NORTHWEST NATURAL GAS CO - 10-Q Quarterly Report

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 March 31, 2005

¨	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

LOGO

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 May 2, 2005, 27,551,032 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 March 31, 2005


		Page Number
	PART I. FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements

	Consolidated Statements of Income for the three-month periods ended March 31, 2005 and 2004	3

	Consolidated Balance Sheets at March 31, 2005 and 2004 and Dec. 31, 2004	4

	Consolidated Statements of Cash Flows for the three-month periods ended March 31, 2005 and 2004	6

	Consolidated Statements of Capitalization at March 31, 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	32

Item 4.	Controls and Procedures	32

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	33

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34

Item 5.	Other Information	34

Item 6.	Exhibits	34

	Signature	35

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Income

(Unaudited)


	Three Months Ended March 31,
Thousands, except per share amounts	2005		2004
Operating revenues:
Gross operating revenues	$	308,777	$	254,450
Cost of sales		180,608		142,416

Net operating revenues		128,169		112,034

Operating expenses:
Operations and maintenance		27,195		25,510
Taxes other than income taxes		13,953		12,453
Depreciation and amortization		15,195		13,906

Total operating expenses		56,343		51,869

Income from operations		71,826		60,165

Other income and expense – net		65		23
Interest charges - net of amounts capitalized		9,128		8,944

Income before income taxes		62,763		51,244
Income tax expense		22,876		18,632

Net income	$	39,887	$	32,612

Average common shares outstanding:
Basic		27,578		25,972
Diluted		27,863		26,314

Earnings per share of common stock:
Basic	$	1.45	$	1.26
Diluted	$	1.43	$	1.24

See Notes to Consolidated Financial Statements

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets


Thousands	March 31, 2005 (Unaudited)			March 31, 2004 (Unaudited)			Dec. 31, 2004
Assets:
Plant and property:
Utility plant	$	1,814,991		$	1,679,267		$	1,794,972
Less accumulated depreciation		514,785			481,829			505,286

Utility plant - net		1,300,206			1,197,438			1,289,686

Non-utility property		34,157			23,861			33,963
Less accumulated depreciation and amortization		5,408			4,969			5,244

Non-utility property - net		28,749			18,892			28,719

Total plant and property		1,328,955			1,216,330			1,318,405

Other investments		57,198			74,332			60,618

Current assets:
Cash and cash equivalents		2,740			2,788			5,248
Accounts receivable		73,776			65,616			63,109
Allowance for uncollectible accounts		(3,499	)		(2,638	)		(2,434	)
Accrued unbilled revenue		38,880			31,788			64,401
Inventories of gas, materials and supplies		31,401			38,006			66,477
Income tax receivable		—			2,623			15,970
Prepayments and other current assets		21,429			17,082			24,346

Total current assets		164,727			155,265			237,117

Regulatory assets:
Income tax asset		65,622			64,475			64,734
Deferred gas costs receivable		12,978			9,544			9,551
Unamortized costs on debt redemptions		7,215			7,685			7,332
Other		6,732			3,917			3,321

Total regulatory assets		92,547			85,621			84,938

Other assets:
Fair value of non-trading derivatives		88,634			36,069			16,399
Other		14,536			11,669			14,718

Total other assets		103,170			47,738			31,117

Total assets	$	1,746,597		$	1,579,286		$	1,732,195

See Notes to Consolidated Financial Statements

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets


Thousands	March 31, 2005 (Unaudited)			March 31, 2004 (Unaudited)			Dec. 31, 2004
Capitalization and liabilities:
Capitalization:
Common stock	$	87,244		$	82,342		$	87,231
Premium on common stock		299,900			258,033			300,034
Earnings invested in the business		214,864			194,231			183,932
Unearned stock compensation		(809	)		(852	)		(862	)
Accumulated other comprehensive income (loss)		(1,818	)		(1,016	)		(1,818	)

Total common stock equity		599,381			532,738			568,517
Long-term debt		483,875			500,130			484,027

Total capitalization		1,083,256			1,032,868			1,052,544

Current liabilities:
Notes payable		10,500			22,900			102,500
Accounts payable		84,693			78,669			102,478
Long-term debt due within one year		15,000			—			15,000
Taxes accrued		22,074			8,186			10,242
Interest accrued		11,171			11,241			2,897
Other current and accrued liabilities		34,320			31,944			34,168

Total current liabilities		177,758			152,940			267,285

Regulatory liabilities:
Accrued asset removal costs		157,975			138,309			153,258
Customer advances		1,592			1,560			1,529
Unrealized gain on non-trading derivatives, net		78,205			36,069			10,912

Total regulatory liabilities		237,772			175,938			165,699

Other liabilities:
Deferred income taxes		206,651			190,332			211,080
Deferred investment tax credits		5,155			6,367			5,660
Fair value of non-trading derivatives		10,429			—			5,487
Other		25,576			20,841			24,440

Total other liabilities		247,811			217,540			246,667

Commitments and contingencies (see Note 7)		—			—			—

Total capitalization and liabilities	$	1,746,597		$	1,579,286		$	1,732,195

See Notes to Consolidated Financial Statements

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Cash Flows

(Unaudited)


	Three Months Ended March 31,
Thousands	2005			2004
Operating activities:
Net income	$	39,887		$	32,612
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		15,195			13,906
Deferred income taxes and investment tax credits		(4,934	)		17,957
Undistributed losses from equity investments		137			381
Allowance for funds used during construction		(86	)		(236	)
Deferred gas costs – net		(3,427	)		(15,171	)
Gain on sale of non-utility investments		(12	)		—
Income from investment in life insurance		(452	)		(818	)
Other		(2,801	)		1,626
Changes in operating assets and liabilities:
Accounts receivable - net of allowance for uncollectible accounts		(9,602	)		(14,479	)
Accrued unbilled revenue		25,521			27,321
Inventories of gas, materials and supplies		35,076			12,853
Income tax receivable		15,970			6,363
Prepayments and other current assets		2,970			6,470
Accounts payable		(17,785	)		(7,360	)
Accrued interest and other taxes		20,106			7,824
Other current and accrued liabilities		152			355

Cash provided by operating activities		115,915			89,604

Investing activities:
Acquisition and construction of utility plant assets		(20,748	)		(22,450	)
Investment in non-utility property		(194	)		(466	)
Proceeds from sale of non-utility investments		3,001			—
Other investments		746			(50	)

Cash used in investing activities		(17,195	)		(22,966	)

Financing activities:
Common stock issued, net of expenses		2,569			2,315
Common stock repurchased		(2,895	)		—
Restricted stock purchased		—			(180	)
Restricted stock amortization		53			43
Change in short-term debt		(92,000	)		(62,300	)
Dividend payments on common stock		(8,955	)		(8,434	)

Cash used in financing activities		(101,228	)		(68,556	)

Decrease in cash and cash equivalents		(2,508	)		(1,918	)
Cash and cash equivalents - beginning of period		5,248			4,706

Cash and cash equivalents - end of period	$	2,740		$	2,788

Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	970		$	684
Income taxes	$	—		$	—

Supplemental disclosure of non-cash financing activities:
Conversions to common stock:
7-1/4% Series of Convertible Debentures	$	152		$	189

See Notes to Consolidated Financial Statements

NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Capitalization


Thousands	March 31, 2005 (Unaudited)					March 31, 2004 (Unaudited)					Dec. 31, 2004
Common stock equity:
Common stock	$	87,244				$	82,342				$	87,231
Premium on common stock		299,900					258,033					300,034
Earnings invested in the business		214,864					194,231					183,932
Unearned compensation		(809	)				(852	)				(862	)
Accumulated other comprehensive income (loss)		(1,818	)				(1,016	)				(1,818	)

Total common stock equity		599,381		55	%		532,738		52	%		568,517		54	%
Long-term debt:
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
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
Convertible Debentures
7-1/4% Series due 2012		4,375					5,630					4,527

		498,875					500,130					499,027
Less long-term debt due within one year		15,000					—					15,000

Total long-term debt		483,875		45	%		500,130		48	%		484,027		46	%

Total capitalization	$	1,083,256		100	%	$	1,032,868		100	%	$	1,052,544		100	%

See Notes to Consolidated Financial Statements

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 interim consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that the management of the Company considers necessary for a fair statement of the results for each period reported. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in the Company’s 2004 Annual Report on Form 10-K (2004 Form 10-K). A significant part of the business of the Company is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.

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

2.	New Accounting Standards

Inventory Costs. In November 2004, the Financial Accounting Standards Board (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 impact this new standard may have on its financial statements, but it is expected that its implementation will not 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. Disclosures of estimated fair value and compensation expense using the Black-Scholes option pricing model, and its corresponding impact on the financial statements, is provided 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 or results of operations.

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 operation.

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

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 March 31, 2005, the aggregate number of performance-based shares awarded and outstanding under the Company’s LTIP at the minimum, threshold, target and maximum levels were as follows:


		No. of Performance Shares Awarded
Year Awarded	Performance Period	Minimum	Threshold	Target	Maximum
2003	2003-05	—	7,000	28,000	56,000
2004	2004-06	—	7,750	31,000	62,000
2005	2005-07	—	8,750	35,000	70,000

	Total	—	23,500	94,000	188,000

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 ended March 31, 2005, the amount accrued and expensed as compensation under the LTIP grants was $0.6 million.

Restated Stock Option Plan. Under the Restated SOP, options on 1,238,200 shares were available for grant and options to purchase 355,849 shares were outstanding at March 31, 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 quarter 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 Accounting Principles Board (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 or for shares issued under the ESPP. For a further discussion of expense recognition for stock-based compensation, see Note 2 above. If compensation expense for awards under these two plans had been recognized 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 Share Based Options and ESPP:	Three Months Ended March 31,
Thousands, except per share amounts	2005			2004
Net income as reported	$	39,887		$	32,612
Pro forma share based compensation expense determined under the fair value based method - net of tax		(92	)		(100	)

Pro forma earnings applicable to common stock - basic		39,795			32,512
Debenture interest less taxes		48			62

Pro-forma earnings applicable to common stock - diluted	$	39,843		$	32,574

Basic earnings per share:
As reported	$	1.45		$	1.26
Pro forma	$	1.44		$	1.25
Diluted earnings per share:
As reported	$	1.43		$	1.24
Pro forma	$	1.43		$	1.24

The Company will be required to adopt SFAS No. 123R for expensing employee stock options and other share based compensation plans 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 purposes and believes that any increase in market risk created by holding derivatives should 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 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 changed 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, with the fair value determined using forward price curves. 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 exemption that is allowed for contracts that are probable of delivery in the normal course of business. 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 March 31, 2005 is an unrealized loss of $8.5 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).

At March 31, 2005 and 2004 and Dec. 31, 2004, all unrealized gains and losses from mark-to-market valuations of the Company’s derivative instruments are not 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:


	March 31,					Dec. 31,
Thousands	2005			2004		2004
Fair Value Gain (Loss)
Natural gas commodity based derivatives:
Fixed-price financial swaps	$	87,995		$	35,982	$	12,641
Fixed-price financial calls		—			—		(2,195	)
Index-price physical supply		(8,483	)		—		—
Fixed-price physical supply		(1,429	)		—		24
Foreign currency forward purchases		122			87		442

Total	$	78,205		$	36,069	$	10,912

5.	Segment Information

The Company principally operates in a segment of business, “Utility,” consisting of the distribution of natural gas. Another segment, “Gas Storage,” represents natural gas storage services provided to interstate customers and optimization services provided by 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-month periods ended March 31, 2005 and 2004. Inter-segment transactions are insignificant.


	Three Months Ended March 31,
Thousands	Utility		Gas Storage		Other			Total
2005
Net operating revenues	$	126,119	$	2,029	$	21		$	128,169
Depreciation and amortization		15,031		164		—			15,195
Other operating expenses		40,920		172		56			41,148
Income (loss) from operations		70,168		1,693		(35	)		71,826
Income (loss) from financial investments		468		—		(137	)		331
Net income		38,844		898		145			39,887
Total assets at March 31, 2005		1,707,832		28,331		10,434			1,746,597

2004
Net operating revenues	$	110,198	$	1,796	$	40		$	112,034
Depreciation and amortization		13,792		114		—			13,906
Other operating expenses		37,746		205		12			37,963
Income from operations		58,660		1,477		28			60,165
Income (loss) from financial investments		817		—		(381	)		436
Net income (loss)		31,881		790		(59	)		32,612
Total assets at March 31, 2004		1,545,618		19,249		14,419			1,579,286

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 months ended March 31, 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.


	Pension Benefits						Other Postretirement Benefits
	Three Months Ended March 31,
Thousands	2005			2004			2005		2004
Service cost	$	1,589		$	1,410		$	114	$	132
Interest cost		3,263			3,200			308		364
Special termination benefits		63			—			—		—
Expected return on plan assets		(3,530	)		(3,310	)		—		—
Amortization of transition obligation		—			—			103		103
Amortization of prior service cost		223			273			—		—
Recognized actuarial loss		481			436			72		118

Net periodic benefit cost	$	2,089		$	2,009		$	597	$	717

Employer Contributions

The Company is not required to make cash contributions to its qualified non-contributory defined benefit plans in 2005, but cash contributions in the form of ongoing benefit payments will be required for its unfunded non-qualified supplemental pension plans and other postretirement benefit plans in 2005. See Part II, Item 8., Note 7, in the 2004 Form 10-K for a discussion of estimated future payments.

7.	Commitments and Contingencies

Environmental Matters

As previously reported, NW Natural owns or previously owned properties currently being investigated that may require environmental response. NW Natural has accrued all material loss contingencies relating to environmental matters that it believes to be probable of assertion and reasonably estimable. The Company continues to study the extent of its environmental liabilities, but due to the preliminary nature of the environmental investigations being conducted, the range of loss 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 continues to estimate its range of remaining liability, including the cost of investigation, from among feasible alternatives, at between $1.3 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. 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, including $0.6 million accrued in the first quarter of 2005.

In April 2004 the Company entered into an Administrative Order on Consent (AOC) providing for early action removal of a body 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. The Company continues to negotiate with the EPA regarding the method and timing of the removal of the body of tar which now is scheduled to take place in the summer of 2005. The Company estimates the removal cost to be in the range of $3.0 million to $5.0 million, depending on the manner in which the contaminated material is disposed. The Company has agreed with the ODEQ to do additional work, if necessary, on the Gasco site in conjunction with the EPA early action remediation work.

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 March 31, 2005, the Company has paid a total of $3.5 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. If 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 March 31, 2005, NW Natural had a $9.2 million receivable representing an estimate of the environmental costs incurred, and expected to be incurred, and recovered from insurance, consisting of $2.9 million for costs relating to the Gasco site, $6.1 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 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) and 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). Plaintiffs in both cases are or have been independent backhoe operators who performed services for the Company under contract who allege violation of the Fair Labor Standards Act (FLSA) for failure to pay overtime and also assert state wage and hour claims. Plaintiffs allege that they should have been considered “employees” of the Company. The plaintiffs in these cases seek overtime and interest to be proven, liquidated damages equal to the overtime award, civil penalties and attorneys fees and costs. Additionally, plaintiffs in the Kasey Cooper case allege that the failure to classify them as employees constituted a breach of contract under certain Company employee benefit plans and seek an unspecified amount of damages for the value of what they would have received under these programs, agreements and plans if they had been classified as employees. In October 2004, plaintiffs’ motion in the Kerry Law case for collective action certification was denied. See Part I, Item 3., Legal Proceedings, in the 2004 Form 10-K.

On March 8, 2005, one of the plaintiffs in the Kerry Law case dropped out of the lawsuit and his claim was dismissed. On March 18, 2005, the remaining two plaintiffs in this case filed a Second Amended Complaint which added an employee benefits claim, specifically alleging that the failure to classify them as employees constituted a breach of contract under certain employee benefit plans. They also seek an unspecified amount of damages for the value of what they would have received under these programs, agreements and plans if they had been classified as employees.

On March 28, 2005, the Kerry Law case and the Kasey Cooper case were consolidated into a single lawsuit in the United States District Court for the District of Oregon (Law v. NW Natural and Whittlesey v. NW Natural (U.S. Dist. Ct. D. Or., Case No. CV-05-241-KI)) (the Consolidated Case). In April 2005, notices of voluntary dismissal were filed with prejudice as to two plaintiffs in the Consolidated Case.

On April 12, 2005, a lawsuit was filed against the Company (Phillip Courtney v. Northwest Natural) (U.S. Dist. Ct. D. Or., Case No. CV-05-507-BR) (the Phillip Courtney case) by a former independent backhoe operator who performed services for the Company under contract. The claims in this lawsuit mirror those in the Consolidated Case and may be consolidated with the claims in that case.

The Company intends to vigorously contest the claims alleged in the Consolidated Case and the Phillip Courtney case. There is insufficient information at this time to reasonably estimate the amount of liability, if any, from these claims.

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.

8.	Comprehensive Income

Total comprehensive income, as defined by SFAS No. 130, “Reporting Comprehensive Income,” is summarized in the following table:


	Three Months Ended March 31,
Thousands	2005		2004
Net income	$	39,887	$	32,612
Other comprehensive income (loss), net of tax		—		—

Total comprehensive income	$	39,887	$	32,612

For the three months ended March 31, 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 income (loss) ($1.8 million at March 31, 2005) is included in common stock equity (see Consolidated Statements of Capitalization, above).

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 months ended March 31, 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 (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 which are most important to the representation of the Company’s financial condition and results of operations and which require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if 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 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 Part II, Item 8., Note 1, “Derivatives Policy,” in the 2004 Form 10-K). In 2005, NW Natural entered into an agreement providing for natural gas commodity exchange transactions with an unaffiliated energy marketing company involving gas purchases under existing NW Natural gas supply contracts. These exchanges result 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 March 31, 2005 resulted in an unrealized loss of $8.5 million, which was recorded on the balance sheet at fair value. Generally, these contracts are subject to regulatory deferral mechanisms, and as such any change in the fair value is not recognized in current income but is recorded as regulatory assets or regulatory liabilities pursuant to SFAS No. 71 (see Part II, Item 8., Note 1, in the 2004 Form 10-K). The Company’s estimate of fair value is determined from period to period based on prices available from external sources and internal modeling based on index prices that are subject to market volatility. For estimated fair values at March 31, 2005 and 2004 and Dec. 31, 2004, see Note 4 to the accompanying consolidated financial statements.

Earnings and Dividends

The Company’s consolidated net income was $39.9 million, or $1.43 a share, in the quarter ended March 31, 2005, as compared to $32.6 million, or $1.24 a share, in the same quarter of the prior fiscal year. In the first quarter of 2005, the Company earned $38.8 million from utility operations (or $1.40 a share), $0.9 million from gas storage (or 3 cents a share) and $0.2 million from other (or one cent a share), as compared to $31.9 million (or $1.21 a share), $0.8 million (or 3 cents a share) and a loss of less than $0.1 million (per share amount was negligible), respectively, in the first quarter of 2004.

First quarter of 2005 compared to first quarter of 2004

The primary factors affecting first quarter earnings this year over last year include:

•

overall earnings were $7.3 million, or 22 percent, higher than last year primarily due to approved rate increases on new capital investments, customer growth and improving industrial margins, which were partially offset by higher operating expenses;

•

net operating revenue (margin) from the utility increased $15.9 million, or 15 percent, over last year on a 5 percent decrease in total sales and transportation volumes;

•

margin from residential and commercial customers increased $14.5 million, or 15 percent, primarily due to approved rate increases for the investments in the South Mist Pipeline Extension (SMPE) and Coos County distribution system completed during 2004 as well as customer growth;

•

volumes from residential and commercial customers decreased 5 percent over last year due to customers’ ongoing conservation efforts and the effects of warmer weather, but the financial impact of these lower volumes was largely offset by the Company’s weather normalization

(WARM) and conservation tariffs and its regulatory demand cost deferral and gas cost sharing mechanisms;

•

margins from industrial customers increased $1.4 million, or 13 percent, over last year on 5 percent lower volumes, with higher margins due to increased sales in higher margin industrial rate schedules;

•

commodity prices on the Company’s purchases of natural gas were mostly hedged for the current period, and those prices were included in customer rates through the annual purchased gas adjustment mechanism, so the impact of higher natural gas prices in 2005 over 2004 had a minimal impact on earnings;

•

the Company continued to add customers at more than a 3 percent annual rate, surpassing 600,000 total customers at the end of March 2005;

•

total operating expenses increased $4.5 million, or 9 percent, reflecting a combination of higher operation and maintenance expense, higher revenue-based franchise tax expense, and higher depreciation expense on increased utility plant assets; and

•

higher income tax expense corresponded to the higher taxable income.

During both of the three months ended March 31, 2005 and 2004, the Company paid dividends of 32.5 cents a share of common stock.

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.

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 Part II, Item 7., “Results of Operations – Regulatory Matters – Weather Normalization,” in the 2004 Form 10-K). In the three months ended March 31, 2005, the Company recognized a $3.7 million margin contribution from this mechanism on weather that was 4 percent warmer than normal, as compared to $2.7 million on weather that was 2 percent warmer than normal in the first quarter of 2004 (see “Residential and Commercial Sales,” below).

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. A report on this review is expected to be received from the OPUC sometime during 2005. Currently there is no indication that their findings would have a material impact on the Company’s purchasing strategies or its annual PGA adjustments.

Conservation Tariff. In October 2002, the OPUC authorized NW Natural to implement a “conservation tariff,” a mechanism designed to adjust margin revenues due to changes in residential and commercial customers’ consumption patterns. 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 as higher energy prices drive up their utility bills.

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 revenues or credits to customers resulting from the decoupling adjustment are recorded to a deferral account that is included in the next year’s annual PGA. Baseline consumption is based on customer consumption patterns as determined in the 2003 Oregon general rate case, adjusted for consumption resulting from new customers. 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 and a report was submitted to the OPUC in March 2005. The independent study report recommended continuation of the conservation tariff with minor modifications. In addition, in March 2005 the Company submitted a request to the OPUC to open an investigation to determine whether the conservation tariff should be continued, modified or eliminated. An order from the OPUC on the conservation tariff is expected before Sept. 30, 2005.

Comparison of Gas Distribution Operations

The following table summarizes the composition of gas utility volumes and revenues for the three months ended March 31:


(Thousands, except customers and degree days)	2005				2004
Utility volumes - therms:
Residential and commercial sales		230,683	62	%		242,476	62	%
Industrial sales and transportation		138,487	38	%		145,844	38	%

Total utility volumes sold and delivered		369,170	100	%		388,320	100	%

Utility operating revenues - dollars:
Residential and commercial sales	$	259,008	85	%	$	224,990	89	%
Industrial sales and transportation		42,991	14	%		27,563	11	%
Other revenues		4,687	1	%		45	0	%

Total utility operating revenues	$	306,686	100	%	$	252,598	100	%
Cost of gas sold		180,567				142,400

Utility net operating revenues (margin)	$	126,119			$	110,198

Total number of customers (end of period)		603,330				583,582

Actual degree days		1,769				1,807

Percent colder (warmer) than normal (25-year average degree days is used as normal)		(4%)				(2%)

NW Natural continued to grow its customer base, with a net increase of 19,748 customers since March 31, 2004, for a growth rate of 3.4 percent. In the three years ended Dec. 31, 2004, more than 55,000 customers were added to the system, representing an average annual growth rate of 3.4 percent.

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 patterns, competitive factors in the energy industry and economic conditions in the Company’s service areas.


	Three Months Ended March 31,
(Thousands, except customers)	2005			2004
Utility volumes - therms:
Residential sales		158,931			172,771
Commercial sales		93,349			101,593
Change in unbilled sales		(21,597	)		(31,888	)

Total weather-sensitive utility volumes		230,683			242,476

Utility operating revenues - dollars:
Residential sales	$	189,588		$	168,490
Commercial sales		94,552			84,034
Change in unbilled sales		(25,132	)		(27,534	)

Total weather-sensitive utility revenues	$	259,008		$	224,990

Total number of residential and commercial customers (end of period)		602,388			582,674

First quarter of 2005 compared to first quarter of 2004

The primary factors affecting residential and commercial volumes and operating revenues in the three months ended March 31, 2005 compared to the comparable period in 2004 were:

•

volumes sold were 5 percent lower, reflecting the effect of 2 percent warmer weather that was partially offset by the impact of 3.4 percent customer growth; and

•

operating revenues were 15 percent higher, primarily due to higher rates effective Oct. 1, 2004, reflecting higher gas costs (see Part II, Item 7., “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 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 in Oregon beginning in November 2003. This mechanism applies to meter readings of participating Oregon customers taken between Nov. 15 and May 15. Approximately 10 percent of NW Natural’s residential and commercial customers are in Washington, where the mechanism is not in effect, and about 8 percent of the eligible Oregon customers elected not to be covered by the mechanism, so the mechanism does not fully insulate the Company from utility earnings volatility due to weather. The mechanism contributed a net $3.7 million of margin on weather that was 4 percent warmer than normal in the three month period ended March 31, 2005, compared to $2.7 million on weather that was 2 percent warmer than normal in the first three months of 2004.

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 March 31, 2005, accrued unbilled revenue was $38.9 million, compared to $31.8 million at March 31, 2004.

Industrial Sales and Transportation

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


	Three Months ended March 31,
(Thousands, except customers)	2005		2004
Utility volumes - therms:
Industrial firm sales		21,738		18,510
Industrial interruptible sales		36,318		24,376
Transportation		80,431		102,958

Total utility volumes		138,487		145,844

Utility operating revenues - dollars:
Industrial firm sales	$	17,544	$	12,294
Industrial interruptible sales		22,613		11,974
Transportation		2,834		3,295

Total utility revenues	$	42,991	$	27,563

Total number of industrial sales and transportation customers (end of period)		942		908

Total volumes delivered to industrial sales and transportation customers were 7.4 million therms, or 5 percent, lower in the first quarter of 2005 as compared to the same period in 2004, but utility operating revenues were up $15.4 million, or 45 percent. The lower volumes but higher revenues reflect a significant shift of customers from transportation to sales service and the higher rates due to increased gas costs. The margin contribution from industrial sales and transportation customers increased $1.4 million, or 13 percent, over 2004 due to improvements in the economy and industrial rate design changes implemented as a result of the 2003 Oregon general rate case.

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 $4.7 million in the first quarter of 2005, compared to less than $0.1 million in the first quarter of 2004. The following table summarizes other revenues by primary category for the three months ended March 31:


	Three Months Ended March 31,
(Thousands)	2005			2004
Revenue adjustments:
Current deferrals:
Decoupling	$	4,402		$	1,005
SMPE		81			1,101
Coos County system expansion		605			—
Other		472			(118	)
Current amortizations:
Decoupling		(839	)		(1,554	)
SMPE		(1,069	)		—
Conservation programs		(888	)		(1,390	)
Year 2000 technology costs		(496	)		(572	)
Other		586			192

Net revenue adjustments		2,854			(1,336	)

Miscellaneous revenues:
Customer fees		1,770			1,214
Other		63			167

Total miscellaneous revenues		1,833			1,381

Total other revenues	$	4,687		$	45

Other revenues in the three months ended March 31, 2005 were $4.6 million higher than in the three months ended March 31, 2004 primarily due to the net increase in decoupling deferrals under the conservation mechanism (up $3.4 million) resulting from a larger decrease in consumption than anticipated in 2005, as compared to 2004, by the utility’s residential and commercial customers (see Part II, Item 7., “Regulatory Matters—Rate Mechanisms,” in the 2004 Form 10-K). Also contributing to the increase in other revenues were a lower amortization of decoupling deferrals compared to last year (down $0.7 million), an increase in customer fees (up $ 0.5 million) and a new deferral for the cost of service recovery authorized on the investment in the Coos County system expansion ($0.6 million).

Cost of Gas Sold

The cost per therm of gas sold was 27 percent higher in the first quarter of 2005 than in the first quarter of 2004 reflecting higher natural gas commodity prices. The cost per therm of gas sold includes current gas purchases, gas drawn from storage inventory, financial gains and losses from commodity-price hedges, margin from off-system gas sales, demand cost balancing adjustments (demand cost equalization), regulatory deferrals and company use.

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 recorded net payments of $1.5 million for the settlement of fixed-price hedge contracts, at maturity, in the first three months of 2005, compared to net receipts of $8.0 million during the first three months of 2004. The unrealized net gain on fixed-price forward hedge contracts was $88 million at March 31, 2005, compared to $36 million at March 31, 2004.

Under NW Natural’s PGA tariff in Oregon, net income from Oregon operations is affected within defined limits by changes in purchased gas costs. NW Natural is allowed to collect an amount for purchased gas costs based on estimates that are included in current utility rates. If the actual purchased gas costs are higher than the amounts included in rates, NW Natural is not allowed to charge its customers currently for those higher gas costs but is allowed to defer the costs and collect them in the future. Similarly, when the actual purchased gas costs are lower than the amount included in rates, the savings are not immediately passed on to customers but are deferred and refunded in future periods. NW Natural absorbs 33 percent of the higher cost of gas sold, or retains 33 percent of the lower cost, in either case as compared to the projected costs built into rates. The remaining 67 percent of the higher or lower gas costs is recorded as deferred regulatory assets or liabilities for recovery from or refund to customers in future rates. In the first three months of 2005, NW Natural’s gas costs were lower than the gas costs embedded in rates, with the effect that NW Natural’s share of the lower costs increased margin by $1.8 million. In the same period of 2004, NW Natural’s gas costs were higher than the projected costs built into rates, and the Company’s share of the higher cost decreased margin by $1.0 million.

NW Natural uses gas supplies and transportation capacity to make off-system sales to mitigate system load variations when gas supplies are not required for use by the utility’s residential, commercial and industrial firm customers. 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 first quarter of 2005 resulted in a net gain of $1.2 million, while its share of margin from off-system gas sales in the first quarter of 2004 was a $0.3 million net loss.

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 March 31, 2005, after regulatory sharing and income taxes, of $0.9 million or 3 cents a share. This compares to net income of $0.8 million or 3 cents a share in the three months ended March 31, 2004. A greater percentage of the net revenues in the first quarter 2005 was realized using interstate storage capacity that is not included in the utility’s retail rates, with a corresponding lower percentage of net revenues being derived from third party optimization activities using assets that are included in retail rates.

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 activities using temporarily unused portions of NW Natural’s upstream pipeline transportation capacity and gas storage capacity. In Oregon, NW Natural retains 80 percent of the pre-tax income from interstate storage services and optimization of storage and pipeline transportation capacity when the costs of such capacity have not been included in utility rates, and 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 distribution 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 March 31, 2005 were a negligible loss compared to a net loss of $0.2 million in the first quarter of 2004. In January 2005, Financial Corporation sold its limited partnership interests in three solar electric generation projects, recording a negligible gain in the first quarter of 2005.

The Company’s net investment balances in Financial Corporation at March 31, 2005 and 2004, were $2.8 and $7.7 million, respectively. The lower investment balance reflects the sale of interests in the solar electric generation projects and the dividend paid by Financial Corporation to the parent, NW Natural, in the first quarter of 2005.

Operating Expenses

Operations and Maintenance

Operations and maintenance expenses in first quarter of 2005 were $27.2 million, 7 percent higher than in the first quarter of 2004. The $1.7 million increase was primarily due to higher payroll related expenses resulting from employee additions, pay increases and higher benefit costs ($1.3 million) and an increase in uncollectible accounts expense ($0.2 million) associated with higher operating revenues.

Taxes Other than Income Taxes

Taxes other than income taxes, which are principally comprised of franchise, property and payroll taxes, increased $1.5 million, or 12 percent, in the first quarter of 2005 over the same period in 2004. Franchise taxes, which are based on gross revenues, increased $1.1 million or 18 percent on higher gross revenue due to higher gas costs. Property taxes increased $0.3 million, or 8 percent, due to utility plant additions in 2004 and 2005.

Depreciation and Amortization

The Company’s depreciation and amortization expense increased by $1.3 million, or 9 percent, in the three-month period ended March 31, 2005, compared to the same period in 2004. The increased expense is primarily due to additional investments in utility property that were made to meet continuing customer growth, including the additional investment in SMPE that was put into service in September 2004 (see “Financial Condition—Cash Flows—Investing Activities,” below).

Interest Charges – Net of Amounts Capitalized

Interest charges-net of amounts capitalized in the first quarter of 2005 was $0.2 million, or 2 percent, higher than in the three months ended March 31, 2004. The increase in 2005 was primarily due to higher interest rates on short-term debt outstanding during the period.

Income Taxes

The effective corporate income tax rate from operations was 36.4 percent for each of the three-month periods ended March 31, 2005 and 2004.

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


	March 31,				Dec. 31, 2004
	2005		2004		Dec. 31, 2004
Common stock equity	54.0	%	50.5	%	48.7	%
Long-term debt	43.7	%	47.4	%	41.3	%
Short-term debt, including current maturities of long-term debt	2.3	%	2.1	%	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 March 31, 2005, the Company had $2.7 million of cash and cash equivalents compared to $2.8 million at March 31, 2004 and $5.2 million at Dec. 31, 2004. 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 March as receivables and inventories are converted into cash, which is used to reduce short-term debt.

Capital expenditures primarily relate to 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 (SEC) 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. In April 2004, the Company issued $40 million of common stock under its shelf registration, leaving $160 million remaining available for the issuance of debt or equity securities.

Neither NW Natural’s Mortgage and Deed of Trust nor the indentures under which other long-term debt is issued contain credit rating triggers or stock price provisions that require the acceleration of debt repayment. Also, there are no rating triggers or stock price provisions contained in

contracts or other agreements with third parties, except for agreements with certain counter-parties under NW Natural’s Derivatives Policy which require the affected party to provide substitute collateral such as cash, guaranty or letter of credit if credit ratings are lowered to non-investment grade, or in some cases if the mark-to-market value exceeds a certain threshold.

Based on the availability of short-term credit facilities and the ability to issue long-term debt and equity securities, the Company believes it has sufficient liquidity to satisfy its anticipated 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

Since Dec. 31, 2004, there have been no material changes to the Company’s estimated future contractual obligations other than those entered into in the ordinary course of business during the three months ended March 31, 2005. The Company’s contractual obligations at Dec. 31, 2004 were described in Part II, Item 7., “Financial Condition – Liquidity and Capital Resources – Contractual Obligations,” in the 2004 Form 10-K.

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 also used temporarily to 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 $10.5 million in commercial paper notes outstanding at March 31, 2005, compared to $22.9 million outstanding at March 31, 2004 and $102.5 million outstanding at Dec. 31, 2004. Commercial paper balances are typically lower at the end of the first quarter 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 March 31, 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 March 31, 2005 and at Dec. 31, 2004, and with the equivalent covenants in the prior year’s lines of credit at March 31, 2004.

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 quarter of 2005, net income increased $7.3 million, and non-cash adjustments and changes in operating assets and liabilities increased by $19.0 million.

The following table summarizes cash provided by operating activities for the three-months ended March 31, 2005 and 2004:


	Three Months Ended March 31,
Thousands	2005		2004
Net income	$	39,887	$	32,612
Non-cash adjustments to net income		3,620		17,645
Changes in operating assets and liabilities (working capital sources)		72,408		39,347

Cash provided by operating activities	$	115,915	$	89,604

First quarter of 2005 compared to first quarter of 2004

The overall change in cash flow from operating activities in the first quarter of 2005 compared to the first quarter of 2004 was an increase of $26.3 million. The significant factors contributing to the cash flow changes between periods are as follows:

•

an increase in net income added $7.3 million to cash flow;

•

a decrease in deferred tax expense reduced cash flow by $22.9 million, reflecting higher tax benefits 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 $22.2 million, primarily reflecting withdrawals from storage during the winter heating season;

•

a decrease in regulatory receivables for deferred gas costs increased cash flow by $11.7 million, reflecting different patterns of activity 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 also increased cash flows by $4.9 million, reflecting collections from higher sales during the winter heating season;

•

an increase in accrued unbilled revenue reduced cash flow by $1.8 million due to higher rates;

•

an increase in accrued taxes and interest increased cash flow by $12.3 million primarily due to higher income tax liabilities in the first quarter of 2005 due to the expiration of bonus depreciation;

•

a decrease in accounts payable reduced cash flow by $10.4 million reflecting higher gas prices;

•

a decrease in income taxes receivable increased cash flow by $9.6 million; and

•

an increase in prepayments and other current assets reduced cash flow by $3.5 million.

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

Investing Activities

Cash requirements for investing activities in the first three months of 2005 totaled $17.2 million, down from $23.0 million in the same period of 2004. Cash requirements for the acquisition and construction of utility plant totaled $20.7 million, down from $22.5 million in 2004. The decrease in cash requirements for utility construction in the first three months of 2005 was primarily the result of the completion of NW Natural’s SMPE project. The SMPE project, which extended the pipeline from the Mist gas storage field to serve growing portions of NW Natural’s service area, was completed and placed into service in September 2004. The total cost of the project was approximately $110 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 in the fourth quarter of 2004.

Investments in non-utility property during the first three months of 2005 totaled $0.2 million, down from $0.5 million during the first three months of 2004.

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 three months of 2005 totaled $101.2 million, up from $68.6 million in the same period of 2004. Factors contributing to the $32.7 million increase were primarily related to the repayment of short-term debt in the first quarter of 2005 ($29.7 million) compared to the same period in 2004, combined with common stock repurchases during the first quarter of 2005 ($2.9 million).

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 80,500 shares in the first quarter of 2005 at a cost of $2.9 million. No shares were purchased in 2004. Since the program’s inception the Company has repurchased 435,900 shares of common stock at a total cost of $11.1 million.

Ratios of Earnings to Fixed Charges

For the three months and 12 months ended March 31, 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 7.42, 3.30 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 first seek to recover the costs of investigation and remediation for which it may be responsible with respect to environmental matters, if any, from insurance. If these costs are not recovered from insurance, then NW Natural will seek recovery through future rates subject to approval by the OPUC. At March 31,2005, NW Natural had a $9.2 million receivable representing an estimate of the environmental costs it expects to incur and 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 March 31, 2005, the Company paid out a total of $3.5 million relating to the 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, the WUTC and the U.S. Department of Transportation’s Office of Pipeline Safety, 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, the maintenance of pipeline integrity, 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;

•

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;

•

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.

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 March 31, 2005 is an unrealized loss of $8.5 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 exemption 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 March 31, 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.

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.

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 March 31, 2005 of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES


	(a)	(b)		(c)	(d)
Period	Total Number of Shares Purchased ⁽¹⁾	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ⁽²⁾	Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs ⁽²⁾
Balance forward				355,400	$	26,800,000
01/01/05- 01/31/05	237	$	33.42	—		—

02/01/05- 02/28/05	16,724	$	37.08	—		—

03/01/05- 03/31/05	—		—	80,500		(2,891,415	)

Total	16,961	$	37.03	435,900	$	23,908,585

⁽¹⁾	During the three months ended March 31, 2005, the Company accepted 16,961 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 pursuant to 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 435,900 shares of common stock at a total cost of $11.1 million. On April 28, 2005, NW Natural’s Board of Directors extended the program through May 31, 2006.

Item 5.

OTHER INFORMATION.

Appointment to Organization and Executive Compensation Committee

On April 28, 2005, the Company’s Board of Directors appointed Kenneth Thrasher a member of the Board’s Organization and Executive Compensation Committee. The Board has affirmatively determined that Mr. Thrasher qualifies as an independent director in accordance with the New York Stock Exchange listing standards and the Company’s Director Independence Standards. Mr. Thrasher, who is Chairman and Chief Executive Officer of Compli Corporation, a software solution provider for management of compliance in employment practices and corporate governance, was elected to the Board on February 25, 2005 for a term ending at the Company’s 2005 Annual Meeting of Shareholders and was nominated for election by the shareholders as a Class II director for a two-year term ending in 2007. The Board also appointed Mr. Thrasher to serve as a member of the Board’s Public Affairs and Environmental Policy Committee.

Item 6.

EXHIBITS

See Exhibit Index attached hereto.

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: May 4, 2005				/s/ Stephen P. Feltz
				Stephen P. Feltz
				Principal Accounting Officer
				Treasurer and Controller

NORTHWEST NATURAL GAS COMPANY

EXHIBIT INDEX

Quarterly Report on Form 10-Q

For Quarter Ended

March 31, 2005


Document		Exhibit Number

Statement re: Computation of Per Share Earnings		11

Computation of Ratio of Earnings to Fixed Charges		12

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

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

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

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