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~~March 31, 2011

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

For the Transition period from _______ to _______

Commission File No. 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices) (Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or ~~15 (d)~~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~~ (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~~April 30, 2011, 26,672,812 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~~March 31, 2011


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

Item 1.	Consolidated Financial Statements:

	Consolidated Statements of Income for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2011 and 2010 ~~and 2009~~	2

	Consolidated Balance Sheets at ~~September 30,~~March 31, 2011 and 2010 ~~and 2009~~ and December 31, ~~2009~~2010	3

	Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and 2010 ~~and 2009~~	5

	Notes to Consolidated Financial Statements	6

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2420

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4838

Item 4.	Controls and Procedures	4939

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	5040

Item 1A.	Risk Factors	5040

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	5140

Item 6.	Exhibits	5140

	Signature	5241

~~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”~~“expects” and similar references to future periods. Examples of forward-looking statements include, but are not limited to statements regarding the following:

plans;

·	objectives;

goals;

·	strategies;

·	future events or performance;

trends;

·	cyclicality;

·	earnings and dividends;

growth;

·	customer rates;

·	commodity costs;

·	~~financial condition;~~operational performance and costs;

·	liquidity and financial positions;

·	project development ~~of projects;~~and expansion;

·	competition;

·	~~exploration~~procurement and development of new gas supplies;

·	liquefied natural gas;

·	estimated expenditures;

·	costs of compliance;

·	credit exposures;

·	potential efficiencies;

·	impacts of ~~new~~ laws, rules and regulations;

·	tax liabilities or refunds;

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

·	projected obligations under retirement plans;

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

·	approval and adequacy of regulatory deferrals; and

·	environmental, regulatory, litigation and insurance costs and ~~recovery.~~recoveries.

Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks, and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you ~~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~~2010 Annual Report on Form 10-K, Part I, Item 1A. “Risk Factors” and Part II, Item 7. and Item 7A., ~~&# 8220;Management’s~~“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk,” ~~respectively.~~and in Part I, Items 2 and 3, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Quantitative and Qualitative Disclosures About Market Risk,” and Part II, Item 1A “Risk Factors,” herein.

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

~~Table of Contents~~

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Income
(Unaudited)


	Three Months Ended
	March 31,
Thousands, except per share amounts	2011		2010
Operating revenues:
Gross operating revenues	$	323,088	$	286,529
Less: Cost of sales		180,625		148,561
Revenue taxes		7,955		7,042
Net operating revenues		134,508		130,926
Operating expenses:
Operations and maintenance		31,172		30,666
General taxes		8,165		3,249
Depreciation and amortization		17,309		15,901
Total operating expenses		56,646		49,816
Income from operations		77,862		81,110
Other income and expense - net		1,214		3,023
Interest expense - net		10,449		10,489
Income before income taxes		68,627		73,644
Income tax expense		27,854		30,036
Net income	$	40,773	$	43,608
Average common shares outstanding:
Basic		26,670		26,538
Diluted		26,724		26,601
Earnings per share of common stock:
Basic	$	1.53	$	1.64
Diluted	$	1.53	$	1.64
Dividends declared per share of common stock	$	0.435	$	0.415

See Notes to Consolidated Financial Statements.

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)



	March 31,			March 31,			December 31,
Thousands	2011			2010			2010
Assets:
Current assets:
Cash and cash equivalents	$	3,480		$	8,839		$	3,457
Restricted cash		924			40,924			924
Accounts receivable		94,521			78,347			67,969
Accrued unbilled revenue		42,342			39,244			64,803
Allowance for uncollectible accounts		(3,821	)		(3,999	)		(2,950	)
Regulatory assets		48,195			55,872			52,714
Derivative instruments		4,861			450			2,245
Inventories:
Gas		43,501			61,918			70,672
Materials and supplies		9,765			9,235			9,713
Income taxes receivable		23,645			-			41,066
Other current assets		13,292			15,481			19,652
Total current assets		280,705			306,311			330,265
Non-current assets:
Property, plant and equipment		2,593,553			2,409,534			2,576,402
Less: Accumulated depreciation		733,639			702,307			722,239
Total property, plant and equipment - net		1,859,914			1,707,227			1,854,163
Regulatory assets		345,452			331,962			348,897
Derivative instruments		1,560			5			628
Other investments		69,501			67,558			69,094
Other non-current assets		14,421			15,970			13,569
Total non-current assets		2,290,848			2,122,722			2,286,351
Total assets	$	2,571,553		$	2,429,033		$	2,616,616

See Notes to Consolidated Financial Statements.

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)



	March 31,			March 31,			December 31,
Thousands	2011			2010			2010
Capitalization and liabilities:
Capitalization:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 26,673, 26,564 and 26,668 at March 31, 2011 and 2010, and December 31, 2010, respectively	$	343,787		$	338,012		$	342,978
Retained earnings		385,899			361,310			356,727
Accumulated other comprehensive income (loss)		(6,458	)		(5,870	)		(6,604	)
Total common stock equity		723,228			693,452			693,101
Long-term debt		551,700			601,700			591,700
Total capitalization		1,274,928			1,295,152			1,284,801

Current liabilities:
Short-term debt		186,435			96,000			257,435
Current maturities of long-term debt		50,000			35,000			10,000
Accounts payable		71,839			93,534			93,243
Taxes accrued		10,063			27,325			10,579
Interest accrued		11,470			12,232			5,182
Regulatory liabilities		29,016			36,032			17,828
Derivative instruments		25,655			39,365			38,437
Other current liabilities		38,433			36,060			35,457
Total current liabilities		422,911			375,548			468,161

Deferred credits and other non-current liabilities:
Deferred tax liabilities		396,357			311,691			373,409
Regulatory liabilities		263,876			247,517			258,031
Pension and other postretirement benefit liabilities		132,053			118,848			144,250
Derivative instruments		13,914			18,637			17,022
Other non-current liabilities		67,514			61,640			70,942
Total deferred credits and other non-current liabilities		873,714			758,333			863,654
Commitments and contingencies (see Note 14)		-			-			-
Total capitalization and liabilities	$	2,571,553		$	2,429,033		$	2,616,616

See Notes to Consolidated Financial Statements.

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)

	Three Months Ended
	March 31,
Thousands	2011			2010
Operating activities:
Net income	$	40,773		$	43,608
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		17,309			15,901
Undistributed earnings from equity investments		25			(356	)
Non-cash expenses related to qualified defined benefit pension plans		1,817			2,001
Contributions to qualified defined benefit pension plans		(13,645	)		(10,000	)
Deferred environmental expenditures		(1,759	)		(3,632	)
Other		(443	)		(2,431	)
Changes in assets and liabilities:
Receivables		(3,122	)		31,951
Inventories		27,119			9,804
Taxes accrued		16,905			6,288
Accounts payable		(14,406	)		(24,882	)
Interest accrued		6,288			6,797
Deferred gas costs		196			(15,428	)
Deferred tax liabilities		25,048			11,517
Other - net		5,959			3,018
Cash provided by operating activities		108,064			74,156
Investing activities:
Capital expenditures		(25,403	)		(52,774	)
Restricted cash		-			(5,381	)
Other		(121	)		782
Cash used in investing activities		(25,524	)		(57,373	)
Financing activities:
Common stock issued (purchased) - net		(244	)		566
Change in short-term debt		(71,000	)		(6,000	)
Cash dividend payments on common stock		(11,601	)		(11,011	)
Other		328			69
Cash used in financing activities		(82,517	)		(16,376	)
Increase in cash and cash equivalents		23			407
Cash and cash equivalents - beginning of period		3,457			8,432
Cash and cash equivalents - end of period	$	3,480		$	8,839

Supplemental disclosure of cash flow information:
Interest paid	$	4,162		$	3,325
Income taxes paid	$	-		$	9,000

See Notes to Consolidated Financial Statements.

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~~

NO~~RTHWEST~~NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Notes to Consolidated Financial Statements

(Unaudited)

1.	~~Summary~~ Organization and Principles of ~~Significant Accounting Policies~~Consolidation

~~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)~~(NNG Financial). Investments in corporate joint ventures and partnerships that we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for byunder the equity method or the cost method, which includes NWN ~~Enery's~~Energy’s investment in Palomar Gas Holdings, LLC (PGH). NW Natural and its affiliated companies are collectively referred to herein as “NW Natural.” The consolidated financial statements are presented after elimination of all significant intercompany balances and transactions, except for amounts required to be included under regulatory accounting standards to reflect the effect of such regulation.

In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe ~~all of our other business activities including~~ our gas storage ~~businesses~~business and other non-utility investments and business activities (see Note 2)4).

~~The information~~Information presented in ~~the~~these 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~~2010 Annual Report on Form 10-K ~~(2009~~(2010 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.

Our significant accounting policies are described in Note 12 of the ~~2009~~2010 Form 10-K. There were no material changes to those accounting policies during the ~~nine~~three months ended ~~September 30, 2010. See below~~March 31, 2011, except for a change in the application of our accounting policy with respect to revenue recognition for the regulatory adjustment for income taxes paid. For further discussion of ~~newly adopted standards and recent~~significant accounting ~~pronouncements. We do not have any subsequent~~policies, see Note 2 below. Subsequent events ~~to report.~~are reported in Note 15.

Certain prior year balances onin our consolidated financial statements have been combined or reclassified to conform towith 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~~2. Summary of ~~Contents~~Significant Accounting Policies

Industry Regulation

At ~~September 30,~~March 31, 2011 and 2010 ~~and 2009~~ and at December 31, ~~2009,~~2010, 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

	Regulatory Assets
	March 31,		March 31,		December 31,
Thousands	2011		2010		2010
Current:
Unrealized loss on derivatives(1)	$	25,655	$	39,365	$	38,437
Pension and other postretirement benefit liabilities(2)		10,988		7,502		10,988
Other(3)		11,552		9,005		3,289
Total current	$	48,195	$	55,872	$	52,714
Non-current:
Unrealized loss on derivatives(1)	$	13,914	$	18,637	$	17,022
Income tax asset		70,241		75,515		72,341
Pension and other postretirement benefit liabilities(2)		115,490		108,010		118,248
Environmental costs(4)		117,544		107,537		114,311
Other(3)		28,263		22,263		26,975
Total non-current	$	345,452	$	331,962	$	348,897

	Regulatory Liabilities
	March 31,		March 31,		December 31,
Thousands		2011		2010		2010
Current:
Gas costs payable	$	14,144	$	26,164	$	15,583
Unrealized gain on derivatives(1)		4,861		450		2,245
Other(3)		10,011		9,418		-
Total current	$	29,016	$	36,032	$	17,828
Non-current:
Gas costs payable	$	3,932	$	2,377	$	2,297
Unrealized gain on derivatives(1)		1,560		5		628
Accrued asset removal costs		256,203		242,952		252,941
Other(3)		2,181		2,183		2,165
Total non-current	$	263,876	$	247,517	$	258,031

(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~~liabilities of the utility are approved for regulatory deferral. Such amounts are recoverable in rates, including an interest component, when recognized in pension expense or net periodic benefit cost (see Note 6)9).

(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~~certain utility sites that are approved for regulatory deferral. We earn the utility’s 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~~

Revenue Recognition

Utility and non-utility revenues, which are derived primarily from the sale, transportation or storage of natural gas, are recognized upon the delivery of gas commodity or service to customers. Since 2007, utility revenues have also included the recognition of a regulatory adjustment for income taxes paid pursuant to a legislative rule (commonly referred to as SB 408) in effect for certain gas and electric utilities in Oregon. Under SB 408, we are required to automatically implement a rate refund, or a rate surcharge, to utility customers on an annual basis. The refund or surcharge amount is based on the estimated difference between income taxes paid and income taxes authorized to be collected in customer rates. We have recorded the estimated refund, or surcharge, each quarter since 2007 based on the estimated annual amount to be recognized. However, on March 29, 2011, a legislative bill was introduced that would repeal SB 408 if enacted as drafted in its current form (SB 967 or Bill). As of May 4, 2011, the Oregon Senate had approved SB 967, but the Bill has not been approved by the Oregon House of Representatives or signed by the Governor of Oregon. We currently believe there is substantial uncertainty surrounding the continuation of the current legal requirements of SB 408. Accordingly, we determined that the threshold for recognizing revenues under the accounting standard for the effects of regulation had not been met, and therefore we did not record an estimated refund, or surcharge, in the first quarter of 2011 for this regulatory adjustment for income taxes paid.

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 (i.e. level 3 valuations), including a rollforward schedule. These changes ~~are~~were effective for periods beginning after December 15, 2010; however, we elected to early adopt these disclosure requirements, as shown in Note ~~7 of~~9 in our ~~2009~~2010 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.

Recent Accounting Pronouncements

There have been no recent accounting pronouncements issued, but not yet effective, which are expected to have a material impact on our financial condition, results of operations or cash flows.

3.	Earnings Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during each period presented. Diluted earnings per share are computed using the weighted average number of common shares outstanding plus the potential effects of the assumed exercise of stock options, and ~~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				Three Months Ended
	September 30,						September 30,				March 31,
Thousands, except per share amounts	2010			2009			2010		2009		2011		2010
Net income (loss)	$	(7,420	)	$	(6,733	)	$	43,076	$	43,716
Net income											$	40,773	$	43,608
Average common shares outstanding - basic		26,606			26,515			26,571		26,508		26,670		26,538
Additional shares for stock-based compensation plans		-			-			70		100		54		63
Average common shares outstanding - diluted		26,606			26,515			26,641		26,608		26,724		26,601
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
Earnings per share of common stock - basic											$	1.53	$	1.64
Earnings per share of common stock - diluted											$	1.53	$	1.64

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For the three months ended ~~September 30,~~March 31, 2011 and 2010, 2,150 and ~~2009, 76,088 and 111,094~~5,120 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~~income 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.

2.4.	Segment Information

We operate in two primary reportable business segments, local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as “other.” We refer to our local gas distribution business as the “utility,” and our “gas storage” and “other” business segments as “non-utility.” Our “gas storage” segment includes ~~Gill Ranch, parts~~NWN Gas Storage, a wholly-owned subsidiary of NWN Energy, ~~and its~~Gill Ranch, a wholly-owned subsidiary of NWN Gas Storage, ~~and~~ the non-utility portion of ~~gas storage services related to~~ our Mist underground storage facility in ~~Oregon.~~Oregon (Mist) and third-party optimization services. Our “other” segment includes NNG Financial ~~Corporation, parts of NWN Energy, including an~~and our equity investment in PGH which is ~~developing a proposed natural gas transmission~~pursuing development of the Palomar pipeline ~~through its wholly-owned subsidiary Palomar Gas Transmission, LLC (Palomar).~~project. For further discussion of our segments, see Note 24 in our ~~2009~~2010 Form 10-K.

~~NWN Gas Storage was formed to manage our gas storage operations, including Gill Ranch. NWN Gas Storage commenced operations during~~The following table presents summary financial information about the ~~second quarter of 2010~~reportable segments for the three months ended March 31, 2011, and ~~was not operational during 2009.~~

2010. Inter-segment transactions were insignificant.

	Three Months Ended March 31
			Non-Utility
Thousands	Utility		Gas Storage		Other			Total
2011
Net operating revenues	$	129,162	$	5,304	$	42		$	134,508
Depreciation and amortization		15,914		1,395		-			17,309
Income from operations		76,124		1,716		22			77,862
Net income (loss)		40,130		688		(45	)		40,773
Total assets at March 31, 2011		2,304,731		244,403		22,419			2,571,553
2010
Net operating revenues	$	125,473	$	5,411	$	42		$	130,926
Depreciation and amortization		15,566		335		-			15,901
Income from operations		76,582		4,511		17			81,110
Net income		40,892		2,501		215			43,608
Total assets at March 31, 2010		2,190,849		217,266		20,918			2,429,033

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

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~~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

3.5.	~~Capital~~Common Stock

As of ~~September 30, 2010,~~March 31, 2011, our common shares authorized were 100,000,000 and our outstanding shares were ~~26,640,453.~~26,672,812.

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~~pursuant to this program during the ~~nine~~three months ended ~~September 30, 2010. To date,~~March 31, 2011, but since inception in 2000 a total of 2.1 million shares have been repurchased at a total cost of $83.3 ~~million under the existing share repurchase program.~~

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million.

4.6.	Stock-Based Compensation

We have several stock-based compensation plans, including a Long-Term Incentive Plan (LTIP), a Restated Stock Option Plan (Restated SOP) and an Employee Stock Purchase Plan. These plans are designed to promote stock ownership in NW Natural by employees and officers. For additional information on our stock-based compensation plans, see Part II, Item 8., Note 4,6, in the ~~2009~~2010 Form 10-K and current updates provided below.

Long-Term Incentive Plan. On February ~~24, 2010, 41,500~~23, 2011, 37,950 performance-based shares were granted under the LTIP, which include a market condition, based on target-level awards and a weighted-average grant date fair value of ~~$25.64~~$25.25 per share. Fair value was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:

~~Stock price on valuation date~~	$	~~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~~

Stock price on valuation date	$	45.74
Performance term (in years)		3.0
Quarterly dividends paid per share	$	0.435
Expected dividend yield		3.7	%
Dividend discount factor		0.8930

In February ~~2010,~~2011, the Board approved a payout of performance-based stock awards under the LTIP for the ~~2007-09~~2008-10 award period. Shares of common stock were purchased on the open market to satisfy ~~the approved~~these awards.

Restated Stock Option Plan. On February ~~24, 2010,~~23, 2011, options to purchase ~~119,750~~122,700 shares were granted under the Restated SOP, with an exercise price equal to the closing market price of ~~$44.25~~$45.74 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~~$6.73 per share. Fair value was estimated as of the date of grant using the Black-Scholes option pricing model based on the following assumptions:

Risk-free interest rate	~~2.3~~	2.0	%
Expected life (in years)	~~4.7~~	4.5
Expected market price volatility factor	~~23.2~~	24.5	%
Expected dividend yield		3.8	%
Forfeiture rate	~~3.2~~	3.1	%

As of ~~September 30, 2010,~~March 31, 2011, there was ~~$1.0~~$1.3 million of unrecognized compensation cost related to the unvested portion of outstanding ~~stock option~~Restated SOP awards expected to be recognized over a period extending through ~~2013.~~

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2014.

5.7.	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~~with maturity dates from ~~2010~~2011 through 2035, ~~and have~~ interest rates ranging from 3.95 percent to 9.05 percent, ~~with~~and a weighted-average coupon rate of ~~6.19 percent (see Note 5 in our 2009 Form 10-K).~~6.17 percent. For the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011, 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 andFor more detail on our outstanding long-term debt, ~~and to provide utility working capital for general corporate purposes.~~see Note 7 in our 2010 Form 10-K.

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 other company’s outstanding debt issues that actively trade and have similar credit ratings, terms and remaining maturities to estimate fair value ~~for~~of our long-term debt issues. These are significant other observable inputs, or level 2 inputs, in the fair value hierarchy.

	September 30,				December 31,		March 31,				December 31,
Thousands	2010		2009		2009		2011		2010		2010
Carrying amount	$	636,700	$	637,000	$	636,700	$	601,700	$	636,700	$	601,700
Estimated fair value	$	740,731	$	670,116	$	707,755	$	680,436	$	687,937	$	690,126

8.	Comprehensive Income

Items excluded from net income and charged directly to stockholders’ equity are included in accumulated other comprehensive income (loss), net of tax. The amount of accumulated other comprehensive loss in stockholders’ equity is $6.5 million and $5.9 million as of March 31, 2011 and 2010, respectively, which is related to employee benefit plan liabilities. The following table provides a reconciliation of net income to total comprehensive income for the three months ended March 31, 2011 and 2010.

	Three Months Ended
	March 31,
Thousands	2011		2010
Net income	$	40,773	$	43,608
Amortization of employee benefit plan liability, net of tax		146		98
Total comprehensive income	$	40,919	$	43,706

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6.9.	Pension and Other Postretirement ~~Benefits~~Benefit Costs

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

	Three Months Ended September 30,												Three Months Ended March 31,
							Other Postretirement												Other Postretirement
	Pension Benefits						Benefits						Pension Benefits						Benefits
Thousands	2010			2009			2010			2009			2011			2010			2011			2010
Service cost	$	1,435		$	1,472		$	156		$	147		$	1,899		$	1,773		$	168		$	156
Interest cost		4,517			4,474			343			405			4,527			4,491			344			343
Expected return on plan assets		(4,528	)		(3,783	)		-			-			(4,456	)		(4,564	)		-			-
Amortization of loss		2,028			1,786			7			5
Amortization of prior service cost		(270	)		307			50			50
Amortization of transition obligation		-			-			103			103
Amortization of net actuarial loss														2,692			1,768			68			7
Amortization of prior service costs														88			206			49			49
Amortization of transition obligations														-			-			103			103
Net periodic benefit cost		3,182			4,256			659			710			4,750			3,674			732			658
Amount allocated to construction		(897	)		(1,220	)		(231	)		(233	)		(1,235	)		(953	)		(226	)		(208	)
Net amount charged to expense	$	2,285		$	3,036		$	428		$	477		$	3,515		$	2,721		$	506		$	450

	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 7,9, in the ~~2009~~2010 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~~cost 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 curr ent plan year and remained in “critical status.” Athis plan is ~~considered~~in addition to bepension expense 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.table above. The Western States Plan ~~board of~~has reported an accumulated funding deficit for the current plan year and remains in critical status. The Western States Plan 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 ~~c hanges~~changes are expected to improve the funding status of the plan. ~~Contribution surcharges above 10 percent will be assessed~~We made contributions totaling $0.1 million 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~~for both the three months ended March 31, 2011 and 2010. If we withdraw and the plan is underfunded, we could be assessed a withdrawal liability. WeCurrently, we have no ~~current~~ intent to withdraw from the plan, so we have not recorded a withdrawal liability.

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Employer Pension Contributions

~~In February 2010,~~During the first quarter of 2011 we made ~~a $10~~cash contributions totaling $13.6 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.~~plans. We also ~~continue~~expect to contribute up to an additional $10 million to these qualified plans over the last nine months of 2011, plus we expect to make ~~cash contributions for~~ongoing benefit payments under our unfunded, non-qualified pension plans and other postretirement benefit plans. For more information see Part II, Item 8., Note 7,9, in the ~~2009~~2010 Form 10-K.

7.10. Income Tax

The effective income tax rate for the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and 2010 ~~and 2009~~ varied from the combined federal and state statutory tax rates principally due to the following:

	September 30,						March 31,
	2010			2009			2011			2010
Federal statutory tax rate		35.0	%		35.0	%		35.0	%		35.0	%
Increase (decrease):
Current state statutory income tax rate, net of federal tax benefit		4.8	%		4.5	%
Current state income tax, net of federal tax benefit								4.6	%		4.9	%
Amortization of investment and energy tax credits		(0.4	) %		(0.4	) %		-0.4	%		-0.5	%
Differences required to be flowed-through by regulatory commissions		1.2	%		(0.1	) %		1.5	%		1.5	%
Gains on company and trust-owned life insurance		(0.8	) %		(1.4	) %		-0.2	%		-0.2	%
Other - net		0.5	%		0.4	%		0.1	%		0.1	%
Effective tax rate		40.3	%		38.0	%
Effective income tax rate								40.6	%		40.8	%

The ~~increase~~decrease in our effective tax rate for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 compared to the same period in ~~2009~~2010 was minor and primarily due to ~~an increase~~a change in state income tax rates. See Note 10 in our 2010 Form 10-K.

11.	Property, Plant and Equipment

The following table sets forth the ~~amortization rate~~major classifications of our ~~regulatory tax asset pursuant to a regulatory order effective November 1, 2009, which we recover in utility rates.~~property, plant and equipment and accumulated depreciation as of March 31, 2011 and 2010 and December 31, 2010:

	March 31,				December 31,
Thousands	2011		2010		2010
Utility plant in service	$	2,264,055	$	2,206,571	$	2,247,952
Utility construction work in progress		28,464		25,736		29,324
Less: Accumulated depreciation		720,134		691,420		710,214
Utility plant-net		1,572,385		1,540,887		1,567,062
Non-utility plant in service		292,089		66,084		290,038
Non-utility construction work in progress		8,945		111,143		9,088
Less: Accumulated depreciation		13,505		10,887		12,025
Non-utility plant-net	$	287,529	$	166,340	$	287,101

Total property, plant and equipment	$	1,859,914	$	1,707,227	$	1,854,163

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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

12. 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~~methods. See Part II, Item 8., Note 9,12, in the ~~2009~~2010 Form 10-K for more detail on our ~~investments).~~investments.

Variable Interest Entities.PGH is a ~~VIE~~development stage variable interest entity. Palomar, a wholly-owned subsidiary of PGH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. PGH is owned 50 percent by usNWN Energy and 50 percent by Gas Transmission Northwest Corporation (GTN), 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,~~March 31, 2011, we updated our VIE analysis and determined that we are not the primary beneficiary of PGH’s activities as defined by the authoritative guidance related to ~~consolidations (see Note 1).~~consolidations. 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~~March 2011, Palomar withdrew its original application with 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~~Federal Energy Regulatory Commission (FERC) for a ~~majority of~~proposed natural gas pipeline in Oregon. At the ~~transmission capacity on the proposed pipeline. As of September 30, 2010,~~same time, 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~~informed FERC that 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~~intends to file an application later this year or in 2012 to reflect changes in the ~~form of~~project and more closely align with the region’s current and future gas needs. Palomar is working with customers in the Northwest to further understand their gas transportation needs. Assuming Palomar obtains commercial support for its revised pipeline proposal, Palomar expects to file a ~~lien on assets of the bankrupt shipper under terms of the current precedent agreement.~~new certificate application with FERC.

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~~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~~March 31, 2011 and determined that nowe did not have any impairment ~~write-down is needed~~ because the fair value of ~~the~~ expected cash flows from development of this pipeline ~~will exceed~~project exceeds our ~~total~~ equity investment. If, however, we learn that the project is not viable or will not go forward, then we could be required to recognize an impairment ~~loss~~charge of up to ~~$14.1~~approximately $14.4 million based on the amount of our equity investment of $14.8 million as of ~~September 30, 2010~~March 31, 2011 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.~~13.

Derivative Instruments

We enter into swap, option and ~~combinations of~~various option ~~contracts~~combinations 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.~~gas. 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~~requirements. A small portion of the derivatives are also related to ~~our long-term debt issuances.~~foreign currency exchange transactions.

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)~~PGA filing receive regulatory deferred accounting treatment. Derivative contracts entered into after the annual PGA rate was set on November 1, ~~2009~~2010 that are for the current gas contract year are subject to our PGA incentive sharing mechanism, which provides for a 90 percent deferral of ~~the changes in fair value to be deferred~~any gains and losses as regulatory assets or liabilities, ~~and~~with the remaining 10 percent ~~to be recorded to~~recognized on 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.~~statement.

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~~2010-11 gas ~~contract~~ year (November 1, ~~2009~~2010 – October 31, ~~2010)~~2011) hedged at a ~~targeted~~ level of 75approximately 77 percent, including 6062 percent financially hedged and 15 percent physically hedged ~~through~~with 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.~~in storage.

At ~~September 30, 2010,~~March 31, 2011, we were hedged with financial contracts for the upcoming 2011-12 gas ~~contract~~ year at approximately 7750 percent based on anticipated sales volumes. ~~At September 30, 2010, we were also~~Of the amount currently hedged for the 2011-12 gas year approximately 35 percent was hedged with financial contracts ~~for the 2011-12 gas contract year between 20~~ and 25an additional 15 percent attributable to storage from future purchases and ~~for the 2012-13 gas contract year between 5 and 10 percent.~~

current storage levels.

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~~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.

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The following table discloses the income statement presentation for the unrealized gains and losses from our derivative instruments for the ~~three~~years ended March 31, 2011 and ~~nine months ended September 30, 2010 and 2009.~~2010. All of our currently outstanding derivative instruments are related to regulated utility operations as illustrated by the derivative gains and losses being deferred to the balance sheet accounts in accordance with regulatory ~~accounting standards.~~accounting.

		Three Months Ended													Three Months Ended
		September 30, 2010						September 30, 2009							March 31, 2011							March 31, 2010
Thousands	Thousands	Natural gas commodity(1)			Foreign exchange (2)			Natural gas commodity(1)			Foreign exchange (2)			Thousands		Natural gas commodity(1)			Foreign currency (2)				Natural gas commodity(1)			Foreign currency (2)
Cost of sales	Cost of sales	$	(35,744	)	$	-		$	50,149		$	-		Cost of sales		$	(33,750	)	$	-			$	(57,564	)	$	-
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	)
Other comprehensive income (loss)														Other comprehensive income (loss)			-			602				-			(17	)
Less:	Less:													Less:
Amounts deferred to regulatory accounts on balance sheet	Amounts deferred to regulatory accounts on balance sheet		84,837			(110	)		23,112			341		Amounts deferred to regulatory accounts on balance sheet			33,750			(602	)			57,564			17
	Total impact on earnings	$	-		$	-		$	-		$	-		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.													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.													Unrealized gain (loss) from foreign currency exchange contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet.

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~~Our derivative liabilities exclude the netting of collateral.~~ We had no collateral posted with our counterparties as of ~~September 30, 2010~~March 31, 2011 or ~~2009.~~2010. 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~~$25 million to ~~$25~~$50 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 ~~mater ial~~material adverse change. Based upon current contracts outstanding, which reflect unrealized losses of ~~$86.2~~$33.1 million at ~~September 30, 2010,~~March 31, 2011, we have estimated the ~~projected~~level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various downgrade credit rating scenarios for NW Natural as follows:

			Credit Rating Downgrade Scenarios										Credit Rating Downgrade Scenarios
Thousands	(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3		Speculative		(Current Ratings) A+/A3		BBB+/Baa1		BBB/Baa2		BBB-/Baa3		Speculative
With Adequate Assurance Calls	$	-	$	3,745	$	8,745	$	14,695	$	42,345	$	-	$	-	$	-	$	3,223	$	18,058
Without Adequate Assurance Calls	$	-	$	3,745	$	8,745	$	14,695	$	42,345	$	-	$	-	$	-	$	3,223	$	14,897

In the three ~~and nine~~ months ended ~~September 30,~~March 31, 2011 and 2010, we realized net losses of ~~$12.6~~$20.9 million and ~~$33.3~~$6.2 million, respectively, from the settlement of natural gas hedge contracts at maturity, which were recorded as increases to the cost of ~~gas, compared to net losses of $29.1 million and $150.8 million, respectively, for the three and nine months ended September 30, 2009.~~gas. The ~~currency~~ exchange rate in all foreign currency forward purchase contracts is included in our purchased cost of gas at settlement; therefore, no gain or loss is recorded from the settlement of those contracts. We 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 o f the debt.

We are exposed to derivative credit and liquidity risk primarily through securing ~~pay-fixed~~fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of our 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~~For more information 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 changeinstruments, see Note 13 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,our 2010 ~~currently does not extend beyond October 2013.~~Form 10-K.

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.

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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.~~March 31, 2011. As of March 31, 2011 and 2010 and December 31, 2010, the fair value was $33.1 million, $57.5 million and $52.6 million, respectively, using significant other observable, or level 2, inputs. We have used no level 3 inputs in our derivative valuations. We also did not have any transfers between level 1 or level 2 during the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 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 )
2010.

~~11.~~14.

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, in some cases, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases we have disclosed the nature of the potential loss ~~beyond the amounts currently accrued,~~ and the ~~probabilities thereof,~~fact that the high end of the range cannot ~~currently~~ be reasonably estimated. ~~See Part II, Item 8., Note 11,~~

We regularly review our environmental liability for each site where we may be exposed to remediation responsibilities. The costs of environmental remediation are difficult to estimate. A number of steps are involved in each environmental remediation effort, including site investigations, remediation, operations and maintenance, monitoring and site closure. Each of these steps may, over time, involve a number of alternative actions, each of which can change the ~~2009 Form 10-K.~~ course and scope of the effort. Many of these steps are dependent upon the approval and direction of federal and state environmental regulators. The policies, determinations and directions of the regulators may develop and change over time and different regulators may take different positions on the various steps, creating further uncertainty as to the timing and scope of remediation activities. In certain cases, in addition to us, there are a number of other potentially responsible parties, each of which, in proceedings and negotiations with other potentially responsible parties and regulators, may influence the course and scope of the remediation effort. The allocation of liabilities among the potentially responsible parties is often subject to dispute and can be highly uncertain. The events giving rise to environmental liabilities often occurred many decades ago, which complicates the determination of allocating liabilities among potentially responsible parties. Site investigations and remediation efforts often develop slowly over many years. In addition, disputes may arise between potentially responsible parties and regulators as to the severity of particular environmental matters and what remediation efforts are appropriate. These disputes could lead to adversarial administrative proceedings or litigation, with uncertain outcomes.

We estimate the range of loss for environmental liabilities using current technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is an estimate within this range of possible losses that is more likely than other cost estimates, we record the liability at the lower end of this range. It is likely that changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to uncertainty concerning our responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives. The status of each ~~site~~of the sites currently under investigation is provided below.

Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 ~~(the Gasco~~(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~~We also submitted a Focused Feasibility Study (FFS) for the groundwater source control ~~OD EQ~~portion of the Gasco site, which ODEQ conditionally approved ~~the FFS~~ in March 2008, subject to the submission of additional information. We provided that information to ODEQ and are now working with the agency on the final design for the source control system. ~~During~~Based on the ~~third quarter~~information currently available for groundwater source control at the Gasco site and our current assumptions regarding remediation, we have estimated a range of ~~2009,~~liability between $11 million and $30 million, for which we have recorded an accrued liability of $11.8 million at March 31, 2011. The range of liability will be reassessed when ODEQ makes a final source control design decision. In addition to groundwater source control, we signed a joint Order on Consent with the Environmental Protection Agency (EPA), which requires the design of ~~a final~~ remedial action for sediments from the Gasco ~~sediments. The~~site. This design project is underway. We also have ~~a liability accrued~~other investigation and clean-up work, including work on the uplands portion of ~~$51.3 million at September 30, 2010 for~~ the Gasco site, that we expect to be required. For the sediments project and other work, we have recorded an additional accrued liability of $38.0 million, which ~~is estimated~~reflects the low end of the range of potential liability. We have accrued at the low end of the range of potential liability for the sediments project and other environmental work at the Gasco site because no amount within the range is considered to be more likely than another, and the high end of the range cannot reasonably be estimated.

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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~~March 31, 2011 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 ~~a re~~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,~~March 31, 2011, 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~~(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 ~~confir med~~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,~~March 31, 2011, we have a liability accrued of $0.5 million for investigation at this site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated. It is near but outside the geographic scope of the current Portland Harbor site sediment ~~studies, the~~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 ~~OD EQ~~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.~~underway. As of ~~September 30, 2010,~~March 31, 2011, we have an estimated liability accrued of ~~$1.1~~$0.9 million for the study of the ~~site, which will include investigation of~~ sediments ~~upland~~and riverbank groundwater and soils ~~and reporting of historical upland activities.~~at the site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

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

Accrued Liabilities Relating to Environmental ~~Sites~~.Sites. The following table summarizes the accrued liabilities relating to environmental sites at ~~September 30,~~March 31, 2011 and 2010 ~~and 2009~~ and December 31 ~~2009:~~2010:

	Current Liabilities						Non-Current Liabilities						Current Liabilities						Non-Current Liabilities
	Sept. 30,		Sept. 30,		Dec. 31,		Sept. 30,		Sept. 30,		Dec. 31,		Mar. 31,		Mar. 31,		Dec. 31,		Mar. 31,		Mar. 31,		Dec. 31,
Thousands	2010		2009		2009		2010		2009		2009		2011		2010		2010		2011		2010		2010
Gasco site	$	7,738	$	8,729	$	9,841	$	43,597	$	42,295	$	43,659	$	13,718	$	9,924	$	11,366	$	36,099	$	42,165	$	38,921
Siltronic site		746		708		653		275		393		593		730		679		720		291		508		201
Portland Harbor site		2,712		-		2,114		5,594		7,820		7,272		2,219		1,873		2,304		5,829		7,041		5,784
Central Service Center site		5		-		5		510		517		511		5		5		5		501		511		510
Front Street site		72		419		72		1,039		-		436		-		72		1		947		252		1,097
Other sites		-		-		-		110		177		123		-		-		-		117		106		108
Total	$	11,273	$	9,856	$	12,685	$	51,125	$	51,202	$	52,594	$	16,672	$	12,553	$	14,396	$	43,784	$	50,583	$	46,621

Regulatory and Insurance Recovery for Environmental Costs. In May 2003, the ~~Oregon~~ Public Utility Commission of Oregon (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~~was extended through January 2010. We have filed a request with the OPUC to extend this deferral, and expect authorization during the second quarter of 2011. In addition, we filed a request with the Washington Utilities and Transportation Commission (WUTC) in February 2011 to defer certain environmental costs associated with services provided to Washington customers, and expect an order from the WUTC during the second quarter of 2011.

On a cumulative basis, we have recognized a total of ~~$104.0~~$106.3 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,~~March 31, 2011, we had a regulatory asset of ~~$111.9~~$117.5 million, which includes ~~$42.2~~$47.1 million of total paid expenditures to date, ~~$57~~$60.5 million for additional environmental costs expected to be paid in the future and accrued interest of ~~$12.7 million. While~~$15.3 million, partially offset by $5.4 million of environmental costs expensed in prior years. See table below.

In December 2010, NW Natural commenced litigation against certain of its historical liability insurers in Multnomah County Circuit Court, State of Oregon, Case Number 1012-17532. The defendants include Associated Electric & Gas Insurance Services Limited, Allianz Global Risk US Insurance Company, certain underwriters at Lloyd's London, certain London market insurance companies and ten other insurance companies. In the suit, NW Natural alleges that the defendant insurance companies issued third party liability insurance policies to NW Natural and that the defendants have breached the terms of those policies by failing to indemnify NW Natural for liabilities arising from environmental contamination at certain sites caused or alleged to be caused by its historical operations. NW Natural seeks damages in excess of $40 million in losses it has incurred to date, as well as declaratory relief for additional losses it expects to incur in the future. After seeking recovery of our environmental costs from our insurers, we believe recovery of ~~these~~the remainder of our deferred charges, if any, 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.~~process. 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.

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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~~concluded our insurance recovery efforts during that time ~~period.~~period, and because recovery would be expected to occur through the implementation of new rates through a general rate proceeding. 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,~~March 31, 2011 and 2010 ~~and 2009~~ and December 31, ~~2009:~~2010:

	Non-Current Regulatory Assets						Non-Current Regulatory Assets
	September 30,		September 30,		December 31,		March 31,		March 31,		December 31,
Thousands	2010		2009		2009		2011		2010		2010
Gasco site	$	72,531	$	66,105	$	69,607	$	76,338	$	70,411	$	74,205
Siltronic site		3,120		2,750		2,974		3,440		3,020		3,174
Portland Harbor site		33,316		29,239		31,500		34,732		32,140		33,940
Central Service Center site		551		548		550		558		550		553
Front Street site		2,000		700		910		2,042		1,032		2,020
Other sites		413		469		507		434		384		420
Total	$	111,931	$	99,811	$	106,048	$	117,544	$	107,537	$	114,312

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 ~~remedia l~~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.

15. Subsequent Event

On April 28, 2011 the OPUC issued an order approving our investment to develop gas reserves on behalf of our Oregon customers under an agreement with Encana Oil & Gas (USA) Inc. Under the agreement, we expect to invest approximately $45-55 million a year, over a five-year period, for a total investment of about $250 million, which will cover a portion of drilling costs in exchange for working interests in certain sections of the Jonah Field located north of Rock Springs, Wyoming. These sections include both future and current producing wells. The gas reserves will provide long-term gas supplies for our Oregon utility customers over a period expected to be about 30 years. During the first 10 years of the agreement, we forecast to receive approximately 58 billion cubic feet (Bcf) from the transaction, or 8-10 percent of our average annual requirements for utility operations. Our total investment under the agreement is expected to result in about 93 Bcf of gas at an average all-in price of approximately $5.15 per dekatherm. We estimate net present value savings to customers of over $50 million over the life of the investment as compared to other long-term supply alternatives.

Under the order, the OPUC determined that the investment was prudent and that the Company is allowed to recover its costs under the agreement on an ongoing basis through its Purchased Gas Adjustment (PGA) cost sharing mechanism, including the deferral process for the commodity cost of gas. Annually, the Company will forecast amounts related to the costs and volumes expected, and variances will be subject to the PGA’s normal sharing mechanism up to $10 million of variance. Any variance in excess of $10 million, either negative or positive, will be passed through to customers at 100 percent, rather than at the 80 or 90 percent level associated with the normal sharing mechanism. As part of the decision by the OPUC to approve the Company’s investment, we will file a general rate case in Oregon no later than December 31, 2011.

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~~NORTHWEST NATURAL GAS COMPANY~~

~~PART I. FINANCIAL INFORMATION~~

~~Item~~

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~~The discussion refers to our consolidated activities for the three ~~and nine~~ months ended ~~September 30, 2010~~March 31, 2011 and ~~2009.~~2010. 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~~2010 Annual Report on Form 10-K ~~(2009~~(2010 Form 10-K).

The consolidated financial statements include the accounts of NW Natural and its direct and indirect wholly-owned ~~subsidiaries:~~subsidiaries which include: Gill Ranch Storage, LLC (Gill Ranch), NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), and NNG Financial Corporation ~~(Financial Corporation), and~~(NNG Financial). These statements also include accounts related to an equity investment in Palomar Gas Holdings, LLC (PGH), which is ~~developing~~pursuing the development of a proposed natural gas pipeline through its wholly-owned subsidiary Palomar Gas Transmission LLC (Palomar). ~~These~~Together these accounts ~~include~~make up our regulated local gas distribution business, our gas storage ~~business,~~businesses, and other regulated and non-regulated investments primarily engaged in energy-related businesses. In this report, the term “utility” is used to describe our regulated ~~local~~ gas distribution ~~segment,~~business (local distribution company), and the term “non-utility” is used to ~~descri be~~describe our gas storage ~~segment~~businesses (gas storage) as well as our other regulated and non-regulated investments and business activities ~~(other segment) (see “Strategic Opportunities,” below, and~~(other). For a further discussion of our business segments, see Note ~~2).~~4.

In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on consolidated earnings. All references in this section to earnings per share are on the basis of diluted shares (see Part II, Item 8., Note 1,3, “Earnings Per Share,” in our ~~2009~~2010 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 operatio ns 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~~Highlights of the ~~third~~first quarter of 2011 as compared to the same period in 2010 include:

·	Consolidated earnings ~~decreased $0.7~~of $40.8 million ~~from a net loss of $6.7 million~~or $1.53 per share in the ~~third~~first quarter of ~~2009~~2011, as compared to ~~a net loss of $7.4~~$43.6 million and $1.64 in the ~~third~~first quarter of 2010;

~~Results~~Net income from utility operations ~~increased $0.1~~decreased $0.8 million, from ~~a net loss of $9.2~~$40.9 million in ~~2009~~2010 to ~~a net loss of $9.1~~$40.1 million in ~~2010;~~2011, largely due to benefits received last year from a property tax refund and the regulatory adjustment for income taxes paid (see Revenue Recognition below under Application of Critical Accounting Policies and Estimates for further discussion of the regulatory adjustment for income taxes paid);

~~Results~~Net income from gas storage operations decreased ~~$0.5~~$1.8 million, from ~~net income of $2.3~~$2.5 million in ~~2009~~2010 to ~~$1.8~~$0.7 million in ~~2010;~~2011, primarily reflecting Gill Ranch’s initial start-up costs and lower level of contracted capacity prior to its first injection season beginning April 1, 2011;

·	Consolidated net operating revenues (margin) ~~decreased 5~~increased $3.6 million or 3 percent ~~from $48.6 million in 2009 to $46.2 million in~~over 2010, with utility margin ~~down 5 percent or $2.4~~up $3.7 million and gas storage margin down 1$0.1 million;

·	Consolidated total operating expenses increased $6.8 million or 14 percent ~~or $0.1 million;~~over 2010, but that was largely attributed to a $5.2 million refund of property tax expense at the utility in 2010 and start-up costs at Gill Ranch;

·	Other income decreased $1.8 million in 2011 compared to 2010, primarily due to $1.9 million of interest income received by the utility in 2010 in connection with the property tax refund referred to above;

·	Cash flow from ~~operations decreased 43 percent, from $199.3~~operating activities in 2011 was $108.0 million, ~~in 2009 to $114.5~~for an increase of $33.9 million ~~in 2010;~~

·	~~Utility customer growth rate was slightly above 1~~or 46 percent over ~~the last 12 months;~~2010; and

The ~~Board approved~~utility added more than 6,000 new customers over the last 12 months, for an annual growth rate of 0.9 percent compared to 0.7 percent 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.~~year ago.

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Issues, Challenges and Performance Measures

Economic ~~weakness.~~Environment. ~~Ongoing weakness~~Weakness in the local, national and ~~U.S.~~global economies has continued to adversely impact utility customer growth, ~~and business~~the 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~~gas, and the ~~economy may be stabilizing.~~value of natural gas storage services. Most recently, our utility’s annual customer growth rate increased slightly to ~~1.2~~0.9 percent at ~~September 30, 2010~~March 31, 2011, as 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~~March 31, 2010. Although total delivered volumes to ~~last year on lower delinquent balances. Despite these improvements,~~utility customers in the first quarter of 2011 increased 20 percent, we are still faced with ~~10 to 11 percent~~ unemployment rates around 10 percent in our service territories of Oregon and southwest Washington and a sluggish business ~~environment . Regardless of~~environment. Despite these challenges, we believe we are well positioned to continue adding ~~distribution~~utility customers due to ~~our~~lower natural gas prices, a relatively low market penetration rate, our ongoing 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~~Gas Prices and ~~supplies.~~ Supplies.Our gas acquisition strategy is ~~designed~~regularly updated to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices toso that we can effectively manage costs, reduce price volatility and maintain a competitive advantage. With recent ~~success~~developments in ~~new~~ drilling technologies and substantial ~~new~~access to supplies from shale gas formations around the U.S. and in Canada, the supply ofoutlook for North American natural gas has increased dramatically, which ~~has contributed~~is contributing to lower and more stable 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 currentl y hedged on~~with gas commodity prices ~~for~~hedged at approximately 77 percent of our forecasted purchase ~~volumes, in~~volumes. In addition, ~~to being~~we are currently hedged ~~between 20 and 25~~at approximately 50 percent for the 2011-12 gas contract year and between 5 and 10 percent for the 2012-13 gas contract year. ~~Our~~The Purchased Gas Adjustment (PGA) ~~mechanism,~~mechanisms in Oregon and Washington, along with our own gas price hedging strategies and gas supplies in storage, enable us to reduce earnings risk exposure for the company and secure lower gas costs for our customers. These lower gas prices, coupled with ~~good customer~~quality service and energy ~~efficiency~~saving 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. See discussion of Utility Investment in Gas Reserves below under Strategic Opportunities.

Although ~~lower~~stable gas prices provide opportunities to manage costs for our ~~distribution~~utility customers, they also present challenges for our ~~s torage~~gas storage business by lowering the value of, and reducing the demand for, storage services ~~and~~thus limiting Gill Ranch’s ability to ~~contract~~sign customer contracts for longer terms at favorable prices.

Environmental ~~investigation and remediation costs.~~ 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~~allowed to defer certain costs pursuant to regulatory ~~decisions including~~decisions. In 2010 and prior years, we were authorized by the Public Utility Commission of Oregon (OPUC) to defer certain environmental costs, and to seek recovery of ~~these~~those amounts in future rates to customers. For 2011, we have a request pending before the OPUC to approve an extension of the deferral order for certain environmental costs. However, before we can 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 these costs and demonstrate ~~that costs~~they were prudently incurred. Recovery may vary significantly from amounts currently recorded as regulatory assets, and amounts not recovered would be required to be charged to income in the period they were deemed to be unrecoverable. See Results of Operations—Regulatory Matters—Rate Mechanisms—Regulatory Recovery for Environmental Costs below, Note 1114 in this report and Note 1115 in our ~~2009~~2010 Form 10-K.

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

~~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 ou r 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.

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~~Strategies and~~ Performance ~~Measures~~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~~utility gas distribution ~~business;~~services and operations; 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 ofon certain metrics including, but not limited to: earnings per share growth; total shareholder return; return on ~~inves ted~~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 develop, 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.~~Operations. 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 pi peline.

Gill Ranch ~~started storage injections and limited commercial~~began operations ~~in October~~during the fourth quarter of 2010. Gill Ranch is offering storage services to the California market at ~~market based~~market-based rates, subject to ~~CPUC~~California Public Utilities Commission (CPUC) regulation including, but not limited to, service terms and conditions, tariff regulations, and security issuances. Due to increasing supplies and price stability of natural gas in North America, and declining demand for natural gas due to current economic conditions, ~~current~~ storage values are expected to remain low in the near term, which ~~may~~will likely affect the prices at which Gill ~~Ranch’s ability~~Ranch is able to ~~contract longer term at favorable prices~~contract. For more information, see Note 4 in this report and ~~may negatively impact earnings and cash flows.~~Part II, Item 7., “2011 Outlook—Strategic Opportunities,” in our 2010 Form 10-K.

The ~~Oregon gas~~Pacific Northwest storage markets ~~have~~ also ~~been~~are negatively impacted by lower gas prices ~~although~~and lack of gas price volatility, but less so than in ~~California. We~~California and many other markets around the country because of limited availability of storage capacity. In 2011, we expect to continue ~~to make plans~~planning for ~~expanding~~possible expansion at our ~~interstate~~gas storage facilities near Mist, Oregon in anticipation of increased demand for electric generation in the Pacific Northwest. Currently we do not have a set timeline for the next expansion at Mist, ~~Oregon. To complete the studies necessary for development of the next storage project at Mist,~~but 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~~completion would be no earlier than 2013 or ~~2012, but~~2014. In the meantime, we ~~have not committed to a targeted construction schedule or in-service date at this time. We~~will continue to monitor the market demand and work on preliminary design and project ~~scope,~~planning, which ~~we expect~~ will ~~include~~ultimately require the development of storage wells, potentially a second compression station and aadditional pipeline gathering ~~system tha t~~facilities that will ~~also~~ enable future storage ~~expansions, as well as updates to our construction cost estimates.~~

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expansions.

Pipeline Diversification. Currently, our utility and Mist gas storage ~~at Mist depends~~operations depend on a single bi-directional interstate transmission pipeline to ship gas supplies. Palomar, a wholly-owned subsidiary of PGH, ~~seeks to build~~is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. PGH is owned 50 percent by usNWN Energy and 50 percent by Gas Transmission Northwest Corporation (GTN), an indirect wholly-owned subsidiary of TransCanada Corporation. The ~~proposed~~ Palomar pipeline ~~is designed~~was originally proposed with an east and a west segment, but Palomar currently plans to design an east only pipeline to serve our utility ~~and~~customers as well as the growing natural gas markets in Oregon and other parts of the Pacific Northwest. The proposed pipeline would be regulated by the Federal Energy Regulatory Commission (FERC).

In ~~May 2010, we learned that the company proposing to build an LNG terminal on the Columbia River, had suspended~~March 2011, Palomar withdrew its ~~operations and filed for bankruptcy. This company had previously entered into a binding precedent agreement~~original application with ~~Palomar~~FERC for a ~~majority of~~natural gas pipeline in Oregon, but at the ~~proposed pipeline’s capacity. In September 2010, the bankruptcy court issued~~same time Palomar informed FERC that it intends to file a new application later this year or in 2012, after it has conducted 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 projectopen season and which consolidates the region’s efforts to develop a cross-Cascades pipeline around the use of the Palomar r oute. 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 ofobtained commercial support for the ~~east segment~~eastern portion of the pipeline between Madras and Molalla in Oregon.

Utility Investment in Gas Reserves. In addition to ~~determine~~hedging gas prices with financial derivative contracts over the ~~timing of its construction. Palomar will continue~~next few years, we recently signed an agreement with Encana Oil & Gas (USA) Inc. (Encana) to ~~focus on permitting activities during 2010 and 2011, but the date for when the Palomar pipeline is~~develop physical gas reserves that are expected to ~~go into service will be impacted by the timing~~supply a portion of our ~~final FERC permit and~~utility customers’ requirements over a period of about 30-years. During the ~~needs~~first 10 years of ~~shippers. See "Financial Condition—Cash Flows—Investing Activities," below~~the agreement, we forecast the volumes of gas received under the agreement to provide approximately 8 to 10 percent of the average annual requirements of our utility customers. Under the agreement, we expect to invest approximately $45 million to $55 million a year for ~~further discussion on the status of Palomar.~~five-years, with our total investment estimated to be about $250 million.

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).

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On April 28, 2011, the OPUC issued an order finding this gas reserve investment prudent and approving it for utility ratemaking, which provides for the recovery of ~~Contents~~

the costs plus a rate base return on our investment through the annual Purchased Gas Adjustment (PGA) mechanism, including the deferral process for the commodity cost of gas. Annually, we will forecast the amounts related to costs and volumes expected, and variances between forecasted and actual will be subject to the PGA incentive sharing provision in Oregon, up to a maximum variance of $10 million (for a discussion of the incentive sharing provision, see “Results of Operations – Regulatory Matters – Rate Mechanisms” below). Any variances in excess of $10 million, both negative and positive, will be deferred and passed through to customers in future rates at 100 percent. As part of the decision by the OPUC, we agreed to file a general rate case in Oregon no later than December 31, 2011.

Consolidated Earnings and Dividends

~~Three months ended September 30, 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~~most significant factors contributing to ~~increased third quarter~~the $2.8 million decrease in consolidated net ~~loss~~income as compared to the prior year were:

a ~~$3.2~~$6.1 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~~related to a ~~$0.4~~refund of property taxes in 2010, which is reflected by an operating expense increase of $5.2 million ~~gain~~under general taxes and a $1.0 million decrease under operations and maintenance, plus an interest income decrease of $1.9 million under other income;

a $2.7 million decrease related to a change in ~~2010;~~our revenue recognition policy for the regulatory adjustment of income taxes paid in 2011 as compared to 2010 (see “Application of Critical Accounting Policies and Estimates – Revenue Recognition,” and “Results of Operations - Business Segments - Utility Operations - Regulatory Adjustment for Income Taxes Paid,” below); and

·	a ~~$0.5~~$1.8 million decrease in net income from our gas storage ~~operations~~segment, primarily ~~due~~reflecting Gill Ranch’s low level of contracted capacity prior to ~~startup costs at Gill Ranch.~~its first injection season beginning April 1, 2011 coupled with initial start-up costs.

Partially offsetting the above factors were:

a ~~$1.0~~$6.4 million increase in utility ~~margin from~~net operating revenue (margin) attributable to an increase in residential and commercial ~~customers, after decoupling mechanism adustments,~~customer use, which reflect gains from colder weather and customer growth, an increase in industrial use, and ~~recovery~~an increase in our incentive share 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);gas cost savings; and

a ~~$0.2~~$2.2 million decrease in ~~operation and maintenance~~income tax 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.~~taxable income.

~~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 43.5 cents per share in the first quarter of 2011, compared to 41.5 cents per share in the ~~third~~first quarter of ~~2010, compared to 39.5 cents per share in the third quarter of 2009.~~2010. The Board of Directors ~~authorized~~declared a quarterly dividend on our common stock of 43.5 cents per share, payable on ~~November 15, 2010~~May 13, 2011, to shareholders of record on ~~October~~April 29, ~~2010, increasing the~~2011. The current indicated annual dividend rate ~~by 5 percent to~~is $1.74 per share.

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Application of Critical Accounting Policies and Estimates

In preparing our financial statements using generally accepted accounting principles in the United States of America (GAAP), management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and related disclosures in the financial statements. Management considers our critical accounting policies to be those which are most important to the representation of our financial condition and results of operations and which require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if we reported under different conditions or used different assumptions. Our most critical estimates and judgments include ~~acco unting~~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~~2010 Form 10-K with respect to the application of critical accounting policies and estimates (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the ~~2009~~2010 Form 10-K), except as indicated below under Revenue Recognition.

Revenue Recognition

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.~~reported, except for the item discussed above under Revenue Recognition. For a description of recent accounting pronouncements that could have an impact on our financial condition, results of operations or cash flows, see Note 1.2.

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)~~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,~~2011, 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~~2010 Form 10-K.

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Rate Mechanisms

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

In October 2010, the OPUC and WUTC approved PGA rate changes effective on November 1, ~~2010 under our PGA mechanisms.~~2010. The effect of ~~the~~these rate changes was to decrease the average monthly bills of Oregon and Washington residential customers by 2 percent. This is our second consecutive 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 PGA mechanism in Oregon, ~~PGA~~there is an incentive sharing ~~mechanism,~~provision whereby we are required to select by August 1 of each year either an 80 percent deferral or a 90 percent deferral of higher or lower actual gas costs compared to estimated PGA prices, such that the impact on current earnings from the ~~gas cost~~ incentive sharing is either 20 percent or 10 percent of the difference between actual and estimated gas costs, respectively. In addition to the gas cost incentive sharing mechanism, we are ~~also~~ subject to an annual earnings review to determine if the utility is earning above its allowed ~~return on equity (ROE)~~ROE threshold. If utility earnings exceed a specific ROE level, then 33 percent of the amount above that level ~~will~~are required to be deferred for refund to customers. Under this provision, if we select the 80 percent deferral option, then we retain all of our earnings up to 150 basis points above the currently ~~authorize d~~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 both 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~~and 2009, 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 ofafter adjustment for long-term interest rates was 11.02 percent and 11.5 percent, respectively. No amounts were required to be refunded to customers as a result of the 2009 utility earnings review. Based upon utility results for 2010 and ~~no earnings were deferred~~the first quarter of 2011 we accrued approximately $0.5 million and $1.0 million, respectively, for refund to ~~customers.~~customers in future rates

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 or gas cost sharing mechanism in Washington.

Regulatory Recovery for Environmental ~~Costs~~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~~We have ~~been extended through January~~filed a request for an extension of this deferral and expect to receive this authorization during the second quarter of 2011. See Note ~~11.~~14. In February 2011, we filed a request with the WUTC to defer environmental costs associated with services provided to Washington customers. We expect an order from the WUTC within the following few months.

Pension Deferral. ~~In March 2010, we filed a request with~~Effective January 1, 2011, the OPUC ~~for authorization~~approved our request to defer annual pension expenses above the amount set in rates, ~~and to recover~~with recovery of these deferred amounts through the ~~amount through future rate increases or through~~implementation of a balancing account, ~~mechanism that would include~~which includes the ~~effects~~expectation 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~~Our recovery of deferred balances includes accrued interest on the account balance at the utility’s authorized rate of return. ~~This settlement agreement is subject~~The estimated reduction 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 for th in the settlement agreement were in effect for 2010, then operationoperations and maintenance expense ~~would have been reduced by $3~~for 2011 is estimated to be in the range of $4 to $5 million, ~~to $4~~and $1.3 million ~~reflecting current year pension expense~~was deferred in ~~excess~~the first quarter of ~~the amount set in rates.~~2011. Future ~~year~~years’ 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~~

For a discussion of other rate mechanisms, see Part II, Item 7., ~~“Application~~“Results of ~~Critical Accounting Policies and Estimates”~~Operations—Regulatory Matters—Rate Mechanisms” in ~~the 2009~~our 2010 Form 10-K.

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~~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~~largely affected by customer growth and to a certain extent by changes in weather and ~~customer consumption~~customers’ gas usage patterns, with a significant portion of our earnings being derived from natural gas sales to residential and commercial customers. In Oregon, we have a conservation tariff ~~mechanism~~ that adjusts margin revenues to offset changes ~~in margin~~ resulting from increases or decreases in ~~average~~ residential and commercial ~~customer consumption.~~customers’ gas usage. We also have a weather normalization mechanism in Oregon 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).~~season. Both mechanisms are designed to reduce the volatility of our utility ~~earnings.~~earnings and customer charges.

~~Three months ended September 30, 2010~~Our utility segment in the first quarter of 2011 earned $40.1 million, or $1.50 per share, compared to ~~September 30, 2009:~~

~~Utility operations resulted in a net loss of $9.1~~$40.9 million, or ~~34 cents~~$1.54 per share for the same period in 2010. The major factors contributing to the ~~third quarter~~change in earnings were higher margins from residential and commercial customers, which were up $6.2 million largely due to the impact of ~~2010 compared to a net loss of $9.2~~colder weather, along with higher industrial customer margins, which were up $0.5 million, ~~or 35 cents per share, in the third quarter of 2009.~~partially offset by increased operating expenses. Total ~~utility~~ volumes sold and delivered in the ~~third~~first quarter of ~~this~~2011 increased 20 percent over last year, ~~increased by 4~~with residential and commercial volumes up 29 percent ~~or 6 million therms~~on weather that was 21 percent colder than last year, plus a 5 percent increase in industrial volumes 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 deliveredOperating expenses were higher 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,~~first quarter of 2011 primarily due to a ~~$13.6 million decrease~~refund of property taxes recognized in ~~gas cost savings from our incentive sharing~~the first quarter of 2010 (see General Taxes, below).

Our weather normalization mechanism ~~partially offset by a $5.5 million increase in~~adjusted residential and commercial margins ~~after weather and decoupling mechanism adjustments, primarily related~~down by $5.9 million for the first quarter of 2011 based on temperatures that were 6 percent colder than average, compared to a margin increase of $13.5 million for the ~~benefits of colder weather in the second~~first quarter of 2010 ~~(see “Residential~~when temperatures were 13 percent warmer than average. Our decoupling mechanism adjusted residential and ~~Commercial Sales,” below).~~commercial margins up by $8.7 million in 2011, compared to a margin increase of $7.9 million in 2010.

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

		Three Months Ended						Favorable/
		March 31,						(Unfavorable)
Thousands, except degree day and customer data		2011			2010			2011 vs. 2010
Utility volumes - therms:
Residential sales			174,930			133,860			41,070
Commercial sales			99,967			78,856			21,111
Industrial - firm sales			10,637			10,153			484
Industrial - firm transportation			35,690			32,611			3,079
Industrial - interruptible sales			17,239			16,324			915
Industrial - interruptible transportation			62,951			61,599			1,352
	Total utility volumes sold and delivered		401,414			333,403			68,011
Utility operating revenues - dollars:
Residential sales		$	198,774		$	169,609		$	29,165
Commercial sales			95,313			80,075			15,238
Industrial - firm sales			8,956			8,618			338
Industrial - firm transportation			1,591			1,436			155
Industrial - interruptible sales			10,483			10,381			102
Industrial - interruptible transportation			2,310			1,919			391
Regulatory adjustment for income taxes paid(1)			286			2,984			(2,698	)
Other revenues			14			6,041			(6,027	)
	Total utility operating revenues		317,727			281,063			36,664
Cost of gas sold			180,610			148,548			(32,062	)
Revenue taxes			7,955			7,042			(913	)
	Utility margin	$	129,162		$	125,473		$	3,689
Utility margin:(2)
Residential sales		$	84,252		$	66,404		$	17,848
Commercial sales			32,558			25,708			6,850
Industrial - sales and transportation			7,610			7,123			487
Miscellaneous revenues			1,584			1,673			(89	)
Gain (loss) from gas cost incentive sharing			1,035			199			836
Other margin adjustments			(1,027	)		(19	)		(1,008	)
	Margin before regulatory adjustments		126,012			101,088			24,924
Weather normalization adjustment			(5,861	)		13,535			(19,396	)
Decoupling adjustment			8,725			7,866			859
Regulatory adjustment for income taxes paid(1)			286			2,984			(2,698	)
	Utility margin	$	129,162		$	125,473		$	3,689
Customers - end of period:
Residential customers			612,738			606,935			5,803
Commercial customers			62,800			62,477			323
Industrial customers			908			917			(9	)
	Total number of customers - end of period		676,446			670,329			6,117
Actual degree days			1,974			1,627
Percent colder (warmer) than average weather(3)			6	%		(13	) %

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

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 ) %

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

The primary changes that impacted margin 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 a pproximately 9 percent of our Oregon~~ residential and commercial ~~customers have opted out of~~sales for 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~~three months ended ~~September 30, 2010~~March 31, 2011 compared to ~~September 30, 2009:~~March 31, 2010 were as follows:

~~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:~~

·	utility sales volumes ~~increased 7~~were 29 percent ~~due to~~higher, primarily reflecting 21 percent colder ~~weather and customer growth;~~weather;

·	utility operating revenues ~~decreased $10.7~~increased $44.4 million or 1318 percent primarily due to 29 percent increased volumes, partially offset by lower average use per customer ~~rates;~~due to conservation efforts; and

utility margin increased $1$6.2 million or 35 percent ~~including weather normalization~~reflecting increased volumes from residential and ~~decoupling mechanism adjustments, primarily due to~~commercial customer growth of 0.9 percent and 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~~which 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~~weather normalization adjustments that benefit customer ~~refunds in 2009 related to gas cost savings; and~~bills when weather is colder than normal.

·	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~~Operating revenues from industrial customers include the commodity cost component of gas sold under sales service but not under transportation service. Therefore, operating revenues from industrial ~~customer switching~~customers can increase or decrease when customers switch between sales service and transportation service, ~~can cause swings in utility operating revenues~~ but generally our margins from these customers are unaffected by these changes because we do not ~~mark up~~include a profit mark-up for the cost of gas.

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

As such, we believe volumes delivered and margins are better measures of performance for the industrial sector. The primary ~~factors~~changes that impacted ~~third quarter results~~volumes and margins from industrial sales and transportation ~~markets~~services for the three months ended March 31, 2011 compared to March 31, 2010 were as follows:

·	volumes delivered to industrial customers increased ~~by 2.3~~5.8 million therms, or ~~2 percent;~~5 percent, due to a slight increase in energy demand. The majority of the increased volumes were attributable to the manufacturing sector; and

·	margin from industrial customers increased ~~$0.1~~$0.5 million, or 27 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:~~

·	primarily due to the increase in total 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.~~delivered.

Regulatory Adjustment for Income Taxes Paid

Oregon law currently 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~~operation and compare it to the amount the ~~company~~utility actually pays to taxing authorities. Under this law, if we pay less in income taxes related to utility operations 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 in 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,~~2009 tax year, the OPUC approved our tax filing to recover $5.6 million, including interest, through a surcharge to Oregon utility customers. It was agreed that the 2009 surcharge, plus accrued interest, would be collected over a one-year period beginning June 1, 2011. For the 2010 tax year, we ~~recognized $5 million of pre-tax income representing a~~estimated the difference ~~of $4.6 million of estimated federal and state~~between income taxes paid ~~in excess of taxes~~and the amounts collected in rates will result in a surcharge of $7.1 million, excluding interest. The 2010 surcharge was primarily driven by a refund of property taxes as well as by utility operating margins including gains from gas cost savings related to our PGA incentive sharing.

For the three months ended March 31, 2011, we estimate the surcharge to be $2.7 million for the regulatory adjustment of income taxes paid. However, we did not recognize revenues in this period for the regulatory adjustment due to the uncertainty surrounding our ability to collect the expected 2011 surcharge in future rates. For further discussion, see “Revenue Recognition” above under Application of Critical Accounting Policies and Estimates. However, we did recognize revenues of $0.3 million in the three months ended March 31, 2011 for accrued interest attributed to surcharges related to the 2009 and 2010 tax years, as compared to $3.0 million for the same period in 2010, which included a surcharge of $2.9 million plus accrued ~~interest. For~~interest of $0.1 million attributed to the ~~nine months ended September 30,~~2008 and 2009 ~~we recognized $3.8 million of incremental margin revenues representing a difference of $3.6 million of federal and state~~tax years.

On March 29, 2011, legislation was introduced in Oregon (SB 967) to repeal existing statutes governing the annual regulatory adjustment for income taxes ~~paid in excess of taxes collected in rates plus accrued interest. The $1.2 million increase in income taxes paid over~~paid. This legislative bill would repeal the regulatory adjustment for tax years after 2009 upon the effective date. In order to ensure a proper balance between income taxes collected in rates by regulated natural gas and electric utilities and amounts actually paid to taxing authorities, SB 967 would require the OPUC to make decisions in future ratemaking proceedings on the amounts of income taxes to be recovered in rates. As of May 4, 2011, SB 967 had been approved by the Oregon Senate but not by the Oregon House of Representatives. If the Oregon legislature votes to pass SB 967 in its current form and the bill is ~~due~~signed into law by the governor, then the asset amounts on the balance sheet at March 31, 2011 for the 2010 tax year, which totals $7.4 million including accrued interest would be impaired and need to be written-off. Such an impairment would result in ~~part~~an after-tax adjustment of approximately $4.4 million, which is equivalent to ~~higher effective income tax rates (see Note 7).~~17 cents per share.

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~~except for 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~~cost deferrals which flow through cost of ~~Contents~~

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

gas sold. Other revenues decreased $2from $6.0 million infor the ~~third quarter of~~three months ended March 31, 2010 ~~compared~~ to less than $0.1 million for the ~~same period in 2009,~~three months ended March 31, 2011, primarily ~~from~~reflecting a ~~net~~$2.1 million decrease in the ~~deferral and~~decoupling amortization, a $1.0 million accrual for estimated refunds to utility customers 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~~our earnings sharing mechanism, a $1.4 million ~~over~~decrease for the ~~same period of 2009, with the increase primarily due~~warm deferral related to colder weather, and a ~~timing difference~~$1.3 million decrease in ~~how we collect our surcharge for~~other 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.amortizations.

Cost of Gas Sold

~~The cost~~Cost of gas sold includes ~~current~~ gas purchases, gas drawn from storage inventory, gains and losses from commodity hedges, pipeline demand ~~charges,~~costs, 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 to be billed to customers at the same cost incurred, or expected to be incurred, by the utility. However, under the PGA mechanism in Oregon, our net income ~~is partially~~can be affected by differences between actual and expected ~~purchased~~ gas costs, ~~due to~~which occur primarily because of market fluctuations and volatility affecting unhedged ~~purchases. To manage this earnings exposure, we~~gas purchases (see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above). We use natural gas ~~derivatives,~~commodity-based hedge contracts (derivatives), primarily fixed-price ~~commo dity~~commodity swaps, consistent with our financial derivatives ~~policies.~~policies to help manage our exposure to rising gas prices. Gains and losses from these financial hedge contracts are generally included in our PGA prices and normally do not impact net income asbecause the ~~hedges~~hedged prices 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~~utility hedge contracts entered into after the annual PGA ~~filing~~rates are set in Oregon ~~if any, may~~can impact net income because we would be required to share in any gains or losses compared to the ~~extent of our share of any gain or loss under~~corresponding commodity prices built into rates in the PGA. In Washington, cost of gas sold does not affect our margins or net income because 100 percent of the actual gas costs, including ~~all~~ hedge gains and losses allocated to Washington gas sales, are passed through in customer rates (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” and “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” in the ~~2009~~2010 Form 10-K, and Note 1013 in this report).

~~Three~~ The following summarizes the major factors that contributed to changes in cost of gas sold for the three months ended ~~September 30, 2010 compared to September 30, 2009:~~March 31, 2011:

·	total cost of gas sold ~~decreased $18.9~~increased $32.1 million, or 2922 percent, due to ~~lower~~a 20 percent increase in total sales volumes and a 2 percent decrease in the average cost of gas ~~prices;~~sold per therm;

the average gas cost collected through rates ~~excluding customer refunds for accumulated gas cost savings~~decreased 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~~to 60 cents per therm in

·	~~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,~~2011, primarily reflecting lower gas prices that were passed on through ~~customer rates~~PGA rate decreases effective November 1, ~~2009;~~2009 and 2010; and

hedge ~~net~~ losses totaling ~~$33.3~~$20.9 million were realized and included in cost of gas sold for the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, compared to ~~$150.8~~$6.2 million of hedge ~~net~~ losses in the same period of ~~2009.~~2010. Since the underlying hedge prices were included in our PGA billing rates, these losses did not impact margin or net income.

The ~~effect on operating results~~amount recorded to pre-tax income from ~~our share~~the shareholders’ portion of ~~the~~our gas cost incentive sharing mechanism was a margin ~~gain~~contribution of ~~$1.1~~$1.0 million in the ~~nine months ended September 30, 2010,~~first quarter of 2011 compared to ~~a margin gain of $14.7~~$0.2 million in ~~the same period~~2010. For a discussion of ~~2009.~~

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our gas cost incentive sharing mechanism, see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above.

Business Segments ~~Other than Utility Operations~~

- Gas Storage

Our gas storage segment ~~currently~~primarily consists of the acquisition, development, operation and management of natural gas storage facilities. As of March 31, 2011, we owned and operated non-utility ~~portion of~~investments at our Mist underground storage facility ~~utility~~in Oregon and ~~non-utility~~at our Gill Ranch underground storage facility in California. Construction of the Gill Ranch storage facility was completed and placed into service during the fourth quarter of 2010. Our gas storage segment also includes asset optimization services using unused gas storage and ~~start-up costs at Gill Ranch (see Part I, Item 1., “Business Segments—Gas Storage,” in our 2009 Form 10-K).~~transportation capacity. For the three months ended ~~September 30, 2010, we~~March 31, 2011, our gas storage segment earned ~~$1.8~~$0.7 million, or 73 cents per share, compared to ~~$2.3~~$2.5 million, or 9 cents per share, for the same period in ~~2009. The $0.5~~2010. This decrease was primarily related to net losses at Gill Ranch due to initial start-up costs and low storage contract revenues prior to April 1, 2011, which is the start of Gill Ranch’s first injection season, and partly due to a slight downturn in revenues from firm storage and optimization services at Mist.

Gas storage net operating revenues (margin) decreased $0.1 million to $5.3 million for the three months ended March 31, 2011. This decrease in ~~net income over 2009~~margin is primarily due to ~~start-up costs at~~a decrease in Mist third-party optimization revenues of $0.8 million, partially offset by 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~~Ranch’s revenues 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$0.6 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.~~

Business Segments - Other

Our other business segment consists primarily of ~~Financial Corporation, an~~NNG Financial’s investment in KB Pipeline, our investment in PGH which in turn has invested in the Palomar pipeline project, and our other non-utility investments and business activities. NNG Financial ~~Corporation~~ had total assets of $1.1 million and ~~$1.3~~$1.2 million as of ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ respectively, primarily reflecting a non-controlling minority interest in the Kelso-Beaver pipeline. Our net equity investment in PGH as of ~~September 30,~~March 31, 2011 and 2010 ~~and 2009~~ was ~~$14.7~~$14.8 million and ~~$12.4~~$14.5 million, respectively. Earnings from our other business segment ~~for the three~~as of March 31, 2011 and ~~nine months ended September 30,~~ 2010 was a net loss of less than $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.~~respectively. See Note 2.4 in the 2010 Form 10-K and in this report.

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Consolidated ~~Operating Expenses~~Operations

Operations and Maintenance

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

~~Operations~~Consolidated operations and maintenance expense was ~~$26.9~~$31.2 million in 2011, compared to $30.7 million in 2010, a increase of $0.5 million or 2 percent. The following summarizes the major factors that contributed to changes in operations and maintenance expense for the three months ended March 31, 2011 compared to ~~$27.1 million in 2009, a decrease of $0.2 million or 1 percent. The primary~~March 31, 2010:

·	a $1.1 million increase for operating expenses at Gill Ranch, including $0.8 million for labor related expenses and $0.3 for compressor related expenses; and

·	a $0.6 million increase in accrued performance bonuses at the utility based on above-target year-to-date operating results compared to last year.

Partially offsetting the above factors ~~contributing to the decrease~~ were:

·	a ~~$0.9~~$1.0 million decrease in ~~payroll expense~~consulting and legal fees due to prior year costs related to ~~a reduced number of utility employees;~~

·	~~a $0.5 million decrease in incentive bonus accruals; and~~our successful property tax appeal;

·	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)~~further discussion); and

·	a ~~$0.9~~$0.2 million decrease in pension expense due to the ~~decline in~~effects of the ~~market value~~new regulatory deferral of ~~plan investments in 2008 which had a greater impact on 2009 expense.~~pension expense authorized by the OPUC (see below for further discussion).

~~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~~0.18 percent for the 12twelve months ended ~~September 30, 2010,~~March 31, 2011, compared to ~~0.39~~0.33 percent infor the same period last year. ~~This year’s lower~~The decrease in our bad debt expense ratio was partly due to improved collections and recoveries 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. CreditDespite these improvements, we believe credit risks are still ~~somewhat high~~elevated 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~~rates. Higher customer usage from ~~warmer than normal~~colder weather these past few months may increase our exposure to credit losses over the remainder of this ~~past winter coupled with customer conservation, lower gas prices an d low income energy assistance funds have contributed to our reduced credit exposure.~~year.

~~Health care~~Effective January 1, 2011, the OPUC approved the deferral of utility pension 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~~NW Natural’s qualified defined benefit plans ~~could increase materially~~for operations and maintenance expense above the amount recovered in rates, which was set in our last general rate case. The pension expense deferral is recorded to a regulatory balancing account, which we expect to result in an estimated $4 to $5 million cumulative amount for 2011. So far, we have deferred $1.3 million of pension expense in the first quarter of 2011, ~~due~~which, when netted with pension expense, resulted in a $0.2 million decrease to operations and maintenance expense compared to the ~~low interest rate environment, but we believe these higher costs may be offset if~~same period in 2010. For further explanation of the ~~OPUC approves the company’s request for a deferred~~pension balancing account, ~~(see discussion of~~ see “Regulatory Matters—Rate Mechanisms—Pension Deferral, ~~under “Regulatory Matters - Rate Mechanisms,~~” ~~above).~~above.

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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~~$4.9 million ~~or 4 percent,~~ in the first three months ~~ended September 30, 2010 over~~of 2011 compared to 2010. The major factor that contributed to the ~~same period~~change in ~~2009, primarily due to an increase in~~general taxes was a prior year $5.2 million refund of property taxes pursuant to a favorable ruling from ~~net additions to property, plant and equipment.~~the Oregon Supreme Court (see below for further discussion).

~~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~~several years, we had been involved in litigation with the Oregon Department of Revenue over ~~whether~~the taxability of certain inventories that were held for sale, ~~were required to be taxed as personal property.~~including gas inventories. In January 2010, the Oregon Supreme Court unanimously ruled in our favor, stating that these inventories were exempt from property tax. As a result of this ruling, we were ~~entitled to a refund of approximately~~refunded $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, 20 10, we had received all of the property tax refunds.~~fees.

Depreciation and Amortization

~~Depreciation~~Total depreciation and amortization expense in 2011 increased by ~~$0.2~~$1.4 million, or 19 percent, ~~for the three months ended September 30, 2010,~~as compared to the same period in ~~2009. For~~2010. The increased expense in 2011 was primarily related to Gill Ranch depreciation, which relates to assets that went into service in the ~~nine months ended September 30, 2010, depreciation and amortization expense increased by $1.2 million, or 3 percent, compared~~fourth quarter of 2010. A portion of the increase was also related to ~~the same period~~additional investments in ~~2009. The increase in both periods reflects added~~ utility plant ~~from~~related to customer growth and ~~other capital project expenditures.~~system improvements.

Other Income and Expense – Net

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

	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
Thousands	2010			2009			2010			2009			2011			2010
Other income and expense - net:
Gains from company-owned life insurance	$	599		$	664		$	1,640		$	2,666		$	505		$	396
Interest income		8			66			2,006			165			7			1,910
Income from equity investments		(152	)		193			576			927			-			316
Net interest on deferred regulatory accounts		1,189			585			3,386			1,374			1,514			991
Other		(311	)		(270	)		(1,639	)		(2,272	)
Gain (loss) on sale of investments														(96	)		223
Other non-operating														(716	)		(813	)
Total other income and expense - net	$	1,333		$	1,238		$	5,969		$	2,860		$	1,214		$	3,023

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

Other income and expense – net ~~increased $0.1~~decreased $1.8 million, primarily due to ~~additional income from our higher deferred regulatory account balances.~~

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

the prior year’s refund of property taxes as discussed above, which included $1.9 million in accrued interest income. Other income and expense ~~– net increased $3.1~~also included a $0.5 million ~~primarily~~increase in interest from regulatory account balances largely due to ~~additional interest~~smaller gas costs refund balances, which was partially offset by our share of reduced 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.~~an equity investment.

Interest Expense – Net

Interest ~~expense –~~ expense—net of amounts capitalized in 2011 decreased by less than $0.1 million ~~in the three months ended September 30, 2010~~ compared to ~~the same period~~2010. The decrease is due to a $0.4 million savings from interest expense on long term debt as a result of bonds that matured in ~~2009 and increased $1.7~~2010, partially offset by a $0.2 million ~~or 6 percent in the nine months ended September 30, 2010 compared~~increase for gas storage related 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).Gill Ranch base gas lease.

Income Tax Expense

~~Income~~The decrease in income tax expense ~~increased $2.3~~of $2.2 million ~~in the nine months ended September 30, 2010~~or 7 percent, compared to ~~2009. The~~2010 was primarily due to lower pre-tax consolidated earnings of $5.0 million or 7 percent and a decrease in our effective tax rate of 40.6 percent in 2011 compared to 40.8 percent in 2010.

For the 2011 tax year, the lower effective tax rate was ~~40.3 percent~~primarily the result of a decrease in ~~2010 compared to 38.0 percent in 2009. The higher~~the Oregon statutory income tax ~~expense and~~rate from 7.9 percent for tax year 2010 to 7.6 percent for tax year 2011. For the 2010 tax year, the higher effective tax rate ~~are~~was primarily the result of ~~an increase in the~~increased amortization of our regulatory tax ~~asset~~ account on pre-1981 utility plant assets (see “Regulatory Matters—Rate ~~Mechanisms—Depreciation Study,~~Mechanisms,” above) and a lower non-taxable gain on company-owned life insurance. For more information on our income taxes, including a reconciliation between the statutory federal and state income tax rates and the effective rate, see Note 10.

In July 2009, the governor of Oregon signed House Bill 3405 establishing increases in the state income tax rate for corporations, and Oregon voters approved this legislation in January 2010. The corporate income tax rate in Oregon increased from 6.6 percent to 7.9 percent for tax years 2009 ~~Form 10-K).~~

~~On March 23,~~and 2010 when taxable income is greater than $250,000. For tax years 2011 and 2012, the ~~Patient Protection~~income tax rate will decrease to 7.6 percent, 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~~for years after 2012 the tax ~~treatment of federal subsidies paid~~rate will return to ~~sponsors of retiree health benefit plans that provide a benefit that is~~6.6 percent, except for corporations with taxable income over $10 million the tax rate will remain 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.7.6 percent.

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Financial Condition

Capital Structure

~~Our goal~~One of our long-term goals is to maintain a strong consolidated capital structure, generally consisting of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt. ~~When~~If additional capital is required, then debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources of capital are also ~~are~~ used to fund long-term debt ~~redemption requirements~~redemptions and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below, and Note 5)7). Achieving the target capital structure and maintaining sufficient liquidity to meet operating requirements are necessary to maintain attractive credit ratings and have access to capital markets at reasonable costs. Our consolidated capital structure at March 31, 2011 and 2010 and at December 31, 2010 was as follows:

	September 30,						December 31,			March 31,						December 31,
	2010			2009			2009			2011			2010			2010
Common stock equity		45.9	%		47.5	%		47.2	%		47.9	%		48.6	%		44.7	%
Long-term debt		40.2	%		47.2	%		43.0	%		36.5	%		42.2	%		38.1	%
Short-term debt, including current maturities of long-term debt		13.9	%		5.3	%		9.8	%		15.6	%		9.2	%		17.2	%
Total		100	%		100	%		100	%		100	%		100	%		100	%

Liquidity and Capital Resources

At ~~September 30, 2010,~~March 31, 2011, we had ~~$2.5~~$3.5 million of cash and cash equivalents compared to ~~$13.7~~$8.8 million at ~~September 30, 2009.~~March 31, 2010. We also had $0.9 million in restricted cash invested at Gill Ranch as of ~~September 30, 2010,~~March 31, 2011, compared to ~~$20.8~~$40.9 million ~~as of September 30, 2009,~~at March 31, 2010, which iswas 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~~Our short-term liquidity is supported by cash balances, internal cash flow from operations, proceeds from the sale of commercial paper notes, committed multi-year credit facilities, cash available from ~~surre nder~~surrender value in company-owned life insurance policies, and proceeds from the sale of long-term debt. We use long-term debt proceeds generally to finance utility capital expenditures, refinance maturing short-term orand 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~~medium term notes (MTNs) at attractive rates and have not needed to borrow from our ~~$250 million~~ back-up ~~facility.~~credit facilities. In the event that we ~~are~~were not able to issue new debt due to market conditions, we expect that our near term liquidity needs ~~can~~could be met by using cash balances or drawing upon our committed credit ~~facility (see “Credit Agreement,” below).~~facilities. 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~~which was filed in 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,~~March 31, 2011, we could have been required to post ~~$42.3~~$18.1 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 1013 and “Credit Ratings,” below)., which is several rating levels below our current ratings.

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~~Some recent~~Business developments that ~~may~~could have a material impact on our liquidity and capital ~~resources~~resource position 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~~under the Pension Protection Act rules (see “Pension Cost and Funding Status of Qualified Retirement Plans,” below). With respect to federal income tax liabilities, an extension was granted that ~~will allow~~allows us to take 50 percent bonus depreciation on a majority of our capital expenditures in 2010, and 100 percent bonus depreciation on qualified expenditures during 2011, which ~~will~~ significantly ~~reduce~~reduces our tax liability for the 2010 and 2011 tax ~~year and provide~~years, thereby providing cash flow benefits in ~~late 2010 and early~~ 2011 (see “Cash Flows—Operating Activities,” below). ~~And with~~With respect to environmental liabilities, we expect to continue using cash resources ~~towards~~to fund our environmental liabilities, but we also anticipate recovering amounts through insurance ~~recovery~~coverage or ~~rate recovery~~utility rates over the next several years, ~~but~~although the amount and timing of these expenditures and recoveries is uncertain (see Note ~~11)~~14).

In addition, Gill Ranch began commercial operations in ~~October~~the fourth quarter of 2010. Although we anticipate future operating cash flows at Gill Ranch to increase as the facility grows to its full design capacity by the end of 2013 and as we contract for incremental storage capacity. The amount and timing of ~~these~~ cash flows ~~are uncertain.~~will depend on future storage values and our ability to optimize storage capacity.

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~~requires 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 final regulations implementing the legislation are ~~finalized.~~issued.

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~~an MTN 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,~~March 31, 2011, our purchase commitments ~~decreased~~increased approximately ~~$47.8~~$28 million since December 31, ~~2009,~~2010, primarily ~~due to payments related to Gill Ranch~~involving contracts entered into in the normal course of business (see “Financial ~~Condition--Contractual~~Condition—Contractual Obligations,” in the ~~2009~~2010 Form 10-K).

~~Short-term~~Short-Term Debt

Our primary source of utility short-term liquidity is from internal cash flows and the sale of commercial ~~paper debt.~~paper. In addition to issuing commercial paper to meet ~~seasonal~~ working capital requirements, including ~~the financing of~~seasonal requirements to finance gas inventories and accounts receivable, short-term debt may also be used to temporarily fund utility capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by one or more unsecured revolving credit facilities (see “Credit ~~Agreement,~~Agreements,” below). Our commercial paper program did not experience any liquidity disruptions as a result of the credit problems that affected ~~issu ers~~issuers of asset-backed commercial paper and certain other commercial paper programs over the last ~~two~~several years. At ~~September 30,~~March 31, 2011 and 2010, ~~and 2009,~~ our utility had commercial paper outstanding of ~~$159.9~~$186.4 million and ~~$56.1~~$56.0 million, respectively. The effective interest rate on the utility’s commercial paper outstanding at March 31, 2011 and 2010 was 0.4 percent and 0.3 percent, respectively.

In March 2009, Gill Ranch entered into a cash collateralized credit facility for up to $40 million, which was extended through September 30, 2010. In June 2010, Gill Ranch repaid its $40 million bank ~~loan outstanding using~~loan. The effective interest rate on the ~~proceeds from its cash collateralized account.~~ Gill Ranch credit facility was 0.8 percent during 2010.

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Credit ~~Agreement~~Agreements

We have a syndicated multi-year credit agreement for unsecured revolving loans totaling $250 million, which may be extended for additional one-year periods subject to lender approval. All lenders agreed to extend the original term for an additional one-year period through May 31, 2013. We also had three bilateral credit agreements totaling $50 million in effect from November 30, 2010 through March 31, 2011. All lenders under our syndicated and bilateral credit ~~agreement~~agreements are major financial institutions with committed balances and investment grade credit ratings as of ~~September 30, 2010~~March 31, 2011 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~~

		Loan Commitment Amounts in Thousands
		Syndicated		Bilateral
Lender rating, by category		Facility		Facility
AAA/Aaa		$	-	$	-
AA/Aa			230,000		50,000
A/A			20,000		-
BBB/Baa			-		-
	Total	$	250,000	$	50,000

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~~credit ratings, we believe the risk of lender default is minimal.

~~The loan~~As discussed above, we extended commitments with all seven lenders under the syndicated ~~credit~~ agreement, ~~have been extended to May 31, 2013.~~with commitments totaling $250 million. The ~~credit~~syndicated agreement also allows us to request increases in the total commitment amount from time to time, up to a maximum amount of $400 million, and to replace any lenders who decline to extend the maturity date of the credit agreement. The ~~credit~~syndicated agreement also permits the issuance of letters of credit in an aggregate amount up to the applicable total borrowing commitment.

Any principal and unpaid interest amounts owed on borrowings under the credit ~~agreement is~~agreements are due and payable on or before the maturity date. There were no outstanding balances under ~~this~~these credit ~~agreement~~agreements at ~~September 30, 2010~~March 31, 2011 and ~~2009. The credit agreement~~2010. These agreements also ~~requires~~require us to maintain a consolidated indebtedness to total capitalization ratio ~~as dete rmined 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,~~March 31, 2011 and 2010, with consolidated indebtedness to total capitalization ratios of 52 percent and ~~2009.~~51 percent, respectively.

The ~~credit agreement~~syndicated and bilateral agreements also ~~requires~~require that we maintain credit ratings with ~~S&P~~Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s) and notify the lenders of any change in our senior unsecured debt ratings by such rating agencies. A change in our debt ratings by S&P or by Moody’s is not an event of default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon the credit agreement. ~~Interest~~However, a change in our debt rating below BBB- or Baa3 would require additional approval from the OPUC prior to issuance of debt, and interest rates on any loans outstanding under the credit ~~agreement~~agreements are tied to debt ratings, which would increase or decrease the cost of any loans under the credit ~~agreement~~agreements when ratings are changed (see “Credit Ratings,” below).

All three lenders under the short-term credit agreements are existing lenders under our syndicated credit agreement. The short-term credit agreements require us to comply with the terms and conditions of the syndicated credit agreement and give the lenders under the short-term credit agreements the same rights with respect to the short-term credit agreements that they have under the syndicated credit agreement. The bilateral credit agreement expired March 31, 2011.

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)~~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)	n/a	A3
Corporate credit rating	A+	n/a
Ratings outlook	Stable	Stable

The above credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of these credit ratings is ~~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~~Maturity and Redemption of Long-Term Debt

For the ~~nine~~three months ended ~~September 30,~~March 31, 2011 and 2010 ~~or 2009,~~ there ~~are~~were no long-term debt maturities or redemptions. ~~In November 2009, $0.3~~Over the next twelve months, $10 million of ~~our 6.65 percent~~ secured MTNs, ~~due 2027 were redeemed pursuant to~~with a ~~one-time put option. This one-time put option has now expired,~~coupon rate of 6.665%, mature in June 2011, and ~~the $19.7 million remaining principal outstanding is expected to be paid at maturity in November 2027.~~

~~We have $45~~another $40 million of ~~long-term debt that will~~secured MTNs, with a coupon rate of 7.13%, mature ~~during the fourth quarter of 2010.~~in March 2012. 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~~2010 Form 10-K.

Cash Flows

Operating Activities

Three months ended March 31, 2011 compared to March 31, 2010:

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. InFor the ~~nine months~~year ended ~~September 30, 2010,~~March 31, 2011, cash flow from operating activities ~~decreased $84.8~~totaled $108.1 million compared to ~~the same period~~$74.2 million in ~~2009.~~2010. The significant factors contributing to changes in operating cash flow ~~for~~in the ~~nine~~first three months ~~ended September 30, 2010~~of 2011 compared to ~~the same period of 2009~~2010 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~~$35.1 million from changes in receivables primarily due to ~~$35.3 million of customer refunds in June 2009 and~~ higher ~~receivable~~ balances from colder weather at the end of ~~2008 versus 2009;~~2009, which benefitted cash flows during 2010;

·	an increase of ~~$15~~$17.3 million from ~~a smaller pension contribution~~changes in ~~2010~~inventories primarily due the decreases in gas prices and increases in gas inventory withdrawals from storage in 2011 compared to ~~2009;~~2010;

·	an increase of $15.6 million from changes in the deferred gas cost regulatory account balance, which reflects a ~~decrease~~lower variance between actual gas prices and embedded gas prices in the PGA for 2011 compared to 2010;

·	an increase of $13.5 million from deferred income taxes, primarily reflecting higher tax benefits from bonus

·	depreciation taken from Gill Ranch capital investments placed in service;

·	an increase of $10.6 million from income taxes receivable and accrued taxes, primarily related to ~~decreases~~our federal refund received in ~~tax deductions;~~the first quarter of 2011 of $14.4 million; and

·	an increase of ~~$10.1~~$10.5 million from ~~the loss realized~~changes in ~~2009~~gas costs payable due to weather impact on ~~the settlement of our interest rate hedge (see Note 10).~~gas purchases.

In September 2010, Congress passed the ~~Small Business Jobs~~Unemployment Insurance, Reauthorization and Job Creation 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 rules 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 was allowed for depreciation equal to 50 percent of the adjusted basis of qualified property ~~may be deducted~~through September 8, 2010, and 100 percent through December 31, 2011, in the year the property is placed in service, and the remaining ~~50 percent~~percentage recovered under the normal depreciation rules. The 50 percent or 100 percent depreciation deduction in the first year is an acceleration of depreciation deductions that otherwise would ~~have been~~be taken in the later years of an ~~ass et’s~~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~~liabilities for the ~~2010~~2011 tax year. Any deductions in excess of 2011 income tax liabilities for federal income tax purposes will be carried forward to the 2012 tax year. As of March 31, 2011, we have a federal and state income tax receivable balance of $23.6 million, which we expect to realize in cash flows during 2011. We received a federal refund of approximately $14.4 million during the first quarter of 2011.

For the year ended December 31, 2010, we reported an estimated net operating loss (NOL) for federal income tax purposes of $94.4 million, primarily due to the effects of accelerated tax depreciation provided by the 2010 Act. The federal NOL will be carried back to 2009 and partially utilized for a refund of taxes paid in prior years. The remaining NOL of approximately $20.2 million will be carried forward to reduce current taxes paid in the ~~2009~~2011 tax year. We ~~estimate this extension~~anticipate that we will ~~generate cash flow of between $40 million~~be able to ~~$45 million~~use all loss carry-forwards in future years. The 2010 federal ~~income taxes.~~NOL would expire in 2031 if not used in earlier years.

~~Table of Contents~~

Investing Activities

Cash used in investing activities for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 totaled ~~$150.1~~$25.5 million, updown from ~~$96.5~~$57.4 million for the same period in ~~2009. Our capital~~2010. Capital expenditures were ~~$185.7~~$25.4 million in the ~~nine~~three months ended ~~September 30, 2010, up $100.4 million~~March 31, 2011, down from ~~$85.2~~$52.8 million for the same period in ~~2009. Our utility capital expenditures decreased $14.0~~2010, of which $27.0 million ~~primarily~~of the decrease was due to ~~completing our automated meter reading project in 2009, and our~~ non-utility ~~capital expenditures increased $114.4 million~~construction activity primarily ~~due~~related 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~~2011, capital expenditures are estimated to be between ~~$80 and $90~~$95 million and ~~non-utility capital expenditures are expected to be between $140 and $150~~$105 million for ~~business~~the utility, excluding our proposed investment in long-term gas reserves (for further discussion, see Note 15). For non-utility development projects, ~~that are~~we expect to spend between $5 million and $15 million total in 2011 for capital projects currently in process (see “Strategic Opportunities,” above).

Over the next five-year period ~~2010~~2011 through ~~2014,~~2015, total utility capital expenditures are estimated at between $400 and $500 ~~million.~~million, excluding the investment of approximately $250 million in gas reserves. The estimated level of utility capital expenditures over the next five years reflects assumptions for customer growth, ~~utility~~ storage ~~development at Mist,~~facility improvements, technology ~~improvements~~investments and utility ~~system~~distribution improvements, including requirements under the current Pipeline Safety ~~Improvement Act of 2002.~~programs. Most of the required funds are expected to be internally generated over the five-year period, ~~and any~~except for the funding of long-term gas reserves. Any remaining funding that is needed to meet capital requirements 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).~~financing.

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,~~2011, Palomar expects to continue working on revised plans for the ~~planning~~east pipeline segment 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 shippersconduct an open season 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.regional needs. The initial planning and permitting costs ~~are being~~have been 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.GTN. For more information, see Note 812 and “Strategic Opportunities—Pipeline Diversification,” above.

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Financing Activities

Cash ~~provided by~~used in financing activities induring the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 totaled ~~$29.6~~$82.5 million, up from cash used of ~~$96~~$16.4 million for the same period in ~~2009.~~2010. Our short-term debt balances ~~increased $57.9~~decreased $71.0 million in the ~~nine~~three months ended ~~September 30, 2010,~~March 31, 2011, compared to a decrease of ~~$189~~$6.0 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.~~2010. We continue to use long-term debt proceeds ~~primarily~~ to finance capital expenditures, refinance maturing short-term or ~~redeem~~ long-term debt maturities, ~~as well as~~and for general corporate purposes.

Pension Cost and Funding Status of Qualified Retirement Plans

We make pension 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~~$95.4 million at December 31, ~~2009.~~2010. During the first quarter of 2011, we contributed $13.6 million into these plans. We anticipate making additional contributions of between $8 million and $10 million before year end. In ~~March~~ 2010, we contributed a total of $10 million, ~~to these plans, with~~and in 2009 we contributed a ~~portion allocated to 2009 and 2010 plan years.~~total of $25 million. For more information on the ~~funding~~funded status of our qualified retirement plans and other postretirement benefits, see Note 6,9, and Part II, Item 7., “Financial Condition—Pension Cost and Funding Status of Qualified Retirement Plans,” and Part II, Item 8., Note 7,9, “Pension and Other Postretirement Benefits,” in the ~~2009~~2010 Form 10-K.

We also contribute to a ~~multiemployer~~multi-employer pension plan (Western States Plan) pursuant to our collective bargaining agreement. ~~Our total contribution~~We made contributions totaling $0.1 million 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~~three months ended ~~September 30,~~March 31, 2011 and 2010, and ~~2009. See Note 6 for further discussion.~~we expect to contribute a total of $0.4 million during 2011.

Ratios of Earnings to Fixed Charges

For the ~~nine~~three and twelve months ended ~~September 30, 2010~~March 31, 2011 and the twelve months ended December 31, ~~2009,~~2010, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were ~~3.18, 3.79~~7.37, 3.63 and ~~3.86,~~3.73 respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income. ~~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~~our 2010 Form 10-K). At ~~September 30, 2010,~~March 31, 2011, we had a regulatory asset of ~~$111.9~~$117.5 million for deferred environmental costs, which includes ~~$42.2 million of total paid expenditures to date, $57~~$60.5 million for additional costs expected to be paid in the future and accrued interest of ~~$12.7~~$15.3 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 ~~furthe r~~further discussion of contingent liabilities, see Note ~~11.~~

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14.

~~Item~~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 and storage value risk, interest rate risk, foreign currency risk, credit risk and weather risk. We monitor and manage these financial exposures as an integral part of our overall risk ~~(see~~management program. No material changes have occurred related to our disclosures about market risk this quarter. See Part I, Item 1A., “Risk Factors,” and Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk,” in the ~~2009~~2010 Form ~~10-K). The following are updates to certain of~~10-K for details regarding 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 beli eve 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.risks.

~~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 cr edit 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.

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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 liqui dity 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~~ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

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

(b) Changes in Internal Control Over Financial Reporting

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

There have been no changes in our internal control over financial reporting that occurred during the quarter ended ~~September 30, 2010~~March 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. The statements contained in Exhibit 31.1 and Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this Item 4(b).

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PART II. OTHER INFORMATION

~~Item~~ITEM 1. LEGAL PROCEEDINGS

~~Litigation~~

~~We are subject to claims~~Other than the proceedings disclosed in Note 14 and those proceedings disclosed and incorporated by reference in Part I, Item 3., “Legal Proceedings,” in our 2010 Form 10-K, we have only routine nonmaterial litigation ~~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~~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.& #160; As a new facility, Gill Ranch is also subject toThere were no material changes from the risk ~~that there may be structural integrity problems with the facility resulting~~factors discussed 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 d ecline.

~~For additional risk factors, see~~ Part I, “Item 1A. Risk Factors,” in our ~~2009~~2010 Form 10-K. In addition to the other information set forth in this report, you should carefully consider those risk factors, which could materially affect our business, financial condition or results of operations. The risks described in the 2010 Form 10-K are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially affect our financial condition, results of operations or cash flows.

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ITEM 2.

~~Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~

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~~March 31, 2011 of equity securities that are registered pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASE OF EQUITY SECURITIES

					(c)		(d)						(c)		(d)
	(a)		(b)		Total Number of Shares		Maximum Dollar Value of		(a)		(b)		Total Number of Shares		Maximum Dollar Value of
	Total Number		Average		Purchased as Part of		Shares that May Yet Be		Total Number		Average		Purchased as Part of		Shares that May Yet Be
	of Shares		Price Paid		Publicly Announced		Purchased Under the		of Shares		Price Paid		Publicly Announced		Purchased Under the
Period	Purchased(1)		per Share		Plans or Programs(2)		Plans or Programs(2)		Purchased(1)		per Share		Plans or Programs(2)		Plans or Programs(2)
Balance forward						2,124,528	$	16,732,648						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		-		-
01/01/11 - 01/31/11										1,232	$	45.81		-		-
02/01/11 - 02/28/11										21,417		45.76		-		-
03/01/11 - 03/31/11										11,006		47.16		-		-
Total		24,709	$	46.19		2,124,528	$	16,732,648		33,655	$	46.22		2,124,528	$	16,732,648

(1)

During the ~~three months~~quarter ended ~~September 30, 2010, 21,257~~March 31, 2011, 23,503 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~~10,152 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~~quarter ended ~~September 30, 2010,~~March 31, 2011, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.

(2)

We have a common stock share repurchase program ~~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~~quarter ended ~~September 30, 2010,~~March 31, 2011, no shares of our common stock were purchased pursuant to this program. Since the program’s inception in 2000 we have repurchased approximately 2.1 million shares of common stock at a total cost of approximately $83.3 million.

~~Item~~ITEM 6. EXHIBITS

See Exhibit Index attached hereto.

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SI~~GNA~~SIGNATURE~~TURE~~

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~~May 4, 2011

/s/ Stephen P. Feltz

Stephen P. Feltz

Principal Accounting Officer

Treasurer and Controller

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NORTHWEST NATURAL GAS COMPANY

~~EXHIBI~~EXHIBIT INDEX~~T INDEX~~

Quarterly Report on Form 10-Q

For ~~Quarter~~Fiscal Year Ended

~~September 30, 2010~~

March 31, 2011

Exhibit
Number		Document
10.1
4		~~Form of Credit~~Carry and Earning Agreement by and between Encana Oil & Gas (USA) Inc. and 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~~effective as of May ~~31, 2007, including Form of Note.~~1, 2011, as amended by a First Amendment to C&E Agreement, dated March 22, 2011.

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

~~10.2~~12		~~Change in Control Severance Agreement, dated August 27, 2010, between Richard Daniel and NW Natural Gas Storage, LLC.~~Statement re computation of ratios of earnings to fixed charges.

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)~~15-d-14(a), Section 302 of the Sarbanes-Oxley Act of ~~2002~~2002.

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

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

101*		The following materials from Northwest Natural Gas Company Quarterly Report on Form 10-Q for the quarter ended ~~September 30, 2010,~~March 31, 2011, formatted in Extensible Business Reporting Language (XBRL): (i) Consolidated Statements of Income; (ii) Consolidated Balance Sheets; (iii) Consolidated Statements of Cash Flows; and (iv) Related notes.



*		~~Users~~*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.

	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

			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.