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, 2010

[ ] 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 29, 2010, 26,640,453 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, 2010


	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, 2010 and 2009	2

	Consolidated Balance Sheets at September 30, 2010 and 2009 and December 31, 2009	3

	Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009	5

	Notes to Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48

Item 4.	Controls and Procedures	49

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	50

Item 1A.	Risk Factors	50

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51

Item 6.	Exhibits	51

	Signature	52

Table of Contents

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,” “predicts,” “projects,” “will continue” 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;

·	financial condition;

·	development of projects;

·	competition;

·	exploration of new gas supplies;

·	estimated expenditures;

·	costs of compliance;

·	credit exposures;

·	potential efficiencies;

·	impacts of new laws and regulations;

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

·	projected obligations under retirement plans;

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

·	adequacy of regulatory deferrals; and

·	environmental, regulatory and insurance costs and recovery.

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 caution you therefore 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 2009 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,” respectively.

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

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Income
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands, except per share amounts	2010			2009			2010		2009
Operating revenues:
Gross operating revenues	$	95,067		$	116,854		$	543,961	$	703,269
Less: Cost of sales		46,359			65,302			281,221		428,864
Revenue taxes		2,497			2,926			13,410		17,221
Net operating revenues		46,211			48,626			249,330		257,184
Operating expenses:
Operations and maintenance		26,913			27,122			85,985		91,248
General taxes		6,659			6,417			17,451		21,480
Depreciation and amortization		16,003			15,817			47,930		46,704
Total operating expenses		49,575			49,356			151,366		159,432
Income (loss) from operations		(3,364	)		(730	)		97,964		97,752
Other income and expense - net		1,333			1,238			5,969		2,860
Interest expense - net		10,632			10,672			31,738		30,048
Income (loss) before income taxes		(12,663	)		(10,164	)		72,195		70,564
Income tax expense (benefit)		(5,243	)		(3,431	)		29,119		26,848
Net income (loss)	$	(7,420	)	$	(6,733	)	$	43,076	$	43,716
Average common shares outstanding:
Basic		26,606			26,515			26,571		26,508
Diluted		26,606			26,515			26,641		26,608
Earnings (loss) per share of common stock:
Basic	$	(0.28	)	$	(0.25	)	$	1.62	$	1.65
Diluted	$	(0.28	)	$	(0.25	)	$	1.62	$	1.64
Dividends per share of common stock	$	0.415		$	0.395		$	1.245	$	1.185

See Notes to Consolidated Financial Statements

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets
(Unaudited)


	September 30,			September 30,			December 31,
Thousands	2010			2009			2009
Assets:
Current assets:
Cash and cash equivalents	$	2,501		$	13,736		$	8,432
Restricted cash		924			20,830			35,543
Accounts receivable		28,503			28,992			77,438
Accrued unbilled revenue		15,399			19,060			71,230
Allowance for uncollectible accounts		(1,736	)		(1,827	)		(3,125	)
Regulatory assets		83,545			60,306			29,954
Derivative assets		1,864			13,924			6,504
Inventories:
Gas		80,955			86,921			71,672
Materials and supplies		8,668			9,775			9,285
Income taxes receivable		6,762			28,837			-
Other current assets		11,282			11,014			21,302
Total current assets		238,667			291,568			328,235
Non-current assets:
Property, plant and equipment		2,528,703			2,299,507			2,362,734
Less accumulated depreciation		711,046			684,769			692,600
Total property, plant and equipment - net		1,817,657			1,614,738			1,670,134
Regulatory assets		339,786			296,814			316,536
Derivative assets		518			3,711			843
Other investments		68,851			64,841			67,365
Other non-current assets		15,898			18,173			16,139
Total non-current assets		2,242,710			1,998,277			2,071,017
Total assets	$	2,481,377		$	2,289,845		$	2,399,252

See Notes to Consolidated Financial Statements

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets
(Unaudited)


	September 30,			September 30,			December 31,
Thousands	2010			2009			2009
Capitalization and liabilities:
Capitalization:
Common stock - no par value; 100,000 shares authorized; 26,640, 26,517 and 26,533 shares outstanding at September 30, 2010 and 2009 and December 31, 2009, respectively	$	342,271		$	336,686		$	337,361
Retained earnings		338,725			308,282			328,712
Accumulated other comprehensive income (loss)		(5,675	)		(4,094	)		(5,968	)
Total stockholders' equity		675,321			640,874			660,105
Long-term debt		591,700			637,000			601,700
Total capitalization		1,267,021			1,277,874			1,261,805

Current liabilities:
Short-term debt		159,875			71,890			102,000
Current maturities of long-term debt		45,000			-			35,000
Accounts payable		79,629			61,757			123,729
Taxes accrued		10,601			11,353			21,037
Interest accrued		12,220			12,287			5,435
Regulatory liabilities		31,502			57,096			46,628
Derivative liabilities		59,898			39,428			19,643
Other current liabilities		28,074			28,891			39,097
Total current liabilities		426,799			282,702			392,569

Deferred credits and other liabilities:
Deferred tax liabilities		324,166			301,336			300,898
Regulatory liabilities		252,425			244,315			248,622
Pension and other postretirement benefit liabilities		121,686			119,011			127,687
Derivative liabilities		27,211			1,660			3,193
Other non-current liabilities		62,069			62,947			64,478
Total deferred credits and other liabilities		787,557			729,269			744,878
Commitments and contingencies (see Note 11)		-			-			-
Total capitalization and liabilities	$	2,481,377		$	2,289,845		$	2,399,252

See Notes to Consolidated Financial Statements

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statement of Cash Flows
(Unaudited)

	Nine Months Ended
	September 30,
Thousands	2010			2009
Operating activities:
Net income	$	43,076		$	43,716
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		47,930			46,704
Undistributed earnings from equity investments		(576	)		(927	)
Non-cash expenses related to qualified defined benefit pension plans		5,758			7,359
Contributions to qualified defined benefit pension plans		(10,000	)		(25,000	)
Deferred environmental costs		(5,153	)		(8,053	)
Settlement of interest rate hedge		-			(10,096	)
Other		(1,863	)		(2,666	)
Changes in assets and liabilities:
Receivables		103,377			136,057
Inventories		(8,666	)		(629	)
Income taxes receivable		(6,762	)		(8,026	)
Accounts payable		(39,985	)		(43,374	)
Accrued interest		6,785			9,502
Accrued taxes		(10,436	)		(1,102	)
Deferred gas savings - net		(22,582	)		28,210
Deferred tax liabilities		23,993			37,523
Other - net		(10,372	)		(9,873	)
Cash provided by operating activities		114,524			199,325
Investing activities:
Capital expenditures		(185,651	)		(85,223	)
Restricted cash		34,619			(15,811	)
Other		953			4,502
Cash used in investing activities		(150,079	)		(96,532	)
Financing activities:
Common stock issued - net		4,129			(478	)
Long-term debt issued		-			125,000
Change in short-term debt		57,875			(188,961	)
Cash dividend payments on common stock		(33,063	)		(31,410	)
Other		683			(124	)
Cash provided by (used in) financing activities		29,624			(95,973	)
Increase (decrease) in cash and cash equivalents		(5,931	)		6,820
Cash and cash equivalents - beginning of period		8,432			6,916
Cash and cash equivalents - end of period	$	2,501		$	13,736

Supplemental disclosure of cash flow information:
Interest paid	$	23,796		$	19,651
Income taxes paid	$	21,100		$	7,500

See Notes to Consolidated Financial Statements

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Notes to Consolidated Financial Statements

(Unaudited)

1.	Summary of Significant Accounting Policies

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 (Financial Corporation). 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 by the equity method or the cost method, which includes NWN Enery'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 all of our other business activities including our gas storage businesses and other investments (see Note 2).

The information presented in the interim consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that management considers necessary for a fair statement of the results for each period reported. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2009 Annual Report on Form 10-K (2009 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 1 of the 2009 Form 10-K. There were no material changes to those accounting policies during the nine months ended September 30, 2010. See below for a further discussion of newly adopted standards and recent accounting pronouncements. We do not have any subsequent events to report.

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

Table of Contents

Industry Regulation

At September 30, 2010 and 2009 and at December 31, 2009, the amounts deferred as regulatory assets and liabilities were as follows:

	Current
	September 30,		September 30,		December 31,
Thousands	2010		2009		2009
Regulatory assets:
Unrealized loss on non-trading derivatives(1)	$	59,898	$	39,428	$	19,643
Pension and other postretirement benefit obligations(2)		7,502		8,074		7,502
Other(3)		16,145		12,804		2,809
Total regulatory assets	$	83,545	$	60,306	$	29,954
Regulatory liabilities:
Gas costs payable	$	20,487	$	32,823	$	37,055
Unrealized gain on non-trading derivatives(1)		1,864		13,924		6,504
Other(3)		9,151		10,349		3,069
Total regulatory liabilities	$	31,502	$	57,096	$	46,628

	Non-Current
	September 30,		September 30,		December 31,
Thousands		2010		2009		2009
Regulatory assets:
Unrealized loss on non-trading derivatives(1)	$	27,211	$	1,660	$	3,193
Income tax asset		75,515		75,931		76,240
Pension and other postretirement benefit obligations(2)		104,327		107,815		109,932
Environmental costs - paid(4)		54,966		44,188		46,204
Environmental costs - accrued but not yet paid(4)		56,965		55,623		59,844
Other(3)		20,802		11,597		21,123
Total regulatory assets	$	339,786	$	296,814	$	316,536
Regulatory liabilities:
Gas costs payable	$	900	$	2,539	$	6,915
Unrealized gain on non-trading derivatives(1)		518		3,711		843
Accrued asset removal costs		248,920		235,891		238,757
Other(3)		2,087		2,174		2,107
Total regulatory liabilities	$	252,425	$	244,315	$	248,622

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

(2)	Certain qualified pension plan and other postretirement benefit obligations are approved for regulatory deferral. Such amounts are recoverable in rates, including an interest component, when recognized in net periodic benefit cost (see Note 6).

(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 those sites that are approved for regulatory deferral. We earn the authorized rate of return as a carrying charge on amounts paid, whereas the amounts accrued but not yet paid do not earn a rate of return or a carrying charge until expended.

Table of Contents

New Accounting Standards

Adopted Standards

Variable Interest Entity. Effective January 1, 2010, we adopted the amended authoritative guidance on variable interest entities (VIE). This guidance requires a continuing analysis to determine whether an entity has a controlling financial interest and whether it is the primary beneficiary. The primary beneficiary with a controlling financial interest would be required to consolidate the VIE in its financial statements. The guidance defines the primary beneficiary as the entity having:

·	the power to control the activities that most significantly impact performance; and

·	the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE.

Although we do have an ownership interest in PGH, which is a VIE, we are not the primary beneficiary (see Note 8) and therefore the adoption of this standard has not had a material effect on our financial condition, results of operations or cash flows; however, if we are required to consolidate PGH or other VIEs that may be acquired in future periods, it could have a material impact on our financial statements (see Note 8).

Recent Accounting Pronouncements

Fair Value Disclosures. In January 2010, the Financial Accounting Standards Board 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, including a rollforward schedule. These changes are effective for periods beginning after December 15, 2010; however, we elected to early adopt these disclosure requirements, as shown in Note 7 of our 2009 Form 10-K. The adoption of this standard did not have, and is not expected to have, a material effect on our financial statement disclosures.

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 the payment of estimated stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Diluted earnings per share are calculated as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands, except per share amounts	2010			2009			2010		2009
Net income (loss)	$	(7,420	)	$	(6,733	)	$	43,076	$	43,716
Average common shares outstanding - basic		26,606			26,515			26,571		26,508
Additional shares for stock-based compensation plans		-			-			70		100
Average common shares outstanding - diluted		26,606			26,515			26,641		26,608
Earnings (loss) per share of common stock - basic	$	(0.28	)	$	(0.25	)	$	1.62	$	1.65
Earnings (loss) per share of common stock - diluted	$	(0.28	)	$	(0.25	)	$	1.62	$	1.64

Table of Contents

For the three months ended September 30, 2010 and 2009, 76,088 and 111,094 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, 2010 and 2009, 427 and 3,601 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.

2.	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 Gill Ranch, parts of NWN Energy and its wholly-owned subsidiary NWN Gas Storage, and the non-utility portion of gas storage services related to our Mist underground storage facility in Oregon. Our “other” segment includes Financial Corporation, parts of NWN Energy, including an equity investment in PGH, which is developing a proposed natural gas transmission pipeline through its wholly-owned subsidiary Palomar Gas Transmission, LLC (Palomar). For further discussion of our segments, see Note 2 in our 2009 Form 10-K.

NWN Gas Storage was formed to manage our gas storage operations, including Gill Ranch. NWN Gas Storage commenced operations during the second quarter of 2010 and was not operational during 2009.

Table of Contents

The following table presents information about the reportable segments for the three and nine months ended September 30, 2010 and 2009. Inter-segment transactions are insignificant.

	Three Months Ended September 30,
Thousands	Utility			Gas Storage		Other			Total
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	)
2009
Net operating revenues	$	43,617		$	4,977	$	32		$	48,626
Depreciation and amortization		15,484			333		-			15,817
Income (loss) from operations		(5,081	)		4,354		(3	)		(730	)
Net income (loss)		(9,163	)		2,255		175			(6,733	)

	Nine Months Ended September 30,
Thousands	Utility			Gas Storage		Other			Total
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 Sept. 30, 2010		2,192,557			266,022		22,798			2,481,377
2009
Net operating revenues	$	241,775		$	15,302	$	107		$	257,184
Depreciation and amortization		45,696			1,008		-			46,704
Income from operations		84,768			12,951		33			97,752
Net income		36,580			7,021		115			43,716
Total assets at Sept. 30, 2009		2,157,411			114,243		18,191			2,289,845
Total assets at Dec. 31, 2009		2,205,313			173,648		20,291			2,399,252

3.	Capital Stock

As of September 30, 2010, our common shares authorized were 100,000,000 and our outstanding shares were 26,640,453.

We have a share repurchase program for our common stock under which we may purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 31, 2011 to repurchase up to an aggregate of 2.8 million shares or up to $100 million. No shares of common stock were repurchased under this program during the nine months ended September 30, 2010. To date, a total of 2.1 million shares have been repurchased at a total cost of $83.3 million under the existing share repurchase program.

Table of Contents

4.	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 4, in the 2009 Form 10-K and current updates provided below.

Long-Term Incentive Plan. On February 24, 2010, 41,500 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 $25.64 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	$	44.25
Performance term (in years)		3.0
Quarterly dividends paid per share	$	0.415
Expected dividend yield		3.7	%
Dividend discount factor		0.8949

In February 2010, the Board approved a payout of performance-based stock awards for the 2007-09 award period. Shares of common stock were purchased on the open market to satisfy the approved awards.

Restated Stock Option Plan. On February 24, 2010, options to purchase 119,750 shares were granted under the Restated SOP, with an exercise price equal to the closing market price of $44.25 per share on the date of grant, vesting over a four-year period following the date of grant and with a term of 10 years and 7 days. The weighted-average grant date fair value was $6.36 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	2.3	%
Expected life (in years)	4.7
Expected market price volatility factor	23.2	%
Expected dividend yield	3.8	%
Forfeiture rate	3.2	%

As of September 30, 2010, there was $1.0 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards expected to be recognized over a period extending through 2013.

Table of Contents

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

Cost of Long-Term Debt

Our long-term debt consists of medium-term notes (MTNs) that have maturity dates from 2010 through 2035, and have interest rates ranging from 3.95 percent to 9.05 percent with a weighted-average coupon rate of 6.19 percent (see Note 5 in our 2009 Form 10-K). For the nine months ended September 30, 2010 we did not issue or redeem any MTNs. In March 2009, we issued $75 million of 5.37 percent secured MTNs due February 1, 2020, and in July 2009, we issued another $50 million of secured MTNs with an interest rate of 3.95 percent and a maturity of July 15, 2014. Proceeds from these MTNs were used to fund utility capital expenditures, to redeem utility short-term and long-term debt, and to provide utility working capital for general corporate purposes.

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 for outstanding debt issues that actively trade and have similar credit ratings, terms and remaining maturities to estimate fair value for our long-term debt issues.

	September 30,				December 31,
Thousands	2010		2009		2009
Carrying amount	$	636,700	$	637,000	$	636,700
Estimated fair value	$	740,731	$	670,116	$	707,755

Table of Contents

6.	Pension and Other Postretirement Benefits

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	2010			2009			2010			2009
Service cost	$	1,435		$	1,472		$	156		$	147
Interest cost		4,517			4,474			343			405
Expected return on plan assets		(4,528	)		(3,783	)		-			-
Amortization of loss		2,028			1,786			7			5
Amortization of prior service cost		(270	)		307			50			50
Amortization of transition obligation		-			-			103			103
Net periodic benefit cost		3,182			4,256			659			710
Amount allocated to construction		(897	)		(1,220	)		(231	)		(233	)
Net amount charged to expense	$	2,285		$	3,036		$	428		$	477

	Nine Months Ended September 30,
							Other Postretirement
	Pension Benefits						Benefits
Thousands		2010			2009			2010			2009
Service cost	$	4,981		$	4,799		$	468		$	442
Interest cost		13,500			13,458			1,028			1,218
Expected return on plan assets		(13,655	)		(11,772	)		-			-
Amortization of loss		5,564			5,103			22			13
Amortization of prior service cost		140			918			148			148
Amortization of transition obligation		-			-			309			309
Net periodic benefit cost		10,530			12,506			1,975			2,130
Amount allocated to construction		(2,797	)		(3,576	)		(646	)		(697	)
Net amount charged to expense	$	7,733		$	8,930		$	1,329		$	1,433

See Part II, Item 8., Note 7, in the 2009 Form 10-K for more information about our pension and other postretirement benefit plans.

In addition to the company-sponsored defined benefit plans referred to above, we contribute to a multiemployer pension plan for our bargaining unit employees in accordance with our collective bargaining agreement, known as the Western States Office and Professional Employees International Union Pension Fund (Western States Plan). 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. As of January 1, 2010, the Western States Plan had an accumulated funding deficiency for the current plan year and remained 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. We made contributions totaling $0.3 million to the Western States Plan for both the nine months ended September 30, 2010 and 2009. The Western States Plan board of trustees imposed a 5 percent contribution surcharge to participating employers, including NW Natural, beginning in August 2009, which increased to a 10 percent contribution surcharge beginning January 2010. The board of trustees also 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. Contribution surcharges above 10 percent 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. We have no current intent to withdraw from the plan, so we have not recorded a withdrawal liability.

Table of Contents

Employer Pension Contributions

In February 2010, we made a $10 million cash contribution to our qualified defined benefit pension plans, portions of which were for the 2009 and 2010 plan years, and additional contributions are expected for future years. We also continue to make cash contributions for our unfunded, non-qualified pension plans and other postretirement benefit plans. For more information see Part II, Item 8., Note 7, in the 2009 Form 10-K.

7. Income Tax

The effective income tax rate for the nine months ended September 30, 2010 and 2009 varied from the combined federal and state statutory tax rates principally due to the following:

	September 30,
	2010			2009
Federal statutory tax rate		35.0	%		35.0	%
Increase (decrease):
Current state statutory income tax rate, net of federal tax benefit		4.8	%		4.5	%
Amortization of investment and energy tax credits		(0.4	) %		(0.4	) %
Differences required to be flowed-through by regulatory commissions		1.2	%		(0.1	) %
Gains on company and trust-owned life insurance		(0.8	) %		(1.4	) %
Other - net		0.5	%		0.4	%
Effective tax rate		40.3	%		38.0	%

The increase in our effective tax rate for the nine months ended September 30, 2010 compared to the same period in 2009 was primarily due to an increase in the amortization rate of our regulatory tax asset pursuant to a regulatory order effective November 1, 2009, which we recover in utility rates.

Table of Contents

8.	Property and Investments

Property

Property, plant and equipment – net consists of the following as of September 30, 2010 and 2009 and December 31, 2009:

	September 30,				December 31,
Thousands	2010		2009		2009
Utility plant in service	$	2,222,222	$	2,175,043	$	2,188,176
Utility construction work in progress		33,359		22,490		27,936
Less accumulated depreciation		700,193		674,575		682,060
Utility plant - net		1,555,388		1,522,958		1,534,052
Non-utility plant in service		66,299		66,016		66,084
Non-utility construction work in progress		206,823		35,958		80,538
Less accumulated depreciation		10,853		10,194		10,540
Non-utility plant - net		262,269		91,780		136,082
Total property, plant and equipment - net	$	1,817,657	$	1,614,738	$	1,670,134

Investments

Our other long-term 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 Note 1 above for the newly adopted standard on variable interest entities, and see Part II, Item 8., Note 9, in the 2009 Form 10-K for more detail on our investments).

Variable Interest Entities. PGH is a VIE owned 50 percent by us and 50 percent by Gas Transmission Northwest Corporation, an indirect wholly-owned subsidiary of TransCanada Corporation. PGH intends to develop a natural gas transmission pipeline in Oregon to serve our utility as well as the growing natural gas markets in Oregon and other parts of the Pacific Northwest, through its wholly-owned subsidiary Palomar. Palomar is a development stage entity. As of September 30, 2010, 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 (see Note 1). Therefore, we account for our investment in PGH and the Palomar project under the equity method, and our equity investment balance at September 30, 2010 and 2009 was $14.7 million and $12.4 million, respectively, which is included in other investments on our balance sheet. The increase in our equity investment balance over the last 12 months is due to $1.2 million of equity contributions plus $1.1 million for our share of income allocation based on our 50 percent ownership interest. 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.

PGH Impairment Analysis. In May 2010, we learned that the company proposing to build an LNG terminal on the Columbia River had suspended its operations and filed for bankruptcy. This company previously entered into a precedent agreement with Palomar for a majority of the transmission capacity on the proposed pipeline. As of September 30, 2010, Palomar had incurred a total of $45.2 million of capital costs, including AFUDC (allowance for funds used during construction), toward the development of the pipeline (both east and west segments), and it had collected $15.8 million from a letter of credit which supported the bankrupt shipper’s obligations under a prior precedent agreement. In addition, Palomar holds credit support in the form of a lien on assets of the bankrupt shipper under terms of the current precedent agreement.

Table of Contents

Our equity investment balance in PGH as of September 30, 2010 was $14.7 million. We performed an impairment analysis of our total equity investment as of September 30, 2010 and determined that no impairment write-down is needed because the value of the expected development of this pipeline will exceed our total equity investment. If, however, we learn that the project is not viable, we could be required to recognize an impairment loss of up to $14.1 million based on the amount of our equity investment as of September 30, 2010 net of cash and working capital at Palomar. We will continue to monitor and update our impairment analysis as needed.

9.	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 $5.7 million and $4.1 million as of September 30, 2010 and 2009, respectively, which is related to employee benefit plan liabilities. The following table provides a reconciliation of net income to total comprehensive income for the three and nine months ended September 30, 2010 and 2009.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands	2010			2009			2010		2009
Net income (loss)	$	(7,420	)	$	(6,733	)	$	43,076	$	43,716
Amortization of employee benefit plan liability, net of tax		97			166			293		292
Total comprehensive income (loss)	$	(7,323	)	$	(6,567	)	$	43,369	$	44,008

10.	Derivative Instruments

We enter into swap, option and combinations of option contracts for the purpose of hedging natural gas and the forecasted issuance of fixed-rate debt which qualify as derivative instruments under accounting rules for derivative instruments and hedging activities. We primarily use these derivative financial instruments to manage commodity prices related to our natural gas purchase requirements and to manage interest rate risk exposure related to our long-term debt issuances.

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 the physical gas supply contracts. Derivatives entered into prudently for future gas years prior to our annual Purchased Gas Adjustment (PGA) filing receive regulatory deferred accounting treatment. Derivative contracts entered into after the annual PGA rate was set on November 1, 2009 that are for the current gas contract year are subject to our PGA incentive sharing mechanism, which provides for 90 percent of the changes in fair value to be deferred as regulatory assets or liabilities and the remaining 10 percent to be recorded to the income statement for contracts not qualifying for cash flow hedge accounting and to other comprehensive income for contracts qualifying for cash flow hedge accounting.

Most of our commodity hedging for the upcoming gas contract year is completed prior to the start of each gas year, and these hedge prices are included in our annual PGA filing. We typically hedge approximately 75 percent of our anticipated year-round sales volumes based on normal weather. We entered the 2009-10 gas contract year (November 1, 2009 – October 31, 2010) hedged at a targeted level of 75 percent, including 60 percent financially hedged and 15 percent physically hedged through gas storage volumes. Our policy allows us to hedge price risk for up to 100 percent of our gas supplies for the next gas year and up to 50 percent for the following gas contract year.

At September 30, 2010, we were hedged with financial contracts for the upcoming gas contract year at approximately 77 percent based on anticipated sales volumes. At September 30, 2010, we were also hedged with financial contracts for the 2011-12 gas contract year between 20 and 25 percent, and for the 2012-13 gas contract year between 5 and 10 percent.

Table of Contents

The following table discloses the balance sheet presentation of our derivative instruments as of September 30, 2010 and 2009 and December 31, 2009:

			Fair Value of Derivative Instruments
			September 30, 2010				September 30, 2009				December 31, 2009
Thousands			Current		Non-Current		Current		Non-Current		Current		Non-Current
Assets:(1)
	Natural gas commodity	$	1,754	$	518	$	13,924	$	3,711	$	6,214	$	843
	Foreign exchange		110		-		-		-		290		-
Total		$	1,864	$	518	$	13,924	$	3,711	$	6,504	$	843
Liabilities:(2)
	Natural gas commodity	$	59,898	$	27,211	$	39,087	$	1,660	$	19,643	$	3,193
	Foreign exchange		-		-		341		-		-		-
Total		$	59,898	$	27,211	$	39,428	$	1,660	$	19,643	$	3,193

(1)	Unrealized fair value gains are classified under current- or non-current assets as derivative assets.
(2)	Unrealized fair value losses are classified under current- or non-current liabilities as derivative liabilities.

Table of Contents

The following table discloses the income statement presentation for the unrealized gains and losses from our derivative instruments for the three and nine months ended September 30, 2010 and 2009. 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, 2010						September 30, 2009
Thousands		Natural gas commodity(1)			Foreign exchange (2)			Natural gas commodity(1)			Foreign exchange (2)
Cost of sales		$	(35,744	)	$	-		$	50,149		$	-
Other comprehensive income			-			449			-			(288	)
Less:
Amounts deferred to regulatory accounts on balance sheet			35,744			(449	)		(50,149	)		288
	Total impact on earnings	$	-		$	-		$	-		$	-

		Nine Months Ended
		September 30, 2010						September 30, 2009
Thousands		Natural gas commodity(1)			Foreign exchange (2)			Natural gas commodity(1)			Foreign exchange (2)
Cost of sales		$	(84,837	)	$	-		$	(23,112	)	$	-
Other comprehensive income			-			110			-			(341	)
Less:
Amounts deferred to regulatory accounts on balance sheet			84,837			(110	)		23,112			341
	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 exchange forward purchase contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet.

Table of Contents

Our derivative liabilities exclude the netting of collateral. We had no collateral posted with our counterparties as of September 30, 2010 or 2009. We attempt to minimize the potential exposure to collateral calls by our counterparties to manage our liquidity risk. Based on our current credit ratings, most counterparties allow us credit limits ranging from $15 million to $25 million before collateral postings are required. Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We also could 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 $86.2 million at September 30, 2010, we have estimated the projected 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	$	-	$	3,745	$	8,745	$	14,695	$	42,345
Without Adequate Assurance Calls	$	-	$	3,745	$	8,745	$	14,695	$	42,345

In the three and nine months ended September 30, 2010, we realized net losses of $12.6 million and $33.3 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 $29.1 million and $150.8 million, respectively, for the three and nine months ended September 30, 2009. The currency exchange rate in all foreign currency forward purchase contracts is included in our purchased cost of gas at settlement; therefore, no gain or loss is recorded from the settlement of those contracts. We settled our $50 million interest rate swap in March 2009, concurrent with our issuance of the underlying long-term debt, and realized a $10.1 million effective hedge loss which is being amortized to interest expense over the term of the debt.

We are exposed to derivative credit risk primarily through securing pay-fixed natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases on behalf of customers. We utilize master netting arrangements through International Swaps and Derivatives Association contracts to minimize this risk along with collateral support agreements with counterparties based on their credit ratings. In certain cases we require guarantees or letters of credit from counterparties in order for them to meet our minimum credit requirement standards.

Our financial derivatives policy requires counterparties to have a certain investment-grade credit rating at the time the derivative instrument is entered into, and the policy specifies limits on the contract amount and duration based on each counterparty’s credit rating. We do not speculate on derivatives; instead we utilize derivatives to hedge our exposure above risk tolerance limits. Any increase in market risk created by the use of derivatives should be offset by the exposures they modify.

We actively monitor our derivative credit exposure and place counterparties on hold for trading purposes or require other forms of credit assurance, such as letters of credit, cash collateral or guarantees as circumstances warrant. Our ongoing assessment of counterparty credit risk includes consideration of credit ratings, credit default swap spreads, bond market credit spreads, financial condition, government actions and market news. We utilize a Monte-Carlo simulation model to estimate the change in credit and liquidity risk from the volatility of natural gas prices. We use the results of the model to establish earnings at-risk trading limits. Our credit risk for all outstanding derivatives at September 30, 2010 currently does not extend beyond October 2013.

We could become materially exposed to credit risk with one or more of our counterparties if natural gas prices experience a significant increase. If a counterparty were to become insolvent or fail to perform on its obligations, we could suffer a material loss, but we would expect such loss to be eligible for regulatory deferral and rate recovery, subject to prudency review. All of our existing counterparties currently have investment-grade credit ratings.

Table of Contents

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, 2010. We also did not have any transfers between level 1 or level 2 during the nine months ended September 30, 2010 and 2009 (see Part II, Item 8., Note 1 in the 2009 Form 10-K for further explanation of the fair value hierarchy).

The following table provides the fair value hierarchy of our derivative assets and liabilities as of the nine months ended September 30, 2010 and 2009 and December 31, 2009:

		September 30,						December 31,
Thousands	Description of Derivative Inputs	2010			2009			2009
Level 1	Quoted prices in active markets	$	-		$	-		$	-
Level 2	Significant other observable inputs		(84,727	)		(23,453	)		(15,489	)
Level 3	Significant unobservable inputs		-			-			-
		$	(84,727	)	$	(23,453	)	$	(15,489	)

11.	Commitments and Contingencies

Environmental Matters

We own, or have 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 environmental site investigations, the range of potential loss beyond the amounts currently accrued, and the probabilities thereof, cannot currently be reasonably estimated. See Part II, Item 8., Note 11, in the 2009 Form 10-K.

The status of each site 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 (the 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 and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. In May 2007, we completed a revised Upland Remediation Investigation Report and submitted it to the ODEQ for review. In November 2007, we submitted a Focused Feasibility Study (FFS) for groundwater source control, ODEQ conditionally approved the FFS in March 2008, subject to the submission of additional information. We provided that information to ODEQ and are working with the agency on the final design for the system. During the third quarter of 2009, we signed a joint Order on Consent with the Environmental Protection Agency (EPA) which requires the design of a final remedial action for the Gasco sediments. The design project is underway. We have a liability accrued of $51.3 million at September 30, 2010 for the Gasco site, which is estimated 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.

Table of Contents

In April 2004, we entered into an Administrative Order on Consent providing for early action removal of a deposit of tar in the river sediments adjacent to the Gasco site (see "Portland Harbor site," below). We completed this removal of the tar deposit in the Portland Harbor in October 2005, and on November 5, 2005 the EPA approved the completed project. The total cost of removal, including technical work, oversight, consultant fees, legal fees and ongoing monitoring, was about $9.9 million. To date, we have paid $9.6 million on work related to the removal of the tar deposit. As of September 30, 2010, we have a liability accrued of $0.3 million under the Portland Harbor site for our estimate of ongoing costs related to this tar deposit removal.

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, 2010 for the Siltronic site is $1 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.

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, referred to as the 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), completion of which is scheduled for 2011. The EPA and the Lower Willamette Group are conducting focused studies on approximately nine miles of the lower Willamette River, including the 5.5-mile segment previously studied by the EPA. 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, additional information is necessary to estimate further liabilities sufficient to support an early restoration-based settlement of natural resource damage claims. As of September 30, 2010, we have a liability accrued of $8 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 (the 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 with the ODEQ’s Independent Cleanup Pathway. As of September 30, 2010, 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 those initial studies were completed. In 2010, ODEQ required work plans for additional studies which were submitted and are undergoing review and approval by DEQ. As of September 30, 2010, we have an estimated liability accrued of $1.1 million for the study of the site, which will include investigation of sediments, upland riverbank groundwater and soils, and reporting of historical upland activities. 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.

Table of Contents

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, 2010 and 2009 and December 31, 2009:

	Current Liabilities						Non-Current Liabilities
	Sept. 30,		Sept. 30,		Dec. 31,		Sept. 30,		Sept. 30,		Dec. 31,
Thousands	2010		2009		2009		2010		2009		2009
Gasco site	$	7,738	$	8,729	$	9,841	$	43,597	$	42,295	$	43,659
Siltronic site		746		708		653		275		393		593
Portland Harbor site		2,712		-		2,114		5,594		7,820		7,272
Central Service Center site		5		-		5		510		517		511
Front Street site		72		419		72		1,039		-		436
Other sites		-		-		-		110		177		123
Total	$	11,273	$	9,856	$	12,685	$	51,125	$	51,202	$	52,594

Regulatory and Insurance Recovery for Environmental Costs. In May 2003, the Oregon Public Utility Commission (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 2011.

On a cumulative basis, we have recognized a total of $104.0 million for environmental costs, including legal, investigation, monitoring and remediation costs, including $4.9 million accrued and paid prior to regulatory deferral order approval. At September 30, 2010, we had a regulatory asset of $111.9 million, which includes $42.2 million of total paid expenditures to date, $57 million for additional environmental costs expected to be paid in the future and accrued interest of $12.7 million. While we believe recovery of these deferred charges is probable through the regulatory process, we intend to pursue recovery from insurance carriers under our general liability insurance policies prior to seeking recovery through rates. Our regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We consider insurance recovery of most of our environmental costs to date probable based on a combination of factors including: a review of the terms of our insurance policies; the financial condition of the insurance companies providing coverage; a review of successful claims filed by other utilities with similar gas manufacturing facilities; and Oregon law that allows an insured party to seek recovery of “all sums” from one insurance company. We have initiated settlement discussions with a majority of our insurers. In the event that settlements cannot be reached, we intend to pursue other legal remedies. We continue to anticipate that our overall insurance recovery effort will extend over several years.

Table of Contents

We anticipate that our regulatory recovery of environmental cost deferrals will not be initiated within the next 12 months because we do not expect to have completed our insurance recovery efforts during that time period. As such we have classified our regulatory assets for environmental cost deferrals as non-current. The following table summarizes the non-current regulatory assets relating to environmental sites at September 30, 2010 and 2009 and December 31, 2009:

	Non-Current Regulatory Assets
	September 30,		September 30,		December 31,
Thousands	2010		2009		2009
Gasco site	$	72,531	$	66,105	$	69,607
Siltronic site		3,120		2,750		2,974
Portland Harbor site		33,316		29,239		31,500
Central Service Center site		551		548		550
Front Street site		2,000		700		910
Other sites		413		469		507
Total	$	111,931	$	99,811	$	106,048

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.

Oregon Steel Mills site. In 2004, NW Natural was served with a third-party complaint by the Port of Portland (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 and discovery is ongoing. 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.

Table of Contents

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

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. This discussion refers to our consolidated activities for the three and nine months ended September 30, 2010 and 2009. Unless otherwise indicated, references in this discussion to “Notes” are to the Notes to Consolidated Financial Statements in this report. This discussion should be read in conjunction with our 2009 Annual Report on Form 10-K (2009 Form 10-K).

The consolidated financial statements include the accounts of NW Natural and its direct and indirect wholly-owned subsidiaries: Gill Ranch Storage, LLC (Gill Ranch), NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), and NNG Financial Corporation (Financial Corporation), and an equity investment in Palomar Gas Holdings, LLC (PGH), which is developing a proposed natural gas pipeline through its wholly-owned subsidiary Palomar Gas Transmission LLC (Palomar). These accounts include our regulated local gas distribution business, our gas storage business, and other regulated and non-regulated investments primarily in energy-related businesses. In this report, the term “utility” is used to describe our regulated local gas distribution segment, and the term “non-utility” is used to describe our gas storage segment (gas storage) as well as our other regulated and non-regulated investments and business activities (other segment) (see “Strategic Opportunities,” below, and Note 2).

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 earnings. All references in this section to earnings per share are on the basis of diluted shares (see Part II, Item 8., Note 1, “Earnings Per Share,” in our 2009 Form 10-K). We also believe that showing operating revenues and margins excluding the refund of gas cost savings on customer bills in June 2009 facilitates more meaningful comparisons between 2009 and 2010. We use such non-GAAP (i.e. non generally accepted accounting principle) financial measures in analyzing our results of operations and believe that they provide useful information to our investors and creditors in evaluating our financial condition.

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

Executive Summary

Results for the third quarter of 2010 include:

·	Consolidated earnings decreased $0.7 million, from a net loss of $6.7 million in the third quarter of 2009 to a net loss of $7.4 million in the third quarter of 2010;

·	Results from utility operations increased $0.1 million, from a net loss of $9.2 million in 2009 to a net loss of $9.1 million in 2010;

·	Results from gas storage operations decreased $0.5 million, from net income of $2.3 million in 2009 to $1.8 million in 2010;

·	Consolidated net operating revenues (margin) decreased 5 percent, from $48.6 million in 2009 to $46.2 million in 2010, with utility margin down 5 percent or $2.4 million and gas storage margin down 1 percent or $0.1 million;

·	Cash flow from operations decreased 43 percent, from $199.3 million in 2009 to $114.5 million in 2010;

·	Utility customer growth rate was slightly above 1 percent over the last 12 months; and

·	The Board approved a quarterly dividend increase of 2 cents per share, or 5 percent, to 43.5 cents a share payable on November 15, 2010 to shareholders of record on October 29, 2010.

Table of Contents

Issues, Challenges and Performance Measures

Economic weakness. Ongoing weakness in local and U.S. economies has continued to impact customer growth and business demand for natural gas. Although these conditions may continue to have a negative impact on our financial results, we are beginning to see some signs the economy may be stabilizing. Most recently, our annual customer growth rate increased to 1.2 percent at September 30, 2010 compared to 1 percent at June 30, 2010 and 0.7 percent at September 30, 2009, and our bad debt expense decreased $2.6 million compared to last year on lower delinquent balances. Despite these improvements, we are still faced with 10 to 11 percent unemployment rates in Oregon and southwest Washington and a sluggish business environment. Regardless of these challenges, we believe we are well positioned to continue adding distribution customers due to our relatively low market penetration, our efforts to convert homes to natural gas, and the potential for environmental initiatives that could favor natural gas use in our region. Current weak economic conditions also continue to negatively affect demand for gas storage services.

Managing gas prices and supplies. Our gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage. With recent success in new drilling technologies and substantial new supplies from shale gas formations around the U.S. and in Canada, the supply of North American natural gas has increased dramatically, which has contributed to lower gas prices. We entered the 2009-10 gas contract year with commodity prices hedged for 75 percent of our estimated gas purchase volumes. For the 2010-11 gas contract year, which began November 1, 2010, we are currently hedged on gas commodity prices for approximately 77 percent of our forecasted purchase volumes, in addition to being hedged between 20 and 25 percent for the 2011-12 gas contract year and between 5 and 10 percent for the 2012-13 gas contract year. Our Purchased Gas Adjustment (PGA) mechanism, along with gas price hedging strategies and gas supplies in storage, enable us to reduce earnings risk exposure and secure lower gas costs for customers. These lower gas prices, coupled with good customer service and energy efficiency programs for our customers, can help strengthen natural gas’ competitive price advantage compared to other fuels. In addition to hedging gas prices over the next three years, we are evaluating and developing other gas acquisition strategies to potentially manage gas price volatility for customers beyond three years. Although lower gas prices provide opportunities to manage costs for our distribution customers, they present challenges for our storage business by lowering the value of storage services and limiting Gill Ranch’s ability to contract for longer terms at favorable prices.

Environmental investigation and remediation costs. We accrue all 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 required to defer certain costs pursuant to regulatory decisions including environmental costs, and to seek recovery of these amounts in future rates to customers. However, before we seek recovery from customers, we are expected to pursue recovery from insurance policies. Ultimate recovery of environmental costs, either from regulated utility rates or from insurance, will depend on our ability to effectively manage costs and demonstrate that costs 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 Note 11 in this report and Note 11 in our 2009 Form 10-K.

Climate change. We recognize that our businesses will be impacted by future carbon constraints. The outcome of federal, state, local and international climate change initiatives cannot be determined at this time, but these initiatives could produce a number of results including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. While our CO2 equivalent emission levels are relatively small, the adoption and implementation of any regulations imposing reporting obligations, or limiting emissions of greenhouse gases associated with our operations, could result in an increase in the prices we charge our customers or a decline in the demand for natural gas. On the other hand, because natural gas has a relatively low carbon content, it is also possible that future carbon constraints could create additional demand for natural gas for electric production, direct use in homes and businesses and as a reliable and relatively low-emission back-up fuel source for alternative energy sources.

Table of Contents

Strategies and 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 core gas distribution business; growing our non-utility gas storage business; investing in new natural gas infrastructure in the region; and maintaining a leadership role within the gas utility industry by addressing long-term energy policies and pursuing business opportunities that support new clean energy technologies. We intend to measure our performance and monitor progress of certain metrics including, but not limited to: earnings per share growth; total shareholder return; return on invested capital; utility return on equity; utility customer satisfaction ratings; 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 integrate, consolidate and streamline operations and support our employees with new technology tools.

In 2009, we announced a voluntary severance program to reduce staffing levels in response to work load declines related to the current low customer growth environment and efficiency improvements. Severance programs and normal attrition resulted in reductions of full-time positions from 1,133 at December 31, 2008 to slightly over 1,000 during 2010, and the savings are reflected in decreases in operation and maintenance costs and utility capital expenditures.

Technology investments, workforce reductions and other initiatives implemented over the last couple years are expected to contribute to long-term operational efficiencies and reduce operating and capital costs throughout NW Natural.

Gas Storage Development. We have a joint project agreement with Pacific Gas & Electric Company (PG&E) to develop, own and operate an underground natural gas storage facility near Fresno, California. Our undivided ownership interest in the project is held by our wholly-owned subsidiary, Gill Ranch. The construction of this facility began in January 2010, and a majority of the construction work was completed by October. Our share of total construction costs is currently estimated to be between $210 million and $220 million. Our share represents 75 percent of the total cost of the initial development, which is designed to be 20 Bcf of gas storage capacity and approximately 27 miles of gas transmission pipeline.

Gill Ranch started storage injections and limited commercial operations in October 2010. Gill Ranch is offering storage services at market based rates, subject to CPUC regulation including, but not limited to, service terms and conditions, tariff regulations, and security issuances. Due to increasing supplies of natural gas in North America and declining demand due to economic conditions, current storage values are expected to remain low in the near term, which may affect Gill Ranch’s ability to contract longer term at favorable prices and may negatively impact earnings and cash flows.

The Oregon gas markets have also been negatively impacted by lower gas prices, although less so than in California. We continue to make plans for expanding our interstate storage facilities at Mist, Oregon. To complete the studies necessary for development of the next storage project at Mist, we have delayed the timeline for construction but continue to move forward with planning. We believe the earliest timeframe for moving forward with construction is 2011 or 2012, but we have not committed to a targeted construction schedule or in-service date at this time. We continue to work on design and project scope, which we expect will include the development of storage wells, a second compression station and a pipeline gathering system that will also enable future storage expansions, as well as updates to our construction cost estimates.

Table of Contents

Pipeline Diversification. Currently our utility and gas storage at Mist depends on a single bi-directional interstate pipeline to ship gas supplies. Palomar, a wholly-owned subsidiary of PGH, seeks to build a new gas transmission pipeline that would provide an interconnection with our utility distribution system. PGH is owned 50 percent by us and 50 percent by Gas Transmission Northwest Corporation (GTN), an indirect wholly-owned subsidiary of TransCanada Corporation. The proposed Palomar pipeline is designed to serve our utility and 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 May 2010, we learned that the company proposing to build an LNG terminal on the Columbia River, had suspended its operations and filed for bankruptcy. This company had previously entered into a binding precedent agreement with Palomar for a majority of the proposed pipeline’s capacity. In September 2010, the bankruptcy court issued an order rejecting that precedent agreement. Palomar is now pursuing its right to foreclose on its security interest in the bankrupt company’s assets. In addition, Palomar currently has a non-binding memorandum of understanding with The Williams Companies' Northwest Pipeline (Northwest Pipeline) that contemplates Northwest Pipeline becoming a part owner in the project and which consolidates the region’s efforts to develop a cross-Cascades pipeline around the use of the Palomar route. Northwest Pipeline owns and operates the single, bi-directional pipeline that connects to NW Natural's distribution system.

As of September 30, 2010, Palomar had invested a total of $45.2 million of capital costs for the pipeline development, including AFUDC (allowance for funds used during construction). Palomar has recovered $15.8 million from a letter of credit which supported the bankrupt shipper’s obligations under its prior precedent agreement, and Palomar holds additional credit support in the form of a lien on assets of the bankrupt shipper under terms of the recently terminated precedent agreement. As noted above, we are pursuing our rights to foreclose on these assets.

As of September 30, 2010, our net equity investment in PGH, which in turn has been invested in Palomar, was $14.7 million. We continue to work with interested shippers and state regulatory commissions to address the aggregate gas infrastructure needs for the region.

In October 2010, Palomar executed an agreement with the Confederated Tribe of the Warm Springs Reservation that provides Tribal consent for the Bureau of Indian Affairs to issue a pipeline right-of-way grant across the Warm Springs Reservation. Adoption of this route alternative for the east segment will both shorten the pipeline length and reduce its environmental impact relative to the initially proposed route in Palomar’s FERC application.

Palomar continues to communicate with FERC regarding its regulatory application, which will need to be amended to reflect the outcome from the bankruptcy and project route change to reflect utilizing the Warm Springs Reservation right-of-way. Palomar is having discussions with prospective regional shippers to evaluate the level of commercial support for the east segment and to determine the timing of its construction. Palomar will continue to focus on permitting activities during 2010 and 2011, but the date for when the Palomar pipeline is expected to go into service will be impacted by the timing of our final FERC permit and the needs of shippers. See "Financial Condition—Cash Flows—Investing Activities," below for further discussion on the status of Palomar.

We believe the proposed pipeline’s east segment is still a viable project, and the Palomar project remains in a development stage. We performed an impairment analysis for our total equity investment as of September 30, 2010 and determined that no impairment write-down is needed (see Note 8).

Table of Contents

Consolidated Earnings and Dividends

Three months ended September 30, 2010 compared to September 30, 2009:

For the three months ended September 30, 2010, we had a net loss of $7.4 million, or 28 cents per share, compared to a net loss of $6.7 million, or 25 cents per share, for the same period last year.

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

·	a $3.2 million decrease in utility margin due to lower gas cost savings from our regulatory incentive sharing mechanism, from a $3.6 million gain in 2009 to a $0.4 million gain in 2010; and

·	a $0.5 million decrease in net income from gas storage operations primarily due to startup costs at Gill Ranch.

Partially offsetting the above factors were:

a $1.0 million increase in utility margin from residential and commercial customers, after decoupling mechanism adustments, from customer growth and recovery of higher income tax expense related to higher state income tax rates and the amortization of regulatory tax assets (see “Results of Operations—Consolidated Operating Expenses—Income Tax Expense,” below); and

·	a $0.2 million decrease in operation and maintenance expense primarily due to lower payroll expense, which reflects a reduced number of utility employees, and lower bad debt expense compared to last year, partially offset by higher subsidiary operating expenses.

Nine months ended September 30, 2010 compared to September 30, 2009:

Net income was $43.1 million, or $1.62 per share, for the nine months ended September 30, 2010, compared to $43.7 million, or $1.64 per share, for the same period last year.

The primary factors contributing to the $0.6 million decrease in net income were:

·	a $13.6 million decrease in utility margin due to lower gas cost savings from our regulatory incentive sharing mechanism, from $14.7 million in 2009 to $1.1 million in 2010; and

·	a $1.7 million increase in interest expense primarily reflecting higher balances of long-term debt outstanding.

Partially offsetting the above factors were:

a $5.5 million increase in utility margin from residential and commercial customers, after adjustments for weather and decoupling adjustments, primarily from colder weather effects from the second quarter of 2010 and the recovery of income tax expense related to higher state income tax rates and amortization of regulatory tax assets (see “Results of Operations—Consolidated Operating Expenses—Income Tax Expense,” below);

·	a $5.3 million decrease in operation and maintenance expense primarily due to decreases in bad debt, payroll and pension expenses, partially offset by consultant and legal fees related to our property tax refund claim; and

·	a $4.0 million decrease in general taxes, primarily related to a refund of property taxes pursuant to a favorable tax ruling from the Oregon Supreme Court.

Dividends paid on our common stock were 41.5 cents per share in the third quarter of 2010, compared to 39.5 cents per share in the third quarter of 2009. The Board of Directors authorized a quarterly dividend on our common stock of 43.5 cents per share, payable on November 15, 2010 to shareholders of record on October 29, 2010, increasing the indicated annual dividend rate by 5 percent to $1.74 per share.

Table of Contents

Application of Critical Accounting Policies and Estimates

In preparing our financial statements using generally accepted accounting principles in the United States of America, 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 2009 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 2009 Form 10-K). Management has discussed its current estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board. Within the context of our critical accounting policies and estimates, management is not aware of any reasonably likely events or circumstances that would result in materially different amounts being reported. For a description of recent accounting pronouncements that could have an impact on our financial condition, results of operations or cash flows, see Note 1.

Results of Operations

Regulatory Matters

Regulation and Rates

We are currently subject to regulation with respect to, among other matters, rates and systems of accounts set by the Oregon Public Utility Commission (OPUC), the Washington Utilities and Transportation Commission (WUTC), FERC and with respect to Gill Ranch, the CPUC. The OPUC and WUTC, and with respect to Gill Ranch, the CPUC, also regulate our issuance of securities. In 2009, approximately 90 percent of our utility gas volumes were delivered to, and utility operating revenues were derived from, Oregon customers and the balance from Washington customers. Future earnings and cash flows from utility operations will be determined largely by the Oregon and southwest Washington economies in general, and by the pace of growth in the residential and commercial markets in Oregon and southwest Washington in particular, and by our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery for our utility gas costs, operating and maintenance costs and investments made in utility plant. See Part II, Item 7., “Results of Operations—Regulatory Matters,” in the 2009 Form 10-K.

Table of Contents

Rate Mechanisms

Purchased Gas Adjustment. Rate changes are established each year under PGA mechanisms in Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases, including gas storage, gas purchases hedged with financial derivatives, interstate pipeline demand charges, 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 2010, the OPUC and WUTC approved rate changes effective on November 1, 2010 under our PGA mechanisms. The effect of the rate changes was to decrease the average monthly bills of Oregon and Washington residential customers by 2 percent. This is our second year of consecutive rate decreases. The OPUC and WUTC also approved rate decreases effective on November 1, 2009 of 16 percent and 22 percent in Oregon and Washington, respectively.

Under the current Oregon PGA incentive sharing mechanism, we are required to select by August 1 of each year, either an 80 percent deferral or 90 percent deferral of higher or lower actual gas costs compared to PGA prices such that the impact on current earnings from the gas cost incentive sharing is either 20 percent or 10 percent, respectively. In addition to the gas cost incentive sharing mechanism, we are also subject to an annual earnings review 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 will 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 2009-2010 and the 2010-2011 PGA years. The ROE threshold is subject to adjustment up or down annually based on movements in long-term interest rates. In September 2010, we received the final report from the OPUC on our 2009 earnings review, which resulted in a utility ROE of 11.2 percent. This is below our threshold of 11.5 percent, and no earnings were deferred for refund to customers.

There has been no change to the Washington PGA mechanism under which we defer 100 percent of the higher or lower actual purchased gas costs and pass that difference through to customers as an adjustment to future rates. We do not have an earnings sharing mechanism in Washington.

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. These authorizations have been extended through January 2011. See Note 11.

Pension Deferral. In March 2010, we filed a request with the OPUC for authorization to defer pension expenses above the amount set in rates, and to recover the amount through future rate increases or through a balancing account mechanism that would include the effects of anticipated lower pension expenses in future years. The company recently entered a settlement agreement with other interested parties to defer pension costs into a balancing account effective January 1, 2011, with accrued interest at the authorized rate of return. This settlement agreement is subject to review and approval by the OPUC before it can go into effect. We expect a decision from the OPUC by the end of this year. If the proposed balancing account set forth in the settlement agreement were in effect for 2010, then operation and maintenance expense would have been reduced by $3 million to $4 million, reflecting current year pension expense in excess of the amount set in rates. Future year deferrals will depend on changes in plan assets and projected benefit liabilities using a number of key assumptions, as well as our pension contributions. See Part II, Item 7., “Application of Critical Accounting Policies and Estimates” in the 2009 Form 10-K.

Table of Contents

Customer Refunds for Gas Storage Sharing. In June 2010, $11 million was refunded to utility customers from our regulatory incentive sharing mechanism related to gas storage services at Mist and optimization services (see “Business Segments Other Utility—Gas Storage,” below). In June 2009, we refunded $7.2 million to customers under the same regulatory mechanism.

Business Segments - Utility Operations

Our utility margin results are primarily affected by customer growth and to a certain extent by changes in weather and customer consumption 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 mechanism that adjusts revenues to offset changes in margin resulting from increases or decreases in average residential and commercial customer consumption. We also have a weather normalization mechanism that adjusts revenues and customer bills up or down to offset changes in margin resulting from above- or below-average temperatures, but only during the winter heating season (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms,” in the 2009 Form 10-K). Both mechanisms are designed to reduce the volatility of our utility earnings.

Three months ended September 30, 2010 compared to September 30, 2009:

Utility operations resulted in a net loss of $9.1 million, or 34 cents per share, in the third quarter of 2010 compared to a net loss of $9.2 million, or 35 cents per share, in the third quarter of 2009. Total utility volumes sold and delivered in the third quarter of this year increased by 4 percent or 6 million therms over last year. Total utility margin decreased by 5 percent or $2.4 million over last year primarily due to lower margin contributions from our gas cost incentive sharing mechanism.

Nine months ended September 30, 2010 compared to September 30, 2009:

In the nine months ended September 30, 2010, utility operations contributed net income of $36.4 million or $1.37 per share, compared to $36.6 million or $1.38 per share in 2009. Total utility volumes sold and delivered in the nine months ended September 30, 2010 decreased by 6 percent or 48 million therms over last year primarily due to warmer weather. Total utility margin decreased by $8.1 million, or 3 percent, primarily due to a $13.6 million decrease in gas cost savings from our incentive sharing mechanism, partially offset by a $5.5 million increase in residential and commercial margins, after weather and decoupling mechanism adjustments, primarily related to the benefits of colder weather in the second quarter of 2010 (see “Residential and Commercial Sales,” below).

Table of Contents

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

	Three Months Ended
	September 30,						Favorable/
Thousands, except degree day data	2010			2009			(Unfavorable)
Utility volumes - therms:
Residential sales		30,031			27,704			2,327
Commercial sales		26,179			24,846			1,333
Industrial - firm sales		8,079			8,180			(101	)
Industrial - firm transportation		28,942			26,962			1,980
Industrial - interruptible sales		12,124			15,235			(3,111	)
Industrial - interruptible transportation		57,268			53,696			3,572
Total utility volumes sold and delivered		162,623			156,623			6,000
Utility operating revenues - dollars:
Residential sales	$	44,255		$	49,215		$	(4,960	)
Commercial sales		27,609			33,396			(5,787	)
Industrial - firm sales		6,934			9,561			(2,627	)
Industrial - firm transportation		1,340			1,371			(31	)
Industrial - interruptible sales		7,709			14,122			(6,413	)
Industrial - interruptible transportation		2,024			1,993			31
Regulatory adjustment for income taxes paid(1)		956			883			73
Other revenues		(723	)		1,282			(2,005	)
Total utility operating revenues		90,104			111,823			(21,719	)
Cost of gas sold		46,349			65,280			18,931
Revenue taxes		2,497			2,926			429
Utility margin	$	41,258		$	43,617		$	(2,359	)
Utility margin:(2)
Residential sales	$	23,237		$	22,137		$	1,100
Commercial sales		10,203			9,682			521
Industrial - sales and transportation		6,608			6,484			124
Miscellaneous revenues		860			826			34
Gain (loss) from gas cost incentive sharing		415			3,623			(3,208	)
Other margin adjustments		(57	)		354			(411	)
Margin before regulatory adjustments		41,266			43,106			(1,840	)
Weather normalization adjustment		-			-			-
Decoupling adjustment		(964	)		(372	)		(592	)
Regulatory adjustment for income taxes paid(1)		956			883			73
Utility margin	$	41,258		$	43,617		$	(2,359	)
Customers - end of period:
Residential customers		604,327			596,917			7,410
Commercial customers		61,656			61,452			204
Industrial customers		920			923			(3	)
Total number of customers - end of period		666,903			659,292			7,611
Actual degree days		110			61
Percent colder (warmer) than average weather(3)		8	%		(40	) %

Table of Contents

		Nine Months Ended
		September 30,						Favorable/
Thousands, except degree day data		2010			2009			(Unfavorable)
Utility volumes - therms:
Residential sales			235,985			264,249			(28,264	)
Commercial sales			152,872			171,460			(18,588	)
Industrial - firm sales			26,857			28,785			(1,928	)
Industrial - firm transportation			92,709			91,740			969
Industrial - interruptible sales			42,372			55,502			(13,130	)
Industrial - interruptible transportation			178,618			165,392			13,226
	Total utility volumes sold and delivered		729,413			777,128			(47,715	)
Utility operating revenues - dollars:
Residential sales		$	297,866		$	374,763		$	(76,897	)
Commercial sales			151,810			205,057			(53,247	)
Industrial - firm sales			22,334			31,214			(8,880	)
Industrial - firm transportation			4,158			4,215			(57	)
Industrial - interruptible sales			26,286			49,341			(23,055	)
Industrial - interruptible transportation			5,924			5,954			(30	)
Regulatory adjustment for income taxes paid(1)			4,974			3,770			1,204
Other revenues			14,917			13,485			1,432
	Total utility operating revenues		528,269			687,799			(159,530	)
Cost of gas sold			281,189			428,803			147,614
Revenue taxes			13,410			17,221			3,811
	Utility margin	$	233,670		$	241,775		$	(8,105	)
Utility margin:(2)
Residential sales		$	130,739		$	143,371		$	(12,632	)
Commercial sales			52,463			58,249			(5,786	)
Industrial - sales and transportation			20,850			20,430			420
Miscellaneous revenues			3,836			4,192			(356	)
Gain (loss) from gas cost incentive sharing			1,110			14,702			(13,592	)
Other margin adjustments			29			1,348			(1,319	)
	Margin before regulatory adjustments		209,027			242,292			(33,265	)
Weather normalization adjustment			11,634			(9,470	)		21,104
Decoupling adjustment			8,035			5,183			2,852
Regulatory adjustment for income taxes paid(1)			4,974			3,770			1,204
	Utility margin	$	233,670		$	241,775		$	(8,105	)
Actual degree days			2,594			2,659
Percent colder (warmer) than average weather(3)			(2	) %		-	%

(1)	Regulatory adjustment for income taxes is described below under “Regulatory Adjustment for Income Taxes Paid.”
(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.

Table of Contents

In June 2009, we refunded $35.8 million to our Oregon and Washington customers for accumulated gas cost savings in our regulatory deferred account. Because this refund was such a significant amount, which materially affected utility operating revenues for the three and nine months ended September 30, 2009, we have provided the following non-GAAP table summarizing our utility operating revenues and margin excluding the impact of this refund for the three and nine months ended September 30, 2009 as compared to the same periods in 2010:

	Three Months Ended
				September 30, 2009
Thousands	September 30, 2010			As Reported		Refund		Excluding Refund (Non-GAAP)
Utility operating revenues:
Residential sales	$	44,255		$	49,215	$	273	$	49,488
Commercial sales		27,609			33,396		156		33,552
Industrial - firm sales		6,934			9,561		70		9,631
Industrial - firm transportation		1,340			1,371		-		1,371
Industrial - interruptible sales		7,709			14,122		-		14,122
Industrial - interruptible transportation		2,024			1,993		-		1,993
Regulatory adjustment for income taxes paid		956			883		-		883
Other revenue		(723	)		1,282		-		1,282
Total utility operating revenues		90,104			111,823		499		112,322
Cost of gas sold		46,349			65,280		485		65,765
Revenue taxes		2,497			2,926		11		2,937
Utility margin	$	41,258		$	43,617	$	3	$	43,620

	Nine Months Ended
				September 30, 2009
Thousands	September 30, 2010			As Reported		Refund		Excluding Refund (Non-GAAP)
Utility operating revenues:
Residential sales	$	297,866		$	374,763	$	19,952	$	394,715
Commercial sales		151,810			205,057		11,579		216,636
Industrial - firm sales		22,334			31,214		1,585		32,799
Industrial - firm transportation		4,158			4,215		-		4,215
Industrial - interruptible sales		26,286			49,341		2,673		52,014
Industrial - interruptible transportation		5,924			5,954		-		5,954
Regulatory adjustment for income taxes paid		4,974			3,770		-		3,770
Other revenue		14,917			13,485		-		13,485
Total utility operating revenues		528,269			687,799		35,789		723,588
Cost of gas sold		281,189			428,803		34,691		463,494
Revenue taxes		13,410			17,221		898		18,119
Utility margin	$	233,670		$	241,775	$	200	$	241,975

The refunds represent the customers’ portion of gas cost savings realized between November 1, 2008 and March 31, 2009, which had been deferred, with interest, pursuant to our PGA tariffs in Oregon and Washington (see “Regulatory Matters – Rate Mechanisms,” above). The refunds reduced total utility operating revenues for the three and nine months ended September 30, 2009 by $35.8 million, cost of gas sold by $34.7 million and revenue taxes by $0.9 million, which resulted in a net reduction to margin of only $0.2 million. This decrease in utility margin was offset by lower revenue-based expenses including bad debt expense and lower regulatory fees.

Table of Contents

Residential and Commercial Sales

Residential and commercial sales are impacted by customer growth rates, seasonal weather patterns, energy prices, competition from other energy sources and economic conditions in our service area. Typically, 80 percent or more of our annual utility operating revenues 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 due to our weather normalization mechanism in Oregon, where about 90 percent of our customers are served. This mechanism is in effect for the period from December 1 through May 15 of each heating season, but customers are allowed to opt out of the mechanism. For the current gas year approximately 9 percent of our Oregon residential and commercial customers have opted out of the mechanism, which is fairly consistent with prior years. In Oregon, we also have a conservation decoupling adjustment mechanism that is intended to break the link between our earnings and the quantity of gas consumed by our customers, so that we do not have an incentive to encourage greater consumption and undermine Oregon’s conservation policy and efforts. In Washington, where the remaining 10 percent of our customers are served, we do not have a weather normalization or a conservation decoupling mechanism. As a result, we are not fully insulated from earnings volatility due to weather and conservation in Washington.

Three months ended September 30, 2010 compared to September 30, 2009:

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 increased 7 percent due to colder weather and customer growth;

·	utility operating revenues decreased $10.7 million or 13 percent primarily due to lower customer rates; and

·	utility margin increased $1 million or 3 percent, including weather normalization and decoupling mechanism adjustments, primarily due to colder weather, customer growth and margin recovery related to higher income taxes.

Nine months ended September 30, 2010 compared to September 30, 2009:

The primary factors contributing to changes in residential and commercial volumes and operating revenues in the nine months ended September 30, 2010, compared to the same period last year were:

·	sales volumes decreased 11 percent due to weather that was warmer during the first quarter of 2010 compared to last year, which is the period when volumes are most impacted by weather, and by customer conservation;

·	utility operating revenues decreased $130.1 million or 22 percent primarily due to customer rate decreases of 16 and 22 percent in Oregon and Washington, respectively, and 11 percent lower sales volumes, partially offset by $31.5 million in customer refunds in 2009 related to gas cost savings; and

·	utility margin increased $5.5 million, or 3 percent, including weather and decoupling adjustments, primarily due to colder weather during the second quarter of 2010 and customer growth of 1.2 percent over the last 12 months.

Colder weather in this year’s second quarter had a larger effect than normal. Because our weather mechanism is in effect for only half of the month of May, and the decoupling mechanism is adjusted for normal weather, we experience larger than normal changes in margin during May when the weather is colder or warmer than normal. For the month of May 2010, temperatures were 33 percent colder than normal. This triggered a higher use of gas by residential and commercial customers that was only partially offset by the weather normalization mechanism. As a result, the colder weather in May contributed $2.8 million to margin.

Utility operating revenues include accruals for unbilled revenues based on estimates of gas deliveries from that month’s meter reading dates to month end. Weather conditions, rate changes and customer billing dates affect the balance of accrued unbilled revenues at the end of each month. At September 30, 2010, accrued unbilled revenue was $15.4 million, compared to $19.1 million at September 30, 2009, with the 19 percent decrease primarily due to lower billing rates.

Table of Contents

Industrial Sales and Transportation

Industrial operating revenues include the commodity cost component of gas sold under sales service but not under transportation service. Therefore, industrial customer switching between sales service and transportation service can cause swings in utility operating revenues but generally our margins are unaffected because we do not mark up the cost of gas.

Three months ended September 30, 2010 compared to September 30, 2009:

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

·	volumes delivered to industrial customers increased by 2.3 million therms, or 2 percent; and

·	margin increased $0.1 million, or 2 percent, as a result of higher volumes.

Nine months ended September 30, 2010 compared to September 30, 2009:

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

·	volumes delivered to industrial customers decreased by 0.9 million therms or less than 1 percent; and

·	margin increased $0.4 million, or 2 percent, as a result of fixed charges not affected by declining use and higher margin rate schedules.

Regulatory Adjustment for Income Taxes Paid

Oregon law requires certain regulated natural gas and electric utilities, including NW Natural, to annually review the amount of income taxes collected in rates from utility operations and compare it to the amount the company actually pays to taxing authorities. Under this law, if we pay less in income taxes than we collect from our Oregon utility customers, or if our consolidated taxes paid are less than the taxes we collect from our Oregon utility customers, then we are required to refund the excess to our Oregon utility customers. Conversely, if we pay more income taxes related to utility operations than we actually collect from our Oregon utility customers, as calculated using rate increments from our most recent general rate case, then we are required to collect a surcharge from our Oregon utility customers.

For the nine months ended September 30, 2010, we recognized $5 million of pre-tax income representing a difference of $4.6 million of estimated federal and state income taxes paid in excess of taxes collected in rates plus accrued interest. For the nine months ended September 30, 2009, we recognized $3.8 million of incremental margin revenues representing a difference of $3.6 million of federal and state income taxes paid in excess of taxes collected in rates plus accrued interest. The $1.2 million increase in income taxes paid over income taxes collected in rates is due in part to higher effective income tax rates (see Note 7).

Other Revenues

Other revenues include miscellaneous fee income as well as utility revenue adjustments reflecting deferrals to, or amortizations from, regulatory asset or liability accounts other than deferred gas costs. Although the decoupling adjustment and other regulatory deferral collections or refunds and amortizations can have a material impact on utility operating revenues, they generally do not have a material impact on margin because they are offset by increases or decreases in customer sales rates.

Table of Contents

Three months ended September 30, 2010 compared to September 30, 2009:

Other revenues decreased $2 million in the third quarter of 2010 compared to the same period in 2009, primarily from a net decrease in the deferral and amortization related to the decoupling adjustment.

Nine months ended September 30, 2010 compared to September 30, 2009:

Other revenues were $14.9 million in the nine months ended September 30, 2010, an increase of $1.4 million over the same period of 2009, with the increase primarily due to a timing difference in how we collect our surcharge for regulatory adjustment for income taxes paid. In 2009 we collected the surcharge in a one-time billing adjustment. In 2010, we are collecting the surcharge in rates as an adjustment in our PGA. The timing of when we collect the surcharge has no impact on margin or net income.

Cost of Gas Sold

The cost of gas sold includes current gas purchases, gas drawn from storage inventory, gains and losses from commodity hedges, pipeline demand charges, seasonal demand cost balancing adjustments, regulatory gas cost deferrals and company gas use. Our regulated utility does not generally earn a profit or incur a loss on gas commodity purchases. The OPUC and the WUTC require natural gas commodity costs 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 is partially affected by differences between actual and expected purchased gas costs due to market fluctuations and volatility affecting unhedged purchases. To manage this earnings exposure, we use natural gas derivatives, primarily fixed-price commodity swaps, consistent with our financial derivatives policies. Gains and losses from financial hedge contracts are generally included in our PGA prices and normally do not impact net income as the hedges are usually 100 percent passed through to customers in annual rate changes, subject to a regulatory prudency review. However, prices on unhedged purchases and hedged purchases entered into after the annual PGA filing in Oregon, if any, may impact net income to the extent of our share of any gain or loss under the PGA. In Washington, 100 percent of the actual gas costs, including all hedge gains and losses, 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 2009 Form 10-K, and Note 10 in this report).

Three months ended September 30, 2010 compared to September 30, 2009:

·	total cost of gas sold decreased $18.9 million, or 29 percent, due to lower gas prices;

the average gas cost collected through rates, excluding customer refunds for accumulated gas cost savings from prior quarters, decreased 31 percent from 89 cents per therm in 2009 to 61 cents per therm in 2010, primarily reflecting the lower gas prices that were passed on through customer rates effective November 1, 2009; and

·	hedge net losses totaling $12.6 million were realized and included in cost of gas sold this quarter, compared to $29.1 million of hedge net losses in the same period of 2009.

The effect on operating results from our share of the gas cost incentive sharing mechanism was a margin gain of $0.4 million in the third quarter of 2010, compared to a margin gain of $3.6 million for the third quarter of 2009.

Nine months ended September 30, 2010 compared to September 30, 2009:

·	total cost of gas sold decreased $147.6 million, or 34 percent, due to a 6 percent decrease in total sales volumes and lower gas prices;

·	the average gas cost collected through rates, excluding customer refunds, decreased 30 percent from 89 cents per therm in 2009 to 62 cents per therm in 2010, primarily reflecting lower gas prices that were passed on through customer rates effective November 1, 2009; and

·	hedge net losses totaling $33.3 million were realized and included in cost of gas sold for the nine months ended September 30, 2010, compared to $150.8 million of hedge net losses in the same period of 2009.

The effect on operating results from our share of the gas cost incentive sharing mechanism was a margin gain of $1.1 million in the nine months ended September 30, 2010, compared to a margin gain of $14.7 million in the same period of 2009.

Table of Contents

Business Segments Other than Utility Operations

Gas Storage

Our gas storage segment currently consists of the non-utility portion of our Mist underground storage facility, utility and non-utility asset optimization and start-up costs at Gill Ranch (see Part I, Item 1., “Business Segments—Gas Storage,” in our 2009 Form 10-K). For the three months ended September 30, 2010, we earned $1.8 million, or 7 cents per share, compared to $2.3 million, or 9 cents per share, for the same period in 2009. The $0.5 million decrease in net income over 2009 is primarily due to start-up costs at Gill Ranch. For the nine months ended September 30, 2010, we earned $6.4 million, or 24 cents per share, compared to $7 million, or 27 cents per share, for the same period in 2009.

We provide gas storage services to customers in the interstate and intrastate markets from our Mist gas storage field in Oregon, primarily using storage capacity that has been developed in advance of core utility customers’ requirements. Under a regulatory incentive sharing mechanism in Oregon, we retain 80 percent of pre-tax income from our Mist gas storage services and from optimization services when the costs of the capacity being used are not included in utility rates, and 33 percent of pre-tax income from such storage and optimization services when the capacity being used is pipeline or is included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for refund to our core utility customers. We have a similar sharing mechanism in Washington for pre-tax income derived from gas storage and optimization services.

We began construction at Gill Ranch in January 2010 and started commercial operations in October 2010. Our share of the project represents 75 percent of the total cost of the initial development, which is designed to provide an estimated 20 Bcf of gas storage capacity and about 27 miles of gas transmission pipeline. Our share of the total projected construction costs was increased to between $210 and $220 million. As of September 30, 2010 and 2009, our construction work-in-process balance in Gill Ranch was $201.1 million and $32.2 million, respectively. See Note 2 in the 2009 Form 10-K.

Other

Our other business segment consists of Financial Corporation, an investment in PGH, and other non-utility investments and business activities. Financial Corporation had total assets of $1.1 million and $1.3 million as of September 30, 2010 and 2009, respectively, reflecting a non-controlling interest in the Kelso-Beaver pipeline. Our net equity investment in PGH as of September 30, 2010 and 2009 was $14.7 million and $12.4 million, respectively. Earnings from our other business segment for the three and nine months ended September 30, 2010 was a net loss of $0.1 million and net income of $0.3 million, respectively, compared to a net income of $0.2 million and $0.1 million for the three and nine months ended September 30, 2009. See Note 2.

Table of Contents

Consolidated Operating Expenses

Operations and Maintenance

Three months ended September 30, 2010 compared to September 30, 2009:

Operations and maintenance expense was $26.9 million in 2010, compared to $27.1 million in 2009, a decrease of $0.2 million or 1 percent. The primary factors contributing to the decrease were:

·	a $0.9 million decrease in payroll expense related to a reduced number of utility employees;

·	a $0.5 million decrease in incentive bonus accruals; and

·	a $0.2 million decrease in utility bad debt expense (see below for more detail).

Partially offsetting the above factors was:

·	a $0.8 million increase primarily due to Gill Ranch start-up costs.

Nine months ended September 30, 2010 compared to September 30, 2009:

Operations and maintenance expense was $86 million in 2010, compared to $91.2 million in 2009, a decrease of $5.2 million or 6 percent. The primary factors that contributed to the decrease in operations and maintenance expense were:

·	a $2.9 million decrease in payroll expense related to a reduced number of utility employees;

·	a $2.6 million decrease in utility bad debt expense (see below); and

·	a $0.9 million decrease in pension expense, due to the decline in the market value of plan investments in 2008 which had a greater impact on 2009 expense.

Partially offsetting the above factors were:

·	a $1.3 million increase primarily due to Gill Ranch start-up costs.

Our bad debt expense as a percent of revenues was 0.15 percent for the 12 months ended September 30, 2010, compared to 0.39 percent in the same period last year. This year’s lower bad debt expense ratio was partly due to improved collections of delinquent account balances. Excluding customer refunds in June and July 2009 (see “Business Segments—Utility Operations,” above), our bad debt expense as a percent of revenues was 0.36 percent for the 12 months ended September 30, 2009. Credit risks are still somewhat high due to the weak economy and high unemployment rates, but our credit environment has improved as evidenced by our 21 percent decrease in delinquent account balances over last year. Lower customer usage from warmer than normal weather this past winter coupled with customer conservation, lower gas prices and low income energy assistance funds have contributed to our reduced credit exposure.

Health care costs have been trending higher, and it was recently reported that 2011 local and national health care cost increases were expected to be between 10 and 12 percent. We estimate that our employee health and welfare benefit costs for 2011 will increase by approximately 5 percent, including making required changes imposed by health care reform. We also anticipate that pension expenses related to the company’s qualified defined benefit plans could increase materially in 2011 due to the low interest rate environment, but we believe these higher costs may be offset if the OPUC approves the company’s request for a deferred balancing account (see discussion of Pension Deferral under “Regulatory Matters - Rate Mechanisms,” above).

Table of Contents

General Taxes

Three months ended September 30, 2010 compared to September 30, 2009:

General taxes, which are principally comprised of property taxes, payroll taxes and regulatory fees, increased $0.2 million, or 4 percent, in the three months ended September 30, 2010 over the same period in 2009, primarily due to an increase in property taxes from net additions to property, plant and equipment.

Nine months ended September 30, 2010 compared to September 30, 2009:

For the nine months ended September 30, 2010, general taxes decreased $4 million, or 19 percent, compared to the same period in 2009, due to a property tax refund of $5.2 million (see below), partially offset by an increase in property taxes from net additions to property, plant, and equipment.

We were involved in litigation with the Oregon Department of Revenue over whether inventories held for sale were required to be taxed as personal property. 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 entitled to a refund of approximately $5.2 million, plus accrued interest, for property 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 paid, $1.9 million for accrued interest income, and $1.0 million of increased operations and maintenance expense for legal and consulting services. As of September 30, 2010, we had received all of the property tax refunds.

Depreciation and Amortization

Depreciation and amortization expense increased by $0.2 million, or 1 percent for the three months ended September 30, 2010, compared to the same period in 2009. For the nine months ended September 30, 2010, depreciation and amortization expense increased by $1.2 million, or 3 percent, compared to the same period in 2009. The increase in both periods reflects added utility plant from customer growth and other capital project expenditures.

Other Income and Expense – Net

The following table summarizes other income and expense – net by primary components for the three and nine months ended September 30, 2010 and 2009:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Thousands	2010			2009			2010			2009
Other income and expense - net:
Gains from company-owned life insurance	$	599		$	664		$	1,640		$	2,666
Interest income		8			66			2,006			165
Income from equity investments		(152	)		193			576			927
Net interest on deferred regulatory accounts		1,189			585			3,386			1,374
Other		(311	)		(270	)		(1,639	)		(2,272	)
Total other income and expense - net	$	1,333		$	1,238		$	5,969		$	2,860

Table of Contents

Three months ended September 30, 2010 compared to September 30, 2009:

Other income and expense – net increased $0.1 million, primarily due to additional income from our higher deferred regulatory account balances.

Nine months ended September 30, 2010 compared to September 30, 2009:

Other income and expense – net increased $3.1 million, primarily due to additional interest income from our deferred regulatory accounts and from $1.9 million in interest income related to the property tax refund discussed under “General Taxes,” above.

Interest Expense – Net

Interest expense – net decreased less than $0.1 million in the three months ended September 30, 2010 compared to the same period in 2009 and increased $1.7 million, or 6 percent in the nine months ended September 30, 2010 compared to the same period in 2009. The year-to-date increase over 2009 is primarily due to higher balances on long-term debt outstanding, including the $75 million of 5.37 percent medium-term notes (MTNs) issued in March 2009 and the $50 million of 3.95 percent MTNs issued in July 2009 (see Note 5).

Income Tax Expense

Income tax expense increased $2.3 million in the nine months ended September 30, 2010 compared to 2009. The effective tax rate was 40.3 percent in 2010 compared to 38.0 percent in 2009. The higher income tax expense and higher effective tax rate are the result of an increase in the amortization of our regulatory tax asset account on pre-1981 plant assets (see “Regulatory Matters—Rate Mechanisms—Depreciation Study,” in the 2009 Form 10-K).

On March 23, 2010, the Patient Protection and Affordable Care Act (the PPACA) was signed into law, and on March 30, 2010 the Health Care and Education Reconciliation Act of 2010 was signed into law. The PPACA changes the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide a benefit that is at least actuarially equivalent to the benefits under Medicare Part D. These subsidy payments become taxable in years beginning after December 31, 2012. Accounting guidance on income taxes requires the impact of this tax law change to be immediately recognized in the period that includes the enactment date. This tax provision of the PPACA did not have, and is not expected to have, an impact on our financial condition, results of operations or cash flows as we were not receiving federal subsidy payments under Medicare Part D.

Table of Contents

Financial Condition

Capital Structure

Our goal 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. When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources also are used to fund long-term debt redemption requirements and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below, and Note 5). 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 was as follows:

	September 30,						December 31,
	2010			2009			2009
Common stock equity		45.9	%		47.5	%		47.2	%
Long-term debt		40.2	%		47.2	%		43.0	%
Short-term debt, including current maturities of long-term debt		13.9	%		5.3	%		9.8	%
Total		100	%		100	%		100	%

Liquidity and Capital Resources

At September 30, 2010, we had $2.5 million of cash and cash equivalents compared to $13.7 million at September 30, 2009. We also had $0.9 million in restricted cash invested at Gill Ranch as of September 30, 2010, compared to $20.8 million as of September 30, 2009, which is being held as collateral for equipment purchase contracts and construction loans. 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 pre-fund utility capital expenditures while long-term fixed rate environments are attractive. Short-term liquidity is supported by cash balances, internal cash flow from operations, proceeds from the sale of commercial paper notes, committed multi-year credit facilities, cash available from surrender value in company-owned life insurance policies, and proceeds from the sale of long-term debt. We use long-term debt proceeds to finance utility capital expenditures, refinance maturing short-term or long-term debt and provide for general corporate purposes. In March 2009, we issued $75 million of secured MTNs with an interest rate of 5.37 percent and a maturity date of February 1, 2020. In July 2009, we issued $50 million of secured MTNs with an interest rate of 3.95 percent and a maturity date of July 15, 2014.

The capital markets in the last two years, including the commercial paper market, experienced significant volatility and tight credit conditions, but conditions over the past 12 months improved as reflected by tighter credit spreads and increased access to new financing for investment grade issuers. 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 $250 million back-up facility. In the event that we are not able to issue new debt due to market conditions, we expect that our near term liquidity needs can be met by using cash balances or drawing upon our committed credit facility (see “Credit Agreement,” below). We also have a universal shelf registration statement 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 $175 million of additional MTNs under the existing shelf registration statement. We expect to file a new shelf registration statement, as required, prior to January 8, 2011.

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, 2010, we could have been required to post $42.3 million of collateral to our counterparties, but that assumes our long-term debt ratings were at non-investment grade levels, a level that is lower than our current ratings (see Note 10 and “Credit Ratings,” below).

Table of Contents

Some recent developments that may impact our liquidity and capital resources include pension contributions, tax benefits and environmental expenditures and insurance recoveries. With respect to pension requirements, we expect to make additional contributions in 2011 and in future years until we are fully funded on our pension obligations (see “Pension Funding Status,” below). With respect to federal income tax liabilities, an extension was granted that will allow us to take 50 percent bonus depreciation on a majority of our capital expenditures in 2010, which will significantly reduce our tax liability for the 2010 tax year and provide cash flow benefits in late 2010 and early 2011 (see “Cash Flows—Operating Activities,” below). And with respect to environmental liabilities, we expect to continue using cash resources towards our environmental liabilities, but we also anticipate recovering amounts through insurance recovery or rate recovery over the next several years, but the amount and timing of these expenditures and recoveries is uncertain (see Note 11).

In addition, Gill Ranch began commercial operations in October 2010. Although we anticipate future operating cash flows, the amount and timing of these cash flows are uncertain.

In July 2010, the U.S. Congress passed and President Obama signed into law the “Wall Street Reform and Consumer Protection Act.” The new legislation will require additional government regulation of derivative and over-the-counter transactions, and that could expand collateral requirements. While we are currently evaluating the new legislation to determine its impact, if any, on our hedging procedures, results of operations, financial position and liquidity, we do not expect to know the full impact of the legislation until regulations implementing the legislation are finalized.

Based on several factors, including our current credit ratings, recent experience issuing commercial paper, current cash reserves, committed credit facilities and other liquidity resources, and our expected ability to issue long-term debt in the form of a Medium-Term Note program under our universal shelf registration, we believe our liquidity is sufficient to meet our 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, 2010, our purchase commitments decreased approximately $47.8 million since December 31, 2009, primarily due to payments related to Gill Ranch (see “Financial Condition--Contractual Obligations,” in the 2009 Form 10-K).

Short-term Debt

Our primary source of short-term liquidity is from internal cash flows and the sale of commercial paper debt. In addition to issuing commercial paper to meet seasonal working capital requirements, including the financing of gas inventories and accounts receivable, short-term debt may 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 Agreement,” 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 two years. At September 30, 2010 and 2009, our utility had commercial paper outstanding of $159.9 million and $56.1 million, respectively. In June 2010, Gill Ranch repaid its $40 million bank loan outstanding using the proceeds from its cash collateralized account.

Table of Contents

Credit Agreement

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. All lenders under our credit agreement are major financial institutions with committed balances and investment grade credit ratings as of September 30, 2010 as follows:

			Amount
			Committed
Lender rating, by category			(in $000's)
AAA/Aaa		$	-
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 debt ratings, we believe the risk of lender default is minimal.

The loan commitments with all lenders under the syndicated credit agreement have been extended to May 31, 2013. The credit agreement 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. The credit 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 owed on borrowings under the credit agreement is due and payable on or before the maturity date. There were no outstanding balances under this credit agreement at September 30, 2010 and 2009. The credit agreement also requires us to maintain a consolidated indebtedness to total capitalization ratio as determined in accordance with the credit agreement 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, 2010 and 2009.

The credit agreement also requires that we maintain credit ratings with S&P and 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 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. Interest rates on any loans outstanding under the credit agreement are tied to debt ratings, which would increase or decrease the cost of any loans under the credit agreement when ratings are changed (see “Credit Ratings,” below).

Credit Ratings

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

Table of Contents

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)		A3
Corporate credit rating	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 solely to facilitate an understanding of our liquidity and costs of funds and is not a recommendation to buy, sell or hold NW Natural securities. Each rating should be evaluated independently of any other rating.

Redemptions of Long-Term Debt

For the nine months ended September 30, 2010 or 2009, there are no long-term debt redemptions. In November 2009, $0.3 million of our 6.65 percent secured MTNs due 2027 were redeemed pursuant to a one-time put option. This one-time put option has now expired, and the $19.7 million remaining principal outstanding is expected to be paid at maturity in November 2027.

We have $45 million of long-term debt that will mature during the fourth quarter of 2010. For additional long-term debt maturing over the next five years, see Part II, Item 7., "Results of Operations—Financial Condition—Contractual Obligations," in our 2009 Form 10-K.

Cash Flows

Operating Activities

Year-over-year changes in our operating cash flows are primarily affected by net income, changes in working capital requirements and other cash and non-cash adjustments to operating results. In the nine months ended September 30, 2010, cash flow from operating activities decreased $84.8 million compared to the same period in 2009. The significant factors contributing to changes in cash flow for the nine months ended September 30, 2010 compared to the same period of 2009 are as follows:

·	a decrease of $50.8 million from changes in deferred gas cost regulatory account which reflects actual gas prices compared to estimated gas prices embedded in customer rates;

·	a decrease of $32.7 million from changes in receivables primarily due to $35.3 million of customer refunds in June 2009 and higher receivable balances at the end of 2008 versus 2009;

·	an increase of $15 million from a smaller pension contribution in 2010 compared to 2009;

·	a decrease of $13.5 million from deferred income taxes, primarily related to decreases in tax deductions; and

·	an increase of $10.1 million from the loss realized in 2009 on the settlement of our interest rate hedge (see Note 10).

In September 2010, Congress passed the Small Business Jobs Act of 2010 (the Act) and the legislation was signed into law by President Obama. The Act extends for one additional year the temporary 50 percent bonus depreciation first enacted in the Economic Stimulus Act of 2008 and subsequently renewed in the American Recovery and Reinvestment Act of 2009. Under the bonus depreciation provision, an additional temporary first-year tax deduction for depreciation equal to 50 percent of the adjusted basis of qualified property may be deducted in the year the property is placed in service and the remaining 50 percent recovered under the normal depreciation rules. The 50 percent depreciation deduction in the first year is an acceleration of depreciation deductions that otherwise would have been taken in the later years of an asset’s recovery period. As a result of this extension, we will recognize an increase in our cash flow by reducing our current tax liability for the 2010 tax year. Any deductions in excess of income for federal income tax purposes will be carried back to the 2009 tax year. We estimate this extension will generate cash flow of between $40 million to $45 million in federal income taxes.

Table of Contents

Investing Activities

Cash used in investing activities for the nine months ended September 30, 2010 totaled $150.1 million, up from $96.5 million for the same period in 2009. Our capital expenditures were $185.7 million in the nine months ended September 30, 2010, up $100.4 million from $85.2 million for the same period in 2009. Our utility capital expenditures decreased $14.0 million primarily due to completing our automated meter reading project in 2009, and our non-utility capital expenditures increased $114.4 million primarily due to investments in Gill Ranch.

Cash flows from restricted cash, which collateralizes equipment purchase contracts and bank loans for Gill Ranch, increased $50.4 million compared to 2009, primarily due to settling our cash collateralized loan in June 2010.

In 2010, utility capital expenditures are estimated to be between $80 and $90 million, and non-utility capital expenditures are expected to be between $140 and $150 million for business development projects that are currently in process (see “Strategic Opportunities,” above).

Over the five-year period 2010 through 2014, utility capital expenditures are estimated at between $400 and $500 million. The estimated level of utility capital expenditures over the next five years reflects assumptions for customer growth, utility storage development at Mist, technology improvements and utility system improvements, including requirements under the Pipeline Safety Improvement Act of 2002. Most of the required funds are expected to be internally generated over the five-year period and any remaining funding will be obtained through the issuance of long-term debt or equity securities, with short-term debt providing liquidity and bridge financing (see Part II, Item 7., “Financial Condition—Cash Flows—Investing Activities,” in the 2009 Form 10-K).

Our portion of the total construction cost for the current development at Gill Ranch increased to be between $210 million and $220 million. As of September 30, 2010, we have invested $183.4 million of equity funds in Gill Ranch. The remaining construction costs are expected to be met from a combination of equity funds, tax benefits and debt, which will be non-recourse to NW Natural. NW Natural has not pledged any of its utility assets, nor has it provided any parent guarantees, toward Gill Ranch’s obligations.

In 2010, Palomar expects to continue working on the planning and permitting phase of the proposed pipeline and continue to evaluate the impacts of changes to project scope and timeline based on the bankruptcy court’s decision in September 2010 to reject the precedent agreement with a shipper who had a majority of the proposed pipeline’s capacity. We are working with other interested shippers to determine their pipeline needs as well as the needs of the region. The total cost for planning and permitting, excluding shippers’ credit support, is estimated to be between $45 million and $55 million, of which our ownership interest is 50 percent. The initial planning and permitting costs are being financed with equity funds from us and our partner, GTN, in PGH, and to a certain extent from shipper credit support (see discussion of shipper obligations below).

In April 2009, Palomar received $15.8 million from a letter of credit which had supported the majority shipper's obligations under a prior precedent agreement and were applied against Palomar project costs. The shipper provided additional collateral to secure its obligations under the current precedent agreement and to support a portion of the ongoing planning and permitting costs as the project developed. In May 2010, the majority shipper suspended operations and filed for bankruptcy protection. Palomar is currently pursuing its rights to foreclose on the collateral. For more information, see Note 8 and “Strategic Opportunities—Pipeline Diversification,” above.

Table of Contents

Financing Activities

Cash provided by financing activities in the nine months ended September 30, 2010 totaled $29.6 million, up from cash used of $96 million for the same period in 2009. Our short-term debt balances increased $57.9 million in the nine months ended September 30, 2010, compared to a decrease of $189 million for the same period in 2009, which was partially offset by our long-term debt issuances of $75 million in March 2009 and $50 million in July 2009. We use long-term debt proceeds primarily to finance capital expenditures, refinance maturing short-term or redeem long-term debt maturities as well as for general corporate purposes.

Pension Funding Status

We make contributions to company-sponsored qualified defined benefit pension plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. Our qualified defined benefit pension plans were underfunded by $83.9 million at December 31, 2009. In March 2010, we contributed $10 million to these plans, with a portion allocated to 2009 and 2010 plan years. For more information on the funding status of our qualified retirement plans and other postretirement benefits, see Note 6, and Part II, Item 7., “Financial Condition—Pension Cost and Funding Status of Qualified Retirement Plans,” and Part II, Item 8., Note 7, “Pension and Other Postretirement Benefits,” in the 2009 Form 10-K.

We also contribute to a multiemployer pension plan (Western States Plan) pursuant to our collective bargaining agreement. Our total contribution to the Western States Plan in 2009 amounted to $0.4 million. We made contributions totaling $0.3 million to the Western States Plan for both the nine months ended September 30, 2010 and 2009. See Note 6 for further discussion.

Ratios of Earnings to Fixed Charges

For the nine and twelve months ended September 30, 2010 and the twelve months ended December 31, 2009, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were 3.18, 3.79 and 3.86, 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. Because a significant part of our business is of a seasonal nature, the ratios for the interim periods are not necessarily indicative of the results for a full year. 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 the 2009 Form 10-K). At September 30, 2010, we had a regulatory asset of $111.9 million for deferred environmental costs, which includes $42.2 million of total paid expenditures to date, $57 million for additional costs expected to be paid in the future and accrued interest of $12.7 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 11.

Table of Contents

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including, but not limited to, commodity supply risk, commodity price risk, interest rate risk, foreign currency risk, credit risk and weather risk (see Part I, Item 1A., “Risk Factors,” and Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk,” in the 2009 Form 10-K). The following are updates to certain of these market risks:

Commodity Price Risk

Natural gas commodity prices are subject to fluctuations due to unpredictable factors including weather, pipeline transportation congestion, potential market speculation and other factors that affect short-term supply and demand. Commodity-price financial swap and option contracts (financial hedge contracts) are used to convert certain natural gas supply contracts from floating prices to fixed or capped prices. These financial hedge contracts are generally included in our annual PGA filing for recovery, subject to a regulatory prudence review. At September 30, 2010 and 2009, notional amounts under these financial hedge contracts totaled $382.5 million and $358.8 million, respectively. If all of the commodity-based financial hedge contracts had been settled on September 30, 2010, a loss of about $86.2 million would have been realized and recorded to a deferred regulatory account (see Note 10). We regularly monitor and manage the financial exposure and liquidity risk of our financial hedge contracts under the direction of our Gas Acquisition Strategies and Policies Committee, which consists of senior management with Audit Committee oversight. Based on the existing open interest in the contracts held, we believe financial exposure to be minimal and existing contracts to be liquid. As of September 30, 2010, all of our current outstanding financial hedge contracts mature on or before October 2013. The $86.2 million unrealized loss is an estimate of future cash flows based on forward market prices that are expected to be paid as follows: $50.1 million in the next 12 months and $36.1 million thereafter. The amount realized will change based on market prices at the time contract settlements are fixed.

Credit Risk

Credit exposure to suppliers. Certain suppliers that sell us gas have either relatively low credit ratings or are not rated by major credit rating agencies. To manage this supply risk, we purchase gas from a number of different suppliers at liquid exchange points. We evaluate and monitor suppliers’ creditworthiness and maintain the ability to require additional financial assurances, including deposits, letters of credit or surety bonds, in case a supplier defaults. In the event of a supplier’s failure to deliver contracted volumes of gas, the regulated utility would need to replace those volumes at prevailing market prices, which may be higher or lower than the original transaction prices. We believe these costs would be subject to the PGA sharing mechanism discussed above. Since most of our commodity supply contracts are priced at the monthly market index price tied to liquid exchange points, and we have significant storage flexibility, we believe that it is unlikely that a supplier default would have a material adverse effect on our financial condition or results of operations.

Credit exposure to financial derivative counterparties. Based on estimated fair value at September 30, 2010, our overall credit exposure relating to commodity hedge contracts reflects an amount we owed of $86.2 million to our financial derivative counterparties. Our financial derivatives policy requires counterparties to have at least an investment-grade credit rating at the time the derivative instrument is entered into, and specific limits on the contract amount and duration based on each counterparty’s credit rating. Due to current market conditions and credit concerns, we continue to enforce strong credit requirements. We actively monitor and manage our derivative credit exposure and place counterparties on hold for trading purposes or require cash collateral, letters of credit or guarantees as circumstances warrant. Our actual derivative credit risk exposure, which reflects amounts that financial derivative counterparties owe to us, is less than $0.4 million, and these amounts are under contracts that are expected to settle on or before October 2013.

Table of Contents

The following table summarizes our overall credit exposure, based on estimated fair value, and the corresponding counterparty unsecured credit ratings. The table uses credit ratings from S&P and Moody’s, reflecting the higher of the S&P or Moody’s rating or a middle rating if the entity is split-rated with more than one rating level difference:

			September 30,				December 31,
Thousands			2010		2009		2009
AAA/Aaa		$	-	$	-	$	-
AA/Aa			(72,034)		(18,730)		(15,792)
A/A			(14,134)		(5,872)		-
BBB/Baa			-		-		-
	Total	$	(86,168)	$	(24,602)	$	(15,792)

To mitigate the credit risk of financial derivatives we have master netting arrangements with our counterparties that provide for making or receiving net cash settlements. Generally, transactions of the same type in the same currency that have a settlement on the same day with a single counterparty are netted and a single payment is delivered or received depending on which party is due funds.

Additionally we have master contracts in place with each of our derivative counterparties that usually include provisions for posting or calling for collateral. Generally we can obtain cash or marketable securities as collateral with one day’s notice. We use various collateral management strategies to reduce liquidity risk. The collateral provisions vary by counterparty but are not expected to result in the significant posting of collateral, if any. We have performed stress tests on the portfolio and concluded that the liquidity risk from collateral calls is not material. Our derivative credit exposure is primarily with investment grade counterparties rated AA-/Aa3 or higher. Contracts are diversified across counterparties to reduce credit and liquidity risk.

For the impact of new legislation on our derivatives, see Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Liquidity and Capital Resources,” above.

Item 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

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

(b) Changes in Internal Control Over Financial Reporting

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

There have been no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2010 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).

Table of Contents

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Litigation

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, we do not expect that the ultimate disposition of any of these matters will have a material adverse effect on our financial condition, results of operations or cash flows. For a discussion of certain pending legal proceedings, see Note 11.

Item 1A. RISK FACTORS

Commencement of Operations at New Storage Facility Risk. Commencement of operations at our new Gill Ranch storage facility involves numerous operational risks that may result in accidents, additional costs and other business risks that could adversely impact our financial condition, results of operations and cash flows.

In October, 2010 we commenced operations at our Gill Ranch storage facility, which is designed to be a 20 bcf storage facility. Commencement of operations at a new storage facility involves many risks. Although we believe that Gill Ranch has been designed to meet our contractual obligations and project specifications with respect to injection, withdrawal and gas specifications, the facility is new and has a limited operating history. If we fail to inject or withdraw natural gas at the levels we expect or at contracted rates or cannot deliver natural gas consistent with our expectations or contractual specifications, we may not be able to obtain storage contracts at the levels and on the terms we expect, and we could incur significant costs to satisfy our contractual obligations under contracts we obtain. As a new facility, Gill Ranch is also subject to the risk that there may be structural integrity problems with the facility resulting in natural gas leakage or migration from our storage facilities, causing a loss of volumes stored and our inability to deliver the stored volumes back to our customers.

As a new facility, we may encounter problems maintaining, or the malfunction of, wellbores and related equipment and facilities that form a part of the infrastructure that is critical to the operation of our storage facilities. We are also reliant on the continued operation of a third-party pipeline and other facilities that provide delivery options to and from our storage facility. Because we do not own all of this pipeline, its operation is not within our control. If any of our critical infrastructure or the third-party pipeline to which we are connected were to become unavailable for current or future withdrawals or injections of natural gas due to repairs, damage to the infrastructure, lack of capacity or other reason, our ability to operate efficiently and satisfy our customers’ needs could be compromised, thereby potentially reducing our revenues.

Long-Term Stabilization of Gas Price Risk. Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on the demand for our natural gas storage services, which could adversely affect our financial results.

Storage businesses benefit from significant price fluctuations resulting from seasonal price sensitivity, which impacts the level of demand for services and the rates storage services are able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience volatility and seasonal price sensitivity in the future at the levels previously seen. If volatility and seasonality in the natural gas industry decrease, because of increased production capacity or otherwise, the demand for our services and the prices that we will be able to charge for those services may decline.

For additional risk factors, see Part I, “Item 1A. Risk Factors,” in our 2009 Form 10-K.

Table of Contents

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, 2010 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
07/01/10 - 07/30/10		884	$	44.89		-		-
08/01/10 - 08/31/10		22,493	$	46.21		-		-
09/01/10 - 09/30/10		1,332	$	46.68		-		-
Total		24,709	$	46.19		2,124,528	$	16,732,648

(1)

During the three months ended September 30, 2010, 21,257 shares of our common stock were purchased on the open market to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan. In addition, 3,452 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 three months ended September 30, 2010, 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 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 31, 2011 to repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million. During the three months ended September 30, 2010, 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.

Table of Contents

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 5, 2010

/s/ Stephen P. Feltz

Stephen P. Feltz

Principal Accounting Officer

Treasurer and Controller

Table of Contents

NORTHWEST NATURAL GAS COMPANY

EXHIBIT INDEX

Quarterly Report on Form 10-Q

For Quarter Ended

September 30, 2010

Exhibit
Number		Document

4		Form of Credit Agreement between Northwest Natural Gas Company and the banks that are party thereto, with JPMorgan Chase Bank, N.A., as administrative agent and Bank of America, N.A., as syndication agent, dated as of May 31, 2007, including Form of Note.

10.1		Letter agreement, dated September 15, 2010, between Richard Daniel and NW Natural Gas Storage, LLC.

10.2		Change in Control Severance Agreement, dated August 27, 2010, between Richard Daniel and NW Natural Gas Storage, LLC.

12		Computation of Ratio of Earnings to Fixed Charges

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

31.2		Certification of Principal Financial Officer Pursuant to
		Rule 13a-14(a)/15d-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, 2010, 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.



*		Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in these XBRL documents is unaudited and that these are not the official publicly filed financial statements of Northwest Natural Gas Company. In accordance with Rule 402 of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.