Edgar Filing: NORTHWEST NATURAL GAS CO

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2011

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

For the Transition period from _______ to _______

Commission File No. 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices) (Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [ X ] No [ ]

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


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

(Do not check if a smaller reporting company)

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

Yes [ ] No [ X ]

At October 31, 2011, 26,702,926 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, 2011


	PART I. FINANCIAL INFORMATION
		Page Number
	Forward-Looking Statements	1

Item 1.	Consolidated Financial Statements:

	Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010	2

	Consolidated Balance Sheets at September 30, 2011 and 2010 and December 31, 2010	3

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010	5

	Notes to Consolidated Financial Statements	6

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45

Item 4.	Controls and Procedures	45

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	46

Item 1A.	Risk Factors	46

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46

Item 6.	Exhibits	46

	Signature	47

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;

·	future events or performance;

trends;

·	cyclicality;

·	earnings and dividends;

growth;

·	customer rates;

·	commodity costs;

·	operational performance and costs;

·	liquidity and financial positions;

·	project development and expansion;

·	competition;

·	storage levels, and values;

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

·	estimated expenditures and investments;

·	costs of compliance;

·	credit exposures;

·	potential efficiencies;

·	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;

·	adequacy of, and shift in mix of, gas supplies;

·	approval and adequacy of regulatory deferrals; and

·	costs and recovery related to environmental, regulatory, litigation and insurance.

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 2010 Annual Report on Form 10-K, Part I, Item 1A. “Risk Factors” and Part II, Item 7. and Item 7A., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk,” and in Part I, Items 2 and 3, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk,” and Part II, Item 1A, “Risk Factors,” herein.

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

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Income
(Unaudited)


				Three Months Ended				Nine Months Ended
				September 30,				September 30,
Thousands, except per share amounts				2011		2010		2011		2010
Operating revenues:
	Gross operating revenues		$	93,313	$	95,067	$	577,598	$	543,961
	Less: Cost of sales			43,133		46,359		313,880		281,221
	Revenue taxes			2,397		2,497		14,195		13,410
		Net operating revenues		47,783		46,211		249,523		249,330
Operating expenses:
	Operations and maintenance			28,372		26,913		89,918		85,985
	General taxes			7,514		6,659		22,338		17,451
	Depreciation and amortization			17,449		16,003		52,304		47,930
		Total operating expenses		53,335		49,575		164,560		151,366
Income (loss) from operations				(5,552)		(3,364)		84,963		97,964
Other income and expense - net				1,781		1,333		4,117		5,969
Interest expense - net				10,241		10,632		30,956		31,738
Income (loss) before income taxes				(14,012)		(12,663)		58,124		72,195
Income tax expense (benefit)				(5,700)		(5,243)		23,470		29,119
Net income (loss)			$	(8,312)	$	(7,420)	$	34,654	$	43,076
Average common shares outstanding:
	Basic			26,686		26,606		26,676		26,571
	Diluted			26,686		26,606		26,730		26,641
Earnings (loss) per share of common stock:
	Basic		$	(0.31)	$	(0.28)	$	1.30	$	1.62
	Diluted		$	(0.31)	$	(0.28)	$	1.30	$	1.62
Dividends declared per share of common stock			$	0.435	$	0.415	$	1.305	$	1.245

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets
(Unaudited)



	September 30,			September 30,			December 31,
Thousands	2011			2010			2010
Assets:
Current assets:
Cash and cash equivalents	$	25,862		$	2,501		$	3,457
Restricted cash		-			924			924
Accounts receivable		25,628			28,503			67,969
Accrued unbilled revenue		14,287			15,399			64,803
Allowance for uncollectible accounts		(1,733	)		(1,736	)		(2,950	)
Regulatory assets		76,734			83,545			52,714
Derivative instruments		3,932			1,864			2,245
Inventories:
Gas		73,572			80,955			70,672
Materials and supplies		10,009			8,668			9,713
Gas reserves		2,366			-			-
Income taxes receivable		5,019			6,762			41,066
Other current assets		14,871			11,282			19,652
Total current assets		250,547			238,667			330,265
Non-current assets:
Property, plant and equipment		2,632,498			2,528,703			2,576,402
Less: Accumulated depreciation		756,592			711,046			722,239
Total property, plant and equipment - net		1,875,906			1,817,657			1,854,163
Gas reserves		28,125			-			-
Regulatory assets		328,757			339,786			348,897
Derivative instruments		227			518			628
Other investments		69,022			68,851			69,094
Other non-current assets		15,256			15,898			13,569
Total non-current assets		2,317,293			2,242,710			2,286,351
Total assets	$	2,567,840		$	2,481,377		$	2,616,616

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets
(Unaudited)



	September 30,			September 30,			December 31,
Thousands	2011			2010			2010
Capitalization and liabilities:
Capitalization:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,703, 26,640, and 26,668 at September 30, 2011 and 2010 and December 31, 2010, respectively	$	346,197		$	342,271		$	342,978
Retained earnings		356,574			338,725			356,727
Accumulated other comprehensive income (loss)		(6,166	)		(5,675	)		(6,604	)
Total common stock equity		696,605			675,321			693,101
Long-term debt		601,700			591,700			591,700
Total capitalization		1,298,305			1,267,021			1,284,801

Current liabilities:
Short-term debt		181,200			159,875			257,435
Current maturities of long-term debt		40,000			45,000			10,000
Accounts payable		50,117			79,629			93,243
Taxes accrued		11,117			10,601			10,579
Interest accrued		11,321			12,220			5,182
Regulatory liabilities		28,593			31,502			17,828
Derivative instruments		46,651			59,898			38,437
Other current liabilities		33,609			28,074			35,457
Total current liabilities		402,608			426,799			468,161

Deferred credits and other non-current liabilities:
Deferred tax liabilities		394,217			324,166			373,409
Regulatory liabilities		266,907			252,425			258,031
Pension and other postretirement benefit liabilities		129,669			121,686			144,250
Derivative instruments		7,429			27,211			17,022
Other non-current liabilities		68,705			62,069			70,942
Total deferred credits and other non-current liabilities		866,927			787,557			863,654
Commitments and contingencies (see Note 14)		-			-			-
Total capitalization and liabilities	$	2,567,840		$	2,481,377		$	2,616,616

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Cash Flows
(Unaudited)

	Nine Months Ended
	September 30,
Thousands	2011			2010
Operating activities:
Net income	$	34,654		$	43,076
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		52,304			47,930
Undistributed (earnings) losses from equity investments		354			(576	)
Non-cash expenses related to qualified defined benefit pension plans		5,491			5,758
Contributions to qualified defined benefit pension plans		(19,245	)		(10,000	)
Deferred environmental expenditures		(7,018	)		(5,153	)
Other		(969	)		(1,863	)
Changes in assets and liabilities:
Receivables		92,840			103,377
Inventories		(3,196	)		(8,666	)
Taxes accrued		36,585			(17,198	)
Accounts payable		(33,369	)		(39,985	)
Interest accrued		6,139			6,785
Deferred gas costs		370			(22,582	)
Deferred tax liabilities		22,908			23,993
Other - net		3,440			(10,372	)
Cash provided by operating activities		191,288			114,524
Investing activities:
Capital expenditures		(70,036	)		(185,651	)
Utility gas reserves		(30,917	)		-
Restricted cash		924			34,619
Other		(192	)		953
Cash used in investing activities		(100,221	)		(150,079	)
Financing activities:
Common stock issued (purchased) - net, including common stock expense		1,320			4,129
Long-term debt issued		50,000			-
Long-term debt retired		(10,000	)		-
Change in short-term debt		(76,235	)		57,875
Cash dividend payments on common stock		(34,807	)		(33,063	)
Other		1,060			683
Cash provided by (used in) financing activities		(68,662	)		29,624
Increase (decrease) in cash and cash equivalents		22,405			(5,931	)
Cash and cash equivalents - beginning of period		3,457			8,432
Cash and cash equivalents - end of period	$	25,862		$	2,501

Supplemental disclosure of cash flow information:
Interest paid	$	24,817		$	23,796
Income taxes paid	$	1,522		$	21,100

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Notes to Consolidated Financial Statements

(Unaudited)

1.	Organization and Principles of Consolidation

The accompanying consolidated financial statements represent the consolidation of Northwest Natural Gas Company (NW Natural) and all companies that we directly or indirectly control, either through majority ownership or otherwise. Our direct and indirect wholly-owned subsidiaries include Gill Ranch Storage, LLC (Gill Ranch), NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), and NNG Financial Corporation (NNG Financial). 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). 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. See Note 4.

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 2010 Annual Report on Form 10-K (2010 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.

Our significant accounting policies are described in Note 2 of the 2010 Form 10-K. There were no material changes to those accounting policies during the nine months ended September 30, 2011, except for changes in the application of our accounting policies with respect to revenue recognition for the regulatory adjustment of income taxes paid and to expense recognition for pension costs under a regulatory deferred accounting order. For further discussion of these changes in significant accounting policies and the impact of new accounting standards, see Note 2 below. We do not have any subsequent events to report.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

2. Significant Accounting Policies Update

Industry Regulation

In applying regulatory accounting principles in accordance with U.S. GAAP, we capitalize or defer certain costs and revenues as regulatory assets and liabilities. At September 30, 2011 and 2010 and at December 31, 2010, the amounts deferred as regulatory assets and liabilities were as follows:

	Regulatory Assets
	September 30,		September 30,		December 31,
Thousands	2011		2010		2010
Current:
Unrealized loss on derivatives(1)	$	46,651	$	59,898	$	38,437
Pension and other postretirement benefit liabilities(2)		10,988		7,502		10,988
Other(3)		19,095		16,145		3,289
Total current	$	76,734	$	83,545	$	52,714
Non-current:
Unrealized loss on derivatives(1)	$	7,429	$	27,211	$	17,022
Income tax asset		70,241		75,515		72,341
Pension and other postretirement benefit liabilities(2)		110,007		104,327		118,248
Environmental costs(4)		122,454		111,931		114,311
Other(3)		18,626		20,802		26,975
Total non-current	$	328,757	$	339,786	$	348,897

	Regulatory Liabilities
	September 30,		September 30,		December 31,
Thousands	2011		2010		2010
Current:
Gas costs payable	$	16,991	$	20,487	$	15,583
Unrealized gain on derivatives(1)		3,932		1,864		2,245
Other(3)		7,670		9,151		-
Total current	$	28,593	$	31,502	$	17,828
Non-current:
Gas costs payable	$	1,250	$	900	$	2,297
Unrealized gain on derivatives(1)		227		518		628
Accrued asset removal costs		263,123		248,920		252,941
Other(3)		2,307		2,087		2,165
Total non-current	$	266,907	$	252,425	$	258,031

(1)	Unrealized gain or loss on derivatives does not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the Purchased Gas Adjustment mechanism when realized at settlement.

(2)

Certain pension and other postretirement benefit liabilities of the utility are approved for regulatory deferral, including amounts recorded to the pension cost balancing account to defer the effects of higher and lower pension expenses. Such amounts are recoverable in rates, including an interest component.

(3)	Other primarily consists of 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 to certain utility sites that are approved for regulatory deferral. In Oregon we earn the utility’s authorized rate of return as a deferred carrying charge on deferred account balances. Environmental costs related to Washington are being deferred starting January 26, 2011 with cost recovery to be determined in a future proceeding.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Revenue Recognition

Utility and non-utility revenues, which are derived primarily from the sale, transportation or storage of natural gas, are recognized upon the delivery of gas commodity or service to customers. Since 2007, utility net operating revenues also included the recognition of a regulatory adjustment for income taxes paid pursuant to a legislative rule (commonly referred to as SB 408) in effect for certain gas and electric utilities in Oregon. Under SB 408, we were required to automatically implement a rate refund, or a rate surcharge, to utility customers on an annual basis. The refund or surcharge amount was based on the difference between income taxes paid and income taxes authorized to be collected in customer rates. We recorded the refund, or surcharge, each quarter from 2007 through 2010 based on the annual amount to be recognized. However, on May 24, 2011, SB 408 was repealed and replaced by Senate Bill 967. SB 967 requires utilities to eliminate amounts accrued under SB 408 for the 2010 and 2011 tax years, thereby denying recovery by NW Natural of the surcharge related to 2010, which resulted in a one-time pre-tax charge of $7.4 million (or 17 cents per share) in the second quarter of 2011. With respect to 2011, there was substantial uncertainty surrounding the continuation of the legal requirements of SB 408 as of March 31, 2011, and accordingly, we changed our revenue recognition policy effective January 1, 2011 and did not record an accrual for the regulatory adjustment of income taxes paid pursuant to SB 408.

Pension Expense

Net periodic pension costs consist of service costs, interest costs, the expected returns on plan assets, and the amortization of actuarial gains and losses. Effective January 1, 2011, we began deferring a portion of our net periodic pension costs to a regulatory account on the balance sheet pursuant to Public Utility Commission of Oregon (OPUC) approval to defer certain pension expenses above or below the amount set in rates. As of September 30, 2011, the total amount deferred was $4.0 million. See Note 9 for further information.

New Accounting Standards

Adopted Standards

Fair Value Disclosures. In January 2010, the Financial Accounting Standards Board (FASB) issued authoritative guidance on new fair value measurements and disclosures. This guidance requires additional disclosures for fair value measurements that use significant assumptions not observable in active markets (i.e. level 3 valuations), including a roll-forward schedule. These changes were effective for periods beginning after December 15, 2010; however, we elected to early adopt these disclosure requirements, as shown in Note 9 in our 2010 Form 10-K. The adoption of this standard did not have a material effect on our financial statement disclosures.

Recent Accounting Pronouncements

Fair Value Measurement. In May 2011, the FASB issued amendments to the authoritative guidance on fair value measurement. The amendments are primarily related to disclosure requirements, which go into effect for periods beginning after December 15, 2011. Early implementation is not allowed and we are currently assessing the impact on our financial statement disclosures.

Comprehensive Income. In June 2011, the FASB issued authoritative guidance on the presentation of comprehensive income within the financial statements. An entity can elect to present items of net income and other comprehensive income in one continuous statement — referred to as the statement of comprehensive income — or in two separate, but consecutive, statements. These changes are effective for periods beginning after December 15, 2011. We intend to present net income and other comprehensive income in one continuous statement starting January 1, 2012.

Multiemployer Pension Plans. In September 2011, the FASB issued authoritative guidance regarding multiemployer pension plan disclosures. The revised standard is intended to provide more information about an employer’s financial obligations to a multiemployer pension plan and, therefore, help financial statement users better understand the financial health of all significant plans in which the employer participates. This standard is effective for periods ending after December 15, 2011. We are currently assessing the impact on our financial statement disclosures.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

3.	Earnings Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during each period presented. Diluted earnings per share are computed using 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
	September 30,						September 30,
Thousands, except per share amounts	2011			2010			2011		2010
Net income (loss)	$	(8,312	)	$	(7,420	)	$	34,654	$	43,076
Average common shares outstanding - basic		26,686			26,606			26,676		26,571
Additional shares for stock-based compensation plans		-			-			54		70
Average common shares outstanding - diluted		26,686			26,606			26,730		26,641
Earnings (loss) per share of common stock - basic	$	(0.31	)	$	(0.28	)	$	1.30	$	1.62
Earnings (loss) per share of common stock - diluted	$	(0.31	)	$	(0.28	)	$	1.30	$	1.62

For the three months ended September 30, 2011 and 2010, 63,263 and 76,088 common share equivalents, respectively, were excluded from the calculation of diluted earnings per share because the effect of these additional shares on the net loss for both periods would have been anti-dilutive. For the nine months ended September 30, 2011 and 2010, 3,436 and 427 common share equivalents, respectively, were excluded from the calculation of diluted earnings per share because the effect of these shares would have been anti-dilutive.

4.	Segment Information

We operate in two primary reportable business segments, local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as “other.” We refer to our local gas distribution business as the “utility,” and our “gas storage” and “other” business segments as “non-utility.” Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of our Mist underground storage facility in Oregon (Mist) and third-party optimization services. Our “other” segment includes NNG Financial and our equity investment in PGH, which is pursuing development of the Palomar pipeline project. For further discussion of our segments, see Note 4 in our 2010 Form 10-K.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

The following table presents summary financial information about the reportable segments for the three and nine months ended September 30, 2011 and 2010. Inter-segment transactions were insignificant.

	Three Months Ended September 30,
					Non-Utility
Thousands		Utility				Gas Storage		Other			Total
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	)
2010
Net operating revenues		$	41,258			$	4,906	$	47		$	46,211
Depreciation and amortization			15,668				335		-			16,003
Income (loss) from operations			(6,858	)			3,474		20			(3,364	)
Net income (loss)			(9,123	)			1,782		(79	)		(7,420	)

	Nine Months Ended September 30,
					Non-Utility
Thousands		Utility				Gas Storage		Other			Total
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
2010
Net operating revenues		$	233,670			$	15,523	$	137		$	249,330
Depreciation and amortization			46,925				1,005		-			47,930
Income from operations			85,995				11,910		59			97,964
Net income			36,410				6,405		261			43,076
Total assets at September 30, 2010			2,192,557				266,022		22,798			2,481,377

Total assets at December 31, 2010		$	2,310,388			$	282,945	$	23,283		$	2,616,616

5.	Common Stock

We have a share repurchase program for our common stock under which we purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 2012 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, 2011. Since inception in 2000, a total of 2.1 million shares have been repurchased at a total cost of $83.3 million.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

6.	Stock-Based Compensation

We have several stock-based compensation plans, including a Long-Term Incentive Plan (LTIP), a Restated Stock Option Plan (Restated SOP) and an Employee Stock Purchase Plan. 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 Part II, Item 8., Note 6, in the 2010 Form 10-K and current updates provided below.

Long-Term Incentive Plan. On February 23, 2011, 37,950 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 $25.25 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	$	45.74
Performance term (in years)		3.0
Quarterly dividends paid per share	$	0.435
Expected dividend yield		3.7	%
Dividend discount factor		0.8930

Restated Stock Option Plan. On February 23, 2011, options to purchase 122,700 shares were granted under the Restated SOP, with an exercise price equal to the closing market price of $45.74 per share on the date of grant, vesting over a four-year period following the date of grant and a term of 10 years and 7 days. The weighted-average grant date fair value was $6.73 per share. Fair value was estimated as of the date of grant using the Black-Scholes option pricing model based on the following assumptions:

Risk-free interest rate	2.0	%
Expected life (in years)	4.5
Expected market price volatility factor	24.5	%
Expected dividend yield	3.8	%
Forfeiture rate	3.1	%

As of September 30, 2011, there was $1.0 million of unrecognized compensation cost related to the unvested portion of outstanding Restated SOP awards expected to be recognized over a period extending through 2014.

7.	Cost and Fair Value Basis of Long-Term Debt

New Issuance of Long-Term Debt

On September 12, 2011, we issued $50 million of secured medium-term notes (MTNs) with an interest rate of 3.176 percent and a maturity date of September 15, 2021.

Cost of Long-Term Debt

Our long-term debt consists of secured MTNs with maturity dates from 2012 through 2035, interest rates ranging from 3.176 percent to 9.05 percent, and a weighted-average coupon rate of 5.93 percent. For the nine months ended September 30, 2011, we redeemed $10 million of MTNs. For more detail on our outstanding long-term debt, see Note 7 in our 2010 Form 10-K and new issuance of long-term debt above.

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Fair Value of Long-Term Debt

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. Because our debt outstanding does not trade in active markets, we used interest rates of other companies outstanding debt issues that actively trade and have similar credit ratings, terms and remaining maturities to estimate fair value of our long-term debt issues. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

	September 30,				December 31,
Thousands	2011		2010		2010
Carrying amount	$	641,700	$	636,700	$	601,700
Estimated fair value	$	774,186	$	740,731	$	690,126

8.	Comprehensive Income

Items excluded from net income and charged directly to stockholders’ equity are included in accumulated other comprehensive income (loss), net of tax. The amount of accumulated other comprehensive loss in stockholders’ equity is $6.2 million and $5.7 million as of September 30, 2011 and 2010, respectively, which is related to employee benefit plan liabilities. The following table provides a reconciliation of net income to total comprehensive income for the nine months ended September 30, 2011 and 2010.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands	2011			2010			2011		2010
Net income (loss)	$	(8,312	)	$	(7,420	)	$	34,654	$	43,076
Amortization of employee benefit plan liability, net of tax		146			97			438		293
Total comprehensive income (loss)	$	(8,166	)	$	(7,323	)	$	35,092	$	43,369

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9.	Pension and Other Postretirement Benefit Costs

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

	Three Months Ended September 30,
								Other Postretirement
		Pension Benefits						Benefits
Thousands		2011			2010			2011			2010
Service cost		$	1,839		$	1,435		$	168		$	156
Interest cost			4,503			4,517			344			343
Expected return on plan assets			(4,455	)		(4,528	)		-			-
Amortization of net actuarial loss			2,683			2,028			68			7
Amortization of prior service costs			88			(270	)		50			50
Amortization of transition obligations			-			-			103			103
Net periodic benefit cost			4,658			3,182			733			659
Amount allocated to construction			(1,279	)		(897	)		(234	)		(231	)
Amount deferred to regulatory balancing account(1)			(1,330	)		-			-			-
Net amount charged to expense		$	2,049		$	2,285		$	499		$	428

	Nine Months Ended September 30,
								Other Postretirement
		Pension Benefits						Benefits
Thousands			2011			2010			2011			2010
Service cost		$	5,638		$	4,981		$	504		$	468
Interest cost			13,556			13,500			1,031			1,028
Expected return on plan assets			(13,367	)		(13,655	)		-			-
Amortization of net actuarial loss			8,067			5,564			204			22
Amortization of prior service costs			264			140			148			148
Amortization of transition obligations			-			-			309			309
Net periodic benefit cost			14,158			10,530			2,196			1,975
Amount allocated to construction			(3,765	)		(2,797	)		(689	)		(646	)
Amount deferred to regulatory balancing account(1)			(3,989	)		-			-			-
Net amount charged to expense		$	6,404		$	7,733		$	1,507		$	1,329

(1) Effective January 1, 2011, the 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 pension expenses in future years. Our recovery of deferred pension expense balances includes accrued interest at the utility’s authorized rate of return.

See Part II, Item 8., Note 9, in the 2010 Form 10-K for more information about our pension and other postretirement benefit plans.

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In addition to the company-sponsored defined benefit plans referred to above, in accordance with our collective bargaining agreement, we contribute to a multiemployer pension plan for our bargaining unit employees known as the Western States Office and Professional Employees International Union Pension Fund (Western States Plan). The cost of this plan is in addition to pension expense in the table above. The Western States Plan is managed by a board of trustees that includes equal representation from participating employers and labor unions. Contribution rates are established by collective bargaining agreements, and benefit levels are set by the board of trustees based on the advice of an independent actuary regarding the level of benefits that agreed-upon contributions are expected to support. The Western States Plan has reported an accumulated funding deficit for the current plan year and remains in critical status. A plan is considered to be in critical status if its funded status is 65 percent or less. Federal law requires pension plans in critical status to adopt a rehabilitation plan designed to restore the financial health of the plan. Rehabilitation plans may specify benefit reductions, contribution surcharges, or a combination of the two. The Western States Plan trustees adopted a rehabilitation plan that reduced benefit accrual rates and adjustable benefits for active employee participants and increased future employer contribution rates. These changes are expected to improve the funding status of the plan. We made contributions totaling $0.3 million to the Western States Plan for both the nine months ended September 30, 2011 and 2010. This amount includes the 10 percent contribution surcharge. Contribution surcharges above the current 10 percent rate will be assessed to employer participants, but these higher surcharges will not go into effect for NW Natural until its next collective bargaining agreement, which is expected to be no earlier than June 1, 2014. Under the terms of our current collective bargaining agreement, which became effective in July 2009, we can withdraw from the Western States Plan at any time. However, if we withdraw and the plan is underfunded, we could be assessed a withdrawal liability. In accordance with accounting rules for multiemployer plans, we have not currently recognized these potential withdrawal liabilities on the balance sheet. Currently, we have no intent to withdraw from the plan, so we have not recorded a withdrawal liability.

Employer Pension Contributions

In the nine months ended September 30, 2011, we made cash contributions totaling $19.2 million to our qualified defined benefit pension plans. We also expect to make additional contributions of up to $4 million to these qualified plans over the last three months of 2011, plus we expect to make ongoing benefit payments under our unfunded, non-qualified pension plans and other postretirement benefit plans. For more information see Part II, Item 8., Note 9, in the 2010 Form 10-K.

10. Income Tax

The effective income tax rate for the nine months ended September 30, 2011 and 2010 varied from the combined federal and state statutory tax rates principally due to the following:

	September 30,
	2011			2010
Federal statutory tax rate		35.0	%		35.0	%
Increase (decrease):
Current state income tax, net of federal tax benefit		4.5	%		4.8	%
Amortization of investment and energy tax credits		(0.4	) %		(0.4	) %
Differences required to be flowed-through by regulatory commissions		1.5	%		1.2	%
Gains on company and trust-owned life insurance		(0.9	) %		(0.8	) %
Other - net		0.7	%		0.5	%
Effective income tax rate		40.4	%		40.3	%

The increase in our effective tax rate for the nine months ended September 30, 2011 compared to the same period in 2010 was negligible. See Note 10 in our 2010 Form 10-K.

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11.	Property, Plant and Equipment

The following table sets forth the major classifications of our property, plant and equipment and accumulated depreciation as of September 30, 2011 and 2010 and December 31, 2010:

	September 30,				December 31,
Thousands	2011		2010		2010
Utility plant in service	$	2,296,788	$	2,222,222	$	2,247,952
Utility construction work in progress		36,459		33,359		29,324
Less: Accumulated depreciation		740,378		700,193		710,214
Utility plant-net		1,592,869		1,555,388		1,567,062
Non-utility plant in service		290,075		66,299		290,038
Non-utility construction work in progress		9,176		206,823		9,088
Less: Accumulated depreciation		16,214		10,853		12,025
Non-utility plant-net	$	283,037	$	262,269	$	287,101

Total property, plant and equipment	$	1,875,906	$	1,817,657	$	1,854,163

12. Gas Reserves and Other Investments

Our 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 fair value, and equity investments in certain partnerships and limited liability companies, which are accounted for under the equity or cost methods. See Part II, Item 8., Note 12, in the 2010 Form 10-K for more detail on our investments.

Gas Reserves

We entered into an agreement with Encana Oil & Gas (USA) Inc. (Encana) to develop physical gas reserves that are expected to supply a portion of NW Natural’s utility customers’ requirements over the next 30 years. The volume of gas produced and allocated to NW Natural under the agreement will increase in the early years as we continue to invest in drilling, with volumes expected to peak at about 13 percent of our utility’s gas supply requirement in gas year 2015-2016. Over the first 10 years of the agreement (2011-2020), volumes are expected to average approximately 8 to 10 percent of the annual gas purchase requirements of our utility customers. Under the agreement, we expect to invest approximately $45 million to $55 million per year for five years, and our total investment is expected to be about $250 million.

Upon reviewing the transaction, the OPUC determined that our Company’s costs under the agreement will be recovered on an ongoing basis through its annual Purchased Gas Adjustment (PGA) mechanism, including the regulatory deferral and incentive sharing process for the commodity cost of gas. Annually, a forecast will be established for the amounts related to costs and volumes expected, and any variances between forecasted and actual will be subject to the PGA incentive sharing in Oregon, up to a maximum variance of $10 million of which 10 percent (or $1 million maximum) would be recognized in current income. Variances in excess of $10 million, both negative and positive, will be deferred and passed through to customers in future rates at 100 percent. As part of the decision by the OPUC, we agreed to file a general rate case in Oregon no later than December 31, 2011.

Encana began drilling in May 2011 under our agreements, and we are currently receiving gas from our interests in a section of the gas field. Our net investment at September 30, 2011 is $20.4 million, with deferred taxes totaling $10.1 million.

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 it is included under gas reserves on our balance sheet. Our maximum loss exposure related to the VIE is limited to our investment balance.

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Palomar

PGH is a development stage variable interest entity. 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.

Variable Interest Entity Analysis. As of September 30, 2011, we updated our VIE analysis and determined that we are not the primary beneficiary of PGH’s activities as defined by the authoritative guidance related to consolidations. Therefore, we account for our investment in PGH and the Palomar project under the equity method, which is included in other investments on our balance sheet. Our maximum loss exposure related to PGH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50 percent owner.

Impairment Analysis. Our investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment when circumstances or events indicate a potential loss in value may have occurred, and on an annual basis following updates to our corporate planning assumptions. When it is determined that a loss in value is other than temporary, an impairment 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 discounted future cash flows. Differing assumptions could affect the timing and amount of an impairment recorded in any period.

Earlier in 2011, our investment in PGH was reviewed for impairment when Palomar withdrew its original application with the Federal Energy Regulatory Commission (FERC) for a proposed natural gas pipeline in Oregon. At the same time, Palomar informed FERC that it intended to re-file an application later this year or in 2012 to reflect changes in the project scope, which was expected to eliminate the western portion of the proposed pipeline and align the revised project with the region’s current and future gas infrastructure needs. Palomar is working with customers in the Pacific Northwest to further understand their gas transportation needs and determine the commercial support for a revised pipeline proposal. We expect to file a new FERC certificate application to reflect a revised scope based on regional needs.

During the second quarter of 2011, we re-evaluated our equity investment in Palomar assets related to the western portion of the pipeline and determined that these costs were impaired, and as a result we recorded a pre-tax charge of $0.3 million for our share of the project. Our remaining investment balance in Palomar consists of costs related to the east zone, of which the investment balance at September 30, 2011 is $14.4 million. We continue to review the east zone costs for impairment based on the current status of the project, including Palomar’s plans to conduct an open season and re-file a revised application with FERC thereafter. Based on our current review, we determined that our remaining equity investment was not impaired because the fair value of expected cash flows from planned development of the eastern portion of the pipeline project exceeds our equity investment. However, if we learn later that the project is not viable or will not go forward, then we could be required to recognize a maximum impairment charge of up to approximately $14.1 million based on the current amount of our equity investment net of cash and working capital at Palomar. We will continue to monitor and update our impairment analysis as needed.

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13.	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 prices related to our natural gas purchase requirements. A small portion of our derivative hedging strategy involves foreign currency exchange transactions related to purchases on 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. Derivatives entered into prudently 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 80 or a 90 percent deferral of any gains and losses as regulatory assets or liabilities, with the remaining 10 or 20 percent recognized in current income. All of our commodity hedging for the 2011-12 gas year was completed prior to the start of the gas year, and these hedge prices were included in our PGA filing.

The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments for the nine months ended September 30, 2011 and 2010. All of our currently outstanding derivative instruments are related to regulated utility operations as illustrated by the derivative gains and losses being deferred to balance sheet accounts in accordance with regulatory accounting standards.

		Three Months Ended
		September 30, 2011				September 30, 2010
Thousands			Natural gas commodity(1)		Foreign currency (2)		Natural gas commodity(1)		Foreign currency (2)
Cost of sales		$	(18,987)	$	-	$	(35,744)	$	-
Other comprehensive income (loss)			-		(1,221)		-		449
Less:
Amounts deferred to regulatory accounts on balance sheet			18,987		1,221		35,744		(449)
	Total impact on earnings	$	-	$	-	$	-	$	-

		Nine Months Ended
		September 30, 2011				September 30, 2010
Thousands			Natural gas commodity(1)		Foreign currency (2)		Natural gas commodity(1)		Foreign currency (2)
Cost of sales		$	(49,106)	$	-	$	(84,837)	$	-
Other comprehensive income (loss)			-		(815)		-		110
Less:
Amounts deferred to regulatory accounts on balance sheet			49,106		815		84,837		(110)
	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.

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No collateral was posted with or by our counterparties as of September 30, 2011 or 2010. 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 diversification, we have not been subject to collateral calls in 2010 or 2011. 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 $49.9 million at September 30, 2011, we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various downgrade credit rating scenarios for NW Natural as follows:

			Credit Rating Downgrade Scenarios
Thousands	(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3		Speculative
With Adequate Assurance Calls	$	-	$	-	$	-	$	5,609	$	37,171
Without Adequate Assurance Calls	$	-	$	-	$	-	$	4,581	$	31,143

In the three and nine months ended September 30, 2011, we realized net losses of $6.6 million and $36.2 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 $12.6 million and $33.3 million, respectively, for the three and nine months ended September 30, 2010. The 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 our customers. For more information on our derivative instruments, see Note 13 in our 2010 Form 10-K.

Fair Value

In accordance with fair value accounting, we include nonperformance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. 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, 2011. As of September 30, 2011 and 2010 and December 31, 2010, the fair value was $49.9 million, $84.7 million and $52.6 million, respectively, using significant other observable, or level 2, inputs. We have used no level 3 inputs in our derivative valuations. We also did not have any transfers between level 1 or level 2 during the nine months ended September 30, 2011 and 2010.

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14.	Commitments and Contingencies

Environmental Matters

We own, or previously owned, properties that may require environmental remediation or action. We accrue all material 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 environmental liabilities, but 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 potential 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. The costs of environmental remediation 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. 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. Many of these steps are dependent upon the approval and direction of federal and state environmental regulators. The policies, determinations and directions of the regulators may develop and change over time and different regulators may take different positions on the various steps, creating further uncertainty as to the timing and scope of remediation activities. In certain cases, in addition to us, there are a number of other potentially responsible parties, each of which, in proceedings and negotiations with other potentially responsible parties and regulators, may influence the course and scope of the remediation effort. The allocation of liabilities among the potentially responsible parties is often subject to dispute and can be highly uncertain. The events giving rise to environmental liabilities often occurred many decades ago, which complicates the determination of allocating liabilities among potentially responsible parties. Site investigations and remediation efforts often develop slowly over many years. In addition, disputes may arise between potentially responsible parties and regulators as to the severity of particular environmental matters and what remediation efforts are appropriate. These disputes could lead to adversarial administrative proceedings or litigation, with uncertain outcomes.

We estimate the range of loss for environmental liabilities using current 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 lower 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 uncertainty concerning our responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives. The status of each of the sites currently under investigation is provided below.

Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (Gasco site). The Gasco site has been under investigation by us for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a Feasibility Scoping Plan which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. In December 2004, we submitted an Ecological and Human Health Risk Assessment to ODEQ, and in May 2007 we completed a revised Remedial Investigation Report and submitted it to ODEQ for review.

In 2007, we also submitted a Focused Feasibility Study (FFS) for the groundwater source control portion of the Gasco site, which ODEQ conditionally approved in March 2008, subject to the submission of additional information. We provided that information to ODEQ and are now working with the agency on the final design for the source control system. Based on the information currently available for groundwater source control at the Gasco site and our current assumptions regarding remediation, we have estimated a range of liability between $11 million and $30 million, for which we have recorded an accrued liability of $11.8 million at September 30, 2011. The estimated range of liability will be reassessed when ODEQ makes a final source control design decision.

In addition to groundwater source control, we signed a joint Order on Consent with the Environmental Protection Agency (EPA), which requires the design of remedial action for sediments from the Gasco site. This design project is underway. For the sediments project and the other investigation and clean-up work, we have recorded an additional accrued liability of $36.6 million, which reflects the low end of the range of potential liability. We accrued at the low end 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.

Siltronic site. We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (the Siltronic site). We are currently conducting an investigation of manufactured gas plant wastes on the uplands at this site for the ODEQ. The liability accrued at September 30, 2011 for the Siltronic site is $0.8 million, 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.

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Portland Harbor site. In 1998, the ODEQ and the EPA completed a study of sediments in a 5.5-mile segment of the Willamette River (Portland Harbor) that includes an area adjacent to the Gasco and Siltronic sites. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and we were notified that we are a potentially responsible party. We then joined with other potentially responsible parties (Lower Willamette Group), to fund environmental studies in the Portland Harbor. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS) under the plan. The draft FS is scheduled for submittal in 2012. In August 2008, we signed a cooperative agreement to participate in a phased natural resource damage assessment, with the intent to identify what, if any, other information is necessary to estimate additional liabilities to support an early restoration-based settlement of natural resource damage claims. As of September 30, 2011, we have an accrued liability of $7.3 million for this site, 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.

Central Service Center site. 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 where releases of hazardous substances have been confirmed and to its list where additional investigation or cleanup is necessary. We are currently performing an environmental investigation of the property under the ODEQ’s Independent Cleanup Pathway. As of September 30, 2011, 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.

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 Lower Willamette Group 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 Lower Willamette Group 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 are underway. As of September 30, 2011, we have an estimated liability accrued of $0.8 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, 2011 and 2010 and December 31, 2010:

	Current Liabilities						Non-Current Liabilities
	Sept. 30,		Sept. 30,		Dec. 31,		Sept. 30,		Sept. 30,		Dec. 31,
Thousands	2011		2010		2010		2011		2010		2010
Gasco site	$	10,389	$	7,738	$	11,366	$	38,051	$	43,597	$	38,921
Siltronic site		721		746		720		114		275		201
Portland Harbor site		2,174		2,712		2,304		5,122		5,594		5,784
Central Service Center site		5		5		5		530		510		510
Front Street site		-		72		1		765		1,039		1,097
Other sites		-		-		-		129		110		108
Total	$	13,289	$	11,273	$	14,396	$	44,711	$	51,125	$	46,621

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

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. Through a series of extensions, the authorized cost deferral and interest accrual has been extended through January 2012. In addition, we filed a request with the Washington Utilities and Transportation Commission (WUTC) in January 2011 to defer certain environmental costs associated with services provided to Washington customers. We received an order from the WUTC on June 30, 2011 granting that request. Environmental costs related to Washington are being deferred as of January 26, 2011 with cost recovery to be determined in a future proceeding.

On a cumulative basis, we have recognized a total of $107.7 million for environmental costs, including legal, investigation, monitoring and remediation costs, and $4.9 million paid and expensed prior to regulatory deferral order approval. At September 30, 2011, we had a regulatory asset of $122.5 million, which includes $51.8 million of total paid expenditures to date, $58 million for additional environmental costs expected to be paid in the future and accrued interest of $18.1 million, partially offset by $5.4 million of environmental costs expensed in prior years. See table below.

In December 2010, NW Natural commenced litigation against certain of its historical liability insurers in Multnomah County Circuit Court, State of Oregon, Case Number 1012-17532. The defendants include Associated Electric & Gas Insurance Services Limited, Allianz Global Risk US Insurance Company, Certain Underwriters at Lloyd's, London, certain London market insurance companies and other insurance companies. In the suit, NW Natural alleges that the defendant insurance companies issued third party liability insurance policies to NW Natural and that the defendants have breached the terms of those policies by failing to indemnify NW Natural for liabilities arising from environmental contamination at certain sites caused or alleged to be caused by its historical operations. NW Natural seeks damages for the losses it has incurred to date, as well as declaratory relief for additional losses it expects to incur in the future. In addition to seeking recovery of our environmental costs from our insurers, we believe recovery of the remainder of our deferred charges, if any, is probable through the regulatory process. Our regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We continue to anticipate that our overall insurance recovery effort could extend over several years, and may include settlements from time to time with one or more of the defendant insurance companies.

Our regulatory recovery of environmental cost deferrals may be initiated in the Oregon general rate case; however, we do not expect to have concluded our insurance recovery efforts by that point, so we are not currently able to estimate the amount of recovery expected through the implementation of new rates from the upcoming general rate proceeding. The following table summarizes the non-current regulatory assets relating to environmental sites at September 30, 2011 and 2010 and December 31, 2010:

	Non-Current Regulatory Assets
	September 30,		September 30,		December 31,
Thousands	2011		2010		2010
Gasco site	$	79,823	$	72,531	$	74,205
Siltronic site		3,535		3,120		3,174
Portland Harbor site		35,889		33,316		33,940
Central Service Center site		610		551		553
Front Street site		2,130		2,000		2,020
Other sites		467		413		420
Total	$	122,454	$	111,931	$	114,312

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Legal Proceedings

We are subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, we do not expect 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.

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.

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

The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural) 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, 2011 and 2010. A significant portion of our business results are seasonal in nature, and as such the results of operations for the three and nine month periods are not necessarily indicative of expected fiscal year results. Therefore, this discussion should be read in conjunction with our 2010 Annual Report on Form 10-K (2010 Form 10-K) as well as our Quarterly Reports on Form 10-Q for the first and second quarters of 2011. Unless otherwise indicated, references below to “Notes” are to the Notes to Consolidated Financial Statements in this report.

The consolidated financial statements include the accounts of NW Natural and its direct and indirect wholly-owned subsidiaries which include: Gill Ranch Storage, LLC (Gill Ranch), NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), and NNG Financial Corporation (NNG Financial). These 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 regulated gas storage businesses (gas storage) as well as our other regulated and non-regulated investments and business activities (other). For a further discussion of our business segments, see Note 4.

In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on consolidated earnings. All references in this section to earnings per share are on the basis of diluted shares (see Part II, Item 8., Note 3, “Earnings Per Share,” in our 2010 Form 10-K). We use such non-GAAP (i.e. non-generally accepted accounting principles) measures in analyzing our financial performance and believe that they provide useful information to our investors and creditors in evaluating our financial condition and results of operations.

Executive Summary

Highlights of consolidated results for the third quarter of 2011 as compared to the same period in 2010 include:

·	Consolidated earnings decreased $0.9 million, from a net loss of $7.4 million or 28 cents per share in the third quarter of 2010 to a net loss of $8.3 million or 31 cents per share in the third quarter of 2011;

·	Net loss from utility operations increased $0.4 million, from $9.1 million in 2010 to $9.5 million in 2011;

·	Net income from gas storage operations decreased $0.6 million, from $1.8 million in 2010 to $1.2 million in 2011, primarily reflecting current market values for contract storage and optimization services;

·	Net operating revenues (margin) increased $1.6 million or 3 percent over 2010, with utility margin down $0.2 million and gas storage margin up $1.8 million;

·	Operating expenses increased $3.8 million or 8 percent over 2010, primarily due to increases attributed to Gill Ranch’s first-year expenses for operations, maintenance, depreciation and amortization;

·	Income tax benefit increased $0.5 million in 2011 compared to 2010, primarily due to a higher pre-tax loss;

·	Cash flow from operating activities on a year-to-date basis was $191.3 million, for an increase of $76.8 million or 67 percent over the same year-to-date period in 2010;

·	Utility customers increased by approximately 5,400 over the last 12 months, for an annual growth rate of 0.8 percent compared to slightly above 1 percent a year ago.

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Issues, Challenges and Performance Measures

Economic Environment. Weakness in the local, national and global economies has continued to impact utility customer growth, the demand for natural gas, and the value of natural gas storage services. Our utility’s annual customer growth rate was 0.8 percent at September 30, 2011, as compared to 0.8 percent at June 30, 2011 and 1.2 percent at September 30, 2010. Total delivered volumes to utility customers in the third quarter of 2011 decreased 3 percent, with unemployment rates remaining around 10 percent throughout our service territories in Oregon and southwest Washington and business conditions remaining sluggish as well. Despite these challenges, we believe our utility is well positioned to continue adding customers due to low natural gas prices, an ability to increase market share in residential and commercial sectors, ongoing programs to convert homes to natural gas, and the potential for environmental initiatives that could favor natural gas use in our region.

Managing Gas Prices and Supplies. Our gas acquisition strategy is regularly updated to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices so that we can effectively manage costs, reduce price volatility and maintain a competitive advantage. With recent developments in drilling technologies and substantial access to supplies from shale gas formations around the U.S. and in Canada, the supply outlook for North American natural gas has increased dramatically, which is contributing to lower and more stable gas prices.

The Purchased Gas Adjustment (PGA) mechanisms in Oregon and Washington, along with our own gas price hedging strategies, gas reserves, and gas supplies in storage, enable us to reduce earnings risk exposure for the company and secure lower gas costs for our customers. These lower gas prices, coupled with our focus on customer service and cost-effective energy efficiency programs, can help strengthen natural gas’ competitive advantage over other energy sources in key markets. See discussion of Investments in Gas Reserves below under Strategic Opportunities.

We typically hedge approximately 75 percent of our anticipated year-round sales volumes based on normal weather. For the 2011-12 gas year (November 1, 2011 – October 31, 2012), we are currently hedged at a level of approximately 75 percent of our forecasted sales volumes, including 51 percent financially hedged and 24 percent physically hedged with gas inventories in storage, local production from the Mist area, and expected production of gas reserves. The gas reserves are related to a recent transaction whereby we agreed to purchase working interests in producing wells from Encana Oil & Gas (USA) Inc. (Encana). For further discussion of gas reserves, see Investments in Gas Reserves under Strategic Opportunities below.

Additionally, we are currently hedged at approximately 30 percent for the 2012-13 gas year and between 9 and 13 percent hedged for annual requirements over the following five gas years. Our hedge levels are subject to change based on actual load volumes, which depend to a certain extent on weather and economic conditions. Also, our storage levels may increase or decrease based on storage expansion or storage recall by the utility. As for gas reserves, these levels are estimates of production, which are subject to change based on possible unforeseen events that include the impact from speed of drilling and the volume of production.

Although stable gas prices provide opportunities to manage costs for our utility customers, they also present challenges for our gas storage business by lowering the value of, and reducing the demand for, storage services, consequently affecting our ability to sign long-term customer contracts at favorable prices.

Environmental Costs. We accrue material environmental loss contingencies related to our properties that require environmental investigation or remediation. Due to numerous uncertainties surrounding the preliminary nature of investigations or the developing nature of remediation requirements, actual costs could vary significantly from our loss estimates. As a regulated utility, we are allowed to defer certain costs pursuant to regulatory decisions. We are authorized by the Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC) to defer certain environmental costs, and to seek recovery of those amounts in future rates to customers. The Company is also seeking recovery of these costs under insurance policies. Any amounts collected from insurance are expected to offset amounts that may otherwise be collected from customers. Recovery of environmental costs from regulated utility rates will depend on our ability to effectively manage these costs and demonstrate that they were prudently incurred. 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 Results of Operations—Regulatory Matters—Rate Mechanisms—Regulatory Recovery for Environmental Costs below, Note 14 in this report and Note 15 in our 2010 Form 10-K.

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Climate Change. See Part II, Item 7., “Executive Summary - Issues, Challenges and Performance Measures—Climate change,” in our 2010 Form 10-K for a discussion of the effect of climate change on our business.

Performance Measures. In order to deal with the challenges affecting our businesses, we annually review and update our strategic plan to map our course over the next several years. Our plan includes strategies for: further improving our utility gas distribution system, services and operations; growing our non-utility gas storage business; investing in natural gas infrastructure when necessary to support the needs of our region; and maintaining a leadership role within the gas utility industry by addressing long-term energy policies and pursuing business opportunities that support clean energy technologies. We intend to measure our performance and monitor progress on relevant metrics such as: earnings per share growth; total shareholder return; return on invested capital; utility return on equity; utility customer satisfaction; utility margin; utility capital and operations and maintenance expense per customer; and non-utility earnings before interest, taxes, depreciation and amortization (non-utility EBITDA).

Strategic Opportunities

Business Process Improvements. To address the current economic and competitive challenges, we continue to evaluate and implement business strategies to improve efficiencies. Our goal is to develop, integrate, consolidate and streamline operations and to support our employees and customers with new technology tools.

Gas Storage Operations. The Company has developed gas storage facilities in Oregon and California. In California, Gill Ranch began operating during the fourth quarter of 2010 and offers storage services to the California market at market-based rates. Gill Ranch is subject to California Public Utilities Commission (CPUC) regulation including, but not limited to, service terms and conditions, tariff regulations, and security issuances. Gill Ranch currently is designed as a 20 Bcf facility, of which 75 percent is owned by NW Natural, but is expandable to a total estimated capacity of 40 Bcf of which NW Natural would own 50 percent. Due to increasing supplies and price stability of natural gas in North America, and declining demand for natural gas due to current economic conditions, storage values are expected to remain low in the near term, which will likely affect the prices at which Gill Ranch is able to contract and the timing of future storage expansions. For more information, see Note 4 in this report and Part II, Item 7., “2011 Outlook—Strategic Opportunities,” in our 2010 Form 10-K.

In Oregon, we own storage facilities at Mist which serve the Pacific Northwest storage markets. These markets also are negatively impacted by lower gas prices and lack of gas price volatility, but to a lesser extent than in California and other markets around the country because of limited availability of storage capacity in the Northwest. In 2012, we expect to continue planning for possible expansion at our Mist gas storage facilities in anticipation of increased demand for electric generation in the Pacific Northwest. We do not have an established timeline for the next expansion at Mist, but we believe expansion could be as early as 2014. In the meantime, we will continue to monitor the market demand and work on preliminary design and project planning, which will ultimately require the development of storage wells, potentially a second compression station and additional pipeline gathering facilities that could enable future storage expansions.

Pipeline Diversification. Currently, our utility and Mist gas storage operations depend on a single bi-directional interstate transmission pipeline to ship gas supplies. 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. The Palomar pipeline was originally proposed with an east and a west segment, but Palomar currently plans to design an east-only pipeline to serve our utility customers as well as the growing natural gas markets in Oregon and other parts of the Pacific Northwest. The proposed pipeline would be regulated by the Federal Energy Regulatory Commission (FERC).

In March 2011, Palomar withdrew its original application with FERC for a natural gas pipeline in Oregon, but at the same time informed FERC that it intends to file a new application later this year or in 2012, after it has conducted an open season and obtained commercial support for the east segment pipeline, which is approximately 110 miles long.

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Investments in Gas Reserves. In addition to hedging gas prices with financial derivative contracts over the next few years, we recently signed an agreement with Encana to develop physical gas supplies to supply a portion of our utility customers’ requirements over a period of about 30 years. During the first 10 years of the agreement, we forecast the volumes of gas received under the Encana agreement to provide approximately 8 to 10 percent 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, with our total investment expected to be about $250 million. Encana will assign to us a working interest in leases to certain sections of the Jonah gas field, located near Rock Springs, Wyoming. These sections include both future and currently producing wells. Operation of the wells will be governed by a joint operating agreement under which Encana will be the operator and we will pay our proportionate share of operating costs.

Upon reviewing the transaction, the OPUC determined that our Company’s costs under the agreement will be recovered on an ongoing basis through our annual PGA mechanism, including the regulatory deferral and incentive sharing process for the commodity cost of gas. See Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment below. Annually, a forecast will be established for the amounts related to costs and volumes expected, and any variances between forecasted and actual will be subject to our PGA incentive sharing in Oregon, up to a maximum variance of $10 million of which 10 percent (or $1 million maximum) would be recognized in current income. Variances in excess of $10 million, both negative and positive, will be deferred and passed through to customers in future rates at 100 percent. As part of the decision by the OPUC, we agreed to file a general rate case in Oregon no later than December 31, 2011.

Consolidated Earnings and Dividends

Three months ended September 30, 2011 compared to September 30, 2010:

For the three months ended September 30, 2011, we reported a net loss of $8.3 million, or 31 cents per share, compared to a net loss of $7.4 million, or 28 cents per share, for the same period last year.

The primary factors contributing to the increased third quarter consolidated net loss were:

·	a $1.5 million increase in operations and maintenance expense primarily related to first-year expenses related to storage operations at Gill Ranch; and

·	a $1.4 million increase in depreciation and amortization also primarily related to first-year storage operations at Gill Ranch.

Partially offsetting the above factors were:

·	a $1.6 million increase in net operating revenues primarily related to storage operations at Gill Ranch.

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Nine months ended September 30, 2011 compared to September 30, 2010:

Net income was $34.7 million, or $ 1.30 per share, for the nine months ended September 30, 2011, compared to $43.1 million, or $ 1.62 per share, for the same period last year.

The primary factors contributing to the $8.4 million decrease in net income were:

a $12.1 million reduction in utility net operating revenues (margin), representing a $7.4 million write-off taken in 2011 plus $5.0 million of revenues accrued in the first nine months of 2010, related to the repealed Oregon legislative rule on utility income taxes paid. See “Results of Operations - Business Segments - Utility Operations - Regulatory Adjustment for Income Taxes Paid,” below for further explanation;

·	a $3.9 million increase in operations and maintenance expense, primarily due to a $4.4 million increase at Gill Ranch reflecting first-year operating expenses;

·	a $4.9 million increase in general taxes, primarily due to a $5.2 million refund of utility property taxes in 2010, partially offset by a $1.1 million decrease in other taxes, and a $0.8 million increase in property and other taxes at Gill Ranch, which reflect first-year operating expenses; and

·	a $4.4 million increase in depreciation and amortization expense, due to a $0.8 million increase at the utility and a $3.6 million increase at Gill Ranch.

Partially offsetting the above factors were:

·	an $8.1 million increase in utility margin attributable to an increase in residential and commercial customer use, reflecting gains from colder weather and customer growth; and

·	a $5.6 million decrease in income tax expense related to lower taxable income.

Dividends paid on our common stock were 43.5 cents per share in the third quarter of 2011, compared to 41.5 cents per share in the third quarter of 2010. The Board of Directors declared a quarterly common stock dividend of 44.5 cents per share, payable on November 15, 2011, to shareholders of record on October 31, 2011, thereby increasing the indicated annual dividend rate by more than 2 percent from $1.74 to $1.78 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 (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 2010 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 2010 Form 10-K), except as indicated below under Revenue Recognition and Pension Expense.

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Revenue Recognition

Utility and non-utility revenues, which are derived primarily from the sale, transportation or storage of natural gas, are recognized upon the delivery of gas commodity or service to customers. From 2007 through 2010, utility revenues included the recognition of a regulatory adjustment for income taxes paid pursuant to a legislative rule (commonly referred to as SB 408), which applied to certain gas and electric utilities in Oregon. Under SB 408, we were required to automatically implement a rate refund, or a rate surcharge, to utility customers on an annual basis. The refund or surcharge amount was based on the difference between income taxes paid and income taxes authorized to be collected in customer rates. We recorded the refund, or surcharge, each quarter based on the annual amount to be recognized. On May 24, 2011 the Oregon Governor signed Senate Bill 967 (SB 967), which repealed SB 408. The new law requires utilities in Oregon, to reverse amounts accrued for the 2010 and 2011 tax years, which resulted in us recording a one-time pre-tax charge to earnings in the second quarter of 2011 in the amount of $7.4 million ($4.4 million after-tax or 17 cents per share). See “Results of Operations—Business Segments - Utility Operations—Regulatory Adjustment for Income Taxes Paid,” below for a further discussion.

Pension Expense

Net periodic pension cost consists of service costs, interest costs, the expected returns on plan assets, and the amortization of actuarial gains and losses. Effective January 1, 2011, we began deferring a portion of our net periodic pension cost to a regulatory account on the balance sheet pursuant to OPUC approval of pension expenses above or below the amount set in rates. As of September 30, 2011, the cumulative amount deferred for future pension cost recovery was $4.0 million.

The funded status of our qualified pension plans is likely to be negatively affected by recent changes in market conditions, including a decline in corporate bond interest rates, which increases the value of pension liabilities, and a decline in equity market prices, which decreases the value of pension assets. The combination of these recent market events is likely to result in higher net periodic pension costs and higher pension contributions. For further discussion, see Note 9.

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, except for the items discussed above under Revenue Recognition and Pension Expense. 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

We are subject to regulation with respect to, among other matters, rates and systems of accounts set by the OPUC, WUTC, FERC, and with respect to Gill Ranch, the CPUC. The OPUC and WUTC also regulate our issuance of securities and the CPUC regulates the issuance of securities by Gill Ranch. In 2011, approximately 90 percent of our utility gas volumes were delivered to, and utility operating revenues were derived from, Oregon customers, and the balance was derived from Washington customers. Future earnings and cash flows from utility operations will be determined largely by the Oregon and Washington economies in general, by the pace of growth in the residential and commercial markets in particular, and by our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery for our utility gas costs, including operating and maintenance expenses and investment costs made in utility plant and other regulatory assets. See Part II, Item 7., “Results of Operations—Regulatory Matters,” in the 2010 Form 10-K.

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Rate Mechanisms

Purchased Gas Adjustment. Rate changes are established for the utility each year under PGA mechanisms in Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases, including contract gas purchase prices, gas prices hedged with financial derivatives or physical gas reserves, gas inventory prices, interstate pipeline demand costs, the application of temporary rate adjustments to amortize balances in deferred regulatory accounts and the removal of temporary rate adjustments effective for the previous year.

In October 2011, the OPUC and WUTC approved PGA rate changes effective on November 1, 2011. The effect of these rate changes was to decrease the average monthly bills of Oregon and Washington residential customers by about 2 percent. This was our third consecutive year of PGA rate decreases, and cumulatively our utility residential customer bills declined 20 percent in Oregon and 26 percent in Washington 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 or 90 percent 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 or 10 percent of the difference between actual and estimated gas costs, respectively. In addition to the gas cost incentive sharing mechanism, we are subject to an annual earnings test to determine if the utility is earning above its allowed return on equity (ROE) threshold. If utility earnings exceed a specific ROE level, then 33 percent of the amount above that level is required to be deferred for refund to customers. Under this provision, if we select the 80 percent 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 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 2009-10, the 2010-2011 and the 2011-2012 PGA years. The ROE threshold is subject to adjustment annually based on movements in long-term interest rates. For calendar years 2009 and 2010, the ROE threshold after adjustment for long-term interest rates was 11.5 percent and 11.02 percent, respectively. No amounts were required to be refunded to customers as a result of the 2009 utility earnings test, while we will be refunding $0.2 million to customers for the 2010 utility earnings test. For 2011, we accrued an estimated $0.2 million for potential refund to customers based on results through September 30.

In our Quarterly Report on Form 10-Q for the period ended June 30, 2011, we reported that the OPUC Staff and other parties were disputing our determination of the amount to be refunded to customers for the 2010 earnings test. The dispute was related to property tax expense reductions and whether they should be removed from the earnings test because they related to prior years. The dispute was heard by the Commissioners at the OPUC and, in October, the Commissioners ruled in the Company’s favor on the treatment of property tax expense reductions.

There has been no change to the Washington PGA mechanism under which we defer 100 percent of the higher or lower actual gas costs and pass those cost differences on to customers through an adjustment to future rates.

System Integrity Program. The OPUC has extended the accounting treatment and cost recovery for the system integrity program through the effective date of our next general rate case. For further discussion of the system integrity program, see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms—System Integrity Program” in our 2010 Form 10-K.

Regulatory Recovery for Environmental Costs. The OPUC has authorized us to defer environmental costs associated with certain named sites and to accrue interest on 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. Through a series of extensions, the authorized cost deferral and interest accrual has been extended through January 2012. See Note 14 for further discussion of our regulatory and insurance recovery of environmental costs.

In January 2011, we filed a request with the WUTC to defer environmental costs, if any, that are incurred in connection with services provided to Washington customers. On June 30, 2011, we received an order granting approval of that request, with cost deferrals effective January 26, 2011.

Pension Deferral. Effective January 1, 2011, the OPUC approved our request to defer annual pension expenses above the current amount set in rates, with recovery of these deferred 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 of return, which is currently 8.62 percent. The estimated reduction to operations and maintenance expense for 2011 is currently estimated to be $5 million, with $4 million being deferred through September 30, 2011. Future years’ deferrals will depend on changes in plan assets and projected benefit liabilities, as well as our pension contributions.

For a discussion of other rate mechanisms, see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms” in our 2010 Form 10-K.

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Business Segments - Utility Operations

Our utility margin results are largely affected by customer growth and to a certain extent by changes in weather and customers’ gas usage patterns, with a significant portion of our earnings being derived from natural gas sales to residential and commercial customers. In Oregon, we have a conservation tariff that adjusts margin revenues to offset changes resulting from increases or decreases in residential and commercial customers’ gas usage. We also have a weather normalization mechanism in Oregon that adjusts customer bills up or down to offset changes in margin resulting from above- or below-average temperatures during the winter heating season. Both mechanisms are designed to reduce the volatility of our utility earnings and customer charges. For more information on our conservation tariff and weather mechanisms, see discussion under Regulatory Matters—Rate Mechanisms in our 2010 Form 10-K.

Three months ended September 30, 2011 compared to September 30, 2010:

Utility operations resulted in a net loss of $9.5 million, or 35 cents per share, in the third quarter of 2011 compared to a net loss of $9.1 million, or 34 cents per share, in the third quarter of 2010. Utility margin during the third quarter of 2011 was fairly flat compared to 2010, with a $0.4 million increase in residential and commercial margin from customer growth, which was more than offset by a $1.0 million decrease from the repeal of SB 408 (see Regulatory Adjustment for Income Taxes Paid below). Total utility volumes sold and delivered in the third quarter of this year decreased by 3 percent over last year, which consisted of a 3 percent decrease in residential and commercial volumes and a 3 percent decrease in industrial volumes.

Our decoupling mechanism adjusted residential and commercial margins down by $0.1 million in the third quarter of 2011, compared to a margin decrease of $1.0 million in 2010.

Nine months ended September 30, 2011 compared to September 30, 2010:

In the nine months ended September 30, 2011, utility operations contributed net income of $31.7 million or $1.19 per share, compared to $36.4 million or $1.37 per share in 2010. Total utility volumes sold and delivered in the nine months ended September 30, 2011 increased by 10 percent over last year primarily due to 14 percent colder weather, while total utility margin decreased by $3.4 million, or 1 percent, primarily due to a reduction in margin of $12.1 million related to the repeal of SB 408 discussed earlier, partially offset by an $8.1 million increase in residential and commercial margins, after weather and decoupling mechanism adjustments, related to the benefits of colder weather in the first half months of 2011 and customer growth (see “Residential and Commercial Sales,” below).

During the nine months ended September 30, 2011 our weather normalization mechanism adjusted residential and commercial margins down by $10.6 million based on temperatures that were 14 percent colder than last year and 12 percent colder than average, compared to a margin increase of $11.6 million last year when temperatures were 2 percent warmer than average. Our decoupling mechanism adjusted residential and commercial margins up by $10.8 million in the nine months ended September 30, 2011, compared to a margin increase of $8.0 million in the nine months ended September 30, 2010, both due to lower average customer usage per degree day.

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The following tables summarize the composition of gas utility volumes, revenues and margin:

	Three Months Ended						Favorable/
	September 30,						(Unfavorable)
Thousands, except degree day and customer data	2011			2010			2011 vs. 2010
Utility volumes - therms:
Residential sales		28,809			30,031			(1,222	)
Commercial sales		25,450			26,179			(729	)
Industrial - firm sales		7,843			8,079			(236	)
Industrial - firm transportation		28,121			28,942			(821	)
Industrial - interruptible sales		11,815			12,124			(309	)
Industrial - interruptible transportation		55,828			57,268			(1,440	)
Total utility volumes sold and delivered		157,866			162,623			(4,757	)
Utility operating revenues - dollars:
Residential sales	$	42,925		$	44,255		$	(1,330	)
Commercial sales		26,773			27,609			(836	)
Industrial - firm sales		6,631			6,934			(303	)
Industrial - firm transportation		1,476			1,340			136
Industrial - interruptible sales		7,138			7,709			(571	)
Industrial - interruptible transportation		2,364			2,024			340
Regulatory adjustment for income taxes paid(1)		3			956			(953	)
Other revenues		(762	)		(723	)		(39	)
Total utility operating revenues		86,548			90,104			(3,556	)
Cost of gas sold		43,117			46,349			3,232
Revenue taxes		2,397			2,497			100
Utility margin	$	41,034		$	41,258		$	(224	)
Utility margin:(2)
Residential sales	$	22,837		$	23,237		$	(400	)
Commercial sales		10,135			10,203			(68	)
Industrial - sales and transportation		6,623			6,608			15
Miscellaneous revenues		867			860			7
Gain (loss) from gas cost incentive sharing		186			415			(229	)
Other margin adjustments		487			(57	)		544
Margin before regulatory adjustments		41,135			41,266			(131	)
Decoupling adjustment		(104	)		(964	)		860
Regulatory adjustment for income taxes paid(1)		3			956			(953	)
Utility margin	$	41,034		$	41,258		$	(224	)
Customers - end of period:
Residential customers		609,159			604,327			4,832
Commercial customers		62,204			61,656			548
Industrial customers		915			920			(5	)
Total number of customers - end of period		672,278			666,903			5,375
Actual degree days		50			110
Percent colder (warmer) than average weather(3)		(51	) %		8	%

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		Nine Months Ended						Favorable/
		September 30,						(Unfavorable)
Thousands, except degree day and customer data		2011			2010			2011 vs. 2010
Utility volumes - therms:
Residential sales			282,116			235,985			46,131
Commercial sales			177,025			152,872			24,153
Industrial - firm sales			26,956			26,857			99
Industrial - firm transportation			95,717			92,709			3,008
Industrial - interruptible sales			43,573			42,372			1,201
Industrial - interruptible transportation			176,645			178,618			(1,973	)
	Total utility volumes sold and delivered		802,032			729,413			72,619
Utility operating revenues - dollars:
Residential sales		$	328,327		$	297,866		$	30,461
Commercial sales			167,262			151,810			15,452
Industrial - firm sales			21,969			22,334			(365	)
Industrial - firm transportation			4,587			4,158			429
Industrial - interruptible sales			25,648			26,286			(638	)
Industrial - interruptible transportation			6,952			5,924			1,028
Regulatory adjustment for income taxes paid(1)			(7,162	)		4,974			(12,136	)
Other revenues			10,637			14,917			(4,280	)
	Total utility operating revenues		558,220			528,269			29,951
Cost of gas sold			313,781			281,189			(32,592	)
Revenue taxes			14,195			13,410			(785	)
	Utility margin	$	230,244		$	233,670		$	(3,426	)
Utility margin:(2)
Residential sales		$	150,855		$	130,739		$	20,116
Commercial sales			59,923			52,463			7,460
Industrial - sales and transportation			21,073			20,850			223
Miscellaneous revenues			3,977			3,836			141
Gain from gas cost incentive sharing			1,308			1,110			198
Other margin adjustments			92			29			63
	Margin before regulatory adjustments		237,228			209,027			28,201
Weather normalization adjustment			(10,612	)		11,634			(22,246	)
Decoupling adjustment			10,790			8,035			2,755
Regulatory adjustment for income taxes paid(1)			(7,162	)		4,974			(12,136	)
	Utility margin	$	230,244		$	233,670		$	(3,426	)
Actual degree days			2,968			2,594
Percent colder (warmer) than average weather(3)			12	%		(2	) %

(1)	Regulatory adjustment for income taxes paid is described below.
(2)	Amounts reported as margin for each category of customers are net of cost of gas sold and revenue taxes.
(3)	Average weather represents the 25-year average degree days, as determined in our last Oregon general rate case.

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Residential and Commercial Sales

The primary factors that impact results of operations in the residential and commercial markets are customer growth, seasonal weather patterns, energy prices, competition from other energy sources and economic conditions in our service areas. Typically, 80 percent or more of our utility’s operating revenues on an annual basis are derived from gas sales to weather-sensitive residential and commercial customers. Although variations in temperatures between periods will affect volumes of gas sold to these customers, the effect on margin and net income is significantly reduced by our weather normalization mechanism in Oregon where about 90 percent of our customers are served. For more information on our weather mechanism, see Regulatory Matters—Rate Mechanisms—Weather Normalization in our 2010 Form 10-K.

Three months ended September 30, 2011 compared to September 30, 2010:

The primary factors contributing to changes in residential and commercial volumes and operating revenues in the third quarter of this year as compared to the same period last year were:

·	sales volumes decreased 3 percent based on weather that was 55 percent warmer than 2010; sales volumes to utility customers are not as weather sensitive in the summer months as they are in the winter-heating season;

·	utility operating revenues decreased $2.2 million or 3 percent partly due to the lower sales volumes and partly due to customer rate decreases over last year; and

·	utility margin increased $0.4 million or 1 percent, including decoupling adjustments.

Nine months ended September 30, 2011 compared to September 30, 2010:

The primary changes that impacted margin from residential and commercial sales for the nine months ended September 30, 2011 compared to September 30, 2010 were as follows:

·	utility sales volumes increased 18 percent, primarily reflecting 14 percent colder weather and customer growth;

·	utility operating revenues increased $45.9 million or 10 percent, primarily reflecting increased volumes from colder weather and customer growth, partially offset by customer rate decreases over last year; and

·	utility margin increased $8.1 million or 4 percent, primarily reflecting increased volumes from customer growth and colder weather, which was partially offset by weather normalization adjustments that benefit customer bills when weather is colder than normal.

Industrial Sales and Transportation

Operating revenues from industrial customers include the commodity cost component of gas sold under sales service but not under transportation service. Therefore, operating revenues from industrial customers can increase or decrease when customers switch between sales service and transportation service, but generally our margins from these customers are unaffected by these changes because we do not include a profit mark-up for the cost of gas. As such, we believe volumes delivered and margins are better measures of performance for the industrial sector.

Three months ended September 30, 2011 compared to September 30, 2010:

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

·	volumes delivered to industrial customers decreased by 2.8 million therms, or 3 percent; and

·	margin was roughly the same as last year.

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Nine months ended September 30, 2011 compared to September 30, 2010:

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

·	volumes delivered to industrial customers increased 2.3 million therms, or 1 percent, due to a slight increase in energy demand, with the majority of the increased volumes attributable to the manufacturing sector; and

·	margin increased $0.2 million, or 1 percent primarily due to the increase in volumes.

Regulatory Adjustment for Income Taxes Paid

From 2007 through 2010, Oregon law required certain regulated natural gas and electric utilities to annually review the amount of income taxes collected in rates from utility operations and compare it to the amount the utility actually pays to taxing authorities. Under this law, if we paid less in income taxes related to utility operations than we collected from Oregon utility customers, then we were required to refund the excess to our Oregon utility customers. Conversely, if we paid more in income taxes than we collected from Oregon utility customers, then we were required to collect a surcharge from Oregon utility customers.

The Company’s income taxes resulted in a surcharge every year since SB 408 became law in 2006. For the 2009 tax year, the OPUC approved the Company’s recovery of $5.1 million plus interest from customers. For the 2010 tax year, we had originally estimated and accrued the difference between income taxes paid and the amounts collected in rates of $7.1 million, excluding interest. However, SB 967 was signed into law in May of 2011, thereby repealing the regulatory adjustment for income taxes paid for the 2010 tax year and all years thereafter. As a result, we recorded a charge of $7.4 million in the second quarter of 2011 to write-off the regulatory asset amount from SB 408, plus interest, related to 2010 tax year. Also, for the corresponding three and nine month periods ended September 30, 2010, we had recognized $1.0 million and $5.0 million, respectively, of pre-tax revenues from SB 408.

SB 967 will require the OPUC to make decisions in future ratemaking proceedings on the amounts of income taxes to be recovered in customer rates. For further discussion, see “Revenue Recognition” above under Application of Critical Accounting Policies and Estimates.

Other Revenues

Other revenues include miscellaneous fee income as well as revenue adjustments reflecting deferrals to, or amortizations from, regulatory asset or liability accounts, except for gas cost deferrals which flow through the cost of gas sold.

Three months ended September 30, 2011 compared to September 30, 2010:

The change in other revenues was negligible from $0.8 million in the third quarter of 2011 compared to $0.7 million in 2010.

Nine months ended September 30, 2011 compared to September 30, 2010:

Other revenues were $10.6 million in the nine months ended September 30, 2011, a decrease of $4.3 million over the same period of 2010, reflecting a $4.7 million decrease in the decoupling amortization and a decrease in other regulatory amortizations of $2.4 million partially offset by a $1.0 million accrual for estimated credits due to utility customers from our regulatory incentive sharing mechanism related to gas storage services at Mist, and an increase in the decoupling deferral of $2.8 million.

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Cost of Gas Sold

Cost of gas sold 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. Our regulated utility does not generally earn a profit, or incur a loss, on gas commodity purchases. The OPUC and WUTC require natural gas commodity costs to be billed to customers at the same cost incurred, or expected to be incurred, by the utility. However, under the PGA mechanism in Oregon, 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 (see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above). We use natural gas commodity-based hedge contracts (derivatives), 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 usually 100 percent passed through to customers in annual rate changes, subject to a regulatory prudency review. However, utility hedge contracts entered into after the annual PGA rates are set in Oregon can impact net income because we would be required to share in any gains or losses compared to the corresponding commodity prices built into rates in the PGA. In Washington, cost of gas sold does not affect our margins or net income because 100 percent of the actual gas costs, including hedge gains and losses allocated to Washington gas sales, are passed through in customer rates (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” and “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” in the 2010 Form 10-K, and Note 13 in this report).

Three months ended September 30, 2011 compared to September 30, 2010:

·	total cost of gas sold decreased $3.2 million, or 7 percent, mainly due to a 3 percent decrease in sales volumes;

·	the average gas cost collected through rates, excluding customer refunds for accumulated gas cost savings from prior quarters remained constant at 61 cents per therm; and

·	hedge losses totaling $6.6 million were realized and included in cost of gas sold this quarter, compared to $12.6 million of hedge losses in the same period of 2010.

The effect on operating results from our gas cost incentive sharing mechanism was a margin gain of $0.2 million in the third quarter of 2011, compared to a margin gain of $0.4 million for the third quarter of 2010.

Nine months ended September 30, 2011 compared to September 30, 2010:

·	total cost of gas sold increased $32.6 million, or 12 percent, due to a 10 percent increase in total sales volumes offset by a 3 percent decrease in the average cost of gas sold per therm;

·	the average gas cost collected through rates decreased from 62 cents per therm in 2010 to 60 cents per therm in 2011, primarily reflecting lower gas prices passed through in PGA rate decreases effective November 1, 2009 and 2010; and

hedge losses totaling $36.2 million were realized and included in cost of gas sold for the nine months ended September 30, 2011, compared to $33.3 million of hedge losses in the same period of 2010. 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 $1.3 million in the nine months ended September 30, 2011 compared to $1.1 million in 2010. For a discussion of our gas cost incentive sharing mechanism, see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above.

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Business Segments - Gas Storage

Our gas storage segment primarily consists of the acquisition, development, operation, and management of natural gas storage facilities. As of September 30, 2011, we owned and operated non-utility investments at our Mist underground storage facility in Oregon and at our Gill Ranch underground storage facility in California. Construction of the Gill Ranch storage facility was completed and placed into service during the fourth quarter of 2010. Our gas storage segment also includes asset optimization services using unused gas storage and transportation capacity.

Three months ended September 30, 2011 compared to September 30, 2010:

For the three months ended September 30, 2011, we earned $1.2 million, or 4 cents per share, compared to $1.8 million, or 7 cents per share, for the same period in 2010. Even though the gas storage segment margin increased $1.8 million over last year due to revenues from the new Gill Ranch facility, net income decreased $0.6 million over 2010 due to lower firm storage and storage optimization revenues at Mist and a net loss at Gill Ranch from first year costs, including depreciation, and low storage contract revenues. In addition to currently low storage values, we did not have, as expected, all 15 Bcf of design capacity at Gill Ranch available for contracted revenues during the first year of operations. However, based on our experience with the storage reservoir so far, we anticipate that the full 15 Bcf should be available to contract with customers by the end of 2012.

Nine months ended September 30, 2011 compared to September 30, 2010:

For the nine months ended September 30, 2011, our gas storage segment earned $3.2 million, or 12 cents per share, compared to $6.4 million, or 24 cents per share, for the same period in 2010. This decrease was partly due to a downturn in revenues from firm storage and optimization services at Mist and to a net loss at Gill Ranch from first year costs, including depreciation, and low storage contract revenues. The net loss at Gill Ranch was also affected by low storage revenues during the first quarter of 2011 because most of the customer contracts did not go into effect until April 1, the beginning of the first full year of operations at Gill Ranch.

Gas storage margin increased $3.7 million to $19.2 million for the nine months ended September 30, 2011, primarily due to Gill Ranch’s revenues of $6.6 million, partially offset by a decrease in firm contract and third-party optimization revenues of $2.9 million at Mist.

Business Segments - Other

Our other business segment consists primarily of NNG Financial’s investment in KB Pipeline, our investment in PGH which in turn has invested in the Palomar pipeline project, and our other non-utility investments and business activities. NNG Financial had total assets of $0.9 million and $1.1 million as of September 30, 2011 and 2010, respectively, primarily reflecting a non-controlling interest in KB Pipeline. Our net equity investment in PGH as of September 30, 2011 and 2010 was $14.4 million and $14.7 million, respectively, reflecting a $0.3 million write-down of our Palomar investment in 2011 for project costs related to the west pipeline segment. In aggregate, earnings from our other business segment for the nine months ended September 30, 2011 and 2010 were a net loss of $0.2 million and net income of $0.3 million, respectively. See Note 4 in the 2010 Form 10-K and Note 4 in this report for further details on our other segment.

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Consolidated Operations

Operations and Maintenance

Three months ended September 30, 2011 compared to September 30, 2010:

Consolidated operations and maintenance expense was $28.4 million in 2011, compared to $26.9 million in 2010, an increase of $1.5 million or 5 percent. The primary factors contributing to the increase were:

·	a $1.4 million increase for operations and maintenance expenses at Gill Ranch; and

·	a $0.9 million increase in employee payroll expense at the utility primarily related to a slight increase in the number of employees.

Partially offsetting the above factors were:

·	a $0.3 decrease in accrued incentive compensation reflecting lower results against targets compared to last year.

Nine months ended September 30, 2011 compared to September 30, 2010:

Consolidated operations and maintenance expense was $89.9 million in 2011, compared to $86 million in 2010, a increase of $3.9 million or 5 percent. The following summarizes the major factors that contributed to changes in operations and maintenance expense for the nine months ended September 30, 2011 compared to September 30, 2010:

·	a $4.4 million increase for operations and maintenance expenses at Gill Ranch;

·	a $1.3 million increase in employee payroll expense at the utility reflecting additional customer service employees and a temporary shift in the allocation of resources between operations and maintenance work and capital project work during the period;

·	a $0.3 million increase in utility bad debt expense due to higher gross operating revenues (see discussion below); and

·	a $0.5 million increase in utility health care costs and other employee benefit expense.

Partially offsetting the above factors were:

·	a $1.0 million decrease in utility consulting and legal fees reflecting expenses incurred last year related to our successful property tax appeal;

·	a $1.7 million decrease in accrued incentive compensation at the utility based on lower results against targets compared to last year; and

·	a $0.9 million decrease in utility pension expense due to the effects of the new regulatory deferral of pension costs authorized by the OPUC (see discussion below).

Our bad debt expense as a percent of revenues was 0.24 percent for the twelve months ended September 30, 2011, compared to 0.15 percent for the same period last year. The increase in our bad debt expense ratio was largely due to lower than normal expense ratio in 2010 that reflected improved collections and recoveries of delinquent account balances. Despite the modest increase, we believe bad debt losses are comparable to last year and low compared to industry averages, but credit risks are still elevated due to the weak economy and high unemployment rates.

Effective January 1, 2011, the OPUC approved the deferral of utility pension costs when NW Natural’s qualified defined benefit pension plans’ operations and maintenance cost exceeds the amount currently recovered in rates. The pension cost deferral is recorded to a regulatory asset balancing account, which we expect to result in an estimated $5 million deferral for 2011. So far, we have deferred $4.0 million in the first nine months of 2011, which, when netted with pension expense, resulted in a $0.9 million decrease to operations and maintenance expense compared to the same period in 2010. For further explanation of the pension balancing account, see “Regulatory Matters—Rate Mechanisms—Pension Deferral,” above.

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General Taxes

Three months ended September 30, 2011 compared to September 30, 2010:

General taxes, which are principally comprised of property taxes, payroll taxes and regulatory fees, increased $0.9 million, or 13 percent, in the three months ended September 30, 2011 over the same period in 2010, reflecting the timing differences on regulatory fees payable and taxes associated with startup of Gill Ranch earlier this year.

Nine months ended September 30, 2011 compared to September 30, 2010:

General taxes increased $4.9 million in the first nine months of 2011 compared to 2010. The major factor that contributed to the change in general taxes was the $5.2 million refund in 2010 for prior years’ property taxes paid pursuant to a favorable ruling from the Oregon Supreme Court. For several years, we had been involved in litigation with the Oregon Department of Revenue over the taxability of certain inventories that were held for sale, including gas inventories. In January 2010, the Oregon Supreme Court unanimously ruled in our favor, stating that these inventories were exempt from property tax. As a result of this ruling, we were refunded $5.2 million, plus accrued interest, for taxes paid on inventories beginning with the 2002-03 tax year. We recognized a net $6.1 million increase in pre-tax income in the first quarter of 2010, which consisted of $5.2 million for the refund of property taxes, $1.9 million for accrued interest income, and $1.0 million in increased operations and maintenance expense for legal and consulting fees.

Depreciation and Amortization

Depreciation and amortization expense increased by $1.4 million, or 9 percent for the three months ended September 30, 2011, compared to the same period in 2010. For the nine months ended September 30, 2011, depreciation and amortization expense increased by $4.4 million, or 9 percent, as compared to the same period in 2010. The increased expense in the three and nine month periods of 2011 was primarily related to depreciation of Gill Ranch assets, which went into service in the fourth quarter of 2010. A portion of the increase was also related to additional investments in utility plant related to customer growth and system improvements.

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	2011			2010			2011			2010
Gains from company-owned life insurance	$	286		$	599		$	1,485		$	1,640
Interest income		6			8			36			2,006
Income (loss) from equity investments		(1	)		(152	)		(354	)		576
Net interest on deferred regulatory accounts		1,548			1,189			4,563			3,163
Gain (loss) on sale of investments		-			-			(96	)		223
Other non-operating		(58	)		(311	)		(1,517	)		(1,639	)
Total other income and expense - net	$	1,781		$	1,333		$	4,117		$	5,969

Other income and expense – net for the nine months ended September 30, 2011 decreased $1.9 million over 2010 primarily due to the 2010 refund of property taxes as discussed above, which included $1.9 million in accrued interest income. Other income and expense also included a $1.4 million increase in interest from regulatory account balances largely due to smaller gas costs refund balances, which was partially offset by a $0.9 million decrease in income from our equity investments the majority of which was related to PGH.

Interest Expense – Net

Interest expense – net decreased $0.4 million for the three months ended September 30, 2011 and $0.8 million for the nine months then ended, compared to the same periods in 2010. The current year decreases were primarily due to a $1.2 million savings from interest expense on long-term debt as a result of bonds that were redeemed in 2010, partially offset by a $0.8 million increase for gas storage related to the Gill Ranch base gas agreement.

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Income Tax Expense

The decrease in income tax expense of $5.6 million or 19 percent for the nine months ended September 30, 2011, compared to the same period in 2010, was primarily due to lower pre-tax consolidated earnings of $14.1 million or 19 percent.

The increase in our effective tax rate for the nine months ended September 30, 2011 compared to the same period in 2010 was negligible. For more information on our income taxes, including a reconciliation between the statutory federal and state income tax rates and our effective rates, see Note 10.

Financial Condition

Capital Structure

One of our long-term goals is to maintain a strong consolidated capital structure, generally consisting of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt. If additional capital is required, then 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 and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below, and Note 7). 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, 2011 and 2010 and at December 31, 2010 was as follows:

	September 30,						December 31,
	2011			2010			2010
Common stock equity		45.8	%		45.9	%		44.7	%
Long-term debt		39.6	%		40.2	%		38.1	%
Short-term debt, including current maturities of long-term debt		14.6	%		13.9	%		17.2	%
Total		100	%		100	%		100	%

Liquidity and Capital Resources

At September 30, 2011, we had $25.9 million of cash and cash equivalents compared to $2.5 million at September 30, 2010. In order to maintain sufficient liquidity during periods of volatile capital markets, at times we will maintain higher cash balances, add short-term borrowing capacity, and issue long-term debt in advance of large utility capital projects when interest rates and market conditions are attractive and favorable for customers.

Our short-term liquidity is supported by cash balances, internal cash flow from operations, proceeds from the sale of commercial paper notes, committed multi-year bank credit facilities, proceeds from cash surrender value loans taken out of company-owned life insurance policies, and proceeds from the sale of long-term debt. We use long-term debt proceeds generally to finance utility capital expenditures, to refinance maturing short-term and long-term debt and to provide for general corporate purposes. In September 2011, we issued $50 million of secured medium-term notes (MTNs) with a coupon rate of 3.176 percent and a maturity of 10 years.

With our current debt ratings (see “Credit Ratings,” below), we have been able to issue commercial paper and MTNs at attractive rates and have not needed to borrow from our back-up bank credit facilities. In the event that we were not able to issue new debt due to market conditions, we expect that our near-term liquidity needs could be met by using cash balances or drawing upon our committed credit facilities and other liquid assets. We also have a universal shelf registration filed with the Securities and Exchange Commission for the issuance of secured and unsecured debt or equity securities, subject to market conditions and regulatory approvals. We have OPUC approval to issue up to $125 million of additional MTNs under the existing shelf registration, which was filed in January 2011.

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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, 2011, we could have been required to post $37.2 million of collateral to our counterparties, but that assumes our long-term debt ratings were at non-investment grade levels, which is several rating levels below our current ratings (see “Credit Ratings,” below).

Business developments that could have a material impact on our liquidity and capital resource position include pension contributions, income tax benefits and environmental expenditures and insurance recoveries. With respect to pension requirements, we expect to make additional contributions later this year and in future years so that the plan will be fully funded in accordance with Pension Protection Act rules (see “Pension Cost and Funding Status of Qualified Retirement Plans,” below). With respect to federal income tax liabilities, an extension was granted that allows us to take bonus depreciation on qualified expenditures during 2011 and 2012, which significantly reduces our tax liability for the 2011 and 2012 tax years, thereby providing cash flow benefits in both years and possibly beyond 2012 if these deductions result in a net operating loss carry-forward (see “Cash Flows—Operating Activities,” below). With respect to environmental liabilities, we expect to continue using cash resources to fund our environmental liabilities, but we also anticipate recovering amounts from insurance and utility customer rates based on our current assumptions regarding litigation and regulatory treatment going forward. See Note 14.

Our Gill Ranch storage business began commercial operations in the fourth quarter of 2010. We anticipate operating cash flows at Gill Ranch to increase over time as our share of the facility ramps up to its full 15 Bcf design capacity, now expected to occur by the end of 2012, and as we contract for such incremental storage capacity. The amount and timing of cash flows will depend on future storage values and our ability to optimize unused storage capacity.

In July 2010, the U.S. Congress passed and President Obama signed into law the “Wall Street Reform and Consumer Protection Act,” requiring additional government regulation of derivative and over-the-counter transactions and expanded collateral requirements. While we are currently evaluating the new legislation to determine its impact on our cash flows from derivative activities, if any, we will not know the full impact until final regulations implementing the legislation are issued.

Based on several factors, including our current credit ratings, our experience issuing commercial paper, our current cash reserves, our committed credit facilities and other liquidity resources, and our expected ability to issue long-term debt under the Company’s universal shelf registration, we believe our liquidity is sufficient to meet anticipated near-term cash requirements, including all contractual obligations and investing and financing activities discussed below.

Off-Balance Sheet Arrangements

Except for certain lease and purchase commitments (see “Contractual Obligations,” below), we have no material off-balance sheet financing arrangements.

Contractual Obligations

At September 30, 2011, our purchase commitments increased approximately $23 million since December 31, 2010, primarily involving long-term contracts entered into in the normal course of business. In addition to these purchase commitments, we entered into an agreement in 2011 with Encana to develop gas reserves for our utility, for which we expect to spend an additional $200 million over the next four calendar years, subject to certain NW Natural rights to terminate the agreement. See “Financial Condition—Contractual Obligations,” in the 2010 Form 10-K.

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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 and accounts receivable, short-term debt may also be used to temporarily fund utility capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by one or more unsecured revolving credit facilities (see “Credit Agreements,” below). 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. At September 30, 2011 and 2010, our utility had commercial paper outstanding of $181.2 million and $159.9 million, respectively. The effective interest rate on the utility’s commercial paper outstanding at September 30, 2011 and 2010 was 0.3 percent and 0.4 percent, respectively.

Credit Agreements

We have a syndicated multi-year credit agreement for unsecured revolving loans totaling $250 million, which may be extended for additional one-year periods subject to lender approval. The original term of this credit agreement was extended through May 31, 2013. All lenders under our syndicated agreement are major financial institutions with committed balances and investment grade credit ratings as of September 30, 2011 (see table below). We also had three bilateral credit agreements totaling $50 million in effect from November 30, 2010 through March 31, 2011 for seasonal working capital needs.

		Loan Commitment Amounts in Thousands
		Syndicated
Lender rating, by category		Facility
AA/Aa		$	230,000
A/A			20,000
BBB/Baa			-
	Total	$	250,000

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 extended commitments with all of our lenders under the $250 million syndicated agreement through May 31, 2013. This syndicated agreement also allows us to request increases in the total commitment amount from time to time, up to a maximum amount of $400 million, and to replace any lenders who decline to extend the maturity date of the credit agreement. This syndicated agreement also permits the issuance of letters of credit in an aggregate amount up to the applicable total borrowing commitment.

Any principal and unpaid interest amounts owed on borrowings under the credit agreements are due and payable on or before the maturity date. There were no outstanding balances under these credit agreements at September 30, 2011 and 2010. These agreements require us to maintain a consolidated indebtedness to total capitalization ratio of 70 percent 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, 2011 and 2010, with consolidated indebtedness to total capitalization ratios of 54 percent for each period.

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The syndicated agreement also requires that we maintain credit ratings with Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s) and notify the lenders of any change in our senior unsecured debt ratings 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 would require additional approval from the OPUC prior to issuance of debt, and interest rates on any loans outstanding under the credit agreements are tied to debt ratings, which would increase or decrease the cost of any loans under the credit agreements when ratings are changed (see “Credit Ratings,” below).

Credit Ratings

Our debt credit ratings are a factor in our liquidity, affecting our access to capital markets including the commercial paper market. Our debt credit ratings also have an impact on the cost of funds and the need to post collateral under derivative contracts. A change in our ratings below BBB- by S&P or Baa3 by Moody’s would require additional approval from the OPUC prior to issuing additional long-term debt.

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
Senior secured (long-term debt)	A+	A1
Senior unsecured (long-term debt)	n/a	A3
Corporate credit rating	A+	n/a
Ratings outlook	Stable	Stable

The above credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of 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.

Maturities and Redemptions of Long-Term Debt

For the nine months ended September 30, 2011, $10 million of secured MTNs with a coupon rate of 6.665% were redeemed at maturity. Over the next twelve months, $40 million of secured MTNs with a coupon rate of 7.13% will be redeemed at maturity in March 2012. For long-term debt maturing over the next five years, see Part II, Item 7., "Results of Operations—Financial Condition—Contractual Obligations," in our 2010 Form 10-K.

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Cash Flows

Operating Activities

Nine months ended September 30, 2011 compared to September 30, 2010:

Year-over-year changes in our operating cash flows are primarily affected by net income, working capital requirements, and other cash and non-cash adjustments to operating results. For the nine months ended September 30, 2011, cash flows from operating activities totaled $191.3 million, compared to $114.5 million in 2010. The significant factors contributing to changes in operating cash flows in the first nine months of 2011 compared to 2010 are as follows:

·	A decrease of $9.2 million from higher pension contributions due to a decline in interest rates and asset values, which increased pension funding requirements;

·	a decrease of $10.5 million from changes in receivables primarily due to higher balances at the end of 2009 compared to 2010 because of colder weather in November and December 2009;

·	an increase of $53.8 million from income tax account balances, primarily related to bonus depreciation which resulted in federal tax refunds of $36.6 million in 2011 and other income tax benefits;

·	an increase of $ 23.0 million from changes in the regulatory deferred gas cost account balance, which reflects a lower level of refunds due utility customers for PGA gas cost savings due to differences between actual gas prices and embedded gas prices in the PGA for 2011 compared to 2010; and

·	an increase of $6.6 million from changes in gas costs payable due to weather impacts on gas purchase requirements between the two periods.

In September 2010, Congress passed the “Unemployment Insurance, Reauthorization and Job Creation Act of 2010” (the Act), and the legislation was signed into law by President Obama. The Act extended for one additional year the bonus depreciation rules first enacted in the Economic Stimulus Act of 2008 and subsequently renewed in the American Recovery and Reinvestment Act of 2009. Under the series of bonus depreciation provisions enacted, additional first-year tax deductions were allowed for depreciation equal to 50 percent of the adjusted basis of qualified property through September 8, 2010, 100 percent from September 9, 2010 through December 31, 2011, and 50 percent through December 31, 2012, with the remaining percentages recovered under normal depreciation rules. The 50 percent or 100 percent first year depreciation deduction is an acceleration of depreciation deductions that otherwise would be taken in the later years of an asset’s recovery period. As a result of this extension, we expect to recognize an increase in our cash flows because of lower current tax liabilities for 2011 and 2012. Any tax deductions in excess of 2011 and 2012 taxable income for federal income tax purposes will result in a net operating loss (NOL), which will be carried forward to the 2013 tax year because of our current tax position (see below). As of September 30, 2011, we have a federal and state income tax receivable balance of $5 million, the majority of which we expect to realize in cash flows during the fourth quarter of 2011. We received federal refunds totaling $36.6 million during 2011.

As of December 31, 2010, we reported an NOL carry-forward of $20.2 million, which will be carried forward to reduce taxable income for the 2011 tax year. We anticipate that we will be able to utilize all of the tax loss carry-forward in the current or future years.

Investing Activities

Nine months ended September 30, 2011 compared to September 30, 2010:

Cash used in investing activities for the nine months ended September 30, 2011 totaled $100.2 million, down from $150.1 million for the same period in 2010. Capital expenditures were $70 million in the nine months ended September 30, 2011, down from $185.7 million for the same period in 2010, primarily due to a $121 million decrease in non-utility construction activity, which were largely related to Gill Ranch expenditures in 2010. We also invested $30.9 million in utility gas reserves through the third quarter of 2011 under our agreement with Encana.

Over the five-year period 2011 through 2015, utility capital expenditures are estimated at between $400 and $500 million, and the utility investment in gas reserves are estimated at $250 million. The level of utility capital expenditures over this five-year period reflects assumptions on customer growth, storage facility improvements, technology investments and utility distribution improvements, including requirements under current pipeline safety rules. Most of the required funding for these investments are expected to be internally generated, except for the funding of long-term gas reserves. The funding of these long-term gas reserves, and any remaining funding that is needed to meet capital requirements of the utility, will be obtained through the issuance of long-term debt or equity securities, with short-term debt providing liquidity and bridge financing.

In 2011, we expect to spend less than $15 million on non-utility development projects, including Gill Ranch and Palomar. Gill Ranch capital expenditures are paid through equity funds and working capital. Palomar expects to continue working on revised plans for the east pipeline segment, including plans to conduct an open season to re-evaluate regional needs. The initial planning and permitting costs have been financed with equity funds from us and our partner, TransCanada American Investments Ltd. For more information on non-utility investment opportunities, see Note 12 and “Strategic Opportunities—Gas Storage Operations” and “—Pipeline Diversification,” above.

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Financing Activities

Nine months ended September 30, 2011 compared to September 30, 2010:

Cash used in financing activities during the nine months ended September 30, 2011 totaled $68.7 million, down from cash provided of $29.6 million for the same period in 2010. The main driver of this decrease in financing activity is our short-term debt balances, which decreased $76.2 million during the nine months ended September 30, 2011, compared to an increase of $57.9 million for the same period in 2010. We also redeemed $10 million of long-term debt in June of 2011. This was offset by a long-term debt issuance of $50 million in September 2011. We continue to use long-term debt proceeds to finance capital expenditures, refinance maturing short-term or long-term debt maturities, and for 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 requirements under federal law. Our qualified defined benefit plans were underfunded by $95.4 million at December 31, 2010. For the nine months ended September 30, 2011, we made cash contributions totaling $19.2 million into these qualified pension plans. We anticipate making additional contributions before year end, bringing the total amount to between $20 million and $23 million in 2011. In 2010 and 2009, we contributed $10 million and $25 million, respectively, into the qualified defined benefit pension plans. The funded status of our qualified pension plans is likely to be negatively affected by recent changes in market conditions, including a decline in corporate bond interest rates, which increases the value of pension liabilities, and a decline in equity market prices, which decreases the value of pension assets. The combination of these recent market events is likely to result in higher net periodic pension costs and higher pension contributions. For more information on the funded status of our qualified retirement plans and other postretirement benefits, see Note 9, 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 2010 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, 2011 and 2010, and we expect to contribute a total of $0.4 million during 2011. See Note 9 for further discussion.

Ratios of Earnings to Fixed Charges

For the nine and twelve months ended September 30, 2011 and the twelve months ended December 31, 2010, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were 2.85, 3.51 and 3.73 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 Exhibit 12.

Contingent Liabilities

Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in our 2010 Form 10-K). At September 30, 2011, we had a regulatory asset of $122.5 million for deferred environmental costs, which includes $58 million for additional costs expected to be paid in the future and accrued interest of $18.1 million. 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 14.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including commodity supply risk, commodity price and storage value risk, interest rate risk, foreign currency risk, credit risk, and weather risk. We monitor and manage these financial exposures as an integral part of our overall risk management program. No material changes have occurred related to our disclosures about market risk for the nine months ended September 30, 2011. See Part I, Item 1A., “Risk Factors,” and Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk,” in the 2010 Form 10-K and Part II, Item 1A., “Risk Factors,” in this report for details regarding these risks.

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, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. The statements contained in Exhibit 31.1 and Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this Item 4(b).

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Other than the proceedings disclosed in Note 14 and those proceedings disclosed and incorporated by reference in Part I, Item 3., “Legal Proceedings,” in our 2010 Form 10-K, we have only routine nonmaterial litigation in the ordinary course of business.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors discussed in Part I, “Item 1A. Risk Factors,” in our 2010 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. The risks described in the 2010 Form 10-K are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially affect our financial condition, results of operations or cash flows.

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, 2011 of equity securities that are registered pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASE OF EQUITY SECURITIES

					(c)		(d)
	(a)		(b)		Total Number of Shares		Maximum Dollar Value of
	Total Number		Average		Purchased as Part of		Shares that May Yet Be
	of Shares		Price Paid		Publicly Announced		Purchased Under the
Period	Purchased(1)		per Share		Plans or Programs(2)		Plans or Programs(2)
Balance forward						2,124,528	$	16,732,648
07/01/11 - 07/31/11		1,276	$	46.01		-		-
08/01/11 - 08/31/11		6,077		43.04		-		-
09/01/11 - 09/30/11		-		-		-		-
Total		7,353	$	43.55		2,124,528	$	16,732,648

(1)

During the quarter ended September 30, 2011, 1,276 shares of our common stock were purchased on the open market or issued by the Company to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan. In addition, 6,077 shares of our common stock were purchased on the open market during the quarter to meet the requirements of our share-based programs. During the quarter ended September 30, 2011, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.

(2)

We have a common stock share repurchase program under which we purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 31, 2012 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, 2011, no shares of our common stock were purchased pursuant to this program. Since the program’s inception in 2000 we have repurchased approximately 2.1 million shares of common stock at a total cost of approximately $83.3 million.

ITEM 6. EXHIBITS

See Exhibit Index attached hereto.

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SIGNATURE

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

NORTHWEST NATURAL GAS COMPANY

(Registrant)

Dated: November 4, 2011

/s/ Stephen P. Feltz

Stephen P. Feltz

Principal Accounting Officer

Treasurer and Controller

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NORTHWEST NATURAL GAS COMPANY

EXHIBIT INDEX

Quarterly Report on Form 10-Q

For the Quarter Ended

September 30, 2011

Exhibit Number Document


10.1	Northwest Natural Gas Company Supplemental Executive Retirement Plan 2011 Restatement

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, 2011, 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.

* In accordance with Rule 406T of Regulation S-T, the XBRL-related information in Exhibit 101 to this Quarterly Report on Form 10-Q is deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act, is deemed not filed for purposes of Section 18 of the Exchange Act and otherwise is not subject to liability under these sections.