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, 2005

OR

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

For the Transition period from                      to                     

Commission File No. 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices) (Zip Code)

Registrant’s Telephone Number, including area code: (503) 226-4211

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

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x    No ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨    No x

At October 31, 2005, 27,549,733 shares of the registrant’s Common Stock, $3-1/6 par value (the only class of Common Stock) were outstanding.

NORTHWEST NATURAL GAS COMPANY

For the Quarterly Period Ended September 30, 2005

		Page Number
	PART I. FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements
	Consolidated Statements of Income for the three-month and nine-month periods ended Sept. 30, 2005 and 2004	3
	Consolidated Balance Sheets at Sept. 30, 2005 and 2004 and Dec. 31, 2004	4
	Consolidated Statements of Cash Flows for the nine-month periods ended Sept. 30, 2005 and 2004	6
	Consolidated Statements of Capitalization at Sept. 30, 2005 and 2004 and Dec. 31, 2004	7
	Notes to Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38
Item 4.	Controls and Procedures	39
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 6.	Exhibits	40
	Signature	41

2

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Income

(Unaudited)

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
Thousands, except per share amounts	2005			2004			2005		2004
Operating revenues:
Gross operating revenues	$	106,667		$	81,441		$	569,111	$	445,550
Cost of sales		62,231			41,958			335,264		241,404
Net operating revenues		44,436			39,483			233,847		204,146
Operating expenses:
Operations and maintenance		25,988			24,507			80,164		74,324
Taxes other than income taxes		8,411			7,268			31,167		27,252
Depreciation and amortization		15,452			14,212			45,959		42,031
Total operating expenses		49,851			45,987			157,290		143,607
Income (loss) from operations		(5,415	)		(6,504	)		76,557		60,539
Other income and expense - net		550			1,644			1,020		2,109
Interest charges - net of amounts capitalized		9,253			8,774			27,287		26,482
Income (loss) before income taxes		(14,118	)		(13,634	)		50,290		36,166
Income tax expense (benefit)		(5,447	)		(5,349	)		17,934		12,555
Net income (loss)	$	(8,671	)	$	(8,285	)	$	32,356	$	23,611
Average common shares outstanding:
Basic		27,560			27,373			27,564		26,868
Diluted		27,630			27,688			27,626		27,187
Earnings (loss) per share of common stock:
Basic	$	(0.31	)	$	(0.30	)	$	1.17	$	0.88
Diluted	$	(0.31	)	$	(0.30	)	$	1.17	$	0.88

See Notes to Consolidated Financial Statements

3

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets

Thousands	Sept. 30, 2005 (Unaudited)			Sept. 30, 2004 (Unaudited)			Dec. 31, 2004
Assets:
Plant and property:
Utility plant	$	1,857,053		$	1,765,461		$	1,794,972
Less accumulated depreciation		532,667			498,286			505,286
Utility plant - net		1,324,386			1,267,175			1,289,686
Non-utility property		39,450			27,151			33,963
Less accumulated depreciation and amortization		5,755			5,118			5,244
Non-utility property - net		33,695			22,033			28,719
Total plant and property		1,358,081			1,289,208			1,318,405
Other investments		57,939			76,368			60,618
Current assets:
Cash and cash equivalents		3,408			4,064			5,248
Accounts receivable		30,518			31,807			63,109
Allowance for uncollectible accounts		(1,553	)		(1,189	)		(2,434	)
Accrued unbilled revenue		16,787			13,958			64,401
Gas inventories		90,961			62,131			58,015
Materials and supplies inventories		7,855			7,804			8,462
Income tax receivable		21,145			8,812			15,970
Prepayments and other current assets		36,106			13,956			24,346
Total current assets		205,227			141,343			237,117
Regulatory assets:
Income tax asset		65,622			64,475			64,734
Deferred environmental costs		17,456			3,441			6,325
Deferred gas costs receivable		5,414			9,130			9,551
Unamortized costs on debt redemptions		6,987			7,450			7,332
Other		4,182			3,999			3,321
Total regulatory assets		99,661			88,495			91,263
Other assets:
Fair value of non-trading derivatives		346,158			70,079			16,399
Other		8,748			9,160			8,393
Total other assets		354,906			79,239			24,792
Total assets	$	2,075,814		$	1,674,653		$	1,732,195

See Notes to Consolidated Financial Statements

4

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets

Thousands	Sept. 30, 2005 (Unaudited)			Sept. 30, 2004 (Unaudited)			Dec. 31, 2004
Capitalization and liabilities:
Capitalization:
Common stock	$	87,230		$	86,816		$	87,231
Premium on common stock		296,376			297,625			300,034
Earnings invested in the business		189,417			165,893			183,932
Unearned stock compensation		(703	)		(994	)		(862	)
Accumulated other comprehensive income (loss)		(1,818	)		(1,016	)		(1,818	)
Total common stock equity		570,502			548,324			568,517
Long-term debt		521,500			484,906			484,027
Total capitalization		1,092,002			1,033,230			1,052,544
Current liabilities:
Notes payable		72,500			82,700			102,500
Long-term debt due within one year		8,000			15,000			15,000
Accounts payable		81,711			60,844			102,478
Taxes accrued		10,867			8,706			10,242
Interest accrued		11,493			11,166			2,897
Other current and accrued liabilities		33,928			30,565			34,168
Total current liabilities		218,499			208,981			267,285
Regulatory liabilities:
Accrued asset removal costs		165,917			146,176			153,258
Customer advances		1,733			1,463			1,529
Unrealized gain on non-trading derivatives - net		338,667			70,079			10,912
Total regulatory liabilities		506,317			217,718			165,699
Other liabilities:
Deferred income taxes		213,126			187,352			211,080
Deferred investment tax credits		5,415			6,501			5,660
Fair value of non-trading derivatives		7,491			—			5,487
Other		32,964			20,871			24,440
Total other liabilities		258,996			214,724			246,667
Commitments and contingencies (see Note 7)		—			—			—
Total capitalization and liabilities	$	2,075,814		$	1,674,653		$	1,732,195

See Notes to Consolidated Financial Statements

5

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended Sept. 30,
Thousands	2005			2004
Operating activities:
Net income	$	32,356		$	23,611
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		45,959			42,031
Deferred income taxes and investment tax credits		1,801			15,111
Undistributed earnings from equity investments		(139	)		(849	)
Allowance for funds used during construction		(351	)		(1,340	)
Deferred gas costs - net		4,137			(14,757	)
Qualified pension plan expense		3,576			3,464
Qualified pension plan contributions		(20,000	)		(2,919	)
Deferred environmental costs		(2,128	)		(1,499	)
Gain on sale of non-utility investments		(12	)		—
Income from investment in life insurance		(1,410	)		(1,974	)
Other		(1,876	)		2,279
Changes in working capital:
Accounts receivable - net of allowance for uncollectible accounts		31,710			17,881
Accrued unbilled revenue		47,614			45,151
Inventories of gas, materials and supplies		(32,339	)		(19,076	)
Income tax receivable		(5,175	)		174
Prepayments and other current assets		2,730			7,044
Accounts payable		(20,767	)		(25,185	)
Accrued interest and other taxes		9,221			8,269
Other current and accrued liabilities		(240	)		(1,024	)
Cash provided by operating activities		94,667			96,392
Investing activities:
Acquisition and construction of utility plant assets		(65,226	)		(110,232	)
Investment in non-utility property		(5,465	)		(3,756	)
Proceeds from sale of non-utility investments		3,001			—
Proceeds from life insurance		296			1,343
Other investments		944			(138	)
Cash used in investing activities		(66,450	)		(112,783	)
Financing activities:
Common stock issued, net of expenses		6,169			44,601
Common stock purchased		(13,827	)		(159	)
Long-term debt issued		50,000			—
Long-term debt redeemed		(15,528	)		—
Change in short-term debt		(30,000	)		(2,500	)
Dividend payments on common stock		(26,871	)		(26,193	)
Cash (used in) provided by financing activities		(30,057	)		15,749
Decrease in cash and cash equivalents		(1,840	)		(642	)
Cash and cash equivalents - beginning of period		5,248			4,706
Cash and cash equivalents - end of period	$	3,408		$	4,064
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	18,414		$	18,538
Income taxes	$	21,939		$	2,500
Supplemental disclosure of non-cash financing activities:
Conversions to common stock:
7-1/4 % Series of Convertible Debentures	$	3,999		$	413

See Notes to Consolidated Financial Statements

6

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Capitalization

	Sept. 30, 2005 (Unaudited)					Sept. 30, 2004 (Unaudited)					Dec. 31, 2004
Common stock equity:
Common stock	$	87,230				$	86,816				$	87,231
Premium on common stock		296,376					297,625					300,034
Earnings invested in the business		189,417					165,893					183,932
Unearned compensation		(703	)				(994	)				(862	)
Accumulated other comprehensive income (loss)		(1,818	)				(1,016	)				(1,818	)
Total common stock equity		570,502		52	%		548,324		53	%		568,517		54	%
Long-term debt:
Medium-Term Notes
First Mortgage Bonds:
6.340% Series B due 2005		—					5,000					5,000
6.380% Series B due 2005		—					5,000					5,000
6.450% Series B due 2005		—					5,000					5,000
6.050% Series B due 2006		8,000					8,000					8,000
6.310% Series B due 2007		20,000					20,000					20,000
6.800% Series B due 2007		9,500					9,500					9,500
6.500% Series B due 2008		5,000					5,000					5,000
4.110% Series B due 2010		10,000					10,000					10,000
7.450% Series B due 2010		25,000					25,000					25,000
6.665% Series B due 2011		10,000					10,000					10,000
7.130% Series B due 2012		40,000					40,000					40,000
8.260% Series B due 2014		10,000					10,000					10,000
4.700% Series B due 2015		40,000					—					—
7.000% Series B due 2017		40,000					40,000					40,000
6.600% Series B due 2018		22,000					22,000					22,000
8.310% Series B due 2019		10,000					10,000					10,000
7.630% Series B due 2019		20,000					20,000					20,000
9.050% Series A due 2021		10,000					10,000					10,000
5.620% Series B due 2023		40,000					40,000					40,000
7.720% Series B due 2025		20,000					20,000					20,000
6.520% Series B due 2025		10,000					10,000					10,000
7.050% Series B due 2026		20,000					20,000					20,000
7.000% Series B due 2027		20,000					20,000					20,000
6.650% Series B due 2027		20,000					20,000					20,000
6.650% Series B due 2028		10,000					10,000					10,000
7.740% Series B due 2030		20,000					20,000					20,000
7.850% Series B due 2030		10,000					10,000					10,000
5.820% Series B due 2032		30,000					30,000					30,000
5.660% Series B due 2033		40,000					40,000					40,000
5.250% Series B due 2035		10,000					—					—
Convertible Debentures
7-1/4% Series due 2012		—					5,406					4,527
		529,500					499,906					499,027
Less long-term debt due within one year		8,000					15,000					15,000
Total long-term debt		521,500		48	%		484,906		47	%		484,027		46	%
Total capitalization	$	1,092,002		100	%	$	1,033,230		100	%	$	1,052,544		100	%

See Notes to Consolidated Financial Statements

7

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Notes to Consolidated Financial Statements

(Unaudited)

1. Basis of Financial Statements

The consolidated financial statements include the accounts of Northwest Natural Gas Company (NW Natural), a regulated utility, and its non-regulated wholly-owned subsidiary businesses, NNG Financial Corporation (Financial Corporation) and Northwest Energy Corporation. Together these businesses are referred to as the “Company.”

The information presented in the consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that the management of the Company 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 the Company’s 2004 Annual Report on Form 10-K (2004 Form 10-K). A significant part of the business of the Company is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.

Certain amounts from prior periods have been reclassified to conform, for comparison purposes, to the current financial statement presentation. These reclassifications had no impact on prior period consolidated net income.

2. New Accounting Standards

Medicare Prescription Drug, Improvement and Modernization Act. In May 2004, the Financial Accounting Standards Board (FASB) issued Staff Position (FSP) No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). FSP No. FAS 106-2 provides specific guidance on accounting for the effects of the Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. The Company has previously determined that the Act has no material impact on cash flows, accumulated postretirement benefit obligations, or net periodic postretirement benefit costs under the current plan design.

Inventory Costs. In November 2004, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” SFAS No. 151 amends the guidance on inventory pricing to require that abnormal amounts of idle facility expense, freight, handling costs and wasted material be charged to current period expense rather than capitalized as inventory costs. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company is evaluating the effect of the adoption and implementation of SFAS No. 151, which is not expected to have a material impact upon the Company’s financial condition, results of operations or cash flows.

Share Based Payments. In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share Based Payment” (SFAS No. 123R), that requires companies to expense the fair value of employee stock options and similar awards. Under SFAS No. 123R, share based payment awards will be measured at fair value on the date of grant based on the estimated number of awards expected to vest. The estimated fair value will be recognized as compensation expense over the period an employee is required to provide service in exchange for the award, usually referred to as the vesting period. The expense would be adjusted for actual forfeitures that occur before vesting, but would not be adjusted for awards that expire or terminate after vesting. The Company is evaluating different option-pricing models to determine the most appropriate measure of fair value under the new standard. Estimated fair value and compensation expense are currently calculated using the Black-Scholes option pricing model, and its corresponding impact on the financial statements is provided in Note 3 below and in Part II, Item 8., Note 4, of the 2004 Form 10-K. The Company is required to adopt SFAS No. 123R in the first quarter of 2006. The Company is evaluating the effect of the adoption and implementation of SFAS No. 123R, which is not expected to have a material impact on the Company’s financial condition, results of operations or cash flows.

Non-monetary Transactions. In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets – An Amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions,” which redefines the types of non-monetary exchanges that require fair value measurement. The Company is required to adopt SFAS No. 153 for non-monetary transactions entered into after June 30, 2005. Adoption of this new standard did not have a material impact on the Company’s financial condition or results of operations.

Conditional Asset Retirement Obligations. In March 2005, the FASB issued FASB Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143.” FIN 47 clarifies that an entity is required to recognize a liability for a legal obligation to perform an asset retirement activity if the fair value can be reasonably estimated even though the timing and/or method of settlement are conditional on a future event. FIN 47 is required to be adopted for annual reporting periods ending after Dec. 15, 2005. The Company is

8

evaluating the effect of the adoption and implementation of FIN 47, which is not expected to have a material impact on its financial condition, results of operations or cash flows.

Accounting Changes and Error Corrections. In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which provides guidance on the accounting for and reporting of accounting changes and error corrections. The statement requires retrospective application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine the period-specific effects or the cumulative effect of the change. The guidance provided in Accounting Principles Board (APB) Opinion No. 20 for reporting the correction of an error in previously issued financial statements remains unchanged and requires the restatement of previously issued financial statements. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

Purchases and Sales of Inventory with the Same Counterparty. In September 2005, the Emerging Issues Task Force (EITF) reached a final consensus on Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”. EITF 04-13 requires that two or more legally separate exchange transactions with the same counterparty be combined and considered a single arrangement for purposes of applying APB Opinion No. 29, “Accounting for Nonmonetary Transactions” (APB 29), when the transactions are entered into in contemplation of one another. EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. The Company is evaluating the effect of the adoption of EITF 04-13, which is not expected to have a material impact on the Company’s financial condition, results of operations or cash flows.

3. Stock-Based Compensation

NW Natural’s stock-based compensation plans consist of the Long-Term Incentive Plan (LTIP), the Restated Stock Option Plan (Restated SOP), the Employee Stock Purchase Plan (ESPP) and the Non-Employee Directors Stock Compensation Plan (NEDSCP). These plans are designed to promote stock ownership in NW Natural by employees and officers, and, in the case of the NEDSCP, non-employee directors. See Part II, Item 8., Note 4, in the 2004 Form 10-K for a discussion of the Company’s stock-based compensation plans.

Long-Term Incentive Plan. At Sept. 30, 2005, the aggregate number of performance-based shares eligible to be awarded under the Company’s LTIP at the threshold, target and maximum levels were as follows:

		No. of Performance Shares Awarded
Year Awarded	Performance Period	Threshold	Target	Maximum
2003	2003-05	6,250	25,000	50,000
2004	2004-06	6,750	27,000	54,000
2005	2005-07	8,750	35,000	70,000
	Total	21,750	87,000	174,000

For the 2003-05 performance period, a series of performance targets were established based on the Company’s average annual return on equity (ROE) for the performance period corresponding to award opportunities ranging from 0 percent to 200 percent of the target awards. No awards are payable unless the threshold annual average ROE level, tied to the Company’s authorized ROE, is achieved during the award period. The maximum awards are payable only upon the achievement of an average annual ROE that is 200 basis points above the Company’s regulatory authorized ROE. For the 2004-06 and 2005-07 performance periods, awards will be based on total shareholder return relative to a peer group of gas distribution companies over the three-year performance period and on performance milestones relative to the Company’s core and non-core strategies. During the performance period, the Company will recognize compensation expense and liability for the LTIP awards based on performance levels achieved, and expected to be achieved, and the estimated market value of the common stock as of the distribution date. For the quarter and nine months ended Sept. 30, 2005, no amounts have been accrued as compensation expense under the LTIP for the 2003-05 performance period, and $0.2 million and $1.3 million were accrued as compensation expense under the LTIP for the 2004-06 and 2005-07 performance periods, respectively.

Restated Stock Option Plan. Under the Restated SOP, options on 1,232,800 shares were available for grant and options to purchase 310,716 shares were outstanding at Sept. 30, 2005. Options generally have 10-year terms and vest ratably over a three-year period following the date of grant. Options to purchase 6,000 shares of common stock, at an exercise price of $38.30, were granted in the first nine months of 2005. The exercise price is equal to the market price of the common stock on the date of grant.

9

The Company has adopted the disclosure requirements of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure—An Amendment of FASB Statement No. 123.” However, it continues to account for stock-based compensation using the intrinsic value method prescribed in APB Opinion No. 25, “Accounting for Stock Issued to Employees.” In accordance with APB Opinion No. 25, no compensation expense is recognized for options granted under the Restated SOP. For a further discussion of expense recognition for stock-based compensation, see Note 2, Share Based Payments, above.

If compensation expense for awards under the Restated SOP and for shares issued under the ESPP had been recognized during the three- and nine-month periods ended Sept. 30, 2005 and 2004 based on fair value on the date of grant, net income and earnings per share would have resulted in the pro forma amounts shown below:

Pro Forma Effect of Stock-Based Options and ESPP:	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
Thousands, except per share amounts	2005			2004			2005			2004
Net income (loss) as reported	$	(8,671	)	$	(8,285	)	$	32,356		$	23,611
Pro forma stock-based compensation expense determined under the fair value based method - net of tax		(84	)		(109	)		(247	)		(315	)
Pro forma net income (loss) - basic		(8,755	)		(8,394	)		32,109			23,296
Debenture interest - net of tax		—			60			—			179
Pro-forma net income (loss) - diluted	$	(8,755	)	$	(8,334	)	$	32,109		$	23,475
Basic earnings (loss) per share
As reported	$	(0.31	)	$	(0.30	)	$	1.17		$	0.88
Pro forma	$	(0.32	)	$	(0.31	)	$	1.16		$	0.87
Diluted earnings (loss) per share
As reported	$	(0.31	)	$	(0.30	)	$	1.17		$	0.88
Pro forma	$	(0.32	)	$	(0.31	)	$	1.16		$	0.86

The Company will adopt SFAS No. 123R for expensing employee stock options and other share based compensation beginning in 2006 (see Note 2), as required. For purposes of the pro forma disclosures above, the estimated fair value of stock options is amortized to expense over the vesting period.

4. Use of Derivative Instruments

NW Natural enters into forward contracts and other related financial transactions for the purchase of natural gas that qualify as derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149 (collectively referred to as SFAS No. 133). NW Natural utilizes derivative financial instruments to manage commodity prices related to natural gas supply requirements. See Part II, Item 8., Notes 1 and 11, in the 2004 Form 10-K.

In the normal course of business, NW Natural enters into forward natural gas commodity purchase (gas supply) contracts to meet the requirements of core utility customers. In the first nine months of 2005, NW Natural entered into a series of exchange transactions with an unaffiliated energy marketing company which resulted in a change in the Company’s accounting treatment for its forward gas supply contracts under SFAS No. 133. SFAS No. 133 requires that derivative instruments be recorded on the balance sheet at fair value. Prior to March 31, 2005, the Company’s forward gas supply contracts were excluded from the fair value measurement requirement of SFAS No. 133 because these contracts were eligible for the normal purchases and normal sales exception. These contracts are now accounted for as derivative instruments and marked-to-market based on fair value pursuant to SFAS No. 133. These contracts include 29 index-based contracts and one fixed-price contract. The mark-to-market adjustment for the forward gas supply contracts at Sept. 30, 2005 is an unrealized loss of $2.1 million, consisting of an unrealized loss of $5.3 million on index-based contracts and a $3.2 million unrealized gain on a fixed-price contract. The net unrealized loss is recorded as a liability with an offsetting entry to a regulatory asset based on regulatory deferral accounting under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (see Part II, Item 8., Note 1, “Industry Regulation,” in the 2004 Form 10-K).

Due to the forward gas supply contracts being classified as derivatives for accounting purposes, the corresponding derivative financial contracts originally designated as cash flow hedges no longer qualify for hedge accounting under SFAS No. 133, even though these contracts continue to hedge the financial risk exposure of the forward gas supply

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contracts. However, due to regulatory deferral accounting under SFAS No. 71, the accounting change had no impact on the Company’s financial condition, results of operations or cash flows. The mark-to-market adjustment at Sept. 30, 2005 for the fixed-price financial swap contracts is an unrealized gain of $321.1 million.

Fixed-price financial call options are purchased to hedge the Company’s forecasted purchases of swing supplies or spot gas. The mark-to-market adjustment at Sept. 30, 2005 is an unrealized gain of $19.4 million. These unrealized gains and losses are subject to regulatory deferral and, as such, are recorded as a non-trading derivative asset or liability which is offset by recording a corresponding amount to a deferred asset or liability account.

Foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for NW Natural’s commodity and commodity-related demand charges paid in Canadian dollars. These forward contracts qualify for cash flow hedge accounting treatment under SFAS No. 133. The mark-to-market adjustment at Sept. 30, 2005 is an unrealized gain of $0.3 million. These unrealized gains and losses are subject to regulatory deferral and, as such, are recorded as a derivative asset or liability which is offset by recording a corresponding amount to a regulatory asset or regulatory liability account.

At Sept. 30, 2005 and 2004 and Dec. 31, 2004, unrealized gains or losses from mark-to-market valuations of the Company’s derivative instruments were not recognized in current income, but were reported as regulatory liabilities or regulatory assets because regulatory mechanisms provide for the realized gains or losses at settlement to be included in utility gas costs subject to regulatory deferral treatment. The estimated fair values (unrealized gains and losses) of derivative instruments outstanding were as follows:

	Fair Value Gains (Losses)
	Sept. 30,					Dec. 31, 2004
Thousands	2005			2004
Natural gas commodity-based derivative instruments:
Fixed-price financial swaps	$	321,119		$	67,422	$	12,641
Fixed-price financial call options		19,394			1,878		(2,195	)
Indexed-price physical supply		(5,281	)		—		—
Fixed-price physical supply		3,158			—		24
Physical supply contracts with embedded options		—			550		—
Foreign currency forward purchases		277			229		442
Total	$	338,667		$	70,079	$	10,912

5. Segment Information

The Company principally operates in a segment of business, “Utility,” consisting of the distribution and sale of natural gas. Another segment, “Interstate Gas Storage,” represents natural gas storage services provided to interstate customers and asset optimization services under a contract with an unaffiliated energy marketing company using temporarily unused portions of NW Natural’s upstream pipeline transportation capacity and gas storage capacity (see Part II, Item 8., Note 2, in the 2004 Form 10-K). The remaining segment, “Other,” primarily consists of non-utility operating activities and non-regulated investments.

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The following table presents information about the reportable segments for the three- and nine-month periods ended Sept. 30, 2005 and 2004. Inter-segment transactions are insignificant.

	Three Months Ended Sept. 30,											Nine Months Ended Sept. 30,
Thousands	Utility			Interstate Gas Storage		Other			Total			Utility		Interstate Gas Storage		Other			Total
2005
Net operating revenues	$	41,261		$	3,126	$	49		$	44,436		$	226,649	$	7,107	$	91		$	233,847
Depreciation and amortization		15,289			163		—			15,452			45,469		490		—			45,959
Other operating expenses		34,169			197		33			34,399			110,650		571		110			111,331
Income (loss) from operations		(8,196	)		2,766		15			(5,415	)		70,531		6,046		(20	)		76,557
Income from financial investments		436			—		68			504			1,410		—		139			1,549
Net income (loss)		(10,473	)		1,571		231			(8,671	)		28,383		3,313		660			32,356
Total assets at Sept. 30, 2005		2,028,389			34,697		12,728			2,075,814			2,028,389		34,697		12,728			2,075,814
2004
Net operating revenues	$	38,114		$	1,326	$	43		$	39,483		$	199,307	$	4,713	$	126		$	204,146
Depreciation and amortization		14,093			119		—			14,212			41,684		347		—			42,031
Other operating expenses		31,554			177		44			31,775			100,902		546		128			101,576
Income (loss) from operations		(7,532	)		1,030		(2	)		(6,504	)		56,722		3,820		(3	)		60,539
Income from financial investments		549			—		898			1,447			1,974		—		849			2,823
Net income (loss)		(9,355	)		582		488			(8,285	)		20,764		2,077		770			23,611
Total assets at Sept. 30, 2004		1,633,850			22,611		18,192			1,674,653			1,633,850		22,611		18,192			1,674,653

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6. Pension and Other Postretirement Benefits

Net Periodic Benefit Cost

The following table provides the components of net periodic benefit cost for the qualified and non-qualified pension plans and other postretirement benefit plans for the three- and nine-month periods ended Sept. 30, 2005 and 2004. See Part II, Item 8., Note 7, in the 2004 Form 10-K for a discussion of the assumptions used in measuring these costs and benefit obligations.

Thousands	Pension Benefits						Other Postretirement Benefits
	Three Months Ended Sept. 30,
	2005			2004			2005		2004
Service cost	$	1,564		$	1,409		$	114	$	132
Interest cost		3,377			3,199			308		364
Special termination benefits		63			—			—		—
Expected return on plan assets		(3,776	)		(3,309	)		—		—
Amortization of transition obligation		—			—			103		103
Amortization of prior service cost		361			274			—		—
Recognized actuarial loss		599			436			72		118
Net periodic benefit cost	$	2,188		$	2,009		$	597	$	717
Thousands	Pension Benefits						Other Postretirement Benefits
	Nine Months Ended Sept. 30,
	2005			2004			2005		2004
Service cost	$	4,742		$	4,227		$	343	$	396
Interest cost		9,902			9,597			924		1,092
Special termination benefits		189			—			—		—
Expected return on plan assets		(10,837	)		(9,927	)		—		—
Amortization of transition obligation		—			—			308		309
Amortization of prior service cost		807			822			—		—
Recognized actuarial loss		1,561			1,308			216		356
Net periodic benefit cost	$	6,365		$	6,027		$	1,791	$	2,153

Employer Contributions

The Company makes contributions to its qualified defined benefit pension plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. Generally, it is the Company’s policy to contribute at least the minimum amount required by the Employee Retirement Income Security Act of 1974. It is also the Company’s intent to contribute additional amounts as are sufficient on an actuarial basis to maintain funding targets and provide for the payment of future benefits under the plans.

In 2004, the Company contributed $5.3 million to the Retirement Plan for Non-Bargaining Unit Employees (NBU Plan) for the 2004 plan year, of which $1.0 million represented the minimum required funding. Although the Company was not required to make additional cash contributions to these plans in 2005 based on minimum funding requirements, during the quarter ended Sept. 30, 2005, the Company contributed an additional $20 million to its two qualified defined benefit pension plans for the plan year 2004, consisting of $13 million to the NBU Plan and $7 million to the Retirement Plan for Bargaining Unit Employees.

The Company continues to evaluate its qualified plans’ funding status based on projected benefit obligations, expected returns on plan assets and anticipated changes in actuarial assumptions to determine if any contributions will be made prior to Dec. 31, 2005 for the 2005 plan year. In addition, the Company will continue to make cash contributions during 2005 in the form of ongoing benefit payments as required for its unfunded non-qualified supplemental pension plans and other postretirement benefit plans. See Part II, Item 8., Note 7, in the 2004 Form 10-K.

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7. Commitments and Contingencies

Environmental Matters

NW Natural owns, or has previously owned, properties that may require environmental remediation or action. NW Natural accrues all material loss contingencies relating to these properties that it believes to be probable of assertion and reasonably estimable. The Company continues to study the extent of its potential environmental liabilities, but due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several environmental site investigations, the range of potential loss beyond the amounts currently accrued, and the probabilities thereof, cannot be reasonably estimated. NW Natural regularly reviews its remediation liability for each site where it may be exposed to remediation responsibilities. The costs of environmental remediation are difficult to estimate. A number of steps are involved in each environmental remediation effort, including site investigations, remediation, operations and maintenance, monitoring and site closure. Each of these steps may, over time, involve a number of alternative actions, each of which can change the course of the effort. In certain cases, in addition to NW Natural, 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 of the remediation effort. The allocation of liabilities among the potentially responsible parties is often subject to dispute and 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. To the extent reasonably estimable, NW Natural estimates the costs of 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 a better estimate within this range of probable cost, NW Natural records the liability at the lower end of this range. It is likely that changes in these estimates will occur throughout the remediation process for each of these sites due to uncertainty concerning NW Natural’s responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives. The status of each of the sites currently under investigation is provided below. Also, see Part II, Item 8., Note 12, in the 2004 Form 10-K for a description of these properties and further discussion.

Gasco site. NW Natural owns property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). The Gasco site has been under investigation by NW Natural for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, the Company 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. The Company estimates its range of remaining potential liability for this site, including the cost of investigation, from among feasible alternatives, at between $1.5 million and $7 million. NW Natural has accrued a liability for the Gasco site at the low end of the range because no amount within the range is considered to be more likely than another.

Siltronic (formerly Wacker) site. NW Natural previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (formerly Wacker Siltronic Corporation) (the Siltronic site). During the first nine months of 2005, the estimated liability for this site increased due to new information regarding required additional storm-water pollution work and indoor air quality studies, resulting in an additional accrual of less than $0.1 million. The amount of the additional accrual was deferred to a regulatory asset account pursuant to an order of the Public Utility Commission of Oregon (OPUC) (see “Regulatory and Insurance Recovery for Environmental Matters,” below).

Portland Harbor site. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (the Portland Harbor) that includes the area adjacent to the Gasco site and the Siltronic site. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and the Company was notified that it is a potentially responsible party. 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). NW Natural’s share of the original cost estimate for the RI/FS work, which was expected to be completed in 2007, was $1.6 million. However, as a result of the EPA’s indication that further study will be required, an additional accrual of $1.3 million was recorded in the third quarter of 2005 for the additional studies and related legal costs. Current information is not sufficient to reasonably estimate additional liabilities, if any, or the range of potential liabilities, for environmental remediation and monitoring after the RI/FS work plan is completed, except for the early action removal of a tar deposit in the river sediments discussed below.

In April 2004 the Company 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. In July 2004, the EPA approved an initial work plan for the early action removal. NW Natural is expected to complete the removal of the tar deposit in the Portland Harbor in November 2005. Additional accruals of $5.3 million and $1.6 million were recorded in the second and third quarters of

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2005, respectively, based on revised estimates of remediation work and ongoing monitoring. The remaining liability for this work is $9.2 million at Sept. 30, 2005.

Oregon Steel Mills site. In 2004, the Company 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 the Company’s predecessor, Portland Gas & Coke Company, and ten 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 Port’s complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. In March 2005, motions to dismiss by the Company and other third-party defendants were denied on the basis that the failure of the Port to plead and prove that the Company was in violation of law was an affirmative defense that may be asserted at trial, but did not provide a sufficient basis for dismissal of the Port’s claim. No date has been set for trial and discovery is ongoing. The Company does not expect that the ultimate disposition of this matter will have a materially adverse affect on the Company’s financial condition, results of operations or cash flows.

Regulatory and Insurance Recovery for Environmental Matters. In May 2003, the OPUC approved NW Natural’s request for deferral of environmental costs associated with specific sites, including the Gasco, Siltronic, and Portland Harbor sites. The authorization, which has been extended through January 2006 and expanded to include the Oregon Steel Mills site, allows NW Natural to defer and seek recovery of unreimbursed environmental costs in a future general rate case. Through Sept. 30, 2005, the Company has paid a cumulative total of $5.4 million relating to the named sites since the effective date of the deferral authorization.

On a cumulative basis, NW Natural has recognized a total of $22.2 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, $10.2 million has been spent to-date and $12.0 million is reported as an outstanding liability. At Sept. 30, 2005, the Company had a regulatory asset of $17.4 million which includes $5.4 million of total expenditures to date and accruals for an additional estimated cost of $12.0 million. The Company believes the recovery of these costs is probable through the regulatory process. The Company also has an insurance receivable of $1.1 million, which is not included in the regulatory asset amount. The Company intends to pursue recovery of these environmental costs from its general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. The Company considers insurance recovery probable based on a combination of factors, including a review of the terms of its 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 recent Oregon legislation that allows an insured party to seek recovery of “all sums” from one insurance company. The Company has not filed claims for insurance recovery nor have the insurance companies approved or denied coverage of these claims.

Legal Proceedings

The Company is subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings, including the matters described below, cannot be predicted with certainty, the Company does not expect that the ultimate disposition of these matters will have a materially adverse effect on the Company’s financial condition, results of operations or cash flows.

Independent Backhoe Operator Action. The Company previously reported the lawsuits filed against it in the consolidated cases of Kerry Law and Arnold Zuehlke, on behalf of themselves and all others similarly situated v. Northwest Natural Gas Company (U.S. Dist. Ct. D. Or. Case No. CV-04-728-KI), Ike Whittlesey, C.G. Nick Courtney, Mark Parrish, John J. Shooter, Roger Whittlesey and Philip Courtney v. Northwest Natural (U.S. Dist. Ct. D. Or. Case No. CV-05-241-KI), and Ken Holtmann and Jeffrey Carl O’Neal v. Northwest Natural (U.S. Dist. Ct. D. Or. Case No. CV-05-724-KI). Ten plaintiffs remain in this consolidated case. The claims are more fully described in Part II, Item 8., Note 12, “Legal Proceedings,” in the 2004 Form 10-K.

Plaintiffs in the consolidated case are or have been independent backhoe operators who performed services for the Company under contract. Plaintiffs allege violation of the Fair Labor Standards Act for failure to pay overtime and also assert state wage and hour claims. Plaintiffs claim that they should have been considered “employees” of the Company, and seek overtime and interest to be proven, liquidated damages equal to the overtime award, civil penalties and attorneys’ fees and costs. Additionally, plaintiffs allege that the failure to classify them as employees constituted a breach of contract and a tort under and with respect to certain unspecified Company employee benefits plans. Plaintiffs seek an unspecified amount of damages for the value of what they would have received under these employee benefit plans if they had been classified as employees.

In October 2005, the court granted the Company’s motion to stay plaintiffs’ claims pending exhaustion of the administrative review process with regard to each of the plans under which plaintiffs allege that they would have been

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eligible to receive benefits. There is insufficient information at this time to reasonably estimate the range of liability, if any, from these claims.

Industrial Customers Switching from Transportation to Sales Service

High natural gas prices have resulted in several of NW Natural’s large industrial transportation customers electing to receive gas commodity under sales service from NW Natural instead of arranging for their own supplies through independent third parties. Since these customers are electing the transfer to sales service after commodity rates were set in the annual PGA, the Company believes its tariff requires it to charge these customers the incremental cost of gas supply incurred by the Company to serve those customers. The Company has notified these customers that they will be charged the incremental gas costs, if any. Certain of these customers have notified the Company that they expected to be charged gas costs at the Company’s weighted average cost of gas price. The Company is working with the OPUC and customer groups to resolve the matter. If it is determined by the OPUC that NW Natural is not allowed to charge these customers its incremental costs, or if customers file suit and are awarded damages in future litigation, then the potential impact could be material to the Company’s financial results in 2005 and 2006, depending on the price and volume of incremental gas purchases.

8. Comprehensive Income

For the nine months ended Sept. 30, 2005 and 2004, reported net income was equivalent to total comprehensive income (loss). Items that are excluded from net income and charged directly to common stock equity are accumulated in other comprehensive income (loss), net of tax. The amount of accumulated other comprehensive loss is $1.8 million at Sept. 30, 2005, which is included in common stock equity (see the accompanying Consolidated Statements of Capitalization, above).

9. Notes Payable and Lines of Credit

In September 2005, NW Natural entered into an agreement for unsecured lines of credit totaling $200 million with five commercial banks, replacing the existing $150 million credit facilities. The new bank lines of credit (bank lines) are available and committed for a term of five years, beginning Oct. 1, 2005 and expiring on Sept. 30, 2010. NW Natural’s bank lines are used primarily as back-up support for the notes payable under the Company’s commercial paper borrowing program. Commercial paper borrowing provides the liquidity to meet the working capital and external financing requirements of NW Natural. The Company received regulatory authorization for the new bank lines in October 2005.

Under the terms of these bank lines, NW Natural pays upfront fees and annual commitment fees but is not required to maintain compensating bank balances. The interest rates on outstanding loans, if any, under these bank lines are based on then-current market interest rates. All principal and unpaid interest under the bank lines is due and payable on Sept. 30, 2010.

The bank lines require that NW Natural maintain credit ratings with Standard & Poor’s and Moody’s Investors Service and to notify the banks of any change in its senior unsecured debt ratings by such rating agencies. A change in NW Natural’s credit rating is not an event of default, nor is the maintenance of a specific minimum level of credit rating a condition of drawing upon the bank lines. However, interest rates on any loans outstanding under these bank lines are tied to credit ratings, which would increase or decrease the cost of any loans under the bank lines when ratings are changed.

The bank lines also require the Company to maintain an indebtedness to total capitalization ratio of 65 percent or less. Failure to comply with this covenant would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding. NW Natural was in compliance with an equivalent covenant in the prior year’s bank lines at Sept. 30, 2005, with an indebtedness to total capitalization ratio of 51.4 percent.

10. Long-Term Debt

In June 2005, the Company issued and sold $50 million in principal amount of secured Medium Term Notes (MTNs), consisting of $40 million of the 4.70% Series B due 2015 and $10 million of the 5.25% Series B due 2035. Proceeds from these sales were used, in part, to redeem $15 million of maturing MTNs in July 2005 (see below), and the balance was applied to the Company’s ongoing utility construction program and the repayment of short-term debt.

In July 2005, the Company redeemed three series of its maturing MTNs aggregating $15 million in principal amount. The series redeemed were the 6.34% Series B, the 6.38% Series B and the 6.45% Series B, each with a principal

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balance outstanding of $5 million due in July 2005. The MTNs were redeemed with proceeds from the sales of $50 million in principal amount of MTNs in June 2005 (see above).

In August, the Company redeemed all of its outstanding Convertible Debentures, 7-1/4% Series due 2012 (the Debentures), at 100% of the principal amount outstanding plus accrued unpaid interest to Aug. 31, 2005 (the redemption date). All but $0.5 million of the Debentures were converted into shares of the Company’s Common Stock on or before the redemption date at the rate of 50.25 shares for each $1,000 principal amount of Debentures. The Debentures were redeemed with cash from operations and proceeds from the sale of commercial paper.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

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

The following is management’s assessment of Northwest Natural Gas Company’s financial condition including the principal factors that affect results of operations. The discussion refers to the consolidated activities of the Company for the three and nine months ended Sept. 30, 2005 and 2004. Unless otherwise indicated, references in this discussion to Notes are to the notes to the accompanying consolidated financial statements.

The consolidated financial statements include the regulated parent company, Northwest Natural Gas Company (NW Natural), and its non-regulated wholly-owned subsidiaries:

• NNG Financial Corporation (Financial Corporation), and its wholly-owned subsidiaries

• Northwest Energy Corporation, and its wholly-owned subsidiary

Together these businesses are referred to herein as the “Company.” In this report, the term “utility” is used to describe the Company’s regulated gas distribution business and the term “non-utility” is used to describe its interstate gas storage business and other non-regulated activities (see Note 5).

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. The Company believes this per share information is useful because it enables readers to better understand the impact of these factors on earnings. All references in this report to earnings per share are on the basis of diluted shares, except where otherwise noted. See Part II, Item 8., Note 1, “Earnings Per Share,” in the Company’s 2004 Annual Report on Form 10-K (2004 Form 10-K).

Application of Critical Accounting Policies and Estimates

In preparing the Company’s 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 its critical accounting policies to be those that are most important to the representation of the Company’s financial condition and results of operations and that require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if the Company reported under different conditions or using different assumptions.

The Company’s most critical estimates or judgments involve regulatory cost recovery, unbilled revenues, derivative instruments, pension assumptions, income taxes and environmental contingencies (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the 2004 Form 10-K). There have been no material changes to the information provided in the Company’s 2004 Form 10-K with respect to the application of critical accounting policies and estimates, except as indicated below under “Accounting for Derivative Instruments and Hedging Activities” and “Accounting for Contingencies.” Management has discussed its estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board.

Accounting for Derivatives Instruments and Hedging Activities

In the normal course of business, NW Natural enters into natural gas commodity purchase and sale contracts using physical assets owned or contractually obligated to the utility, including gas storage and pipeline transportation capacity. Prior to 2005, these contracts qualified for the normal purchase and normal sale exception as defined by Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149 (collectively referred to as SFAS No. 133) (see Note 4). In 2005, NW Natural entered into an agreement providing for natural gas commodity exchange transactions with an unaffiliated energy marketing company, which involved gas purchases by NW Natural originally intended for gas sales to utility customers. These exchanges resulted in the Company’s natural gas purchase contracts no longer qualifying for the normal purchase and normal sale exception under SFAS No. 133. As a result, these contracts are accounted for as derivative instruments and marked-to-market based on fair value pursuant to SFAS No. 133, effective March 31, 2005. The mark-to-market adjustment at Sept. 30, 2005 resulted in a net unrealized loss of $2.1 million, which was recorded on the balance sheet at fair value. Generally, these physical gas purchases are subject to regulatory deferral, and, as such, any unrealized gain or loss in the fair value is not recognized in current income but is recorded as a regulatory asset or regulatory liability pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (see Part II, Item 8., Note 1, in the 2004 Form 10-K) and included in cost of gas in annual rate changes under

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the Company’s Purchased Gas Adjustment (PGA) tariffs. The Company’s estimate of fair value is determined by internal modeling based on natural gas index prices that are subject to market volatility and an evaluation of counterparty credit risk (see Item 3., “Quantitative and Qualitative Disclosures About Market Risk”). For estimated fair values (unrealized gains and losses) at Sept. 30, 2005 and 2004 and Dec. 31, 2004, see Note 4. As a result of these forward gas purchase contracts being classified as derivatives for accounting purposes, any related financial derivative instruments (e.g., financial swaps and call options) previously designated as hedge instruments against the physical gas purchase contracts, no longer qualify for hedge accounting under SFAS No. 133. Therefore, the financial swap and call option contracts are no longer designated as cash flow hedges although they continue to economically hedge the financial risk exposure of the underlying physical gas purchase contracts. The change from hedge accounting treatment had no income statement effect due to the application of SFAS No. 71 for unrealized gains and losses on hedge contracts expected to be included in the determination of future gas rates.

Accounting for Contingencies

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 SFAS No. 5, “Accounting for Contingencies.” NW Natural updates its estimates of loss contingencies and related disclosures when new information becomes available. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties, and NW Natural records accruals for loss contingencies based on an analysis of potential results, developed in consultation with outside counsel and consultants when appropriate. When information is sufficient to estimate only a range of potential liabilities, and no point within the range is more likely than any other, the Company recognizes an accrued liability at the lower end of the range and discloses the range (see “Contingencies,” below.) It is possible, however, that the range of potential liabilities could be significantly different than amounts currently accrued and disclosed, and the Company’s financial condition and results of operations could be materially affected by changes in assumptions or estimates related to these contingencies.

With respect to its environmental liabilities and related costs, NW Natural develops estimates based on currently available information, existing technology and environmental regulations. NW Natural received regulatory approval to defer and seek recovery of costs related to certain sites and believes the recovery of any costs not recovered under its general liability insurance policies is probable through the regulatory process (see Note 7). In accordance with SFAS No. 71, the Company has recorded a regulatory asset for the amount expected to be recovered. The Company intends to pursue recovery for these environmental costs from its general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. At Sept. 30, 2005, $17.4 million in environmental costs have been recorded as a regulatory asset, including $5.4 million of costs paid to-date and $12.0 million has been accrued for estimated future environmental costs. If it is determined that both the insurance recovery and future rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is made.

Earnings and Dividends

Three months ended Sept. 30, 2005 compared to Sept. 30, 2004

The Company incurred a consolidated loss of $8.7 million, or 31 cents a share, for the three months ended Sept. 30, 2005, as compared to a loss of $8.3 million, or 30 cents a share, for the third quarter of 2004. The third quarter loss for both years was attributable to the Company’s utility operations, which recorded losses of $10.5 million and $9.4 million for the three months ended Sept. 30, 2005 and 2004, respectively. A loss from utility operations is typical during the third quarter due to the lower summertime use of natural gas. With respect to the Company’s non-utility operating results, the interstate gas storage business recorded net income of $1.6 million for the three months ended Sept. 30. 2005, compared to net income of $0.6 million for the same period last year, and other non-regulated business activities earned $0.2 million in the 2005 period compared to $0.5 million in 2004.

The increase in third quarter consolidated net loss was primarily due to:

• an increase in utility operating expenses of $3.8 million or 8 percent over last year, including higher operations and maintenance expense ($1.5 million) partly related to increased payroll and employee benefit costs, higher property tax and depreciation expense ($1.6 million) related to new plant investments, and higher revenue-based franchise taxes ($0.5 million) related to increased gross revenues (see “Operating Expenses,” below); however, these increases in utility operating expenses were largely covered by revenue increases approved in the most recent general rate cases in Oregon and Washington;

• an increase in the utility’s net operating revenues (margin) of $3.1 million or 8 percent, largely offsetting the increase in utility operating expenses (see above), due to general rate increases in Oregon in 2003 and 2004 and in Washington in 2004 to recover the higher cost of service for new plant

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investments and expected operating cost increases, to residential and commercial customer growth of 3.4 percent, and to an improvement in industrial margins from increased sales to higher margin rate schedules (see Part II, Item 7., “Results of Operations—Regulatory Matters—General Rate Cases,” in the 2004 Form 10-K and “Comparison of Gas Distribution Operations—Residential and Commercial Sales” and “—Industrial Sales and Transportation,” below);

• an increase in interstate gas storage revenues ($1.8 million) primarily due to an increase in optimization services, which utilizes unused portions of the Company’s gas storage and upstream pipeline transportation capacity (see “Interstate Gas Storage,” below); and

• a nominal increase in realized gas cost savings due to lower actual gas purchase costs compared to the costs embedded in customer rates, which includes upstream sales margin credited to the cost of gas, despite significantly higher spot gas prices during the current period compared to a year ago when customer rates were set (see “Cost of Gas Sold,” below).

Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004

Consolidated net income was $32.4 million, or $1.17 a share, for the nine months ended Sept. 30, 2005, compared to $23.6 million, or $0.88 a share, for the same period of 2004. In the nine months ended Sept. 30, 2005, the Company earned $28.4 million from utility operations, $3.3 million from interstate storage operations and $0.7 million from other non-regulated activities compared, respectively, to $20.8 million, $2.1 million and $0.8 million in the nine months ended Sept. 30, 2004.

The increase in year-to-date consolidated net income was primarily due to:

• an increase in utility margin of $27.3 million or 14 percent over last year primarily due to rate increases for new plant investments, and to customer growth and improved industrial margins;

• a net 1 percent increase in volumes delivered to residential and commercial customers over last year due to 3.4 percent customer growth and 7 percent colder weather, partially offset by declining use per customer per degree day; however, the margin gained from colder weather compared to last year, and the margin lost from declining use, were largely offset by the Company’s weather normalization and conservation tariff mechanisms (see “Results of Operations—Comparison of Gas Distribution Operations (Utility),” below and Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms,” in the 2004 Form 10-K);

• an increase in realized gas cost savings as compared to the cost of gas embedded in customer rates due to an increased margin contribution from off-system sales, which is credited to the cost of gas, and the increased use of lower cost supplies from gas storage inventory; and

• partially offsetting the above factors was an increase in utility operating expenses of $13.5 million or 9 percent over last year due to a combination of higher operations and maintenance expense ($5.8 million) partly related to increased payroll and employee benefit costs ($4.9 million), higher revenue-based franchise tax expense related to increased gross revenues ($2.6 million), and higher property tax and depreciation expenses related to increased utility plant in service ($4.9 million). These increases in utility operating expenses were largely covered by revenue increases approved in the most recent general rate cases in Oregon and Washington.

The Company paid dividends on its common stock of 32.5 cents per share in each of the three month periods ended Sept. 30, 2005 and 2004, and paid dividends of 97.5 cents per share in each of the nine month periods ended Sept. 30, 2005 and 2004. On Oct. 12, 2005, the Board of Directors declared a quarterly dividend of 34.5 cents per share, an increase of 2 cents per share, on the Company’s common stock, payable Nov. 15, 2005. The new indicated annual dividend rate is $1.38 per share.

Results of Operations

Regulatory Developments

NW Natural provides gas utility service in Oregon and Washington, with Oregon representing over 90 percent of its revenues and cash flows. Future earnings and cash flows from utility operations will be determined by, among other factors, the Company’s ability to obtain reasonable and timely regulatory ratemaking treatment for its operating expenses and investments in utility plant. See Part II, Item 7., “Results of Operations—Regulatory Matters,” in the 2004 Form 10-K.

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Rate Mechanisms

Weather Normalization. In November 2003, the Oregon Public Utility Commission (OPUC) authorized, and NW Natural implemented, a weather normalization mechanism in Oregon that helps stabilize utility margins by adjusting customer billings based on temperature variances from average weather. The weather normalization mechanism applies only to Oregon residential and commercial customers, and the adjustment is in effect on customer bills from Nov. 15 to May 15 of each heating season. See “Comparison of Gas Distribution Operations (Utility),” below and Part II, Item 7., “Results of Operations—Regulatory Matters—Weather Normalization,” in the 2004 Form 10-K.

As part of the approval of NW Natural’s weather normalization mechanism, NW Natural was required to file a report reviewing the first two years of the mechanism’s operation. On Oct. 19, 2005, the Company filed the required report, which reviewed weather normalization programs in other states, analyzed the weather sensitivity of NW Natural customers, simulated program outcomes, discussed the financial effects of using incorrect normal weather definitions, reviewed service quality issues and assessed the opt-out provision. The report concluded that the weather normalization mechanism operated to benefit the Company and its customers. The weather normalization mechanism is effective through September 2008.

Purchased Gas Adjustment. Rate changes are applied each year under the PGA mechanisms in NW Natural’s tariffs in Oregon and Washington to reflect changes in the costs of natural gas commodity purchased under contracts with gas producers, the application of temporary rate adjustments to amortize balances in deferred regulatory asset and liability accounts and the removal of temporary rate adjustments effective for the previous year. The OPUC and the Washington Utilities and Transportation Commission (WUTC) approved rate increases on Sept. 22, 2005 and Sept. 28, 2005, respectively, effective Oct. 1, 2005. In Oregon, the combined effect of the rate change is to increase the average monthly bills of residential and commercial sales customers by 15.2 percent and 16.6 percent, respectively. In Washington, the combined effect of the rate change is to increase the average monthly bills of residential and commercial sales customers by 12.0 percent and 12.1 percent, respectively.

In the fourth quarter of 2004, the staff of the OPUC initiated a review of gas purchasing strategies for all three local gas distribution companies serving Oregon customers, and a report was issued by the OPUC in June 2005. The OPUC reviewed and acknowledged the report and accepted the OPUC staff’s proposed administrative recommendations. Although the report did not result in any change in the Company’s gas purchasing strategies, as a result of the OPUC’s review and the 2005 PGA increase, the OPUC staff has initiated a series of informal workshops to discuss the Oregon PGA mechanism design. Workshops are scheduled to begin in November and conclude in mid-January 2006. Management believes it is likely that a formal proceeding will be established to determine if changes to the current PGA mechanism are warranted.

Conservation Tariff. In October 2002, the OPUC authorized NW Natural to implement a “conservation tariff,” which is a mechanism designed to adjust margin revenues to compensate the utility for declining usage due to residential and commercial customers’ conservation efforts. The tariff was a partial decoupling mechanism that was intended to break the link between the Company’s earnings and the quantity of energy consumed by its customers, so the Company does not have an incentive to discourage customers from taking measures to reduce energy use. On average, residential and commercial customers have continued to reduce energy consumption over the past several years in response to the impact of higher energy prices on their utility bills and increased awareness of energy efficiency programs.

The conservation tariff included two components. The first component was a price elasticity adjustment, which adjusts for anticipated increases or decreases in consumption attributable to annual changes in commodity costs or periodic changes in the Company’s general rates. The second component was a conservation adjustment calculated on a monthly basis to account for deviations between actual and expected volumes (decoupling adjustment). Additional charges or credits to customers resulting from the decoupling adjustment are recorded to a deferral account, which is included in the next year’s annual PGA. Baseline consumption was determined by customer consumption data used in the 2003 Oregon general rate case, adjusted for added consumption resulting from new customers. See “Comparison of Gas Distribution Operations (Utility),” below and Part II, Item 7., “Results of Operations—Regulatory Matters—Conservation Tariff,” in the 2004 Form 10-K.

The conservation tariff was scheduled to expire at the end of September 2005, unless the OPUC approved an extension based on the results of an independent study to measure the mechanism’s effectiveness. The independent study was completed earlier this year, and a report was submitted to the OPUC on March 31, 2005 along with a request by the Company to open an investigation to determine whether the conservation tariff should be continued, modified or eliminated. The independent study report recommended continuation of the conservation tariff with minor modifications.

On July 26, 2005, the Company and several parties to the proceeding agreed to a stipulation to support the continuation of the conservation tariff for an additional four years, through Sept. 30, 2009, and to increase the mechanism’s

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coverage from a partial decoupling of 90 percent of residential and commercial gas usage to a full decoupling of 100 percent. The stipulation was approved by the OPUC on Aug. 25, 2005.

OPUC Audit

In 2004, the OPUC approved a stipulation among NW Natural, the OPUC staff and two parties in NW Natural’s 2003 Oregon general rate case. The stipulation provided for the settlement of issues in an investigation initiated by the OPUC in 2003 relating to NW Natural’s transactions or interests in certain properties in the vicinity of the Company’s headquarters building in downtown Portland, and the use of some of these properties for employee parking. NW Natural agreed in the stipulation to undergo an audit in 2005 funded by the Company. The audit commenced in August 2005 and is focused on financial hedging transactions, deferred taxes, tax credits, the Coos Bay distribution system project, securities issuances, the calculation of allowance for funds used during construction (AFUDC), and affiliated interest transactions. The consultant conducting the audit on behalf of the OPUC staff is expected to issue a report to the OPUC in the fourth quarter of 2005.

Oregon Billing Service Quality Measure

On Sept. 22, 2005, the OPUC approved a new billing service quality measure for Oregon customers. The measure requires billing accuracy, after certain exclusions, of 99.4 percent each month. If billing accuracy falls below 99.4 percent, a remedy of $50,000 per month may be imposed, up to a maximum of $0.3 million per year. The quality measure becomes effective Jan. 1, 2006. The Company does not expect the billing service quality measure to have a material effect on the Company’s financial condition, results of operations or cash flows.

Income Tax Legislation

On Aug. 1, 2005, the Oregon legislature passed Senate Bill 408, effective for taxes collected on or after Jan. 1, 2006, which requires the OPUC to establish an annual tax adjustment to ensure that Oregon utilities do not collect in rates more income taxes than they actually pay to government entities. The bill, which was signed into law on Sept. 2, 2005, requires that the OPUC interpret the bill’s provisions to determine how the tax adjustment will be applied. The OPUC has issued temporary rules and, on Oct. 14, 2005, NW Natural filed with the OPUC its first three-year tax report showing the amount of taxes NW Natural paid (according to the definitions in SB 408) compared with the amount of taxes it was authorized to collect in rates for each of the calendar years 2002, 2003 and 2004. NW Natural’s report concluded that, based on the calculations required by the temporary rules, the Company paid more in taxes than the amount of taxes it was authorized to collect in rates. This report was not required for the purpose of determining rate adjustments, and these results are not necessarily indicative of future calculations. The report, as well as reports submitted by other utilities, is intended to help the OPUC develop rules required to implement SB 408. Due to the uncertainties related to the OPUC’s interpretations and rule making with respect to the application of the bill’s provisions, the Company is not able to determine at this time what impact, if any, the new legislation will have on the Company’s financial condition, results of operations or cash flows.

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Comparison of Gas Distribution Operations (Utility)

The following tables summarize the composition of utility volumes and revenues for the three and nine months ended Sept. 30:

	Three Months Ended September 30,
(Thousands, except customer count and degree day data)	2005					2004
Utility volumes - therms:
Residential and commercial sales		53,182		29	%		52,762		28	%
Industrial sales and transportation		128,231		71	%		132,409		72	%
Total utility volumes sold and delivered		181,413		100	%		185,171		100	%
Utility operating revenues - dollars:
Residential and commercial sales	$	67,248		64	%	$	57,301		72	%
Industrial sales and transportation		36,767		36	%		23,615		29	%
Other revenues		(513	)	0	%		(858	)	(1	%)
Total utility operating revenues	$	103,502		100	%	$	80,058		100	%
Cost of gas sold		62,241					41,944
Utility net operating revenues (margin)	$	41,261				$	38,114
Margin
Residential and commercial sales	$	38,888		94	%	$	35,788		94	%
Industrial sales and transportation		11,146		27	%		10,064		26	%
Miscellaneous revenues		927		2	%		717		2	%
Other margin adjustments		(8,887	)	(22	%)		(7,439	)	(20	%)
Margin before weather normalization and decoupling		42,074		101	%		39,130		102	%
Weather normalization adjustment		(2	)	0	%		(2	)	0	%
Conservation decoupling adjustment		(811	)	(1	%)		(1,014	)	(2	%)
Margin	$	41,261		100	%	$	38,114		100	%
Total number of customers (end of period)		602,486					582,457
Actual degree days		101					76
Percent colder (warmer) than normal (25-year average degree days is used as normal)		(1	%)				(16	%)

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	Nine Months Ended September 30,
(Thousands, except degree day data)	2005					2004
Utility volumes - therms:
Residential and commercial sales		382,610		48	%		378,199		48	%
Industrial sales and transportation		407,713		52	%		413,999		52	%
Total utility volumes sold and delivered		790,323		100	%		792,198		100	%
Utility operating revenues - dollars:
Residential and commercial sales		439,213		78	%	$	363,251		82	%
Industrial sales and transportation		117,409		21	%		74,654		17	%
Other revenues		5,213		1	%		2,762		1	%
Total utility operating revenues	$	561,835		100	%	$	440,667		100	%
Cost of gas sold		335,186					241,360
Utility net operating revenues (margin)	$	226,649				$	199,307
Margin
Residential and commercial sales	$	232,999		103	%	$	212,339		107	%
Industrial sales and transportation		34,381		15	%		30,498		15	%
Miscellaneous revenues		4,047		2	%		2,900		1	%
Other margin adjustments		(49,310	)	(22	%)		(51,222	)	(26	%)
Margin before weather normalization and decoupling		222,117		98	%		194,515		97	%
Weather normalization adjustment		2,516		1	%		5,418		3	%
Conservation decoupling adjustment		2,016		1	%		(626	)	0	%
Margin	$	226,649		100	%	$	199,307		100	%
Actual degree days		2,522					2,352
Percent colder (warmer) than normal (25-year average degree days is used as normal)		(5	%)				(10	%)

Total utility volumes sold and delivered in the three- and nine-month periods ended Sept. 30, 2005 decreased 2 percent and less than 1 percent, respectively, compared to the corresponding 2004 periods, primarily reflecting lower volumes delivered to large industrial customers under special contracts.

NW Natural’s customer base continued to increase, with a net increase of 20,029 customers since Sept. 30, 2004, for a growth rate of 3.4 percent. In the three years ended Dec. 31, 2004, more than 55,000 customers were added to the system, representing an annual growth rate of 3.4 percent.

NW Natural’s utility results are affected, among other things, by customer growth and by changes in weather and customer consumption patterns, with a significant portion of its earnings being derived from natural gas sales to residential and commercial customers. In 2002, the OPUC approved a conservation tariff that adjusts margin up or down based on changes in residential and commercial customer consumption; and in 2003, the OPUC approved a weather normalization mechanism that adjusts customer bills, and Company margin, based on above- or below-average temperatures during the winter heating season (see “Results of Operations—Regulatory Developments—Rate Mechanisms,” above). Both mechanisms are designed to reduce the volatility of the Company’s utility earnings.

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Three months ended Sept. 30, 2005 compared to Sept. 30, 2004

In the three months ended Sept. 30, 2005, weather, although 1 percent warmer than normal, was 33 percent colder than last year, largely contributing to a 9 percent increase in margin from residential and commercial sales. The weather normalization mechanism covers customer bills during the period from November 15 to May 15 of each year and therefore does not cover volume fluctuations due to weather in the third quarter. The conservation tariff’s decoupling mechanism, which adjusts margin after the annual Oregon PGA mechanism is set based on expected volume changes due to price elasticity, reduced margin by $0.8 million in the third quarter of 2005 compared to a reduction of $1.0 million in the third quarter of 2004.

Other margin adjustments, which include pipeline demand charges, unaccounted-for gas charges and other regulatory gas cost and revenue adjustments, reduced margin by $8.9 million in the third quarter of 2005 compared to a margin reduction of $7.4 million in 2004. The increase in net deductions from other margin adjustments was primarily due to lower pipeline demand charge deferrals resulting from increased industrial firm sales volumes and to higher unaccounted-for gas charges as compared to last year’s third quarter.

Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004

In the nine months ended Sept. 30, 2005, weather was 7 percent colder than last year, which contributed largely to a 10 percent increase in margin from residential and commercial sales. The weather normalization mechanism covers most of the temperature variances during the first nine months of the calendar year because most of the heating degree days in the period occur between January 1 and May 15, a period in which the weather in 2005 was 5 percent warmer than normal. As a result, the weather normalization mechanism contributed $2.5 million to margin in the nine months ended Sept. 30, 2005, and contributed $5.4 million to margin in the same period of 2004 based on weather that was 10 percent warmer than normal. The decoupling mechanism contributed $2.0 million to margin in the first nine months of 2005, after adjusting for price elasticity in the annual Oregon PGA, compared to a reduction of $0.6 million in 2004.

Other margin adjustments, which include pipeline demand charges, unaccounted-for gas charges and other regulatory gas cost and revenue adjustments, reduced margin by $49.3 million in the first nine months of 2005 compared to $51.2 million in 2004. The decrease in net deductions from other margin adjustments was primarily due to higher cost of gas savings in the current year-to-date period as compared to last year.

Residential and Commercial Sales

The following table summarizes the utility volumes and utility operating revenues in the residential and commercial markets. The primary factors that impact the results of operations in these markets are seasonal weather, energy prices, competition and economic conditions in the Company’s service areas.

	Three Months Ended Sept. 30,					Nine Months Ended Sept. 30,
(Thousands, except customers)	2005			2004		2005			2004
Utility volumes - therms:
Residential sales		27,877			26,198		258,377			260,012
Commercial sales		25,574			24,106		166,431			168,071
Change in unbilled sales		(269	)		2,458		(42,198	)		(49,884	)
Total weather-sensitive utility volumes		53,182			52,762		382,610			378,199
Utility operating revenues - dollars:
Residential sales	$	40,324		$	33,256	$	316,463		$	267,186
Commercial sales		27,372			22,044		169,598			141,546
Change in unbilled sales		(448	)		2,001		(46,848	)		(45,481	)
Total weather-sensitive utility revenues	$	67,248		$	57,301	$	439,213		$	363,251
Total number of customers (end of period)		601,543			581,526		601,543			581,526

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Three months ended Sept. 30, 2005 compared to Sept. 30, 2004

The primary factors affecting residential and commercial volumes and operating revenues in the three months ended Sept. 30, 2005 compared to the corresponding period in 2004 were:

• volumes sold were 1 percent higher, due to 3.4 percent customer growth, partially offset by a decline in average use per customer; and

• operating revenues were 17 percent higher, primarily due to higher customer rates, which include increased commodity prices passed through to customers (see “Cost of Gas,” below and Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” in the 2004 Form 10-K) and customer growth.

Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004

The primary factors affecting residential and commercial volumes and operating revenues in the nine months ended Sept. 30, 2005 compared to the corresponding period in 2004 were:

• volumes sold were 1 percent higher, reflecting the effect of 7 percent colder weather and over 3 percent customer growth, partially offset by a 3 percent decline in average use per customer; and

• revenues were 21 percent higher, primarily due to higher rates resulting from increased gas costs (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” in the 2004 Form 10-K), the colder weather and customer growth.

Typically, 80 percent or more of annual utility operating revenues are derived from gas sales to weather-sensitive residential and commercial customers. Although variations in temperatures between periods will affect the volumes of gas sold to these customers, the effect on margin and net income is significantly reduced with the weather normalization mechanism and the conservation tariff (see “Comparison of Gas Distribution Operations (Utility),” above.

Total utility operating revenues include accruals for gas delivered but not yet billed to customers (unbilled revenues) based on estimates of gas deliveries from that month’s meter reading dates to month end. Amounts reported as unbilled revenues reflect the increase or decrease in the balance of accrued unbilled revenues compared to the prior year-end. Weather conditions, rate changes and customer billing dates affect the balance of accrued unbilled revenue at the end of each month. At Sept. 30, 2005, accrued unbilled revenue was $16.8 million, compared to $14.0 million at Sept. 30, 2004.

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Industrial Sales and Transportation

The following table summarizes the delivered volumes and utility operating revenues in the industrial sales and transportation market:

	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
(Thousands, except customers)	2005		2004		2005		2004
Utility volumes - therms:
Industrial - firm sales		14,855		13,191		53,416		45,858
Industrial - firm transportation		33,398		43,723		99,710		135,838
Industrial - interruptible sales		35,303		23,299		106,751		70,655
Industrial - interruptible transportation		44,675		52,196		147,836		161,648
Total utility volumes		128,231		132,409		407,713		413,999
Utility operating revenues - dollars:
Industrial - firm sales	$	12,238	$	9,049	$	43,285	$	30,602
Industrial - firm transportation		941		1,236		3,055		3,782
Industrial - interruptible sales		21,846		11,437		65,835		34,472
Industrial - interruptible transportation		1,742		1,893		5,234		5,798
Total utility operating revenues	$	36,767	$	23,615	$	117,409	$	74,654
Total number of customers (end of period)		943		931		943		931

Three months ended Sept. 30, 2005 compared to Sept. 30, 2004

The primary factors affecting industrial sales and transportation volumes and operating revenues in the three months ended Sept. 30, 2005 compared to the same period in 2004 include:

• 3 percent lower total volumes sold and transported, with a 19 percent decrease in transportation volumes largely offset by a 37 percent increase in sales volumes; the change between transportation and sales volumes primarily reflects customers electing to transfer from transportation service, where they had been buying commodity supplies from independent third parties, to sales service where they buy their commodity supplies from NW Natural;

• 56 percent higher operating revenues due to increases in customer rates, which include the higher commodity prices passed through to customers in the annual PGA (see “Cost of Gas,” below), and to customer transfers from transportation to sales service and from lower margin schedules to higher margin schedules; and

• 11 percent higher margins due to general rate increases relating to capital investments and due to increases in volumes delivered to higher margin rate schedules, which reflect improvement in certain sectors of the economy and transfers of some customers from lower margin rate schedules to higher margin schedules.

Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004

The primary factors affecting industrial sales and transportation volumes and operating revenues in the nine months ended Sept. 30, 2005 compared to the same period in 2004 include:

• 2 percent lower total volumes sold and transported, with a 17 percent decrease in transportation volumes largely offset by a 37 percent increase in sales volumes, primarily reflecting customers electing to transfer from transportation service to sales service;

• 57 percent higher operating revenues due to increases in customer rates, which include the higher commodity prices passed through to customers in the annual PGA (see “Cost of Gas Sold,” below), and to

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customer transfers from transportation service to sales service and from lower margin schedules to higher margin schedules; and

• 13 percent higher margins due to general rate increases relating to capital investments and due to increases in volumes delivered to higher margin rate schedules, which reflect improvement in economic conditions and transfers of some customers from lower margin rate schedules to higher margin schedules.

High natural gas prices have resulted in a number of NW Natural’s large industrial customers switching from transportation service, where they arranged for their own supplies through independent third parties, to receiving gas commodity under sales service from NW Natural. The Company’s tariff requires it to charge these customers the incremental cost of gas supply incurred by the Company to serve those customers. See Note 7.

Other Revenues

Other revenues include miscellaneous fee income as well as revenue adjustments reflecting deferrals to, or amortizations from, regulatory asset or liability accounts other than deferrals relating to gas costs (see Part II, Item 8., Note 1, “Industry Regulation,” in the 2004 Form 10-K). Other revenues decreased net operating revenues by $0.5 million in the third quarter of 2005 compared to a reduction of $0.9 million in the third quarter of 2004. Other revenues increased net operating revenues by $5.2 million and $2.8 million for the first nine months of 2005 and 2004, respectively. The following table summarizes other revenues by primary category:

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
(Thousands)	2005			2004			2005			2004
Revenue adjustments:
Current deferrals:
Conservation decoupling	$	(811	)	$	(1,013	)	$	2,016		$	(625	)
South Mist pipeline extension		(129	)		195			164			1,475
Coos Bay distribution system		111			—			814			—
OPUC investigation		—			(107	)		—			(1,065	)
Other		(3	)		—			(36	)		—
Current amortizations:
Interstate gas storage credits		—			—			2,714			5,324
Conservation decoupling		(180	)		(275	)		(1,416	)		(2,410	)
South Mist pipeline extension		(221	)		—			(1,789	)		—
Conservation programs		(222	)		(303	)		(1,551	)		(2,256	)
Year 2000 technology costs		(113	)		(109	)		(852	)		(983	)
Other		129			37			1,103			402
Net revenue adjustments		(1,439	)		(1,575	)		1,167			(138	)
Miscellaneous revenues:
Customer fees		509			633			3,530			2,541
Other		417			84			516			359
Total miscellaneous revenues		926			717			4,046			2,900
Total other revenues	$	(513	)	$	(858	)	$	5,213		$	2,762

Three months ended Sept. 30, 2005 compared to Sept. 30, 2004

Other revenues in the three months ended Sept. 30, 2005 were $0.3 million higher than the comparable period in 2004 primarily because of an increase in the current decoupling deferrals and a decrease in the amortization of prior period decoupling deferrals ($0.3 million), offset by a decrease in customer fees ($0.1 million).

Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004

Other revenues in the nine months ended Sept. 30, 2005 were $2.5 million higher than in the comparable period in 2004 primarily due to an increase in the current decoupling deferrals and a decrease in the amortization of prior period decoupling deferrals ($3.6 million) and an increase in customer fees ($1.0 million), partially offset by a decrease in the

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interstate gas storage credits to customers ($2.6 million) due to lower net income from storage operations in calendar year 2004 compared to 2003.

Cost of Gas Sold

Natural gas commodity prices have increased significantly in recent periods. During the third quarter and the first nine months of 2005, the cost per therm of gas sold was 28 percent and 27 percent higher, respectively, than in the comparable 2004 periods, primarily due to higher natural gas prices. The cost per therm sold includes current gas purchases, gas withdrawn from storage inventory, gains and losses from financial commodity hedges, margin from off-system gas sales, demand cost balancing adjustments, regulatory deferrals and company use (see Part II, Item 7., “Results of Operations—Comparison of Gas Operations—Cost of Gas Sold,” in the 2004 Form 10-K).

NW Natural uses a natural gas commodity-price hedge program under the terms of its Derivatives Policy to help manage its floating price gas commodity contracts (see “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” above, and Note 4). NW Natural realized net financial hedge gains of $20.5 million and $30.3 million from this program during the three- and nine-month periods ended Sept. 30, 2005, respectively, compared to net hedge gains of $10.2 million and $27.9 million during the same periods of 2004. Gains and losses relating to the financial hedging of utility gas purchases are included in cost of gas, which is factored into NW Natural’s PGA deferrals and annual rate changes, and therefore have no material impact on net income.

Under NW Natural’s PGA tariff in Oregon, net income from Oregon operations is affected within defined limits by changes in purchased gas costs (see Part II, Item 7., “Results of Operations—Comparison of Gas Operations,” in the 2004 Form 10-K). NW Natural’s gas costs in the third quarter of 2005 were slightly higher than the costs embedded in rates, which decreased margin by a negligible amount. For the third quarter of 2004, NW Natural’s gas costs were also higher than those embedded in rates, which decreased margin by $0.1 million. In the first nine months of 2005, NW Natural’s share of gas cost savings from amounts embedded in rates contributed $1.9 million of margin, compared to net savings and a contribution to margin of $0.4 million in the comparable 2004 period.

NW Natural is able to use gas supplies under contract but not required for delivery to core market (residential, commercial and industrial firm) customers due to warmer weather and other factors to make off-system sales. Under the PGA tariff in Oregon, NW Natural retains 33 percent of the margins realized from its off-system gas sales and records the remaining 67 percent as a deferred regulatory asset or liability for recovery from, or refund to, customers in future rates. NW Natural’s share of margin from off-system gas sales in the third quarter of 2005 was a negligible loss compared to a loss of $0.2 million for the same period in 2004. In the first nine months of 2005, NW Natural’s share of margin from off-system gas sales contributed $0.3 million of margin, compared to a nominal loss for the same period in 2004.

Commodity Cost

The Company’s weighted average cost of gas (WACOG) is annually adjusted in rates to reflect changes in the cost of gas purchased by the Company from its natural gas suppliers, including the costs of purchasing financial derivative products to limit customers’ exposure to gas cost volatility, and changes in the cost of pipeline and storage capacity under contract with the Company’s pipeline transporters (see “Regulatory Developments—Rate Mechanisms,” above). The Company’s WACOG compares favorably to current market prices. Gas prices across the country have been affected significantly by a number of factors including hurricane activity in the Gulf of Mexico. Current price quotes for the 2006-2007 gas purchasing year indicate a continuing trend of price increases. If gas prices remain high and the Company is required to purchase gas on the spot market to serve its load, which in large part depends upon weather and other factors, the difference between the Company’s WACOG in rates and actual gas costs on the small unhedged portion of the Company’s portfolio (typically less than 10 percent) could result in significant losses, with two-thirds of the variance deferred to a regulatory account and one-third recorded to income (see Part II, Item 7., “Results of Operations—Comparison of Gas Operations—Cost of Gas Sold,” in the 2004 Form 10-K).

Business Segments Other than Gas Distribution Operations

Interstate Gas Storage

NW Natural earned net income of $1.6 million after regulatory sharing and income taxes from its non-utility interstate gas storage business segment in the three months ended Sept. 30, 2005. This compares to net income of $0.6 million in the three months ended Sept. 30, 2004. For the nine months ended Sept. 30, 2005, results from this segment were net income of $3.3 million, compared to $2.1 million for the comparable period in 2004.

The Company’s optimization activities are provided under a contract with an unaffiliated energy marketing company, which optimizes the value of NW Natural’s assets by engaging in marketing temporarily unused portions of off-

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system pipeline transportation capacity and gas storage capacity. In addition, in the first quarter of 2005, NW Natural entered into a series of exchange transactions with this company, which resulted in a change in the Company’s accounting treatment for its forward gas supply contracts under SFAS No. 133. SFAS No. 133 requires that derivative instruments be recorded on the balance sheet at fair value. Prior to March 31, 2005, the Company’s forward gas supply contracts were excluded from the fair value measurement requirement of SFAS No. 133 because these contracts were eligible for the normal purchases and normal sales exception. These contracts are now accounted for as derivative instruments and marked-to-market based on fair value pursuant to SFAS No. 133 (see Note 4).

In Oregon, NW Natural retains 80 percent of the pre-tax income from interstate gas storage services and optimization of utility storage and pipeline transportation capacity when the costs of such capacity have not been included in utility rates, and retains 33 percent of the pre-tax income from such optimization when the capacity costs have been included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for refund to NW Natural’s utility customers. NW Natural has a similar sharing mechanism in Washington for pre-tax income derived from interstate storage services and third party optimization.

Subsidiary – Financial Corporation

Financial Corporation’s operating results for the three months ended Sept. 30, 2005 were net income of $0.1 million compared to net income of $0.4 million in the third quarter of 2004. For the first nine months of 2005, net income was $0.2 million compared to net income of $0.5 million for the same period in 2004.

The Company’s net investment balances attributed to Financial Corporation at Sept. 30, 2005 and 2004 were $3.0 and $6.0 million, respectively. The lower investment balance reflects the sale of interests in the solar electric generation projects in January 2005 and a dividend paid by Financial Corporation to the parent, NW Natural, in the first quarter of 2005.

Operating Expenses

Operations and Maintenance

Operations and maintenance expenses in third quarter of 2005 were $26.0 million, 6 percent higher than in the third quarter of 2004. The $1.5 million increase was primarily due to:

• a $0.6 million increase in total payroll-related expense resulting from employee additions, pay increases and higher benefit costs; and

• an $0.8 million increase in repair costs and written-off damage claims relating to the Company’s utility mains and services;

• offset, in part, by a $0.2 million decrease in the uncollectible accounts expense due to improved collection results and recoveries of accounts previously written-off.

Operations and maintenance expenses in the first nine months of 2005 were $80.2 million, 8 percent higher than in the first nine months of 2004. The $5.8 million increase was primarily due to:

• a $2.7 million increase in regular payroll-related expense resulting from employee additions, pay increases and higher benefit costs;

• a $2.2 million increase in bonus payroll expense related to improved performance on company-wide goals compared to last year and to an increase in the accrued long-term incentive plan liability due to a higher stock price on which the award is based;

• an $0.8 million increase in repair costs and written-off damage claims relating to the Company’s utility mains and services; and

• a $0.3 million increase in software maintenance;

• offset, in part, by a $0.5 million decrease in uncollectible accounts expense due to improved collection results and recoveries of accounts previously written-off.

Taxes Other than Income Taxes

Taxes other than income taxes, which are principally comprised of franchise, property and payroll taxes, increased $1.1 million, or 16 percent, and $3.9 million, or 14 percent, in the three- and nine-month periods ended Sept. 30, 2005, respectively, compared to the same periods in 2004. For the three- and nine-month periods ended Sept. 30, 2005, franchise taxes, which are based on gross revenues, increased $0.5 million and $2.6 million, respectively, reflecting higher gross revenues primarily due to higher rates. For the three- and nine-month periods ended Sept. 30, 2005, property taxes increased $0.4 million and $1.0 million, respectively, due to utility plant additions in 2004 and 2005.

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Depreciation and Amortization

Depreciation and amortization expense increased by $1.2 million, or 9 percent, and $3.9 million, or 9 percent, in the three- and nine-month periods ended Sept. 30, 2005, compared to the same periods in 2004. The increased expense is primarily due to depreciation on additional investments in utility property that were made to meet continuing customer growth, including the largest component of the Company’s investment in South Mist Pipeline Extension (SMPE) which was put into service in September 2004 (see “Financial Condition—Cash Flows—Investing Activities,” below).

Other Income

The following table summarizes other income by primary components for the three and nine months ended Sept. 30, 2005 and 2004:

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
(Thousands)	2005			2004			2005			2004
Other income (expense):
Gains from Company-owned life insurance	$	436		$	549		$	1,410		$	1,974
Allowance for funds used during construction—equity		—			355			—			544
Interest income		180			21			409			138
Other non-operating expense		(202	)		(291	)		(1,061	)		(1,225	)
Interest income (charges) on deferred regulatory account balances		99			112			123			(171	)
Earnings from equity investments of Financial Corporation		37			898			139			849
Total other income	$	550		$	1,644		$	1,020		$	2,109

Other income decreased $1.1 million in both the three- and nine-month periods ended Sept. 30, 2005, respectively, compared to the same periods in 2004. The decrease in the three-month period ended Sept. 30, 2005 was primarily due to lower earnings from equity investments of Financial Corporation ($0.9 million) and the absence of the equity component of AFUDC ($0.4 million) reflecting lower construction work in progress balances. The decrease in the nine-month period ended Sept. 30, 2005 was primarily due to lower earnings from equity investments of Financial Corporation ($0.7 million) and the absence of the equity component of AFUDC ($0.5 million), reflecting lower construction work in progress balances and lower gains from Company-owned life insurance ($0.6 million), partially offset by higher interest income ($0.3 million) and higher interest charges on deferred regulatory account balances ($0.3 million).

Interest Charges – Net of Amounts Capitalized

Interest charges – net of amounts capitalized increased by $0.5 million, or 5 percent, and $0.8 million, or 3 percent, in the three- and nine-month periods ended Sept. 30, 2005, respectively, compared to the same periods in 2004. The increase in interest charges is due to an increase in the average balance of debt outstanding during the period, higher interest rates on short-term debt, and lower interest credits allocated to the debt component for AFUDC (see Part II, Item 7., “Results of Operations—Interest Charges—Net of Amounts Capitalized,” in the 2004 Form 10-K).

Income Taxes

The effective corporate income tax rate was 35.7 percent for the nine-month period ended Sept. 30, 2005, compared to 34.7 percent for the nine-month period ended Sept. 30, 2004. The increase in the effective income tax rate reflected the effect of higher federal and state income taxes attributed to a $14.1 million dollar increase in pre-tax income.

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Financial Condition

Capital Structure

The Company’s goal is to maintain a target capital structure comprised of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt. When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources also are used to meet long-term debt redemption requirements and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below). In addition, the Company may use its common stock repurchase program to maintain its target capital structure (see “Financing Activities,” below).

The Company’s consolidated capital structure at Sept. 30, 2005 and 2004 and at Dec. 31, 2004, including short-term debt, was as follows:

	Sept. 30,				Dec. 31, 2004
	2005		2004
Common stock equity	48.7	%	48.5	%	48.6	%
Long-term debt	44.5	%	42.9	%	41.4	%
Short-term debt, including current maturities of long-term debt	6.8	%	8.6	%	10.0	%
Total	100.0	%	100.0	%	100.0	%

The Company believes that achieving the target capital structure and maintaining sufficient liquidity contribute to maintaining attractive credit ratings and having access to capital markets at reasonable costs.

Liquidity and Capital Resources

At Sept. 30, 2005, the Company had $3.4 million of cash and cash equivalents compared to $4.1 million at Sept. 30, 2004 and $5.2 million at Dec. 31, 2004. During the third quarter of 2005, cash and cash equivalents decreased by $36.9 million, from $40.3 million at June 30, 2005 to $3.4 million at Sept. 30, 2005, which reflected cash primarily being used to redeem the maturities of long-term debt and to fund the ongoing utility construction program. See Note 10 and “Cash Flows—Financing Activities,” below.

Short-term liquidity is provided by cash from operations and from the sale of commercial paper notes, which are supported by committed bank lines of credit. The Company had available through Sept. 30, 2005 committed lines of credit totaling $150 million with several commercial banks, which were replaced with new lines of credit totaling $200 million effective Oct. 1, 2005 (see Note 9 and “Lines of Credit,” below). Short-term debt balances are typically higher at the end of the third and fourth quarters each year due to seasonal working capital requirements, which reflect the financing of natural gas inventories and accounts receivable.

Capital expenditures are primarily for utility construction requirements relating to customer growth and system improvements (see “Cash Flows—Investing Activities,” below). Certain contractual commitments under capital leases, operating leases and gas supply purchase and other contracts require an adequate source of funding. These capital and contractual expenditures are financed through cash from operations and from the issuance of short-term debt, which is periodically refinanced through the sale of long-term debt or equity securities.

Neither NW Natural’s Mortgage and Deed of Trust nor the indentures under which other long-term debt is issued contain credit rating triggers or stock price provisions that require the acceleration of debt repayment. Also, there are no rating triggers or stock price provisions contained in contracts or other agreements with third parties, except for agreements with certain counter-parties under NW Natural’s Derivatives Policy which require the affected party to provide substitute collateral such as cash, guaranty or letter of credit if credit ratings are lowered to non-investment grade, or in some cases if the mark-to-market value exceeds a certain threshold.

Based on the availability of short-term credit facilities and the ability to issue long-term debt and equity securities, the Company believes it has sufficient liquidity to satisfy its anticipated near-term cash requirements, including the contractual obligations and investing and financing activities discussed below.

Off-Balance Sheet Arrangements

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

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Contractual Obligations

During the nine months ended Sept. 30, 2005, there were no material changes to the Company’s estimated future contractual obligations other than an increase in the amount of existing gas purchase obligations due to rising gas commodity prices (see table below), the $50 million of secured long-term debt issued in June 2005 as described in Note 10, a contract for environmental clean-up related to the removal of a tar deposit at the Portland Harbor site as described in Note 7 and obligations entered into in the ordinary course of business. The Company’s contractual obligations at Dec. 31, 2004 were described in Part II, Item 7., “Financial Condition—Liquidity and Capital Resources—Contractual Obligations,” in the 2004 Form 10-K.

The Company’s contractual obligations under existing gas purchase contracts are as follows:

	Payments Due
(Thousands) Gas purchase obligations (1)	Up to 1 Year		1-2 Years		2-3 Years		3-4 Years			4-5 Years		Thereafter		Total
At Sept. 30, 2005	$	517,169	$	253,124	$	239,625	$	127,732		$	63,620	$	122,617	$	1,323,887
At Dec. 31, 2004		277,371		184,572		167,093		150,898			62,155		112,684		954,773
Net increase (decrease)	$	239,798	$	68,552	$	72,532	$	(23,166	)	$	1,465	$	9,933	$	369,114

(1) All gas purchase contracts use price formulas tied to monthly index prices. Commitment amounts are based on index prices at Sept. 30, 2005.

Commercial Paper

The Company’s primary source of short-term funds is from the sale of commercial paper notes payable. In addition to issuing commercial paper to meet seasonal working capital requirements, including the financing of gas purchases and accounts receivable, short-term debt is used to temporarily fund capital expenditure requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. NW Natural’s outstanding commercial paper, which is sold under agency agreements with commercial banks, is supported by committed bank lines of credit (see “Lines of Credit,” below, Note 9, and Part II, Item 8., Note 6, in the 2004 Form 10-K). NW Natural had $72.5 million in commercial paper notes outstanding at Sept. 30, 2005, compared to $82.7 million outstanding at Sept. 30, 2004 and $102.5 million outstanding at Dec. 31, 2004.

Lines of Credit

In September 2005, NW Natural entered into an agreement for unsecured lines of credit totaling $200 million with five commercial banks, replacing the existing $150 million credit facilities. The new bank lines of credit (bank lines) are available and committed for a term of five years from Oct. 1, 2005 to Sept. 30, 2010. NW Natural’s bank lines are used primarily as back-up support for the notes payable under the Company’s commercial paper borrowing program. Commercial paper borrowing provides the liquidity to meet the working capital and external financing requirements of NW Natural. The Company received regulatory authorization for the new bank lines in October 2005.

Under the terms of these bank lines, NW Natural pays upfront fees and annual commitment fees but is not required to maintain compensating bank balances. The interest rates on outstanding loans, if any, under these bank lines are based on then-current market interest rates. All principal and unpaid interest under the bank lines is due and payable on Sept. 30, 2010.

The bank lines require that NW Natural maintain credit ratings with Standard & Poor’s and Moody’s Investor Services and to notify the banks of any change in its senior unsecured debt ratings by such rating agencies. A change in NW Natural’s credit rating is not an event of default, nor is the maintenance of a specific minimum level of credit rating a condition of drawing upon the bank lines. However, interest rates on any loans outstanding under these bank lines are tied to credit ratings, which would increase or decrease the cost of any loans under the bank lines when ratings are changed.

The bank lines also require the Company to maintain an indebtedness to total capitalization ratio of 65 percent or less. Failure to comply with this covenant would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding. NW Natural was in compliance with an equivalent covenant in the prior year’s bank lines at Sept. 30, 2005.

Credit Ratings

The table below summarizes NW Natural’s current credit ratings and ratings outlook from three rating agencies, Standard and Poor’s Rating Services (S&P), Moody’s Investors Service (Moody’s) and Fitch Ratings (Fitch).

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Rating Category	S&P	Moody’s	Fitch
Commercial paper (short-term debt)	A-1	P-1	F1
Senior secured (long-term debt)	A+	A2	A+
Senior unsecured (long-term debt)	A	A3	A
Ratings outlook	Stable	Stable	Stable

These credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell or hold the Company’s securities. Each rating should be evaluated independently of any other rating.

Redemptions of Long-Term Debt

In July 2005, the Company redeemed three series of its maturing Medium-Term Notes (MTNs) aggregating $15 million in principal amount. The series redeemed were the 6.34% Series B, the 6.38% Series B and the 6.45% Series B, each due in July 2005. The MTNs were redeemed with proceeds from the sales of $50 million in principal amount of MTNs in June 2005 (see “Cash Flows—Financing Activities,” below).

In August 2005, the Company redeemed all of its outstanding Convertible Debentures, 7-1/4% Series due 2012 (the Debentures) at 100% of their principal amount plus accrued interest to the date of redemption. All but $0.5 million of the Debentures were converted into shares of the Company’s common stock on or prior to the redemption date at the rate of 50.25 shares for each $1,000 principal amount of Debentures (see Note 10).

Cash Flows

Operating Activities

Year-over-year changes in the Company’s operating cash flows are primarily affected by net income, non-cash adjustments to net income primarily from depreciation, deferred income taxes and deferred gas costs, and changes in working capital. In the first nine months of 2005, net income increased $8.7 million, non-cash adjustments decreased $10.0 million and changes in working capital increased $0.4 million compared to the same period in 2004.

The following table summarizes cash provided by operating activities for the nine-month periods ended Sept. 30, 2005 and 2004:

	Nine Months Ended Sept. 30,
Thousands	2005		2004
Net income	$	32,356	$	23,611
Non-cash adjustments to net income		29,557		39,547
Changes in working capital		32,754		33,234
Cash provided by operating activities	$	94,667	$	96,392

Nine months ended Sept. 30, 2005 compared to Sept. 30, 2004

The overall change in cash flow from operating activities in the first nine months of 2005 compared to 2004 was a decrease of $1.7 million. The significant factors contributing to the cash flow changes between periods are as follows:

• an increase in net income added $8.7 million to cash flow;

• an increase in the contribution to the Company-sponsored pension plans decreased cash by $17.1 million;

• an increase in accrued unbilled revenue increased cash by $2.5 million;

• an increase in accounts payable increased cash flow by $4.4 million primarily reflecting higher gas prices at year-end 2004 compared to year-end 2003 and increased bonus accruals for 2005;

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• a decrease in deferred income taxes and investment tax credits reduced cash flow by $13.3 million, reflecting higher tax benefits realized in 2004 from accelerated bonus depreciation on large capital additions that were placed into service in 2004;

• an increase in inventories decreased cash flow by $13.3 million, primarily reflecting injections into storage at higher gas prices during the 2005 period;

• a decrease in regulatory receivables for deferred gas costs increased cash flow by $18.9 million, reflecting deferral activity, including collections, between the two periods with respect to purchased gas cost savings and off-system gas sales under NW Natural’s PGA tariff (see “Results of Operations—Comparison of Gas Operations—Cost of Gas Sold,” above);

• a decrease in accounts receivable increased cash flows by $13.8 million, reflecting collections from higher receivable balances at Dec. 31, 2004 compared to Dec. 31, 2003; and

• an increase in income taxes receivable decreased cash flow by $5.3 million.

The Company has lease and purchase commitments relating to its operating activities that are financed with cash flows from operations (see “Liquidity and Capital Resources,” above, and Part II, Item 8., Note 12, in the 2004 Form 10-K).

Investing Activities

Cash requirements for investing activities in the first nine months of 2005 totaled $66.5 million, down from $112.8 million in the same period of 2004. Cash requirements for the acquisition and construction of utility plant totaled $65.2 million, down from $110.2 million in the same period of 2004. The decrease in utility construction in the first nine months of 2005 reflects the completion in 2004 of NW Natural’s SMPE project, which extended the pipeline from the Mist gas storage field to serve growing portions of NW Natural’s service area. The total cost of the project was approximately $108 million, which includes amounts reflected in investing activities over the past few years. The cost of service associated with the SMPE project, net of deferred tax benefits, was included in utility customer rates beginning in the fourth quarter of 2004.

Investments in non-utility property during the first nine months of 2005 totaled $5.5 million, up from $3.8 million during the first nine months of 2004. The higher investments in 2005 were primarily for improvements to the Company’s interstate gas storage facilities.

In January 2005, Financial Corporation received proceeds from the sale of its limited partnership interests in three solar electric generation projects totaling $3.0 million.

Financing Activities

Cash used in financing activities in the first nine months of 2005 totaled $30.1 million, compared to cash provided of $15.7 million in the same period of 2004. Factors contributing to the $45.8 million decrease were a larger reduction in short-term debt in the first nine months of 2005 ($30.0 million) compared to the first nine months of 2004 ($2.5 million), the redemption of long term debt and convertible debentures in 2005 ($15.5 million), the repurchase of common stock in 2005 ($13.8 million) compared to the same period in 2004 ($0.2 million) and the lower amount of equity financing in 2005 ($6.2 million) compared to 2004 ($44.6 million), partially offset by the issuance of $50.0 million in MTNs during the first nine months of 2005.

In June 2005, NW Natural sold $40 million of its 4.70% Series B secured MTNs due 2015 and $10 million of its 5.25% Series B secured MTNs due 2035 and used the proceeds, together with internally generated cash, to reduce short-term debt.

In April 2004, the Company sold 1,290,000 shares of its common stock in an underwritten public offering, and used the net proceeds of $38.5 million from the offering to reduce short-term indebtedness by about $29 million and to fund, in part, NW Natural’s utility construction program (see Part II, Item 7., “Financial Condition—Liquidity and Capital Resources,” in the 2004 Form 10-K).

In 2000, NW Natural commenced a program to repurchase up to 2 million shares, or up to $35 million in value, of its common stock through a repurchase program that, in April 2005, was extended through May 2006. The purchases are made in the open market or through privately negotiated transactions. The Company purchased 377,900 shares in the first nine months of 2005 at a cost of $13.8 million. No shares were purchased pursuant to the program in 2004. Since

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the program’s inception, the Company has repurchased 733,300 shares of common stock at a total cost of $22.0 million (see Part II, Item 2., “Unregistered Sales of Equity Securities and Use of Proceeds,” below).

Pension Funding Status

The Company’s pension funding status is determined by actuarial valuations. The Company makes contributions to its qualified non-contributory defined benefit pension (DBP) plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. The Company is not required to make additional cash contributions to its qualified DBP plans in 2005 based on minimum funding requirements, but elected to contribute an additional $20.0 million on Sept. 15, 2005 for the 2004 plan year. The Company will continue to evaluate its qualified DBP plans’ funding status based on expected returns on plan assets and anticipated changes in actuarial assumptions to determine if an additional contribution will be made prior to year-end. In addition, the Company will continue to make cash contributions during 2005 in the form of ongoing benefit payments as required for its unfunded non-qualified supplemental pension plans and other postretirement benefit plans. See Part II, Item 8., Note 7, in the 2004 Form 10-K for a discussion of estimated future payments.

Ratios of Earnings to Fixed Charges

For the nine months and 12 months ended Sept. 30, 2005 and the 12 months ended Dec. 31, 2004, the Company’s ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were 2.76, 3.37 and 3.02, 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.

Contingencies

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 SFAS No. 5, “Accounting for Contingencies.” NW Natural updates its estimates of loss contingencies and related disclosures when new information becomes available. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties, and NW Natural records accruals for loss contingencies based on an analysis of potential results, developed in consultation with outside counsel and consultants when appropriate. When information is sufficient to estimate only a range of potential liabilities, and no point within the range is more likely than any other, the Company recognizes an accrued liability at the lower end of the range and discloses the range (see Note 7). It is possible, however, that the range of potential liabilities could be significantly different than amounts currently accrued and disclosed, and the Company’s financial condition and results of operations could be materially affected by changes in assumptions or estimates related to these contingencies.

With respect to its environmental liabilities and related costs, NW Natural develops estimates based on currently available information, existing technology and environmental regulations. These costs include investigation, monitoring, and remediation. NW Natural received regulatory approval to defer and seek recovery of costs related to certain sites and believes the recovery of these costs is probable through the regulatory process. In accordance with SFAS No. 71, the Company has recorded a regulatory asset for the amount expected to be recovered. The Company intends to pursue recovery of these environmental costs from its general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. At Sept. 30, 2005, a cumulative $17.4 million in environmental costs has been recorded as a regulatory asset, including $5.4 million of costs paid to-date and $12.0 million of accrued estimated future environmental costs. If it is determined that both the insurance recovery and future customer rate recovery of such costs is not probable, then the costs will be charged to expense in the period such determination is made. See Note 7.

Industrial Customers Switching from Transportation to Sales Service

High natural gas prices have resulted in several of NW Natural’s large industrial transportation customers electing to receive gas commodity under sales service from NW Natural instead of arranging for their own supplies through independent third parties. Since these customers are electing the transfer to sales service after commodity rates were set in the annual PGA, the Company believes its tariff requires it to charge these customers the incremental cost of gas supply incurred by the Company to serve those customers. The Company has notified these customers that they will be charged the incremental gas costs, if any. Certain of these customers have notified the Company that they expected to be charged gas costs at the Company’s WACOG price. The Company is working with the OPUC and customer groups to resolve the matter. If it is determined by the OPUC that NW Natural is not allowed to charge these customers its incremental costs, or customers are awarded damages through litigation, then the potential impact could be material to the Company’s financial results in 2005 and 2006, depending on the price and volume of incremental gas purchases.

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Forward-Looking Statements

This report and other presentations made by the Company from time to time may contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and other statements that are other than statements of historical facts. The Company’s expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis. However, each such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause the actual results of the Company to differ materially from those projected in such forward-looking statements, including:

• prevailing state and federal governmental policies and regulatory actions, including those of the OPUC and the WUTC, with respect to allowed rates of return, industry and rate structure, purchased gas cost and investment recovery, acquisitions and dispositions of assets and facilities, operation and construction of plant facilities, present or prospective wholesale and retail competition, changes in tax laws and policies and changes in and compliance with environmental and safety laws, regulations, policies and orders, and laws, regulations and orders with respect to the maintenance of pipeline integrity;

• weather conditions and other natural phenomena, including earthquakes or other geohazard events;

• unanticipated population growth or decline, and changes in market demand caused by changes in demographic or customer consumption patterns;

• competition for retail and wholesale customers;

• market conditions and pricing of natural gas relative to other energy sources;

• risks relating to the creditworthiness of customers, suppliers and derivative counterparties;

• risks relating to dependence on a single pipeline transportation provider for natural gas supply;

• risks resulting from uninsured damage to Company property, intentional or otherwise;

• unanticipated changes that may affect the Company’s liquidity or access to capital markets;

• the Company’s ability to maintain effective internal controls over financial reporting in compliance with Section 404 of the Sarbanes-Oxley Act of 2002;

• unanticipated changes in interest or foreign currency exchange rates or in rates of inflation;

• economic factors that could cause a severe downturn in certain key industries, thus affecting demand for natural gas;

• unanticipated changes in operating expenses and capital expenditures;

• changes in estimates of potential liabilities relating to environmental contingencies;

• unanticipated changes in future liabilities relating to employee benefit plans, including changes in key assumptions;

• capital market conditions, including their effect on pension and other postretirement benefit costs;

• potential inability to obtain permits, rights of way, easements, leases or other interests or other necessary authority to construct pipelines, develop storage or complete other system expansions; and

• legal and administrative proceedings and settlements.

All subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, also are expressly qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for the Company to predict all such factors,

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nor can it assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to various forms of market risk including commodity supply risk, weather risk and interest rate risk (see Part II, Item 7A., “Quantitative and Qualitative Disclosures About Market Risk,” in the 2004 Form 10-K). In addition, the Company is exposed to credit risk relating to receivables from its customers and financial derivative counterparties, particularly when gas prices increase substantially as they have recently.

Commodity Supply Risk with Unaffiliated Energy Marketing Company. There have been no material changes to the information relating to market risk provided in the Company’s 2004 Form 10-K. However, in the first nine months of 2005, NW Natural entered into a series of exchange transactions with an unaffiliated energy marketing company, which resulted in the Company’s accounting for its forward gas purchase contracts as derivative instruments under SFAS No. 133. SFAS No. 133 requires that derivative instruments be recorded on the balance sheet at fair value. The mark-to-market adjustment at Sept. 30, 2005 on contracts that were previously accounted for as normal purchase normal sale is an unrealized loss of $2.1 million, which is recorded as a liability with an offsetting entry to a regulatory asset account based on regulatory deferral accounting treatment under SFAS No. 71. The Company’s forward gas supply contracts were previously excluded from the provisions of SFAS No. 133 under the normal purchases and normal sales exception that is allowed for contracts that are probable of delivery in the normal course of business. These exchange transactions are intended and designed to reduce commodity prices, with the derivatives decreasing the Company’s net exposures to market risk. These derivatives are used for managing business risks and not for trading purposes.

In the exchange transactions referred to above, NW Natural continues to receive the same physical deliveries of natural gas volumes at the entry point into its distribution system, while the unaffiliated energy marketing company seeks to use the equivalent physical commodity volumes at an upstream delivery point. Under the optimization agreement with this company, NW Natural receives a fixed fee plus a share of any gains above the fixed fee. NW Natural’s exchange transaction is consistent with its policies on physical gas purchases and derivative instruments, which govern the use of commodity supply contracts and financial derivatives in order to manage the Company’s commodity supply and related price risk. These policies provide for the use of only those contracts, volumes and instrument types that are needed in the normal course of business, that help to manage gas supply costs and that have a close volume or price correlation to the Company’s assets, liabilities or forecasted transactions, thereby ensuring that such instruments will be used for hedging business risks and not for trading purposes.

Credit Exposure to Financial Derivative Counterparties. Increases in natural gas prices raised the Company’s credit exposure to its financial derivative counterparties and customers. During the third quarter of 2005, the Company’s credit exposure to financial derivative counterparties relating to commodity swap and call options, based on estimated fair value, increased by $278.0 million, from $62.5 million at June 30, 2005 to $340.5 million at Sept. 30, 2005. Of this increase, $192.1 million was attributable to existing contracts at June 30, 2005 and $85.9 million was due to new contracts entered into during the third quarter. The Company’s Derivatives Policy (the Policy) requires derivative counterparties to have a minimum credit rating at the time the derivative instrument is entered into, and the Policy specifies certain limits on the contract amount and duration based on each counterparty’s credit quality. There were no credit rating downgrades for any of NW Natural’s counterparties during the third quarter of 2005.

The following table summarizes the Company’s credit exposure, based on estimated fair value, and the corresponding counterparty credit ratings. The table uses credit ratings from Standard & Poor’s Rating Services (S&P) and Moody’s Investors Service (Moody’s), reflecting the higher of S&P or Moody’s rating:

	Financial Derivative Exposures by Credit Rating
Thousands	Fair Value Gains (Losses)
	Sept. 30, 2005		Sept. 30, 2004		Dec. 31, 2004
AAA/Aaa	$	29,092	$	1,974	$	(1,206	)
AA/Aa		287,940		64,560		13,105
A		—		198		—
BBB/Baa		23,481		2,567		(1,453	)
Total	$	340,513	$	69,300	$	10,446

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Credit Exposure to Customers. Increases in the market price of natural gas are expected to increase the Company’s credit exposure to customers. Also, higher prices have resulted in some of NW Natural’s large industrial customers changing from transportation service to sales service. Under transportation service, the customer is purchasing its commodity supplies from an independent third party, with NW Natural only providing a transportation service for the delivery of that gas to the customer’s premise. Under sales service, the customer is purchasing both its gas commodity and transportation service from NW Natural. With higher natural gas commodity prices, NW Natural’s credit exposure to large industrial sales customers is expected to increase significantly. NW Natural monitors and manages the credit exposure of its industrial sales customers through credit policies and procedures, which are designed to reduce credit risk. These policies and procedures include an ongoing review of credit risks, including changes in the services provided to industrial customers as well as changes in market conditions and customers’ credit quality. Changes in credit risk may require NW Natural to obtain additional assurance, such as deposits, letters of credit, guarantees and prepayments, to reduce its credit exposure.

NW Natural also monitors and manages the credit exposure of its residential and commercial customers. This credit risk is largely mitigated by the nature of the Company’s regulated business and reasonably short collection terms, as well as by the consistent application of credit policies and procedures.

Item 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

As of Sept. 30, 2005, the principal executive officer and principal financial officer of the Company have evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act)). Based upon that evaluation, the principal executive officer and principal financial officer of the Company have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to the Company and its consolidated subsidiaries required to be included in the Company’s reports filed with or furnished to the Securities and Exchange Commission under the Exchange Act.

(b) Changes in Internal Control Over Financial Reporting

There has been no change in the Company’s internal control over financial reporting that occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Litigation

For a discussion of certain pending legal proceedings, see Part I, Item 1., Note 7, to the accompanying consolidated financial statements, above.

The Company is subject to other 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, the Company does not expect that the ultimate disposition of these matters will have a materially adverse effect on the Company’s financial condition, results of operations or cash flows.

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

The following table provides information about purchases by the Company during the quarter ended Sept. 30, 2005 of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES

Period	(a) Total Number of Shares Purchased (1)	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	(d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
Balance forward				490,200	$	21,938,837
07/01/05-07/31/05	—		—	—		—
08/01/05-08/31/05	—		—	243,100		(8,950,729	)
09/01/05-09/30/05	5,141	$	37.41	—		—
Total	5,141	$	37.41	733,300	$	12,988,108

⁽¹⁾ During the three months ended Sept. 30, 2005, the Company accepted 5,141 shares of its common stock as payment for stock option exercises pursuant to the Company’s Restated Stock Option Plan.

⁽²⁾ On May 25, 2000, the Company announced a program to repurchase up to 2 million shares, or up to $35 million in value, of NW Natural’s common stock through a repurchase program that has been extended annually. The purchases are made in the open market or through privately negotiated transactions. Since the program’s inception, the Company has repurchased 733,300 shares of common stock at a total cost of $22.0 million. In April 2005, NW Natural’s Board of Directors extended the program through May 31, 2006.

Item 6. EXHIBITS

See Exhibit Index attached hereto.

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SIGNATURE

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

	NORTHWEST NATURAL GAS COMPANY
	(Registrant)
Dated: November 3, 2005	/s/ Stephen P. Feltz
	Stephen P. Feltz
	Principal Accounting Officer
	Treasurer and Controller

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NORTHWEST NATURAL GAS COMPANY

EXHIBIT INDEX

To

Quarterly Report on Form 10-Q

For Quarter Ended

Sept. 30, 2005

Document	Exhibit Number
Form of Credit Agreement between Northwest Natural Gas Company and each of JPMorgan Chase Bank, N.A., U.S. Bank National Association, Bank of America, N.A., Wells Fargo Bank, N.A. and Wachovia Bank, National Association, dated as of Oct. 1, 2005, including Form of Note.	10.1
Form of Long-Term Incentive Plan Agreement	10.2
Form of Restated Stock Option Plan Agreement	10.3
Statement re: Computation of Per Share Earnings	11
Computation of Ratio of Earnings to Fixed Charges	12
Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002	31.1
Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002	31.2
Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	32.1

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