certain infrastructure investments, but no further expansion of our gas transmission pipeline.

~~Pipeline diversification.~~PIPELINE DIVERSIFICATION. Currently, our utility operations and gas storage operations at Mist depend on a single bi-directional interstate transmission pipeline to ship ~~customer supplies. Palomar, a wholly-owned subsidiary of PGH, is pursuing~~gas supplies to customers. We continue to work with regulators and utilities in the ~~development of~~Pacific Northwest to advance a new ~~gas transmission~~integrated, regional cross-Cascades pipeline ~~that would provide an interconnection with~~through our ~~utility distribution system~~Palomar investment to ~~better serve~~reduce this risk and create diversity and increased reliability for our ~~utility customers as well as the growing natural gas markets in Oregon and other parts of the Pacific Northwest.~~ system.

~~This~~The proposed pipeline would be ~~subject to regulation~~regulated by the Federal Energy Regulatory Commission (FERC). Palomar intends to file an application with FERC for a ~~new~~pipeline delivering gas from the GTN pipeline near Madras in central Oregon to a NW Natural hub near Molalla, Oregon. The application will be filed after itNW Natural has completed resource plans and Palomar has conducted a new open season to obtain ~~specific~~adequate commercial support for the pipeline. The approval and timing of potential construction of the pipeline will depend on the project being competitive with alternative Pacific Northwest pipeline projects, obtaining regulatory permits, and garnering the necessary commercial support from shippers. See ~~Part II, Item 7., “2012 Outlook—Strategic Opportunities,” in our 2011 Form 10-K.~~Note 11 for further discussion.

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~~Utility gas reserves.~~GAS RESERVES. In addition to hedging gas prices with financial ~~swap and option~~derivative contracts, we entered into an agreement with Encana Oil & Gas (USA) Inc. (Encana) in 2011 ~~to develop physical gas supplies~~ to hedge a portion of our Oregon utility customers’ ~~requirements~~cost of gas over an estimated 30 years. We have invested in working interests in certain gas leases. These working interests are in a gas field located in Sublette County, Wyoming. During the first 10 years of the contract, we forecast the volumes of gas to be produced under the ~~Encana~~gas reserves agreement ~~will~~as sufficient to hedge approximately 88% to ~~10 percent~~10% of the average annual requirements of our utility customers. Under the agreement, we expect to invest approximately $45 million to $55 million per year for five years, subject to certain NW Natural rights to terminate the agreement, with our total investment expected to be about $250 million. We pay a fixed portion of drilling costs per well, and Encana assigns to us working interests in leases to certain sections of the Jonah gas field, located near Rock Springs, Wyoming. These sections include both future and currently producing wells. The working interest entitles us to receive a portion of the gas produced in the assigned sections. Encana is the operator, and we pay our proportionate share of the operating costs. Currently, the Encana transaction is expected to hedge approximately 8 percent of our utility gas supply ~~for the 2012-13 gas year.~~requirements. We ~~also continue to evaluate additional investments in gas reserves as part of our gas hedging strategy. We~~ receive certain federal tax deductions ~~associated with~~for drilling ~~costs.~~costs incurred under our gas reserves agreements. The timing of when ~~the Company realizes~~we realize these federal tax benefits ~~from these drilling costs may be~~has been affected by net operating losses (NOLs) for tax purposes, which will be carried forward to reduce our current tax liability in future years. We continue to evaluate additional investments in gas reserves as part of our gas hedging strategy. See ~~Results~~Part II, Item 7, "Results of Operations—Regulatory Matters—Rate Mechanisms—Gas Reserves ~~below and Part II, Item 7., “2012 Outlook—Strategic Opportunities,”~~" in our ~~2011~~2012 Form 10-K.

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CONSOLIDATED EARNINGS AND DIVIDENDS

Consolidated Earnings ~~and Dividends~~

Consolidated highlights include:



	Three Months Ended March 31,
In thousands, except per share data	2013		2012		Change
Consolidated operating revenues	$	277,861	$	309,639	$	(31,778	)
Consolidated operating expenses	203,655		230,973		(27,318		)
Consolidated interest expense, net	11,127		11,191		(64		)
Consolidated net income	37,639		40,284		(2,645		)
Consolidated EPS	1.40		1.50		(0.10		)

~~Three months ended~~2013 COMPARED TO 2012. ~~September 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:

~~For the~~ ~~three months endedSeptember 30, 2012, we reported a net~~ ~~loss~~ of ~~$10.6 million, or~~ ~~39 cents~~ ~~per share, compared to a net~~ ~~loss~~ of ~~$8.3 million, or~~ ~~31 cents~~ ~~per share, for the same period last year.~~

The primary factors contributing to decreased ~~third~~first quarter consolidated net income were:

a $~~2.7~~$5.9 million decrease in ~~income tax benefits~~utility margin primarily due ~~to a one-time charge related to the Oregon general rate case;~~to:


◦	a decrease in utility margin related to the revenue timing impact of changes in fixed monthly charges and the decoupling baseline in rates from our 2012 Oregon general rate case;


◦	the overall revenue reduction tied partly to the lower authorized return on equity also from our rate case mentioned above; and


◦	lower contribution to margin from our gas cost incentive sharing mechanism.


◦	Partially offsetting these decreases were margin increases from customer growth and our gas reserves investment.

a $~~0.8~~0.9 million increase in depreciation and amortization expenses primarily due to a higher level of investment in utility property, plant and ~~equipment; and~~

a ~~$0.6 millionincrease~~ in operations and maintenance expense primarily due to increases in utility payroll and utility non-payroll expense including higher costs for safety enhancements, business development, information technology system maintenance and other customer service cost increases, partially offset by decreases in employee incentive compensation.equipment.

Partially offsetting the above factors ~~was:~~

were:

a $~~1.3~~1.5 million increase in ~~utility margin~~gas storage operating revenues primarily due to ~~an increase in revenues related to customer growth, an increase in revenues related to our gas cost incentive sharing mechanism, and a decrease in~~ revenue ~~sharing with customers~~increases from ~~our annual earnings test accrual.~~

~~Nine months endedSeptember 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:

~~Net income was~~ ~~$31.5 million, or~~ ~~$1.17~~ ~~per share,~~additional contracted storage capacity at Gill Ranch for the ~~nine months ended~~ ~~September 30, 2012, compared to~~ ~~$34.7 million, or~~ ~~$1.30~~ ~~per share, for the same period last year.~~2012-2013 gas storage year;

~~The primary factors contributing to decreased year-to-date net income were:~~

a $~~5.6~~0.7 million ~~increase~~decrease in utility operations and maintenance expense due to ~~increases~~a decrease in ~~utility payroll and employee benefit costs, utility training costs, and expenses related to~~ our ~~Oregon general rate case;~~

~~a $2.7 million one-time, after-tax tax charge related to the Oregon general rate case.~~

a ~~$2.0 millionincrease~~ ~~in depreciation and amortization expenses primarily due to higher levels of investment in property, plant and equipment at the utility and gas storage operations;~~

a ~~$1.4 millionincrease~~ ~~in general taxes primarily due to increased property values and associated taxes at Gill Ranch;~~allowance for uncollectible accounts; and

a $~~1.2~~1.7 million ~~increase~~decrease in ~~interest~~income tax expense ~~primarily~~ due to ~~the new debt issuance at Gill Ranch late in 2011.~~

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~~Partially offsetting the above factors were:~~

a ~~$6.7 millionincrease~~ ~~in utility margin primarily due to a one-time,~~lower pre-tax ~~charge of $7.4 million in 2011 related to a utility tax law change in Oregon, and an increase of~~ ~~$2.2 million~~ ~~in revenues related to our gas cost incentive sharing mechanism, partially offset by a decrease in utility margin from the effects of warmer weather in 2012 compared to 2011; and~~

~~a $2.4 million~~ ~~increase~~ ~~in gas storage operating income primarily attributable to revenue increases from Gill Ranch from additional contracted storage capacity.~~income.

Dividends ~~paid on our common stock were 44.5 cents per share in the third quarter of 2012, compared to 43.5 cents per share in the third quarter of 2011.~~

Dividend highlights include:



	Three Months Ended March 31,
Per common share	2013		2012		Change
Dividends paid	$	0.455	$	0.445	$	0.01

The Board of Directors declared a quarterly dividend on our common stock of 45.5 cents per share, payable on ~~November~~May 15, ~~2012,~~2013, to shareholders of record on ~~October 31, 2012. The current~~April 30, 2013, reflecting an indicated annual dividend rate isof $1.82 per share.

~~Application of Critical Accounting Policies and Estimates~~

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

~~regulatory cost recovery and amortizations;~~

~~revenue recognition;~~

~~derivative instruments and hedging activities;~~

~~pensions and postretirement benefits;~~

~~income taxes; and~~

~~environmental contingencies.~~

There have been no material changes to the information provided in the 2011 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 2011 Form 10-K), except as indicated below under regulatory cost recovery and pension contributions.

~~Regulatory Cost Recovery~~

In the Oregon general rate case, the OPUC ruled that we cannot recover deferred amounts that represent the increase in deferred income taxes caused by the 2009 Oregon tax rate change. As a result, we have recognized a one time, after tax charge of $2.7 million in the quarter.

~~Pension Contributions~~

In July 2012, President Obama signed into law the Moving Ahead for Progress in the 21st Century Act (MAP-21 Act). This legislation changes several provisions affecting pension plans, including temporary funding relief and Pension Benefit Guaranty Corporation (PBGC) premium increases, which reduces the level of minimum required contributions in the near-term but generally increases operational costs of running a pension plan. Prior to the MAP-21 Act, we were using interest rates based on a 24-month average yield of investment grade corporate bonds (also referred to as “segment rate”) to calculate minimum contribution requirements. The MAP-21 Act establishes a new minimum and maximum corridor for segment rates based on a 25-year average of bond yields, which is to be used in calculating contribution requirements. For 2013, the new corridor will be set at no less than 85 percent and no more than 115 percent of the corresponding 25-year average segment rate. In 2014, the corridor widens to 80 percent to 120 percent of the 25-year average, and the corridor continues to widen by 5 percent each year thereafter until reaching 70 percent to 130 percent. Under current market conditions, we estimate the segment rate for the 2013 Plan Year will increase from approximately 4.90 percent to 6.25 percent, and this 1.35 percent increase in interest rates would reduce our minimum contribution requirement by approximately $15 million, from roughly $26 million under the unadjusted 24-month segment rate to roughly $11 million under the adjusted 24-month segment rate using the 85 to 115 percent corridor.

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~~We are continuing to evaluate the impact of MAP-21 on contribution requirements and will update our funding and pension expense estimates in future filings.~~RESULTS OF OPERATIONS

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~~.

~~Results of Operations~~

Regulatory Matters

Regulation and Rates

~~Utility.~~UTILITY. Our utility business is subject to regulation with respect to, among other matters, rates, terms of service, and systems of accounts set by the ~~Oregon Public Utility Commission (OPUC),~~OPUC, Washington Utilities and Transportation Commission (WUTC), and FERC. The OPUC and WUTC also regulate the issuance of securities by our utility. In ~~2011,~~2012, approximately 90 ~~percent~~% of our utility gas volumes and revenues were derived from Oregon customers, with the remaining 10 ~~percent~~% from Washington customers. Earnings and cash flows from utility operations are largely determined by rates set in general rate cases and other regulatory proceedings in Oregon and Washington, but will also be affected by the economies in Oregon and Washington, by the pace of customer growth in the residential and commercial markets, and by 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 "~~Oregon~~ General Rate ~~Case~~Cases" below.

~~Gas Storage.~~GAS STORAGE. Our gas storage business is subject to regulation with respect to, among other matters, issuance of securities and systems of accounts set by the OPUC, California Public Utilities Commission (CPUC), and FERC. The OPUC and FERC regulate ~~our Mist gas~~intrastate and interstate storage ~~business~~services, respectively, under a maximum ~~cost-based rate~~cost of service model ~~whereas~~which allows for storage prices to be set at or below the cost of service as approved by each agency in the last regulatory filing. The CPUC regulates Gill Ranch under a market-based rate model which allows for the price of storage services to be set by the marketplace. ~~Our gas~~In 2012, approximately 54% of our storage revenues were derived from FERC and Oregon regulated operations and approximately 55 percent OPUC and FERC approved cost-based rates and 45 percent CPUC approved market-based rates for the nine months ended September 30, 2012. This compared to 66 percent OPUC and FERC approved rates and 34 percent CPUC approved rates for the same period in 2011.46% from California operations.

See Part II, Item ~~7.,~~7, “Results of Operations—Regulatory Matters,” in the ~~2011~~2012 Form 10-K.

~~Oregon~~ General Rate ~~Case~~Cases

~~In December 2011, we filed an application for a~~OREGON. Our most recent general rate ~~increase with~~case in Oregon was completed in 2012; the ~~OPUC. In the filing, we requested~~OPUC authorized rates to customers based on an ~~increase in authorized annual Oregon jurisdictional revenues~~ROE of ~~$43.7 million, equivalent to a rate increase of 6.2 percent. The filing requested~~9.5% and an ~~authorized~~ overall rate of return ~~on rate base~~ of 8.28 percent, with a return on common stock equity (ROE) of 10.3 percent and a capital structure of 50 percent common equity. The overall amount and percent of the requested rate increase included an estimated $15.1 million increase already included in current rates for the cumulative effect of customer conservation covered by NW Natural's decoupling mechanism, which reflects declining use per customer since 2003. This decision essentially resets the baseline against which changes in use per customer are measured under the Company's decoupling mechanism, which has been in place since 2003. Our requested increase also included costs related to pension contributions, and additional utility services. In its filing, the Company also requested the establishment of a rate recovery mechanism for deferred costs related to our environmental liabilities.

In October 2012, we received a preliminary order concerning the Company's general rate case, which, together with various stipulations that were settled in advance of the order, resulted in the following items being approved by the Commission effective November 1, 2012:

An annual Oregon jurisdictional revenue increase of $8.7 million, equivalent to a rate increase of 1.2 percent. This increase includes the recovery of amounts that had previously been deferred through the company's decoupling mechanism of about $15 million. As a result, the overall effect on the Company is a decline in net operating revenues (utility margin) of approximately $6 million on an annualized basis;

~~An overall rate of return on rate base of 7.78 percent and an authorized ROE of 9.5 percent,~~7.78% with a capital structure of ~~50 percent~~50% common equity and ~~50 percent~~50% long-term ~~debt;~~

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The retention of our current decoupling and weather normalization mechanisms. See Conservation Tariff below and Part II, Item 7., “Results of Operations-Regulatory Matters-Rate Mechanisms,” in the 2011 Form 10-K for detailsdebt. These customer rates went into effect on ~~these programs;~~

A two-year extension of our cap-ex tracking mechanism to recover capital costs related to system integrity program. See Part II, Item 7., “Results of Operations-Regulatory Matters-Rate Mechanisms-System Integrity Program,” in the 2011 Form 10-K for details on this program; and

A new Site Remediation Recovery Mechanism (SRRM) that allows the Company to recover prudently incurred environmental site remediation costs. This SRRM will allow recovery of one-fifth of the Company's current and future deferred expenses each year in rates, subject to an annual prudency review. A separate earnings review will be established, which will be further defined in a future proceeding.November 1, 2012.

The following items were deferred ~~or denied~~for decision by the ~~Commission:~~Commission to separate dockets:

~~The request~~

Prepaid Pension Assets - the Company requested to include prepaid pension assets in rate base and allow a return on and recovery of the ~~asset~~asset; a new docket was ~~denied; however,~~ordered by the OPUC ~~indicated in the preliminary order that it will open a docket~~ to review the treatment of ~~pension expense~~pensions on a general, non-utility-specific basis. That docket is currently open. Until a conclusion is reached, the OPUC has authorized us to continue to collect and defer pension costs ~~as we have historically, as outlined below;~~based on previous rate case recovery amounts;

~~A recent pipeline project totaling $19.1 million was excluded from rate base, but we expect~~

Interstate Storage Sharing - the ~~Company will be permitted to demonstrate prudence of the project in a subsequent regulatory proceeding, with the potential effect of regulatory lag in cost recovery; and~~

~~The recovery of deferred income taxes caused by the 2009 Oregon tax rate change was denied. As a result, we have taken a one-time after-tax charge of $2.7 million in the third quarter.~~

~~The OPUC also deferred decisions on certain issues that were raised in this proceeding including its determination to open dockets to consider: the~~existing arrangement we use to share revenues with customers from our Mist interstate storage operations and optimization ~~with customers;~~services was continued, but a docket is to be opened to review the ~~use of~~sharing arrangement;

Working Gas Inventory - the OPUC ordered a ~~new process~~review to determine the appropriate ~~amounts~~amount of working gas inventory that we earn a return on, and its corresponding rate of ~~return; and whether prepaid pension assets should be added~~return. Included in the general rate decrease effective November 1, 2012 was a reduction in margin of about $4 million related to ~~rate base. A decision~~working gas inventory. We have been authorized to defer the carrying cost on ~~these items is expected in 2013, with the~~ working gas inventory pending the outcome of this open docket. The decision ~~expected to~~on this new docket will be applied retroactively to November 1, ~~2012.~~2012; and

Site Remediation and Recovery Mechanism (SRRM) - the earnings test for our new SRRM is also being developed in a separate, open proceeding; a prudence review for all past deferred environmental expenditures is also being conducted in this proceeding this year. Under the mechanism, an annual review for prudency of subsequent spend will be conducted each year. See "Environmental Costs" below.

~~The OPUC's final order may act to modify~~We expect decisions on these open dockets during 2013 or ~~supplement the information described herein. NW Natural will need to review and analyze the final order of the OPUC in order to more fully determine the effects of the order on NW Natural.~~2014.

Rate Mechanisms

~~Purchased Gas Adjustment (PGA).~~PURCHASED GAS ADJUSTMENT. Rate changes are established for the utility each year under PGA mechanisms in Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases. This includes gas prices under spot purchases as well as contract supplies, gas prices hedged with financial derivatives,

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gas prices from the withdrawal of storage inventories, ~~and~~ the production of gas reserves, interstate pipeline demand costs, the application of temporary rate adjustments, which amortize balances of deferred regulatory accounts, and the removal of temporary rate adjustments effective for the previous year.

In October 2012, the OPUC approved PGA rate changes effective November 1, 2012. The effect of these rate changes was to decrease the average monthly bills of Oregon residential customers by about 7 percent. This was our fourth consecutive year of PGA rate decreases, and cumulatively our Oregon utility residential customer bills declined 26 percent since 2008.

In October 2012, NW Natural's WUTC PGA rates were allowed to go into effect on November 1, 2012. However, the WUTC also ordered a continuing review of hedge transactions of all Washington gas companies' PGA filings. We do not anticipate any changes to our PGA rates as filed; however, if the WUTC were to find any of our hedges to be imprudent, rates could be adjusted as a result of this review. The effect of the ordered PGA rates was to decrease the average monthly bills of Washington residential customers by about 8 percent. This was also our fourth consecutive year of PGA rate decreases in Washington, and cumulatively our Washington utility residential customer bills declined 34 percent since 2008.

Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select each year either an ~~80 percent~~80% deferral or a ~~90 percent~~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 percent~~20% or ~~10 percent~~10% of the difference between actual and estimated gas costs, respectively. For the 2012-2013 PGA year, we selected the 90% deferral option. Under the Washington PGA mechanism, we defer ~~100 percent~~100% of the higher or lower actual gas costs, and those gas cost differences are normally passed on to customers through the annual PGA rate adjustment. ~~See “Customer Credits for Gas Cost Incentive Sharing” below for a discussion of our utility’s early refund to customers of deferred gas cost savings from November 1, 2011 through March 31, 2012.~~

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In addition to the gas cost incentive sharing mechanism, we are subject to an annual earnings review in Oregon to determine if the utility is earning above its authorized ~~return on equity (ROE)~~ROE threshold. If utility earnings exceed a specific ROE level, then ~~33 percent~~33% of the amount above that level is required to be deferred for refund to customers. Under this provision, if we select the ~~80 percent~~80% deferral option, then we retain all of our earnings up to 150 basis points above the currently authorized ROE. If we select the ~~90 percent~~90% deferral option, then we retain all of our earnings up to 100 basis points above the currently authorized ROE. ~~We selected the 90 percent deferral option for the 2010-2011, 2011-2012 and 2012-2013 PGA years.~~ The ROE threshold is subject to adjustment annually based on movements in long-term interest rates. For calendar years 2010 and 2011, the ROE threshold after adjustment for long-term interest rates was 11.02 percent and 10.92 percent, respectively. We refunded $0.2 million to customers based on the 2010 utility earnings test, and based on the recently approved PGA, we will refund $0.7 million to customers based on the 2011 utility earnings test. We do not expect to be subject to a refund for the 2012 or 2013 earnings test ~~year.~~years.

~~Conservation Tariff.~~SYSTEM INTEGRITY PROGRAM (SIP). The OPUC has approved specific accounting treatment and cost recovery for our transmission pipeline integrity management program and the related rules adopted by the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) and provided a two-year extension of our capital expenditure tracking mechanism to recover capital costs related to SIP. We record the costs related to the integrity management program as either capital expenditures or regulatory assets, accumulate the costs over each 12-month period, and recover the revenue requirement associated with these costs, subject to audit, through rate changes effective with the Oregon ~~conservation tariff was reauthorized~~annual PGA. As such, our SIP costs are tracked into rates with the annual PGA filing, except that the first $3.3 million of capital costs, and an annual cap on expenditures of $12 million, are not included in the amounts tracked into rates annually. However, in April 2013 we signed a stipulation, which upon Commission approval, will increase the $3.3 million exclusion to $4 million while also increasing the $12 million annual cap by a total of $13.7 million over the next two tracker years. With the increased cap, we plan to be substantially complete with our bare steel replacement by the end of 2015, and as a result this stipulation precludes us from tracking any additional SIP costs into rates specifically for bare steel replacement after 2015.

ENVIRONMENTAL COSTS. The OPUC has authorized us to defer environmental costs associated with certain named sites and to accrue a carrying cost on amounts deferred, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. Through a series of extensions, the authorized cost deferral and accrual of carrying costs was extended through January 2012. In January 2013, we filed a request with the OPUC to continue our deferral of these environmental costs, and we are awaiting an order from the OPUC.

The new SRRM, authorized in the 2012 Oregon general rate ~~case. The conservation tariff employs~~case, allows the Company to recover prudently incurred environmental site remediation costs, net of insurance recoveries. This SRRM will allow recovery of one-fifth of the Company's currently deferred environmental expenses and future expenses as incurred each year in rates on a ~~use-per-customer decoupling mechanism, which adjusts margin revenues~~rolling basis until all such expenses are recovered, subject 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 nextan annual PGA filing. Baseline consumption was determined by customer consumption data used in the Oregon general rate case. Since 2003, we have experienced a decline of approximately 12 percent in average use per residential customer and a decline of approximately 7 percent in average use per commercial customer. As a resultprudence review. Recovery of these ~~declines, customers have paid surcharges related~~incurred costs will also be subject to an earnings test, which has not yet been defined, but a ~~decoupling adjustment~~docket has been opened on the matter. This earnings test could include deadbands, or other limitations based on our earnings in ~~seven of~~a year, which could reduce the ~~past nine heating seasons. See “Business Segments - Utility Operations,” below.~~amounts we are allowed to recover.

~~Environmental Costs.~~ ~~As noted above, the OPUC has authorized a new environmental cost recovery mechanism as part of the general rate case.~~ The WUTC has also authorized the deferral of environmental costs ~~if any,~~ that are appropriately charged to Washington customers. This order was effective January 26, 2011 with cost recovery and a carrying charge to be determined in a future proceeding. A decision regarding allocation of costs to each state is pending. See Note 13 for further discussion of our regulatory and insurance recovery of environmental costs.

~~Pension Deferral.~~PENSION DEFERRAL. Effective January 1, 2011, the OPUC approved our request to defer annual pension ~~expense~~expenses above the amount set in rates, ~~in our last general rate case. The~~with recovery of these deferred ~~pension costs will be~~amounts 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 on the account balance at the utility’s ~~authorized rate~~actual cost of ~~return.~~

Table of Contents

long-term debt. The ~~reduction to~~deferral from operations and maintenance expense in ~~2011~~2012 was ~~$6.0~~$7.9 million. Future years’ deferrals will depend on changes in plan assets and projected benefit liabilities ~~using~~based on a number of key assumptions, ~~as well as being affected by~~and our pension ~~contributions by the Company.~~contributions. We estimate pension expense deferrals totaling $8 million to $9 million in ~~2012,~~2013, with ~~$2.1 million and $6.3~~$2.3 million being deferred for the three ~~and nine~~ months ended ~~September 30, 2012, respectively.~~ March 31, 2013.

As noted above, ~~no change was made~~the Company continues to ~~our~~seek rate treatment in Oregon for amounts invested in prepaid pension ~~mechanisms as part~~assets in a docket which is currently open. The timing of ~~the general rate case.~~a decision on this docket is uncertain and may continue into 2014.

~~Customer Credits for Gas Cost Incentive Sharing.~~CUSTOMER CREDITS FOR GAS STORAGE SHARING. For the period between November 1, 2011 and March 31, 2012, our actual gas costs were significantly lower than the gas costs currently embedded in customer rates. As a result, our PGA incentive sharing mechanism recorded 90 percent of gas cost savings during this period, attributed to Oregon customers, and 100 percent of the savings attributed to Washington customers, to a regulatory account for credit to customers (see “Purchased Gas Adjustment,” above). Ordinarily, these credits would be refunded in customer rates starting in November under the next year’s PGA filing, but in April 2012 the company requested regulatory approval to immediately refund $35.1 million and $4.2 million to our Oregon and Washington customers, respectively, through billing credits. These credits were approved, and we began crediting these amounts to customer bills in June of 2012.

~~Customer Credits for Gas Storage Sharing.~~In April ~~2012,~~2013, the ~~company~~Company requested regulatory approval to provide its Oregon utility customers with ~~a $9.2~~an $8.8 million interstate storage credit, in their June bills, from our regulatory incentive sharing mechanism related to interstate gas storage and asset management services. ~~The~~Last year, the OPUC approved ~~this~~a $9.2 million credit, ~~and we began crediting this amount~~which was returned to Oregon customer ~~bills~~ in ~~Oregon in~~their June ~~of 2012.~~2012 bills.

For a discussion of other rate mechanisms, see Part II, Item ~~7.,~~7, “Results of Operations—Regulatory Matters—Rate ~~Mechanisms”~~Mechanisms” in our ~~2011~~2012 Form 10-K.

~~Table of Contents~~

Business Segments - ~~Utility~~Local Gas Distribution "Utility" Operations

Our utility margin results are largely affected by customer growth and, to a certain extent, by changes in volume 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 accounting adjustment 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 our utility’s earnings and customer charges. ~~For~~See “Results of Operations—Regulatory Matters—Rate Mechanisms” in our 2012 Form 10-K for more information on our ~~conservation~~decoupling and weather normalization ~~tariffs, see discussion under “Results of Operations—Regulatory Matters—Rate Mechanisms” in our~~ mechanisms.

Utility segment highlights include:



	Three Months Ended March 31,
In thousands, except per share data	2013		2012		Change
Utility net income	$	36,031	$	39,468	$	(3,437	)
EPS - utility segment	$	1.34	$	1.47	$	(0.13	)
Gas sold and delivered (in therms)	400,190		408,159		(7,969		)
Utility margin⁽¹⁾	$	127,300	$	133,150	$	(5,850	)

~~2011~~⁽¹⁾ ~~Form 10-K.~~

~~Three months ended September 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:See Utility Margin Table below for additional detail.

~~Utility operations resulted in a net loss of $~~2013 COMPARED TO 2012. ~~11.9 million, or~~ ~~44 cent~~ ~~cent per share, for the~~ ~~third quarter~~ of ~~2012~~ ~~compared to a net loss of $9.5 million, or 35 cents per share, for the~~ ~~third quarter~~ of ~~2011~~. The ~~increase in the 2012 net loss was primarily due~~primary factors contributing to the one-time tax charge related to Oregon general rate case and higher operating expenses, partially offset by increases in utility margin. See "Application of Critical Accounting Policies and Estimates—Regulatory Cost Recovery" for additional information on the tax charge from the general rate case.

~~Gas Utility Volumes, Revenues and Utility Margin~~

~~Total utility volumes sold and delivered for the~~ ~~third quarter~~ of ~~2012~~ ~~were relatively flat compared to last year, while revenues were~~ ~~$4.4 million~~ ~~lower than last year but utility margin was~~ ~~$1.3 million~~ higher compared to the same period last year. The decrease in revenues was primarily due to customer rate decreases, while the increase in utility margin was due to customer growth in residential and commercial sectors, gas cost incentive sharing from lower natural gas prices, and lower revenue sharing from annual utility earnings review compared to last year. The net increase in customer count was approximately 6,900 over the last twelve months, for an annual growth rate of 1.0 percent, which was up slightly from 0.8 percent for same period last year.

~~Nine months ended September 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:

~~In the~~ ~~nine months ended September 30, 2012, utility operations contributed net income of~~ ~~$28.3 million~~ or ~~$1.05~~ ~~per share, compared to $31.7 million or $1.19 per share in~~ ~~2011. The~~ decrease in net income ~~was~~were as follows:

a $5.9 million decrease in utility margin primarily due to:

◦

a $5.1 million decrease in margin related to the timing impacts of changes in fixed monthly charges and decoupling baselines in the 2012 rate case. As a result of changes to the decoupling baseline for average use per customer included in the 2012 Oregon general rate case, the decoupling mechanism's results this year will not be comparable to last year, although the overall impact on revenues will generally be the same on an annualized basis;


◦	a $0.7 million decrease in margin related to the general rate decrease primarily due to our lower authorized ROE of 9.5%;


◦	a $2.1 million decrease in gains from gas cost incentive sharing; and


◦	the effects of warmer weather, which decreased volumes and thus sales.


◦	Partially offsetting these decreases was approximately $2 million increase related to customer growth and the rate-base return on our gas reserve investments.

a $2.1 million decrease in income taxes due to ~~the one-time tax charge related to general rate case, higher operating expenses and the effects of warmer weather on~~lower pre-tax utility margin. These factors were partially offset by increases in utility margin. See "Application of Critical Accounting Policies and Estimates—Regulatory Cost Recovery" for additional information on the tax charge from the general rate case.

~~Gas Utility Volumes, Revenues and Utility Margin~~income.

Total utility volumes sold and delivered in the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013 decreased ~~decreased by~~ 2%2 ~~percent~~ over last year primarily due to 10 ~~percent~~the impact of warmer weather ~~while total utility margin increased by~~ ~~$6.7 million, or~~ 3 percent. The increase in utility margin was primarily attributed to a one-time, pre-tax charge of $7.4 million in the first nine months of 2011 related to the repeal of utility tax legislation in Oregon, and a ~~$3.6 million~~ ~~gain, or a~~ ~~$2.2 million~~ ~~increase over last year, from higher gas cost incentive sharing resulting from lower gas commodity prices. In addition, the increase was also due to a~~ 1 percent increase in customers over last year. These increases to margin were partially offset by declines in customer volumes and the timing of colder weather in May 2011 compared to 2012 as the weather normalization mechanism for customer usage ends on ~~May 15th while the decoupling mechanism assumes weather adjusted volumes for the entire month.~~

~~During the~~ ~~nine months ended September 30, 2012, our weather normalization mechanism adjusted~~ residential and commercial ~~margins down by~~ ~~$3.8 million~~ ~~based on temperatures that were~~ 2 ~~percent colder than average, compared to a margin decrease of~~ ~~$10.6 million~~ ~~last year when temperatures were~~ 12 ~~percent colder than average. Our decoupling mechanism adjusted residential and commercial margins up by~~ ~~$6.8 million~~ ~~for the~~ ~~nine months ended September 30, 2012~~ ~~and~~ ~~$10.8 million~~ ~~for the~~ ~~nine months endedSeptember 30, 2011, to largely offset the impact of lower average use per customer on a weather normalized basis.~~use.

2829

Table of Contents

UTILITY MARGIN TABLE. The following ~~tables summarize~~table summarizes the composition of utility gas ~~utility~~ volumes and revenues and ~~margin.~~costs of sales for the three months ended March 31, 2013 and 2012. Certain prior year amounts in ~~prior year balances under~~ the ~~utility margin section of the tables~~following table have been reclassified to conform with the current year’s presentation. These reclassifications reflect amounts ~~moved from other utility margin adjustments into~~included in residential, commercial, and industrial categories where such amounts were ~~assignable~~specifically attributable to ~~a specific~~that customer category. Utility volumes and margin in total ~~was~~were not affected by these reclassifications.

Three Months Ended Three Months Ended Favorable/
Three Months Ended September 30, (Unfavorable)
Thousands, except degree day and customer data 2012 2011 2012 vs. 2011
Utility volumes - therms:
Residential sales 28,369
28,809
(440 )
Commercial sales 25,117
25,001
116
Industrial - firm sales 7,506
7,843
(337 )
Industrial - firm transportation 26,952
28,570
(1,618 )
Industrial - interruptible sales 12,081
11,815
266
Industrial - interruptible transportation 58,339
55,828
2,511
Total utility volumes sold and delivered 158,364
157,866
498
Utility operating revenues - dollars:
Residential sales $ 38,937
$ 41,233
$ (2,296 )
Commercial sales 25,183
26,454
(1,271 )
Industrial - firm sales 5,930
6,539
(609 )
Industrial - firm transportation 1,724
1,527
197
Industrial - interruptible sales 6,258
7,019
(761 )
Industrial - interruptible transportation 2,076
2,368
(292 )
Regulatory adjustment for income taxes paid⁽¹⁾
—
3
(3 )
Other revenues 2,048
1,405
643
Total utility operating revenues 82,156
86,548
(4,392 )
Cost of gas sold 37,570
43,117
(5,547 )
Revenue taxes 2,255
2,397
(142 )
Utility margin $ 42,331
$ 41,034
$ 1,297
Utility margin:⁽²⁾

Residential sales $ 22,681
$ 22,836
$ (155 )
Commercial sales 10,165
10,136
29
Industrial - sales and transportation 6,727
6,623
104
Miscellaneous revenues 668
867
(199 )
Gain from gas cost incentive sharing 467
186
281
Other margin adjustments 1,315
487
828
Margin before regulatory adjustments 42,023
41,135
888
Weather normalization adjustment —
—
—
Decoupling adjustment 308
(104 ) 412
Regulatory adjustment for income taxes paid⁽¹⁾
—
3
(3 )
Utility margin $ 42,331
$ 41,034
$ 1,297
Customers - end of period:
Residential customers 615,642
609,159
6,483
Commercial customers 62,648
62,204
444
Industrial customers 919
915
4
Total number of customers - end of period 679,209
672,278
6,931
Actual degree days 58
50

Percent colder (warmer) than average weather⁽³⁾
43 % (51 )%

~~Table of Contents~~



	Three Months Ended Three Months Ended						Favorable/
	Three Months Ended March 31,						(Unfavorable)
In thousands, except degree day and customer data	2013			2012			2013 vs. 2012

Utility volumes - therms:
Residential and commercial sales	268,664			276,159			(7,495		)
Industrial sales and transportation	131,526			132,000			(474		)
Total utility volumes sold and delivered	400,190			408,159			(7,969		)
Utility operating revenues:
Residential and commercial sales	$	256,366		$	287,014		$	(30,648	)
Industrial sales and transportation	19,025			22,311			(3,286		)
Other revenues	1,529			1,435			94
Less: Revenue taxes	7,261			7,855			(594		)
Total utility operating revenues	269,659			302,905			(33,246		)
Less: Cost of gas	142,359			169,755			(27,396		)
Utility margin	$	127,300		$	133,150		$	(5,850	)
Utility margin:⁽¹⁾
Residential and commercial sales	$	117,363		$	121,415		$	(4,052	)
Industrial sales and transportation	7,718			7,636			82
Miscellaneous revenues	1,529			1,595			(66		)
Gain from gas cost incentive sharing	542			2,637			(2,095		)
Other margin adjustments	148			(133		)	281
Utility margin	$	127,300		$	133,150		$	(5,850	)
Customers - end of period:
Residential customers	623,609			617,665			5,944
Commercial customers	64,649			63,210			1,439
Industrial customers	941			919			22
Total number of customers - end of period	689,199			681,794			7,405
Actual degree days	1,904			1,954
Percent colder (warmer) than average weather⁽²⁾	3		%	4		%

Nine Months Ended Favorable/
September 30, (Unfavorable)
Thousands, except degree day and customer data 2012 2011 2012 vs. 2011
Utility volumes - therms:
Residential sales 268,503
281,862
(13,359 )
Commercial sales 168,913
175,410
(6,497 )
Industrial - firm sales 25,718
27,183
(1,465 )
Industrial - firm transportation 95,539
97,585
(2,046 )
Industrial - interruptible sales 44,001
43,347
654
Industrial - interruptible transportation 182,866
176,645
6,221
Total utility volumes sold and delivered 785,540
802,032
(16,492 )
Utility operating revenues - dollars:
Residential sales $ 288,714
$ 331,835
$ (43,121 )
Commercial sales 146,126
169,566
(23,440 )
Industrial - firm sales 18,716
22,264
(3,548 )
Industrial - firm transportation 5,411
4,901
510
Industrial - interruptible sales 21,261
25,753
(4,492 )
Industrial - interruptible transportation 6,143
6,968
(825 )
Regulatory adjustment for income taxes paid⁽¹⁾
—
(7,162 ) 7,162
Other revenues 5,061
4,095
966
Total utility operating revenues 491,432
558,220
(66,788 )
Cost of gas sold 241,823
313,781
(71,958 )
Revenue taxes 12,688
14,195
(1,507 )
Utility margin $ 236,921
$ 230,244
$ 6,677
Utility margin:⁽²⁾

Residential sales $ 145,923
$ 150,855
$ (4,932 )
Commercial sales 58,444
59,923
(1,479 )
Industrial - sales and transportation 21,114
21,073
41
Miscellaneous revenues 3,634
3,977
(343 )
Gain from gas cost incentive sharing 3,556
1,308
2,248
Other margin adjustments 1,333
92
1,241
Margin before regulatory adjustments 234,004
237,228
(3,224 )
Weather normalization adjustment (3,834 ) (10,612 ) 6,778
Decoupling adjustment 6,751
10,790
(4,039 )
Regulatory adjustment for income taxes paid⁽¹⁾
—
(7,162 ) 7,162
Utility margin $ 236,921
$ 230,244
$ 6,677
Actual degree days 2,717
2,968

Percent colder than average weather⁽³⁾
2 % 12 %


⁽¹⁾	~~Regulatory adjustment for income taxes paid is described below.~~


~~(2)~~	Amounts reported as margin for each category of customers are operating revenues, which are net of revenue taxes, less cost of ~~gas sold and revenue taxes.~~gas.


~~(3)~~ ⁽²⁾	Average weather represents the 25-year average degree days, as determined in our Oregon general rate case. For the three months ended March 31, 2013 and 2012, average weather represents degree days based on the 25-year average that was set in our 2012 and 2003 Oregon general rate ~~case.~~cases, respectively.

Table of Contents

Residential and Commercial Sales

Residential and commercial sales highlights include:

~~Three months ended September 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:



	Three Months Ended March 31,
In thousands	2013			2012			Change
Volumes - therms:
Residential sales	169,950			176,037			(6,087		)
Commercial sales	98,714			100,122			(1,408		)
Total volumes	268,664			276,159			(7,495		)
Operating revenues:
Residential sales	$	172,168		$	194,839		$	(22,671	)
Commercial sales	84,198			92,175			(7,977		)
Total operating revenues	$	256,366		$	287,014		$	(30,648	)
Utility margin:
Residential:
Sales	$	84,601		$	85,608		$	(1,007	)
Weather normalization adjustments	(3,660		)	(2,812		)	(848		)
Decoupling adjustments	2,817			6,201			(3,384		)
Total residential utility margin	83,758			88,997			(5,239		)
Commercial:
Sales	33,647			32,965			682
Weather normalization adjustments	(1,638		)	(1,003		)	(635		)
Decoupling adjustments	1,596			456			1,140
Total commercial utility margin	33,605			32,418			1,187
Total utility margin	$	117,363		$	121,415		$	(4,052	)

2013 COMPARED TO 2012. The primary factors contributing to changes in residential and commercial ~~markets in the~~ ~~third quarter~~ ~~of this year~~margin were as ~~compared to the same period last year were:~~follows:

sales volumes ~~remained relatively flat compared to the prior year;~~decreased 3%, primarily reflecting 3% warmer weather;

~~utility~~ operating revenues decreased ~~$3.6 million~~11% or 5 ~~percent, primarily~~, due to ~~$1.9~~a 3% decrease in sales volumes, a 14% decrease in average gas prices, which flowed through the Company's PGA rates; and

utility margin decreased 3%, primarily reflecting:


◦	a $5.1 million decrease due to timing differences of $2.8 million from the new fixed monthly charges and $2.4 million from the reset of decoupling baseline for average gas used by utility customers in Oregon; and


◦	a $0.7 million decrease due to the overall revenue requirement decrease from the 2012 Oregon rate case, which included a decrease in our authorized ROE;


◦	In addition, margin declined due to the effects of warmer weather.


◦	Partially offsetting these decreases were increases of approximately $2.0 million from customer growth and the rate-base return on our gas reserve investments.

As a result of ~~credits to customers' bills in July related~~changes to the ~~refund~~decoupling baseline for average use per customer included in the 2012 Oregon general rate case, the decoupling mechanism's results this year will not be comparable to last year, although the overall impact on revenues will generally be the same on an annualized basis.

Table of ~~gas cost savings~~Contents

Industrial Sales and ~~lower billing rates to customers from a PGA rate decrease effective November 1, 2011;~~Transportation

Industrial sales and transportation highlights include:

~~utility margin remained relatively flat compared to the prior year.~~



	Three Months Ended March 31,
In thousands	2013		2012		Change
Volumes - therms:
Industrial - firm sales	9,480		10,619		(1,139		)
Industrial - firm transportation	39,753		38,851		902
Industrial - interruptible sales	17,069		17,730		(661		)
Industrial - interruptible transportation	65,224		64,800		424
Total volumes	131,526		132,000		(474		)
Utility margin:
Industrial - firm and interruptible sales	$	3,684	$	3,730	$	(46	)
Industrial - firm and interruptible transportation	4,034		3,905		129
Total utility margin	$	7,718	$	7,635	$	83

~~Nine months ended September 30, 2012~~2013 COMPARED TO 2012. ~~compared to~~ ~~September 30, 2011~~:

The primary factors contributing to changes in ~~residential~~industrial sales and ~~commercial markets for the~~ ~~nine months ended September 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~transportation margin were as follows:

~~utility sales~~total volumes ~~were~~ 4 ~~percent lower, primarily reflecting~~ 10 ~~percent warmer weather;~~

~~utility operating revenues~~ decreased ~~$66.6 million~~ or 13 ~~percent primarily~~by less than 1% due to ~~$36.2 million of credits to customers’ bills primarily in June related to the refund of gas cost savings, as well as the effects of warmer weather and~~ lower ~~billing rates to~~usage from a few large customers; and

utility margin ~~decreased~~ ~~$3.7 million~~ or 2 percent, including weather normalization, which stabilizes margins when weather is warmer or colder than normal, and decoupling, which stabilizes margins when average use per customer in Oregon increases or decreases. The decrease in margin reflects the warmer weather compared to last year's very cold weather, and the timing of the colder weather in the prior year when the full impact of the weather normalization mechanisms was in effect.

~~Industrial Sales and Transportation~~

~~Three months ended September 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:

~~The primary factors that impacted third quarter results from industrial sales and transportation markets were as follows:~~

~~volumes delivered to industrial customers remained relatively flat with an increase of only~~ ~~0.8 million~~ ~~therms, or less than~~ 1 ~~percent; and~~

~~margin from industrial customers contributed a slight increase of $0.1 million, or~~ 2 ~~percent, to operating income.~~

~~Nine months ended September 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:

~~The primary factors that impacted year-to-date results from industrial sales and transportation markets were as follows:~~

~~volumes delivered to industrial customers~~ increased ~~3.4 million~~1% ~~therms, or~~ 1 ~~percent, primarily reflecting the impact of customers switching to natural gas~~ due to customer growth of 2.4%, partially offset by decreased margins from the ~~lower prices of natural gas compared to oil; and~~few large customers mentioned above.

~~utility margin from industrial customers remained flat.~~

~~Regulatory Adjustment for Income Taxes Paid~~

In prior years, Oregon law required the company to annually review the amount of income taxes collected in rates from utility operations and compare it to the amount of taxes the utility paid. This law was repealed in 2011. As a result, we did not recognize any income or expense related to this regulatory adjustment for the ~~three and nine months ended September 30, 2012~~, while in the second quarter of 2011, we recorded a one-time, pre-tax charge of $7.4 million, including accrued interest. For more information on regulatory income taxes paid, see Results of Operations – Business Segments – Utility Operations – Regulatory Adjustment for Income Taxes Paid in our ~~2011~~ ~~Form 10-K.~~

~~Table of Contents~~

~~Other Revenues~~

~~Other revenues include miscellaneous fee income and other regulatory adjustments. Other revenues were $2.0 million~~ ~~in the~~ ~~third quarter~~ of ~~2012, an increase of $0.6 million~~ ~~over the~~ ~~third quarter~~ of ~~2011. Other revenues were $5.1 million~~ ~~in the~~ ~~nine months ended September 30, 2012, an increase of $1.0 million~~ ~~over the same period of~~ ~~2011~~.

Cost of Gas ~~Sold~~

Cost of gas ~~sold~~ as reported by the utility includes gas purchases, gas drawn from storage inventory, gains and losses from commodity hedges, pipeline demand costs, seasonal demand cost balancing adjustments, regulatory gas cost deferrals, production from gas reserves, and company gas use. The OPUC and WUTC generally require natural gas commodity costs to be billed to customers at the actual cost incurred, or expected to be incurred, by the utility. Customer rates are set each year so that if cost estimates were met we would not earn a profit or incur a loss on gas commodity purchases; however, in Oregon we have an incentive sharing mechanism whereby we either increase or decrease margin results based on a percentage of actual gas costs as compared to embedded gas costs in the PGA. Under this provision, our net income can be affected by differences between actual and expected gas costs, which occur primarily because of market fluctuations and volatility affecting unhedged gas purchases in the ~~PGA (see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above).~~PGA. In addition, we ~~recently entered into~~have a regulatory agreement where we ~~receive~~earn a rate base return on our investment in gas reserves, which is reflected in utility ~~margin (see Part II, Item 7.,~~margin. See “Regulatory ~~Matters-Rate Mechanisms-Purchased~~Matters—Rate Mechanisms—Purchased Gas Adjustment ~~and Regulatory Matters-Rate Mechanisms-Gas Reserves in the~~ ~~2011~~ ~~Form 10-K).~~” above.

We use natural gas ~~commodity-based~~commodity hedge contracts (derivative instruments), primarily fixed-price commodity swaps, consistent with our financial derivatives policies to help manage our exposure to rising gas prices. Gains and losses from these financial hedge contracts are generally included in our PGA ~~prices~~ and normally do not impact net income because the hedged prices are reflected in our annual ~~rate changes,~~PGA rates, subject to a regulatory ~~prudency~~prudence review. However, hedge contracts entered into after the annual PGA rates are set infor Oregon customers can impact net income because we would be required to share in any gains or losses as compared to the corresponding commodity prices built into rates in the PGA. In Washington, ~~100 percent~~100% of the actual gas costs, including hedge gains and losses allocated to Washington gas sales, are passed through in customer ~~rates (see~~rates. See Part II, Item ~~7.,~~7, “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities” and ~~“Results of Operations—Regulatory~~“Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment” in ~~the~~ ~~2011~~our 2012 Form 10-K, and Note 12 in this ~~report).~~report.

Table of Contents

Cost of gas highlights include:



	Three Months Ended March 31,
In thousands, except as noted	2013		2012		Change
Total volumes sold and delivered (therms)	400,190		408,159		(7,969		)
Cost of gas	$	142,359	$	169,755	$	(27,396	)
Average cost of gas (cents per therm)	0.48		0.56		(0.08		)
Total realized financial hedge losses on financial swaps	5,400		29,400		(24,000		)
Utility margin gain from gas cost incentive sharing	542		2,637		(2,095		)

~~Three months ended September 30, 2012~~2013 COMPARED TO 2012. The primary factors contributing to the 16% ~~compared to~~ ~~September 30, 2011~~:

~~The following summarizes the major factors that contributed to changes~~decrease in cost of gas ~~sold for the~~ were as follows:~~three months ended September 30, 2012~~:

a 2% decrease in total sales volumes;

average cost of gas ~~sold~~collected through rates decreased $~~5.5 million~~14%, or 13 percent, including the $1.9 million of credits applied to customer billings in July 2012 related to the refund of gas cost savings. Excluding the customer credits, total cost of gas decreased $3.6 million or 8 percent, primarily reflecting lower market prices for natural gas, ~~prices;~~

~~average gas cost collected through rates, excluding customer refunds for gas cost savings, decreased from 61 cents per therm in~~ ~~2011~~ ~~to 54 cents per therm in~~ ~~2012, primarily reflecting the lower prices that were~~which are passed on tocustomers through ~~the~~ PGA ~~effective~~rate changes on November 1 ~~2011;~~each year; and

hedge losses ~~totaling $12.7 million were~~ realized and included in cost of gas ~~sold this quarter, compared to $6.6~~decreased $24.0 million ~~of hedge losses in the same period of~~ ~~2011~~. Since ~~the~~ underlying hedge prices ~~were~~are generally included in our PGA billing rates, ~~these~~hedge losses ~~did~~do not impact ~~the company’s~~ margin or net income.

The effect on ~~operating results~~shareholders from our gas cost incentive sharing mechanism was a contribution to margin ~~gain~~ of $0.5 million infor the ~~third quarter~~ of ~~2012~~,three months ended March 31, 2013, compared to ~~a margin gain of~~ $~~0.2~~2.6 million for the ~~third quarter~~ of ~~2011~~.

~~Nine months ended September 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:

~~total cost of gas sold decreased $72.0 million, or~~ 23 percent, including the $37.7 million of credits applied to customer billings primarily in June 2012 related to the refund of gas cost savings. Excluding the customer credits, total cost of gas decreased $34.3 million or 11 percent, primarily reflecting lower usage due to weather that was 10 ~~percent warmer than the~~ same period in ~~2011~~;

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~~average gas cost collected through rates, excluding customer refunds for gas cost savings, decreased from 60 cents per therm in~~ ~~2011~~ ~~to 55 cents per therm in~~ ~~2012, primarily reflecting lower gas prices that were passed on through PGA rate decreases effective November 1, 2011; and~~

~~hedge losses totaling $63.3 million were realized and included in cost of gas sold for the~~ ~~nine months ended September 30, 2012, compared to $36.2 million of hedge losses in the same period of~~ ~~2011. Since the underlying hedge prices were included in our PGA billing rates, these losses did not impact margin or net income.~~

~~The amount recorded to pre-tax income from the shareholders’ portion of our gas cost incentive sharing mechanism was a margin contribution of $3.6 million~~ ~~in the first nine months of~~ ~~2012~~ ~~compared to $1.3 million~~ in ~~2011~~.2012. 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 percent~~75% ownership interest in the Gill Ranch underground storage facility in California. We also contract with an independent energy marketing company to provide asset management services using our utility and non-utility storage and transportation capacity.

~~Three months ended September 30, 2012~~Gas storage segment highlights include: ~~compared to~~ ~~September 30, 2011~~:



	Three Months Ended March 31,
In thousands, except per share data and as otherwise noted	2013		2012		Change
Gas storage net income	$	1,636	$	806	$	830
EPS - gas storage segment	0.06		0.03		0.03
Gas storage contracted capacity (Bcf)	21		19		2

~~For~~2013 COMPARED TO 2012. The primary factor contributing to the~~three months ended September 30, 2012, we earned $1.3 million, or~~ ~~5 cents per share, compared to~~ ~~$1.2 million, or 4 cents per share, for the same period in~~ ~~2011. Gas storage operating income increased~~ ~~$1.2 million~~ to ~~$3.6 million~~ ~~for the~~ ~~three months ended September 30, 2012. The~~ increase in ~~net income over~~ ~~2011~~ primarily reflects higher revenues from an increase in contracted capacity and lower than expected operating costs, partially offset by higher interest expense from Gill Ranch’s $40 million senior secured debt, which was issued in the fourth quarter of 2011, and lower market prices for storage.

~~Nine months ended September 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:

~~Our~~our gas storage segment ~~earnings remained flat with $3.2 million~~ ~~of net income, or~~ ~~12 cents per share for both the~~ ~~nine months ended September 30, 2012~~ ~~and~~ ~~2011. Gas storage operating income increased~~ ~~$2.4 million~~ to ~~$9.6 million~~ ~~for the~~ ~~nine months ended September 30, 2012. This increase in operating income~~ was ~~primarily due to~~ increased revenues ~~from~~at Gill Ranch from additional contracted storage capacity for the 2012-2013 gas storage year and higher third party asset management revenues. For the 2013-2014 gas storage year, we are fully contracted ~~capacity.~~at Gill Ranch and at Mist, but market pricing for storage, particularly in California, has been negatively affected by the abundant supply of natural gas and low volatility of natural gas prices.

Business Segments - Other

Our other business segment primarily consists ~~primarily~~ of ~~NNG Financial's~~an equity investment in KB Pipeline, an equity investment in PGH, which in turn has invested in ~~the Palomar~~a cross-Cascade pipeline project, and other miscellaneous non-utility investments and business activities. ~~NNG Financial had total assets~~

Other business highlights include:



	Three Months Ended March 31,
In thousands	2013		2012		Change
Investment in:
NNG Financial	$	1,150	$	1,054	$	96
PGH Investment	13,430		13,455		(25		)

Table of ~~$1.0 million and $0.9 million as of~~Contents

2013 COMPARED TO 2012. ~~September 30, 2012~~ ~~and~~ ~~2011, respectively, primarily reflecting a non-controlling interest in~~Our other businesses remained relatively flat over the ~~KB Pipeline, which is contracted to serve our utility. Our net equity investment in PGH as of~~ ~~September 30, 2012~~ ~~and~~ ~~2011~~ was $13.4 million and $14.4 million, respectively, with the year-over-year decrease reflecting a $1.0 million write-down taken in the fourth quarter of 2011. In aggregate, earnings from our other business segment for the ~~nine~~three months ended ~~September 30,~~March 31, 2013 compared to the same period in 2012 ~~and~~ ~~2011~~ ~~were a slight gain and~~ with a net loss of $less than $0.1 million in 2013 and net income of less than $0.1 million in 2012. ~~0.2 million, respectively.~~ See~~Note 4~~ ~~in the~~ ~~2011~~ ~~Form 10-K, and~~ Note 4 and Note 11 ~~in this report,~~ for further details on our other business segment and our investment in PGH.

Consolidated Operations

Operations and Maintenance

Operations and maintenance highlights include:

~~Three months endedSeptember 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:



	Three Months Ended March 31,
In thousands	2013		2012		Change
Operations and maintenance	$	33,757	$	34,432	$	(675	)

~~Operations~~2013 COMPARED TO 2012. The decrease in operations and maintenance expense was ~~$29.0~~primarily due to a $1.3 million in ~~2012~~ ~~compared to~~ ~~$28.4 million~~ in ~~2011, for an increase of~~ ~~$0.6 million~~ or ~~2 percent. The primary factors contributing to the increase were:~~

~~a $0.8 million increase~~ decrease in utility ~~non-payroll expense including higher costs for safety enhancements, business development, information technology system maintenance and other customer service cost increases;~~

bad debt expense. Partially offsetting this decrease was a ~~$0.2 million increase in utility payroll expense primarily related to an increase in field service employees; and~~

~~a $0.2~~$0.5 million increase in utility employee ~~benefit expense, primarily~~ related ~~to health care and pension costs. See below for additional discussion on pension costs.~~

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~~Partially offsetting the above factors was:~~

~~a $1.0 million decrease in utility performance awards; and~~

~~a $0.2 million reduction in gas storage general and administrative expense reflecting lower costs as compared to start-up costs incurred at Gill Ranch in 2011.~~

~~Nine months endedSeptember 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:

~~Operations and maintenance expense was~~ ~~$95.5 million~~ in ~~2012~~ ~~compared to~~ ~~$89.9 million~~ in ~~2011, for an increase of~~ ~~$5.6 million~~ or ~~6 percent. The following summarizes the major factors that contributed to changes in operations and maintenance expense for the~~ ~~nine months ended September 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:

~~a $2.7 million increase in utility payroll expense primarily related to an increase in field service employees;~~

a $2.6 million increase in utility non-payroll expense including higher costs for new employee training, expenses related to the Oregon general rate case, higher costs for information technology system maintenance and other customer service cost increases; and

~~a $1.1 million increase in utility employee benefit~~ expense, principally related to health care and pension ~~costs.~~costs, which were driven by an increase in employee count. See below for ~~additional~~further discussion on ~~pension costs.~~

~~Partially offsetting the above factors were:~~

~~a $0.6 million reduction in gas storage general and administrative expense primarily reflecting lower costs as compared to start-up costs incurred at Gill Ranch in the first nine months of 2011; and~~

~~a $0.1 million decrease in utility bad debt expense.~~

~~Our~~ bad debt expense and pension costs below.

The utility's bad debt expense remains well below 0.5% of operating revenues and has decreased ~~in the~~ ~~third quarter~~ of ~~2012~~ ~~partially~~compared to 2012. This decrease is primarily due to ~~the positive impact~~lower levels of ~~customer refunds on~~ delinquent account balances during the ~~period. Our bad debt expense as~~period and a ~~percent~~continuation of ~~revenues was 0.23 percent~~lower delinquency rates resulting in an overall decrease to our allowance for ~~the twelve months ended~~ ~~September 30, 2012~~, compared to 0.24 percent for the same period last year. This year's increase in bad debt as a percent of revenues is largely due to the revenue decrease of approximately $39 million representing the refund of accumulated gas cost savings for customers.uncollectible accounts. Our bad debt expense results ~~continue~~are at historically low levels for the Company despite challenging economic conditions in recent years. We believe credit risks are still somewhat elevated due to the continuing weak economy and high unemployment rates, but we expect our bad debt expense ratio over the long term to remain below 0.5 percent of revenues.

Our accounting expense for pension costs increased in ~~2012~~2013 largely due to lower interest rates; however, ~~the~~we have OPUC ~~approved a deferral of our~~approval to defer certain utility pension costs ~~for amounts~~ in excess of what is currently recovered in customer rates. The pension cost deferral is recorded to a regulatory balancing account, which ~~reduces~~stabilizes the recognized amount of operations and maintenance expense. For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2013 and 2012,, we deferred pension expenses totaling $2.3 million and $2.1 million, ~~and $6.3 million, respectively, and $1.3 million and $4.0 million for the same periods last year (see~~respectively. See Note 87). As a result, increased pension costs had a minimal effect on operations and maintenance expense in the current periods, with the increase principally related to the cost allocation to our Washington operations, and increases in our non-qualified and other postretirement benefit expenses, which are not covered by the pension balancing account. For further explanation of the pension balancing account, see “Regulatory Matters—Rate Mechanisms—Pension Deferral,” above.

~~General Taxes~~Income Tax Expense

Income tax expense highlights include:



	Three Months Ended March 31,
Dollars in thousands	2013			2012			Change
Income tax expense	$	25,960		$	27,663		$	(1,703	)
Effective tax rate	40.8		%	40.7		%	0.1		%

~~General taxes remained flat at~~2013 COMPARED TO 2012. ~~$7.5 million~~ ~~for both the~~ ~~three months ended September 30, 2012~~ ~~and~~ ~~September 30, 2011. However, general taxes increased~~ ~~$1.4 million~~Income tax expense decreased in the first ~~nine months~~quarter of ~~2012~~ ~~compared to~~ ~~2011, primarily~~2013 due to a ~~$0.8 million increase in property taxes at Gill Ranch to reflect increased capital investments added to our assessed tax base for 2012.~~

~~Depreciation and Amortization~~

~~Depreciation and amortization expense increased by~~ $~~0.8~~4.3 million~~, or~~ ~~5 percent~~ ~~for the~~ ~~three months ended September 30, 2012~~, decrease in income before income taxes compared to the same period in ~~2011~~2012. ~~For~~See Note 8 for more information on income taxes, including a reconciliation between the statutory federal and state income tax rates and our effective rates.~~nine months endedSeptember 30, 2012~~,

Other Consolidated Expenses

General taxes, depreciation and amortization, other income and expense, ~~increased by~~ ~~$2.0 million, or~~ ~~4 percent, as~~and interest expense were all relatively unchanged for the three months ended March 31, 2013 compared to the same period in ~~2011. The increased expense in~~ ~~2012~~ ~~was primarily related to higher depreciation at the utility and Gill Ranch because of plant asset additions.~~2012.

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~~Other Income and Expense – Net~~

~~The following table provides details on other income and expense – net by primary components:~~

Three Months Ended Nine Months Ended
September 30, September 30,
Thousands 2012 2011 2012 2011
Gains from company-owned life insurance $ 510
$ 286
$ 1,902
$ 1,485
Interest income 9
6
114
36
Income from equity investments 21
(1 ) 22
(354 )
Net interest on deferred regulatory accounts 1,499
1,548
3,339
4,563
Gain (loss) on sale of investments —
—
—
(96 )
Other non-operating (329 ) (58 ) (1,741 ) (1,517 )
Total other income and expense - net $ 1,710
$ 1,781
$ 3,636
$ 4,117

~~Other income and expense – net for the~~ ~~nine months ended September 30, 2012~~ ~~decreased~~ ~~$0.5 million~~ primarily due to $1.2 million of lower interest from net regulatory account balances. Net regulatory account balances in the first half of 2012 were lower due to environmental insurance recoveries received at the end of 2011 as well as accumulated gas cost savings from November 2011 through June 2012. The company’s refund of gas cost savings has increased the regulatory account balances which has resulted in higher interest in the third quarter of 2012. This decrease in other income and expense is partially offset by increases of $0.4 million and $0.4 million in income from equity investments and gains from life insurance policy proceeds, respectively.

~~Interest Expense – Net~~

~~Interest expense – net increased~~ ~~$0.3 million~~ ~~and~~ ~~$1.2 million~~ ~~for the~~ ~~three and nine months ended September 30, 2012, respectively, compared to the same periods in~~ ~~2011~~. The increase was primarily due to interest on our new $40 million senior secured debt at Gill Ranch, which was issued in the fourth quarter of 2011, partially offset by a redemption earlier this year of a $40 million utility long-term debt issue with a coupon rate of 7.13 percent.

~~Income Tax Benefit/Expense~~

~~Income tax benefit decreased~~ ~~$2.7 million~~ ~~for the~~ ~~three months ended September 30, 2012~~ ~~while income tax expense increased~~ ~~$2.3 million~~ ~~for the~~ ~~nine months ended September 30, 2012, compared to the same periods in~~ ~~2011. This was primarily due to a $2.7 million one-time, after-tax charge related to the Oregon general rate case. See~~ ~~Note 9~~, Application of Critical Accounting Policies and Estimates—Regulatory Cost Recovery, and Results of Operations—Regulatory Matters—Oregon General Rate Case for additional information on the tax charge from the general rate case.

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~~Financial Condition~~FINANCIAL CONDITION

Capital Structure

One of our long-term goals is to maintain a strong consolidated capital structure, generally consisting of 4545% to ~~50 percent~~50% common stock equity and 5050% to ~~55 percent~~55% long-term and short-term debt. When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources of capital are also used to fund long-term debt ~~redemptions~~retirements and short-term commercial paper ~~maturities (see “Liquidity~~maturities. See “Liquidity and Capital Resources” below and Note 76).

Achieving the target capital structure and maintaining sufficient liquidity to meet operating requirements are necessary to maintain attractive credit ratings and have access to capital markets at reasonable costs. Our consolidated capital structure at ~~September 30, 2012~~ ~~and~~ ~~2011~~ ~~and at~~ ~~December 31, 2011~~was as follows:


	September 30,				December 31,		March 31,				December 31,
	2012		2011		2011		2013		2012		2012
Common stock equity	46.7	%	45.8	%	46.5	%	47.9	%	49.6	%	45.3	%
Long-term debt	41.8	%	39.6	%	41.7	%	43.8		42.8		42.9
Short-term debt, including current maturities of long-term debt	11.5	%	14.6	%	11.8	%
Short-term debt, including any current maturities of long-term debt							8.3		7.6		11.8
Total	100	%	100	%	100	%	100	%	100	%	100	%

Liquidity and Capital Resources

At ~~September 30, 2012~~March 31, 2013, we had $~~5.7~~8.3 million of cash and cash equivalents compared to $~~25.9~~4.0 million at ~~September 30, 2011~~March 31, 2012. We also had $4.0 million in restricted cash at Gill Ranch ~~as of~~at both ~~September 30,~~ March 31, 2013 and 2012, which is being held as collateral for ~~the~~its long-term debt outstanding. 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, or~~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, and our use of proceeds from utility specific issuances are restricted to certain utility purposes. Our use of retained earnings is not subject to those same restrictions.

For the utility segment, our short-term liquidity is supported by cash balances, internal cash flow from operations, proceeds from the sale of commercial paper notes, borrowings from multi-year credit facilities, cash available from surrender value in company-owned life insurance policies, and proceeds from the sale of long-term debt. We use utility long-term debt proceeds to finance utility capital expenditures, refinance maturing debt of the utility and provide for general corporate purposes of the utility.

~~Capital markets over~~Current market conditions are better than the past few years ~~including the commercial paper market, experienced significant volatility and tight credit conditions, but current market conditions are significantly better~~ as reflected by tighter credit spreads and increased access to financing for investment grade issuers. Based on our current debt ratings (see ~~“Credit~~“Credit Ratings” below), we have been able to issue commercial paper and ~~first mortgage bonds~~long-term debt at attractive rates and have not needed to borrow from our back-up credit ~~facilities.~~facility. In the event that we are not able to issue new debt due to market conditions, we expect that our near term liquidity needs can be met by using cash balances or, for the utility segment, drawing upon our committed credit ~~facilities.~~facility. We also have a universal shelf registration filed with the SEC for the issuance of secured and unsecured debt or equity securities, subject to market conditions and certain regulatory approvals. As of ~~September 30, 2012~~March 31, 2013, we had OPUC approval to issue up to ~~$125~~$75 million of additional long-term debt under the existing shelf registration for approved ~~purposes, of which $75 million was remaining for issuance after NW Natural issued $50 million of first mortgage bonds on October 30, 2012.~~purposes.

In the event that our senior unsecured long-term debt credit ratings are downgraded, or our outstanding derivative position exceeds a certain credit threshold, our counterparties under derivative contracts could require us to post cash, a letter of credit or other form of collateral, which could expose us to additional cash requirements and may trigger ~~significant~~ increases in short-term borrowings. If the credit risk-related contingent features underlying these contracts were triggered on ~~September 30, 2012~~March 31, 2013, we could have been required to post $18.3 million of collateral to our counterparties, ifassuming our long-term debt ratings were at non-investment grade levels, which would be a very significant change from current rating levels for NW ~~Natural (see~~Natural. See Note 12 and ~~“Credit~~“Credit Ratings” ~~below).~~below.

In July 2010, the U.S. Congress passed and President Obama signed into law the “Dodd-Frank Wall Street Reform and Consumer Protection Act” (Dodd-Frank ~~Act)~~Act or DFA). The legislation established a new statutory framework for

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the comprehensive regulation of financial institutions that participate in the swaps market and, among other things, requires additional government

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regulation of derivative and over-the-counter transactions and expanded collateral requirements. In July 2012, pursuant to the Dodd-Frank Act, the Commodity Futures Trading Commission (CFTC) and SEC issued rules that further define the term “Swap,” and provide enhanced record keeping and reporting requirements. The CFTC rules regarding clearing swaps are not yet final. However, if clearing is required for qualifying end-users, such as NW Natural, the Company will be required to post collateral with a clearing firm. The minimum liquidity required, in the form of either posting cash or having an increased line of credit availability, will be, if required, higher than the Company's current collateral exposure levels. At this time, we do not expect the rules to have a material impact on our financial statements and disclosures. The Company is not currently ~~does not qualify~~subject to regulation as a ~~swap dealer~~Swap Dealer under the DFA nor ~~believe~~do we expect that it will be in the future based on current or ~~anticipated~~as yet unfinalized rules. Further, we believe we are eligible for and have taken appropriate steps to be exempt from certain reporting obligations under the DFA. We will continue to monitor interpretations and ~~CFTC~~Commodity Futures Trading Commission guidance to determine the impact, if any, on our hedging policies, procedures, results of operations, financial position and liquidity.

Other recent developments that may have a significant impact on our liquidity and capital resources include pension contribution requirements, current tax benefits from bonus depreciation and ~~liabilities,~~other tax advantaged investments, environmental expenditures and insurance recoveries, and customer refunds of gas cost savings.

With respect to ~~pension requirements,~~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 MAP-21 ~~Act (see~~Act. See Part II, Item 7, "Application of Critical Accounting ~~Policies - Pension Contributions,~~Policies—Accounting for Pensions and Postretirement Benefits" ~~above, and “Pension Cost and Funding Status of Qualified Retirement Plans,” below). With respect to~~in our 2012 Form 10-K.

Regarding federal income tax liabilities, ~~an extension was~~extensions have been granted ~~that allowed~~allowing us to take ~~100 percent bonus depreciation on qualified expenditures during 2011, and allows 50 percent~~50% bonus depreciation on a majority of our capital expenditures in 2012 and 2013 plus intangible drilling cost deductions from our gas reserves investment expected in 2011 - 2015, which significantly reduces our tax liability for those tax years and ~~provides~~is expected to provide cash flow benefits in ~~2012 and 2013. With respect to~~subsequent years.

Concerning environmental ~~liabilities,~~expenditures, we expect to continue using cash resources to fund our environmental liabilities, but we also anticipate recovering amounts through insurance and utility rates over the next several years, ~~even though~~although the amount and timing of these expenditures and recoveries is ~~uncertain (see~~ uncertain. See Note 13 and "Results of Operations—Regulatory Matters—~~Oregon General Rate Case" above and “Cash Flows—Operating Activities” below).~~Environmental Costs" above.

With respect to customer refunds or credits, ~~gas prices were significantly lower between November 1, 2011 and March 31, 2012 than~~in April 2013, the ~~gas prices embedded~~Company requested regulatory approval to provide its Oregon utility customers with an approximately $9 million interstate storage credit, in ~~customer rates. As a result,~~their June bills, from our ~~PGA~~regulatory incentive sharing mechanism ~~deferred 90 percent of these~~related to interstate gas ~~cost savings attributed to Oregon,~~storage and 100 percent of the savings attributed to Washington, into a regulatory account for refund back to customers (see “Purchased Gas Adjustment,” above). Ordinarily, these refunds would be credited to customer rates in the next year’s PGA filing, but in the second quarter ofasset management services. In 2012, the ~~company received regulatory approval to immediately credit $35 million to Oregon customers and $4 million to Washington customers through billing credits. In addition, the company also~~Company received approval to provide its Oregon utility customers with a $9 million interstate storage credit from ~~our regulatory~~the incentive sharing mechanism related to gas storage and asset management ~~services. These~~services, plus a $39 million refund to customers for gas cost savings. The 2012 credits were applied to customer bills in June and July of 2012.

Our gas storage segment’s short-term liquidity is supported by cash balances, internal cash flow from operations, external financing, and, to a certain extent, funding from its parent company. Gill Ranch has a limited operational history, having begun operations in October 2010. ~~Although we~~We anticipate operating cash flows to be sufficient for liquidity purposes, but the amount and timing of these cash flows from year to year are ~~uncertain.~~uncertain as the majority of Gill Ranch's storage contracts are short-term. In November 2011, Gill Ranch issued $40 million of senior secured ~~notes,~~debt, with a fixed interest rate on $20 million and a variable interest rate on the remaining $20 million. The average combined interest rate on the ~~notes~~debt was ~~7.38 percent~~7.38% per annum through ~~September 30, 2012~~March 31, 2013. ~~These notes are~~This debt is secured by all of the membership interests in Gill Ranch ~~Storage, LLC,~~ and ~~are~~is nonrecourse to NW Natural and other entities of the consolidated group. The maturity date of ~~these notes~~the debt is November 30, 2016.

Under the ~~note~~debt agreements, Gill Ranch is subject to certain covenants and restrictions, including but not limited to a financial covenant that requires Gill Ranch to maintain minimum adjusted ~~EBITDA~~earnings before interest, taxes, depreciation, and amortization (EBITDA) at various levels over the term of the ~~notes.~~debt. The minimum adjusted EBITDA increases incrementally over the first few years, reaching its highest level in the 12-month period beginning April 1, 2015. Under the agreements, Gill Ranch is also subject to a debt service reserve requirement of ~~10 percent~~10% of the outstanding principal amount, ~~initially~~currently $4 million, certain prepayment penalties, restrictions on dividends out of Gill Ranch unless certain earnings ratios are met, and restrictions on the incurrence of additional debt. At ~~September 30, 2012,~~March 31, 2013, we were in compliance with all covenants and restrictions ~~for~~under the ~~note~~debt agreements.

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 ~~under our universal shelf registration,~~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.

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Short-Term Debt

Our primary source of utility short-term liquidity is from internal cash flows and the sale of commercial paper. In addition to issuing commercial paper to meet working capital requirements, including seasonal requirements to finance gas ~~inventories~~purchases and accounts receivable, short-term debt may also be used to temporarily fund utility capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by one or more unsecured revolving credit ~~facilities (see “Credit~~facilities. See “Credit Agreements” below). Our commercial paper program did not experience any liquidity disruptions as a result of the credit problems that affected issuers of asset-backed commercial paper and certain other commercial paper programs over the last several years.below. At ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012, our utility had commercial paper outstanding of $~~175.8~~130.8 million and $~~181.2~~113.7 million, respectively. The effective interest rate on the utility’s commercial paper outstanding at ~~September 30, 2012~~March 31, 2013 and ~~2011~~2012 was ~~0.3 percent.~~0.3% and 0.2%, respectively.

Credit Agreements

~~We have~~In December 2012, we entered into a ~~syndicated~~new multi-year credit agreement for unsecured revolving loans totaling ~~$250 million. The original term~~$300 million with a maturity date of ~~this credit agreement was extended through May 31, 2013.~~December 20, 2017 and an available extension of commitments for two additional one-year periods, subject to lender approval. All lenders under ~~our syndicated~~the new agreement are major financial institutions with committed balances and investment grade credit ratings as of ~~September 30, 2012~~March 31, 2013 ~~(see table below).~~as follows:


	Loan Commitment Amounts in Thousands
In thousands
Lender rating, by category	Syndicated Facility		Loan Commitment
AA/Aa	$	165,000	$	123,000
A/A1	85,000		177,000
BBB/Baa	—		—
Total	$	250,000	$	300,000

Based on credit market conditions, it is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, including a review of capital ratios, credit default swap spreads, and credit ratings, we believe the risk of lender default is minimal.

~~As discussed above, we have commitments with all of our lenders under the $250 million syndicated agreement through May 31, 2013. This syndicated~~Our credit agreement allows us to request increases in the total commitment amount, ~~from time to time,~~ up to a maximum ~~amount~~ of ~~$400 million. This syndicated~~$450 million. The agreement also permits the issuance of letters of credit in an aggregate amount of up to ~~the applicable total borrowing commitment. This credit facility is scheduled to expire next year, but we intend to enter into a new agreement to replace the existing facility.~~

$200 million. Any principal and unpaid interest amounts owed on borrowings under the credit agreements ~~are~~is due and payable on or before the maturity date. There were no outstanding balances under ~~these~~this or our prior credit ~~agreements~~agreement at ~~September 30, 2012~~March 31, 2013 ~~and~~or ~~2011~~2012. ~~These agreements require~~Both the current and former credit agreement requires us to maintain a consolidated indebtedness to total capitalization ratio of ~~70 percent~~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, 2012~~March 31, 2013 and ~~2011~~2012, with consolidated indebtedness to total capitalization ratios of 5352.1 ~~percent~~% and 5450.4% ~~percent,~~, respectively.

The ~~syndicated~~ agreement also requires ~~that we~~us to maintain credit ratings with ~~S&P~~Standard & Poor's (S&P) and ~~Moody’s~~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 by 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. ~~However, a change in our debt rating below BBB- or Baa3 by Moody’s would require additional approval from the OPUC prior to issuance of debt.~~ In addition, 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~~changed. See “Credit Ratings” ~~below).~~below.

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Credit Ratings

Our debt credit ratings are a factor in our liquidity, affecting our access to the capital markets including the commercial paper market. Our debt credit ratings also have an impact on the cost of funds and the need to post collateral under derivative contracts. AIn February 2013, S&P upgraded our secured long-term first mortgage bond rating from A+ to AA-. This change has not materially impacted our liquidity, access to the short-term commercial paper markets, or our borrowing costs. There were no other changes in our credit ratings ~~below BBB- by S&P or Baa3 by Moody’s would require additional approval from the OPUC prior to our issuing additional long-term debt.~~during 2013.

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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-1~~P-2
Senior secured (long-term debt)	A+AA-	A1
Senior unsecured (long-term debt)	n/a	A3
Corporate credit rating	A+	n/a
Ratings outlook	Stable	~~Stable~~Negative

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 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

For the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013, ~~$40 million~~there were no redemptions or maturities of ~~first mortgage bonds with a coupon rate of 7.13% were redeemed at maturity. Over the next twelve months,~~long-term debt, and there are no scheduled maturities or redemptions of long-term ~~debt. For~~debt over the next twelve months. See Part II, Item 7, "Financial Condition—Contractual Obligations” in our 2012 Form 10-K for long-term debt maturing over the next five ~~years, see “Contractual Obligations” in our~~ ~~2011~~ ~~Form 10-K.~~years.

Cash Flows

Operating Activities

~~Nine months endedSeptember 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:

~~For the~~ ~~nine months endedSeptember 30, 2012, cash flow from operating activities totaled~~ ~~$178.1 million, compared to~~ ~~$191.3 million~~ in ~~2011~~. Year-over-year changes in our operating cash flows are primarily affected by net income, changes in working capital requirements, and other cash and non-cash adjustments to operating results.

Operating activity highlights include:



	Three Months Ended March 31,
In thousands	2013		2012		Change
Cash provided by operating activities	$	106,118	$	114,054	$	(7,936	)

2013 COMPARED TO 2012. The significant factors contributing to ~~changes~~the decrease in operating cash flow ~~in the~~ for first ~~nine months of~~ ~~2012~~quarter ~~compared to~~ ~~2011~~ ~~are~~were as follows:

~~an increase of~~ ~~$13.8 million~~ ~~from reductions in receivable balances primarily due to higher receivable balances from colder weather at the end of 2011, which were collected early in 2012;~~

~~an increase of~~ ~~$10.4 million~~ ~~in other-net primarily related to an increase in net collections of deferred regulatory asset balances;~~

~~an increase of~~ ~~$8.5 million~~ ~~in accounts payable balances, primarily due to an increase in customer equal payment plan balances, and the timing of payroll tax payments in 2012 compared to 2011;~~

a decrease of $~~31.8 million~~ ~~in taxes accrued, primarily related to federal tax refunds totaling $36.6 million received in 2011; and~~

~~a decrease of~~ ~~$15.8~~21.7 million from changes in the deferred gas cost savings balance, due to large accumulated gas cost savings in 2012;

a decrease of $3.9 million from changes in taxes accrued; and

an increase of $3.7 million in deferred environmental expenditures due to higher payments related to environmental activities in 2013.

Partially offsetting these decreases was:

a decrease of $12.4 million in contributions to qualified defined benefit pension plans primarily reflecting lower contribution requirements under "Moving Ahead for Progress in the 21st Century Act" (MAP-21), which ~~was reduced when mid-year balances were refunded~~among other things includes provisions that reduce the level of minimum required contributions in the near-term, but generally increases contributions in the long-run in addition to ~~customers~~increasing the operational costs of running a pension plan; and

an increase of $12.3 million from changes in ~~June~~accounts payable due a smaller reduction in gas costs in the first quarter of 2013 compared to 2012.

~~Also affecting cash flow from operating activities is the amount of cash contributions made to the utility’s qualified defined benefit pension plans.~~ During the ~~nine~~three months ended ~~September 30, 2012~~March 31, 2013, we contributed $~~23.5~~1.4 million to ~~these~~our utility's qualified defined benefit pension plans, which was ~~significantly higher~~slightly lower than the $~~4.3~~1.5 million in non-cash expense recognized on the income statement, compared to contributions of $~~19.2~~13.8 million and $~~5.5~~2.0 million in non-cash expense for the same ~~nine~~three month period in ~~2011.~~2012. We expect pension contributions to exceed non-cash expense for the next few years, but contribution amounts will be less than previously anticipated due to funding relief approved under the new MAP-21 Act in July 2012. ~~We are currently evaluating the impact of these new funding rules and the~~The amounts and timing of ~~these expenses~~future contributions will depend on market interest rates and investment returns on the plans’ assets.

3938

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Also significantly affecting cash flows over the past few years has been income tax ~~relief,~~legislation, including the ~~Tax~~American Taxpayer Relief ~~Unemployment Insurance Reauthorization, and Job Creation~~ Act of ~~2010 (the Tax Relief~~2012 (2012 Act)~~. the Tax Relief Act allowed 100 percent~~, which extended 50% bonus depreciation ~~on qualified~~through 2013 for MACRS property ~~placed in service between September 9, 2010 through December 31, 2011. It also extended the 50 percent bonus depreciation deduction to qualifying property placed in service during 2012.~~with a recovery period of 20 years or less. These and other tax benefits resulted in a net operating tax loss for 2010, which was carried back to the tax year 2009 and resulted in a federal income tax refund of $22.3 million received in ~~2011.~~2011 and an additional $2.1 million received in 2012. We generated taxable income in 2011 that was fully offset by ~~net operating loss (NOL)~~an NOL carried forward from 2010. We ~~continue~~continued to generate NOL carry-forwards during 2012. We estimate generating taxable income during 2013. As of ~~September 30, 2012~~March 31, 2013, we had an estimated federal income tax receivable balance of $~~1.8~~2.0 million and an estimated NOL carry-forward balance of ~~$41.3 million~~$76.6 million. In 2011 and 2012, Oregon conformed with federal bonus depreciation, contributing to ~~2013.~~a state NOL carryforward of $82.0 million. We anticipate being able to use the full amount of ~~the current~~both NOL ~~carry-forward balance~~carryforward balances in future ~~years.~~years prior to expiration. The ~~federal NOL from 2010~~NOLs would otherwise expire in ~~2031, if not used in earlier years.~~20 years for federal and 15 years for Oregon.

Investing Activities

Investing activity highlights include:

~~Nine months endedSeptember 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:



	Three Months Ended March 31,
In thousands	2013		2012		Change
Total cash used in investing activities	$	36,266	$	37,735	$	(1,469	)
Capital expenditures	22,674		20,447		2,227
Utility gas reserves	12,257		17,220		(4,963		)

~~Cash~~2013 COMPARED TO 2012. The $1.5 million decrease in cash used in investing activities ~~for~~was due to the ~~nine months ended September 30, 2012~~ ~~totaled~~ ~~$142.5 million, up from~~ ~~$100.2 million~~timing of payments for ~~the same period in~~ ~~2011. Capital expenditures were~~ ~~$100.9 million~~ ~~in the~~ ~~nine months ended September 30, 2012, up from~~ ~~$70.0 million~~ ~~for the same period in~~ ~~2011, which was largely driven by utility facilities projects as noted below. We also invested~~ ~~$41.8 million~~ in utility gas reserves partially offset by an increase in ~~the first nine months of~~ ~~2012~~ ~~compared to~~ ~~$30.9 million~~ ~~in the same period of~~ ~~2011~~.

In 2012, we purchased a property in Sherwood, Oregon, which will enable us to consolidate and streamline certain field operations and maintenance groups, and provide us with advanced pipeline training facilities as well as a back-up emergency operations site.

~~For the year 2012, we expect to spend up to $150 million on~~ utility capital ~~projects~~expenditures reflecting increased investment for new customer acquisitions and ~~up to $5 million on non-utility capital projects. Gas storage capital expenditures in 2012 are expected to be paid primarily from working capital.~~general system maintenance. For more information on capital projects, see “Cash Flows—Investing ~~Activities”~~Activities” in the ~~2011~~2012 Form 10-K, and for more information on utility and non-utility investment opportunities, see Note 119 and “Strategic Opportunities,” above.

Financing Activities

Financing activity highlights include:

~~Nine months endedSeptember 30, 2012~~ ~~compared to~~ ~~September 30, 2011~~:



	Three Months Ended March 31,
In thousands	2013		2012		Change
Total cash used in financing activities	$	70,438	$	78,121	$	(7,683	)
Change in short-term debt	59,500		27,900		31,600
Long-term debt retired	—		40,000		(40,000		)
Cash dividend payments	12,248		11,913		335

~~Cash~~2013 COMPARED TO 2012. The decrease in cash used in financing ~~activities during the~~ ~~nine months ended September 30, 2012~~ ~~totaled~~ ~~$35.6 million, down from cash used of~~ ~~$68.7 million~~ ~~for the same period~~activity was primarily due to changes in~~2011. The main driver of this decrease in financing activity is~~ our short-term debt balances, which increased $~~34.2~~59.5 million in the ~~nine months ended September 30, 2012~~,first quarter of 2013 compared to ~~a decrease~~an increase of ~~$76.2 million for the same period in 2011. This decrease was offset by a~~ $3027.9 million ~~increase~~ in 2012. In addition, we also retired $40 million of long-term debt ~~redemptions~~ in ~~2012 along with a~~ ~~$50 million~~ ~~decrease in long-term debt issued.~~the first quarter of 2012. We continue to use long-term debt proceeds to finance utility capital expenditures, refinance maturing short-term or long-term debt maturities, and ~~for~~to fund other general corporate purposes.

~~Pension Cost and Funding Status of Qualified Retirement Plans~~

We make pension contributions to company-sponsored qualified defined benefit plans based on actuarial assumptions and estimates, tax regulations and funding laws. Our qualified defined benefit plans were underfunded by $146.9 million at December 31, 2011. For the ~~nine months ended September 30, 2012, we made cash contributions totaling~~ ~~$23.5 million~~ into our Company sponsored qualified pension plans in accordance with the Pension Protection Act of 2006. In July 2012, Congress passed legislation called the MAP-21, which among other things includes a method of stabilizing interest rate assumptions and minimum funding requirements for our qualified plans. Under MAP-21, we expect to continue making contributions to these qualified plans but most likely at reduced levels over the next three years. For more information on the funded status of our qualified retirement plans and other postretirement benefits, see ~~Note 8~~, and Part II, Item 7., “Financial Condition—Pension Cost and Funding Status of Qualified Retirement Plans,” and Part II, Item 8., Note 9, “Pension and Other Postretirement Benefits,” in the 2011 Form 10-K.

~~We also contribute to a multi-employer union pension plan (Western States Plan) pursuant to our collective bargaining agreement. We made contributions totaling~~ ~~$0.3 million~~ ~~to the Western States Plan in both the~~ ~~nine months ended September 30, 2012~~ ~~and~~ ~~2011, and we expect to contribute a total of $0.4 million during~~ ~~2012. See~~ ~~Note 8~~ ~~for further discussion. We continue to evaluate our ongoing participation in this and overall retirement benefit plans with bargaining unit employees.~~

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Ratios of Earnings to Fixed Charges

For the ~~nine~~three and twelve months ended ~~September 30, 2012~~March 31, 2013 and the twelve months ended December 31, ~~2011~~2012, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission (SEC) method, were ~~2.70~~6.47, ~~3.29~~3.17, and ~~3.41~~3.26, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income. ~~See~~The prior period amounts have been corrected for the prior period error identified during the period, see Note 14 for detail on the prior period correction and Exhibit ~~12.~~12 for the detailed ratio calculation.

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Contingent Liabilities

Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for ~~contingencies (see~~contingencies. See Part II, Item ~~7.,~~7, “Application of Critical Accounting Policies and ~~Estimates,”~~Estimates” in our ~~2011~~2012 Form ~~10-K).~~10-K. At ~~September 30, 2012~~March 31, 2013, we had a regulatory asset of $~~128.2~~125.7 million for deferred environmental costs, which includes ~~$78.4~~$69.3 million for additional costs expected to be paid in the future and ~~$22.3~~$18.7 million of capitalized accrued interest. If it is determined that both the insurance recovery and 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 "Results of Operations—~~Regulatory Matters—Oregon General~~ Rate ~~Case"~~Mechanisms—Environmental Costs" above.

APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

regulatory cost recovery and amortizations;

revenue recognition;

derivative instruments and hedging activities;

pensions and postretirement benefits;

income taxes; and

environmental contingencies.

There have been no material changes to the information provided in the 2012 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 2012 Form 10-K).


~~ITEM 3.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

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 ending ~~September 30, 2012~~March 31, 2013. See Part I ~~Item 1A., “Risk Factors,”~~ and Part II, Item ~~7A. “Quantitative~~1A, “Risk Factors” in this report and Part II, Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” in the ~~2011~~2012 Form 10-K ~~and Part II, Item 1A., “Risk Factors,” in this report~~ for details regarding these risks.

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~~ITEM 4.~~	~~CONTROLS AND PROCEDURES~~

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

The Company's management, together with its consolidated subsidiaries, 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 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

The Company's management, together with its consolidated subsidiaries, is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Exchange Act Rule 13a-15(f).

There have been no changes in our internal control over financial reporting that occurred during the quarter ended ~~September 30, 2012~~March 31, 2013 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~~

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~~3, “Legal Proceedings” in our ~~2011~~2012 Form 10-K, we have only routine nonmaterial litigation in the ordinary course of business.


~~ITEM 1A.~~	~~RISK FACTORS~~

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors discussed in Part I, ~~“Item 1A.~~ Item 1A, "Risk Factors” in our ~~2011~~2012 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~~

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

The following table provides information about purchases ~~by us during the quarter ended~~ ~~September 30, 2012~~of our equity securities that are registered pursuant to Section 12 of the Securities Exchange ~~Act:~~Act of 1934 during the quarter ended March 31, 2013:

ISSUER ~~PURCHASE~~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⁾		(a) Total Number of Shares Purchased ⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ⁽²⁾	(d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs ⁽²⁾
Balance forward				2,124,528	$	16,732,648				2,124,528	$	16,732,648
07/01/12 - 07/31/12	—	$	—	—	—
08/01/12 - 08/31/12	2,689	49.19		—	—
09/01/12 - 09/30/12	—	—		—	—
01/01/13 - 01/31/13							—	$	—	—	—
02/01/13 - 02/28/13							1,183	45.72		—	—
03/01/13 - 03/31/13							3,944	43.72		—	—
Total	2,689	$	49.19	2,124,528	$	16,732,648	5,127	$	44.18	2,124,528	$	16,732,648


~~(1)~~	~~During the quarter ended~~ ~~September 30, 2012, 2,689 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, 2012, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.~~

~~(2)~~

⁽¹⁾ During the quarter ended March 31, 2013, 5,127 shares of our common stock were purchased on the open market to meet the requirements of our share-based programs. During the quarter ended March 31, 2013, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated SOP.

⁽²⁾We have a common stock share repurchase program under which we purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 31, 2013 to repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million. During the quarter ended March 31, 2013 ~~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, 2012~~, no shares of our common stock were purchased pursuant to this program. Since the program’s inception in 2000 we have repurchased approximately 2.1 million shares of common stock at a total cost of approximately $83.3 million.


~~ITEM 6.~~	~~EXHIBITS~~

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 6, 2012~~May 2, 2013
		/s/ ~~Stephen P. Feltz~~Brody J. Wilson
		~~Stephen P. Feltz~~Brody J. Wilson
		Principal Accounting Officer
		~~Treasurer and~~Acting Controller

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NORTHWEST NATURAL GAS COMPANY

~~EXHIBIT INDEX~~

Exhibit Index to Quarterly Report on Form 10-Q

For the Quarter Ended

~~September 30, 2012~~March 31, 2013



Exhibit Number	Document
12	Statement re computation of ratios of earnings to fixed charges.

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

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

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

101	The following materials from Northwest Natural Gas Company Quarterly Report on Form 10-Q for the quarter ended ~~September 30, 2012,~~March 31, 2013, 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.



	Three Months Ended Three Months Ended September 30,
				Non-Utility
Thousands	Utility			Gas Storage		Other		Total
2012
Net operating revenues	$	42,331		$	7,544	$	40	$	49,915
Depreciation and amortization	16,661			1,620		—		18,281
Income (loss) from operations	(8,439		)	3,624		19		(4,796		)
Net income (loss)	(11,853		)	1,255		40		(10,558		)
2011
Net operating revenues	$	41,034		$	6,710	$	39	$	47,783
Depreciation and amortization	15,875			1,574		—		17,449
Income (loss) from operations	(8,029		)	2,458		19		(5,552		)
Net income (loss)	(9,518		)	1,160		46		(8,312		)



	Three Months Ended
	September 30, 2012						September 30, 2011
Thousands	Natural gas commodity⁽¹⁾			Foreign currency ⁽²⁾			Natural gas commodity⁽¹⁾			Foreign currency ⁽²⁾
Cost of sales	$	22,558		$	—		$	(18,987	)	$	—
Other comprehensive income (loss)	—			273			—			(1,221		)
Less:
Amounts deferred to regulatory accounts on balance sheet	(22,558		)	(273		)	18,987			1,221
Total impact on earnings	$	—		$	—		$	—		$	—



	Three Months Ended Three Months Ended						Favorable/
	Three Months Ended September 30,						(Unfavorable)
Thousands, except degree day and customer data	2012			2011			2012 vs. 2011
Utility volumes - therms:
Residential sales	28,369			28,809			(440		)
Commercial sales	25,117			25,001			116
Industrial - firm sales	7,506			7,843			(337		)
Industrial - firm transportation	26,952			28,570			(1,618		)
Industrial - interruptible sales	12,081			11,815			266
Industrial - interruptible transportation	58,339			55,828			2,511
Total utility volumes sold and delivered	158,364			157,866			498
Utility operating revenues - dollars:
Residential sales	$	38,937		$	41,233		$	(2,296	)
Commercial sales	25,183			26,454			(1,271		)
Industrial - firm sales	5,930			6,539			(609		)
Industrial - firm transportation	1,724			1,527			197
Industrial - interruptible sales	6,258			7,019			(761		)
Industrial - interruptible transportation	2,076			2,368			(292		)
Regulatory adjustment for income taxes paid⁽¹⁾	—			3			(3		)
Other revenues	2,048			1,405			643
Total utility operating revenues	82,156			86,548			(4,392		)
Cost of gas sold	37,570			43,117			(5,547		)
Revenue taxes	2,255			2,397			(142		)
Utility margin	$	42,331		$	41,034		$	1,297
Utility margin:⁽²⁾
Residential sales	$	22,681		$	22,836		$	(155	)
Commercial sales	10,165			10,136			29
Industrial - sales and transportation	6,727			6,623			104
Miscellaneous revenues	668			867			(199		)
Gain from gas cost incentive sharing	467			186			281
Other margin adjustments	1,315			487			828
Margin before regulatory adjustments	42,023			41,135			888
Weather normalization adjustment	—			—			—
Decoupling adjustment	308			(104		)	412
Regulatory adjustment for income taxes paid⁽¹⁾	—			3			(3		)
Utility margin	$	42,331		$	41,034		$	1,297
Customers - end of period:
Residential customers	615,642			609,159			6,483
Commercial customers	62,648			62,204			444
Industrial customers	919			915			4
Total number of customers - end of period	679,209			672,278			6,931
Actual degree days	58			50
Percent colder (warmer) than average weather⁽³⁾	43		%	(51		)%