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 June 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 ¨

At July 29, 2005, 27,575,547 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 June 30, 2005

		Page Number
	PART I. FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements
	Consolidated Statements of Income for the three-month and six-month periods ended June 30, 2005 and 2004	3
	Consolidated Balance Sheets at June 30, 2005 and 2004 and Dec. 31, 2004	4
	Consolidated Statements of Cash Flows for the six-month periods ended June 30, 2005 and 2004	6
	Consolidated Statements of Capitalization at June 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	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 4.	Controls and Procedures	34
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 4.	Submission of Matters to a Vote of Security Holders	36
Item 5.	Other Information	36
Item 6.	Exhibits	36
	Signature	37

2

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Income

(Unaudited)

	Three Months Ended June 30,					Six Months Ended June 30,
Thousands, except per share amounts	2005		2004			2005		2004
Operating revenues:
Gross operating revenues	$	153,667	$	109,659		$	462,444	$	364,109
Cost of sales		92,425		57,030			273,033		199,446
Net operating revenues		61,242		52,629			189,411		164,663
Operating expenses:
Operations and maintenance		26,981		24,307			54,176		49,817
Taxes other than income taxes		8,803		7,531			22,756		19,984
Depreciation and amortization		15,312		13,913			30,507		27,819
Total operating expenses		51,096		45,751			107,439		97,620
Income from operations		10,146		6,878			81,972		67,043
Other income and expense – net		405		442			470		465
Interest charges – net of amounts capitalized		8,906		8,764			18,034		17,708
Income (loss) before income taxes		1,645		(1,444	)		64,408		49,800
Income tax expense (benefit)		505		(728	)		23,381		17,904
Net income (loss)	$	1,140	$	(716	)	$	41,027	$	31,896
Average common shares outstanding:
Basic		27,555		27,257			27,568		26,615
Diluted		27,834		27,582			27,841		26,947
Earnings (loss) per share of common stock:
Basic	$	0.04	$	(0.03	)	$	1.49	$	1.20
Diluted	$	0.04	$	(0.03	)	$	1.48	$	1.19

See Notes to Consolidated Financial Statements

3

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets

Thousands	June 30, 2005 (Unaudited)			June 30, 2004 (Unaudited)			Dec. 31, 2004
Assets:
Plant and property:
Utility plant	$	1,835,326		$	1,717,296		$	1,794,972
Less accumulated depreciation		523,518			491,340			505,286
Utility plant - net		1,311,808			1,225,956			1,289,686
Non-utility property		34,862			26,807			33,963
Less accumulated depreciation and amortization		5,581			5,083			5,244
Non-utility property - net		29,281			21,724			28,719
Total plant and property		1,341,089			1,247,680			1,318,405
Other investments		57,978			75,083			60,618
Current assets:
Cash and cash equivalents		40,343			7,528			5,248
Accounts receivable		35,740			38,701			63,109
Allowance for uncollectible accounts		(2,521	)		(1,886	)		(2,434	)
Accrued unbilled revenue		17,244			11,970			64,401
Inventories of gas, materials and supplies		45,842			48,960			66,477
Income tax receivable		—			5,015			15,970
Prepayments and other current assets		16,048			12,194			24,346
Total current assets		152,696			122,482			237,117
Regulatory assets:
Income tax asset		65,622			64,475			64,734
Deferred gas costs receivable		7,958			9,513			9,551
Unamortized costs on debt redemptions		7,097			7,568			7,332
Other		7,092			5,377			3,321
Total regulatory assets		87,769			86,933			84,938
Other assets:
Fair value of non-trading derivatives		64,089			29,428			16,399
Other		20,818			13,338			14,718
Total other assets		84,907			42,766			31,117
Total assets	$	1,724,439		$	1,574,944		$	1,732,195

See Notes to Consolidated Financial Statements

4

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets

Thousands	June 30, 2005 (Unaudited)			June 30, 2004 (Unaudited)			Dec. 31, 2004
Capitalization and liabilities:
Capitalization:
Common stock	$	87,285		$	86,563		$	87,231
Premium on common stock		300,074			295,159			300,034
Earnings invested in the business		207,050			183,190			183,932
Unearned stock compensation		(756	)		(892	)		(862	)
Accumulated other comprehensive income (loss)		(1,818	)		(1,016	)		(1,818	)
Total common stock equity		591,835			563,004			568,517
Long-term debt		521,500			500,073			484,027
Total capitalization		1,113,335			1,063,077			1,052,544
Current liabilities:
Notes payable		—			4,901			102,500
Accounts payable		66,472			78,679			102,478
Long-term debt due within one year		27,241			—			15,000
Taxes accrued		8,543			5,837			10,242
Interest accrued		2,953			2,929			2,897
Other current and accrued liabilities		35,312			30,708			34,168
Total current liabilities		140,521			123,054			267,285
Regulatory liabilities:
Accrued asset removal costs		162,350			140,847			153,258
Customer advances		1,662			1,584			1,529
Unrealized gain on non-trading derivatives, net		54,666			28,285			10,912
Total regulatory liabilities		218,678			170,716			165,699
Other liabilities:
Deferred income taxes		206,666			189,514			211,080
Deferred investment tax credits		5,200			6,341			5,660
Fair value of non-trading derivatives		9,423			1,143			5,487
Other		30,616			21,099			24,440
Total other liabilities		251,905			218,097			246,667
Commitments and contingencies (see Note 7)		—			—			—
Total capitalization and liabilities	$	1,724,439		$	1,574,944		$	1,732,195

See Notes to Consolidated Financial Statements

5

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended June 30,
Thousands	2005			2004
Operating activities:
Net income	$	41,027		$	31,896
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		30,507			27,819
Deferred income taxes and investment tax credits		(4,874	)		17,113
Undistributed losses (earnings) from equity investments		(54	)		49
Allowance for funds used during construction		(201	)		(581	)
Deferred gas costs - net		1,593			(15,140	)
Gain on sale of non-utility investments		(12	)		—
Income from investment in life insurance		(974	)		(1,425	)
Other		(4,109	)		(1,003	)
Changes in operating assets and liabilities:
Accounts receivable - net of allowance for uncollectible accounts		27,456			11,684
Accrued unbilled revenue		47,157			47,139
Inventories of gas, materials and supplies		20,635			1,899
Income tax receivable		15,970			3,952
Prepayments and other current assets		8,298			11,500
Accounts payable		(36,006	)		(7,349	)
Accrued interest and other taxes		(1,643	)		(3,000	)
Other current and accrued liabilities		1,145			(881	)
Cash provided by operating activities		145,915			123,672
Investing activities:
Acquisition and construction of utility plant assets		(43,009	)		(62,789	)
Investment in non-utility property		(889	)		(3,412	)
Proceeds from sale of non-utility investments		3,001			—
Proceeds from investment in life insurance		—			1,141
Other investments		678			(97	)
Cash used in investing activities		(40,219	)		(65,157	)
Financing activities:
Common stock issued, net of expenses		4,669			42,185
Common stock repurchased		(4,861	)		—
Restricted stock purchased		—			(272	)
Long-term debt issued		50,000			—
Change in short-term debt		(102,500	)		(80,300	)
Dividend payments on common stock		(17,909	)		(17,306	)
Cash used in financing activities		(70,601	)		(55,693	)
Increase in cash and cash equivalents		35,095			2,822
Cash and cash equivalents - beginning of period		5,248			4,706
Cash and cash equivalents - end of period	$	40,343		$	7,528
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	17,796		$	17,788
Income taxes	$	11,739		$	2,500
Supplemental disclosure of non-cash financing activities:
Conversions to common stock:
7-1/4 % Series of Convertible Debentures	$	286		$	246

See Notes to Consolidated Financial Statements

6

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Capitalization

	June 30, 2005 (Unaudited)					June 30, 2004 (Unaudited)					Dec. 31, 2004
Common stock	$	87,285				$	86,563				$	87,231
Premium on common stock		300,074					295,159					300,034
Earnings invested in the business		207,050					183,190					183,932
Unearned stock compensation		(756	)				(892	)				(862	)
Accumulated other comprehensive income (loss)		(1,818	)				(1,016	)				(1,818	)
Total common stock equity		591,835		53	%		563,004		53	%		568,517		54	%
Medium-Term Notes
First Mortgage Bonds:
6.340% Series B due 2005		5,000					5,000					5,000
6.380% Series B due 2005		5,000					5,000					5,000
6.450% Series B due 2005		5,000					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 (see Note 9)		4,241					5,573					4,527
		548,741					500,073					499,027
Less long-term debt due within one year (see Note 9)		27,241					—					15,000
Total long-term debt		521,500		47	%		500,073		47	%		484,027		46	%
Total capitalization	$	1,113,335		100	%	$	1,063,077		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 presentation 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 and requires certain disclosures regarding the effects of a federal subsidy provided by the Act.

Based on current guidance, clarification of the Act and existing plan design, the Company has now determined, with input from the plan’s actuary, that the prescription drug benefit provided by its postretirement benefit plan will qualify for a small federal subsidy. The Company’s adoption of FSP No. FAS 106-2, effective July 1, 2004, had no material impact on cash flows, accumulated postretirement benefit obligations or net periodic postretirement benefit costs.

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 the Company’s 2004 Form 10-K, Part II, Item 8., Note 4. 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 is not expected to have a material impact on the Company’s financial condition or results of operations.

8

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 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.

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 June 30, 2005, the aggregate number of performance-based shares awarded and outstanding 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 six months ended June 30, 2005, $0.4 million and $1.0 million were accrued and expensed as compensation under the LTIP grants, respectively, for the 2004-06 and 2005-07 performance periods.

Restated Stock Option Plan. Under the Restated SOP, options on 1,238,800 shares were available for grant and options to purchase 321,349 shares were outstanding at June 30, 2005. Options generally have 10-year terms and vest ratably over a three-year period following the date of grant. No new options were granted in the first six months of 2005.

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 above.

9

If compensation expense for awards under the Restated SOP and for shares issued under the ESPP had been recognized during 2004 and 2005 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 June 30,						Six Months Ended June 30,
Thousands, except per share amounts	2005			2004			2005			2004
Net income (loss) as reported	$	1,140		$	(716	)	$	41,027		$	31,896
Pro forma stock-based compensation expense determined under the fair value based method - net of tax		(92	)		(106	)		(183	)		(206	)
Pro forma net income (loss) - basic		1,048			(822	)		40,844			31,690
Debenture interest less taxes		47			61			94			123
Pro-forma net income (loss) - diluted	$	1,095		$	(761	)	$	40,938		$	31,813
Basic earnings (loss) per share
As reported	$	0.04		$	(0.03	)	$	1.49		$	1.20
Pro forma	$	0.04		$	(0.03	)	$	1.48		$	1.19
Diluted earnings (loss) per share
As reported	$	0.04		$	(0.03	)	$	1.48		$	1.19
Pro forma	$	0.04		$	(0.03	)	$	1.47		$	1.18

The Company will be required to adopt SFAS No. 123R for expensing employee stock options and other share based compensation beginning in 2006 (see Note 2). 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. Use of derivatives is permitted only after the commodity price and exchange rate have been identified, are determined to exceed acceptable tolerance levels and are considered to be unavoidable because they are necessary to support normal business activities. NW Natural does not enter into derivative instruments for trading or speculative purposes and intends any increase in market risk created by holding derivatives to be offset by the exposures they modify. 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. NW Natural recently 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. The mark-to-market adjustment for the forward gas supply contracts outstanding at June 30, 2005 is an unrealized loss of $7.8 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, “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 fixed-price financial swap contracts previously designated as cash flow hedge instruments for the forward gas supply contracts 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 contracts. However, due to the regulatory deferral mechanism under SFAS No. 71, the accounting changes had no impact on the Company’s financial condition, results of operations or cash flows.

Foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for NW Natural’s commodity and 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 June 30, 2005 is a negligible

10

unrealized gain. 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 deferred asset or liability account.

At June 30, 2005 and 2004 and Dec. 31, 2004, no unrealized gains or losses from mark-to-market valuations of the Company’s derivative instruments were recognized in current income, but are reported as derivative assets or liabilities and offset by a corresponding deferred account balance under 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:

	June 30,						Dec. 31,
Thousands	2005			2004			2004
Natural gas commodity-based derivative instruments:
Fixed-price financial swaps	$	62,464		$	28,629		$	12,641
Fixed-price financial call options		—			(369	)		(2,195	)
Indexed-price physical supply		(7,844	)		—			—
Fixed-price physical supply		—			—			24
Foreign currency forward purchases		46			25			442
Total	$	54,666		$	28,285		$	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.

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

	Three Months Ended June 30,											Six Months Ended June 30,
Thousands	Utility			Interstate Gas Storage		Other			Total			Utility		Interstate Gas Storage		Other			Total
2005
Net operating revenues	$	59,269		$	1,952	$	21		$	61,242		$	185,388	$	3,981	$	42		$	189,411
Depreciation and amortization		15,149			163		—			15,312			30,180		327		—			30,507
Other operating expenses		35,561			202		21			35,784			76,481		374		77			76,932
Income (loss) from operations		8,559			1,587		—			10,146			78,727		3,280		(35	)		81,972
Income from financial investments		506			—		208			714			974		—		71			1,045
Net income		12			844		284			1,140			38,856		1,742		429			41,027
Total assets at June 30, 2005		1,682,429			29,424		12,586			1,724,439			1,682,429		29,424		12,586			1,724,439
2004
Net operating revenues	$	50,995		$	1,591	$	43		$	52,629		$	161,193	$	3,387	$	83		$	164,663
Depreciation and amortization		13,799			114		—			13,913			27,591		228		—			27,819
Other operating expenses		31,602			163		73			31,838			69,348		368		85			69,801
Income (loss) from operations		5,594			1,314		(30	)		6,878			64,254		2,791		(2	)		67,043
Income (loss) from financial investments		607			—		332			939			1,425		—		(49	)		1,376
Net income (loss)		(1,761	)		705		340			(716	)		30,119		1,495		282			31,896
Total assets at June 30, 2004		1,536,332			21,996		16,616			1,574,944			1,536,332		21,996		16,616			1,574,944

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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 six-month periods ended June 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 June 30,
	2005			2004			2005		2004
Service cost	$	1,589		$	1,409		$	114	$	132
Interest cost		3,263			3,199			308		364
Special termination benefits		63			—			—		—
Expected return on plan assets		(3,530	)		(3,309	)		—		—
Amortization of transition obligation		—			—			103		103
Amortization of prior service cost		223			274			—		—
Recognized actuarial loss		481			436			72		118
Net periodic benefit cost	$	2,089		$	2,009		$	597	$	717
Thousands	Pension Benefits						Other Postretirement Benefits
	Six Months Ended June 30,
	2005			2004			2005		2004
Service cost	$	3,177		$	2,819		$	228	$	264
Interest cost		6,526			6,399			616		729
Special termination benefits		126			—			—		—
Expected return on plan assets		(7,061	)		(6,619	)		—		—
Amortization of transition obligation		—			—			206		206
Amortization of prior service cost		446			547			—		—
Recognized actuarial loss		963			872			144		237
Net periodic benefit cost	$	4,177		$	4,018		$	1,194	$	1,436

Employer Contributions

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. In 2004, the Company contributed $5.3 million to one of its DBP plans for the 2004 plan year, of which $1.0 million represented the minimum required funding. The Company is not required to make additional cash contributions to its qualified DBP plans in 2005 based on minimum funding requirements. However, the Company is considering and may elect to make an additional contribution up to $35 million on or before 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 Sept. 15, 2005. 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.

7. Commitments and Contingencies

Environmental Matters

NW Natural owns or previously owned properties currently being investigated that may require environmental response. 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 preliminary nature of the environmental investigations being conducted, the range of loss

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contingencies beyond the amounts currently accrued, and the probabilities thereof, cannot be reasonably estimated. 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.

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 quarter of 2005, the estimated liability for this site increased due to additional storm-water pollution work and indoor air quality studies required at the Siltronic site, resulting in an additional expense in the first quarter of 2005 of less than $0.1 million. The amount of this additional expense was deferred to a regulatory asset account pursuant to an order of the Oregon Public Utility Commission (OPUC) (see 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 the 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 estimated cost for the RI/FS, which is expected to be completed in 2007, is $1.6 million. The EPA has indicated that further study will be required; however, the scope of any additional work, and the related range of liability, cannot reasonably be determined at this time.

In April 2004 the Company entered into an Administrative Order on Consent (AOC) 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 will begin removal of the tar deposit in the Portland Harbor this summer with an expected completion by the end of 2005. The EPA chose the removal option in which the tar deposit will be dredged from the river and a protective cap of sand placed over the entire site after completion of the removal. The range of costs for the removal, including technical work, oversight, consultants and legal fees is between $8.0 and $10.0 million. As a result of the EPA’s decision on the removal option, an additional accrual of $5.3 million was recorded in June 2005. The Company’s estimate of probable liability for the removal of the tar deposit is $8.2 million.

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 nine 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. NW Natural does not believe there are facts sufficient to constitute a claim against the Company.

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, Portland Harbor and Portland Gas sites. The authorization, which has been extended through January 2006 and extended to cover the Oregon Steel Mills site, allows NW Natural to defer and seek recovery of unreimbursed environmental costs in a future general rate case. On a cumulative basis through June 30, 2005, the Company has paid a total of $3.9 million relating to the named sites since the effective date of the deferral authorization.

NW Natural will first seek to recover from insurance the costs of investigation and remediation for which it may be responsible with respect to the Gasco, Siltronic, Portland Harbor, Portland Gas and Oregon Steel Mills sites. To the extent these costs are not recovered from insurance, then NW Natural will seek recovery through future rates subject to a prudency review and approval by the OPUC. At June 30, 2005, NW Natural had a $14.8 million receivable representing an estimate of the environmental costs accrued to date and expected to be recovered from insurance, consisting of $3.2 million for costs relating to the Gasco site, $11.4 million for costs relating to the Portland Harbor site and $0.2 million for costs relating to the Oregon Steel Mills site.

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

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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 Kerry Law, Arnold Zuehlke and Kenneth Cooper, 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-AS) (the Kerry Law case), Kasey Cooper, Kevin Cooper, C.G. Nick Courtney, John V. Shooter, Ike Whittlesey and Roger Whittlesey v. Northwest Natural (U.S. Dist. Ct. D. Or., Case No. CV-05-241-KI) (the Kasey Cooper case) and Phillip Courtney v. Northwest Natural (U.S. Dist. Ct. D. Or., Case No. CV-05-507-BR) (the Phillip Courtney case). In October 2004, plaintiffs’ motion in the Kerry Law case for collective action certification was denied. On May 20, 2005 a fourth lawsuit was filed against the Company, Ken Holtmann et al v. Northwest Natural (U.S. Dist. Ct. D. Or., Case No. 05-CV-00724-BR) (the Holtmann case). The Kerry Law case, the Kasey Cooper case and the Holtmann case have been consolidated into a single matter (consolidated case). The Philip Courtney case was dismissed and Mr. Courtney was joined in the consolidated case. Kenneth Cooper, Casey Cooper and Kevin Cooper dismissed themselves from the lawsuit. Ten plaintiffs remain in the consolidated case, which is pending in the United States District Court for the District of Oregon (U.S. Dist. Ct. D. Or., Case No. CV-04-728-KI). The claims are more fully described in Part II, Item 8., Note 12, “Legal Proceedings,” in the 2004 Form 10-K.

In May 2005, NW Natural filed a motion to stay or in the alternative to dismiss plaintiffs’ “contract” claims on the basis that such claims are preempted by the Employee Retirement Income Security Act of 1974, as amended, and therefore plaintiffs’ should be required to exhaust the administrative review process with regard to each of the plans under which they allege they would have been eligible to receive benefits. Plaintiffs subsequently requested leave to amend their complaint to plead additionally and in the alternative a tort claim. Plaintiffs allege that the Company breached an implied covenant of good faith and fair dealing by allegedly misclassifying plaintiffs as independent contractors thus depriving them of the “benefits and compensation” they would have otherwise received under various employee benefit plans if they had been classified as employees. There is insufficient information at this time to reasonably estimate the range of liability, if any, from this claim. The matter is pending.

South Mist Pipeline Extension (SMPE). In connection with the construction of the SMPE, NW Natural negotiated with some land owners regarding valuation of easements and rights-of-way obtained pursuant to condemnation proceedings. In other cases, compensation was determined in individual court proceedings. All such proceedings for easements and rights-of-way were completed by July 2005. The aggregate amount of compensation paid was not material to the Company’s financial condition, results of operations or cash flows.

8. Comprehensive Income

For the six months ended June 30, 2005 and 2004, reported net income was equivalent to total comprehensive income. 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 June 30, 2005, which is included in common stock equity (see the accompanying Consolidated Statements of Capitalization, above).

9. Long-Term Debt

In June 2005, the Company issued and sold, pursuant to its Medium-Term Note (MTN) program, $50 million in principal amount of secured 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 debt 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 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).

The Company has called all of its outstanding Convertible Debentures, 7-1/4% Series due 2012 (the Debentures), for redemption on Aug. 31, 2005, at 100% of their principal amount plus accrued unpaid interest to the date of redemption. At any time prior to the close of business on Aug. 31, 2005, the Debentures may be converted into shares of the Company’s Common Stock at the rate of 50.25 shares for each $1,000 principal amount of Debentures surrendered, equivalent to a conversion price of $19.90 per share.

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Including the optional redemption of the Debentures discussed above, the maturities for each of the 12-month periods ended June 30 for the next five years on the long-term debt outstanding amount to:

	12-Month Periods Ended June 30,
	2006		2007		2008		2009		2010
(Thousands)
Long-term debt maturities	$	27,241	$	29,500	$	—	$	5,000	$	—
Optional put maturities, if exercised		10,000		20,000		—		20,000		20,000
Totals	$	37,241	$	49,500	$	—	$	25,000	$	20,000

Holders of certain long-term debt issues have put options that, if exercised, would accelerate maturities. These optional put maturities, which are shown in the above table, have interest rates that range from 6.52 to 7.05 percent.

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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 six months ended June 30, 2005 and 2004.

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 to the accompanying consolidated financial statements).

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 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 its application of critical accounting policies and estimates, except as indicated below under “Accounting for Derivative Instruments and Hedging Activities.” Management has discussed its estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board.

Within the context of the Company’s critical accounting policies and estimates, management is not currently aware of any reasonably likely events or circumstances that would result in materially different amounts being reported.

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. The Company previously reported that 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 to the accompanying consolidated financial statements). In 2005, NW Natural entered into an agreement providing for natural gas commodity exchange transactions with an unaffiliated energy marketing company involving gas purchases by NW Natural under existing gas supply contracts. 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 now accounted for as derivative instruments and marked-to-market based on fair value pursuant to SFAS No. 133. The mark-to-market adjustment at June 30, 2005 resulted in an unrealized loss of $7.8 million, which was recorded on the balance sheet at fair value. Generally, these physical gas purchase contracts are subject to regulatory deferral, and, as

16

such, any unrealized gain or loss in the fair value is not recognized in current income but is recorded as regulatory assets or regulatory liabilities 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). The Company’s estimate of fair value is determined by internal modeling based on natural gas index prices that are subject to market volatility. For estimated fair values (unrealized gains and losses) at June 30, 2005 and 2004 and Dec. 31, 2004, see Note 4 to the accompanying consolidated financial statements. As a result of these forward gas supply contracts being classified as derivatives for accounting purposes, the fixed-price financial swap contracts, previously designated as hedge instruments for the physical gas supply contracts, no longer qualify for hedge accounting under SFAS No. 133. Therefore, the financial swap contracts are no longer designated as cash flow hedges even though they continue to hedge the financial risk exposure of the physical gas supply contracts. Due to the regulatory accounting treatment under SFAS No. 71, there is no expected income statement impact resulting from these changes in accounting treatment.

Earnings and Dividends

Three months ended June 30, 2005 compared to June 30, 2004

The Company’s consolidated net income was $1.1 million, or 4 cents a share, for the three months ended June 30, 2005, as compared to a loss of $0.7 million, or 3 cents a share, for the second quarter of 2004. In the second quarter of 2005, the Company earned a negligible amount from utility operations, $0.8 million from interstate gas storage operations and $0.3 million from other non-regulated business activities, as compared, respectively, to a loss of $1.8 million and net income of $0.7 million and $0.3 million in the second quarter of 2004.

The increase in second quarter consolidated net income was primarily due to:

• an increase in utility net operating revenues (margin) of $8.2 million or 16 percent over last year due to approved rate increases for new plant investments, customer growth and improved industrial margins (see “Comparison of Gas Distribution Operations—Residential and Commercial Sales” and “—Industrial Sales and Transportation,” below) ;

• colder weather in the quarter compared to last year, which was only partially offset by the Company’s weather normalization mechanism (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms,” in the 2004 Form 10-K);

• a decrease in gas cost savings compared to last year, including lower off-system sales margin which is credited to cost of gas, due to higher natural gas prices (see “Comparison of Gas Distribution Operations—Cost of Gas,” below);

• an increase in interstate gas storage margin due to an increase in optimization services (see “Interstate Gas Storage,” below); and

• a $5.3 million increase in utility operating expenses over last year due to a combination of higher operation and maintenance expense related to increased labor and employee benefit costs, higher revenue-based franchise tax expense related to increased gross revenues, and higher property tax and depreciation expenses related to additional investments in utility plant assets (see “Operating Expenses,” below).

Six months ended June 30, 2005 compared to June 30, 2004

Consolidated net income was $41.0 million, or $1.48 a share, for the six months ended June 30, 2005, as compared to $31.9 million, or $1.19 a share, for the same year-to-date period of 2004. In the six months ended June 30, 2005, the Company earned $38.9 million from utility operations, $1.7 million from interstate storage operations and $0.4 million from other non-regulated activities, as compared, respectively, to $30.1 million, $1.5 million and $0.3 million in the six months ended June 30, 2004.

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

• an increase in margin of $24.2 million or 15 percent over last year primarily due to rate increases for new plant investments, customer growth and improved industrial margins;

• a net 1 percent increase in volumes delivered to residential and commercial customers over last year due to 3.8 percent customer growth and 6 percent colder weather, partially offset by declining use per customer per degree day; 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);

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• 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

• an increase in utility operating expenses of $9.7 million over last year due to a combination of higher operation and maintenance expense related to increased labor and employee benefit costs, higher revenue-based franchise tax expense related to increased gross revenues, and higher property tax and depreciation expenses related to increased utility plant balances.

The Company paid dividends on its common stock of 32.5 cents in each of the three month periods ended June 30, 2005 and 2004, and paid dividends of 65 cents per share in each of the six month periods ended June 30, 2005 and 2004. The current indicated annual dividend rate is $1.30 a 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. Future earnings and cash flows from utility operations will be determined largely by the pace of continued growth in the residential and commercial markets and by NW Natural’s ability to remain price competitive in the large industrial market, to control expenses and to obtain reasonable and timely regulatory ratemaking treatment for its operating and maintenance costs and investments in utility plant. See Part II, Item 7., “Results of Operations—Regulatory Matters,” in the 2004 Form 10-K.

General Rate Cases

In May 2005, the Company reached a settlement with the Federal Energy Regulatory Commission staff and all intervenors with respect to its rate case filed in January 2005. The settlement provided for a small net increase in the maximum rates for the Company’s interstate storage services operation and new service offerings. The new maximum rates are designed to reflect updated costs related to development of the Mist gas storage facilities since 2001 and costs associated with the South Mist Pipeline Extension (SMPE) project. The new rates were effective July 1, 2005.

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.

Purchased Gas Adjustment. Rate changes are applied each year under the Purchased Gas Adjustment (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 approved rate increases effective Oct. 1, 2004 averaging 20.1 percent for Oregon residential sales customers, and the Washington Utilities and Transportation Commission (WUTC) approved rate increases effective Nov. 1, 2004 averaging 19.5 percent for Washington residential sales customers. These increases included a cost of service recovery for the SMPE project, which was completed and placed into service in September 2004 with an additional revenue increase totaling $14.7 million per year.

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 on June 20, 2005. The OPUC reviewed and acknowledged the report and accepted the OPUC staff’s proposed administrative recommendations. However, the report did not result in any change in the Company’s gas purchasing strategies.

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 is a partial decoupling mechanism that breaks 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.

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The conservation tariff includes two components. The first component is 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 is 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 is determined by customer consumption patterns 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 is scheduled to expire at the end of September 2005, unless the OPUC approves 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 coverage from a partial decoupling of 90 percent of residential and commercial gas usage to a full decoupling of 100 percent. On Aug. 2, 2005, a motion was filed to suspend the procedural schedule in the docket pending OPUC action upon the stipulation. The Company, OPUC staff and several parties to the proceeding are finalizing the stipulation and preparing joint testimony in support of the stipulation to file with the OPUC. The stipulation is subject to review and approval by the OPUC.

Tax Legislation

On Aug. 1, 2005, the Oregon legislature passed Senate Bill 408, which requires the OPUC to establish an annual tax adjustment mechanism to ensure that Oregon utilities do not collect in rates more taxes than they actually pay to government entities. The Governor has not yet signed the bill. If the bill is signed into law, the OPUC must interpret the bill’s provisions to determine how the tax adjustment will be applied. Due to the uncertainties related 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 six months ended June 30:

	Three Months Ended June 30,
(Thousands, except customer count and degree day data)	2005					2004
Utility volumes - therms:
Residential and commercial sales		98,745		41	%		82,961		38	%
Industrial sales and transportation		140,995		59	%		135,746		62	%
Total utility volumes sold and delivered		239,740		100	%		218,707		100	%
Utility operating revenues - dollars:
Residential and commercial sales	$	113,423		75	%	$	81,419		75	%
Industrial sales and transportation		37,651		25	%		23,476		22	%
Other revenues		574		0	%		3,116		3	%
Total utility operating revenues	$	151,648		100	%	$	108,011		100	%
Cost of gas sold		92,379					57,016
Net utility operating revenues (margin)	$	59,269				$	50,995
Margin, by category
Residential sales	$	42,823		71	%	$	33,602		65	%
Commercial sales		20,098		34	%		16,626		33	%
Industrial - firm sales and transportation		5,075		9	%		4,561		9	%
Industrial - interruptible sales and transportation		5,865		10	%		5,021		10	%
Miscellaneous revenues		1,287		2	%		803		2	%
Other margin adjustments		(13,180	)	-22	%		(11,816	)	-23	%
Margin before weather normalization and decoupling		61,968		104	%		48,797		96	%
Weather normalization mechanism		(728	)	-1	%		3,151		6	%
Conservation tariff-decoupling mechanism		(1,971	)	-3	%		(953	)	-2	%
Net utility operating revenues (margin)	$	59,269		100	%	$	50,995		100	%
Total number of customers (end of period)		604,572					582,270
Actual degree days		652					469
Percent colder (warmer) than normal		(5	%)				(31	%)
(25-year average degree days is used as normal)

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	Six Months Ended June 30,
(Thousands, except degree day data)	2005					2004
Utility volumes - therms:
Residential and commercial sales		329,428		54	%		325,437		54	%
Industrial sales and transportation		279,482		46	%		281,590		46	%
Total utility volumes sold and delivered		608,910		100	%		607,027		100	%
Utility operating revenues - dollars:
Residential and commercial sales	$	371,965		81	%	$	305,950		85	%
Industrial sales and transportation		80,642		18	%		51,039		14	%
Other revenues		5,726		1	%		3,620		1	%
Total utility operating revenues	$	458,333		100	%	$	360,609		100	%
Cost of gas sold		272,945					199,416
Net utility operating revenues (margin)	$	185,388				$	161,193
Margin, by category
Residential sales	$	134,136		73	%	$	120,860		76	%
Commercial sales		59,975		32	%		55,691		35	%
Industrial - firm sales and transportation		11,309		6	%		10,067		6	%
Industrial - interruptible sales and transportation		11,926		6	%		10,367		6	%
Miscellaneous revenues		3,120		2	%		2,183		1	%
Other margin adjustments		(40,423	)	-22	%		(43,783	)	-27	%
Margin before weather normalization and decoupling		180,043		97	%		155,385		97	%
Weather normalization mechanism		2,518		1	%		5,420		3	%
Conservation tariff-decoupling mechanism		2,827		2	%		388		0	%
Net utility operating revenues (margin)	$	185,388		100	%	$	161,193		100	%
Actual degree days		2,421					2,276
Percent colder (warmer) than normal		(5	%)				(10	%)
(25-year average degree days is used as normal)

The increase in total utility volumes sold and delivered in the three- and six-month periods ended June 30, 2005, as compared to the same periods in 2004, primarily reflects colder weather and customer growth, partially offset by customer conservation.

NW Natural continued to grow its customer base, with a net increase of 22,302 customers since June 30, 2004, for a growth rate of 3.8 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 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.

Three months ended June 30, 2005 compared to June 30, 2004

In the three months ended June 30, 2005, weather, although 5 percent warmer than normal, was 39 percent colder than last year, largely contributing to a 25 percent increase in margin from residential and commercial sales. The weather normalization mechanism only partially covers volume reductions in the second quarter when weather is warmer

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than normal because the mechanism ends on May 15 of each year. Also, Washington customers are not covered by the weather normalization mechanism and about 8 percent of Oregon customers have elected not to be covered by the mechanism. In addition, the temperature variances early in the second quarter are most likely to have a larger impact on the weather normalization amount in the quarter because there are more heating degree days earlier in the quarter. As a result of colder than normal weather in the first half of the quarter, the weather normalization mechanism reduced margin by $0.7 million in the three months ended June 30, 2005 on 5 percent warmer than normal weather for the entire period, as compared to a contribution of $3.2 million to margin in the same period of 2004 when weather was 30 percent warmer than normal. The conservation tariff decoupling mechanism reduced margin by $2.0 million in the second quarter of 2005 compared to a reduction of $1.0 million in the second quarter of 2004.

Other margin adjustments, which include pipeline demand charges, unaccounted-for gas charges and other regulatory cost of gas and revenue adjustments, reduced margin by $13.2 million in the second quarter of 2005 compared to $11.8 million in 2004. The increase in net deductions from margin adjustments was primarily due to lower demand charge deferrals resulting from increased sales volumes and lower cost of gas savings as compared to last year’s second quarter.

Six months ended June 30, 2005 compared to June 30, 2004

In the six months ended June 30, 2005, weather was 6 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 six months of the calendar year because most of the heating degree days occur in the period prior to May 15. As a result, the weather normalization mechanism contributed $2.5 million to margin in the six months ended June 30, 2005 on 5 percent warmer than normal weather, and contributed $5.4 million to margin in the same period of 2004 on weather that was 10 percent warmer than normal. The decoupling mechanism contributed $2.8 million to margin in the first six months of 2005 compared to $0.4 million in 2004.

Other margin adjustments reduced margin by $40.4 million in the first six months of 2005 and $43.8 million in 2004. The increase in net deductions from margin adjustments was primarily due to higher cost of gas savings in the current year-to-date period as compared to last year, lower unaccounted-for gas charges and a net increase in revenue adjustments.

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 June 30,						Six Months Ended June 30,
(Thousands, except customers)	2005			2004			2005			2004
Utility volumes - therms:
Residential sales		71,569			61,043			230,500			233,814
Commercial sales		47,508			42,372			140,857			143,965
Change in unbilled sales		(20,332	)		(20,454	)		(41,929	)		(52,342	)
Total weather-sensitive utility volumes		98,745			82,961			329,428			325,437
Utility operating revenues - dollars:
Residential sales	$	86,888		$	65,770		$	276,139		$	233,930
Commercial sales		47,803			35,597			142,226			119,502
Change in unbilled sales		(21,268	)		(19,948	)		(46,400	)		(47,482	)
Total weather-sensitive utility revenues	$	113,423		$	81,419		$	371,965		$	305,950
Total number of customers (end of period)		604,572			582,270			604,572			582,270

Three months ended June 30, 2005 compared to June 30, 2004

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

• volumes sold were 19 percent higher, primarily reflecting the effect of 39 percent colder weather and 3.8 percent customer growth; and

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• operating revenues were 37 percent higher, primarily due to the increase in sales volume and higher rates, which reflect the higher gas costs, effective Oct. 1, 2004 (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” in the 2004 Form 10-K).

Six months ended June 30, 2005 compared to June 30, 2004

The primary factors affecting residential and commercial volumes and operating revenues in the six months ended June 30, 2005 compared to the comparable period in 2004 were:

• volumes sold were 1 percent higher, reflecting the effect of 6 percent colder weather and over 3 percent customer growth, partially offset by a 4 percent decline in average use per customer; and

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

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 was significantly reduced with the implementation of the weather normalization mechanism and the conservation tariff. See “Comparison of Gas Distribution Operations (Utility),” above. Margin from the weather normalization mechanism was adjusted in the current quarter to reflect temperature data errors in prior periods for one district in NW Natural’s service area. The overall impact of these corrections was negligible in this quarter because the changes in weather normalization adjustments were offset by corresponding adjustments in the decoupling mechanism related to the same periods. The net effect of the errors was immaterial to all prior periods.

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 June 30, 2005, accrued unbilled revenue was $17.2 million, compared to $12.0 million at June 30, 2004.

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Industrial Sales and Transportation

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

	Three Months Ended June 30,				Six Months Ended June 30,
(Thousands)	2005		2004		2005		2004
Utility volumes - therms:
Industrial - firm sales		16,823		14,157		38,561		32,667
Industrial - interruptible sales		35,130		22,980		71,448		47,356
Transportation		89,042		98,609		169,473		201,567
Total utility volumes		140,995		135,746		279,482		281,590
Utility operating revenues - dollars:
Industrial - firm sales	$	13,503	$	9,259	$	31,047	$	21,553
Industrial - interruptible sales		21,376		11,061		43,989		23,035
Transportation		2,772		3,156		5,606		6,451
Total utility operating revenues	$	37,651	$	23,476	$	80,642	$	51,039
Total number of industrial customers (end of period)		950		945		950		945

Three months ended June 30, 2005 compared to June 30, 2004

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

• total volumes were 4 percent higher, reflecting improved economic conditions in the region; and

• revenues were 60 percent higher, reflecting rate increases related to capital investments and increased gas costs, and higher volumes of gas sold due to a significant shift of customers from transportation service to sales service.

Six months ended June 30, 2005 compared to June 30, 2004

The primary factor affecting industrial sales and transportation volumes and operating revenues in the six months ended June 30, 2005 compared to the same period in 2004 was revenues that were 58 percent higher, reflecting a significant shift of customers from transportation to sales service and the higher rates related to capital investments and increased gas costs.

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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 increased net operating revenues by $0.5 million and $5.6 million in the second quarter and first six months of 2005, respectively, compared to $3.1 million and $3.5 million in the second quarter and first six months of 2004, respectively. The following table summarizes other revenues by primary category:

	Three Months Ended June 30,						Six Months Ended June 30,
(Thousands)	2005			2004			2005			2004
Revenue adjustments:
Current deferrals:
Decoupling	$	(1,971	)	$	(953	)	$	2,827		$	388
SMPE		212			179			293			1,280
Coos Bay		98			—			703			—
OPUC investigation		—			(840	)		—			(958	)
Other		(505	)		—			(33	)		—
Current amortizations:
Interstate gas storage credits		2,714			5,324			2,714			5,324
Decoupling		(397	)		(581	)		(1,236	)		(2,135	)
SMPE		(499	)		—			(1,568	)		—
Conservation programs		(441	)		(563	)		(1,329	)		(1,953	)
Year 2000 technology costs		(243	)		(302	)		(739	)		(874	)
Other		319			50			974			365
Net revenue adjustments		(713	)		2,314			2,606			1,437
Miscellaneous revenues:
Customer fees		1,251			694			3,021			1,908
Other		36			108			99			275
Total miscellaneous revenues		1,287			802			3,120			2,183
Total other revenues	$	574		$	3,116		$	5,726		$	3,620

Three months ended June 30, 2005 compared to June 30, 2004

Other revenues in the three months ended June 30, 2005 were $2.5 million lower than the comparable period in 2004 primarily because of a decrease in the current decoupling deferrals ($1.0 million), a decrease in the interstate gas storage credits to customers due to lower net income from storage operations in calendar year 2004 compared to 2003 ($2.6 million) and an increase in customer fees ($0.6 million). Other revenues for the second quarter of 2005 include a correction to the decoupling adjustment resulting from a temperature data error that also affected the weather normalization adjustment (see “Residential and Commercial Sales,” above), with no material impact on the Company’s financial condition or results of operations. The decoupling deferrals for current and prior periods were adjusted to reflect the corrected data for each.

Six months ended June 30, 2005 compared to June 30, 2004

Other revenues in the six months ended June 30, 2005 were $2.1 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 ($3.3 million) and an increase in customer fees ($1.1 million), partially offset by a decrease in the interstate gas storage credits to customers due to lower net income from storage operations in calendar year 2004 compared to 2003 ($2.6 million).

Cost of Gas Sold

Natural gas commodity prices have increased significantly in recent periods (see Part II, Item 7., “Results of Operations—Comparison of Gas Operations—Cost of Gas Sold,” in the 2004 Form 10-K). During the second quarter and the first six months of 2005, the cost per therm of gas sold was 29 percent and 26 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 (demand equalization), regulatory deferrals and company use.

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NW Natural uses a natural gas commodity-price hedge program under the terms of its Derivatives Policy to help manage its variable price gas commodity contracts (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” in the 2004 Form 10-K). NW Natural realized net financial hedge gains of $11.3 million and $9.8 million from this program during the three- and six-month periods ended June 30, 2005, respectively, compared to net hedge gains of $9.0 million and $18.0 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 second quarter of 2005 were slightly lower than the costs embedded in rates, and NW Natural’s share of the lower costs increased margin by $ 0.2 million. For the second quarter of 2004, NW Natural’s gas costs were also lower than the gas costs embedded in rates, and NW Natural’s share of the lower costs increased margin by $1.1 million. In the first six 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 second quarter of 2005 was a negligible loss compared to income of $0.2 million for the same period in 2004. In the first six months of 2005, NW Natural’s share of margin from off-system gas sales contributed $0.3 million of margin, compared to $0.2 million for the same period in 2004.

Business Segments Other than Gas Distribution Operations

Interstate Gas Storage

NW Natural earned net income from its non-utility interstate gas storage business segment in the three months ended June 30, 2005, of $0.8 million after regulatory sharing and income taxes. This compares to net income of $0.7 million in the three months ended June 30, 2004. For the six months ended June 30, 2005, results from this segment were net income of $1.7 million, compared to $1.5 million for the comparable period in 2004.

The Company’s third party optimization activities are under a contract with an unaffiliated energy marketing company. That company optimizes the value of NW Natural’s assets by engaging in marketing temporarily unused portions of NW Natural’s off-system pipeline transportation capacity and gas storage capacity.

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 June 30, 2005 were net earnings of $0.2 million compared to net earnings of $0.3 million in the second quarter of 2004. For the first six months of both 2005 and 2004, results were net earnings of $0.1 million. The net earnings for both the three- and six-month periods in 2005 and 2004 were less than 1 cent per share.

The Company’s net investment balances attributed to Financial Corporation at June 30, 2005 and 2004 were $3.1 and $5.7 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.

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Operating Expenses

Operations and Maintenance

Operations and maintenance expenses in second quarter of 2005 were $27.0 million, 11 percent higher than in the second quarter of 2004. The $2.7 million increase was primarily due to higher payroll related expenses resulting from employee additions, pay increases and higher benefit costs ($3.0 million), offset, in part, by a decrease in uncollectible accounts expense ($0.4 million).

Operations and maintenance expenses in the first six months of 2005 were $54.2 million, 9 percent higher than in the first six months of 2004. The $4.4 million increase was primarily due to higher payroll related expenses resulting from employee additions, pay increases and higher benefit costs ($4.3 million), offset, in part, by a decrease in uncollectible accounts expense ($0.3 million).

Taxes Other than Income Taxes

Taxes other than income taxes, which are principally comprised of franchise, property and payroll taxes, increased $1.3 million, or 17 percent, and $2.8 million, or 14 percent, in the three- and six-month periods ended June 30, 2005, respectively, compared to the same periods in 2004. For the three- and six-month periods ended June 30, 2005, franchise taxes, which are based on gross revenues, increased $1.0 million and $2.1 million, respectively, reflecting higher gross revenues primarily due to higher rates. For the three- and six-month periods ended June 30, 2005, property taxes increased $0.3 million and $0.6 million, respectively, due to utility plant additions in 2004 and 2005.

Depreciation and Amortization

The Company’s depreciation and amortization expense increased by $1.4 million, or 10 percent, and $2.7 million, or 10 percent, in the three- and six-month periods ended June 30, 2005, compared to the same periods in 2004. The increased expense is primarily due to additional investments in utility property that were made to meet continuing customer growth, including the largest component of the Company’s investment in SMPE, which was put into service in September 2004 (see “Financial Condition—Cash Flows—Investing Activities,” below).

Interest Charges – Net of Amounts Capitalized

The Company’s net interest expense increased by $0.1 million, or 2 percent, and $0.3 million, or 2 percent, in the three- and six-month periods ended June 30, 2005, respectively, compared to the same periods in 2004. The slight increase in interest charges is due to an increase in the average balance of debt outstanding during the period, higher interest rates and lower interest credits allocated to the debt component for the allowance for funds used during construction (see Part II, Item 7., “Results of Operations—Interest Charges—Net of Amounts Capitalized,” in the 2004 Form 10-K). Also, the issuance of $50 million of new long-term debt in June 2005, at rates higher than short-term debt, had a minor impact on interest charges in the current periods (see “Cash Flows—Financing Activities,” below).

Income Taxes

The effective corporate income tax rate from operations was 36.3 percent and 36.0 percent for the six-month periods ended June 30, 2005 and 2004, respectively.

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).

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

	June 30,				Dec. 31, 2004
	2005		2004
Common stock equity	51.9	%	52.7	%	48.7	%
Long-term debt	45.7	%	46.8	%	41.3	%
Short-term debt, including current maturities of long-term debt (see Note 9)	2.4	%	0.5	%	10.0	%
Total	100.0	%	100.0	%	100.0	%

Achieving the target capital structure and maintaining sufficient liquidity are necessary to maintain attractive credit ratings and have access to capital markets at reasonable costs.

Liquidity and Capital Resources

At June 30, 2005, the Company had $40.3 million of cash and cash equivalents compared to $7.5 million at June 30, 2004 and $5.2 million at Dec. 31, 2004. The increase in cash and cash equivalents at June 30, 2005 over the prior periods reflects the sale by the Company of $50 million of its medium-term notes in the second quarter of 2005. See Note 9 to the accompanying consolidated financial statements 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 has available through Sept. 30, 2005 committed lines of credit totaling $150 million with four commercial banks (see “Lines of Credit,” below, and Part II, Item 8., Note 6, in the 2004 Form 10-K). Short-term debt balances are typically higher at the end of December each year due to seasonal working capital requirements, which reflect the financing of accounts receivable and natural gas inventories during the winter heating season. Short-term debt balances are significantly lower at the end of June as receivables and inventories are converted into cash, which is used to reduce short-term debt.

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.

To provide long-term financing, in February 2004 the Company filed a universal shelf registration with the Securities and Exchange Commission providing for the issuance and sale of up to $200 million of securities, which may consist of secured debt (First Mortgage Bonds), unsecured debt, preferred stock or common stock. Under its shelf registration, the Company has sold $90 million of securities, leaving $110 million available for the future issuance of long-term debt or equity securities (see “Cash Flows—Financing Activities,” below).

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.

Contractual Obligations

During the six months ended June 30, 2005, there were no material changes to the Company’s estimated future contractual obligations other than the $50 million of secured long-term debt described in Note 9, 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

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described in Part II, Item 7., “Financial Condition—Liquidity and Capital Resources—Contractual Obligations,” in the 2004 Form 10-K.

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 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 an agency agreement with a commercial bank, is supported by committed bank lines of credit (see “Lines of Credit,” below, and Part II, Item 8., Note 6, in the 2004 Form 10-K). NW Natural had no commercial paper notes outstanding at June 30, 2005, compared to $4.9 million outstanding at June 30, 2004 and $102.5 million outstanding at Dec. 31, 2004. Commercial paper balances are typically lower at the end of the first and second quarters compared to year-end due to collections from higher sales and the withdrawal of inventories during the winter heating season.

Lines of Credit

Effective Oct. 1, 2004, NW Natural entered into lines of credit with Bank of America, N.A., JP Morgan Chase Bank, U.S. Bank National Association, and Wells Fargo Bank, totaling $150 million in aggregate. Half of the credit facility with each bank, or $75 million, is committed and available through Sept. 30, 2005, and the other $75 million is committed and available through Sept. 30, 2007.

Under the terms of these lines of credit, NW Natural pays commitment fees but is not required to maintain compensating bank balances. The interest rates on any outstanding borrowings under these lines of credit are based on current market rates. There were no outstanding balances on these lines of credit at June 30, 2005 or 2004, or at Dec. 31, 2004.

NW Natural’s lines of credit require that credit ratings be maintained in effect at all times and that notice be given of any change in its senior unsecured debt ratings. 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 to drawing upon the lines of credit. However, interest rates on any loans outstanding under NW Natural’s bank lines are tied to credit ratings, which would increase or decrease the cost of debt outstanding under these lines of credit, if any, when ratings are changed.

The lines of credit require the Company to maintain an indebtedness to total capitalization ratio of 65 percent or less and to maintain a consolidated net worth at least equal to 80 percent of its net worth at Sept. 30, 2004, plus 50 percent of the Company’s net income for each subsequent fiscal quarter. Failure to comply with either of these covenants would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding. The Company was in compliance with these covenants at June 30, 2005 and at Dec. 31, 2004, and with the equivalent covenants in the prior year’s lines of credit at June 30, 2004.

The Company intends to renew or renegotiate its current lines of credit during the third quarter of 2005, and, dependent upon current market conditions, may elect to increase the amount of the lines and extend their maturities, subject to OPUC and WUTC approval.

Credit Ratings

In June 2005, NW Natural’s secured long-term debt credit rating was upgraded by Fitch Ratings (Fitch), from “A” to “A+”. In addition, Fitch raised the Company’s unsecured long-term debt rating from “A-” to “A” and re-affirmed its short-term commercial paper rating at “F1”. 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.

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.

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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 July 2005, the Company called all of its outstanding Convertible Debentures, 7-1/4% Series due 2012 (the Debentures), for redemption on Aug. 31, 2005 at 100% of their principal amount plus accrued interest to the date of redemption. At any time prior to the close of business on Aug. 31, 2005, the Debentures may be converted into shares of the Company’s common stock at the rate of 50.25 shares for each $1,000 principal amount of Debentures surrendered, equivalent to a conversion price of $19.90 per share.

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 six months of 2005, net income increased $9.1 million, non-cash adjustments decreased $4.8 million and changes in operating assets and liabilities increased $17.9 million compared to the same period in 2004.

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

	Six Months Ended June 30,
Thousands	2005		2004
Net income	$	41,027	$	31,896
Non-cash adjustments to net income		21,876		26,669
Changes in operating assets and liabilities (working capital)		83,012		65,107
Cash provided by operating activities	$	145,915	$	123,672

Six months ended June 30, 2005 compared to June 30, 2004

The overall change in cash flow from operating activities in the first six months of 2005 compared to 2004 was an increase of $22.2 million. The significant factors contributing to the cash flow changes between periods are as follows:

• an increase in net income added $9.1 million to cash flow;

• a decrease in accounts payable reduced cash flow by $28.7 million primarily reflecting higher gas prices at year-end 2004 compared to year-end 2003;

• a decrease in deferred income taxes and investment tax credits reduced cash flow by $22.0 million, reflecting higher tax benefits realized in 2004 from accelerated bonus depreciation on large capital additions that were placed into service in 2004;

• a decrease in inventories increased cash flow by $18.7 million, primarily reflecting higher volume withdrawals from storage and higher gas prices on such withdrawals during the 2005 period;

• a decrease in regulatory receivables for deferred gas costs increased cash flow by $16.7 million, reflecting different patterns of deferral activity and deferral collections between the two years 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 $15.8 million, reflecting collections from higher receivable balances during the 2005 period; and

• a decrease in income taxes receivable increased cash flow by $12.0 million.

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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 six months of 2005 totaled $40.2 million, down from $65.2 million in the same period of 2004. Cash requirements for the acquisition and construction of utility plant totaled $43.0 million, down from $62.8 million in the same period of 2004. The decrease in cash requirements for utility construction in the first six 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 with the fourth quarter of 2004.

On June 2, 2005, the State of Washington adopted new gas pipeline safety rules that, in some cases, are more stringent than existing federal rules. The Company is evaluating the effect of these rules on the Company’s Washington operations and existing compliance programs, but the newly adopted rules are not expected to have a material impact on the Company’s financial condition, results of operations or cash flows.

Investments in non-utility property during the first six months of 2005 totaled $0.9 million, down from $3.4 million during the first six months of 2004. The higher investments in 2004 were primarily for improvements to the Company’s 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 six months of 2005 totaled $70.6 million, up from $55.7 million in the same period of 2004. Factors contributing to the $14.9 million increase were a larger reduction in short-term debt in the first six months of 2005 ($102.5 million) as compared to the first six months of 2004 ($80.3 million), and the lower amount of equity financing in 2005 ($4.7 million) as compared to 2004 ($42.2 million), partially offset by the issuance of $50.0 million in MTNs during the first six 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 by $102.5 million in the first six months of 2005.

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. The offering of common stock was pursuant to the Company’s universal shelf registration statement for the registration of $200 million of securities, which was effective in February 2004 (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 134,800 shares in the first six months of 2005 at a cost of $4.9 million. No shares were purchased in 2004. Since the program’s inception, the Company has repurchased 490,200 shares of common stock at a total cost of $13.1 million.

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 may elect to contribute up to an additional $35.0 million on or before 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 Sept. 15, 2005. In addition, the Company will continue to make cash contributions during 2005 in the form of ongoing benefit payments as required for its unfunded

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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 six months and 12 months ended June 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 4.41, 3.40 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.

Contingent Liabilities

Environmental Matters

The Company is subject to federal, state and local laws and regulations related to environmental matters. These evolving laws and regulations may require expenditures over a long timeframe to control environmental impacts. The Company believes that appropriate investigation or remediation is being undertaken at all the relevant sites. NW Natural will seek to recover the costs of investigation and remediation for which it may be responsible with respect to environmental matters, if any, from insurance. To date, the Company has spent and accrued a total of $19.3 million for environmental costs, most of which should be recoverable from insurance. To the extent these costs are not recovered from insurance, NW Natural will seek recovery through future rates subject to approval by the OPUC. Based on amounts spent and accrued to date, NW Natural has a $14.8 million receivable as of June 30, 2005 representing an estimate of the environmental costs it expects to recover from insurance. Accordingly, the Company does not expect that the ultimate resolution of these matters will have a material adverse effect on its financial condition, results of operations or cash flows. See Note 7 to the accompanying consolidated financial statements.

In May 2003, the OPUC approved NW Natural’s request for deferral of environmental costs associated with specific sites. The authorization, which has been extended through January 2006, allows NW Natural to defer and seek recovery of unreimbursed environmental costs in a future general rate case. On a cumulative basis through June 30, 2005, the Company paid out a total of $3.9 million relating to the specified sites since the effective date of the deferral authorization. See Note 7 to the accompanying consolidated financial statements.

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 and policies, and the U.S. Department of Transportation’s Office of Pipeline Safety with respect to the maintenance of pipeline integrity;

• weather conditions and other natural phenomena;

• 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 and suppliers;

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

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• 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;

• 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;

• competition for new energy development opportunities;

• 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, 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.

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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). There have been no material changes to the information relating to market risk provided in the Company’s 2004 Form 10-K. However, NW Natural recently 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, with the fair value determined using forward price curves. The mark-to-market adjustment at June 30, 2005 is an unrealized loss of $7.8 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 unaffiliated energy marketing 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 and instruments 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.

Item 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

As of June 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 June 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				435,900	$	23,908,585
04/01/05- 04/30/05	—		—	4,500		(159,837	)
05/01/05- 05/31/05	—		—	28,600		(1,033,147	)
06/01/05- 06/30/05	2,000	$	36.84	21,200		(776,764	)
Total	2,000	$	36.84	490,200	$	21,938,837

⁽¹⁾ During the three months ended June 30, 2005, the Company accepted 2,000 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 490,200 shares of common stock at a total cost of $13.1 million. In April 2005, NW Natural’s Board of Directors extended the program through May 31, 2006.

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Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

NW Natural’s Annual Meeting of Shareholders was held in Portland, Oregon on May 26, 2005. At the meeting, five director-nominees were elected, as follows:

Director	Class	Term Expiring	Votes For	Votes Withheld
Kenneth Thrasher	II	2007	23,861,014	210,685
Martha L. (“Stormy”) Byorum	III	2008	23,860,684	211,015
John D. Carter	III	2008	23,731,376	340,323
C. Scott Gibson	III	2008	23,809,782	261,917
Richard G. Reiten	III	2008	23,750,414	321,285

The other six directors whose terms of office as directors continued after the Annual Meeting are: Timothy P. Boyle, Mark S. Dodson, Tod R. Hamachek, Randall C. Papé, Russell F. Tromley and Richard L. Woolworth. There were no broker non-votes on the election of directors.

No other matters were voted upon at the meeting.

Item 5. OTHER INFORMATION

On July 27, 2005, the Organization and Executive Compensation Committee of the Board of Directors modified the Company earnings performance factor for the 2005 Executive Annual Incentive Plan by changing the measure from net income to earnings per share. The performance scale was also adjusted to take into account the Company’s weather normalization mechanism, which was an inadvertent oversight in the original calculation of the target measures. See Exhibit 10.1 attached to this report.

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: August 4, 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

June 30, 2005

Document	Exhibit Number
Summary of Executive Compensation – Named Executive Officers	10.1
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