Edgar Filing: NORTHWEST NATURAL GAS CO

form10q-2009.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2009

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

For the Transition period from _______ to _______

Commission File No. 1-15973

NORTHWEST NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)


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

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

(Address of principal executive offices) (Zip Code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [ ] No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer [ X ]	Accelerated filer [ ]
Non-accelerated filer [ ]	Smaller reporting company [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ]No [ X ]

At April 30, 2009, 26,504,188 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

NORTHWEST NATURAL GAS COMPANY

For the Quarterly Period Ended March 31, 2009

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

Item 1.	Consolidated Financial Statements:

	Consolidated Statements of Income for the three months ended March 31, 2009 and 2008	3

	Consolidated Balance Sheets at March 31, 2009 and 2008 and December 31, 2008	4

	Consolidated Statements of Cash Flows for the three months ended March 31, 2009 and 2008	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	37

Item 4.	Controls and Procedures	38

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	39

Item 1A.	Risk Factors	39

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 6.	Exhibits	39

	Signature	40

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Forward-Looking Statements

Statements and information included in this report that are not purely historical are forward-looking statements within the “safe harbor” provisions and meaning of Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). Forward-looking statements include any statement other than a statement of purely historical fact, but are not limited to, statements concerning plans, objectives, goals, business and financial strategies, future events or performance or operational efficiencies, trends, cyclicality and the seasonality of our business, growth, capitalization, company ratings, development of projects, future cost of gas or our ability to manage such costs, gains or losses from our share of gas costs that are less than or more than the gas costs embedded in customer rates, exploration of new gas supplies, estimated expenditures, budgets, capital and construction costs, and future cash flows, costs of compliance, impact of accounting policies and standards, potential efficiencies, impacts of new laws and regulations, projected obligations and liabilities under retirement plans, adequacy of and shift in mix of gas supplies, and adequacy of accruals and regulatory deferrals. Such statements are expressed in good faith and we believe have a reasonable basis; however, each forward-looking statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause our actual results to differ materially from those projected, including:

prevailing state and federal governmental policies and regulatory actions with respect to allowed rates of return, industry and rate structure, timely and adequate regulatory recovery of deferred costs, including, but not limited to, purchased gas cost and investment recovery, acquisitions and dispositions of assets and facilities, operation and construction of plant facilities, present or prospective wholesale and retail competition, changes in laws and regulations including but not limited to tax laws and policies, changes in and compliance with environmental and safety laws, regulations, policies and orders, and laws, regulations and orders with respect to the maintenance of pipeline integrity, including regulatory allowance or disallowance of costs based on regulatory prudency reviews;

·	economic factors that could cause a severe downturn in the national economy, in particular the economies of Oregon and Washington, thus affecting demand for natural gas;

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

·	the creditworthiness of customers, suppliers and financial derivative counterparties;

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

·	sufficiency of our liquidity position and unanticipated changes that may affect our liquidity or access to capital markets, including volatility in the credit environment and financial services sector;

·	capital market conditions, including their effect on financing costs, the fair value of pension assets and on pension and other postretirement benefit costs;

·	application of the Oregon Public Utility Commission rules interpreting Oregon legislation intended to ensure that utilities do not collect more income taxes in rates than they actually pay to government entities;

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

·	competition for retail and wholesale customers and our ability to remain price competitive;

·	our ability to access sufficient gas supplies and our dependence on a single pipeline transportation company for natural gas transmission;

·	property damage associated with a pipeline safety incident, as well as risks resulting from uninsured damage to our property, intentional or otherwise;

·	financial and operational risks , estimates and projections relating to business development and investment activities, including the Gill Ranch underground gas storage facility and Palomar pipeline;

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

·	changes in estimates of potential liabilities relating to environmental contingencies or in timely and adequate regulatory or insurance recovery for such liabilities;

·	unanticipated changes in future liabilities and legislation relating to employee benefit plans, including changes in key assumptions;

·	our ability to transfer knowledge of our aging workforce and maintain a satisfactory relationship with the union that represents a majority of our workers;

·	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 the timing of such projects;

·	federal, state or other regulatory actions related to climate change; and

·	legal and administrative proceedings and settlements.

These forward-looking statements involve risks and uncertainties. We may make other forward-looking statements from time to time, including statements in press releases and public conference calls and webcasts. All forward-looking statements made by us are based on information available to us at the time the statements are made and speak only as of the date on which such statement is made. We undertake 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 us to predict all such factors, nor can we 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. Some of these risks and uncertainties are discussed in our 2008 Annual Report on Form 10-K, Part I, Item 1A., “Risk Factors” and Part II, Item 7. and Item 7A., “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk,” respectively.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Income

(Unaudited)

	Three Months Ended
	March 31,
Thousands, except per share amounts	2009		2008
Operating revenues:
Gross operating revenues	$	437,355	$	387,694
Less: Cost of sales		284,174		245,920
Revenue taxes		10,542		9,351
Net operating revenues		142,639		132,423
Operating expenses:
Operations and maintenance		33,955		28,458
General taxes		8,491		8,134
Depreciation and amortization		15,522		17,705
Total operating expenses		57,968		54,297
Income from operations		84,671		78,126
Other income and expense - net		890		173
Interest charges - net of amounts capitalized		9,370		9,430
Income before income taxes		76,191		68,869
Income tax expense		28,828		25,701
Net income	$	47,363	$	43,168
Average common shares outstanding:
Basic		26,501		26,409
Diluted		26,597		26,560
Earnings per share of common stock:
Basic	$	1.79	$	1.63
Diluted	$	1.78	$	1.63

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets

(Unaudited)

	March 31,			March 31,			Dec. 31,
Thousands	2009			2008			2008
Assets:
Plant and property:
Utility plant	$	2,158,946		$	2,071,072		$	2,142,988
Less accumulated depreciation		663,417			627,265			659,123
Utility plant - net		1,495,529			1,443,807			1,483,865
Non-utility property		80,689			68,815			74,506
Less accumulated depreciation		9,665			8,261			9,314
Non-utility property - net		71,024			60,554			65,192
Total plant and property		1,566,553			1,504,361			1,549,057

Current assets:
Cash and cash equivalents		10,341			6,417			6,916
Accounts receivable		99,985			82,775			81,288
Accrued unbilled revenue		61,034			56,025			102,688
Allowance for uncollectible accounts		(4,948	)		(4,066	)		(2,927	)
Regulatory assets		124,085			6,288			147,319
Fair value of non-trading derivatives		4,798			34,175			4,592
Inventories:
Gas		82,182			25,663			86,134
Materials and supplies		9,846			8,834			9,933
Income taxes receivable		1,804			-			20,811
Prepayments and other current assets		26,339			20,652			24,216
Total current assets		415,466			236,763			480,970

Investments, deferred charges and other assets:
Regulatory assets		284,166			179,173			288,470
Fair value of non-trading derivatives		189			1,227			146
Other investments		68,302			56,164			54,132
Other		17,691			10,601			5,377
Total investments, deferred charges and other assets		370,348			247,165			348,125
Total assets	$	2,352,367		$	1,988,289		$	2,378,152

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Balance Sheets

(Unaudited)


	March 31,			March 31,			Dec. 31,
Thousands	2009			2008			2008
Capitalization and liabilities:
Capitalization:
Common stock	$	335,261		$	332,182		$	336,754
Earnings invested in the business		332,900			299,923			296,005
Accumulated other comprehensive income (loss)		(4,323	)		(2,840	)		(4,386	)
Total common stock equity		663,838			629,265			628,373
Long-term debt		587,000			512,000			512,000
Total capitalization		1,250,838			1,141,265			1,140,373

Current liabilities:
Notes payable		88,600			54,600			248,000
Long-term debt due within one year		-			5,000			-
Accounts payable		93,304			93,061			94,422
Taxes accrued		14,224			23,160			12,455
Interest accrued		11,215			11,287			2,785
Regulatory liabilities		46,475			88,197			20,456
Fair value of non-trading derivatives		107,461			1,703			136,735
Other current and accrued liabilities		41,414			34,970			36,467
Total current liabilities		402,693			311,978			551,320

Deferred credits and other liabilities:
Deferred income taxes and investment tax credits		267,827			221,670			257,831
Regulatory liabilities		239,561			220,137			228,157
Pension and other postretirement benefit liabilities		140,318			42,709			138,229
Fair value of non-trading derivatives		15,387			4,995			21,646
Other		35,743			45,535			40,596
Total deferred credits and other liabilities		698,836			535,046			686,459
Commitments and contingencies (see Note 11)		-			-			-
Total capitalization and liabilities	$	2,352,367		$	1,988,289		$	2,378,152

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended
	March 31,
Thousands	2009			2008
Operating activities:
Net income	$	47,363		$	43,168
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		15,522			17,705
Deferred income taxes and investment tax credits		9,848			14,432
Undistributed gains from equity investments		(288	)		(25	)
Deferred gas savings - net		33,974			3,740
Non-cash expenses related to qualified defined benefit pension plans		2,490			780
Deferred environmental costs		(2,669	)		(2,048	)
Income from life insurance investments		(1,081	)		(459	)
Settlement of interest rate hedge		(10,096	)		-
Deferred regulatory and other		(15,020	)		(13,679	)
Changes in working capital:
Accounts receivable and accrued unbilled revenue - net		25,837			9,822
Inventories of gas, materials and supplies		4,039			45,447
Income taxes receivable		19,007			-
Prepayments and other current assets		3,677			4,917
Accounts payable		(928	)		(28,409	)
Accrued interest and taxes		10,199			18,483
Other current and accrued liabilities		5,013			5,405
Cash provided by operating activities		146,887			119,279
Investing activities:
Investment in utility plant		(21,641	)		(19,263	)
Investment in non-utility property		(6,171	)		(1,682	)
Proceeds from life insurance		120			-
Contributions to non-utility investments		(900	)		(1,500	)
Other		(5,483	)		(63	)
Cash used in investing activities		(34,075	)		(22,508	)
Financing activities:
Common stock issued (purchased) - net		(1,184	)		1,874
Long-term debt issued		75,000			-
Change in short-term debt		(172,251	)		(88,500	)
Cash dividend payments on common stock		(10,468	)		(9,903	)
Other		(484	)		68
Cash used in financing activities		(109,387	)		(96,461	)
Increase in cash and cash equivalents		3,425			310
Cash and cash equivalents - beginning of period		6,916			6,107
Cash and cash equivalents - end of period	$	10,341		$	6,417

Supplemental disclosure of cash flow information:
Interest paid	$	816		$	1,017
Income taxes paid	$	-		$	350

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

Notes to Consolidated Financial Statements

(Unaudited)

1.	Basis of Financial Statements and Accounting Policies

The consolidated financial statements include the accounts of Northwest Natural Gas Company (NW Natural), which consist of our regulated gas distribution business, our regulated gas storage businesses, which includes our wholly-owned subsidiary Gill Ranch Storage, LLC (Gill Ranch), and other investments and business activities, which includes our wholly-owned subsidiary NNG Financial Corporation (Financial Corporation) and an equity investment in a proposed natural gas transmission pipeline (Palomar) (see Note 2).

In this report, the term “utility” is used to describe the gas distribution business and the term “non-utility” is used to describe the gas storage businesses and other non-utility investments and business activities. Intercompany accounts and transactions have been eliminated, except for transactions required by regulatory accounting not to be eliminated under Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.”

The information presented in the interim consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that management considers necessary for a fair statement of the results for each period reported. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2008 Annual Report on Form 10-K (2008 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.

Investments in corporate joint ventures and partnerships in which our ownership interest is 50 percent or less and over which we do not exercise control are accounted for by the equity method or the cost method.

Our accounting policies are described in Note 1 of the 2008 Form 10-K. There were no significant changes to those accounting policies during the three months ended March 31, 2009. See below for a further discussion of newly adopted standards and recent accounting pronouncements.

Newly Adopted Standards

Business Combinations. Effective January 1, 2009, we adopted SFAS No. 141R, “Business Combinations.” This statement amends the principles and requirements for how an acquiror accounts for and discloses its business combinations. The adoption of SFAS No. 141R did not have a material effect on our financial condition, results of operations or cash flows.

Noncontrolling Interests. Effective January 1, 2009, we adopted SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This statement amends the reporting requirements of Accounting Research Bulletin No. 51 for noncontrolling interests in subsidiaries to improve the relevance, comparability and transparency of the financial information disclosed. The adoption of SFAS No. 160 did not have a material effect on our financial condition, results of operations or cash flows.

Derivative Instruments and Hedging Activities. Effective January 1, 2009, we adopted SFAS No. 161, “Accounting for Derivative Instruments and Hedging Activities,” which requires enhanced disclosures of derivative instruments and hedging activities. SFAS No. 161 expands disclosures by adding qualitative disclosures about our hedging objectives and strategies, fair value gains and losses, and credit-risk-related contingent features in derivative agreements. The disclosures are intended to provide an enhanced understanding of:

·	how and why we use derivative instruments;

·	how derivative instruments and related hedge items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and its related interpretations; and

·	how derivative instruments and related hedged items affect our financial condition, results of operations and cash flows.

The adoption and implementation of this statement did not have, and is not expected to have a material effect on our financial statement disclosures. The required disclosures are included in Note 10, below.

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Determining Whether Share-Based Payment Transactions are Participating Securities. Effective January 1, 2009, we adopted FASB Staff Position (FSP) No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities.” This statement requires nonforfeitable rights to dividends or dividend equivalents on unvested share-awards to be included in the computation of earnings per share under the two-class method. The adoption of FSP No. EITF 03-6-1 did not have, and is not expected to have, a material effect on our financial condition, results of operations or cash flows.

Recent Accounting Pronouncements

Pensions. In December 2008, the FASB issued SFAS No. 132R-1, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” which requires enhanced disclosures of plan assets in an employer’s defined benefit pension or other postretirement benefit plan. SFAS No. 132R-1 is effective for reporting periods ending after December 15, 2009. The disclosures are intended to provide an enhanced understanding of:

·	how investment allocation decisions are made;
·	the major categories of plan assets;

·	the inputs and valuation techniques used to measure the fair value of plan assets;

·	the effect of fair value measurements using significant unobservable inputs (Level 3 input from SFAS No. 157, “Fair Value Measurements”) on changes in plan assets for the period; and

·	significant concentration or risk within plan assets.

The adoption of SFAS No. 132R-1 is not expected to have a material effect on our financial statement disclosures.

Interim Disclosures about Financial Instruments. In April 2009, the FASB issued FSP SFAS No. 107-1 and Accounting Principles Board (APB) No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This statement requires disclosures about the fair value of financial instruments to be made in interim reporting periods where summarized financial information is issued. FSP SFAS No. 107-1 and APB No. 28-1 will be effective for interim reporting periods ending after June 15, 2009. The adoption of this statement is not expected to have a material effect on our disclosures.

Fair Value Considerations. In April 2009, the FASB issued FSP SFAS No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” This pronouncement provides an outline and required disclosures, if necessary, to determine if the market for measuring our financial instruments has significantly decreased in volume and level of activity. FSP SFAS No. 157-4 is effective for interim and annual reporting periods ending after June 15, 2009. The adoption of this statement is not expected to have a material effect on our financial condition, results of operations or cash flows.

2.	Segment Information

We operate in two primary reportable business segments, local gas distribution and gas storage. We also have other investments and business activities not specifically related to either of these two reporting segments which we aggregate and report as “other.” We refer to our local gas distribution business as the “utility,” and our “gas storage” and “other” business segments as “non-utility.” Our gas storage segment includes Gill Ranch and a portion of the Mist underground storage facility, and our “other” segment includes an equity investment in Palomar and our Financial Corporation subsidiary.

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The following table presents information about the reportable segments. Inter-segment transactions are insignificant.

	Three Months Ended March 31,
Thousands	Utility		Gas Storage		Other		Total
2009
Net operating revenues	$	138,094	$	4,500	$	45	$	142,639
Depreciation and amortization		15,183		339		-		15,522
Income from operations		80,894		3,745		32		84,671
Net income		45,304		2,032		27		47,363
Total assets at March 31, 2009	$	2,244,899	$	88,991	$	18,477	$	2,352,367
2008
Net operating revenues	$	127,379	$	4,997	$	47	$	132,423
Depreciation and amortization		17,379		326		-		17,705
Income from operations		73,877		3,843		406		78,126
Net income		40,542		2,353		273		43,168
Total assets at March 31, 2008		1,908,870		65,969		13,450		1,988,289
Total assets at December 31, 2008	$	2,289,601	$	72,073	$	16,478	$	2,378,152

Included in total assets at March 31, 2009 and 2008, our major non-utility investments were as follows:

·	Mist gas storage (excluding utility) was $56.0 million and $56.2 million, respectively;
·	Gill Ranch was $19.0 million and $0.1 million, respectively;

·	Palomar was $15.5 million and $7.6 million, respectively;

·	Financial Corporation was $1.0 million and $1.1 million, respectively; and
·	Investment in Boeing 737 (leveraged lease) was $0.0 million and $3.6 million, respectively, as it was sold in April 2008.

In March 2009, Gill Ranch entered into a $40 million cash collateralized credit facility that expires on September 30, 2009. As of March 31, 2009, Gill Ranch had borrowed loan proceeds of $5.8 million with an effective interest rate of LIBOR plus 50 basis points.

Palomar had executed precedent agreements whereby a significant majority of the pipeline capacity was committed to one shipper. In April 2009, Palomar and that shipper replaced their existing precedent agreement with a new agreement for the same amount of capacity and Palomar received cash proceeds which had supported the shipper's obligations under the prior agreement. Our maximum loss exposure related to Palomar at March 31, 2009 would be limited to our investment balance of $15.5 million less any commitments or credit support from third parties.

3.	Capital Stock

As of March 31, 2009, common shares authorized were 100,000,000 and outstanding were 26,504,188.

We have a share repurchase program for our common stock under which we purchase shares on the open market or through privately negotiated transactions. Since inception of the repurchase program in 2000, the Board has authorized repurchases through May 31, 2010 up to an aggregate 2.8 million shares or $100 million. No shares were repurchased under this program during the three months ended March 31, 2009. To date, a total of 2.1 million shares or $83.3 million have been repurchased.

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4.	Stock-Based Compensation

Our stock-based compensation plans consist of the Long-Term Incentive Plan (LTIP), the Restated Stock Option Plan (Restated SOP) and the Employee Stock Purchase Plan (ESPP). These plans are designed to promote stock ownership by employees and officers. For additional information on our stock-based compensation plans, see Part II, Item 8., Note 4, in the 2008 Form 10-K and current updates provided below.

Long-Term Incentive Plan. On February 25, 2009, 39,000 performance-based shares were granted under the LTIP based on target-level awards, which include a market condition, with a weighted-average grant date fair value of $9.59 per share. Fair value was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following weighted-average assumptions:


Stock price on valuation date		$41.15
Performance term (in years)		3.0
Quarterly dividends paid per share		$0.395
Expected dividend yield		3.8%
Dividend discount factor		0.8927

In February 2009, the Board approved the payout of our 2006-08 performance-based stock awards. Shares were purchased on the open market to satisfy the approved awards.

Restated Stock Option Plan. On February 25, 2009, options to purchase 111,750 shares were granted under the Restated SOP, with an exercise price equal to the closing market price of $41.15 per share on the date of grant, vesting over a four-year period following the date of grant and with a term of 10 years and 7 days. The weighted-average grant date fair value was $5.46 per share. Fair value was estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted-average assumptions:


Risk-free interest rate		2.0%
Expected life (in years)		4.7
Expected market price volatility factor		22.5%
Expected dividend yield		3.8%
Forfeiture rate		3.7%

As of March 31, 2009, there was $1.1 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards expected to be recognized over a period extending through 2012.

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5.	Long-Term Debt

On March 25, 2009, we issued $75 million of 5.37 percent secured medium-term notes (MTNs) due February 1, 2020. Proceeds from these MTNs were used to redeem short-term debt of the utility and for general corporate purposes, including funding utility capital expenditures and working capital needs.

At March 31, 2009 and 2008 and December 31, 2008, we had outstanding long-term debt as follows:

	March 31,		March 31,
	2009		2008		Dec. 31,
Thousands	(Unaudited)		(Unaudited)		2008
Medium-Term Notes
First Mortgage Bonds:
6.50 % Series B due 2008(1)	$	-	$	5,000	$	-
4.11 % Series B due 2010		10,000		10,000		10,000
7.45 % Series B due 2010		25,000		25,000		25,000
6.665% Series B due 2011		10,000		10,000		10,000
7.13 % Series B due 2012		40,000		40,000		40,000
8.26 % Series B due 2014		10,000		10,000		10,000
4.70 % Series B due 2015		40,000		40,000		40,000
5.15 % Series B due 2016		25,000		25,000		25,000
7.00 % Series B due 2017		40,000		40,000		40,000
6.60 % Series B due 2018		22,000		22,000		22,000
8.31 % Series B due 2019		10,000		10,000		10,000
7.63 % Series B due 2019		20,000		20,000		20,000
5.37 % Series B due 2020(2)		75,000		-		-
9.05 % Series A due 2021		10,000		10,000		10,000
5.62 % Series B due 2023		40,000		40,000		40,000
7.72 % Series B due 2025		20,000		20,000		20,000
6.52 % Series B due 2025		10,000		10,000		10,000
7.05 % Series B due 2026		20,000		20,000		20,000
7.00 % Series B due 2027		20,000		20,000		20,000
6.65 % Series B due 2027		20,000		20,000		20,000
6.65 % Series B due 2028		10,000		10,000		10,000
7.74 % Series B due 2030		20,000		20,000		20,000
7.85 % Series B due 2030		10,000		10,000		10,000
5.82 % Series B due 2032		30,000		30,000		30,000
5.66 % Series B due 2033		40,000		40,000		40,000
5.25 % Series B due 2035		10,000		10,000		10,000
		587,000		517,000		512,000
Less long-term debt due within one year		-		5,000		-
Total long-term debt	$	587,000	$	512,000	$	512,000

(1)	Redeemed at maturity in July 2008.

(2)	Issued on March 25, 2009.

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6.	Earnings Per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during each period presented. The diluted earnings per share calculation includes common shares outstanding and the potential effects of the assumed exercise of stock options outstanding and estimated stock awards from our other stock-based compensation plans. Diluted earnings per share are calculated as follows:

	Three Months Ended
	March 31,
Thousands, except per share amounts	2009		2008
Net income	$	47,363	$	43,168
Average common shares outstanding - basic		26,501		26,409
Additional shares for stock-based compensation plans		96		151
Average common shares outstanding - diluted		26,597		26,560
Earnings per share of common stock - basic	$	1.79	$	1.63
Earnings per share of common stock - diluted	$	1.78	$	1.63

For the three months ended March 31, 2009 and 2008, 6,891 and 1,765 common shares, respectively, were excluded from the calculation of diluted earnings per share because the effect of these additional shares for both periods would have been anti-dilutive.

7.	Pension and Other Postretirement Benefits

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

							Other Postretirement
	Pension Benefits						Benefits
	Three Months Ended March 31,
Thousands	2009			2008			2009			2008
Service cost	$	1,663		$	1,655		$	147		$	133
Interest cost		4,492			4,301			406			349
Expected return on plan assets		(3,995	)		(4,777	)		-			-
Amortization of loss		1,659			96			4			-
Amortization of prior service cost		306			314			49			49
Amortization of transition obligation		-			-			103			103
Net periodic benefit cost		4,125			1,589			709			634
Amount allocated to construction		(1,178	)		(379	)		(232	)		(207	)
Net amount charged to expense	$	2,947		$	1,210		$	477		$	427

See Part II, Item 8., Note 7, in the 2008 Form 10-K for more information about our pension and other postretirement benefit plans.

In addition to the company-sponsored defined benefit plans referred to above, we contribute to a multiemployer pension plan for our bargaining unit employees in accordance with our collective bargaining agreement. This plan, the Western States Office and Professional Employees Pension Fund (Western States Plan), is managed by a Board of Trustees that includes representatives from participating employers and labor unions. Contribution rates are established by collective bargaining and benefit levels are set by the Board of Trustees based on the advice of an independent actuary regarding the level of benefits that agreed-upon contributions can be expected to support. As of March 31, 2009, the Western States Plan had an accumulated funding deficiency (i.e., a failure to satisfy the minimum funding requirements) for the current plan year and was declared to be in “critical status.” Federal law requires pension plans in critical status to adopt a rehabilitation plan designed to restore the financial health of the plan. Rehabilitation plans may specify benefit reductions, contribution surcharges, or a combination of the two. Our total contribution to the Western States Plan in 2008 amounted to $0.4 million. We expect the Board of Trustees to impose a 5 percent surcharge to participating employers in 2009 and a 10 percent contribution surcharge for years thereafter, and also reduce benefit rates and adjustable benefits for active employee participants as part of its rehabilitation plan to improve funding status of the plan. It is uncertain as to whether other actions will be necessary, including when higher surcharges may be imposed on participating employers or whether we may withdraw from the plan subject to consent from NW Natural's bargaining unit employees. As we have no current intent to withdraw from the plan, we have not recorded a withdrawal liability.

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Employer Contributions

We make contributions periodically to our single-employer qualified defined benefit pension plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. In April 2009, we made an aggregate $25 million cash contribution for the 2008 plan year. In addition, we made cash contributions for our unfunded, non-qualified pension plans and other postretirement benefit plans in the form of ongoing benefit payments of $0.7 million and $0.6 million during the three months ended March 31, 2009 and 2008, respectively. We also made contributions totaling $0.1 million to the Western States Plan for both the three months ended March 31, 2009 and 2008. For more information see Part II, Item 8., Note 7, in the 2008 Form 10-K.

8.	Comprehensive Income

Items that are excluded from net income and charged directly to common stock equity are included in accumulated other comprehensive income (loss), net of tax. The amount of accumulated other comprehensive loss in common stock equity is $4.3 million, $2.8 million and $4.4 million at March 31, 2009 and 2008 and December 31, 2008, respectively, which is related to employee benefit plan liabilities and unrealized gains or losses from derivatives not included under regulatory assets and liabilities (see Note 10, below). The following table provides a reconciliation of net income to total comprehensive income for the three months ended March 31, 2009 and 2008.

	Three Months Ended
	March 31,
Thousands	2009		2008
Net income	$	47,363	$	43,168
Amortization of employee benefit plan liability, net of tax		63		55
Change in unrealized loss from derivatives, net of tax		-		604
Total comprehensive income	$	47,426	$	43,827

9.	Fair Value of Financial Instruments

We use fair value measurements to record adjustments to certain financial instruments and to determine fair value disclosures. As of March 31, 2009 and 2008 and December 31, 2008, we recorded our derivatives at fair value according to SFAS No. 157.

In accordance with SFAS No. 157, we use the following fair value hierarchy for determining our derivative fair value measurements:

·	Level 1: Valuation is based upon quoted prices for identical instruments traded in active markets;

·	Level 2: Valuation is based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-based valuation techniques for which all significant assumptions are observable in the market; and

·	Level 3: Valuation is generated from model-based techniques that use significant assumptions not observable in the market. These unobservable assumptions reflect our own estimates of assumptions market participants would use in valuing the asset or liability.

When developing fair value measurements, it is our policy to use quoted market prices whenever available, or to maximize the use of observable inputs and minimize the use of unobservable inputs when quoted market prices are not available. Derivative contracts outstanding at March 31, 2009 and 2008 and December 31, 2008 were measured at fair value using models or other market accepted valuation methodologies derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (a) quoted future prices for commodities; (b) forward currency prices; (c) time value; (d) volatility factors; (e) current market and contractual prices for underlying instruments; (f) market interest rates and yield curves; and (g) credit spreads, as well as other relevant economic measures.

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In accordance with SFAS No. 157, we include nonperformance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. Our assessment of nonperformance risk is generally derived from the credit default swap market or from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at March 31, 2009 and 2008 and December 31, 2008.

The following table provides the fair value measurements for our derivative assets and liabilities as of March 31, 2009 and 2008 and December 31, 2008 in accordance with the fair value hierarchy under SFAS No. 157:


		March 31,			March 31,		Dec. 31,
Thousands	Description of Derivative Inputs	2009			2008		2008
Level 1	Quoted prices in active markets	$	-		$	-	$	-
Level 2	Significant other observable inputs		(117,861	)		28,704		(153,643	)
Level 3	Significant unobservable inputs		-			-		-
		$	(117,861	)	$	28,704	$	(153,643	)

10.	Derivatives Instruments

We enter into forward contracts and other related financial transactions that qualify as derivative instruments under SFAS No. 133, “Accounting for Derivatives,” as amended by SFAS No. 138 and SFAS No. 149 (collectively referred to as SFAS No. 133). We utilize derivative financial instruments primarily to manage commodity prices related to natural gas supply requirements and interest rates related to existing or anticipated debt issuances.

As in the prior two gas years, our strategy entering the 2008-09 gas year (November 1, 2008 – October 31, 2009) was to hedge up to a targeted hedge level of approximately 75 percent of our normal weather anticipated year round sales volumes. We do most of our hedging for the upcoming gas year prior to the start of that gas year and include the hedge prices in our annual purchased gas adjustment filing.

The financially hedged volumes outstanding at March 31, 2009 totaled 391 million therms. These amounts include hedged volumes for the current and next gas year. At March 31, 2009, we were approximately 60 to 70 percent hedged for the remainder of the 2008-09 gas year and approximately 30 percent financially hedged for the 2009-10 gas year based on normal weather anticipated sales volumes.

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In accordance with SFAS No. 161, the following table discloses the amounts and balance sheet presentation of our derivative instruments as of March 31, 2009 and 2008 and December 31, 2008:

	Fair Value of Derivative Instruments
Thousands	Mar. 31, 2009				Mar. 31, 2008				Dec. 31, 2008
	Current		Non-Current		Current		Non-Current		Current		Non-Current
Assets (1)
Commodity contracts	$	4,798	$	189	$	34,175	$	1,227	$	4,592	$	146
Total	$	4,798	$	189	$	34,175	$	1,227	$	4,592	$	146
Liabilities (2)
Commodity contracts	$	107,307	$	15,387	$	1,595	$	1,383	$	136,290	$	9,734
Interest rate contracts		-		-		-		3,613		-		11,912
Foreign exchange contracts		154		-		108		-		445		-
Total	$	107,461	$	15,387	$	1,703	$	4,996	$	136,735	$	21,646

(1)	The unrealized fair value gains are classified under current- or non-current assets as fair value of non-trading derivatives.

(2)	The unrealized fair value losses are classified under current- or non-current liabilities as fair value of non-trading derivatives.

In accordance with SFAS No. 161, the following table discloses the amounts and income statement presentation of our derivative instruments. It also illustrates that all fair value measurements are related to regulated utility operations and are deferred to balance sheet accounts in accordance with regulatory accounting under SFAS No. 71 for the three months ended March 31, 2009 and 2008.

	Unrealized Gains (Losses) from Derivative Instruments for the three months ended
	March 31, 2009						March 31, 2008
Thousands	Commodity contracts (1)			Foreign exchange contracts (3)			Commodity contracts (1)			Interest rate contracts (2)			Foreign exchange contracts (3)
Cost of sales	$	(117,707	)	$	-		$	32,425		$	-		$	-
Other comprehensive income		-			(154	)		(564	)		(3,613	)		(108	)
Less:
Amounts deferred to regulatory accounts on balance sheet		117,707			154			(31,861	)		3,613			108
Total impact on earnings	$	-		$	-		$	-		$	-		$	-

(1)	Unrealized gain (loss) from commodity hedge contracts is recorded in cost of sales and reclassified to regulatory deferral accounts on the balance sheet in accordance with SFAS No. 71.

(2)	Unrealized gain (loss) from interest rate hedge contracts is recorded in other comprehensive income ( loss ) and reclassified to regulatory deferral accounts on the balance sheet in accordance with SFAS No. 71.

(3)	Unrealized gain (loss) from foreign exchange hedge contracts is recorded in other comprehensive income, and reclassified to regulatory deferral accounts on the balance sheet in accordance with SFAS No. 71.

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In accordance with SFAS No. 161, the gross derivative liability excludes the netting of collateral. We had no collateral posted during the quarter or at the end of the quarter with our derivative counterparties. We calculate our potential exposure to collateral calls by our counterparties to manage our liquidity risk. Based on our current credit rating, most counterparties give us credit limits that range from $15 million to $25 million before we become obligated to post collateral. We measure our collateral call exposure as contractually required under collateral support agreements. To be conservative, we also measure our collateral call exposure with calls for adequate assurance, which is not specific as to amount of credit limit allowed, but could potentially arise if we were to be exposed to a material adverse change. The fair value associated with the amounts in the table below is a $116.3 million unrealized loss. The following table discloses the estimates of potential collateral calls with and without adequate assurance calls, using outstanding derivative instruments at March 31, 2009, based on current gas prices and with various credit rating scenarios for NW Natural.

Thousands	Current Ratings A+/A3			BBB+/Baa1			BBB/Baa2			BBB-/Baa3			Speculative
With Adequate Assurance Calls	$	(1,086	)	$	(6,086	)	$	(14,361	)	$	(35,490	)	$	(88,518	)
Without Adequate Assurance Calls	$	-		$	-		$	(5,775	)	$	(24,403	)	$	(72,432	)

In the three months ended March 31, 2009, we realized net losses of $79.3 million from the settlement of natural gas hedge contracts, which were recorded as increases to the cost of gas, compared to net gains of $4.3 million in 2008, which were recorded as decreases to the cost of gas. The currency exchange rate in all foreign currency forward purchase contracts is included in our purchased cost of gas at settlement; therefore, no gain or loss is recorded from the settlement of those contracts. We settled our $50 million interest rate swap in March 2009 concurrent with our issuance of the underlying long-term debt and realized a $10.1 million effective hedge loss, which will be amortized to interest expense over the maturity period of the debt .

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

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

Some of our counterparties were recently downgraded but continue to maintain strong investment grade credit ratings. Due to current market conditions and credit concerns, we continue to enforce a high level of credit requirements for financial derivative counterparties in accordance with our policy. We actively monitor our derivative credit exposure and place counterparties on hold for trading purposes or require letters of credit, cash collateral or guarantees as circumstances warrant.

Our ongoing assessment of counterparty credit risk includes consideration of credit ratings, the credit default swap market, bond market credit spreads, financial results, government actions and market news. We utilize a Monte-Carlo simulation model to estimate the change in credit and liquidity risk from the volatility of natural gas prices. We use the results of the model to establish trading limits. The duration of our credit risk for all outstanding derivatives currently does not extend beyond October 31, 2010.

We could become materially exposed to credit risk with one or more of our counterparties if natural gas prices experience a significant increase. If a counterparty were to become insolvent or fail to perform on its obligations, we could suffer a material loss, but we would expect such loss to be subject to review and potentially deferred for rate recovery. All of our existing counterparties currently have investment-grade credit ratings, and as of March 31, 2009, we have no exposure to a derivative credit loss with any counterparty.

As of March 31, 2009, all outstanding natural gas hedge contracts were scheduled to mature on or before October 31, 2010.

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11.	Commitments and Contingencies

Environmental Matters

We own, or have previously owned, properties that are likely to require environmental remediation or action. We accrue all material loss contingencies relating to these properties that we believe to be probable of assertion and reasonably estimable. We continue to study and evaluate the extent of our potential environmental liabilities at each identified site. Due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several environmental site investigations, the amount or range of potential loss beyond the amounts currently accrued, and the probabilities thereof, cannot currently be reasonably estimated. See Part II, Item 8., Note 12, in the 2008 Form 10-K. The status of each site currently under investigation is provided below.

Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). The Gasco site has been under investigation by us for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. In May 2007, we completed a revised Upland Remediation Investigation Report and submitted it to the ODEQ for review. In November 2007, we submitted a Focused Feasibility Study for groundwater source control which ODEQ conditionally approved in March 2008. Source control design is underway. We have a net liability accrued of $19.4 million at March 31, 2009 for the Gasco site, which is estimated at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

Siltronic site. We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (the Siltronic site). In 2005, ODEQ directed NW Natural to complete a Remedial Investigation/Feasibility Study (RI/FS) for manufactured gas plant wastes on the uplands at this site. ODEQ approved NW Natural’s investigation work plan, and field work for the investigations is ongoing. The net liability accrued at March 31, 2009 for the Siltronic site is $0.9 million, which is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

Portland Harbor site. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (Portland Harbor) that includes the area adjacent to the Gasco and Siltronic sites. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and we were notified that we are a potentially responsible party. We then joined with other potentially responsible parties, referred to as the Lower Willamette Group, to fund environmental studies in the Portland Harbor. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor RI/FS. The submittal of the Remedial Investigation Report to the EPA is expected in 2009, with the submittal of the Feasibility Study to the EPA anticipated in 2010. The EPA and the Lower Willamette Group are conducting focused studies on approximately eleven miles of the lower Willamette River, including the 5.5-mile segment previously studied by the EPA. In 2008, we received a revised estimate and updated our estimate for additional expenditures related to RI/FS development and environmental remediation. In August 2008, we signed a cooperative agreement to participate in a phased natural resource damage assessment, with the intent to identify what, if any, additional information is necessary to estimate further liabilities sufficient to support an early restoration-based settlement of natural resource damage claims. In November 2007, EPA invited all parties (approximately 70) to whom it has thus far sent notices of potential liability for the Portland Harbor site to a meeting to discuss EPA Region 10’s expectation of a comprehensive settlement offer regarding implementation of the Portland Harbor record of decision, shortly after it issues such decision . Approximately 60 parties have “convened” to negotiate an agreement outlining the process for a non-judicial allocation. An initial allocation process agreement has been developed and is presently being circulated for execution. As of March 31, 2009, we have a net liability accrued of $12.6 million for this site, which is at the low end of the range of the potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

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In April 2004, we entered into an Administrative Order on Consent providing for early action removal of a deposit of tar in the river sediments adjacent to the Gasco site. We completed the removal of the tar deposit in the Portland Harbor in October 2005, and on November 5, 2005 the EPA approved the completed project. The total cost of removal, including technical work, oversight, consultant fees, legal fees and ongoing monitoring, was about $10.8 million. To date, we have paid $10.2 million on work related to the removal of the tar deposit. As of March 31, 2009, we have a net liability accrued of $0.6 million for our estimate of ongoing costs related to the tar deposit removal.

Central Service Center site. In 2006, we received notice from the ODEQ that our Central Service Center in southeast Portland (the Central Service Center site) was assigned a high priority for further environmental investigation. Previously there were three manufactured gas storage tanks on the premises. The ODEQ believes there could be site contamination associated with releases of condensate from stored manufactured gas as a result of historic gas handling practices. In the early 1990s, we excavated waste piles and much of the contaminated surface soils and removed accessible waste from some of the abandoned piping. In early 2007, we received notice that this site was added to the ODEQ’s list of sites where releases of hazardous substances have been confirmed and its list where additional investigation or cleanup is necessary. We are currently performing an environmental investigation of the property with the ODEQ’s Independent Cleanup Pathway. As of March 31, 2009, we have a net liability of $0.5 million accrued for investigation at this site. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated. Although it is outside the geographic scope of the current Portland Harbor site sediment studies, the EPA directed the Lower Willamette Group to collect a series of surface and subsurface sediment samples off the river bank adjacent to where that facility was located. Based on the results of that sampling, the EPA notified the Lower Willamette Group that additional sampling would be required. As the Front Street site is upstream from the Portland Harbor site, the EPA agreed that it could be managed separately from the Portland Harbor site under ODEQ authority. Work plans for sediment investigation and a historical report have been submitted to ODEQ . As of March 31, 2009, we accrued an estimated liability of $0.3 million for the study of the site, which will include investigation of sediments and provide a report of historical upland activities. The estimate is at the low end of the range of potential liability because no amount within the range is considered to be more likely than another and the high end of the range cannot reasonably be estimated.

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

Accrued Liabilities Relating to Environmental Sites. The following table summarizes the accrued liabilities relating to environmental sites at March 31, 2009 and 2008 and December 31, 2008:


	Current Liabilities						Non-Current Liabilities
	March 31,		March 31,		Dec. 31,		March 31,		March 31,		Dec. 31,
Thousands	2009		2008		2008		2009		2008		2008
Gasco site	$	8,457	$	8,444	$	6,012	$	10,935	$	12,406	$	14,701
Siltronic site		831		1,502		682		114		-		332
Portland Harbor site		-		1,454		277		13,191		12,887		13,642
Central Service Center site		-		-		-		526		529		526
Front Street site		294		-		-		-		-		294
Other sites		-		-		-		64		84		80
Total	$	9,582	$	11,400	$	6,971	$	24,830	$	25,906	$	29,575

Regulatory and Insurance Recovery for Environmental Costs. In May 2003, the Oregon Public Utility Commission (OPUC) approved our request to defer and seek recovery of unreimbursed environmental costs associated with certain named sites, including those described above. Also, beginning in 2006 the OPUC authorized us to accrue interest on deferred environmental cost balances, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. Through a series of extensions, this authorization has been extended through January 25, 2009. We have requested another extension from the OPUC, which is currently pending.

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On a cumulative basis, we have recognized a total of $71.2 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, $36.8 million has been spent to date and $34.4 million is reported as an outstanding liability. At March 31, 2009, we had a regulatory asset of $67.8 million, which includes $32.0 million of total paid expenditures to date, $29.0 million for additional environmental costs expected to be paid in the future and accrued interest of $6.8 million. We believe the recovery of these deferred charges is probable through the regulatory process. We intend to pursue recovery of an insurance receivable and environmental regulatory deferrals from insurance carriers under our general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We consider insurance recovery of most of our environmental costs probable based on a combination of factors including: a review of the terms of our insurance policies; the financial condition of the insurance companies providing coverage; a review of successful claims filed by other utilities with similar gas manufacturing facilities; and Oregon law that allows an insured party to seek recovery of “all sums” from one insurance company. We have initiated settlement discussions with a majority of our insurers but continue to anticipate that our overall insurance recovery effort will extend over several years.

We anticipate that our regulatory recovery of environmental cost deferrals will not be initiated within the next 12 months because we do not expect to have completed our insurance recovery efforts during that time period. As such we have classified our regulatory assets for environmental cost deferrals as non-current. The following table summarizes the non-current regulatory assets relating to environmental sites at March 31, 2009 and 2008 and December 31, 2008:

	Non-Current Regulatory Assets
	March 31,		March 31,		Dec. 31,
Thousands	2009		2008		2008
Gasco site	$	31,493	$	29,414	$	30,707
Siltronic site		2,223		2,247		2,327
Portland Harbor site		32,820		30,880		31,791
Central Service Center site		548		545		545
Front Street site		347		-		338
Other sites		350		300		396
Total	$	67,781	$	63,386	$	66,104

Legal Proceedings

We are subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, we do not expect that the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations or cash flows.

Oregon Steel Mills site. In 2004, NW Natural was served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial and discovery is ongoing. We do not expect that the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows.

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NORTHWEST NATURAL GAS COMPANY

PART I. FINANCIAL INFORMATION

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

The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural) financial condition, including the principal factors that affect results of operations. This discussion refers to our consolidated activities for the three months ended March 31, 2009 and 2008. Unless otherwise indicated, references in this discussion to “Notes” are to the Notes to Consolidated Financial Statements in this report. This discussion should be read in conjunction with our 2008 Annual Report on Form 10-K (2008 Form 10-K).

The consolidated financial statements include the accounts of NW Natural and its wholly-owned subsidiaries, NNG Financial Corporation (Financial Corporation) and Gill Ranch Storage, LLC (Gill Ranch), and an equity investment in a proposed natural gas pipeline. These accounts consist of our regulated local gas distribution business, our regulated gas storage businesses, and other regulated and non-regulated investments primarily in energy-related businesses. In this report, the term “Utility” is used to describe our regulated local gas distribution segment, and the term “Non-utility” is used to describe our gas storage segment (gas storage) and our other regulated and non-regulated investments and business activities (other segment) (see “Strategic Opportunities,” below, and Note 2).

In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on earnings. All references in this section to earnings per share are on the basis of diluted shares (see Part II, Item 8., Note 1, “Earnings Per Share,” in our 2008 Form 10-K).

Executive Summary

Highlights of the first quarter of 2009 include:

·	Consolidated net income increased 10 percent from $43.2 million in the first quarter of 2008 to $47.4 million, or $1.78 per share, in the first quarter of 2009;

·	Net operating revenues increased 8 percent from $132.4 million to $142.6 million, largely due to gains from our regulatory share of gas cost savings;

·	Income from utility operations increased 9 percent from $73.9 million to $80.9 million, while income from gas storage operations decreased 3 percent from $3.8 million to $3.7 million;

·	Cash flow from operations increased 23 percent from $119.3 million to $146.9 million, primarily due to deferred gas cost savings; and

·	We celebrated our company's 150th anniversary in January 2009.

Issues, Challenges and Performance Measures

Managing the utility business in a period of gas price volatility. Our gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our utility’s residential, commercial and industrial customers on firm service. Equally important, however, is our strategy to hedge gas prices for a significant portion of our annual purchase requirements based upon our utility’s gas load forecast for core utility customers. We have hedged gas prices for the majority of our gas purchases for the gas contract year that began on November 1, 2008, and we believe we have sufficient supplies of natural gas to meet the needs of our core utility customers. During the first quarter of 2009, the market price of natural gas has continued to be below the prices embedded in our customers’ rates through our annual purchased gas adjustment (PGA) resulting in increased margin from our regulatory share of gas cost savings. Gas costs lower than those set in the PGA may positively impact earnings due to an incentive sharing mechanism in Oregon. Conversely, gas costs higher than those set in the PGA may negatively impact earnings and may also affect our competitive advantage because they could reduce our ability to add residential and commercial customers and potentially cause industrial customers to shift their energy needs to alternative fuel sources. Our PGA cost sharing mechanism, along with gas hedging strategies and inventories in storage, enables us to manage and reduce earnings risk exposure due to higher gas costs. We have started to lock in gas prices for next year and may begin to hedge future years prices based on current price levels, and we continue to develop other gas acquisition strategies to manage future gas prices and efficiently meet demands.

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Economic weakness and financial market stress. The overall weakness in the U.S. economy, has resulted in significant negative pressure on consumer demand and business spending. These conditions could have a negative impact on our financial results including certain performance measures such as margins, customer growth rates, bad debt expense, and net interest charges. Our annual customer growth rate slowed to 1.2 percent at March 31, 2009 compared to 2.5 percent at March 31, 2008. Based on current market conditions, we expect customer growth rates in 2009 to continue below 2008 levels, and possibly decline more if economic conditions deteriorate further. Our growth rate has the potential to remain above the national average due to a comparatively low market penetration of natural gas in our service territory, the forecasted population growth in our service territory, the potential for environmental initiatives in Oregon and Washington that could favor natural gas as an energy source, and our efforts to convert existing homes from other heating fuels to natural gas.

Our funding for strategic and other capital investment opportunities is dependent upon our ability to access capital markets and maintain working capital sufficient to meet operating requirements. We intend to continue focusing on: maintaining a strong balance sheet; providing sufficient liquidity resources; monitoring and managing critical business risks; and securing, as needed, proceeds from the issuance of equity or long-term debt securities in order to fund utility and business development capital expenditures. To help mitigate the effect of the negative economic and capital market trends referred to above, we expect to manage costs, extend short-term debt maturities, maintain higher cash balances, maintain the ability to increase the amount of committed credit facilities, and access capital markets as needed to secure proceeds from the issuance of long-term securities for capital expenditure requirements. If we are unable to secure financing to fund certain strategic opportunities, we may look at potentially re-prioritizing the use of existing resources or consider delaying investments until market conditions improve.

We believe that, despite the current economic and credit market environment, our financial condition, including our liquidity position, is strong and we can access capital at reasonable costs. See Part I, Item 1A., “Risk Factors,” and Part II, Item 7., “Financial Condition—Liquidity and Capital Resources,” in our 2008 Form 10-K.

Performance Measures. In order to deal with these and other challenges affecting our business, we recently completed a new strategic plan to map our course over the next several years. The plan includes strategies for further improving our core gas distribution business; for growing our non-utility gas storage business; for investing in new natural gas infrastructure in the region; and for maintaining a leadership role within the gas utility industry by addressing long-term energy policies and pursuing business opportunities that support new clean technologies. The key performance measures we intend to use in monitoring progress against our goals in these areas include, but are not limited to : earnings per share growth; total shareholder return; return on invested capital; utility return on equity; utility customer satisfaction ratings; capital, operations and maintenance expense per customer; and non-utility earnings before interest, taxes, depreciation and amortization, commonly referred to as EBITDA.

Strategic Opportunities

Business Process Improvements. To address our economic and competitive challenges, we intend to continue re-assessing business processes for improved efficiencies. Our goal to integrate, consolidate and streamline operations and support our employees with new technology tools is underway. In 2008, we implemented the first phase of our new enterprise resource planning (ERP) system, and in February 2009 we implemented the second phase with our fixed assets, payroll and construction work management systems. This substantially completes our transition to the new ERP system, which is designed to improve overall operating efficiencies with:

·	the integration of systems and data;

·	automated control procedures with auditable financial and operational workflows; and

·	improved monthly closing and financial reporting processes.

In 2008, we initiated a project to automate the reading of gas meters (AMR) for the remaining two-thirds of our customers. The meters equipped with this technology electronically transmit usage data to receiving devices located in our vehicles as they are driven in the area, substantially reducing the labor costs associated with manually reading meters. The capital cost of this project is estimated to be $30 million, and in January 2009 we filed for and subsequently received approval for regulatory deferral of this investment in Oregon (see “Results of Operations—Regulatory Matters—Rate Mechanisms—AMR Deferral Application,” below). Also in 2008, we initiated an automated dispatching system, which provides integrated planning and scheduling with global positioning system capabilities to more effectively collect and distribute data. These technology investments and other initiatives are expected to facilitate process improvements and contribute to long-term operational efficiencies throughout NW Natural.

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Gas Storage Development. In September 2007, we initiated a joint project with Pacific Gas & Electric Company (PG&E) to develop an underground natural gas storage facility near Fresno, California. We formed a wholly-owned subsidiary, Gill Ranch, to plan, develop and operate the facility. In July 2008, Gill Ranch filed an application with the California Public Utilities Commission (CPUC) for a Certificate of Public Convenience and Necessity. In December 2008, the CPUC indicated that our application qualified for a Mitigated Negative Declaration, which allows an expedited review process. We expect to receive a decision on our application by the end of this year. Gill Ranch will become subject to CPUC regulation regarding various matters including, but not limited to, securities issuances, lien grants and sales of property. We estimate our share of the total cost of this project to be between $160 and $180 million. Our share represents 75 percent of the total cost of the initial phase of storage development, which includes an estimated 20 Bcf of gas storage capacity and approximately 27 miles of gas transmission pipeline. The initial phase of gas storage at Gill Ranch is currently scheduled to be in-service by late 2010.

Pipeline Diversification. Currently, we depend on a single interstate pipeline company to ship gas supplies to our system. Palomar Gas Transmission, LLC (Palomar), a wholly-owned subsidiary of Palomar Gas Holdings, LLC, (PGH), is seeking to build a new transmission pipeline that would connect with our system. PGH is owned 50 percent by NW Natural and 50 percent by Gas Transmission Corporation (GTN), an indirect wholly-owned subsidiary of TransCanada Corporation. The proposed Palomar pipeline is a 217-mile natural gas transmission pipeline in Oregon designed to serve our utility and the growing markets in Oregon and other parts of the western United States. The project includes an east and west segment. The east segment of the Palomar pipeline would extend approximately 111 miles west from an interconnection with GTN’s existing interstate transmission mainline near Maupin, Oregon to an interconnection with NW Natural’s gas distribution system near Molalla, Oregon. The west segment would then extend approximately 106 miles further west to additional interconnections including a possible connection to one of the several liquefied natural gas (LNG) terminals proposed to be built on the Columbia River. The east segment of Palomar would diversify NW Natural’s delivery options and enhance the reliability of service to our utility customers by providing an alternate transportation path for gas purchases from different regions in western Canada and the U.S. Rocky Mountains. The west segment of Palomar would also provide our utility customers with access to a new source of gas supply if an LNG terminal is built on the Columbia River. The Palomar pipeline would be regulated by the Federal Energy Regulatory Commission (FERC). In December 2008, Palomar filed for a Certificate of Public Convenience and Necessity with the FERC. See "Financial Condition—Investing Activities," below for further discussion on Palomar.

Earnings and Dividends

Net income was $47.4 million, or $1.78 per share, for the three months ended March 31, 2009, compared to $43.2 million, or $1.63 per share, for the same period last year.

The primary factors contributing to the $4.2 million increase in net income were:

·	an $8.4 million gain in utility margin from our regulatory share of gas cost savings, compared to a margin loss of $0.4 million from our share of gas cost increases in the first quarter of 2008; and

·	a $2.5 million increase from a regulatory adjustment for income taxes paid versus collected in rates.

Partially offsetting the above factors were:

·	a $5.5 million increase in operations and maintenance expense primarily due to increases in incentive pay accruals, employee pension costs and bad debt expense; and

·	a decrease in utility margin from industrial sales and transportation of $0.9 millions due to lower volumes.

Dividends paid on our common stock were 39.5 cents per share in the first quarter of 2009, compared to 37.5 cents per share in the first quarter of 2008. In April 2009, the Board of Directors declared a quarterly dividend on our common stock of 39.5 cents per share, payable on May 15, 2009 to shareholders of record on April 30, 2009. The current indicated annual dividend rate is $1.58 per share.

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Application of Critical Accounting Policies and Estimates

In preparing our financial statements using generally accepted accounting principles in the United States of America, management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and related disclosures in the financial statements. Management considers our critical accounting policies to be those which are most important to the representation of our financial condition and results of operations and which require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if we reported under different conditions or used different assumptions. Our most critical estimates and judgments include accounting for:

·	regulatory cost recovery and amortizations;

·	revenue recognition;

·	derivative instruments and hedging activities;

pensions;

·	income taxes; and

·	environmental contingencies.

There have been no material changes to the information provided in the 2008 Form 10-K with respect to the application of critical accounting policies and estimates (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the 2008 Form 10-K). Management has discussed the estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board.

Within the context of our critical accounting policies and estimates, management is not aware of any reasonably likely events or circumstances that would result in materially different amounts being reported. For a description of recent accounting pronouncements that could have an impact on our financial condition, results of operations or cash flows, see Note 1.

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Results of Operations

Regulatory Matters

Regulation and Rates

We are currently subject to regulation with respect to, among other matters, rates and systems of accounts set by the Oregon Public Utility Commission (OPUC), Washington Utilities and Transportation Commission (WUTC) and FERC. The OPUC and WUTC also regulate our issuance of securities. In 2009, approximately 90 percent of our utility gas volumes were delivered to, and utility operating revenues were derived from, Oregon customers and the balance from Washington customers. Future earnings and cash flows from utility operations will be determined largely by the Oregon and Washington economies in general, and by the pace of growth in the residential and commercial markets in particular, and by our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery for our utility gas costs, operating and maintenance costs and investments made in utility plant. See Part II, Item 7., “Results of Operations—Regulatory Matters,” in the 2008 Form 10-K.

At March 31, 2009 and 2008 and at December 31, 2008, the amounts deferred as regulatory assets and liabilities were as follows:

	Current
	March 31,		March 31,		Dec. 31,
Thousands	2009		2008		2008
Regulatory assets:
Unrealized loss on non-trading derivatives(1)	$	107,461	$	1,703	$	136,735
Pension and other postretirement benefit obligations(2)		8,074		1,912		8,074
Other(4)		8,550		2,673		2,510
Total regulatory assets	$	124,085	$	6,288	$	147,319
Regulatory liabilities:
Gas costs payable	$	31,925	$	41,422	$	5,284
Unrealized gain on non-trading derivatives(1)		4,798		33,611		4,592
Other(4)		9,752		13,164		10,580
Total regulatory liabilities	$	46,475	$	88,197	$	20,456

	Non-Current
	March 31,		March 31,		Dec. 31,
Thousands	2009		2008		2008
Regulatory assets:
Unrealized loss on non-trading derivatives(1)	$	15,387	$	4,995	$	21,646
Income tax asset		70,096		69,547		69,948
Pension and other postretirement benefit obligations(2)		111,851		26,678		113,869
Environmental costs - paid(3)		38,804		30,004		36,135
Environmental costs - accrued but not yet paid(3)		28,977		33,459		29,969
Other(4)		19,051		14,490		16,903
Total regulatory assets	$	284,166	$	179,173	$	288,470
Regulatory liabilities:
Gas costs payable	$	9,201	$	7,281	$	1,868
Unrealized gain on non-trading derivatives(1)		189		1,227		146
Accrued asset removal costs		227,770		209,248		223,716
Other(4)		2,401		2,381		2,427
Total regulatory liabilities	$	239,561	$	220,137	$	228,157


(1)	An unrealized gain or loss on non-trading derivatives does not earn a rate of return or a carrying charge. These amounts, when realized at settlement, are recoverable through utility rates as part of the PGA mechanism.
(2)	Qualified pension plan and other postretirement benefit obligations are approved for regulatory deferral. Such amounts are recoverable in rates, including an interest component, when recognized in net periodic benefit cost (see Note 7).

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

(4)	Other primarily consists of deferrals and amortizations under other approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge.

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Rate Mechanisms

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

In October 2008, the OPUC and WUTC approved rate changes effective on November 1, 2008 under our PGA mechanisms. The effect of the rate changes was to increase the average monthly bills of Oregon residential customers by 14 percent and those of Washington residential customers by 21 percent.

Under the new Oregon PGA incentive sharing mechanism, effective November 1, 2008, we are required to select, by August 1 of each year, either an 80 percent deferral or 90 percent deferral of higher or lower gas costs compared to PGA prices such that the impact on current earnings from the gas cost sharing is either 20 percent or 10 percent, respectively. We are also subject to an annual earnings review to evaluate the utility’s financial performance. If utility earnings exceed a threshold level, then 33 percent of the amount above the threshold will be deferred for future refund to customers. Under our current mechanism, if we select the 80 percent deferral, we retain all of our earnings up to 150 basis points above the currently authorized ROE, or if we select the 90 percent deferral, we retain all of our earnings up to 100 basis points above the currently authorized ROE. For the PGA year in Oregon beginning on November 1, 2008, we selected the 80 percent deferral of gas cost differences. The earnings threshold is currently subject to adjustment up or down each year depending on movements in long-term interest rates.

In 2008, the earnings threshold after adjustment for long-term interest rates was 13.1 percent. We do not expect that any amounts will be required to be refunded to customers as a result of the 2008 earnings review, which will be approved by the OPUC during the second quarter of 2009. There has been no change to the Washington PGA mechanism under which we defer 100 percent of the higher or lower actual purchased gas costs and pass that difference through to customers as an adjustment to future rates.

Regulatory Recovery for Environmental Costs. In May 2003, the OPUC approved our request to defer unreimbursed environmental costs associated with certain named sites. Beginning in 2006, the OPUC authorized us to accrue interest on deferred environmental cost balances, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. Through a series of extensions, this authorization has been extended through January 25, 2009. We have requested another extension from the OPUC, which is currently pending. See Note 11.

Integrated Resource Plan. The OPUC and WUTC have implemented integrated resource planning (IRP) processes under which utilities develop plans defining alternative growth scenarios and resource acquisition strategies. These plans are consistent with state and energy policy and include:

·	an evaluation of supply and demand resources;

·	the consideration of uncertainties in the planning process and the need for flexibility to respond to changes; and

·	a primary goal of “least cost” service.

We filed our 2008 IRP with the OPUC and an update to our 2007 IRP with the WUTC in April 2008. In October 2008, we received notification from the WUTC that our 2007 IRP met the requirements of the Washington Administrative Code. In January 2009, the OPUC acknowledged our 2008 IRP. Although the OPUC acknowledgment of the IRP does not constitute ratemaking approval of any specific resource acquisition strategy or expenditure, the OPUC generally indicates that it would give considerable weight in prudency reviews to utility actions that are consistent with acknowledged plans. The WUTC has indicated that the IRP process is one factor it will consider in a prudency review.

On March 31, 2009, we filed our 2009 IRP with the WUTC. We anticipate that the WUTC will review and comment on the document by the end of 2009.

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System Integrity Program. In July 2004, the OPUC approved specific accounting treatment and cost recovery for our transmission pipeline integrity management program, a program mandated by the Pipeline Safety Improvement Act of 2002 and the related rules adopted by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration. We record these costs as either capital expenditures or regulatory assets, accumulate the costs over each 12 month period ending September 30, and recover the costs, subject to audit, through rate changes effective with the annual PGA in Oregon. In February 2009, the OPUC approved a stipulated agreement to create a new, consolidated system integrity program (SIP). The new SIP will integrate the older and the proposed programs into a single program. The SIP also includes a component for a proposed distribution integrity management program, which will be implemented following the enactment of new federal regulations. Costs will be tracked into rates annually, with recovery to be sought after the first $3.3 million of capital costs. An annual cap for expenditures will be approximately $12 million, but extraordinary costs above the cap may be approved with written consent of all parties.

The SIP allows recovery of costs incurred in Oregon during the period from October 2008 through October 2011, or until the effective date of new rates adopted in the company’s next general rate case. We do not have any special accounting or rate treatment for system integrity program costs incurred in the state of Washington.

AMR Deferral Application. In 2008, we initiated a project to automate the reading of gas meters for the remaining two-thirds of our customers. The capital cost of this project is estimated to be $30 million, and in January 2009 we filed for approval to defer the costs associated with the AMR project. This request was approved on March 30, 2009. We plan to seek approval to recover the deferred costs in our next PGA filing.

Depreciation Study. In December 2008, the OPUC and WUTC approved our filed depreciation study and our request to change the amortization of our regulatory asset account balance on pre-1981 plant. These approvals specifically authorized the implementation of new depreciation rates in Oregon and Washington, with a corresponding decrease to customer rates effective January 1, 2009. The new amortization schedule on pre-1981 regulatory assets, with a corresponding increase to customer rates, became effective January 1, 2009 in Washington and will be effective November 1, 2009 in Oregon. The implementation of these new rates will decrease depreciation expense and increase effective income tax expense rates, both of which will be offset by a corresponding change in utility operating revenues. In addition, in December 2008 we filed our depreciation study with the FERC requesting approval to apply these same new depreciation rates to our gas storage business assets. Our FERC filing was approved on May 4, 2009 and the new depreciation rates are effective as of January 1, 2009.

Customer Refunds for Gas Cost Incentive Sharing. For the period between November 1, 2008 and March 31, 2009, our actual gas costs were significantly lower than the gas costs embedded in customer rates. As a result, our PGA incentive sharing mechanism recorded 80 percent of these gas cost savings to a regulatory account for refund to customers (see “Purchased Gas Adjustment,” above). Ordinarily, these refunds would be included in customer rates under next year’s PGA filing. However, in April 2009 we sought regulatory approval from the OPUC to immediately refund an aggregate $32 million to our Oregon customers through billing credits. If approved, we intend to refund this amount to customers during the second quarter of 2009.

Business Segments - Utility Operations

Our utility margin results are affected by customer growth and to a certain extent by changes in weather and customer consumption patterns, with a significant portion of our earnings being derived from natural gas sales to residential and commercial customers. In Oregon, we have a conservation rate mechanism that adjusts revenues to offset changes in margin resulting from increases or decreases in residential and commercial customer consumption. We also have a weather normalization mechanism that adjusts revenues and customer bills up or down to offset changes in margin resulting from above- or below-average temperatures during the winter heating season (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms,” in the 2008 Form 10-K). Both mechanisms are designed to reduce the volatility of our utility earnings.

Utility operations resulted in net income of $45.3 million, or $1.70 per share, in the first quarter of 2009 compared to $40.5 million, or $1.53 per share, in first quarter of 2008. The most significant factors contributing to the $4.8 million increase in earnings were the margin gains from our regulatory share of gas cost savings and from a regulatory adjustment for income taxes paid. Total utility margin increased $10.7 million, with $8.8 million from our share of lower gas costs and $2.5 million from the regulatory tax adjustment, partially offset by a $4.4 million decrease in margin from lower depreciation rates (see “Consolidated Operating Expenses—Depreciation and Amortization,” below). Even though weather was 2 percent colder than last year, total utility volumes decreased 38 million therms, or 8 percent, primarily from reduced usage by industrial customers due to economic conditions.

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

	Three months ended
	March 31,						Favorable/
Thousands, except degree day and customer data	2009			2008			(Unfavorable)
Utility volumes - therms:
Residential sales		178,389			182,368			(3,979	)
Commercial sales		103,117			106,956			(3,839	)
Industrial - firm sales		12,037			14,542			(2,505	)
Industrial - firm transportation		35,401			48,986			(13,585	)
Industrial - interruptible sales		22,899			26,042			(3,143	)
Industrial - interruptible transportation		59,467			70,382			(10,915	)
Total utility volumes sold and delivered		411,310			449,276			(37,966	)
Utility operating revenues - dollars:
Residential sales	$	253,057		$	225,683		$	27,374
Commercial sales		129,350			114,964			14,386
Industrial - firm sales		13,704			13,822			(118	)
Industrial - firm transportation		1,402			1,586			(184	)
Industrial - interruptible sales		21,939			19,681			2,258
Industrial - interruptible transportation		1,922			2,095			(173	)
Regulatory adjustment for income taxes paid (1)		3,513			1,055			2,458
Other revenues		7,913			3,756			4,157
Total utility operating revenues		432,800			382,642			50,158
Cost of gas sold		284,164			245,912			(38,252	)
Revenue taxes		10,542			9,351			(1,191	)
Utility margin	$	138,094		$	127,379		$	10,715
Utility margin: (2)
Residential sales	$	86,333		$	87,592		$	(1,259	)
Commercial sales		33,774			34,634			(860	)
Industrial - sales and transportation		7,422			8,331			(909	)
Miscellaneous revenues		1,892			1,728			164
Gain (loss) from gas cost incentive sharing		8,432			(353	)		8,785
Other margin adjustments		498			346			152
Margin before regulatory adjustments		138,351			132,278			6,073
Weather normalization adjustment		(8,714	)		(7,548	)		(1,166	)
Decoupling adjustment		4,944			1,594			3,350
Regulatory adjustment for income taxes paid (1)		3,513			1,055			2,458
Utility margin	$	138,094		$	127,379		$	10,715
Customers - end of period:
Residential customers		601,917			594,431			7,486
Commercial customers		62,541			62,035			506
Industrial customers		929			949			(20	)
Total number of customers - end of period		665,387			657,415			7,972
Actual degree days		2,021			1,980
Percent colder (warmer) than average (3)		8	%		5	%

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

(2)	Amounts reported as margin for each category of customers are net of cost of gas sold and revenue taxes.

(3)	Average weather represents the 25-year average degree days, as determined in our last Oregon general rate case.

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Residential and Commercial Sales

Residential and commercial sales are impacted by customer growth, seasonal weather patterns, energy prices, competition from other energy sources and economic conditions in our service areas. Typically, 80 percent or more of our annual utility operating revenues are derived from gas sales to weather-sensitive residential and commercial customers. Although variations in temperatures between periods will affect volumes of gas sold to these customers, the effect on margin and net income is significantly reduced due to our weather normalization mechanism in Oregon where about 90 percent of our customers are served, and is effective from December 1 through May 15 of each heating season. Approximately 10 percent of our eligible Oregon customers have opted out of the mechanism. In Oregon, we also have a conservation decoupling adjustment mechanism that is intended to break the link between our earnings and the quantity of gas consumed by our customers, so that we do not have an incentive to encourage greater consumption contrary to customers’ energy conservation efforts. In Washington, where approximately 10 percent of our customers are served, we do not have a weather normalization or a conservation decoupling mechanism. As a result, we are not fully insulated from earnings volatility due to weather and conservation.

For the three months ended March 31, 2009 compared to March 31, 2008, we experienced:

·	3 percent lower sales volumes from residential and commercial customers due to weak economic conditions and customers conserving more, partially offset by weather that was 2 percent colder than last year; and

·	annual customer growth of 1.2 percent in 2009 as compared to 2.5 percent in 2008.

Utility operating revenues include accruals for unbilled revenues (gas delivered but not yet billed to customers) based on estimates of gas deliveries from that month’s meter reading dates to month end. Weather conditions, rate changes and customer billing dates affect the balance of accrued unbilled revenues at the end of each month. At March 31, 2009, accrued unbilled revenue was $61.0 million, compared to $56.0 million at March 31, 2008, a 9 percent increase primarily due to higher billing rates in 2009.

Industrial Sales and Transportation

Industrial operating revenues include the commodity cost component of gas sold under sales service but not for transportation service. Therefore, industrial customer switching between sales service and transportation service can cause swings in operating revenues, but generally our margins are not affected because we do not mark up the cost of gas. In addition, a significant portion of margin revenues from our largest industrial customers are in the form of fixed monthly charges. As such, we believe margin is a better measure of performance for the industrial sector. The primary factors that impacted results of operations in industrial sales and transportation markets are as follows:

·	volumes delivered to industrial customers decreased by 30.1 million therms, or 19 percent; and

·	margin decreased $0.9 million, or 11 percent, reflecting reduced usage due to the current economic environment, partially offset by fixed charges that are not affected by declining use.

Several large industrial customers transferred from sales service back to transportation service since mid-year 2008. High natural gas prices can result in a number of our large industrial customers switching from transportation service, where they arrange for their own supplies through independent third parties, to sales service, where we sell them the gas commodity under regulatory tariffs. In such cases, our tariff requires us to charge any incremental cost of gas supply incurred to those customers.

Regulatory Adjustment for Income Taxes Paid

In Oregon, Senate Bill 408 (SB 408) requires utilities to true-up any differences between income taxes authorized to be collected in rates from customers and income taxes actually paid to governmental entities that are “properly attributed” to the utilities’ regulated operations. Utilities are required to file a tax report with the OPUC reporting these amounts on October 15 of each year. If amounts collected and amounts paid differ by $100,000 or more, then the OPUC must order the utility to establish an automatic adjustment clause to account for the difference, with a rate adjustment to be effective June 1 of each year.

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Based on our regulated operations through March 31, 2009, we recognized $3.5 million of pre-tax income representing a difference of $3.3 million of federal and state income taxes paid in excess of taxes collected in rates plus accrued interest of $0.2 million attributed to the 2007 and 2009 tax years. This indicated surcharge was primarily driven by gains from gas cost savings from our PGA incentive mechanism during the first quarter of 2009. For the three months ended March 31, 2008, we recognized a surcharge of $1.1 million representing $0.7 million attributed to regulated operations for the 2008 tax year and a $0.4 million adjustment for the 2007 tax year.

Other Revenues

Other revenues include miscellaneous fee income as well as utility revenue adjustments reflecting deferrals to, or amortizations from, regulatory asset or liability accounts other than deferred gas costs. Other revenues were $7.9 million in the first quarter of 2009, an increase of $4.2 million over the first quarter of 2008, with the increase primarily due to a net increase in the deferral and amortization related to the decoupling adjustment. Although the decoupling adjustment can have a material impact on gross operating revenues, it does not have a material impact on margin because it generally offsets increases and decreases in customer sales margins.

Cost of Gas Sold

The cost of gas sold includes current gas purchases, gas drawn from storage inventory, gains and losses from commodity hedges, pipeline demand charges, seasonal demand cost balancing adjustments, regulatory gas cost deferrals and company gas use. The OPUC and the WUTC require the natural gas commodity cost to be billed to customers at the same cost incurred or expected to be incurred by the utility. However, under the PGA mechanism in Oregon, our net income is affected by differences between actual and expected purchased gas costs primarily due to changes in market prices and weather, which affects the volume of unhedged purchases. We use natural gas derivatives, primarily fixed-price commodity swaps, under the terms of our financial derivatives policies to help manage our exposure to rising gas prices. Gains and losses from financial hedge contracts are generally included in our PGA prices and normally do not impact net income as the hedges are usually 100 percent passed through to customers in annual rate changes, subject to a regulatory prudency review. However, utility gas hedges entered into after the annual PGA filing in Oregon may impact net income to the extent of our share of any gain or loss under the PGA. In Washington, 100 percent of the actual gas costs, including hedge gains and losses, are passed through in customer rates (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” and “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” in the 2008 Form 10-K, and Note 10). For the three months ended March 31, 2009:

·	total cost of gas sold increased $38.3 million or 16 percent compared to 2008;

·	the average gas cost collected through rates increased 20 percent from 75 cents per therm in 2008 to 90 cents per therm in 2009, primarily reflecting cost increases that were passed through to customers through PGA rate increases effective November 1, 2008; and

·	hedge losses totaling $79.3 million were realized, compared to $4.3 million of hedge gains in the same period of 2008.

For the three months ended March 31, 2009, our actual gas costs were lower than gas costs embedded in rates, while during the three months ended March 31, 2008 and the year ended December 31, 2008 our actual gas costs were higher than the gas costs embedded in rates. The effect on net income from the gas cost incentive sharing mechanism was a margin gain of $8.4 million in the first quarter of 2009, compared to a margin loss of $0.4 million for the three months ended March 31, 2008.

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Business Segments Other than Utility Operations

Gas Storage

Our gas storage segment primarily consists of the non-utility portion of our Mist underground storage facility, asset optimization and Gill Ranch. In the first quarter of 2009, we earned $2.0 million, or 8 cents per share, from our gas storage segment, after regulatory sharing and income taxes. This compares to net income of $2.4 million, or 9 cents per share, in the first quarter of 2008. The $0.4 million decrease in earnings over 2008 is due to decreased revenues from optimization services under a contract with an independent energy marketing company. See Part I, Item 1., “Business Segments—Gas Storage,” in our 2008 Form 10-K.

In Oregon, we retain 80 percent of the pre-tax income from gas storage services as well as from optimization services when the costs of the capacity being used is not included in utility rates, or 33 percent of the pre-tax income from such storage and optimization services when the capacity being used is included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for refund to our core utility customers. We have a similar sharing mechanism in Washington for pre-tax income derived from gas storage and optimization services. We are currently in the process of developing a second underground storage facility, Gill Ranch, and related pipeline near Fresno, California. Our Gill Ranch project is expected to serve the California and west coast market. See Note 2.

Other

Our other business segment consists of Financial Corporation, an equity investment in Palomar and other non-utility investments and business activities. Financial Corporation’s total investment balance as of March 31, 2009 and 2008 were $1.0 million and $1.1 million, respectively, and our equity balance in the proposed Palomar transmission pipeline was $15.5 million and $7.6 million, respectively. Our total assets at Financial Corporation reflect a non-controlling interest in the Kelso Beaver pipeline. The current equity balance in Palomar reflects our investment to date in a proposed 217-mile transmission pipeline. Net income from our other business segment for the first quarter of 2009 and 2008 was less than $0.1 million and $0.3 million, respectively. For further information, see Note 2.

Consolidated Operating Expenses

Operations and Maintenance

Operations and maintenance expense in the first quarter of 2009 was $34.0 million, compared to $28.5 million in 2008, an increase of $5.5 million or 19 percent. The major factors that contributed to the increase in operations and maintenance expense are:

·	a $1.7 million increase in bonus accruals due to higher operating results primarily from our gas cost savings;

·	a $1.7 million increase in pension expense primarily due to lower income from pension assets resulting from a decline in the market value of assets during 2008; and

·	a $0.9 million increase in utility bad debt expense.

Our bad debt expense ratio as a percent of revenues was 0.4 percent for the 12 months ended March 31, 2009, compared to 0.3 percent in the same period year. With a weaker economy and high unemployment rates, it may be more difficult for our customers to pay their bills. Under the PGA mechanism, our rates are adjusted each year to recover the expected increase in bad debt expense due to the higher cost of natural gas. The revenue adjustment for bad debt expense is based on our average write-off rate over the last three years multiplied by the estimated increase in commodity costs. In the first quarter of 2009, margin revenues increased by approximately $0.4 million due to an OPUC approved rate increase to offset the expected increase in bad debt expense related to higher gas costs. Although we may experience a higher increase in bad debt expense this year, we believe much of the increase will be offset by the allowed rate increase under our PGA mechanism.

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General Taxes

General taxes, which are principally comprised of property taxes, payroll taxes and regulatory fees, increased $0.4 million, or 4 percent, in the three months ended March 31, 2009 over the same period in 2008. Property taxes increased $0.2 million, or 3 percent, reflecting an increase in net utility plant and net non-utility plant in service. Regulatory fees increased $0.2 million, or 8 percent, reflecting higher utility gross operating revenues.

We have been involved in litigation with the Oregon Department of Revenue (ODOR) over whether natural gas inventories and appliance inventories held for resale are required to be taxed as personal property. In November 2007, the Oregon Tax Court ruled in our favor stating that these inventories were exempt from property tax. However, the ODOR appealed the judgment to the Oregon Supreme Court in August 2008. If we are successful in this litigation, we would be entitled to a refund of over $5.0 million for property taxes paid on gas inventories beginning with the 2002-2003 tax year and appliance inventories beginning with the 2005-06 tax year, plus accrued interest. Due to the uncertain outcome of the proceeding, we have not recorded the recovery of property taxes paid on gas inventories or appliance inventories to recognize the potential gain contingency.

Depreciation and Amortization

Depreciation and amortization expense decreased by $2.2 million, or 12 percent, for the three months ended March 31, 2009, compared to the same period in 2008. The lower expense reflects decreased depreciation rates effective January 1, 2009 in accordance with OPUC and WUTC approval of our depreciation study. The decrease in depreciation expense in 2009 will be offset by a corresponding decrease in operating revenues this year. See “Regulatory Matters—Rates and Regulations—Depreciation Study,” above.

Other Income and Expense – Net

The following table summarizes other income and expense – net by primary components:

	Three Months Ended
	March 31,
Thousands	2009			2008
Other income and expense - net:
Gains from company-owned life insurance	$	1,081		$	459
Interest income		60			(1	)
Income (loss) from equity investments		288			(25	)
Net interest on deferred regulatory accounts		501			(167	)
Other		(1,040	)		(93	)
Total other income and expense - net	$	890		$	173

In the three months ended March 31, 2009, other income and expense – net increased $0.7 million compared to the same period in 2008. The increase is primarily due to additional income from our company-owned life insurance and interest income from our deferred regulatory accounts, partially offset by a decrease in our other non-operating expenses.

Interest Charges – Net of Amounts Capitalized

Interest charges – net of amounts capitalized decreased less than $0.1 million, or less than 1 percent, in the three months ended March 31, 2009 compared to the same period in 2008.

Income Tax Expense

Income tax expense totaled $28.8 million in the three months ended March 31, 2009 compared to $25.7 million in the three months ended March 31, 2008. The effective tax rate was 37.8 percent in 2009 compared to 37.3 percent in 2008. The higher income tax rate in 2009 is due primarily to accelerated amortization of deferred tax amounts related to pre-1981 regulatory assets.

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Financial Condition

Capital Structure

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

	March 31,			March 31,			Dec. 31,
	2009			2008			2008
Common stock equity		49.6	%		52.4	%		45.3	%
Long-term debt		43.8	%		42.6	%		36.8	%
Short-term debt, including current maturities of long-term debt		6.6	%		5.0	%		17.9	%
Total		100.0	%		100.0	%		100.0	%

Liquidity and Capital Resources

At March 31, 2009, we had $10.3 million of cash and cash equivalents compared to $6.4 million at March 31, 2008. Short-term liquidity is provided by cash balances, internal cash flow from operations, proceeds from the sale of commercial paper notes, committed credit facilities, including multi-year commitments which are primarily used to back-up commercial paper (see “Credit Agreement,” below), an ability to borrow from cash surrender value in company-owned life insurance policies, and proceeds from the sale of long-term debt. We use long-term debt proceeds to finance capital expenditures, refinance maturing short-term or long-term debt and for general corporate purposes. On March 25, 2009, we issued $75 million of secured medium-term notes (MTNs) at 5.37 percent, which will mature in 2020. In connection with this issuance, we settled our $50 million interest rate swap and realized a $10.1 million loss, which will be recognized in interest expense over the maturity period of the debt .

Our senior secured long-term debt ratings are AA- and A2 from Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s), respectively, while our short-term debt ratings are A-1+ and P-1 from S&P and Moody’s, respectively. The capital markets, including the commercial paper market, have experienced significant volatility and tight credit conditions in the last six months, as reflected by increased credit spreads and limited access to new financing. With our current debt ratings we have been able to issue commercial paper notes at attractive rates without the need to borrow from our $250 million back-up facility. In the event that we are not able to issue commercial paper or other debt instruments due to market conditions, we expect that our liquidity needs can be met by using cash balances or drawing upon our committed credit facility (see “Credit Agreement,” below). We also have a universal shelf registration statement filed with the Securities and Exchange Commission for the issuance of secured and unsecured debt or equity securities, market conditions permitting. At March 31, 2009, we had OPUC approval to issue up to $225 million of additional MTNs under the shelf registration.

Our senior unsecured long-term debt ratings are A+ and A3 from S&P and Moody’s, respectively. In the event that our senior unsecured long-term debt credit ratings are downgraded, our counterparties under derivative contracts could require us to post cash, a letter of credit or other form of collateral, which could expose us to additional costs and may trigger significant increases in draws from our borrowing facilities.

Based on our current credit ratings, our recent experience issuing commercial paper, our current cash reserves, the availability and size of our committed credit facilities and other liquidity resources and our ability to issue long-term debt and equity securities under our universal shelf registration, we believe our liquidity is sufficient to meet our anticipated near-term cash requirements, including the contractual obligations and investing and financing activities discussed below.

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Off-Balance Sheet Arrangements

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

Contractual Obligations

Since December 31, 2008, our future contractual obligations have not materially changed. Our contractual obligations at December 31, 2008 are described in Part II, Item 7., “Financial Condition—Liquidity and Capital Resources—Contractual Obligations,” in the 2008 Form 10-K.

Commercial Paper and Other Short-Term Loans

Our primary source of short-term liquidity is from internal cash flows and the sale of commercial paper notes payable. In addition to issuing commercial paper to meet seasonal working capital requirements, including the financing of gas inventories and accounts receivable, short-term debt may be used to temporarily fund capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by one or more unsecured revolving credit facilities (see “Credit Agreement,” below). Our commercial paper program did not experience any liquidity disruptions as a result of the credit problems that affected issuers of asset-backed commercial paper and certain other commercial paper programs last year. At March 31, 2009 and 2008 we had commercial paper outstanding of $82.8 million and $54.6 million, respectively. This year’s outstanding balances were higher than last year’s primarily due to higher balances in gas inventories and accounts receivable and temporary negative cash flow from losses related to the settlement of gas hedge contracts.

Credit Agreement

We have a syndicated line of credit for unsecured revolving loans totaling $250 million available and committed for a term expiring on May 31, 2012, with $210 million of that commitment amount extended through May 31, 2013. The lenders under our syndicated credit agreement are major financial institutions with committed balances and investment grade credit ratings as of March 31, 2009 as follows:

	Amount
	Committed
Lender rating, by category	(in $000's)
AAA/Aaa	$	-
AA/Aa		165,000
A/A		85,000
BBB/Baa		-
Total	$	250,000

Based on current credit market conditions , it is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, including a review of capital ratios, credit default swap spreads and credit ratings, we believe the risk of lender default is minimal.

Pursuant to the terms of our credit agreement for the syndicated line of credit, we may request maturity extensions for additional one-year periods subject to lender approval. We extended commitments with six of the seven lenders under the syndicated credit agreement, with commitments totaling $210 million, to May 31, 2013. The credit agreement also allows us to request increases in the total commitment amount from time to time, up to a maximum amount of $400 million, and to replace any lenders who decline to extend the terms of the credit agreement. The credit agreement also permits the issuance of letters of credit in an aggregate amount up to the applicable total borrowing commitment. Any principal and unpaid interest owed on borrowings under the credit agreement are due and payable on or before the expiration date. There were no outstanding balances under this credit agreement at March 31, 2009 and 2008. The credit agreement also requires us to maintain a consolidated indebtedness to total capitalization ratio of 70 percent or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at March 31, 2009 and 2008, with consolidated indebtedness to total capitalization ratios of 50.4 percent, and 47.6 percent, respectively.

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

Credit Ratings

The following table summarizes our current debt credit ratings from S&P and Moody’s:

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

Both rating agencies have assigned investment grade credit ratings to NW Natural. These credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell or hold NW Natural securities. Each rating should be evaluated independently of any other rating.

Redemptions of Long-Term Debt

Redemptions of long-term debt during the three months ended March 31, 2009 and 2008 and the year-ended December 31, 2008 were as follows:

	Three months ended March 31,				Year ended
Thousands	2009		2008		Dec. 31, 2008
Medium-Term Notes:
First Mortgage Bonds:
6.50% Series B due 2008	$	-	$	-	$	5,000

For long-term debt maturing over the next five years, see Part II, Item 7A., "Results of Operations—Financial Condition—Contractual Obligations," in our 2008 Form 10-K.

Cash Flows

Operating Activities

Year-over-year changes in our operating cash flows are primarily affected by net income, changes in working capital requirements and other cash and non-cash adjustments to operating results. In the first quarter of 2009, cash flow from net income and operating activities, excluding working capital changes, increased $16.4 million compared to the same period in 2008. Cash flow from working capital changes in the first quarter of 2009 increased by $11.2 million compared to the same period in 2008. The overall change in cash flow from operating activities was an increase of $27.6 million. The significant factors contributing to the cash flow changes between 2009 and 2008 are as follows:

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2009 compared to 2008:

·	an increase in cash of $30.2 million in deferred gas costs, an increase in cash of $27.5 million in accounts payable and a decrease in cash of $41.4 million in gas inventory due to lower gas costs in 2009 compared to 2008;

·	a decrease in cash of $10.1 million due to the loss realized on the settlement of our interest rate hedge which will be amortized over the period of the debt outstanding (see Note 10);

·	an increase in cash of $16.0 million in accounts receivable and accrued unbilled revenue due to higher rates effective November 1, 2008 and colder weather in December 2008 (see Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above); and

·	an increase in cash of $19.0 million in income taxes receivable due to accelerated depreciation and a net operating loss in 2008.

In April 2009, we announced we have filed for regulatory approval from the OPUC to provide an aggregate $32 million refund to our Oregon customers, related to our significant gas cost savings from lower gas prices during the period of November 1, 2008 to March 31, 2009. If approved, we intend to refund this amount to customers through billing credits in the second quarter of 2009. This refund will reduce gross operating revenues and utility margin, but will be offset by a corresponding reduction in cost of gas sold.

In December 2008, we filed an application with the Internal Revenue Service (IRS) for a change in tax accounting method in connection with our routine repairs and maintenance of gas pipelines that are currently being capitalized and depreciated. We anticipate that the IRS will consent to this change during the second or third quarter of 2009. If we receive consent, then we will file a claim for a tax deduction and record current tax benefits and a deferred tax liability, which will result in a cash refund of taxes paid. We estimate the tax refund amount in 2009 for prior years’ taxes paid to be in excess of $15 million related to the routine repairs and maintenance.

Investing Activities

Cash used for investing activities in the first quarter of 2009 totaled $34.1 million, up from $22.5 million for the same period in 2008. Cash requirements for the acquisition and construction of utility plant were $21.6 million in first quarter of 2009, up $2.3 million from $19.3 million for the same period in 2008 primarily due to automated meter reading project costs. Cash requirements for investments in non-utility property were $6.2 million in the first quarter of 2009, primarily related to investments in Gill Ranch, compared to $1.7 million in 2008. Cash used in other investing activities in the first quarter of 2009 totaled $6.3 million, compared to $1.6 million in 2008, with the increase in 2009 primarily due to a $5.8 million restricted cash investment in Gill Ranch.

In 2009, utility capital expenditures are estimated to be between $100 and $110 million, and non-utility capital investments are expected to be between $50 and $70 million for business development projects that are currently in process (see “Strategic Opportunities,” above).

Over the five-year period 2009 through 2013, utility construction expenditures are estimated at between $450 and $500 million. The estimated level of capital expenditures over the next five years reflects continued customer growth, utility storage development at Mist, AMR, technology improvements and utility system improvements, including requirements under the Pipeline Safety Improvement Act of 2002. Most of the required funds are expected to be internally generated over the five-year period and any remaining funding will be obtained through the issuance of long-term debt or equity securities, with short-term debt providing liquidity and bridge financing (see Part II, Item 7., “Financial Condition—Cash Flows—Investing Activities,” in the 2008 Form 10-K).

Our share of the total cost of Gill Ranch is between $160 million and $180 million. As of March 31, 2009, we have spent $19.0 million on our Gill Ranch project.

In 2009 and 2010, Palomar will continue to work on the planning and permitting phase of the Palomar pipeline project. The total cost for planning and permitting is estimated to be between $40 million and $50 million, 50 percent of which is our investment based on our ownership interest. As of March 31, 2009, we had invested $15.5 million in this project. The total cost estimate for the entire 217-mile pipeline, if constructed, is estimated to be between $750 million and $800 million, with our current 50 percent share estimated at between $375 million and $400 million. See "Strategic Opportunities—Pipeline Diversification," above.

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The Palomar pipeline project includes both an east and west segment. Palomar intends to proceed with the construction of the west segment of the pipeline if an LNG terminal is developed. However, the development of LNG terminals along the Columbia River may or may not proceed, dependent upon a variety of factors, including obtaining state and federal permits, securing acceptable financing and economic conditions. Palomar had executed precedent agreements whereby a significant majority of the pipeline capacity was committed to one shipper. In April 2009, Palomar and that shipper replaced their existing precedent agreement with a new agreement for the same amount of capacity and Palomar received cash proceeds which had supported the shipper's obligations under the prior agreement. The cash proceeds received are expected to be applied against project costs. The new agreement provides the shipper will provide a new form of credit support, as determined to be acceptable to Palomar, that is expected to support a portion of the planning and permitting costs as the project develops. The failure to receive acceptable credit support or a failure to provide acceptable ongoing credit support to meet such shipper's obligations may result in Palomar reassessing its commitment to the development of the west segment.

Based on an ongoing review of the Palomar pipeline project, and continuing interest expressed by this shipper, and other potential shippers, PGH determined that the Palomar project was still viable, especially the east segment. As of May 1, 2009, Palomar has binding precedent agreements with two shippers, our own utility and this other shipper, which represents a majority of the current design capacity on the pipeline. We will continue to manage project risks, evaluate project costs and assess the fair value of our investment on a quarterly basis, including a valuation of the available credit support. Further, during 2009 and 2010, PGH will continue to evaluate market conditions and project status to determine if and when to proceed with construction of all or some portion of the project. See Part I, Item 1A., "Risk Factors," in the 2008 Form 10-K.

Financing Activities

Cash used in financing activities in the first three months of 2009 totaled $109.4 million, up from $96.5 million cash used in the same period of 2008. Our short-term debt balances decreased by $172.3 million in the first three months of 2009 compared to a decrease of $88.5 million in 2008. In March 2009, we issued $75 million of MTNs at 5.37 percent, the proceeds of which were primarily used to reduce short-term debt balances. No shares were purchased under our common stock repurchase program, and no long-term debt was redeemed in the three months ended March 31, 2009 and 2008.

Pension Funding Status

We make contributions to our qualified defined benefit pension plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. The Pension Protection Act of 2006 (the Act) established new funding requirements for defined benefit plans. The Act establishes a 100 percent funding target for plan years beginning after December 31, 2008. Our qualified defined benefit pension plans were underfunded by $98.4 million at December 31, 2008. Our minimum contribution requirement during 2009 is estimated to be $17 million to avoid any restrictions on benefit payments. In April 2009, we contributed $25 million. We have no further funding requirements for our qualified plans in 2009, but we may make additional contributions later this year that could bring our total contributions in 2009 up to $40 million. For more information on the funding status of our qualified retirement plans and other postretirement benefits, see Note 7, and Part II, Item 7., “Financial Condition—Pension Cost and Funding Status of Qualified Retirement Plans,” and Part II, Item 8., Note 7, “Pension and Other Postretirement Benefits,” in the 2008 Form 10-K.

We also contribute to a multiemployer pension plan pursuant to our collective bargaining agreement. Our total contribution to the Western States Plan in 2008 amounted to $0.4 million. See Note 7 for further discussion.

Ratios of Earnings to Fixed Charges

For the three and twelve months ended March 31, 2009 and the twelve months ended December 31, 2008, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were 8.74, 3.96 and 3.76, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income. Because a significant part of our business is of a seasonal nature, the ratios for the interim periods are not necessarily indicative of the results for a full year.

Contingent Liabilities

Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies” (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the 2008 Form 10-K). At March 31, 2009, we had a regulatory asset of $67.8 million for environmental costs, which includes $32.0 million of total paid expenditures to date, $29.0 million for additional environmental costs expected to be paid in the future and accrued interest of $6.8 million. If it is determined that both the insurance recovery and future customer rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is made. For further discussion of contingent liabilities, see Note 11.

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Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including commodity supply risk, commodity price risk, interest rate risk, foreign currency risk, credit risk and weather risk (see Part I, Item 1A., “Risk Factors,” and Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk,” in the 2008 Form 10-K). The following are updates to certain of these market risks:

Commodity Price Risk

Natural gas commodity prices are subject to fluctuations due to unpredictable factors including weather, pipeline transportation congestion, potential market speculation and other factors that affect short-term supply and demand. Commodity-price financial swap and option contracts (financial hedge contracts) are used to convert certain natural gas supply contracts from floating prices to fixed, capped or discounted prices. These financial hedge contracts are generally included in our annual PGA filing for cost recovery, subject to a regulatory prudence review. At March 31, 2009 and 2008, notional amounts under these financial hedge contracts totaled $281.9 million and $170.2 million, respectively. If all of the commodity-based financial hedge contracts had been settled on March 31, 2009, a loss of about $116.3 million would have been realized and recorded to a deferred regulatory account (see Note 10). We regularly monitor and manage the financial exposure and liquidity risk of our financial hedge contracts under the direction of our Gas Acquisition Strategies and Policies Committee, which consists of senior management with Audit Committee oversight. Based on the existing open interest in the contracts held, we believe financial exposure to be minimal and existing contracts to be liquid. All of our financial hedge contracts mature on or before October 31, 2010. The $116.3 million unrealized loss is an estimate of future cash flows based on forward market prices that are expected to be paid as follows: $101.4 million in the next 12-month period, and $14.9 million in the following 12-month period. The amount realized will change based on market prices at the time contract settlements are fixed.

Credit Risk

Credit exposure to financial derivative counterparties. Based on estimated fair value at March 31, 2009, our credit exposure relating to commodity hedge contracts reflected an amount we owed of $116.3 million to our financial derivative counterparties. Our financial derivatives policy requires counterparties to have a certain minimum investment-grade credit rating at the time the derivative instrument is entered into, and specific limits on the contract amount and duration based on each counterparty’s credit rating. Some counterparties were downgraded but continue to maintain investment grade ratings (see table below). Due to current market conditions and credit concerns, we continue to enforce strong credit requirements. We actively monitor and manage our derivative credit exposure and place counterparties on hold for trading purposes or require letters of credit or guarantees as circumstances warrant. Our derivative credit risk exposure, which reflects amounts that financial derivative counterparties owe to us, is minimal and all outstanding contracts at March 31, 2009 expire or are expected to settle on or before October 31, 2010.

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

	Financial Derivative Position by Credit Rating
	Unrealized Fair Value Gain (Loss)
Thousands	March 31, 2009			March 31, 2008		Dec. 31, 2008
AAA/Aaa	$	(9,246	)	$	5,102	$	(16,827	)
AA/Aa		(101,516	)		19,452		(122,287	)
A/A		(5,531	)		5,193		(12,006	)
BBB/Baa		-			-		-
Total	$	(116,293	)	$	29,747	$	(151,120	)

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

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

Item 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

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

(b) Changes in Internal Control Over Financial Reporting

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

There have been no changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2009 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. The statements contained in Exhibit 31.1 and Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this Item 4(b).

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PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

Litigation

We are subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, we do not expect that the ultimate disposition of any of these matters will have a material adverse effect on our financial condition, results of operations or cash flows.

For a discussion of certain pending legal proceedings, see Note 11.

Item 1A. RISK FACTORS

There were no material changes from the risk factors discussed in Part I, “Item 1A. Risk Factors,” in our 2008 Form 10-K. In addition to the other information set forth in this report, you should carefully consider those risk factors, which could materially affect our business, financial condition or results of operations. The risks described in the 2008 Form 10-K are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially affect our financial condition, results of operations or cash flows.

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

The following table provides information about purchases by us during the quarter ended March 31, 2009 of equity securities that are registered pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES

					(c)		(d)
	(a)		(b)		Total Number of Shares		Maximum Dollar Value of
	Total Number		Average		Purchased as Part of		Shares that May Yet Be
	of Shares		Price Paid		Publicly Announced		Purchased Under the
Period	Purchased (1)		per Share		Plans or Programs (2)		Plans or Programs (2)
Balance forward						2,124,528	$	16,732,648
01/01/09 - 01/31/09		925	$	41.74		-		-
02/01/09 - 02/28/09		22,836	$	43.99		-		-
03/01/09 - 03/31/09		54,750	$	39.15		-		-
Total		78,511	$	40.59		2,124,528	$	16,732,648

(1)

During the quarter ended March 31, 2009, 21,598 shares of our common stock were purchased on the open market to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan. In addition, 56,913 shares of our common stock were purchased on the open market during the quarter to meet the requirements of our share-based programs. During the three months ended March 31, 2009, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.

(2)

We have a share repurchase program for our common stock under which we purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 31, 2010 to repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million. During the three months ended March 31, 2009, no shares of our common stock were purchased pursuant to this program. Since the program’s inception in 2000 we have repurchased 2.1 million shares of common stock at a total cost of $83.3 million.

Item 6. EXHIBITS

See Exhibit Index attached hereto.

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SIGNATURE

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

NORTHWEST NATURAL GAS COMPANY

(Registrant)

Dated: May 4, 2009

/s/ Stephen P. Feltz

Stephen P. Feltz

Principal Accounting Officer

Treasurer and Controller

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NORTHWEST NATURAL GAS COMPANY

EXHIBIT INDEX

Quarterly Report on Form 10-Q

For Quarter Ended

March 31, 2009

		Exhibit
Document		Number

Computation of Ratio of Earnings to Fixed Charges		12

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

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

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