10-K

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2006

OR

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

For the transition period from                      to                     

Commission file number 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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act). Yes [ X ]    No [    ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. [    ]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [    ]

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [    ]

No [ X ]

As of June 30, 2006, the registrant had 27,547,346 shares of its Common Stock outstanding. The aggregate market value of these shares of Common Stock (based upon the closing price of these shares on the New York Stock Exchange on that date) held by non-affiliates was $1,010,618,119.

Indicate number of shares outstanding of each of registrant’s classes of common stock as of February 23, 2007:

Common Stock 27,256,341

DOCUMENTS INCORPORATED BY REFERENCE

List documents incorporated by reference and the Part of the Form 10-K into which the document is incorporated.

Portions of the Proxy Statement of Company, to be filed in connection with the 2007 Annual Meeting of Shareholders, are incorporated by reference in Part III.

NORTHWEST NATURAL GAS COMPANY

Annual Report to Securities and Exchange Commission

on Form 10-K

For the Fiscal Year Ended December 31, 2006

Table of Contents

PART I		Page
	Glossary of Terms	2
Item 1.	Business	3
	General	3
	Business Segments	3
	Subsidiaries	4
	Gas Supply, Storage and Transportation Capacity	5
	Regulation and Rates	11
	Additions to Infrastructure	14
	Pipeline Safety	15
	Competition and Marketing	15
	Environmental Issues	17
	Employees	18
	Available Information	18
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	22
Item 2.	Properties	22
Item 3.	Legal Proceedings	23
Item 4.	Submission of Matters to a Vote of Security Holders	23
PART II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6.	Selected Financial Data	26
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	61
Item 8.	Financial Statements and Supplementary Data	65
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	112
Item 9A.	Controls and Procedures	112
Item 9B.	Other Information	112
PART III
Item 10.	Directors, Executive Officers of the Registrant and Corporate Governance	113
Item 11.	Executive Compensation	114
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	114
Item 13.	Certain Relationships and Related Transactions, and Director Independence	115
Item 14.	Principal Accountant Fees and Services	115
PART IV
Item 15.	Exhibits and Financial Statement Schedules	116
SIGNATURES		117

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GLOSSARY OF TERMS

Basic earnings per share: earnings applicable to common stock for a period, divided by the average number of shares of common stock outstanding during that period.

Bcf: one billion cubic feet, a volumetric measure of natural gas, roughly equal to 10 million therms.

Btu: British thermal unit, a basic unit of thermal energy measurement. One Btu equals the energy required to raise one pound of water one degree Fahrenheit. One hundred thousand Btu’s equal one therm.

Bypass: a direct connection to the interstate gas pipeline, which circumvents the pipes of the local gas distribution company; usually considered only by large industrial users.

Core utility customers: residential, commercial and industrial firm service customers on our distribution system.

Decoupling: a rate mechanism which is designed to break the link between earnings and the quantity of natural gas consumed by customers. The design is intended to allow the utility to encourage customers to conserve energy while not adversely affecting its earnings due to losses in sales volumes.

Degree days: units of measure that reflect temperature-sensitive consumption of natural gas, calculated by subtracting the average of a day’s high and low temperature from 65 degrees Fahrenheit.

Demand charge: a component in all core utility gas rates that covers the cost of securing pipeline capacity to meet peak demand, whether that capacity is used or not.

Design day: a design day is the maximum anticipated demand on the natural gas distribution system during a 24-hour period assuming weather at an average temperature of 12 degrees Fahrenheit, the coldest day in the last 20 years in our service territory.

Diluted earnings per share: earnings applicable to common stock for a period, divided by the average number of shares of stock that would be outstanding assuming the issuance of common shares for all existing stock based compensation plans with a dilutive impact during the reporting period.

Firm service: natural gas service offered to customers under contracts or rate schedules that will not be disrupted to meet the needs of other customers, particularly during cold weather.

Gas storage: a means of holding gas in reserve for future delivery, either through injection into an underground storage field, or storing it in the form of liquefied natural gas.

General rate case: a periodic filing with state regulators to establish equitable rates and balance the

interests of all classes of customers and our shareholders.

Interruptible service: natural gas service offered to customers (usually large commercial or industrial) under contracts or rate schedules that allow for temporary interruptions to meet the needs of firm service customers.

Liquefied natural gas (LNG): the cryogenic liquid form of natural gas. At temperatures below minus 258 degrees Fahrenheit, natural gas can be stored in a liquid form, which is 600 times more dense than its gaseous form.

Margin: gross revenues less the associated cost of sales. Also referred to as net operating revenues.

Purchased Gas Adjustment (PGA): also known as the gas cost tracker, is a regulatory mechanism for annually adjusting customer rates due to changes in gas commodity costs.

Return on equity (ROE): a measure of corporate profitability, calculated as net income divided by average common stock equity. Authorized ROE refers to the equity rate approved by a regulatory agency for utility investments funded by common stock equity.

Return on invested capital: a measure of profitability calculated by dividing net income before interest expense by average long-term capital.

Sales service: service provided to a customer that receives both natural gas supply and transportation of that gas from the regulated utility.

Therm: the basic unit of natural gas measurement, equal to 100,000 Btu’s. An average residential customer in our service area uses about 700 therms in an average-weather year.

Transportation service: service provided to a customer that secures its own natural gas supply and pays the regulated utility only for use of the distribution system to transport it.

Underground gas storage: storage of natural gas by injection into underground rock formations; historically gas is withdrawn during the winter heating season or during periods of high gas prices.

Utility margin: utility gross revenues less the associated cost of gas and applicable revenue taxes. Also referred to as utility net operating revenues.

Weather normalization: a rate mechanism that allows a utility to adjust customers’ bills during the winter heating season to reduce variations in margin recovery due to fluctuations from average temperatures.

Winter heating season: generally considered to be the period from November through March.

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NORTHWEST NATURAL GAS COMPANY

PART I

ITEM 1. BUSINESS

General

Northwest Natural Gas Company was incorporated under the laws of Oregon in 1910. Our company and its predecessors have supplied gas service to the public since 1859. Since September 1997, we have been doing business as NW Natural.

Business Segments

Local Gas Distribution

We are principally engaged in the distribution of natural gas in Oregon and southwest Washington. In this report our principal business segment is referred to as local gas distribution or utility. Local gas distribution involves purchasing gas from producers, transporting the gas over interstate pipelines from the supply basins to our service territory, and reselling the gas to customers at rates and terms approved by the Oregon Public Utility Commission (OPUC) or by the Washington Utilities and Transportation Commission (WUTC). Gas distribution also includes transporting gas owned by large customers from the interstate pipeline connection, or city gate, to the customers’ facilities for a fee, also approved by the OPUC or WUTC. Approximately 98 percent of our consolidated assets are related to the local gas distribution segment. The OPUC has allocated to us as our exclusive service area a major portion of western Oregon, including the Portland metropolitan area, most of the Willamette Valley and the coastal area from Astoria to Coos Bay. We also hold certificates from the WUTC granting us exclusive rights to serve portions of three southern Washington counties bordering the Columbia River. Gas service is provided in 122 cities and neighboring communities, in 15 Oregon counties, as well as in 14 cities and neighboring communities in three Washington counties. The city of Portland is the principal retail and manufacturing center in the Columbia River Basin, and is a major port for trade with Asia.

At year-end 2006, we had 575,116 residential customers, 60,523 commercial customers and 945 industrial sales customers. Approximately 90 percent of our customers are located in Oregon and 10 percent are in Washington. Industries served include: pulp, paper and other forest products; the manufacture of electronic, electrochemical and electrometallurgical products; the processing of farm and food products; the production of various mineral products; metal fabrication and casting; the production of machine tools, machinery and textiles; the manufacture of asphalt, concrete and rubber; printing and publishing; nurseries; government and educational institutions; and electric generation. No individual customer or industry accounts for a significant portion of our industrial revenues.

Gas Storage

The gas storage business segment (previously referred to as Interstate Gas Storage) includes NW Natural’s underground natural gas storage services to large intrastate and interstate customers using NW Natural’s storage and related transportation capacity that is in excess of the utility’s core (residential, commercial and industrial firm) customer requirements. Additionally, an independent energy marketing company provides asset optimization services to the utility under a contractual arrangement. Approximately 2 percent of our consolidated assets and 9 percent of consolidated net

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income in 2006 are related to the gas storage business segment. For each of the years ended December 31, 2006, 2005 and 2004, this business segment derived a majority of its revenues from five storage customers. The largest of these customers is served under a long-term contract. The total working gas capacity of the Mist underground gas storage facility has been revised from 13.9 Bcf to around 14 Bcf to reflect reservoir performance and incremental growth in certain reservoir pools. Of this capacity, the gas storage business included in this segment has access to about 5 Bcf of capacity while the core utility has access to the remaining 9 Bcf.

Pre-tax income from gas storage and third-party optimization is subject to revenue sharing with core utility customers. In Oregon, 80 percent of the pre-tax income is retained by this segment when the costs of the capacity used have not been included in utility rates, or 33 percent of the pre-tax income is retained when the capacity costs have been included in utility rates. The remaining 20 percent and 67 percent of pre-tax income, respectively, are deferred to a regulatory account for crediting to our core utility customers. We have a similar sharing mechanism in Washington for pre-tax income derived from gas storage services and third-party optimization.

Interstate Gas Storage. This part of the business segment provides firm and interruptible gas storage and related transportation services on NW Natural’s system to several interstate customers. The interstate storage services and maximum rates are authorized by the Federal Energy Regulatory Commission (FERC). The storage capacity used by this business has been developed by NW Natural in advance of core utility customers’ requirements.

Intrastate Gas Storage. In February 2006, we began providing an Oregon firm intrastate gas storage service under an OPUC-approved rate schedule. The firm storage service terms and conditions mirror the firm interstate storage service, except that these customers are located and served in Oregon under an OPUC-approved rate schedule that includes service and site-specific qualifications.

Third Party Optimization. NW Natural has a contract with an independent energy marketing company to optimize the value of our assets, primarily through the use of commodity transactions and capacity release transactions. See Part II, Item 7., “Comparison of Gas Distribution Operations—Business Segments Other than Local Gas Distribution—Gas Storage.”

Other

We have other non-regulated investments, including assets in NNG Financial Corporation (Financial Corporation) (see “Subsidiaries,” below), a Boeing 737-300 aircraft leased to Continental Airlines and miscellaneous other investments in non-regulated activities. Less than 1 percent of our consolidated assets and about 1 percent of 2006 consolidated net income are related to activities in the “Other” business segment.

Subsidiaries

Financial Corporation

We currently operate one direct, active subsidiary, Financial Corporation. Financial Corporation, a wholly-owned subsidiary incorporated in Oregon, holds financial investments including limited partnership interests in two wind power electric generation projects located in California and two low-income housing projects in Portland, Oregon. In January 2005, Financial Corporation sold its limited partnership interests in three solar electric generating plants located in California. Financial

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Corporation also has one active, wholly-owned subsidiary, KB Pipeline Company (KB Pipeline), which owns a 10 percent interest in an 18-mile interstate natural gas pipeline. As a part owner of the pipeline, KB Pipeline is subject to certain regulations enacted by FERC with respect to the Standards of Conduct for Transmission Providers.

Gas Supply, Storage and Transportation Capacity

General

We meet the expected needs of our core utility customers through natural gas purchases from a variety of suppliers. Our supply and capacity plan is based on forecasted system requirements and takes into account estimated load growth by type of customer, attrition, conservation, distribution system constraints, interstate pipeline capacity and contractual limitations and the forecasted movement of customers between bundled sales service and transportation-only service. Sensitivity analyses are performed based on factors such as weather variations and price elasticity effects. We have a diverse portfolio of short-, medium- and long-term firm gas supply contracts that we supplement during periods of peak demand with gas from storage facilities either owned by or contractually committed to us.

Gas Acquisition Strategy

Our goals in purchasing gas for our core utility market consist of:

• Reliability—Ensuring a gas resource portfolio that is sufficient to satisfy core utility customer requirements under design-day weather conditions, as defined in our Integrated Resource Plan (see “Regulation and Rates—Integrated Resource Plan,” below);

• Lowest reasonable cost—Applying strategies to acquire gas supplies at the lowest reasonable cost to utility customers;

• Price stability—Making use of physical assets (e.g. gas storage) and financial instruments (e.g. financial hedge contracts such as price swaps) to manage price variability; and

• Cost recovery—Managing gas purchase costs prudently to minimize the risks associated with regulatory review and recovery of gas acquisition costs.

To achieve those goals, we employ a gas purchasing strategy based upon a diversity of supply, liquidity, price risk management, asset optimization and regulatory alignment, as discussed in more detail below.

Diversity of Supply. There are three means by which we diversify our gas supply acquisitions: regional supply basin, contract types and contract duration.

The following table represents the actual and target purchase percentages from the regional sources of gas available to us:

Regional Supply Basin
Region	2006 Actual		2006-2011 Target
Alberta	41	%	45	%
British Columbia	29	%	30	%
U.S. Rockies	30	%	25	%
Mist gas field	<1	%	<1	%
Total	100	%	100	%

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We believe that gas supplies available in the western United States and Canada are adequate to serve our core utility customers for the foreseeable future, and that our cost of gas generally will track market prices.

We typically enter into gas purchase contracts for:

• year-round baseload supply;

• November–March (winter heating season) baseload supply;

• winter heating season contracts where we have the option to call on all, some or none of the supplies on a daily basis; and

• spot purchases, taking into account forecasted customer requirements, storage injections and withdrawals and seasonal weather fluctuations.

Other less frequent types of contracts include April-October baseload contracts, April-October contracts where the supplier has the option to supply gas to us on a daily basis, and seasonal exchange purchase and sale contracts. In general, we try to maintain a diversified portfolio of purchase arrangements. For example, we use a variety of multi-year contract durations to avoid having to re-contract all supplies every year. See “Core Utility Market Basic Supply,” below.

Liquidity. We purchase our gas supplies at liquid trading points to facilitate competition and price transparency. These trading points include the NOVA Inventory Transfer (NIT) point in Alberta (also referred to as AECO), Huntingdon/Sumas and Station 2 in British Columbia, and various receipt points in the Rocky Mountains.

Price Risk Management. There are four general methods that we currently use for managing gas commodity price risk:

• negotiating fixed prices directly with gas suppliers;

• negotiating financial instruments that exchange the floating price in a physical supply contract for a fixed price (referred to as price swaps);

• negotiating financial instruments that set a ceiling and/or floor price on a floating price contract (referred to as call and put options, respectively); and

• buying gas and injecting it into storage. See “Cost of Gas,” below.

Asset Optimization. We use our gas supply, storage and transportation flexibility to capture opportunities that emerge during the course of the year for gas purchases, sales, exchanges or other means to manage net gas costs. In particular, our Mist underground storage facility provides flexibility in this regard. In addition to our own activities to economically manage our gas supply costs, we contract with an independent energy marketing company to more fully capture optimization opportunities.

Regulatory Alignment. Mechanisms for gas cost recovery are designed to be fair and balanced for customers and shareholders. In general, we do not earn a return on the gas commodity purchased, and we attempt to minimize risks associated with cost recovery through:

• the use of purchased gas adjustment (PGA) mechanisms approved by the OPUC and WUTC (see “Regulation and Rates—Rate Mechanisms,” below);

• aligning customer and shareholder interests through an incentive sharing mechanism for the PGA and asset optimization mechanisms; and

• periodic review of regulatory deferrals with state regulatory commissions and key customer groups.

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Cost of Gas

The cost of gas to supply our core utility market primarily consists of the purchase price paid to suppliers, charges paid to pipelines to transport the gas to our distribution system and gains or losses related to hedge contracts entered into in connection with supply of gas to core customers. While the rates for pipeline transportation and storage services are subject to federal regulation, the purchase price of gas is not.

Supply cost. Natural gas commodity prices increased dramatically over the last six years due to growing demand for natural gas, especially for power generation, stagnant North American gas production, surging alternative fuel prices, and the impact in 2005 of hurricane activity that affected oil and natural gas production in the Gulf of Mexico. We are in a favorable position with respect to gas production because of the proximity of our service territory to supply basins in western Canada and the Rocky Mountains, where some growth in gas production is expected to continue for the foreseeable future.

Transportation cost. Pipeline transportation rates had been relatively stable in recent years, but two of the five major pipelines used by NW Natural filed for significant rate increases in 2006. Pipeline transportation rate increases are generally recoverable through our state-approved PGA mechanisms. See “Regulation and Rates—Interstate Pipeline Rate Cases,” below.

Hedging. We seek to mitigate the effects of higher gas commodity prices and price volatility on core utility customers by using our underground storage facilities strategically, by entering into natural gas commodity-based financial hedge contracts, and by crediting gas costs with margin revenues derived from off-system sales of commodity supplies and released transportation capacity in periods when core utility customers do not fully utilize firm pipeline transportation capacity and gas supplies.

Managing the Cost of Gas

We manage natural gas commodity price risk through an active hedging program in which we enter into either fixed price physical supply contracts or fixed price financial derivatives contracts. The financial contracts make up a majority of our commodity price hedging activity and these contracts are with a variety of investment-grade credit counterparties, typically with credit ratings of AA- or higher. See Part II, Item 7A., “Market Risk—Credit Risk—Credit exposure to financial derivative counterparties.” Under this program, we enter into commodity swap, put and call option agreements for the coming year and up to three years into the future. Gains or losses from financial commodity hedge contracts are treated as reductions or increases to the cost of gas. The intended effect of this program is to lock in prices for a majority of our gas supply portfolio for the following gas contract year, including at least 50 percent of the expected heating season purchases, based on the market prices and forecasted purchase requirements prevailing at the time the financial agreements are entered into. Prices have been secured for less than 50 percent of gas purchases in subsequent gas contract years, but maintaining some longer term hedging in future years helps to stabilize future gas costs and reduces variations in annual customer rate changes.

In addition to the volumes for which prices are locked in through financial hedges, we also use gas storage as a physical hedge. We purchase and inject about 15 percent of our annual gas supply requirements into storage during the summer when gas prices are historically lower. That gas is stored for withdrawal during the winter months in five different storage facilities. We own and operate three of these storage facilities located within our service territory, which eliminates the need for additional upstream pipeline capacity and provides significant cost savings.

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Source of Supply—Design Day Sendout

The effectiveness of our gas supply program ultimately rests on whether we provide reliable service at a reasonable cost to our core customers. To assure reliability, we base our plans on being able to meet the supply needs on the coldest weather experienced over the last 20 years in our service territory. We start with the coldest overall heating season and then modify it to include the coldest weather day over that same 20 year period. This coldest “design day” is the maximum anticipated demand on the natural gas distribution system during a 24-hour period, which currently assumes weather at an average temperature of 12 degrees Fahrenheit. We assume that all interruptible customers will be curtailed on the design day. Our projected sources of delivery for design day firm utility customer sendout total approximately 8.9 million therms. We are currently capable of meeting 63 percent of our firm customer design day requirements with storage and peaking supply sources located within or adjacent to our service territory. Optimal utilization of storage and peaking facilities on our design day reduces the dependency on firm transportation. On January 5, 2004, we experienced our current-record firm customer sendout of 7.2 million therms, and a total sendout of 8.9 million therms, on a day that was approximately 9 degrees Fahrenheit warmer than the design day temperature. That January 2004 cold weather event lasted about 10 days, and the actual firm customer sendout each day provided data indicating that load forecasting models required very little re-calibration. Accordingly, we believe that our supplies would be sufficient to meet firm customer demand if we are to experience design day conditions.

The following table reflects the sources of supply that are projected to be used to satisfy the design day sendout for the 2006-2007 winter heating season:

Projected Sources of Supply for Design Day Sendout
Sources of Supply	Therms (in milions)	Percent
Firm Contracts	3.25	37
Off-system storage	1.06	12
Mist underground storage (utility only)	2.30	26
LNG storage	1.80	20
Recall agreements	0.45	5
Total	8.86	100

We believe the combination of the natural gas supply purchases under contract, our peaking supplies and the transportation capacity held under contract on the interstate pipelines are sufficient to satisfy the needs of existing customers and are positioned to grow, as needed, to meet requirements in future years.

Core Utility Market Basic Supply

We purchase gas for our core utility customers from a variety of suppliers located in the western United States and Canada. As shown above, about 70 to 75 percent of our supply comes from Canada, with the balance coming primarily from the U.S. Rocky Mountain region. At January 1, 2007, we had 21 firm contracts with 10 suppliers and remaining terms ranging from three months to eight years, which provide for a maximum of 1.7 million therms of firm gas per day during the peak winter heating season and 1.2 million therms per day during the remainder of the year. These contracts have

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a variety of pricing structures and purchase obligations. During 2006, we purchased 833 million therms of gas under the following contract durations:

Contract Duration (primary terms)	Percent of Purchases
Long-term (one year or longer)	54	%
Short-term (more than one month, less than a year)	19	%
Spot (less than one month)	27	%
Total	100	%

We regularly renew or replace our expiring long-term gas supply contracts with new agreements from a variety of existing and new suppliers. Aside from the optimization of our core utility gas supplies by the independent energy marketing company (see “Gas Acquisition Strategy—Asset Optimization,” above), four suppliers each amount to between 12.5 percent and 14.8 percent of our average daily contract volumes. Firm year-round supply contracts have remaining terms ranging from one to eight years. All term gas supply contracts use price formulas tied to monthly index prices, primarily at the NIT trading point in Alberta. We hedge a majority of these contracts each year using financial instruments as part of our gas purchasing strategy (see “Managing the Cost of Gas,” above).

In addition to the year-round contracts, we continue to contract in advance for firm gas supplies to be delivered only during the winter heating season primarily under short-term contracts. During 2006, new short-term purchase agreements were entered into with four suppliers. These agreements have a variety of pricing structures and provide for a total of up to 500,000 therms per day during the 2006-2007 heating season. We intend to enter into new purchase agreements in 2007 for equivalent volumes of gas with our existing or other similar suppliers, as needed, to replace short-term and one-year contracts that will expire during 2007.

We also buy gas on the spot market as needed to meet demand. We have flexibility under the terms of some of our firm supply contracts enabling us to purchase spot gas in lieu of firm contract volumes, thereby allowing us to take advantage of favorable pricing on the spot market from time to time.

We continue to purchase gas from a non-affiliated producer in the Mist gas field in Oregon. The production area is situated near our underground gas storage facility. The price for this gas is tied to our weighted average cost of gas. Current production is approximately 10,000 therms per day from about 14 wells, supplying less than 1 percent of our total annual purchase requirements. Production from these wells varies as existing wells are depleted and new wells are drilled.

Core Utility Market Peaking Supply and Storage

We supplement our firm gas supplies with gas from storage facilities either owned or contractually committed to us. Gas is generally purchased and stored during periods of low demand for use during periods of peak demand. In addition to enabling us to meet our peak demand, these facilities make it possible to lower the annual average cost of gas by allowing us to minimize our pipeline transportation contract demand costs and to purchase gas for storage during the summer months when prices are historically lower.

Underground storage. We have contracts with Northwest Pipeline Corporation (Northwest Pipeline) for firm gas storage services from an underground storage facility at Jackson Prairie near Chehalis, Washington, and an LNG facility at Plymouth, Washington. Together, these facilities

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provide us with daily firm deliverability of about 1.1 million therms and total seasonal capacity of about 16 million therms. Separate contracts with Northwest Pipeline provide for the transportation of these storage supplies to our service territory. All of these contracts have reached the end of their primary terms, but we have exercised our renewal rights that allow for annual extensions at our option.

We also provide daily and seasonal peaking from our underground gas storage facility in the Mist gas field. Including the latest expansions in 2005, this facility has a maximum daily deliverability of 4.4 million therms and a total working gas capacity of about 14 Bcf. In September 2004, we completed our South Mist pipeline extension project, which is a utility transmission pipeline from our Mist gas storage field to growing portions of our distribution service area. Also in 2004, a total of 400,000 therms per day of Mist storage capacity, which had been available for the non-utility gas storage business, was recalled and committed to use for core utility customers. This was the first instance of returning capacity that had been developed in advance of core utility customers’ needs for interstate gas storage services under the regulatory agreement with the OPUC. Under this agreement, storage capacity is recalled as needed and added to utility rate base, at our original cost less accumulated depreciation, with a corresponding rate increase to customers to reflect the cost of service. No additional recalls of Mist capacity were required in 2005 or 2006. The core utility market now has 2.3 million therms per day of deliverability and approximately 9 Bcf of working gas committed from the Mist storage facility.

In December 2005, we completed our latest expansion of the Mist gas storage facility. This investment increased the facility’s incremental capacity and total daily delivery capacity. All of this expansion is currently being used to serve growth in the gas storage market. Ultimately, this expansion also will be available to serve the needs of our core utility customers. The expansion increased working gas capacity at Mist to about 14 Bcf, with 5 Bcf allocated to the gas storage business segment. As the needs of core utility customers grow, existing storage capacity will be recalled and transferred for use by core utility customers and tracked into customer rates. As storage capacity is recalled to serve core utility customers, new storage capacity can be developed. Additional expansion at Mist is currently underway for customer use in 2007.

LNG. We own and operate two LNG plants in our service territory that liquefy gas during the summer months for storage until the peak winter heating season. These two plants provide a maximum combined daily deliverability of 1.8 million therms and a total seasonal capacity of 17 million therms.

Recallable capacity. We also have contracts with one electric generator and two industrial customers that together provide an additional 52,000 therms per day of year-round upstream capacity, plus 450,000 therms per day of recallable capacity and supply. Two of these three contracts renew from year to year, while the third will expire in 2010.

Transportation

Dependence on a Single Transportation Pipeline. Our distribution system is directly connected to a single interstate pipeline, Northwest Pipeline. Although we are dependent on a single pipeline, the pipeline is bi-directional as it transports gas into the Portland metropolitan market from two directions: (1) the north, which brings supplies from British Columbia and Alberta supply basins; and (2) the east, which brings supplies from Alberta as well as the Rocky Mountain supply basins. The need for pipeline transportation diversity has been underscored by past Northwest Pipeline ruptures and the resulting federal order in 2003 that required Northwest Pipeline to replace its 26-inch mainline from the Canadian

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border to our service territory. That replacement project was completed by Northwest Pipeline in November 2006. We are pursuing options to further diversify our pipeline transportation paths. Specifically, we are currently evaluating a potential pipeline project that would connect TransCanada Pipelines Limited’s (TransCanada) Gas Transmission Northwest (GTN) interstate transmission line to our gas distribution system. This project could provide an alternate transportation path for gas purchases in Alberta that currently move through the Northwest Pipeline system.

Rates. Rates for pipeline transportation are established by FERC for service under long-term transportation agreements with the U.S. interstate pipelines and by Canadian federal or provincial authorities for service under agreements with the Canadian pipelines over which we ship gas.

Transportation Agreements. The largest of our transportation agreements with Northwest Pipeline extends through 2013 and provides for firm transportation capacity of up to 2.1 million therms per day. This agreement provides access to natural gas supplies in British Columbia and the U.S. Rocky Mountains.

Our second largest transportation agreement with Northwest Pipeline extends through 2011. It provides 1.0 million therms per day of firm transportation capacity from the point of interconnection of the Northwest Pipeline and GTN systems in eastern Oregon to our service territory. GTN’s pipeline runs from the U.S./Canadian border through northern Idaho, southeastern Washington and central Oregon to the California/Oregon border. We have firm long-term capacity on GTN and two upstream pipelines in Canada, which, with GTN, are business units of TransCanada, to match this amount of Northwest Pipeline capacity northward into Alberta, Canada.

We also have an agreement with Northwest Pipeline that extends through 2013 for approximately 350,000 therms per day of firm transportation capacity. This agreement accesses gas supplies in the U.S. Rocky Mountain region.

In addition, we have firm long-term pipeline transportation contracts with two other major transporters. A contract with Duke Energy Gas Transmission (formerly Westcoast Energy, Inc.) extends through October 2014 and provides approximately 600,000 therms per day of firm gas transportation from Station 2 in northern British Columbia to the Huntingdon/Sumas connection with Northwest Pipeline at the U.S./Canadian border. A contract with Terasen Gas extends through October 2020 and provides approximately 470,000 therms per day of firm gas transportation from southeastern British Columbia to the same Huntingdon/Sumas connection with Northwest Pipeline. Our capacity with Terasen Gas is matched with companion contracts for pipeline capacity on the TransCanada BC System and NOVA system in British Columbia and Alberta, allowing purchases to be made from the gas fields of Alberta, Canada. See “Regulation and Rates—Interstate Pipeline Rate Cases,” below.

Regulation and Rates

We provide local distribution gas utility service in Oregon and Washington and, accordingly, we are subject to state regulation with respect to, among other matters, rates, systems of accounts and issuance of securities by the OPUC and the WUTC. Local distribution service in Oregon represents over 90 percent of the utility’s revenues.

NW Natural is exempt from FERC jurisdiction under Sections 1(b) and 1(c) of the Natural Gas Act (the Hinshaw exemption). We provide FERC-regulated storage services to interstate customers pursuant to a limited jurisdiction certificate from FERC.

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General Rate Cases

Our most recent general rate increase in Oregon authorized rates designed to produce a return on shareholders’ equity (ROE) of 10.2 percent and was effective September 1, 2003. Our most recent general rate case in Washington authorized a revenue increase of $3.5 million per year but did not specifically authorize an ROE and was effective July 1, 2004.

In May 2005, we reached a settlement with the FERC staff and all intervenors with respect to our rate case filed in January 2005 related to Mist interstate storage service. The settlement provided for a small net increase in the maximum rates for our interstate storage. These new maximum rates are designed to reflect updated costs related to development of the Mist gas storage facility since 2001 and costs associated with the South Mist pipeline extension project. The new rates were effective July 1, 2005.

Rate Mechanisms

Purchased Gas Adjustment. Rate changes are applied each year under the PGA tariff mechanisms in Oregon and Washington to reflect changes in the total costs of natural gas commodity. The OPUC and the WUTC approved rate increases on October 25, 2006 that became effective on November 1, 2006, compared to October 1 in the prior year. The effect of the rate changes was to increase the average monthly bills of Oregon residential sales customers by 3.5 percent and those of Washington residential sales customers by 2.6 percent.

Under the current PGA mechanisms, we collect an amount for purchased gas costs based on estimates included in rates. If the actual purchased gas costs differ from the amounts included in rates, we are required to defer a majority of that difference and pass it on to customers as an adjustment to future rates. As part of an incentive mechanism in Oregon, the utility recognizes in current earnings either a charge to expense for 33 percent of the higher cost of gas sold, or a credit to expense for 33 percent of the lower cost of gas sold. In Washington, the PGA deferral is 100 percent of the higher or lower actual cost of gas sold.

In October 2006, the OPUC approved a modification to our PGA tariff, effective November 1, 2006, which provides that we use actual recoveries of gas costs in revenues billed (instead of using estimated gas costs incorporated in rates) compared to actual purchased gas costs to determine our PGA deferral. The effect of the new method is that changes in our line loss expense due to changes in unaccounted for gas volumes are deferred and included in the annual PGA mechanism. However, consistent with our prior PGA sharing mechanism, 67 percent of any cost differences for Oregon volumes is deferred for refund or recovery in customer rates in subsequent periods, while the remaining 33 percent is included in current earnings.

The OPUC has begun a formal review of the PGA process, which will cover portfolio requirements, incentive sharing levels and filing requirements, among other items. The investigation is expected to be completed in early 2008. Implementation of any changes to the PGA mechanism is expected in the 2008 PGA filing.

Conservation Tariff. In October 2002, the OPUC authorized the implementation of a “conservation tariff,” which is a rate mechanism designed to adjust margin for changes in average consumption patterns due to residential and commercial customers’ conservation efforts. The tariff is a partial decoupling mechanism that is intended to break the link between earnings and the quantity of gas consumed by customers, removing any incentive for the utility to discourage customers’

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conservation efforts. On average, residential and commercial customers have continued to reduce energy consumption over the past several years in response to the impact of higher energy prices on their utility bills and an increased awareness of energy efficiency measures and programs. In Washington, customer use is not covered by a conservation tariff, and as such our utility earnings are affected by increases and decreases in usage based on customers’ conservation efforts. Washington customers account for about 10 percent of utility revenues.

The Oregon conservation tariff includes two components: (1) a price elasticity adjustment, which adjusts rates annually for expected increases or decreases in customer volumes due to annual changes in commodity costs or periodic changes in our general rates; and (2) a conservation adjustment calculated on a monthly basis to account for deviations between actual and expected volumes (also referred to as the decoupling adjustment). The margin adjustment resulting from differences between actual and expected volumes under the decoupling component is recorded to a deferral account, which is included in the next year’s annual PGA. Baseline consumption was determined by customer consumption data used in the 2003 Oregon general rate case, adjusted for new customers. See Part II, Item 7., “Results of Operations—Comparison of Gas Distribution Operations.”

In 2005, an independent study to measure the Oregon tariff mechanism’s effectiveness recommended continuation of the conservation tariff with minor modifications. In 2005 and 2006, the OPUC approved the continuation of the conservation tariff through September 30, 2009 and increased the mechanism’s coverage from a partial decoupling of 90 percent of residential and commercial gas usage to a full decoupling of 100 percent.

Weather Normalization. In November 2003, the OPUC authorized, and the utility implemented, a weather normalization mechanism in Oregon that helps stabilize utility margins by adjusting residential and commercial customer billings based on temperature variances from average weather. The current normalization mechanism is applied to our residential and commercial customers’ bills between December 1 and May 15 for each heating season. The mechanism adjusts the margin component of customers’ rates to reflect “average” weather using the 25-year average temperature for each day of the billing period. Daily average temperatures and 25-year average temperatures are based on a set point temperature of 59 degrees Fahrenheit for residential customers and 58 degrees Fahrenheit for commercial customers. We do not have a weather normalization mechanism approved for our Washington customers, which account for about 10 percent of our utility revenues.

Excess Earnings Test. The OPUC’s annual formal review process to test for excess earnings ensures that we are allowed to pass through 100 percent of prudently incurred gas costs into rates. We are subject to an excess earnings test requirement in which we retain all of our earnings up to a threshold level equal to our authorized ROE of 10.2 percent plus 300 basis points. Revenues equivalent to 33 percent of any earnings above the threshold are required to be refunded to customers. The excess earnings threshold is subject to adjustment up or down each year based on movements in long-term interest rates. In 2006 and 2005, the threshold after adjustment was 13.44 percent and 13.32 percent, respectively. No amounts were required to be refunded to customers as a result of the 2005 or 2004 earnings test. We do not expect any amounts to be refunded to customers as a result of the 2006 earnings test, which will be reviewed by the OPUC during the second quarter of 2007. In Washington, we are not subject to an annual excess earnings test, and 100 percent of all prudently incurred gas costs are passed through into customer rates.

Recent Changes in Industrial Tariffs. In August 2006, the OPUC and WUTC approved tariff changes to the service options for our major industrial accounts. The changes set out additional

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parameters to provide more certainty in the level of gas supplies we will need to acquire to serve this customer group. The parameters include an annual election period, special pricing provisions for out-of-cycle changes and a requirement that customers on our annual weighted average cost of gas tariff complete the term of their service election.

Pipeline Integrity Cost Recovery. In July 2004, the OPUC approved our application relating to the accounting treatment and full recovery for the cost of the pipeline integrity management program, as mandated by the Pipeline Safety Improvement Act of 2002 and related rules adopted by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration. The accounting and rate treatment for these costs extends through September 30, 2008 and may be reviewed for potential extension after that date. We do not have any special accounting or rate treatment for pipeline integrity costs incurred in the state of Washington.

Interstate Pipeline Rate Cases

On June 30, 2006, the two interstate pipeline companies that provide natural gas transportation to our distribution system filed general rate increase cases with the FERC. See Part II, Item 7., “Results of Operations—Regulatory Matters—Interstate Pipeline Rate Cases”. Increases in interstate pipeline transportation expenses are subject to our PGA deferral mechanism and are 100 percent passed-through to customers in both Oregon and Washington. Pipeline transportation demand charges are not subject to the 33 percent incentive sharing mechanism in Oregon. Both of these increases in pipeline transportation rates were included in our 2006 PGA rates. In February 2007, Northwest Pipeline filed a settlement proposal with the FERC that would resolve all issues with the active parties and would result in an increase in our transportation rates of about $12.0 million. Amounts collected from our utility customers in excess of this settlement amount will be deferred and returned to customers in our next PGA rate filing in late 2007.

Integrated Resource Plan

The OPUC and WUTC have implemented integrated resource planning processes under which utilities develop plans defining alternative growth scenarios and resource acquisition strategies. Our most recent integrated resource plan was filed in Oregon and Washington in 2005. Elements of the plan included:

• an evaluation of supply and demand resources;

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

• a primary goal of “least cost” service; and

• consistency with state energy policy.

Although the OPUC’s order acknowledging the integrated resource plan does not constitute ratemaking approval of any specific resource acquisition or expenditure, the OPUC generally indicates that it would give considerable weight in prudency reviews to utility actions that are consistent with acknowledged plans. Elements of our draft integrated resource plan demonstrate that the continued development of the Mist underground gas storage facility is the least-cost option for serving customer growth. We expect to file an updated plan in 2007.

Additions to Infrastructure

We expect a high level of capital expenditures for additions to infrastructure over the next five years, reflecting projected customer growth, technology, system replacement, improvement and

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reinforcement projects and the development of additional gas storage facilities. Estimated capital expenditures in 2007 total about $110 million, and for the years 2007-11 capital expenditures are estimated at between $500 and $600 million. We continue to be one of the fastest growing gas utilities in the nation (see “Competition and Marketing,” below). In 2006, our customer base grew by more than 3 percent for the 20^th year in a row.

Pipeline Safety

The Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (2006 Act) was signed into law in December 2006. The 2006 Act mandates certain standards related to our distribution lines, including a development of integrity management programs for those distribution pipelines. We do not anticipate any material impacts during 2007, but do expect changes related to the 2006 Act to begin to impact us in 2008.

The Pipeline Safety Improvement Act of 2002 (Act) and related regulations require gas transmission pipeline operators to identify lines located in High Consequence Areas (HCAs) and develop integrity management programs to periodically inspect the integrity of the pipelines and make repairs or replacements as necessary to ensure the ongoing safety of the pipelines. The legislation and related pipeline safety regulations require us to complete inspection of 50 percent of the highest risk pipelines located in our HCAs within the first five years, and the remaining covered pipelines within 10 years, of the date of enactment. We are also required to re-inspect the covered pipelines every seven years from the date of the previous inspection for the life of the pipelines. We have met the first major milestone required by the Act and are on track to complete the next milestone, which is to complete the inspection of 50 percent of our highest risk transmission pipelines by the end of 2007.

Effective January 12, 2005, we assumed responsibilities as operator of an approximately 60-mile pipeline that transports gas from Northwest Pipeline to Coos County, Oregon. The pipeline is owned by Coos County, and we have an agreement to operate the pipeline and related lateral pipelines that runs yearly until terminated by either party. The pipeline safety requirements of the Act apply to us as operator of that pipeline.

In 2001, we entered into a stipulation with the OPUC for an enhanced pipeline safety program that includes an accelerated bare steel replacement program and a geo-hazard safety program. The bare steel program accelerates the replacement of our bare steel piping over 20 years instead of 40 years and allows us to receive rate treatment for costs associated with the program exceeding $3 million per year. The geo-hazard component of the safety program expired on December 31, 2006. It included the identification, assessment and remediation of risks to piping infrastructure created by landslides, washouts, earthquakes or similar occurrences, and allowed us to receive deferred rate treatment for costs associated with the program. Although the regulatory authority for the geo-hazard safety program expired, we received approval from the OPUC to defer the costs up to $2.5 million associated with a specific remediation project, which is expected to be completed in 2007.

Competition and Marketing

Competition with Other Energy Products

We have no direct competition in our service area from other natural gas distributors. However, for residential customers’ heating needs, we compete with electricity, fuel oil, propane and, to a lesser extent, wood. We also compete with electricity and fuel oil for commercial applications. In the

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industrial market, we compete with all forms of energy, including gas-to-gas competition from third-party sellers of natural gas commodity. Competition among these forms of energy is based on price, reliability, efficiency and performance.

The slight competitive price advantage of natural gas over electricity was maintained in 2006 as natural gas commodity prices began to moderate and electricity prices remained stable in both the residential and commercial markets. The current price advantage varies due to differences in retail electric rates between investor-owned utilities, where we have maintained a moderate price advantage, and public utilities, where our price advantage, if any, is marginal. In 2006, although electricity prices continued to become more competitive primarily due to higher gas prices and improving end use technology for heat pumps, natural gas retained its relative price advantage compared to electricity provided by the investor-owned utilities that serve approximately 75 percent of the homes in our Oregon service area. We expect to maintain a price advantage compared to electricity from the investor-owned electric utilities in part because a growing portion of the electricity sold by these utilities is generated using natural gas.

Residential and Commercial Markets

The relatively low market saturation of natural gas in residential single-family dwellings in our service territory, estimated at approximately 50 percent, together with the price advantage of natural gas compared with electricity in most areas and our operating convenience over fuel oil, provides the potential for continuing growth from residential and commercial conversions. In 2006, 18,449 net residential customers (after subtracting disconnected or terminated services) were added, primarily from single- and muti-family new construction, but also included existing residential housing that converted from oil, electric or propane appliances to natural gas. The net increase of all new customers added in 2006 was 19,421. This represents a growth rate of 3.1 percent, which is about twice the national average for local gas distribution companies as reported by the American Gas Association.

Industrial Markets

As a result of the deregulation and restructuring of the energy markets during the past two decades, the natural gas industry, including producers, interstate pipelines and local gas distribution companies, has undergone significant changes. Traditionally, local gas distribution companies sold a “bundled” product that included both the natural gas commodity and delivery to the end-use customer’s meter. However, beginning in the late 1980s, large industrial customers sought to achieve savings by procuring their own supplies of natural gas from producers and contracting with pipelines and local gas distribution companies for transportation of natural gas to their facilities. These changes were intended to promote competition where it was economically beneficial to consumers.

Competition to serve the industrial and large commercial market in the Pacific Northwest has been relatively steady since the early 1990s in terms of numbers and types of competitors. Competitors consist of gas marketers, oil/propane sellers and electric utilities. Wood-based fuels continue to lose market share in these markets primarily due to environmental concerns and restrictions.

The OPUC and WUTC have approved transportation tariffs under which we may contract with customers to deliver customer-owned gas. Transportation tariffs available to industrial customers are priced at our cost of providing transportation service. Generally, we are unaffected financially if industrial customers transport customer-owned gas rather than purchasing gas directly from us, as long as they remain on a tariff or contract with the same quality of service. This is because we do not

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generally make any margin on the sale of the gas commodity. However, industrial customers may select between firm and interruptible service, among other different levels or qualities of service, and these choices can positively or negatively affect margin. The relative level and volatility of prices in the natural gas commodity markets, the availability of interstate pipeline capacity to ship customer-owned gas and the cost structure embedded in our industrial rates are among the primary factors that have caused some industrial customers to alternate between sales and transportation service or between higher and lower qualities of service.

We redesigned our industrial rates in Oregon and Washington as part of our general rate cases in 2003 and 2004, respectively, in order to better reflect relative costs of service and to become more competitive in the industrial market. In August 2006, the OPUC and WUTC approved further tariff changes to the service options for our industrial accounts. The changes set out additional parameters that give us more certainty in the level of gas supplies we will need to purchase in order to serve this customer group. The parameters include an annual election cycle period, special pricing provisions for out-of-cycle changes and the requirement that customers on our annual weighted average cost of gas tariff complete the agreed upon term of their service. In the case of customers switching out-of-cycle from transportation to sales service, the customer will be charged the cost of incremental gas supply under our regulatory tariff.

We have negotiated special transportation service agreements with some of our largest industrial customers. These special agreements are designed to provide transportation rates that are competitive with the customer’s alternative capital and operating costs of installing direct connections to Northwest Pipeline’s interstate pipeline system, which would allow them to bypass our gas distribution system. These agreements generally prohibit bypass during their terms. Due to the cost pressures that confront a number of our largest customers competing in global markets, bypass continues to be a threat. Although we do not expect a significant number of our large customers to bypass our system in the foreseeable future, we may experience further deterioration of margin associated with customers’ transfers to contracts with pricing designed to be competitive with bypass.

Environmental Issues

Properties and Facilities

We have properties and facilities that are subject to federal, state and local laws and regulations related to environmental matters. These evolving laws and regulations may require expenditures over a long timeframe to control environmental effects. Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. These factors include, but are not limited to, the following:

• the complexity of the site;

• changes in environmental laws and regulations at the federal, state and local levels;

• the number of regulatory agencies or other parties involved;

• new technology that renders previous technology obsolete, or experience with existing technology that proves ineffective;

• the ultimate selection of a particular technology;

• the level of remediation required; and

• variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site.

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We own or previously owned properties currently being investigated that may require environmental response, including a property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (Gasco site), a property adjacent to the Gasco site that is now the location of a manufacturing plant owned by Siltronic Corporation (Siltronic site), and an area adjacent to the Gasco and the Siltronic sites along a segment of the Willamette River that has been listed by the U.S. Environmental Protection Agency as a Superfund site for which we have been identified as one of a number of potentially responsible parties (Portland Harbor site). We do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial condition or results of operations; however, if it is determined that both the insurance recovery and future rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is made and could have a material impact on our financial condition or results of operations. See Part II, Item 8, Note 12, to the accompanying Consolidated Financial Statements for a further discussion of potential environmental responses and related costs.

Future Environmental Issues

We recognize that our business is likely to face future carbon constraints. A variety of legislative and regulatory measures to address greenhouse gas emissions are in various phases of discussion or implementation. These include the proposed international standards (Kyoto Protocol), proposed federal legislation and proposed or enacted state actions to develop statewide or regional programs, each of which have imposed or would impose reductions in greenhouse gas emissions. The outcome of federal and state climate change initiatives cannot be determined at this time, but these initiatives could result in a variety of regulatory programs including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could result in increased costs associated with operating and maintaining our facilities, could increase other costs to our business and could impact the prices we charge our customers. Because natural gas is a fossil fuel with a low carbon content, it is possible that future carbon constraints could create additional demand for natural gas, both for electric production and direct use in homes and businesses. We have actively participated in policy development through the Oregon Governor’s Task Force on Climate Change and are leading efforts within the American Gas Association to promote the enactment of fair climate change legislation. We recently created an Environmental Policy and Sustainability Department with responsibility for engaging in policy development and identifying ways to reduce greenhouse gas emissions associated with our operations.

Employees

At December 31, 2006, we had 1,211 employees, of which 815 were members of the Office and Professional Employees International Union (OPEIU), Local No. 11, AFL-CIO. We have a labor agreement (Joint Accord) with members of OPEIU covering wages, benefits and working conditions that will expire on May 31, 2009.

Available Information

We file annual, quarterly and special reports and other information with the Securities and Exchange Commission (SEC). We make available on our website (http://www.nwnatural.com), free of charge, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, as well as proxy materials, filed or furnished pursuant to Section 13(a) or 15(d) and Section 14 of the Securities Exchange Act of 1934, as amended (Exchange Act), as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

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We have adopted a Code of Ethics for all employees and a Financial Code of Ethics that applies to senior financial employees, both of which are available on our website. Our Corporate Governance Standards, Director Independence Standards, charters of each of the committees of the Board of Directors and additional information about us are also available on the website.

Copies of these documents may be requested, at no cost, by writing or calling Shareholder Services, NW Natural, One Pacific Square, 220 N.W. Second Avenue, Portland, Oregon 97209, telephone 503-226-4211.

Our Chief Executive Officer certified to the New York Stock Exchange (NYSE) on June 13, 2006 that, as of that date, he was not aware of any violation by the company of NYSE’s corporate governance listing standards, and that we had filed with the SEC, as exhibits 31.1 and 31.2 to our Annual Report on Form 10-K for the year ended December 31, 2005, the certificates of the Chief Executive Officer and the Chief Financial Officer certifying the quality of NW Natural’s internal control over financial reporting and public disclosures. For the year-ended December 31, 2006, the certificates of the Chief Executive Officer and the Chief Financial Officer are filed with this report as Exhibits 31.1 and 31.2.

ITEM 1A. RISK FACTORS

Our business and financial results are subject to a number of risks and uncertainties, including those set forth below and in other documents we file with the SEC.

Regulatory risk. The rates we charge customers for gas distribution services are established by the OPUC and the WUTC. The failure to approve rates which provide for recovery of our costs and an adequate return on invested capital may adversely impact our financial condition and results of operations.

The rates and terms at which the utility resells gas to its customers or transports gas owned by large customers from the interstate pipeline connection to the customers’ facilities must be approved by the OPUC or the WUTC. The rates are designed to allow us to recover costs of providing such services and to earn an adequate return on our capital investment. We expect to continue to make significant capital expenditures to expand and improve our distribution system. The failure of the OPUC or the WUTC to approve on a timely basis requested rate increases to recover increased costs or to allow an adequate return could adversely impact our financial condition and results of operations.

Gas prices. Higher natural gas commodity prices and fluctuations in the price of gas may adversely affect our earnings.

In recent years, natural gas commodity prices have increased dramatically due to growing demand, especially for power generation, and stagnant North American gas production. In Oregon and in Washington, the utility has PGA tariffs which provide for annual revisions in rates resulting from changes in the cost of purchased gas. The Oregon PGA tariff provides that 33 percent of any difference between the actual purchased gas costs and the actual recoveries of gas costs in rates be recognized as current income or expense. Accordingly, higher gas costs than those assumed in setting rates can adversely affect our results of operations.

The OPUC has begun a formal review of the PGA process which will cover portfolio requirements, incentive sharing levels and filing requirements, among other items. The investigation is

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expected to be completed in early 2008. Implementation of any changes to the PGA mechanism is expected in the 2008 PGA filing.

Notwithstanding our current rate structure, higher gas costs could result in increased pressure on the OPUC or the WUTC to seek other means to reduce rates, which also could adversely affect our results of operations.

Business risk. Our risk management policies and hedging activities cannot eliminate the risk of commodity price movements and may expose us to additional liabilities for which rate recovery may be disallowed.

Our gas purchasing requirements expose us to risks of commodity price movements. We attempt to manage our exposure through enforcement of established risk limits and risk management procedures, including hedging activities. These risk limits and risk management procedures may not always work as planned and cannot eliminate the risks associated with gas purchasing and hedging. These practices are subject to regulatory review in setting our PGA tariffs and, if found to be imprudent, could be disallowed, which could adversely affect our financial condition and results of operations.

Customer conservation. Customers’ conservation efforts may have a negative impact on our revenues.

Higher gas costs and rates may result in increased conservation by customers, which can decrease sales and adversely affect results of operations. The OPUC authorized our conservation tariff, which is designed to recover lost margin due to changes in residential and commercial customers’ consumption patterns. The conservation tariff is intended to adjust for increases or decreases in consumption attributable to annual changes in commodity costs or periodic changes in general rates and for deviations between actual and expected usage. The conservation tariff expires in September 2009. The failure of the OPUC to extend the conservation tariff in the future could adversely affect our financial condition and results of operations. We do not have a conservation tariff in Washington.

Environmental risks. Certain of our properties and facilities may pose environmental risks requiring remediation, the cost of which could adversely affect our results of operations and financial condition. Also, management expects that future legislation may impose carbon constraints to address global climate change.

We own, or previously owned, properties that require environmental remediation or other action. We accrue all material loss contingencies relating to these properties, but our results of operations may be adversely affected to the extent that estimates of the probable costs increase significantly as additional information becomes available and to the extent we are not able to recover the incremental cost through customer rates or from insurance. A regulatory asset has already been recorded for some of these estimated costs. To the extent we are unable to recover these costs in rates or through insurance, then we would be required to reduce our regulatory asset which could adversely affect our results of operations and financial condition.

We cannot predict with certainty the amount or timing of future expenditures related to any environmental investigation and remediation that may be required because of the difficulty of estimating such costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. There are also no assurances

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that existing environmental regulations will not be revised or that new stricter regulations seeking to protect the environment will not be adopted or become applicable to us. Revised environmental regulations which result in increased compliance costs or additional operating restrictions could have a material adverse effect on our results of operations, particularly if those costs are not fully recoverable from customers.

There are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phases of discussion or implementation. The outcome of federal and state actions to address global climate change could result in a variety of regulatory programs including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could result in increased costs associated with operating and maintaining our facilities, could increase other costs to our business and could impact the prices we charge our customers.

Competition. Our gas distribution business is subject to increased competition and eroding price advantage.

To the extent that competition increases, our profit margins may be negatively affected. In the residential market, we compete with suppliers of electricity, fuel oil, propane and, to a lesser extent, wood. We also compete with suppliers of electricity and fuel oil for commercial applications. In the industrial market, we compete with all forms of energy suppliers. Competition among these forms of energy is based on price, reliability, efficiency and performance.

Higher natural gas prices have eroded, or in some cases eliminated, the competitive price advantage of natural gas over alternative energy sources. If the higher gas price environment is sustained, our ability to attract new customers could be significantly affected, which could have a negative impact on our customer growth rate and results of operations.

Single transportation pipeline. We rely on a single pipeline for the transportation of gas to our service territory.

We are largely dependent on a single, bi-directional pipeline for transportation of gas into our service territory. Our results of operations may be negatively impacted if there is a rupture in the pipeline and we incur costs associated with actions taken to mitigate disruption of service.

Pension funding. The cost of providing pension and other postretirement benefit plans is subject to changes in assumptions, fluctuations in the market value of plan assets and changes in demographics, all of which may have a material effect on our results of operations and cash flows.

We maintain two qualified non-contributory defined benefit pension plans, several non-qualified supplemental pension plans and other postretirement benefit plans. We may be required to recognize a material increase or decrease in annual pension or postretirement benefit expense based on changes in assumed interest rates, market returns, expected rate of wage increases and other factors, and we may be required to record a charge to our balance sheet to the extent that projected benefit obligations exceed the fair value of plan assets.

Operating risk. Transporting and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs.

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Our gas distribution activities involve a variety of inherent operating hazards and risks, such as leaks, accidents, mechanical problems, fires, storms, landslides and other adverse weather conditions and hazards, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution and disruption of our operations, which in turn could lead to substantial losses. The occurrence of any of these events may not be covered by our insurance policies or recoverable through rates, which could adversely affect our financial condition and results of operations.

Weather risk. Our results of operations may be negatively affected by warmer than average weather.

A large portion of the utility’s margin is derived from sales to space heating residential and commercial customers during each winter heating season. Current rates are based on an assumption of average weather. In Oregon, the effects of warmer or colder weather on utility margin are reduced through the operation of our weather normalization mechanism and conservation tariff. However, 9 percent of eligible customers elected not to be covered by the weather normalization mechanism. Also, approximately 10 percent of our residential and commercial customers are in Washington where we do not have a weather normalization mechanism or conservation tariff. As a result, we are not fully protected against warmer than average weather, which may have an adverse affect on our financial condition, results of operations and cash flows.

Workforce risk. Our business is heavily dependent on being able to attract and retain qualified employees and to maintain a competitive cost structure with market-based salaries and employee benefits.

Our gas distribution business is subject to a variety of workforce risks, including being able to attract and retain qualified employees, being able to transfer the knowledge and expertise of an aging workforce to new employees as older workers retire and being able to reach collective bargaining agreements with the union that represents about 70 percent of our workers.

Customer growth. Our results of operations may be negatively affected by our ability to sustain customer growth.

Our earnings growth and results of operations have largely been dependent upon the sustained growth of our residential and commercial customer base at an annual rate of over 3 percent. If we are unable to sustain these levels of customer growth, our results of operations may be negatively affected. A number of factors could negatively impact our ability to sustain growth, such as a downturn in the economy, reduced housing starts and competition.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

Our natural gas distribution system consists of 13,474 miles of distribution and transmission mains located in our service territory in Oregon and Washington. In addition, the distribution system includes service pipes, meters and regulators, and gas regulating and metering stations. The mains are located in municipal streets or alleys pursuant to valid franchise or occupation ordinances, in county

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roads or state highways pursuant to valid agreements or permits granted pursuant to statute, or on lands of others pursuant to valid easements obtained from the owners of such lands. We also hold all necessary permits for the crossing of the Willamette River and a number of smaller rivers by our mains.

We own service facilities in Portland, as well as various satellite service centers, garages, warehouses and other buildings necessary and useful in the conduct of our business. We lease office space in Portland for our corporate headquarters, which lease expires on May 31, 2018. District offices are maintained on owned or leased premises at convenient points in the distribution system. We own LNG storage facilities in Portland and near Newport, Oregon.

We hold interests in 8,624 net acres of underground natural gas storage and 1,780 net acres of oil and gas leases in Oregon. We own rights to depleted gas reservoirs near Mist, Oregon, that are continuing to be developed as underground gas storage facilities. We also hold an option to purchase future storage rights in certain other areas of the Mist gas field.

In order to reduce risks associated with gas leakage in older parts of our system, we undertook an accelerated pipe replacement program under which we removed or replaced 100 percent of our cast iron mains by October 2000. In 2001, we initiated an accelerated pipe replacement program under which we will reduce the amount of bare steel mains in the system.

We consider all of our properties currently used in our operations, both owned and leased, to be well maintained, in good operating condition, and, along with planned additions, adequate for our present and foreseeable future needs.

Our Mortgage and Deed of Trust is a first mortgage lien on substantially all of the property constituting our utility plant.

ITEM 3. LEGAL PROCEEDINGS

See Note 12 to Consolidated Financial Statements, “Commitments and Contingencies—Legal Proceedings.”

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

There were no matters submitted to a vote of security holders, through the solicitation of proxies or otherwise, during the quarter ended December 31, 2006.

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PART II

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

(A) Our common stock is listed and trades on the New York Stock Exchange under the symbol “NWN.”

The high and low trades for our common stock during the past two years were as follows:

	2006				2005
Quarter Ended	High		Low		High		Low
March 31	$	36.57	$	32.83	$	37.24	$	32.42
June 30		37.04		33.30		38.67		34.36
September 30		40.08		35.81		39.63		35.60
December 31		43.69		38.53		37.77		33.25

The closing quotations for our common stock on December 29, 2006 and December 30, 2005 were $42.44 and $34.18, respectively.

(B)     As of December 31, 2006, there were 8,753 holders of record of our common stock.

(C)     We have paid quarterly dividends on our common stock in each year since the stock first was issued to the public in 1951. Annual common dividend payments have increased each year since 1956. Dividends per share paid during the past two years were as follows:

Payment Date	2006		2005
February 15	$	0.345	$	0.325
May 15		0.345		0.325
August 15		0.345		0.325
November 15		0.355		0.345
Total per share	$	1.390	$	1.320

The amount and timing of dividends payable on our common stock are within the sole discretion of our Board of Directors. It is the intention of the Board of Directors to continue to pay cash dividends on our common stock on a quarterly basis. However, the declaration and amount of future dividends will be dependent upon our earnings, cash flows, financial condition and other factors.

(D)    The following table provides information about purchases of our equity securities that are registered pursuant to Section 12 of the Exchange Act during the quarter ended December 31, 2006:

ISSUER PURCHASES OF EQUITY SECURITIES

	(a)		(b)	(c)		(d)
Period	Total Number of Shares Purchased (1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2)
Balance forward				812,700	$	60,260,697
10/01/06-10/31/06	1,380	$	40.27	70,000		(2,851,596	)
11/01/06-11/30/06	22,576	$	40.90	113,400		(4,571,685	)
12/01/06-12/31/06	1,742	$	42.72	165,000		(6,937,500	)
Total	25,698			1,161,100	$	45,899,916

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⁽¹⁾ During the quarter ended December 31, 2006, 24,901 shares of our common stock were purchased in the open market to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan (DSPP). In addition, 797 shares of our common stock were purchased in the open market during the quarter under equity-based programs. During the three months ended December 31, 2006, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.

⁽²⁾ On May 25, 2000, we announced a program to repurchase up to 2 million shares, or up to $35 million in value, of our common stock through a repurchase program that has been extended annually. In April 2006, the Board extended the program through May 31, 2007 and increased the authorization from 2 million shares to 2.6 million shares and increased the dollar limit from $35 million to $85 million. Share repurchases are made in the open market or through privately negotiated transactions. During the three months ended December 31, 2006, 348,400 shares of our common stock were purchased pursuant to this program. Since the program’s inception, we have repurchased 1,161,100 shares of common stock at a total cost of $39.1 million.

On September 29, 2006, we entered into a Stock Purchase Plan Engagement Agreement with our broker in order to establish a trading plan for our repurchase program that qualifies for the safe harbors provided by Rule 10b-18 and Rule 10b5-1 under the Securities Exchange Act of 1934, as amended. The agreement expired on December 31, 2006.

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ITEM 6. SELECTED FINANCIAL DATA

Thousands, except per share amounts and   ratio of earnings to fixed charges	For the year ended Dec. 31,
	2006		2005		2004		2003		2002
Utility operating revenues:
Residential sales	$	536,468	$	471,502	$	383,067	$	328,346	$	354,735
Commercial sales		290,666		250,287		200,424		176,336		201,475
Industrial - firm sales		66,986		64,507		45,259		33,578		42,965
Industrial - interruptible sales		93,107		100,740		55,380		23,655		15,937
Unbilled revenues1		-		-		-		14,474		(12,702	)
Total gas sales revenues		987,227		887,036		684,130		576,389		602,410
Transportation		12,800		10,755		12,655		17,968		26,020
Other		161		2,862		4,160		7,627		4,018
Total gross utility operating revenues		1,000,188		900,653		700,945		601,984		632,448
Cost of gas sold		648,081		563,772		399,176		323,128		353,034
Revenue taxes		24,840		21,633		16,865		14,650		14,743
Utility operating revenues		327,267		315,248		284,904		264,206		264,671
Non-utility operating revenues		12,909		9,745		6,591		9,210		8,130
Net operating revenues	$	340,176	$	324,993	$	291,495	$	273,416	$	272,801
Net income	$	63,415	$	58,149	$	50,572	$	45,983	$	43,792
Redeemable preferred and preference stock dividend requirements		-		-		-		294		2,280
Earnings applicable to common stock	$	63,415	$	58,149	$	50,572	$	45,689	$	41,512
Average common shares outstanding:
Basic		27,540		27,564		27,016		25,741		25,431
Diluted		27,657		27,621		27,283		26,061		25,814
Earnings per share of common stock:
Basic	$	2.30	$	2.11	$	1.87	$	1.77	$	1.63
Diluted	$	2.29	$	2.11	$	1.86	$	1.76	$	1.62
Dividends per share of common stock	$	1.39	$	1.32	$	1.30	$	1.27	$	1.26
Total assets – at end of period	$	1,956,856	$	2,042,304	$	1,732,195	$	1,585,379	$	1,467,277
Redeemable preferred stock	$	-	$	-	$	-	$	-	$	8,250
Long-term debt	$	517,000	$	521,500	$	484,027	$	500,319	$	445,945
Ratio of earnings to fixed charges		3.40		3.32		3.02		2.84		2.85

¹ Unbilled revenues have been allocated by class for 2006, 2005 and 2004.

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

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SELECTED FINANCIAL DATA (continued)

Thousands, except customer and gas cost per therm data	2006			2005			2004			2003			2002
Capitalization - at end of period
Common stock equity	$	599,545		$	586,931		$	568,517		$	506,316		$	482,392
Redeemable preferred stock		-			-			-			-			8,250
Long-term debt		517,000			521,500			484,027			500,319			445,945
Total capitalization	$	1,116,545		$	1,108,431		$	1,052,544		$	1,006,635		$	936,587
Gas sales and transportation deliveries (therms):
Residential		382,665			371,538			352,356			343,534			357,091
Commercial		242,683			233,987			222,875			226,257			240,155
Industrial - firm		66,971			74,880			62,843			55,314			63,215
Industrial - interruptible		112,736			149,106			104,278			47,994			26,241
Unbilled therms1		-			-			-			12,099			(6,617	)
Total gas sales		805,055			829,511			742,352			685,198			680,085
Transportation		387,594			328,056			389,514			414,554			445,999
Total volumes delivered		1,192,649			1,157,567			1,131,866			1,099,752			1,126,084
Customers (average for period):
Residential		564,700			545,163			525,976			510,336			492,871
Commercial		59,889			58,914			57,973			56,504			55,416
Industrial - firm		650			666			629			362			350
Industrial - interruptible		197			201			178			98			74
Transportation		99			78			106			179			190
Total customers		625,535			605,022			584,862			567,479			548,901
Customer statistics:
Heat requirements:
Actual degree days		4,089			4,178			3,853			3,952			4,232
Percent colder (warmer) than average		(4%	)		(2%	)		(10%	)		(7%	)		(1%	)
Average annual use per customer in therms:
Residential		678			682			670			673			725
Commercial		4,052			3,972			3,844			4,004			4,334
Gas purchased cost per therm - net (cents)		75.37			71.42			56.60			46.99			51.07

¹ Unbilled therms have been allocated by class for 2006, 2005 and 2004.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management’s assessment of Northwest Natural Gas Company’s financial condition, including the principal factors that affect results of operations. The discussion refers to our consolidated activities for the three years ended December 31, 2006. References in this discussion to “Notes” are to the Notes to Consolidated Financial Statements in this report.

The consolidated financial statements include the accounts of Northwest Natural Gas Company, which principally consists of our regulated local gas distribution business, our regulated gas storage business, and our other non-regulated businesses, which includes our wholly-owned subsidiary business, NNG Financial Corporation (Financial Corporation). In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage business segment (gas storage), previously referred to as “interstate gas storage,” and our other non-regulated activities (other) (see 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 report to earnings per share are on the basis of diluted shares (see Note 1, “Earnings Per Share”).

Executive Summary

Our strategy in 2006 was to remain focused on profitably growing our regulated utility and gas storage businesses. The utility is our largest business segment with approximately 98 percent of consolidated total assets, which contributed 90 percent of consolidated net income in 2006. Factors critical to the success of the utility include maintaining a safe and reliable distribution system, acquiring an adequate supply of gas, providing distribution services at a competitive price, and being able to recover the operating and capital costs of the utility in the rates charged to customers. The utility is regulated by two state commissions, the Oregon Public Utility Commission (OPUC) and the Washington Utilities and Transportation Commission (WUTC).

Our gas storage segment represents approximately 2 percent of consolidated total assets and contributed 9 percent of consolidated net income in 2006. This business unit primarily provides firm and interruptible gas storage at our Mist underground storage facility to large interstate and intrastate customers using storage and related transportation capacity that is in excess of our utility’s core (residential, commercial and industrial firm) customer requirements. Asset optimization is also part of the gas storage segment, with optimization services provided for the utility under an agreement with an independent energy marketing company. Factors critical to the success of our gas storage business segment include the ability to: develop additional storage capacity at competitive market prices; plan for the replacement of capacity that is expected to be recalled by the utility to serve its core customers in the future; and obtain timely and reasonable rate changes.

Highlights of 2006 include:

• Net income and diluted earnings per share increased 9 percent in 2006, to $63.4 million and $2.29 per share;

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• Solid growth in net operating revenues from our regulated utility distribution and gas storage businesses were major drivers to increased earnings in 2006;

• Net operating revenues from our regulated utility increased 4 percent to $327.3 million, largely attributable to strong customer growth, which increased by more than 3 percent for the 20^th consecutive year, and increased margin sharing from gas cost savings through our regulatory incentive mechanism;

• Net operating revenues from gas storage increased 33 percent to $12.8 million, including a higher amount of revenue sharing with our utility customers, which increased 43 percent to $7.0 million;

• Operations and maintenance expense increases were held to 1 percent in 2006, including incremental costs for employee retirement and severance programs and employee bonuses tied to improved financial results which were largely offset by cost reductions from business process redesign initiatives that we began implementing in 2006;

• Cash flow from operations increased 88 percent to $148.6 million, reflecting strong operating and working capital results;

• $25 million of new long-term debt was issued in the fourth quarter of 2006, with the proceeds being used to redeem short-term debt and fund capital expenditures;

• In a J.D. Power & Associates’ residential customer survey, NW Natural ranked first in the nation for customer satisfaction with billing and payment services, and third in the nation for overall customer satisfaction among the 56 largest gas utilities; and,

• Our quarterly common stock dividend rate increased 3 percent to $0.355 per share in the fourth quarter of 2006, making this the 51^st consecutive year of increasing dividends paid to shareholders.

Issues, Challenges and Performance Measures

A number of factors affect our operations and financial performance. The most significant issue the utility faces in the near term is high gas prices. Wholesale gas prices over the past few years have increased significantly, primarily due to increasing demand. In 2005, the gas supply market tightened significantly as hurricanes hit parts of the United States, resulting in the disruption of gas supplies and causing gas prices to spike. Since then, gas prices have moderated and are now relatively more stable than last year. We expect energy prices to remain slightly higher than in the past few years, with higher gas prices already reflected in our customers’ bills for the 2006-07 heating season. We believe we have sufficient supplies of natural gas under contract to meet the needs of our firm customers, but further price increases for gas could change our competitive advantage and our customers’ preference for natural gas. If higher gas prices persist, it could significantly affect our ability to add residential and commercial customers and could result in industrial customers shifting their businesses’ energy needs to alternative fuel sources. To address these competitive issues, we are continually developing new gas acquisition strategies to manage gas prices and meet market demands, and we are working on initiatives intended to improve operational efficiencies throughout the company through a comprehensive business process redesign effort (see “Business Process Redesign,” below).

Other issues and challenges we expect to face in 2007 include executing on our business process redesign initiatives, managing gas supplies and prices under unpredictable market conditions, managing the potential impact of adverse regulatory actions or policy changes, managing storage and transportation capacity, managing and maintaining customer growth, maintaining a competitive advantage over alternative fuels and managing environmental risks and exposures and higher interest rates. For a more detailed discussion of these and other risks, see “Part I, Item 1A—Risk Factors,”

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above, “Item 7A., Quantitative and Qualitative Disclosures About Market Risk,” below, and “Forward-Looking Statements,” below, following Item 7A.

Our strategic plan addresses the risks affecting our business by focusing on:

• improving our ability to add customers profitably;

• managing wholesale natural gas prices through an active hedging program to keep customer prices stable and as low as possible;

• maintaining our reputation for exemplary customer service;

• reducing business risks;

• managing all costs, including capital investments;

• maintaining a strong financial position;

• improving our cost structure through business process redesign initiatives; and

• judiciously growing beyond our local distribution business where such growth would complement our core assets and competencies.

Return on invested capital and common equity ratios are key indicators of our operating performance and financial condition. We compare our utility return on equity results each year against the return authorized by the OPUC. We also compare our total shareholder return (stock price appreciation plus dividends) against a peer group of local gas distribution companies because it is necessary for us to attract investors so that we can continue to cost-effectively raise the capital needed to run our businesses. Other key performance measures we use in monitoring progress against our goals include earnings per share, cash provided by operations, free cash flow (cash from operations less payments for investing activities and dividends), customer satisfaction ratings, customer additions, operations and maintenance expense per customer, construction cost per meter installed and non-revenue producing capital expenditures per customer.

Strategic Opportunities

Business Process Redesign. During 2006, we initiated a project to evaluate our business processes and costs against our peers and to redesign those processes where long-term efficiencies could be gained. We identified a number of areas where we could restructure our business to gain efficiencies, including more centralization, an increased focus on process orientation, and more standardized processes. In order to effectively implement these strategies, we are taking steps to redesign our business into the following six core areas to more effectively group and focus resources around our business processes:

• Acquire Customers. Focuses on the integration of activities involved in acquiring customers, including construction, sales, marketing and operation of our retail appliance center.

• Serve Customers. Focuses on all aspects of how we serve our customer base, including customer contact, meter reading, account services and field services areas.

• Deliver Gas. Focuses on the transportation of gas to our customers and includes qualification assurance of our employees, engineering and code compliance.

• Energy Supply. Focuses on procuring gas, pipeline integrity, gas storage and business development for the future.

• Resource Management. Focuses on how well we use the resources at our disposal by centralizing dispatch and scheduling, business analysis and technology implementation.

• Business Services. Focuses on supporting all of the areas above through human resources, information technology, regulation, finance, legal and other administrative functions.

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We have begun the implementation of this business model, which is expected to continue over the next several years. Workforce reductions related to the implementation of this new model are expected to be accomplished primarily through attrition and voluntary severance arrangements. In 2006, we incurred costs of $1.9 million related to workforce reductions of approximately 80 employees.

Pipeline Diversity. In September 2006, we announced that we are evaluating a potential pipeline project that would connect TransCanada’s Gas Transmission Northwest (GTN) interstate transmission line to our local gas distribution system. We have commenced a process to determine if there is sufficient interest by potential customers to justify construction of the pipeline. If the project is determined to be viable, we would form a partnership with GTN to build and own the pipeline. In addition to owning a share of the pipeline, we would anticipate being a large user of the pipeline and GTN would be its operator. The pipeline would be intended to provide our utility customers and GTN’s customers with a more diversified delivery source and greater reliability of gas supplies from the interstate system. The decision on whether to proceed with the development of the pipeline is expected to be made in 2007. No material contractual obligations related to the pipeline have been incurred as of December 31, 2006. If constructed, commercial operation would be expected to commence in 2011.

Earnings and Dividends

Net income was $63.4 million, or $2.29 a diluted share, for the year ended December 31, 2006, compared to $58.1 million, or $2.11 a share, and $50.6 million, or $1.86 a share, for the years ended December 31, 2005 and 2004, respectively. Returns on equity for these three years were 10.7 percent, 10.1 percent and 9.4 percent, respectively.

2006 compared to 2005:

Positive factors contributing to increased earnings were:

• increased utility volumes and net operating revenues (margin) from sales to residential and commercial customers due to 3.1 percent customer growth, plus extended coverage from the weather normalization and conservation mechanisms in Oregon, partially offset by weather that was 4 percent warmer than average and 2 percent warmer than 2005 (see “Results of Operations—Comparison of Gas Distribution Operations,” below, and “Results of Operations—Regulatory Matters—Rate Mechanisms,” below);

• increased margin from regulatory sharing of gas cost savings, from $4.2 million in 2005 to $8.1 million in 2006, partially offset by a $2.7 million temporary unrealized loss related to a derivative contract that will settle and reverse in 2007; and

• increased gas storage margin over the prior year, primarily due to increased storage contract volumes and increased optimization revenue from the independent energy marketing company.

Partially offsetting the above positive factors were:

• increased property tax and depreciation expenses related to increased utility plant in service, which were partially covered by revenue increases approved in the most recent Purchased Gas Adjustment (PGA) filings in Oregon and Washington;

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• increased operations and maintenance expense related to higher bonuses tied to improved performance results and to employee severance charges tied to business redesign initiatives, partially offset by lower payroll and employee benefit costs; and

• increased income tax expense related to higher taxable income.

2005 compared to 2004:

Positive factors contributing to increased earnings were:

• increased utility volumes and net operating revenues from sales to residential and commercial customers due to 3.4 percent customer growth, 8 percent colder weather and conservation tariff mechanisms, partially offset by declining average use per customer and a decrease in the contribution from the weather normalization mechanism (see “Results of Operations—Comparison of Gas Distribution Operations,” below, and “Results of Operations—Regulatory Matters—Rate Mechanisms,” below);

• decreased utility volumes but increased utility margin from industrial customers, primarily reflecting a shift of several customers to higher margin service which offset the overall decline in volumes;

• increased utility margin from miscellaneous revenues; and

• increased gas storage margin primarily due to increased storage services under contract and higher optimization revenues.

Partially offsetting the above positive factors were:

• increased operations and maintenance expense related to increased payroll and employee benefit costs, increased damages to company property, industrial customer settlement charges and employee severance charges;

• increased property tax and depreciation expenses related to increased utility plant in service, which were partially covered by revenue increases approved in the most recent PGA and general rate cases in Oregon and Washington; and

• increased income tax expense related to higher taxable income.

Dividends paid on our common stock were $1.39 a share in 2006, compared to $1.32 a share in 2005 and $1.30 a share in 2004. The current indicated annual dividend rate is $1.42 per share.

Application of Critical Accounting Policies and Estimates

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

Our most critical estimates or judgments involve regulatory cost recovery, revenue recognition, derivative instruments, pension assumptions, income taxes and environmental contingencies.

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Management has discussed the estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board. Our critical accounting policies and estimates are described below.

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

Regulatory Accounting

We are regulated by the OPUC and WUTC, which establish our utility rates and rules governing utility services provided to customers, and, to a certain extent, set forth the accounting treatment for certain regulatory transactions. In general, we use the same accounting principles as non-regulated companies reporting under GAAP. However, certain accounting principles, primarily Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” require different accounting treatment for regulated companies to show the effects of such regulation. For example, we account for the cost of gas using a PGA deferral and cost recovery mechanism, which is submitted for approval annually to the OPUC and WUTC (see “Results of Operations—Regulatory Matters—Rate Mechanisms,” below). There are other expenses or revenues that the OPUC or WUTC may require us to defer for recovery or refund in future periods. SFAS No. 71 requires us to account for these types of deferred expenses (or deferred revenues) as regulatory assets (or regulatory liabilities) on the balance sheet. When we are allowed to recover these expenses from or refund them to customers, we recognize the expense or revenue on the income statement at the same time we realize the adjustment to amounts included in utility rates charged to customers.

The conditions we must satisfy to adopt the accounting policies and practices of SFAS No. 71, which are applicable to regulated companies, include:

• an independent regulator sets rates;

• the regulator sets the rates to cover specific costs of delivering service; and

• the service territory lacks competitive pressures to reduce rates below the rates set by the regulator.

We continue to apply SFAS No. 71 in accounting for our regulated utility operations. Future regulatory changes or changes in the competitive environment could require us to discontinue the application of SFAS No. 71 for some or all of our regulated businesses. This would require the write-off of those regulatory assets and liabilities that would no longer be probable of recovery from or refund to customers. Based on current regulatory and competitive conditions, we believe that it is reasonable to expect continued application of SFAS No. 71 for our regulated activities, and that all of our regulatory assets and liabilities at December 31, 2006 and 2005 are recoverable or refundable through future customer rates. See Note 1, “Industry Regulation.”

Revenue Recognition

Utility revenues, derived primarily from the sale and transportation of natural gas, are recognized when gas is delivered to and received by the customer. Revenues are accrued for gas delivered to customers, but not yet billed, based on estimates of gas deliveries from the last meter reading date to month end (accrued unbilled revenues). Accrued unbilled revenues are primarily based

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on a percentage estimate of our unbilled gas each month, which is dependent upon a number of factors, some of which require management’s judgment. These factors include total gas receipts and deliveries, customer meter reading dates, customer usage patterns and weather. Accrued unbilled revenue estimates are reversed the following month when actual billings occur. Estimated unbilled revenues at December 31, 2006 and 2005 were $87.5 million and $81.5 million, respectively. The increase in accrued unbilled revenues at year-end 2006 was primarily due to higher gas prices included in customer rates and higher volumes reflecting customer growth. If the estimated percentage of unbilled volume at December 31, 2006 was adjusted up or down by 1 percent, then our unbilled revenues, net operating revenues and net income would have increased or decreased by an estimated $3.4 million, $0.7 million and $0.4 million, respectively.

Non-utility revenues, derived primarily from our gas storage business segment, are recognized upon delivery of the service to customers. Revenues from our optimization partner are recognized over the life of the optimization contract for the guaranteed amount, or are recognized as they are earned for amounts above the guaranteed value based on information provided by the independent energy marketing company.

Accounting for Derivative Instruments and Hedging Activities

Our Financial Derivatives Policy and Gas Acquisition Policy set forth guidelines for using selected financial derivative products to support prudent risk management strategies within designated parameters. These policies specifically prohibit the use of derivatives for trading or speculative purposes. The accounting rules for determining whether a contract meets the definition of a derivative instrument or qualifies for hedge accounting treatment are complex. The contracts that qualify as derivative instruments are recorded on our balance sheet at fair value. If certain regulatory conditions are met, then the fair value is recorded together with an offsetting entry to a regulatory asset or liability account pursuant to SFAS No. 71 (see Note 1, “Industry Regulation,”) and no gain or loss is recognized in current income. The gain or loss from the fair value of a derivative instrument that is subject to regulatory deferral is included in the recovery from, or refund to, utility customers in future periods (see “Regulatory Accounting,” above). If a derivative contract is not subject to regulatory deferral, then the accounting treatment for gains and losses is made in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149, collectively referred to as SFAS No. 133 (see Note 1, “Derivatives” and “Industry Regulation”). Our estimate of fair value is determined from period-to-period based on an internal discounted cash flow model using exchange-based forward market prices that are subject to market volatility, except for option contracts where fair value is based on a Black-Scholes model. The estimate of fair value may change significantly from period-to-period depending on market conditions and prices. These changes may have a material impact on our results of operations, but the impact would be largely mitigated due to the majority of our derivatives activities being subject to regulatory deferral treatment. For estimated fair values at December 31, 2006 and 2005, see Note 11.

Derivative contracts entered into after our annual PGA filing for the current gas contract period are subject to a regulatory incentive sharing mechanism in Oregon, with 67 percent of unrealized gains and losses recorded to a regulatory asset or liability account and the remaining 33 percent recognized in current income. The unrealized loss on financial derivative contracts entered into during the fourth quarter of 2006, which was after the 2006 PGA filing, totaled $9.5 million, of which $2.9 million was recorded in cost of gas as of December 31, 2006. This unrealized loss will be reversed in 2007 when the derivative contracts are settled.

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The following table summarizes the amount of realized gains and losses from commodity price and currency hedge transactions for the last three years:

Thousands	2006			2005			2004
Net gain (loss) on commodity-price swaps—for utility	$	(18,849	)	$	90,205		$	44,888
Net loss on commodity-price options—for utility		(1,160	)		(1,315	)		(2,464	)
Subtotal on commodity—for utility		(20,009	)		88,890			42,424
Net loss on commodity-price swaps—for gas storage		-			-			(186	)
Net gain on foreign currency forward purchases—for utility		355			532			219
Total realized net gain (loss)	$	(19,654	)	$	89,422		$	42,457

Realized gains (losses) from commodity-price and foreign currency forward purchase contracts are recorded as reductions (increases) to the cost of gas and are included in the calculation of annual PGA rate changes. Unrealized gains and losses resulting from mark-to-market valuations are generally not recognized in current income or other comprehensive income, but are recorded as regulatory liabilities or regulatory assets, which are offset by a corresponding balance in non-trading derivative assets or liabilities (see Note 11).

Accounting for Pensions

We maintain two qualified non-contributory defined benefit pension plans covering all regular employees with more than one year of service, several non-qualified supplemental pension plans for eligible executive officers and certain key employees and other employee postretirement benefit plans. Only the two qualified defined benefit pension plans have plan assets, which are held in a qualified trust to fund retirement benefits.

Net periodic pension costs (pension costs) and projected benefit obligations (benefit obligations) are determined in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” using a number of key assumptions including discount rates, rate of compensation increases, retirement ages, mortality rates and the expected long-term return on plan assets (see “Financial Condition—Pension Cost and Funding Status,” below, and Note 7). These key assumptions have a significant impact on the amounts reported. Pension costs consist of service costs, interest costs, the amortization of actuarial gains, losses and prior service costs, the expected returns on plan assets and, in part, on a market-related valuation of assets. The market-related valuation reflects differences between expected returns and actual investment returns, which are recognized over a three-year period from the year in which they occur, thereby reducing year-to-year volatility in pension costs.

Effective December 31, 2006, the funded status of our pension plans is required to be recognized in accordance with SFAS No. 158 (see “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Benefit Plans” under Note 1, “New Accounting Standards”). SFAS No. 158 requires balance sheet recognition of the overfunded or underfunded status of our pension plans in accumulated other comprehensive income (AOCI), net of tax, based on the fair value of plan assets compared to the actuarial value of future benefit obligations. However, the pension costs relating to certain NW Natural pension plans are recovered in utility rates based on SFAS No. 87, and as such we received regulatory approval from the OPUC to record a regulatory asset or regulatory liability, rather than include AOCI in common equity, for the funded status of those plans pursuant to SFAS No. 71 (see “Regulatory Accounting”, above, and Note 1, “Industry Regulation”). As a result of regulatory approval we recognized a $54.4 million regulatory asset for the unfunded status of these qualified pension and other

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postretirement benefit plans. If future regulatory changes are to occur that will affect our ability to recover pension costs based on SFAS No. 87, then we would be required to adjust a portion or all of the deferred regulatory asset amount for pension and other postretirement benefit plans. This would cause us to recognize the $33.2 million after-tax charge to common equity and a $21.2 million deferred income tax asset based on the December 31, 2006 funded status, but it would not have an immediate impact on current earnings. Upon adoption of SFAS No. 158, total assets increased $25.7 million, total liabilities increased $26.1 million and equity decreased $0.4 million (see Note 7).

A number of factors are considered in developing pension assumptions, including an evaluation of relevant discount rates, expected long-term investment returns, plan asset allocations, expected changes in salaries, wages and retirement benefits, analyses of current market conditions and input from actuaries and other consultants. For the December 31, 2006 measurement date, we:

• increased the pension discount rate assumptions from 5.75 percent to a range of 6.00 percent to 6.05 percent. The new rate assumptions were determined for each plan based on a matching of the estimated cash flow, which reflects the timing and amount of future benefit payments, to the Citigroup Above Median Curve, which consists of high quality bonds (rated AA- or higher by Standard & Poor’s or Aa3 or higher by Moody’s Investor Service);

• updated the retirement and withdrawal rates based on a recent study of actual plan experience;

• confirmed the expected rate of future compensation increases between 4.00 and 5.00 percent; and

• confirmed the expected long-term return on plan assets at 8.25 percent.

The benefit obligation at December 31, 2006 decreased $9.3 million due to the increase in the discount rate and increased $0.3 million due to the retirement and withdrawal rates updated for actual experience.

We determine the expected long-term rate of return on plan assets by averaging the expected earnings for the target asset portfolio. In developing our expected rate of return assumption, we evaluate an analysis of historical actual performance and long-term return projections, which gives consideration to the current asset mix and our target asset allocation. The actual annualized returns for the past one-year, five-year and 10-year periods ended December 31, 2006 were 14.9 percent, 10.1 percent and 10.2 percent, respectively.

We believe our pension assumptions to be appropriate based on plan design and an assessment of market conditions. However, the following shows the sensitivity of our pension costs and benefit obligations to future changes in certain actuarial assumptions:

Thousands, except percent	Change in Assumption		Impact on 2006 Pension Costs		Impact on Benefit Obligations at Dec. 31, 2006
Discount rate	(0.25	%)	$	884	$	8,506
Expected long-term return on plan assets	(0.25	%)	$	534		N/A

The impact of a change in pension costs on operating results would be less than the amounts shown above because only between 60 and 70 percent of our pension costs is charged to operations and maintenance expense. The remaining 30 to 40 percent is capitalized to construction accounts as payroll overhead and included in utility plant, which is amortized to expense over the useful life of the asset placed into service.

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Accounting for Income Taxes

Income taxes are accounted for in accordance with SFAS No. 109, “Accounting for Income Taxes,” by recognizing deferred income taxes for all temporary differences between the book and tax basis of assets and liabilities at current income tax rates.

SFAS No. 109 also requires the recognition of additional deferred income tax assets and liabilities for temporary differences where regulators require us to flow through deferred income tax benefits or expenses in the ratemaking process of the regulated utility (regulatory tax assets and liabilities). This is consistent with the ratemaking policies of the OPUC and WUTC. Regulatory tax assets and liabilities are recorded to the extent we believe they will be recoverable from, or refunded to, customers in future rates. At December 31, 2006 and 2005, we had regulatory assets representing differences between book and tax basis related to pre-1981 property of $67.1 million and $65.8 million, respectively, and recorded an offsetting deferred tax liability for the same amounts (see Note 1, “Income Tax Expense”). We believe that it is reasonable to expect recovery of these regulatory assets through future customer rates. However, future regulatory changes could require the write-off of all or a portion of these regulatory assets should they no longer be probable of recovery in future rates (see “Regulatory Accounting,” above, and Notes 1 and 9).

A recent interpretation of SFAS No. 109 (FIN 48), “Accounting for Uncertainty in Income Taxes – an interpretation of Financial Accounting Standards Board (FASB) Statement No. 109,” was issued by the FASB in July 2006 to address how companies should account for the tax benefits of timing and permanent income tax positions taken or expected to be taken in a tax return. SFAS No. 109 contains rules which set out how the benefits of tax positions taken or expected to be taken in a tax return are to be reflected in current and deferred income taxes for financial reporting purposes, but it does not establish a confidence level or threshold that must be met in order to recognize a tax benefit in the financial statements. FIN 48 is effective for fiscal years beginning after December 15, 2006, which for us was January 1, 2007.

Adoption of FIN 48 will require us to identify and evaluate all material tax positions taken in previously filed and still open tax returns as well as tax positions expected to be taken in future returns. Each tax position will need to be examined to determine whether the more likely than not recognition standard has been met, and if so, to compute the amount of the tax benefit to be recognized under FIN 48. Based upon a preliminary assessment of the application of FIN 48, the adoption of FIN 48 is not expected to have a material effect on our financial condition, results of operations or cash flows.

Contingencies

Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies.” Estimates of loss contingencies, including estimates of legal defense costs when such costs are probable of being incurred and are reasonably estimable, and related disclosures are updated when new information becomes available. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties. Accruals for loss contingencies are recorded based on an analysis of potential results, developed in consultation with outside counsel and consultants when appropriate. When information is sufficient to estimate only a range of potential liabilities, and no point within the range is more likely than any other, we recognize an accrued liability at the low end of the range and disclose the range (see “Contingent Liabilities,” below). It is possible, however, that the range of potential liabilities could be

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significantly different than amounts currently accrued and disclosed, with the result that our financial condition and results of operations could be materially affected by changes in the assumptions or estimates related to these contingencies.

With respect to our environmental liabilities and related costs, we develop estimates based on currently available information, existing technology and environmental regulations. We previously received regulatory approval to defer and seek recovery of costs related to certain sites and believe the recovery of any costs not recovered under our general liability insurance policies is probable through the regulatory process (see Note 12). In accordance with SFAS No. 71, we recorded a regulatory asset for the amount expected to be recovered. We intend to first pursue recovery for these environmental costs from our general liability insurance policies, which, to the extent successful, would require a corresponding reduction in the regulatory asset. At December 31, 2006, $27.8 million in environmental costs have been recorded as a regulatory asset, including $19.1 million of costs paid to-date and $8.7 million accrued for estimated future environmental costs. If it is determined that both the insurance recovery and future rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is made and could have a material impact on our financial condition or results of operations.

Results of Operations

    Regulatory Matters

Regulation and Rates

We are subject to regulation with respect to, among other matters, rates, systems of accounts and issuance of securities by the OPUC and the WUTC. In 2006, 93 percent of our utility gas deliveries and 90 percent of our 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 pace of continued growth in the residential and commercial markets 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.

General Rate Cases

Our most recent general rate increase in Oregon authorized rates to customers based on a return on shareholders’ equity (ROE) of 10.2 percent and was effective September 1, 2003. Our most recent general rate case in Washington authorized a revenue increase of $3.5 million per year but did not specifically authorize an ROE and was effective July 1, 2004.

In May 2005, we reached a settlement with the staff of the Federal Energy Regulatory Commission (FERC) and all intervenors with respect to our rate case filed in January 2005 related to Mist interstate storage service. The settlement provided for a small net increase in the maximum rates for our interstate storage services, which became effective July 1, 2005. The rates established in this case are designed to reflect updated costs related to investments in the Mist gas storage facility since 2001 and costs associated with the South Mist Pipeline Extension project.

Rate Mechanisms

Purchased Gas Adjustment. Rate changes are applied each year under the PGA tariff mechanisms in Oregon and Washington to reflect changes in the expected cost of natural gas

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commodity purchases, including contractual arrangements to hedge the purchase price with financial derivatives (see “Comparison of Gas Distribution Operations—Cost of Gas Sold,” below), 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. Under the current PGA mechanisms, we collect an amount for purchased gas costs based on estimates included in rates. If the actual purchased gas costs differ from the estimated amounts included in rates, then we are required to defer that difference and pass it on to customers as an adjustment to future rates. As part of an incentive mechanism in Oregon, only 67 percent of the difference is deferred such that the impact on current earnings is either a charge to expense for 33 percent of the higher cost of gas sold, or a credit to expense for 33 percent of the lower cost of gas sold. In Washington, the PGA deferral is 100 percent of the higher or lower actual cost of gas sold.

The OPUC and the WUTC approved PGA rate increases on October 25, 2006 that became effective on November 1, 2006. The effect of the PGA rate changes was to increase the average monthly bills of Oregon residential sales customers by 3.5 percent and those of Washington residential sales customers by 2.6 percent. The OPUC also approved a modification to our PGA deferral mechanism, effective November 1, 2006, which provides that we use actual recoveries of gas costs in revenues billed (instead of the prior method that used estimated deliveries for gas costs incorporated in monthly rates) compared to actual purchased gas costs. The new method requires changes in line loss expense to be subject to the PGA deferral mechanism, with 67 percent of any cost differences for Oregon volumes deferred for refund or recovery in customer rates in subsequent periods and the remaining 33 percent included in current earnings. These PGA increases included increased transportation costs (see “Interstate Pipeline Rate Cases,” below).

Pursuant to the PGA tariffs, rate increases were approved by the OPUC averaging 15.2 percent for Oregon residential sales customers, and by the WUTC averaging 12.0 percent for Washington residential sales customers, both effective October 1, 2005. In 2004, the OPUC approved a PGA rate increase averaging 20.1 percent for Oregon residential sales customers, and the WUTC approved a PGA rate increase averaging 19.5 percent for Washington residential sales customers, effective October 1 and November 1, 2004, respectively.

The OPUC notified us that they will be conducting a formal review of the PGA process covering gas portfolio requirements, incentive sharing levels and filing requirements, among other items. The investigation is expected to be completed in early 2008. Implementation of any changes to the PGA mechanism is expected to be effective with the 2008 PGA filing.

Conservation Tariff. In October 2002, the OPUC authorized the implementation of a “conservation tariff,” which is a rate mechanism designed to adjust margin to compensate the utility for changes in consumption patterns due to residential and commercial customers’ conservation efforts. The tariff is a decoupling mechanism that is intended to break the link between earnings and the quantity of energy consumed by customers, removing any incentive to discourage customers’ conservation efforts. In Washington, customer use is not covered by a conservation tariff, and as such our utility earnings are affected by increases and decreases in usage based on customers’ conservation efforts. Washington customers account for about 10 percent of utility revenues.

In 2005, an independent study to measure the mechanism’s effectiveness recommended continuation of the conservation tariff, with minor modifications. In 2005 and 2006, the OPUC approved the continuations of the conservation tariff through September 30, 2009, and increased the

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mechanism’s coverage from a partial decoupling of 90 percent of residential and commercial gas usage to a full decoupling of 100 percent.

Weather Normalization. In November 2003, the OPUC authorized, and the utility implemented, a weather normalization mechanism in Oregon that helps stabilize utility margins by adjusting residential and commercial customer billings based on temperature variances from average weather. The current normalization mechanism is applied to our residential and commercial customers’ bills between December 1 and May 15 for each heating season. The mechanism adjusts the margin component of customers’ rates to reflect average weather, which uses the 25-year average temperature for each day of the billing period. Daily average temperatures and 25-year average temperatures are based on a set point temperature of 59 degrees Fahrenheit for residential customers and 58 degrees Fahrenheit for commercial customers (see “Comparison of Gas Distribution Operations,” below). We do not have a weather normalization mechanism approved for our Washington customers.

Excess Earnings Test. The OPUC has a formalized process to test for excess utility earnings annually and has confirmed our ability to pass through 100 percent of prudently incurred gas costs into rates. We are authorized to retain all of our earnings up to a threshold level equal to our authorized ROE of 10.2 percent plus 300 basis points. One-third of any earnings above that level will be refunded to customers. The excess earnings threshold is subject to adjustment up or down each year depending on movements in long-term interest rates. In 2006 and 2005, the threshold after adjustment was 13.44 percent and 13.32 percent, respectively. No amounts were required to be refunded to customers as a result of the 2005 or 2004 earnings test and we do not expect that any amounts will be required to be refunded to customers as a result of the 2006 earnings test, which will be reviewed by the OPUC during the second quarter of 2007. In Washington, we are not subject to an annual excess earnings test, and 100 percent of all prudently incurred gas costs are passed through into customer rates.

Recent Changes to Industrial Tariffs. In August 2006, the OPUC and WUTC approved tariff changes to the service options for our major industrial accounts. The changes set out additional parameters that give us more certainty in the level of gas supplies we will need to acquire to serve this customer group. The parameters include an annual election period, special pricing provisions for out-of-cycle changes and a requirement that customers on our annual weighted average cost of gas tariff complete the term of their service election.

Pipeline Integrity Cost Recovery. In July 2004, the OPUC approved our applications relating to the accounting treatment and full recovery for the cost of the pipeline integrity management program, as mandated by the Pipeline Safety Improvement Act of 2002 and related rules adopted by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (see “Financial Condition—Cash Flows—Investing Activities,” below). We classify our costs as either capital expenditures or regulatory assets, accumulate the costs over each 12-month period ending June 30, and recover the costs, subject to audit, through rate changes effective with the annual PGA. The accounting and rate treatment for these costs extends through September 30, 2008 and may be reviewed for potential extension after that date. We do not have any special accounting or rate treatment for pipeline integrity costs incurred in the state of Washington.

Interstate Pipeline Rate Cases

On June 30, 2006, the two interstate pipeline companies that provide natural gas transportation to our distribution system filed for general rate increases with the FERC. Northwest Pipeline

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Corporation (Northwest Pipeline) filed for an overall cost of service increase of approximately $119.0 million (a 41 percent increase), including an increase in the firm transportation rate of approximately 45 percent. In connection with this filing, our firm gas transportation rates increased by approximately $17.8 million annually. The major components in the Northwest Pipeline increase relate to a significant capacity replacement project, other capacity displacement projects, an increase in the rate of return and higher operation and maintenance expenses and costs associated with accounting changes to expense pipeline integrity assessment costs. The filed rates and associated tariff sheets became effective on January 1, 2007, subject to refund pending the outcome of further proceedings in the case. In February 2007, Northwest Pipeline filed a settlement proposal with the FERC that would resolve all issues with the active parties and would result in an increase in our transportation rates of about $12.0 million. Amounts collected from our customers in excess of this settlement amount will be deferred and returned to customers in our next PGA rate request in late 2007.

Gas Transmission Northwest’s (GTN) rate case proposes, among other things, an increase in firm transportation rates of approximately 71 percent. In connection with this filing, our transportation rates on that pipeline increased by approximately $3.1 million annually. The primary reason for GTN’s filing was unsubscribed capacity on the system due to significant capacity turnback and shipper defaults. The filed rates and associated tariff sheets became effective on January 1, 2007, subject to refund pending further proceedings in the case.

Increases in interstate pipeline transportation expenses are subject to our PGA mechanism and are 100 percent passed-through to customers in both Oregon and Washington. Both of the filed general rate increases were reflected in our 2006 PGA filings.

Utility Regulation Legislation

During 2005, the Oregon legislature passed Senate Bill 408 (SB 408) relating to taxes collected by utilities in rates on or after January 1, 2006. SB 408 requires Oregon investor-owned electric and gas utilities to file annual reports and other information with the OPUC. The report is to be filed by October 15 of the year following the reporting year and must identify the amount of income taxes paid, either by the utility or its consolidated group and properly attributed to the utility, as well as the amount of taxes authorized to be collected in rates. If the OPUC determines that the difference between the two amounts is greater than $100,000, the utility is required to establish an “automatic adjustment clause” to adjust rates.

In September 2006, the OPUC issued a final order adopting permanent rules to implement SB 408. The permanent rules established reference points for determining margins and effective tax rates from a utility’s ratemaking proceedings. In addition, the OPUC adopted an apportionment methodology for determining taxes properly attributed to the utility from a consolidated tax filing. The OPUC also determined that interest should accrue beginning January 1, 2006, using a mid-year convention for amounts determined under the automatic adjustment clause.

Utilities subject to SB 408 were required to seek a Private Letter Ruling (PLR) from the Internal Revenue Service requesting a ruling as to whether a utility’s compliance with the provisions of SB 408 would cause the utility to fail to comply with provisions of federal tax law, including the normalization requirements of the Internal Revenue Code. We submitted our PLR to the Internal Revenue Service in December 2006. While a utility’s request for a PLR is pending, no rate adjustment will be implemented. However, interest will begin to accrue on the amount of any rate adjustment determined by the OPUC.

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Based on our assessment of the permanent rules, we have estimated that our 2007 Tax Report for the 2006 tax year will reflect a surcharge of approximately $1.6 million; that is, the amount of taxes paid to government entities will exceed the amount of taxes the utility collected in rates, thus creating a rate adjustment that requires a reimbursement from customers. It is anticipated that any amounts due from customers for the 2006 tax year would not be realized until after June 1, 2008, pending a review by the OPUC. We have determined that the recognition of this regulatory gain in our statement of operations is uncertain until: the OPUC completes its review of how the final rules will be applied to our 2006 financial results; the underlying estimates are finalized; and efforts in the current Oregon legislative session to potentially change certain provisions of SB 408 are completed. Based on our current corporate structure and level of non-utility investments and activities, we do not expect that ongoing compliance with SB 408 will have a material adverse effect on our financial condition, results of operations or cash flows.

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Comparison of Gas Distribution Operations

The following table summarizes the composition of gas utility volumes and revenues for the years ended December 31, 2006, 2005 and 2004:

										Favorable/(Unfavorable)
Thousands, except degree day and customer data	2006			2005			2004			2006 vs. 2005			2005 vs. 2004
Utility volumes - therms:
Residential sales		382,665			371,538			352,356			11,127			19,182
Commercial sales		242,683			233,987			222,875			8,696			11,112
Industrial - firm sales		66,971			74,880			62,843			(7,909	)		12,037
Industrial - firm transportation		150,153			135,807			176,978			14,346			(41,171	)
Industrial - interruptible sales		112,736			149,106			104,278			(36,370	)		44,828
Industrial - interruptible transportation		237,441			192,249			212,536			45,192			(20,287	)
Total utility volumes sold and delivered		1,192,649			1,157,567			1,131,866			35,082			25,701
Utility operating revenues - dollars:
Residential sales	$	536,468		$	471,502		$	383,067		$	64,966		$	88,435
Commercial sales		290,666			250,287			200,424			40,379			49,863
Industrial - firm sales		66,986			64,507			45,259			2,479			19,248
Industrial - firm transportation		4,901			4,087			5,035			814			(948	)
Industrial - interruptible sales		93,107			100,740			55,380			(7,633	)		45,360
Industrial - interruptible transportation		7,899			6,668			7,620			1,231			(952	)
Other revenues		161			2,862			4,160			(2,701	)		(1,298	)
Total utility operating revenues		1,000,188			900,653			700,945			99,535			199,708
Cost of gas sold		648,081			563,772			399,176			(84,309	)		(164,596	)
Revenue taxes		24,840			21,633			16,865			(3,207	)		(4,768	)
Utility net operating revenues (margin)	$	327,267		$	315,248		$	284,904		$	12,019		$	30,344
Utility margin: (1)
Residential sales	$	204,951		$	195,098		$	172,209		$	9,853		$	22,889
Commercial sales		83,334			78,919			70,565			4,415			8,354
Industrial - sales and transportation		32,383			31,632			31,026			751			606
Miscellaneous revenues		4,333			4,990			3,472			(657	)		1,518
Other margin adjustments		2,610			2,950			(1,939	)		(340	)		4,889
Margin before regulatory adjustments		327,611			313,589			275,333			14,022			38,256
Weather normalization mechanism		2,282			(1,308	)		7,873			3,590			(9,181	)
Decoupling mechanism		(2,626	)		2,967			1,698			(5,593	)		1,269
Utility margin	$	327,267		$	315,248		$	284,904		$	12,019		$	30,344
Customers - end of period:
Residential customers		575,116			556,667			537,152			18,449			19,515
Commercial customers		60,523			59,543			58,548			980			995
Industrial customers		945			953			935			(8	)		18
Total number of customers - end of period		636,584			617,163			596,635			19,421			20,528
Actual degree days		4,089			4,178			3,853
Percent colder (warmer) than average (2)		(4%	)		(2%	)		(10%	)

⁽¹⁾ Amounts reported as margin for each category of customers is net of demand charges and revenue taxes.

⁽²⁾ Average weather represents the 25-year average degree days, as determined in our last Oregon general rate case.

Certain amounts in prior years have been reclassified to conform to the current year presentation. These reclassifications had no impact on prior year results of operations.

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2006 compared to 2005:

Total utility margin increased $12.0 million or 4 percent in 2006 compared to 2005 with residential and commercial customers contributing an additional $12.3 million to margin in 2006, including weather normalization and decoupling mechanisms. The $0.8 million increase in margin from industrial customers in 2006 was offset by a decrease in revenue adjustments from regulatory deferrals and amortizations and miscellaneous fees. The weather normalization and decoupling mechanisms decreased margin by a net $2.0 million in 2006 compared to 2005, primarily reflecting lower than expected consumption decline due to customer conservation efforts.

Our customer base continued to grow in 2006, with a net increase of 19,421 customers. The growth rate for 2006 was 3.1 percent, compared to 3.4 percent in 2005. The slower growth rate in 2006 was primarily due to a smaller increase in residential customers reflecting a modest slowdown in new construction.

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 tariff that adjusts margin up or down based on changes in residential and commercial customer consumption, and we have a weather normalization mechanism that adjusts customer bills and our margin up or down based on above- or below-average temperatures during the winter heating season (see “Results of Operations—Regulatory Developments—Rate Mechanisms,” above). Both mechanisms are designed to reduce the volatility of our utility earnings.

In 2006, weather was 2 percent warmer than in 2005. The weather normalization mechanism added $2.3 million to margin for the year ended December 31, 2006 based on weather that was 4 percent warmer than average. The mechanism reduced margin by $1.3 million in 2005 based on weather that was 2 percent warmer than average. Generally, we would have expected the weather normalization mechanism in 2005 to recover lost margin when temperatures were warmer than average, but that year we lost heating volumes and corresponding margin revenues in the latter part of May when temperatures were significantly warmer than average because those volume and margin losses were not entirely covered by the weather normalization mechanism, which ends on May 15 each year.

The decoupling mechanism decreased margin by $2.6 million in 2006, after adjusting for price elasticity in the annual Oregon PGA filing, compared to a contribution of $3.0 million in 2005.

2005 compared to 2004:

Total margin increased $30.3 million or 11 percent in 2005 compared to 2004 with residential and commercial customers contributing an additional $23.3 million to margin, including weather normalization and decoupling mechanisms. Industrial customers contributed an additional $0.6 million to margin, and revenue adjustments for regulatory deferrals and amortizations and miscellaneous fees increased margin by $6.4 million. The weather normalization and decoupling mechanisms adjusted margin down by $7.9 million in 2005 compared to 2004, primarily reflecting the impact of 8 percent colder weather in 2005.

Our customer base increased by 20,528 in 2005 for a growth rate of 3.4 percent, compared to 3.2 percent in 2004.

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In 2005, weather was 8 percent colder than in 2004, which partially contributed to the 9 percent increase in margin from residential and commercial sales from those customers not covered by weather normalization. The weather normalization mechanism reduced margin by $1.3 million for the year ended December 31, 2005 based on weather that was 2 percent warmer than average but contributed $7.9 million to margin in 2004 based on weather that was 10 percent warmer than average.

The decoupling mechanism contributed $3.0 million to margin in 2005, after adjusting margin for expected price elasticity in the annual Oregon PGA filing, compared to a contribution of $1.7 million in 2004.

Residential and Commercial Sales

The primary factors that impact results of operations in the residential and commercial markets are seasonal weather patterns, competitive factors in the energy industry and economic conditions in our service territory.

2006 compared to 2005:

• volumes sold were 3 percent higher, primarily reflecting 3.1 percent customer growth in the residential and commercial sector and improved economic conditions, partially offset by 2 percent warmer weather;

• operating revenues were 15 percent higher, primarily due to a 3 percent increase in volumes and an 11 percent increase in the average rate per therm due to recent PGA rate increases, effective October 1, 2005 and November 1, 2006; and

• margin was 5 percent higher, reflecting customer growth and higher gas cost savings from our PGA incentive sharing mechanism in Oregon (see “Cost of Gas,” below).

2005 compared to 2004:

• volumes sold were 5 percent higher, including unbilled sales, reflecting the impact of 3.4 percent customer growth and 8 percent colder weather partially offset by declining average consumption due to customer conservation;

• operating revenues were 24 percent higher, primarily due to a 5 percent increase in volumes and an 18 percent increase in the average rate per therm due to the PGA rate increases, effective October 1, 2004 and 2005; and,

• margin was 13 percent higher reflecting customer growth and increases in gas cost savings from our PGA incentive sharing mechanism in Oregon (see “Cost of Gas,” below).

Typically, 80 percent or more of annual utility operating revenues are derived from gas sales to weather-sensitive residential and commercial customers. Although variations in temperatures between periods will affect volumes of gas sold to these customers, the effect on margin and net income is significantly reduced with the weather normalization mechanism in Oregon (see “Regulatory Matters—Rate Mechanisms,” above). Beginning in 2006, this mechanism is effective from December 1 through May 15 of each heating season. Approximately 10 percent of our residential and commercial customers are in Washington, where the mechanism is not in effect, and about 9 percent of our eligible Oregon customers have voluntarily elected not to be covered by the mechanism, so the mechanism does not fully insulate us from earnings volatility due to weather. The mechanism increased margin by a net $2.3 million in the twelve-month period ended December 31, 2006, decreased margin by $1.3 million in 2005 and increased margin by $7.9 million in 2004.

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Industrial Sales and Transportation

The primary factors that impact results of operations in the industrial sales and transportation markets are commodity costs, competitive factors in the energy industry and economic conditions in our service territory.

2006 compared to 2005:

• volumes delivered to industrial customers increased 15.3 million therms, or 2.8 percent, with the increase primarily in lower margin interruptible schedules;

• operating revenue decreased $3.1 million, or 1.8 percent, due to customers transferring from sales service to transportation service where cost of gas is not a component in operating revenues; and

• margin increased 2 percent, reflecting increased volumes.

2005 compared to 2004:

• volumes delivered to industrial customers decreased 4.6 million therms, or less than 1.0 percent;

• operating revenue increased $62.7 million, or 55 percent, reflecting a 34 percent increase in sales volumes due to customers that migrated from transportation to sales service where the cost of gas component is included in revenues and to rate increases effective October 1, 2004 and 2005; and

• margin increased 2 percent due to the migration of customers to higher margin rate schedules, partially offset by lower volumes.

Several large industrial customers transferred from sales service back to transportation service in 2006. In 2005, high natural gas prices resulted 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. Our tariff requires us to charge the incremental cost of gas supply incurred to serve those customers.

Other Revenues

Other revenues include miscellaneous fee income as well as revenue adjustments reflecting deferrals to, or amortizations from, regulatory asset or liability accounts other than deferrals relating to gas costs. Other revenues increased net operating revenues by $0.2 million in 2006, compared to $2.9 million in 2005 and $4.2 million in 2004.

2006 compared to 2005:

Other revenues in 2006 were $2.7 million lower than in 2005 primarily due a $5.6 million decrease in deferrals under the decoupling mechanism (see “Regulatory Matters—Rate Mechanisms,” above) and a $1.5 million increase in amortization of the decoupling deferrals from prior periods, partially offset by an increase of $1.3 million in interstate gas storage credits to customers reflecting increased net income from storage operations, a decrease of $1.7 million in amortization expense for the South Mist Pipeline Extension and a decrease of $1.0 million in the deferral for the Oregon income tax kicker refund.

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2005 compared to 2004:

In 2005, other revenues were $1.3 million lower than in 2004 primarily due to a $2.6 million decrease in interstate gas storage credits to customers resulting from lower net income from storage operations and the deferral of $1.0 million for the Oregon income tax kicker refund, partially offset by a $1.1 million increase in customer late payment fees and a special enhanced service contract and a $1.3 million increase in deferrals under the decoupling mechanism (see “Regulatory Matters—Rate Mechanisms,” above).

Cost of Gas Sold

Natural gas commodity prices have risen significantly in recent years. The effects of higher commodity prices and price volatility on core utility customers are mitigated, in part, through our use of underground storage facilities, fixed-price commodity hedge contracts and short term sales of excess gas supply and transportation capacity to off-system customers in periods when core utility customers do not require the full amount of contract gas supplies or firm pipeline capacity.

The total cost of gas sold was $648.1 million in 2006, an increase of $84.3 million or 15 percent compared to 2005, and cost of gas sold in 2005 was $563.8 million, an increase of $164.6 million or 41 percent higher than 2004. The cost per therm of gas sold includes current gas purchases, gas drawn from storage inventory, gains or losses from commodity hedges, margin from off-system gas sales, pipeline demand charges, seasonal demand cost balancing adjustments, regulatory gas cost deferrals and company gas use.

Under the PGA tariff in Oregon, our net income is affected within defined limits by changes in purchased gas costs (see “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above). In each of the last three years, our actual gas costs were lower than the gas costs embedded in rates, with the effect that our share of the cost savings increased margin by $8.1 million, $4.2 million and $0.6 million for 2006, 2005 and 2004, respectively.

We use a natural gas commodity-price hedge program under the terms of our Financial Derivatives Policy to help manage our exposure to floating price gas purchase contracts (see “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” above, and Note 11). We realized net losses of $20.0 million from our financial hedges in 2006, compared to gains of $88.9 million and $42.4 million in 2005 and 2004, respectively. Gains and losses from the financial hedging of utility gas purchases generally are included in cost of gas, which are factored into our PGA deferrals and annual rate changes, but to the extent that any utility gas hedge is entered into after the annual PGA filing, then the gains and losses are subject to our PGA incentive sharing mechanism with 67 percent deferred and 33 percent recorded to current income.

Business Segments Other than Local Gas Distribution

Gas Storage

We earned $6.0 million in net income from our non-utility gas storage business segment in 2006, after regulatory sharing and income taxes, equivalent to 21 cents a share, compared to $4.6 million or 17 cents a share in 2005 and $2.9 million or 11 cents a share in 2004 (see Note 2). Earnings from this business segment were higher in 2006 primarily because of increased net revenues

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from interstate storage service contracts and our contract with an independent energy marketing company that optimizes the value of our utility assets.

In Oregon, we retain 80 percent of the pre-tax income from gas storage as well as from third party optimization revenues when the costs of the capacity used have not been included in utility rates, or 33 percent of the pre-tax income from such storage and optimization when the capacity costs have been included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for crediting to our core utility customers. We have a similar sharing mechanism in Washington for pre-tax income derived from storage services and third party optimization.

Other

Net income from our other non-regulated investment activities was $0.8 million in both 2006 and 2005 and $0.6 million in 2004. In 2006, we recognized net income of $0.2 million from Financial Corporation, and we completed the sale of a non-utility real estate investment that contributed a $0.3 million gain, before tax. Also in 2006, we recognized an additional $0.2 million from a real estate transaction where the property was sold on an installment basis, and we reclassified our investment in a Boeing 737-300 aircraft to current assets due to the lease term expiration in 2007 and our expectation that the asset will be sold prior to year end.

Subsidiaries

Financial Corporation

Operating results in 2006 were net income of $0.2 million, compared to $0.3 million in 2005 and $0.2 million in 2004. Our investment in Financial Corporation was $2.6 million at December 31, 2006, compared to $3.1 million at December 31, 2005.

Operating Expenses

Operations and Maintenance

Operations and maintenance expenses increased by $1.3 million in 2006, or 1 percent, compared to 2005 and increased $11.1 million, or 11 percent, in 2005 compared to 2004. The following summarizes the major factors that contributed to changes in operations and maintenance expense:

2006 compared to 2005:

• a $2.0 million increase in payroll expense, primarily due to bonuses related to improved results on annual performance goals and an increase in the long-term incentive plan liability due to a higher total shareholder return than our peer group average on which the award is based;

• a $1.1 million increase in severance expenses related to the 2006 severance incentive plan; and

• a $0.8 million increase in stock option expense due to the required adoption of SFAS No. 123R related to stock-based compensation expense (see Note 4).

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Partially offsetting the above increases were:

• a $1.2 million decrease in system damages and damage claims written-off; and

• a $2.3 million reduction in charges related to a settlement with a group of industrial customers in 2005.

2005 compared to 2004:

• a $3.0 million increase in regular payroll-related expense resulting from employee additions, pay increases and higher benefit costs;

• a $2.3 million increase in bonus payroll expense related to improved results on performance goals and an increase in the accrued long-term incentive plan liability due to a higher stock price on which the award is based;

• a $2.0 million charge related to a settlement with a group of industrial customers;

• a $1.0 million increase in system damages and damage claims written-off;

• a $0.9 million increase related to employee severance charges;

• a $0.4 million increase in costs for software maintenance; and

• a $0.4 million increase in costs for consumer safety advertising.

Partially offsetting the above increases was:

• a $0.3 million decrease in uncollectible accounts expense reflecting improved collection results and cash recoveries of accounts previously written-off.

Some of the cost increases we experienced in 2005 over 2004 were included in the rates approved in our general rate cases in Oregon and Washington (see “Regulatory Matters—General Rate Cases,” above).

General Taxes

General taxes, which are principally comprised of property and payroll taxes, increased $1.2 million, or 5 percent, in 2006 compared to 2005, and increased $1.2 million, or 6 percent, in 2005 compared to 2004.

Payroll taxes decreased $0.1 million in 2006 compared to 2005 and decreased $0.5 million in 2005 compared to 2004. In 2004, payroll taxes included an accrual for taxes on the 2004 bonuses paid in 2005.

Property taxes increased $0.7 million in 2006 and $1.5 million in 2005 primarily due to increased utility plant in service.

Regulatory fees increased by $0.5 million or 28 percent in 2006 compared to 2005 due to higher utility operating revenues. Increases in regulatory fees are generally recovered on a timely basis through an increase in customer rates through the annual PGA filing.

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Depreciation and Amortization

The following table summarizes the increases in total plant and property and total depreciation and amortization for the three years ended December 31:

Thousands	2006			2005			2004
Plant and property:
Utility plant:
Depreciable	$	1,925,837		$	1,839,206		$	1,768,630
Non-depreciable, including construction work in progress		37,661			36,238			26,342
		1,963,498			1,875,444			1,794,972
Non-utility property:
Depreciable		36,952			36,920			27,109
Non-depreciable, including construction work in progress		5,700			3,916			6,854
		42,652			40,836			33,963
Total plant and property	$	2,006,150		$	1,916,280		$	1,828,935
Depreciation and amortization:
Utility plant	$	63,552		$	60,935		$	56,899
Non-utility property		883			710			472
Total depreciation and amortization expense	$	64,435		$	61,645		$	57,371
Average depreciation rate - utility		3.4	%		3.4	%		3.4	%
Average depreciation rate - non-utility		2.5	%		2.6	%		2.3	%

Total depreciation and amortization expense increased by $2.8 million, or 5 percent, in 2006 and by $4.3 million, or 7 percent, in 2005. The increased expense for both years is primarily due to additional investments in utility plant to meet continuing customer growth and to make system improvements (see “Financial Condition—Cash Flows—Investing Activities,” below, and Note 9). We recently completed a depreciation study on all company plant and property, which generally indicates that depreciation rates overall would be reduced if we maintain the existing average service life depreciation method. However, if the OPUC were to adopt a different depreciation method such as the equal life group method, then depreciation rates could increase. Utility depreciation rates and methods are subject to review and approval by the OPUC and WUTC, and new rates will not be placed into service until depreciation rate proceedings are approved. We intend to submit the depreciation study for regulatory approval in 2007 and implement the new rates upon approval. We do not anticipate that adoption of these new rates will have a material impact on our financial condition or results of operations.

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Other Income and Expense—Net

The following table provides details on other income and expense – net for the last three years:

Thousands	2006			2005			2004
Gains from company-owned life insurance	$	2,609		$	1,856		$	2,855
Allowance for funds used during construction - equity		-			-			708
Interest income		363			403			232
Other non-operating expenses		(852	)		(1,393	)		(1,222	)
Net interest on deferred regulatory accounts		(177	)		282			74
Earnings from equity investments of Financial Corporation		191			57			181
Total other income	$	2,134		$	1,205		$	2,828

Other income and expense–net improved by $0.9 million in 2006 over 2005. The increase was primarily due to higher gains of $0.8 million from company-owned life insurance, reflecting higher policy benefits realized during 2006, and a net decrease of $0.5 million in other non-operating expenses, reflecting cost reduction initiatives. These positive changes were partially offset by a $0.5 million increase in net interest charges on deferred regulatory accounts, reflecting higher net credit balances outstanding in these accounts.

Other income and expense–net was $1.6 million lower in 2005 compared to 2004. The decrease was primarily due to $1.0 million lower gains from company-owned life insurance, reflecting the liquidation of $17.6 million in cash surrender value of policies in 2004, and the absence of the equity component in the allowance for funds used during construction (AFUDC) reflecting lower construction work in progress balances.

Interest Charges–Net of Amounts Capitalized

Interest charges–net of amounts capitalized in 2006 was $2.0 million, or 5 percent, higher than in 2005, reflecting higher interest rates on short-term debt balances and slightly higher average balances of long-term debt outstanding during the period due to the issuance of $50 million in June 2005 and $25 million in December 2006. AFUDC reduced interest expense by $0.8 million in 2006, compared to reductions of $0.5 million in 2005 and $1.0 million in 2004. The increase in AFUDC in 2006 reflects higher construction work in progress balances. The decrease in AFUDC in 2005 reflects lower balances due to the completion in 2004 of our major South Mist Pipeline Extension project, which extended the pipeline from our Mist gas storage field to serve growing portions of our service area. The average interest crediting rate for AFUDC, comprised of short-term and long-term borrowing rates, as appropriate, was 4.7 percent in 2006, 3.1 percent in 2005 and 3.0 percent in 2004.

Income Tax Expense

Income tax expense totaled $36.2 million in 2006 compared to $32.7 million in 2005. The effective tax rate was 36.4 percent in 2006 compared to 36.0 percent in 2005. The higher 2006 effective tax rate partially reflects the expiration of a federal tax credit associated with Financial Corporation’s investment in a low-income housing project (see Note 2, “Other”) and non-taxable life insurance gains. Income tax expense increased by $6.2 million in 2005, as compared to total income tax expense of $26.5 million in 2004, and the effective tax rate increased 1.6 percent from an effective tax rate of 34.4 percent in 2004. The higher 2005 effective tax rate was primarily attributable to a decrease in tax benefits of $0.8 million resulting from a non-taxable gain on company-owned life insurance in 2004 and from $0.7 million in other tax adjustments recorded in 2004.

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A recent interpretation (FIN 48) of SFAS No. 109, “Accounting for Uncertainty in Income taxes—an interpretation of FASB Statement No. 109,” was issued by the FASB in July 2006 to address how companies should account for the tax benefits of timing and permanent income tax positions taken or expected to be taken in a tax return. See “Application of Critical Accounting Policies and Estimates—Accounting for Income Taxes,” above and Note 1, “Recent Accounting Pronouncements.”

Financial Condition

Capital Structure

Our goal is to maintain a target capital structure comprised of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt. When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources also are used to meet long-term debt redemption requirements and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below, and Notes 3, 5 and 6). Our consolidated capital structure was as follows:

December 31,	2006		2005
Common stock equity	48.1	%	47.2	%
Long-term debt	41.5	%	42.0	%
Short-term debt, including current maturities of long-term debt	10.4	%	10.8	%
Total	100.0	%	100.0	%

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

Liquidity and Capital Resources

At December 31, 2006, we had $5.8 million in cash and cash equivalents compared to $7.1 million at December 31, 2005. Short-term liquidity is provided by cash from operations and from the sale of commercial paper notes, which are supported by committed bank lines of credit. We have available committed bank lines totaling $200 million with five commercial banks through September 30, 2010 (see “Lines of Credit,” below, and Note 6). Short-term debt balances typically are reduced toward the end of the winter heating season as a significant amount of our current assets, primarily accounts receivable and gas inventories, are converted into cash.

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

To provide long-term financing, we periodically issue and sell secured or unsecured debt, preferred stock or common stock. In April 2004, we issued $40 million of common stock and in June 2005 and December 2006, we issued $50 million and $25 million of secured medium-term notes, respectively. At December 31, 2006, we had $85 million available for future issuance of debt or equity securities under a universal shelf registration, which was previously approved by the OPUC (see “Financing Activities,” below).

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

Based on the availability of short-term credit facilities and our expectation of being able to issue long-term debt and equity securities, we believe there is sufficient liquidity to satisfy our anticipated cash requirements, including the contractual obligations and investing and financing activities discussed below.

Dividend Policy

We have paid quarterly dividends on our common stock in each year since the stock first was issued to the public in 1951. Annual common dividend payments have increased each year since 1956. The amount and timing of dividends payable on our common stock are within the sole discretion of our Board of Directors. It is the intention of the Board of Directors to continue to pay cash dividends on common stock on a quarterly basis. However, the declarations and amounts of future dividends will be dependent upon our earnings, cash flows, financial condition and other factors.

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

The following table shows our contractual obligations by maturity and type of obligation.

	Payments Due in Years Ending December 31,
Thousands	2007		2008		2009		2010		2011		Thereafter		Total
Commercial paper	$	100,100	$	-	$	-	$	-	$	-	$	-	$	100,100
Long-term debt maturities		29,500		5,000		-		35,000		10,000		467,000		546,500
Interest on long-term debt		34,396		33,632		33,417		33,406		30,858		341,592		507,301
Pension funding obligation		13,139		13,818		14,513		15,615		16,221		93,212		166,518
Postretirement funding obligation		1,571		1,596		1,626		1,685		1,753		9,002		17,233
Capital leases		317		233		84		-		-		-		634
Operating leases		4,200		4,100		4,100		4,100		4,100		35,300		55,900
Gas purchase contracts1		283,180		177,943		98,807		47,263		25,828		73,179		706,200
Gas pipeline commitments		81,024		70,848		64,988		66,085		70,059		198,863		551,867
Other purchase commitments		15,121		57		-		-		-		-		15,178
Total	$	562,548	$	307,227	$	217,535	$	203,154	$	158,819	$	1,218,148	$	2,667,431

¹ All gas purchase contract use price formulas tied to monthly index prices. Commitment amounts are based on index prices at December 31, 2006.

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Other purchase commitments primarily consist of remaining balances under existing purchase orders. These and other contractual obligations are financed through cash from operations and from the issuance of short-term debt, which is periodically refinanced through the sale of long-term debt or equity securities.

Holders of certain long-term debt have put options that, if exercised, would require repurchases of up to $20 million principal amount in each of 2007, 2008 and 2009. If repurchased prior to maturity, then the interest obligation shown in the above table would be reduced in future years. The interest rate on the long-term debt issues with put options ranges between 6.52 percent and 7.05 percent.

In March 2004, our employees who are members of the Office and Professional Employees International Union, Local No. 11, approved a labor agreement (Joint Accord) covering wages, benefits and working conditions. This contract will expire on May 31, 2009.

Commercial Paper

Our primary source of short-term funds is from the sale of commercial paper notes. 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 also be used to temporarily fund capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our commercial paper program is supported by committed bank lines of credit (see “Lines of Credit,” below). We had $100.1 million in commercial paper notes outstanding at December 31, 2006, compared to $126.7 million at December 31, 2005.

Lines of Credit

In September 2005, we entered into agreements for unsecured lines of credit totaling $200 million with five commercial banks, replacing the former $150 million credit facilities. The bank lines of credit are available and committed for a term of five years from October 1, 2005 to September 30, 2010. Our bank lines are used primarily as back-up support for the notes payable under our commercial paper borrowing program. Commercial paper provides the liquidity to meet our working capital and external financing requirements.

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

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

The bank lines also require us to maintain an indebtedness to total capitalization ratio of 65 percent or less. Failure to comply with this covenant would entitle the banks to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at December 31, 2006 and 2005.

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Credit Ratings

The table below summarizes our credit ratings from two rating agencies, 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	Stable	Stable

On February 28, 2006, S&P raised the credit ratings on our senior secured long-term debt to “AA-” from “A+” and our senior unsecured long-term debt to “A+” from “A.” S&P also raised the credit ratings on commercial paper to “A-1+” from “A-1.” Both of the rating agencies have assigned us an investment grade rating. These credit ratings and ratings outlook 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 our securities. Each rating should be evaluated independently of any other rating.

In August 2006, we elected to discontinue the credit rating service from Fitch Ratings (Fitch) for cost management reasons. At the time this service was cancelled, Fitch had assigned an A+ rating to our secured long-term debt, an A rating to our unsecured long-term debt and an F1 rating to our commercial paper program. Also, the ratings outlook from Fitch was stable.

Redemptions of Long-Term Debt

In June 2006, we redeemed $8.0 million of secured 6.05% Series B Medium-Term Notes (MTNs) at maturity.

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

In August 2005, we called for redemption all of our outstanding Convertible Debentures, 7-1/4% Series due 2012, at 100 percent of their principal amount plus accrued interest to the date of redemption. During 2005, debentures with an aggregate principal amount of $4.0 million were converted into shares of common stock on or prior to the redemption date at the rate of 50.25 shares for each $1,000 principal amount of debentures and $0.5 million of debentures were redeemed.

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 2006, our cash flow from net income and operating activity adjustments, excluding working capital changes, increased by $44.6 million, primarily due to a $31.0 million decrease in cash contributions to our qualified defined benefit pension plans and a $18.2 million increase in cash collections from deferred gas costs and improved operating results, partially offset by a decrease in deferred income tax benefits reflecting the expiration of higher tax benefits realized in 2004 from accelerated bonus

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depreciation. In 2005, the cash flow from net income and operating activity adjustments, excluding working capital changes, decreased by $25.9 million, primarily due to a decrease in deferred income tax benefits reflecting the expiration of higher tax benefits realized in 2004 from accelerated bonus depreciation and an increase in cash contributions to our qualified pension plans, partially offset by an increase in net income and cash from deferred gas costs.

The overall change in cash flow from operating activities in 2006 compared to 2005 was an increase of $69.5 million. The overall change in cash flow from operations was a decrease of $25.8 million in 2005 compared to 2004. The significant factors contributing to the cash flow changes between years are as follows:

2006 compared to 2005:

• an increase in net income added $5.3 million to cash flow;

• a decrease in cash of $26.0 million related to a deferred income tax benefit in 2006 compared to a deferred income tax expense in 2005;

• the change to regulatory liabilities in 2006 from regulatory receivables in 2005 related to deferred gas costs increased cash flow by $18.2 million, reflecting deferral activity between the two years with respect to purchased gas cost savings and off-system gas sales under our PGA tariff;

• cash increased by $31.0 million in 2006 compared to 2005 due to the 2005 cash contributions to our qualified defined benefit pension plans;

• an increase in cash in 2006 of $36.5 million due to a decrease in accounts receivable and accrued unbilled revenue related to warmer weather around year end;

• an increase of $27.7 million in cash resulting primarily from a decrease in gas inventory costs in 2006 compared to 2005;

• a decrease in income taxes receivable contributed $10.5 million to cash in 2006;

• a reduction in accounts payable decreased cash $54.5 million in 2006 primarily due to lower gas prices around year end;

• a reduction in prepayments increased cash $6.4 million in 2006; and

• an increase in deferred regulatory liabilities increased cash by $11.3 million in 2006.

2005 compared to 2004:

• an increase in net income added $7.6 million to cash flow;

• a decrease in deferred income tax expense in 2005, compared to a significant increase in 2004, decreased cash by $27.2 million, reflecting the expiration of higher tax benefits realized in 2004 from accelerated bonus depreciation;

• a small decrease in regulatory receivables in 2005, compared to a large increase in 2004 for deferred gas costs, increased cash flow by $17.8 million, reflecting deferral activity, including collections, between the two years with respect to purchase gas cost savings and off-system gas sales under our PGA tariff;

• cash contributions to our qualified defined benefit pension plan decreased cash flows by $22.7 million, primarily due to a $31.0 million pension contribution to those plans in 2005, compared to $8.3 million in 2004;

• an increase in deferred environmental costs decreased cash flow by $6.9 million, reflecting an increase in cash requirements for environmental remediation work during 2005 (see “Contingent Liabilities—Environmental Matters,” below);

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• a larger increase in accounts receivable reduced cash flow by $11.6 million, primarily reflecting the higher gas prices and the timing of customer account collections;

• a larger increase in accrued unbilled revenue reduced cash flow by $11.8 million, reflecting a combination of higher gas prices and colder weather in December 2005 compared to December 2004;

• an increase in inventories decreased cash flow by $4.1 million, primarily reflecting injections into storage at higher gas prices;

• a decrease in income taxes receivable increased cash flow by $9.7 million; and

• an increase in accounts payable increased cash flow by $16.4 million, primarily reflecting higher gas prices at year-end 2005.

We have lease and purchase commitments relating to our operating activities that are financed with cash flows from operations (see “Liquidity and Capital Resources—Contractual Obligations,” above, and Note 12).

Investing Activities

Cash requirements for investing activities in 2006 totaled $90.6 million, down slightly from $92.0 million in 2005. Cash requirements for the acquisition and construction of utility plant totaled $95.3 million in 2006, up from $89.3 million in 2005. The increase in cash requirements for utility construction in 2006 primarily reflects $12.5 million of capital expenditures in 2006 for an automated meter reading system, which will be completed in 2007.

Cash requirements for investing activities in 2005 totaled $92.0 million, down from $132.6 million in 2004. Cash requirements for the acquisition and construction of utility plant totaled $89.3 million, down from $138.3 million in 2004. The decrease in cash requirements for utility construction in 2005 reflects the completion in 2004 of our South Mist Pipeline Extension project, which extended the pipeline from our Mist gas storage field to serve growing portions of our service area. The total cost of the project was approximately $108.0 million, which includes amounts reflected in investing activities primarily over the 2002-2004 period. The cost of service associated with the final phase of the project, net of deferred tax benefits, was included in utility customer rates beginning in the fourth quarter of 2004.

Investments in our pipeline integrity management program were $11.0 million in 2006, compared to $6.1 million in 2005 and $1.6 million in 2004. These costs are estimated at approximately $50 million to $100 million over a ten-year period through 2012. The costs are accumulated over each 12-month period ending September 30, and the capitalized costs, subject to audit, are recovered through the annual PGA based on adjustments to rate base each year. The approved regulatory accounting and rate treatment for these costs extends through September 30, 2008, and may be reviewed for potential extension after that date.

Investments in non-utility property totaled $1.8 million in 2006, compared to $6.8 million in 2005 and $10.6 million in 2004. The lower investments in both 2006 and 2005 compared to 2004 were primarily due to the completion of expansion projects at our gas storage facilities in 2004 and partially in 2005.

In 2006, we received proceeds from the settlement of company-owned life insurance policy benefits totaling $4.0 million compared to $0.3 million in 2005. In 2004, we received proceeds from the surrender of certain life insurance policies as well as from policy benefit distributions totaling $17.6 million.

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During the five-year period 2007 through 2011, utility construction expenditures are estimated at between $500 and $600 million. The estimated level of capital expenditures over the next five years reflects continued customer growth, gas storage development, 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.

Our utility and non-utility capital expenditures for 2007 are estimated to total $110 million, including $27 million for customer growth, $21 million for system improvements, $13 million for equipment, facilities and information technology, $10 million for pipeline integrity costs, $5 million for an automated meter reading project, $14 million for utility and non-utility gas storage, and $20 million for construction overhead. These estimates do not include costs of the potential pipeline project with GTN or other investments that may be driven by our business process redesign (see “Strategic Opportunities,” above).

In December 2003, the U.S. Department of Transportation’s Office of Pipeline Safety (now the Pipeline Hazardous Materials Safety Administration) issued a rule that specifies the detailed requirements for transmission pipeline integrity management plans as mandated by the Pipeline Safety Act. See Part I., Item 1., “Pipeline Safety.” We have met the first major milestones required by the Act and are on track to complete the next milestone, inspection of the highest risk 50 percent of our transmission pipelines, by the end of 2007.

Financing Activities

Cash used in financing activities in 2006 totaled $59.4 million, as compared to cash provided by financing in 2005 of $14.8 million. Factors contributing to the $74.2 million net change were the net change in short-term debt ($50.8 million), a lower amount of long-term debt issued during 2006 ($25.0 million) and the lower amount of equity financing in 2006 ($3.6 million), partially offset by a smaller redemption of long-term debt in 2006 compared to 2005 ($7.5 million).

Cash provided by financing activities in 2005 totaled $14.8 million, compared to $28.3 million in 2004. Factors contributing to the $13.4 million decrease were the redemption of long-term debt and convertible debentures ($15.5 million), the increased repurchases of common stock in 2005 ($14.4 million) and the lower amount of equity financing in 2005 ($39.1 million), partially offset by the issuance of $50 million of secured MTNs during 2005 and the net change in short-term debt ($6.9 million).

In December 2006, we sold $25 million of 5.15% Series B, secured MTNs due 2016 and used the proceeds to reduce short-term indebtedness and to fund utility construction.

In 2005, we sold $40 million of 4.70% Series B, secured MTNs due 2015 and $10 million of 5.25% Series B, secured MTNs due 2035, and used the proceeds to redeem long-term debt, to reduce short-term indebtedness and to make investments in utility plant.

In April 2004, we issued and sold 1,290,000 shares of our common stock in an underwritten public offering, and used the net proceeds of $38.5 million to reduce short-term indebtedness and to fund, in part, our utility construction program.

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In 2000, we announced a program to repurchase up to 2 million shares, or up to $35 million in value, of our common stock through a repurchase program, and in 2006 that program was modified to 2.6 million shares and $85 million in value and extended through May 2007. The purchases are made in the open market or through privately negotiated transactions. Repurchases pursuant to the program in 2006 totaled 395,500 shares or $16.0 million and in 2005 were 410,200 shares, or $14.9 million. No shares were purchased pursuant to the program in 2004. Since the program’s inception, we have repurchased 1,161,100 shares of common stock at a total cost of $39.1 million (see Part II, Item 5, “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities,” above).

In 2006, we produced free cash flow of $19.7 million, compared to 2005 and 2004 when we had negative free cash flows of $49.3 million and $62.8 million, respectively. Free cash flow is the amount of cash left over after the payment of all cash expenses, capital expenditures (investment activities) and dividends. Free cash flow is a non-GAAP financial measure, but we believe this supplemental information enables the reader of the financial statements to better understand our cash generating ability and to benefit from seeing cash flow results from management’s perspective in addition to the traditional GAAP presentation. We monitor free cash flow as one measure of our return on investments. Provided below is a reconciliation from cash provided by operations (GAAP basis) to our non-GAAP free cash flow.

Thousands (year ended December 31)	2006			2005			2004
Cash provided by operating activities	$	148,566		$	79,066		$	104,899
Cash used in investing activities		(90,567	)		(92,008	)		(132,631	)
Cash divided payments on common stock		(38,298	)		(36,376	)		(35,105	)
Free cash flow	$	19,701		$	(49,318	)	$	(62,837	)

The free cash flow information presented above is not intended to be a substitute for, nor is it meant to be a better measure of, cash flow results prepared in accordance with GAAP. In addition, the non-GAAP measure we provide may be calculated differently by other companies that present a similar non-GAAP financial measure for free cash flow.

Pension Cost and Funding Status of Qualified Retirement Plans

Pension costs are determined in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” (see “Application of Critical Accounting Policies—Accounting for Pensions,” above). Pension costs are allocated between operations and maintenance expense and capital accounts based on employee payroll distributions.

Pension costs for our two qualified defined benefit pension plans totaled $8.2 million in 2006, an increase of $1.3 million over 2005. The increase in 2006 pension costs was primarily due to the lower discount rate (5.75 percent in 2006 compared to 6.00 percent in 2005) and the adoption of new mortality rate assumptions as of December 31, 2005.

We make contributions to our qualified defined benefit pension plans based on actuarial assumptions and estimates, tax regulations and funding requirements under federal law. Generally, it is our policy to contribute at least the minimum amount required by Internal Revenue Code regulations and the Employee Retirement Income Security Act of 1974. It is also our intent to contribute additional

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amounts sufficient on a sound actuarial basis to maintain funding targets and provide for the payment of future benefits under the plans.

During 2005, we contributed $31 million to our two qualified defined benefit plans, but no additional contributions were made to these plans in 2006. Although we were not required to make cash contributions in either 2005 or 2006 based on minimum funding requirements, we contributed to these plans in 2005 to maintain a target funding level based on plan benefit obligations.

The fair market value of the assets in these two plans increased to $236.5 million at December 31, 2006, up from $218.6 million at December 31, 2005. The increase included $31.5 million in investment gains, which were offset in part by $12.1 million in withdrawals to pay benefits and $1.4 million in eligible expenses of the two plans. The present value of benefit obligations under the two plans increased from $254 million at December 31, 2005 to $255 million at December 31, 2006. The two qualified defined benefit pension plans were underfunded in aggregate by approximately $18.9 million at December 31, 2006.

Pension costs for the plans totaled $6.9 million in 2005, compared to $6.6 million in 2004. The increase in pension costs in 2005 was primarily due to the lower discount rate (6.00 percent in 2005 compared to 6.25 percent in 2004), partially offset by higher earnings on additional cash contributions to the plans.

At December 31, 2005, the fair market value of the qualified defined benefit pension plans’ assets totaled $219 million, up from $187 million at December 31, 2004. The increase included $13.5 million in investment gains and employer contributions of $31 million, which were offset in part by $11.8 million in withdrawals to pay benefits and $0.9 million in eligible expenses of the two plans. The present value of benefit obligations under the two plans increased from $209 million to $254 million during 2005, primarily due to the adoption of a new mortality table to reflect the increased life expectancies of plan participants. The two plans were underfunded in aggregate by about $36 million at December 31, 2005.

Despite the increase in pension costs and the current underfunded status of the plans, we believe the plans to be adequately funded and that we will be able to continue to maintain appropriate funding levels. The annualized returns for the past one, five and 10 years ended December 31, 2006 were 14.9 percent, 10.1 percent and 10.2 percent, respectively. We do not expect our current or future cash contribution requirements to the two plans to have a material adverse effect on our liquidity or financial condition (see Note 7). Effective January 1, 2007, we closed our Non-Bargaining Unit Plan to newly-hired or rehired employees.

Ratios of Earnings to Fixed Charges

For the years ended December 31, 2006, 2005 and 2004, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were 3.40, 3.32 and 3.02, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income.

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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 “Application of Critical Accounting Policies and Estimates—Contingencies,” above). At December 31, 2006, a cumulative $27.8 million in environmental costs was recorded as a regulatory asset, including $19.1 million of costs paid to-date and $8.7 million of estimated accrued future environmental costs. If it is determined that both the insurance recovery and future customer rate recovery of such costs is not probable, then the costs will be charged to expense in the period such determination is made. For further discussion of contingent liabilities, see Note 12.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including commodity supply risk, weather risk and interest rate risk. The following describes our exposure to these risks.

Commodity Supply Risk

We enter into short-term, medium-term and long-term natural gas supply contracts, along with associated short-, medium- and long-term transportation capacity contracts. Historically, we have taken physical delivery of at least the minimum quantities specified in our natural gas supply contracts. These contracts are primarily index-based and subject to annual re-pricing, a process that is intended to reflect anticipated market price trends during the next year. Our PGA mechanisms in Oregon and Washington provide for the recovery from customers of actual commodity costs, except that, for Oregon customers, we absorb 33 percent of the higher cost of gas sold, or retain 33 percent of the lower cost, in either case as compared to the annual PGA price built into customer rates.

Market risks related to potential adverse changes in commodity prices, foreign exchange rates or counterparty credit quality in relation to these financial and physical contracts are discussed below.

Commodity Price Risk

Natural gas commodity prices are subject to fluctuations due to unpredictable factors including weather, pipeline transportation congestion and other factors that affect short-term supply and demand. Commodity-price swap and call option contracts (financial hedge contracts) are used to convert certain natural gas supply contracts from floating prices to fixed prices. These financial hedge contracts are generally included in our annual PGA filing, subject to a prudency review. At December 31, 2006 and 2005, notional amounts under these commodity swap and call option contracts totaled $349.7 million and $470.5 million, respectively. If all of the commodity-price swap and call option contracts had been settled on December 31, 2006, a regulatory loss of $37.8 million would have been realized and deferred (see Note 11). We monitor the liquidity of our financial derivative contracts. Based on the existing open interest in the contracts held, we believe existing contracts to be liquid. All of our financial derivative contracts settle within the next two years. The $37.8 million unrealized loss is an estimate of future cash flows that are expected to be paid as follows: $30.8 million in 2007 and $7.0 million in 2008. The amount realized will change based on market prices at the time contract settlements are fixed.

Foreign Currency Risk

The costs of certain natural gas commodity supplies and certain pipeline services purchased from Canadian suppliers are subject to changes in the value of the Canadian currency in relation to the U.S. currency. Foreign currency forward contracts are used to hedge against fluctuations in exchange

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rates with respect to the purchases of natural gas from Canadian suppliers. At December 31, 2006 and 2005, notional amounts under foreign currency forward contracts totaled $5.0 million and $19.9 million, respectively. As of December 31, 2006, no foreign currency forward contracts extended beyond December 31, 2007. If all of the foreign currency forward contracts had been settled on December 31, 2006, a loss of $0.1 million would have been realized (see Note 11).

Credit Risk

Credit exposure to suppliers. Certain suppliers that sell us gas have either relatively low credit ratings or are not rated by major credit rating agencies. To manage this supply risk, we purchase gas from a number of different suppliers, with no single supplier accounting for more than 20 percent of our total purchases for a given monthly period. We evaluate and continuously monitor suppliers’ creditworthiness and maintain the ability to require additional financial assurances, including deposits, letters of credit or surety bonds in case a supplier defaults. In the event of a supplier’s failure to deliver contracted volumes of gas, the regulated utility would need to replace those volumes at prevailing market prices, which may be higher or lower than the original transaction prices. We believe these costs would be subject to the PGA sharing mechanism discussed above. Since most of our commodity supply contracts are priced at the monthly market index price, and we have significant storage flexibility, we believe that it is unlikely that a supplier default would have a material adverse effect on our financial condition or results of operations.

Credit exposure to financial derivative counterparties. Based on estimated fair value, our credit exposure to financial derivative counterparties relating to commodity swap and call option contracts was a negative $41.0 million at December 31, 2006. Our Financial Derivatives Policy requires counterparties to have a minimum 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. There were no credit rating downgrades for any of our counterparties during 2006.

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 S&P or Moody’s rating, or a middle rating if the entity is split-rated more than one rating level:

	Financial Derivative Position by Credit Rating         Unrealized Fair Value Gain (Loss)
Thousands	Dec. 31, 2006			Dec. 31, 2005
AAA/Aaa	$	-		$	-
AA/Aa		(40,955	)		172,315
A/A		-			-
BBB/Baa		-			3,346
Total	$	(40,955	)	$	175,661

Credit exposure to customers. Increases in the price of natural gas are expected to increase our credit exposure to customers. However, in the short term, market prices have moderated and resulted in some of our large industrial customers changing from sales services to transportation service. Under sales service, the customer purchases both its gas commodity supply and transportation service from us. Under transportation service, the customer purchases its commodity supplies from an independent third party, with us only providing the transportation service for delivery of that gas to the customer’s premise. As a result of this migration from sales service to transportation service, our credit exposure to large industrial customers is expected to moderate. We monitor and manage the credit exposure of

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our industrial customers through credit policies and procedures, which are designed to reduce credit risk. These policies and procedures include an ongoing review of credit risks, including changes in the services provided to industrial customers as well as changes in market conditions and customers’ credit quality. Changes in credit risk may require us to obtain additional assurance, such as deposits, letters of credit, guarantees and prepayments to reduce our credit exposure.

We also monitor and manage the credit exposure of our residential and commercial customers. This credit risk is largely mitigated by the nature of our regulated business and reasonably short collection terms, as well as by the consistent application of our credit policies and procedures.

Weather Risk

We are exposed to weather risk primarily from our regulated utility business. A large percentage of our utility margin is volume driven, and current rates are based on an assumption of average weather. In 2003, the OPUC approved a weather normalization mechanism for residential and commercial customers. This mechanism affects customer bills between December 1 through May 15 of each winter heating season, increasing or decreasing the margin component of customers’ rates to reflect “average” weather using the 25-year average temperature for each day of the billing period. The mechanism is intended to stabilize the recovery of our utility’s fixed costs and reduce fluctuations in customers’ bills due to colder or warmer than average weather. Customers in Oregon are allowed to opt out of the weather normalization mechanism. As of December 31, 2006, about 9 percent of our Oregon customers had opted out. In addition to the Oregon customers opting out, our Washington residential and commercial customers account for approximately 10 percent of our total customer base and are not covered by weather normalization. The combination of Oregon and Washington customers not covered by a weather normalization mechanism is less than 20 percent of all residential and commercial customers.

Interest Rate Risk

We are exposed to interest rate risk associated with new debt financing needed to fund capital requirements, including future contractual obligations and maturities of long-term and short-term debt. Interest rate risk is managed through the issuance of fixed-rate debt with varying maturities. We may also enter into financial derivative instruments, including interest rate swaps, locks, options and other hedge products, to manage and mitigate interest rate exposure. At December 31, 2006 and 2005, we had no variable-rate long-term debt and no financial derivative instruments to hedge interest rates. Holders of certain long-term debt have put options that, if exercised, would accelerate maturities by $20 million in each of 2007, 2008 and 2009 (see Note 5 and Note 10).

Forward-Looking Statements

This report and other presentations made by us from time to time may contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and other statements that are other than statements of historical facts. Our expectations, beliefs and projections are expressed in good faith and are believed to 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, including those of the OPUC and the WUTC, with respect to allowed rates of return, industry and rate

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structure, purchased gas cost and investment recovery, acquisitions and dispositions of assets and facilities, operation and construction of plant facilities, present or prospective wholesale and retail competition, changes in tax laws and policies and changes in and compliance with environmental and safety laws, regulations, policies and orders, and laws, regulations and orders with respect to the maintenance of pipeline integrity;

• implementation by the OPUC of final 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, pandemic events and other natural phenomena, including earthquakes or other geohazard events;

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

• competition for retail and wholesale customers;

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

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

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

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

• unanticipated changes that may affect our liquidity or access to capital markets;

• risks relating to the execution of our business process redesign;

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

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

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

• unanticipated changes in operating expenses and capital expenditures;

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

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

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

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

• legal and administrative proceedings and settlements.

All subsequent forward-looking statements, whether written or oral and whether made by or on behalf of NW Natural, also are expressly qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, and 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.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Table of Contents

		Page
1.	Management’s Report on Internal Control Over Financial Reporting	66
2.	Report of Independent Registered Public Accounting Firm	67
3.	Consolidated Financial Statements:
	Consolidated Statements of Income for the Years Ended December 31, 2006, 2005 and 2004	69
	Consolidated Balance Sheets at December 31, 2006 and 2005	70
	Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the Years Ended December 31, 2006, 2005 and 2004	72
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004	73
	Consolidated Statements of Capitalization at December 31, 2006 and 2005	74
	Notes to Consolidated Financial Statements	75
4.	Quarterly Financial Information (unaudited)	110
5.	Supplementary Data for the Years Ended December 31, 2006, 2005 and 2004:
	Financial Statement Schedule
	Schedule II—Valuation and Qualifying Accounts and Reserves	111

Supplemental Schedules Omitted

All other schedules are omitted because of the absence of the conditions under which they are

required or because the required information is included elsewhere in the financial statements.

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America (GAAP). Our internal control over financial reporting includes those policies and procedures that:

(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions involving company assets;

(ii) provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in accordance with GAAP, and that receipts and expenditures are being made only in accordance with authorizations of management and the Board of Directors; and

(iii) provide reasonable assurance regarding prevention or timely detection of the unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of NW Natural’s internal control over financial reporting as of December 31, 2006. In making this assessment, management used the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.

Based on our assessment and those criteria, management has concluded that NW Natural maintained effective internal control over financial reporting as of December 31, 2006.

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in this annual report.

/s/ Mark S. Dodson

Mark S. Dodson

President and Chief Executive Officer

/s/ David H. Anderson

David H. Anderson

Senior Vice President and Chief Financial Officer

February 28, 2007

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Northwest Natural Gas Company:

We have completed integrated audits of Northwest Natural Gas Company’s consolidated financial statements and of its internal control over financial reporting as of December 31, 2006, in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements and financial statement schedule

In our opinion, the consolidated financial statements listed in the accompanying table of contents present fairly, in all material respects, the financial position of Northwest Natural Gas Company and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying table of contents presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for share based compensation in 2006 and the manner in which it accounts for defined benefit pension and other postretirement plans effective December 31, 2006.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Controls Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States).

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Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and the board of directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PricewaterhouseCoopers LLP

Portland, Oregon

February 28, 2007

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NORTHWEST NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

Thousands, except per share amounts (year ended December 31)	2006		2005		2004
Operating revenues:
Gross operating revenues	$	1,013,172	$	910,486	$	707,604
Less: Cost of sales		648,156		563,860		399,244
Revenue taxes		24,840		21,633		16,865
Net operating revenues		340,176		324,993		291,495
Operating expenses:
Operations and maintenance		114,560		113,216		102,155
General taxes		24,419		23,185		21,943
Depreciation and amortization		64,435		61,645		57,371
Total operating expenses		203,414		198,046		181,469
Income from operations		136,762		126,947		110,026
Other income and expense - net		2,134		1,205		2,828
Interest charges - net of amounts capitalized		39,247		37,283		35,751
Income before income taxes		99,649		90,869		77,103
Income tax expense		36,234		32,720		26,531
Net income	$	63,415	$	58,149	$	50,572
Average common shares outstanding:
Basic		27,540		27,564		27,016
Diluted		27,657		27,621		27,283
Earnings per share of common stock:
Basic	$	2.30	$	2.11	$	1.87
Diluted	$	2.29	$	2.11	$	1.86

------------------------------------

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Thousands (December 31)	2006			2005
Assets:
Plant and property:
Utility plant	$	1,963,498		$	1,875,444
Less accumulated depreciation		574,093			536,867
Utility plant - net		1,389,405			1,338,577
Non-utility property		42,652			40,836
Less accumulated depreciation and amortization		6,916			5,990
Non-utility property - net		35,736			34,846
Total plant and property		1,425,141			1,373,423
Current assets:
Cash and cash equivalents		5,767			7,143
Accounts receivable		82,070			84,418
Accrued unbilled revenue		87,548			81,512
Allowance for uncollectible accounts		(3,033	)		(3,067	)
Regulatory assets		31,509			3,879
Fair value of non-trading derivatives		5,109			163,759
Inventories:
Gas		68,576			77,256
Materials and supplies		9,552			8,905
Income taxes receivable		-			13,234
Prepayments and other current assets		21,695			54,309
Total current assets		308,793			491,348
Investments, deferred charges and other assets:
Regulatory assets		164,771			94,972
Fair value of non-trading derivatives		1,448			14,894
Other investments		47,985			58,451
Other		8,718			9,216
Total investments, deferred charges and other assets		222,922			177,533
Total assets	$	1,956,856		$	2,042,304

-----------------------------------

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

CONSOLIDATED BALANCE SHEETS

Thousands (December 31)	2006			2005
Capitalization and liabilities:
Capitalization:
Common stock	$	371,127		$	87,334
Premium on common stock		-			296,471
Earnings invested in the business		230,774			205,687
Unearned stock compensation		-			(650	)
Accumulated other comprehensive income (loss)		(2,356	)		(1,911	)
Total common stock equity		599,545			586,931
Long-term debt		517,000			521,500
Total capitalization		1,116,545			1,108,431
Current liabilities:
Notes payable		100,100			126,700
Long-term debt due within one year		29,500			8,000
Accounts payable		113,579			135,287
Taxes accrued		21,230			12,725
Interest accrued		2,924			2,918
Regulatory liabilities		11,919			163,660
Fair value of non-trading derivatives		38,772			99
Other current and accrued liabilities		21,455			29,916
Total current liabilities		339,479			479,305
Deferred credits and other liabilities:
Deferred income taxes and investment tax credits		210,084			227,400
Regulatory liabilities		202,982			180,827
Pension and other postretirement benefit liabilities		52,690			17,323
Fair value of non-trading derivatives		11,031			6,777
Other		24,045			22,241
Total deferred credits and other liabilities		500,832			454,568
Commitments and contingencies (see Note 12)		-			-
Total capitalization and liabilities	$	1,956,856		$	2,042,304

-----------------------------------

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND

COMPREHENSIVE INCOME

Thousands	Common Stock and Premium			Earnings Invested in the Business			Unearned Stock Compensation			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity			Comprehensive Income
Balance at Dec. 31, 2003	$	338,008		$	170,053		$	(729	)	$	(1,016	)	$	506,316
Net Income		-			50,572			-			-			50,572		$	50,572
Minimum pension liability adjustment - net of tax		-			-			-			(802	)		(802	)		(802	)
Purchases of restricted stock		(55	)		(51	)		(431	)		-			(537	)
Restricted stock amortizations		-			-			298			-			298
Dividends paid on common stock		-			(35,105	)		-			-			(35,105	)
Tax benefits from employee stock option plan		872			-			-			-			872
Issuance of common stock		47,148			-			-			-			47,148
Convertible debentures		1,292			-			-			-			1,292
Common stock expense		-			(1,537	)		-			-			(1,537	)
Balance at Dec. 31, 2004		387,265			183,932			(862	)		(1,818	)		568,517		$	49,770
Net Income		-			58,149			-			-			58,149		$	58,149
Minimum pension liability adjustment - net of tax		-			-			-			(93	)		(93	)		(93	)
Restricted stock amortizations		-			-			212			-			212
Dividends paid on common stock		-			(36,376	)		-			-			(36,376	)
Tax benefits from employee stock option plan		220			-			-			-			220
Issuance of common stock		7,266			-			-			-			7,266
Common stock repurchased		(14,945	)		-			-			-			(14,945	)
Convertible debentures		3,999			-			-			-			3,999
Common stock expense		-			(18	)		-			-			(18	)
Balance at Dec. 31, 2005		383,805			205,687			(650	)		(1,911	)		586,931		$	58,056
Net Income		-			63,415			-			-			63,415		$	63,415
Minimum pension liability adjustment - net of tax		-			-			-			(81	)		(81	)		(81	)
Recognition of non-qualified employee benefit plan liability, net of tax											(364	)		(364	)
Restricted stock amortizations		298			-			-			-			298
Dividends paid on common stock		-			(38,298	)		-			-			(38,298	)
Tax benefits from employee stock option plan		317			-			-			-			317
Stock-based compensation		555			-			-			-			555
Restricted stock reclassification		(650	)		-			650			-			-
Issuance of common stock		2,773			-			-			-			2,773
Common stock repurchased		(15,971	)		-			-			-			(15,971	)
Common stock expense		-			(30	)		-			-			(30	)
Balance at Dec. 31, 2006	$	371,127		$	230,774		$	-		$	(2,356	)	$	599,545		$	63,334

------------------------------------

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

Thousands (year ended December 31)	2006			2005			2004
Operating activities:
Net income	$	63,415		$	58,149		$	50,572
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		64,435			61,645			57,371
Deferred income taxes and investment tax credits		(16,440	)		9,551			36,713
Undistributed earnings from equity investments		(191	)		(57	)		(181	)
Deferred gas costs - net		20,752			2,577			(15,178	)
Gain on sale of non-utility investments		(495	)		-			-
Income from life insurance investments		(2,609	)		(1,873	)		(2,855	)
Contributions to qualified defined benefit pension plans		-			(31,000	)		(8,261	)
Non-cash expenses related to qualified defined benefit pension plans		5,500			4,532			4,322
Deferred environmental expenditures		(6,675	)		(9,132	)		(2,215	)
Deferred regulatory costs and other		14,533			3,243			3,289
Changes in working capital:
Accounts receivable and accrued unbilled revenue - net		(3,722	)		(40,262	)		(16,885	)
Inventories of gas, materials and supplies		8,033			(19,684	)		(15,618	)
Income taxes receivable		13,234			2,736			(6,984	)
Prepayments and other current assets		2,952			(3,439	)		245
Accounts payable		(21,708	)		32,809			16,449
Accrued interest and taxes		8,511			2,504			1,536
Other current and accrued liabilities		(959	)		6,767			2,579
Cash provided by operating activities		148,566			79,066			104,899
Investing activities:
Investment in utility plant		(95,307	)		(89,259	)		(138,347	)
Investment in non-utility property		(1,773	)		(6,842	)		(10,568	)
Proceeds from sale of non-utility investments		2,517			3,001			-
Proceeds from life insurance		4,009			296			17,575
Other		(13	)		796			(1,291	)
Cash used in investing activities		(90,567	)		(92,008	)		(132,631	)
Financing activities:
Common stock issued, net of expenses		3,913			7,486			46,616
Common stock repurchased		(15,971	)		(14,945	)		(537	)
Long-term debt issued		25,000			50,000			-
Long-term debt retired		(8,000	)		(15,528	)		-
Change in short-term debt		(26,600	)		24,200			17,300
Cash dividend payments on common stock		(38,298	)		(36,376	)		(35,105	)
Other		581			-			-
Cash (used in) provided by financing activities		(59,375	)		14,837			28,274
(Decrease) increase in cash and cash equivalents		(1,376	)		1,895			542
Cash and cash equivalents - beginning of period		7,143			5,248			4,706
Cash and cash equivalents - end of period	$	5,767		$	7,143		$	5,248
Supplemental disclosure of cash flow information:
Interest paid	$	39,294		$	36,974		$	36,061
Income taxes paid	$	31,270		$	28,479		$	2,500
Supplemental disclosure of non-cash financing activities:
Conversions to common stock:
7- 1/4 % Series of Convertible Debentures	$	-		$	3,999		$	1,292

------------------------------------

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

CONSOLIDATED STATEMENTS OF CAPITALIZATION

Thousands (December 31)	2006				2005
Common stock equity:
Common stock	$	371,127			$	87,334
Premium on common stock		-				296,471
Earnings invested in the business		230,774				205,687
Unearned compensation		-				(650	)
Accumulated other comprehensive income (loss)		(2,356	)			(1,911	)
Total common stock equity		599,545		54%		586,931		53%
Long-term debt:
Medium-Term Notes
First Mortgage Bonds:
6.050% Series B due 2006		-				8,000
6.310% Series B due 2007		20,000				20,000
6.800% Series B due 2007		9,500				9,500
6.500% Series B due 2008		5,000				5,000
4.110% Series B due 2010		10,000				10,000
7.450% Series B due 2010		25,000				25,000
6.665% Series B due 2011		10,000				10,000
7.130% Series B due 2012		40,000				40,000
8.260% Series B due 2014		10,000				10,000
4.700% Series B due 2015		40,000				40,000
5.150% Series B due 2016		25,000				-
7.000% Series B due 2017		40,000				40,000
6.600% Series B due 2018		22,000				22,000
8.310% Series B due 2019		10,000				10,000
7.630% Series B due 2019		20,000				20,000
9.050% Series A due 2021		10,000				10,000
5.620% Series B due 2023		40,000				40,000
7.720% Series B due 2025		20,000				20,000
6.520% Series B due 2025		10,000				10,000
7.050% Series B due 2026		20,000				20,000
7.000% Series B due 2027		20,000				20,000
6.650% Series B due 2027		20,000				20,000
6.650% Series B due 2028		10,000				10,000
7.740% Series B due 2030		20,000				20,000
7.850% Series B due 2030		10,000				10,000
5.820% Series B due 2032		30,000				30,000
5.660% Series B due 2033		40,000				40,000
5.250% Series B due 2035		10,000				10,000
		546,500				529,500
Less long-term debt due within one year		29,500				8,000
Total long-term debt		517,000		46%		521,500		47%
Total capitalization	$	1,116,545		100%	$	1,108,431		100%

------------------------------------

See Notes to Consolidated Financial Statements.

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NORTHWEST NATURAL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.            SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Organization and Principles of Consolidation

The consolidated financial statements include the accounts of Northwest Natural Gas Company (NW Natural), our regulated gas distribution business and our regulated gas storage business and a non-regulated wholly-owned subsidiary business, NNG Financial Corporation (Financial Corporation).

In this report, the term “utility” is used to describe the regulated gas distribution business and the term “non-utility” is used to describe the gas storage business and other non-regulated activities (see Note 2). Intercompany accounts and transactions have been eliminated.

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 (see Note 9).

Certain prior year balances on our consolidated balance sheet have been reclassified to conform with the current presentation. These reclassifications had no impact on our consolidated results of operations, financial condition or cash flows.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America (GAAP) requires management to make estimates and assumptions that affect reported amounts in the consolidated financial statements and accompanying notes. Actual amounts could differ from those estimates and changes would be reported in future periods. Management believes that the estimates and assumptions used are reasonable.

Industry Regulation

Our principal business is the distribution of natural gas, which is regulated by the Oregon Public Utility Commission (OPUC) and the Washington Utilities and Transportation Commission (WUTC). Accounting records and practices of the regulated business conform to the requirements and uniform system of accounts prescribed by these regulatory authorities in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” The utility business segment is authorized by the OPUC and the WUTC to earn a reasonable return on invested capital.

In applying SFAS No. 71, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the OPUC or WUTC in general rate or expense deferral proceedings, to provide for recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a return or a carrying charge.

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At December 31, 2006 and 2005, the amounts deferred as regulatory assets and liabilities were as follows:

	Current				Non-Current
Thousands	2006		2005		2006		2005
Regulatory assets:
Gas costs receivable	$	-	$	2,890	$	-	$	4,084
Unrealized loss on non-trading derivatives3		30,798		-		9,584		-
Income tax asset		-		-		67,141		65,843
Pension and other postretirement benefit obligations1		-		-		54,425		-
Environmental costs - paid2		-		-		19,113		12,439
Environmental costs - accrued but not yet paid2		-		-		8,760		6,440
Other		711		989		5,748		6,166
Total regulatory assets	$	31,509	$	3,879	$	164,771	$	94,972
Regulatory liabilities:
Gas costs payable	$	737	$	-	$	13,041	$	-
Unrealized gain on non-trading derivatives3		-		163,660		-		8,117
Accrued asset removal costs		-		-		187,422		169,927
Other		11,182		-		2,519		2,783
Total regulatory liabilities	$	11,919	$	163,660	$	202,982	$	180,827

¹ Certain pension and other postretirement benefit obligations required by SFAS No. 158 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.)

² Environmental costs are related to sites that are approved for regulatory deferral. We earn the authorized rate of return as a carrying charge on amounts paid, but the amounts accrued but not yet paid do not earn a rate of return or a carrying charge until expended.

³ Unrealized gain or loss on non-trading derivatives do 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.

We believe that continued application of SFAS No. 71 for regulated activities is appropriate and consistent with the current regulatory environment, and that all regulated assets and liabilities at December 31, 2006 and 2005 are recoverable or refundable through future utility rates. We review all regulatory assets at least annually for recoverability. If we should determine that all or a portion of these regulatory assets or liabilities no longer meet the criteria for continued application of SFAS No. 71, then we would be required to write off the net unrecoverable balances against earnings.

New Accounting Standards

Adopted Standards

Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R).” SFAS No. 158 requires balance sheet recognition of the overfunded or underfunded status of pension and other postretirement

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benefit plans. For pension plans, the liability will be based on the projected benefit obligation. Under SFAS No. 158, any actuarial gains and losses, prior service costs and transition assets or obligations that were not recognized under previous accounting standards must be recognized in accumulated other comprehensive income (AOCI) under common stock equity, net of tax, until they are amortized as a component of net periodic benefit cost. In addition, the measurement date, which is the date when the fair value of plan assets and benefit obligations are measured, is required to be a company’s fiscal year end. The measurement date change did not have an impact on our measurement of benefit obligations or the fair value of plan assets because we previously used our fiscal year end as our measurement date.

Effective December 31, 2006, we adopted SFAS No. 158 and recorded balance sheet adjustments to recognize the funded status of our pension and other postretirement plans. These adjustments did not have a material impact on our results of operations, cash flows or our ability to meet our financial debt covenants. We received regulatory approval from the OPUC for deferred asset recognition of AOCI related to the funded status of certain plans under SFAS No. 71 as these amounts are probable of collection in future rates. As such, we have recognized the unfunded status of our qualified pension plans and our postretirement benefit plan as a deferred regulatory asset, and we will recognize changes in actuarial gains and losses, prior service costs and transition assets or obligations each year as an adjustment to the regulatory deferred asset or liability account as these amounts are recognized as components of net periodic benefit costs each year. See Note 7 for a discussion of pension and other postretirement plans.

Share Based Payment. Effective January 1, 2006, we adopted SFAS No. 123R, “Share Based Payment,” using the Modified Prospective Application method without restatement of prior periods. Prior to implementation of SFAS No. 123R, we accounted for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R requires companies to recognize compensation expense for all equity-based compensation awards issued to employees that are expected to vest. Under this method, we began to amortize compensation cost for the remaining portion of outstanding awards for which the requisite service was not yet rendered at January 1, 2006. Compensation cost for these awards was based on the fair value of the awards at the grant date, which was determined under the intrinsic value method. We determine the fair value of and account for awards that are granted, modified or settled on or after January 1, 2006 in accordance with SFAS No. 123R. The adoption of SFAS No. 123R did not have a material impact on our financial condition, results of operations or cash flows. See Note 4 for a discussion of stock-based compensation.

Accounting for Changes and Error Corrections. Effective January 1, 2006, we adopted SFAS No. 154, “Accounting for Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which provides guidance on the accounting for and reporting of accounting changes and error corrections. The statement requires retrospective application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine the period-specific effects or the cumulative effect of the change. The guidance provided in APB Opinion No. 20 for reporting the correction of an error in previously issued financial statements remains unchanged and requires the restatement of previously issued financial statements. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption of SFAS No. 154 did not have an impact upon our financial condition, results of operations or cash flows.

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Inventory Costs. Effective January 1, 2006, we adopted SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” which amends the guidance on inventory pricing to require that abnormal amounts of idle facility expense, freight, handling costs and wasted material be charged to current period expense rather than capitalized as inventory costs. The adoption of SFAS No. 151 did not have a material impact on our financial condition, results of operations or cash flows.

Purchases and Sales of Inventory with the Same Counterparty. Effective April 1, 2006, we adopted FASB Emerging Issues Task Force (EITF) Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF 04-13 requires that two or more legally separate exchange transactions with the same counterparty be combined and considered a single arrangement for purposes of applying APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” when the transactions are entered into in contemplation of one another. EITF 04-13 was effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. Adoption of this standard did not have a material impact on our financial condition, results of operations or cash flows.

Variable Interest Entities. In April 2006, the FASB issued a staff position (FSP) interpreting variable interest entities (VIE) under FASB Interpretation No. (FIN) 46(R)-6, “Determining the Variability to be Considered in Applying FIN 46(R).” This FSP emphasizes that preparers should use a “by design” approach in determining whether an interest is variable. A “by design” approach includes evaluating whether an interest is variable based on a thorough understanding of the design of the potential VIE, including the nature of the risks that the potential VIE was designed to create and pass along to interest holders in the entity. Consolidation of a VIE by the primary beneficiary is required if it is determined that the VIE does not effectively disperse risks among the parties involved. FSP No. FIN 46(R)-6 must be applied prospectively to all entities with which the company first becomes involved and to all entities previously required to be analyzed under FIN 46(R) when a reconsideration event has occurred effective on or after July 1, 2006. Implementation of FSP No. FIN 46(R)-6 did not have a material impact on our financial condition, results of operations or cash flows.

Recent Accounting Pronouncements

Accounting for Certain Hybrid Instruments. In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Instruments,” which amends SFAS Nos. 133 “Accounting for Derivative Instruments and Hedging Activities,” and 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities-a replacement of FASB Statement No. 125.” SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for as a whole if the holder elects to account for the whole instrument on a fair value basis. The statement is effective for all financial instruments acquired or issued after January 1, 2007. We are evaluating the effect of the adoption and implementation of SFAS No. 155, which is not expected to have a material impact on our financial condition, results of operations or cash flows.

Accounting for Uncertainty in Income Taxes. In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109,” which provides guidance for the recognition and measurement of a tax position taken or expected to be taken in a tax return.

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FIN 48 is effective as of the beginning of the first annual period after December 15, 2006, or January 1, 2007. It replaces the “probable” and “reasonable estimate” standards of SFAS No. 5 with a two-step approach for determining the amount of tax benefits (thus treating “loss contingencies” and “gain contingencies” consistently) to be recorded in a company’s financial statements. Management is required to evaluate all tax positions taken for each jurisdiction and determine the likelihood of the positions being sustained. If management is highly confident that a tax position will be sustained and there is a greater than 50 percent likelihood that the full amount of the tax position will be ultimately realized, a company would recognize the full benefit associated with the tax position.

New disclosures under FIN 48 will primarily consist of:

• A policy on classification of interest and penalties (either as components of operating income or components of the income tax provision);

• A tabular reconciliation of the total amounts of unrecognized tax benefits at the beginning and end of the period;

• The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate; and,

• A description of tax years that remain subject to examination by major tax jurisdictions.

Adoption of FIN 48 will require us to identify and evaluate all material tax positions taken in previously filed and currently open tax returns as well as tax positions expected to be taken in future returns. Each tax position will need to be examined to determine whether the more likely than not recognition standard has been met, and if so, to compute the amount of the tax benefit to be recognized under FIN 48. Based upon a preliminary assessment of the application of FIN 48, the adoption of FIN 48 is not expected to have a material effect on our financial condition, results of operations or cash flows. See Note 8.

Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which provides a common definition for the measurement of fair value for use in applying GAAP and in preparing financial statement disclosures. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are evaluating the effect of the adoption and implementation of SFAS No. 157, which is not expected to have a material impact on our financial condition, results of operations or cash flows.

Plant and Property and Accrued Asset Removal Costs

Plant and property is stated at cost, including capitalized labor, materials and overhead (see Note 9). The cost of constructing utility plant and gas storage assets includes an allowance for funds used during construction, which represents the net financing cost during the period of funds used for construction purposes (see “Allowance for Funds Used During Construction,” below).

Our provision for depreciation of utility property is computed under the straight-line, age-life method in accordance with independent engineering studies and as approved by regulatory authorities. The weighted average depreciation rate for utility plant in service was approximately 3.4 percent for the each of the years ended December 31, 2006, 2005 and 2004, reflecting the approximate economic life of the property.

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In accordance with long-standing industry practice, we accrue for future asset removal costs on many long-lived assets through a charge to depreciation expense allowed in rates and accumulate such amounts in regulatory liabilities. At the time removal costs are incurred, accumulated depreciation is charged with the costs of removal and the book cost of the asset. Our estimate of accumulated removal costs is based on rates using our most recent depreciation study. No gain or loss is recognized upon normal retirement. In the rate setting process, the accrued asset removal costs are treated as a reduction to the net rate base.

Allowance for Funds Used During Construction

Certain additions to utility plant include an allowance for funds used during construction, which represents the net cost of borrowed or other funds used during construction and is calculated using actual current interest rates. If borrowings are less than the total costs of construction work in progress, then a composite rate of interest on all debt, shown as a reduction to interest charges, and a return on equity funds, shown as other income, is used to compute the allowance. While cash is not realized currently from allowance for funds used during construction, it is realized in future years through increased revenues from rate recovery resulting from higher rate base and higher depreciation expense. Our composite allowance for funds used during construction rates were 4.7 percent in 2006, 3.1 percent in 2005 and 3.0 percent in 2004.

Cash and Cash Equivalents

For purposes of reporting cash flows, cash and cash equivalents include cash on hand and highly liquid temporary investments with original maturity dates of three months or less. At December 31, 2006 and 2005, book overdrafts of $3.7 million and $4.1 million, respectively, were included within accounts payable.

Revenue Recognition and Accrued Unbilled Revenues

Utility revenues, derived primarily from the sale and transportation of gas, are recognized when the gas is delivered to and received by the customer. Revenues include accruals for gas delivered but not yet billed to customers based on estimates of gas deliveries from meter reading dates to month end (accrued unbilled revenues). Accrued unbilled revenues are dependent upon a number of factors that require management’s judgment, including total gas receipts and deliveries, customer use and weather. Accrued unbilled revenues are reversed the following month when actual billings occur. Our accrued unbilled revenues at December 31, 2006 and 2005 were $87.5 million and $81.5 million, respectively.

Non-utility revenues, derived primarily from gas storage services, are recognized upon delivery of the service to customers. Revenues from optimization of excess storage and transportation capacity include amounts that are recognized ratably over the life of the contract for guaranteed amounts, or as earned for amounts above the guaranteed amount based on the terms of our contract with the independent energy marketing company which optimizes the value of our assets primarily through the use of commodity transactions and capacity release transactions (see Note 2).

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Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable consist primarily of amounts due for gas sales and transportation services to core (residential, commercial and industrial firm) customers, plus amounts due for gas storage and other miscellaneous receivables. With respect to these trade receivables and accrued unbilled revenues, we establish an allowance for uncollectible accounts (allowance) based on the aging of receivables, collection experience of past due accounts on payment plans, and historical trends of write-offs as a percent of revenues. With respect to large individual customer receivables, a specific allowance is established and added to the general allowance when amounts are identified as unlikely to be partially or fully recovered. Inactive accounts are written-off against the allowance after 120 days past due or when deemed to be uncollectible. Differences between our estimated allowance and actual write-offs will occur based on changes in general economic conditions, customer credit issues and the level of natural gas prices. Each quarter the allowance for the uncollectible accounts is adjusted, if necessary, based on the most current information available.

Inventories

Inventories, which consist primarily of natural gas in storage for the utility, are generally stated at the lower of average cost or net realizable value. The regulatory treatment of gas inventories provides for full cost recovery in customer rates, subject to a prudency review, including any differences between the actual purchase cost of gas injected into inventory and the embedded cost of inventory in current rates. All gas that is injected into storage is priced into inventory at the actual purchase cost based on a regulatory dispatch model for our gas purchases. All gas that is withdrawn from inventory is charged to cost of gas during the current period at the weighted average cost of inventory embedded in customer rates, which is established in our annual purchased gas adjustment (PGA) filing. Material and supplies inventories are stated at the lower of average cost or net realizable value.

Derivatives

In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (collectively referred to as SFAS No. 133), we measure derivatives at fair value and recognize them as either assets or liabilities on the balance sheet. SFAS No. 133 requires that changes in the fair value of a derivative be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133 provides an exception for contracts intended for normal purchases and normal sales for which physical delivery is probable. In addition, certain derivatives contracts are approved by regulatory authorities for recovery through customer rates. Accordingly, the changes in fair value of these contracts are deferred as regulatory assets or liabilities pursuant to SFAS No. 71. Derivatives contracts entered into for core utility customer requirements after the PGA rate has been set are subject to the PGA incentive sharing mechanism, whereby 67 percent of the changes in fair value are deferred as regulatory assets or liabilities and the remaining 33 percent is recorded to the income statement (see Note 11).

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Our Financial Derivatives Policy sets forth the guidelines for using selected financial derivative products to support prudent risk management strategies within designated parameters. Our objective for using derivatives is to decrease the volatility of earnings and cash flows and to prevent speculative risk. The use of derivatives is permitted only after the risk exposures have been identified, are determined to exceed acceptable tolerance levels and are considered to be unavoidable because they are necessary to support normal business activities. We do not enter into derivative instruments for trading purposes and we believe that any increase in market risk created by holding derivatives should be offset by the exposures they modify.

Revenue Taxes

We account for utility revenue-based taxes assessed by governmental entities as a separate cost collected from customers for remittance to those governmental entities. Therefore our revenue taxes are accounted for as a cost of sale and presented separately on the income statement.

Income Tax Expense

NW Natural and its one active wholly-owned subsidiary file consolidated federal and state income tax returns. Current income taxes are allocated based on each entity’s respective taxable income or loss and investment tax credits as if each entity filed a separate return. We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109 requires recognition of deferred tax liabilities and assets for the future tax consequences of events that have been included in the consolidated financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse (see Note 8).

SFAS No. 109 also requires recognition of deferred income tax assets and liabilities for temporary differences where regulators prohibit deferred income tax treatment for ratemaking purposes. We have recorded a deferred tax liability equivalent to $67.1 million and $65.8 million at December 31, 2006 and 2005, respectively, to recognize future taxes payable resulting from transactions that have previously been reflected in the financial statements for these temporary differences. Regulatory assets or liabilities corresponding to such additional deferred income tax assets or liabilities may be recorded to the extent we believe they will be recoverable from or payable to customers through the ratemaking process. Pursuant to SFAS No. 71, a corresponding regulatory asset has been recorded which represents the probable future revenue that will result from inclusion in rates charged to customers of taxes which will be paid in the future. The probable future revenue to be recorded takes into consideration the additional future taxes which will be generated by that revenue. Amounts applicable to income taxes due from customers primarily represent differences between the book and tax basis of net utility plant in service and actual removal costs incurred.

Deferred investment tax credits on utility plant additions and leveraged leases, which reduce income taxes payable, are deferred for financial statement purposes and amortized over the life of the related plant or lease. Investment and energy tax credits generated by the non-regulated subsidiary are amortized over a period of one to five years.

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Other Income and Expense—Net

Other income and expense—net consists of interest income, gain on sale of investments, investment income of Financial Corporation and other miscellaneous income from merchandise sales, rents, leases and other items.

Thousands	2006			2005
Other Income and Expense - Net
Gains from company-owned life insurance	$	2,609		$	1,856
Interest income		363			403
Earnings from equity investments of Financial Corporation		191			57
Other non-operating expenses		(852	)		(1,393	)
Net interest on deferred regulatory accounts		(177	)		282
Other Income and Expense - Net	$	2,134		$	1,205

Earnings Per Share

Basic earnings per share are computed based on the weighted average number of common shares outstanding each year. Diluted earnings per share reflect the potential effects of the conversion of convertible debentures and the exercise of stock options. Diluted earnings per share are calculated as follows:

Thousands, except per share amounts	2006		2005		2004
Net income	$	63,415	$	58,149	$	50,572
Convertible debenture interest less taxes		-		-		200
Net income - diluted	$	63,415	$	58,149	$	50,772
Average common shares outstanding - basic		27,540		27,564		27,016
Stock based compensation		117		57		40
Convertible debentures		-		-		227
Average common shares outstanding - diluted		27,657		27,621		27,283
Earnings per share of common stock - basic	$	2.30	$	2.11	$	1.87
Earnings per share of common stock - diluted	$	2.29	$	2.11	$	1.86

For the years ended December 31, 2006, 2005 and 2004, 105,600 shares, 6,000 shares and 201,800 shares, respectively, represent the number of stock options which were excluded from the calculation of diluted earnings per share because the effect was antidilutive.

Stock-Based Compensation

We periodically provide stock-based compensation to employees in the form of stock options and other incentive awards. As required by SFAS No. 123R, we recognize the fair value of all share-based payments as compensation expense in the financial statements. Prior to January 1, 2006, as permitted by SFAS No. 123, we applied APB Opinion No. 25, “Accounting for Stock Issued to Employees,” to account for stock-based compensation. Accordingly, we did not recognize compensation expense for the fair value of our stock option grants. We implemented SFAS 123R effective January 1, 2006 by applying the modified prospective transition method. The impact on net income of this new standard, had it been adopted in 2005, is reflected in the pro forma amounts in Note 4. We have recognized and will continue to recognize compensation

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expense for the fair value of stock awards granted under our Long-Term Incentive Plan (LTIP) and the Non-Employee Directors Stock Compensation Plan (NEDSCP) in the period when the shares are earned (see “New Accounting Standards—Adopted Standards—Share Based Payments,” above, and Note 4).

2.         CONSOLIDATED SUBSIDIARY OPERATIONS AND SEGMENT INFORMATION:

At December 31, 2006, we had one active, direct wholly-owned subsidiary, Financial Corporation.

Our core business segment is the local gas distribution segment, also referred to as the “utility,” which involves the distribution and sale of natural gas. Another business segment, “gas storage” (previously referred to as “interstate gas storage”) represents natural gas storage services provided to intrastate and interstate customers, and includes asset optimization services under a contract with an independent energy marketing company. The remaining business segment, “other,” primarily consists of non-regulated investments in alternative energy projects in California (see “Financial Corporation,” below), a Boeing 737-300 aircraft leased to Continental Airlines and low-income housing in Portland, Oregon (see Note 9).

Gas Storage

The gas storage business segment is primarily made up of underground natural gas storage services that we provide to large intra- and inter-state customers using our owned storage capacity that has been developed in advance of core utility customers’ requirements. In Oregon, we retain 80 percent of the income before tax from these services and credit the remaining 20 percent to a deferred regulatory account for sharing with core utility customers. For each of the years ended December 31, 2006, 2005 and 2004, this business segment derived a majority of its revenues from five customers. The largest of these customers is served under a long-term contract.

Results for the gas storage segment include revenues, net of amounts shared with core utility customers, from a contract with an independent energy marketing company that optimizes the use of the our assets primarily through the use of commodity transactions and transportation capacity release transactions. In Oregon, we retain 80 percent of the pre-tax income when the costs of the capacity have not been included in utility rates, or 33 percent of the pre-tax income when the costs have been included in core utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for distribution to core utility customers. We have a similar sharing mechanism in Washington for revenue derived from storage and third party optimization.

Other

At December 31, 2006, we reclassified to current assets our net investment of $5.3 million in a Boeing 737-300 airplane leased to Continental Airlines. The original lease term expires in September 2007, and we expect to sell the airplane by the end of 2007. Also in 2006, we sold non-utility real estate investments for $1.8 million, which resulted in a gain on sale of $0.5 million.

Financial Corporation has several financial investments, including investments as a limited partner in windpower electric generating projects and low-income housing projects. Financial Corporation’s total assets were $2.6 million and $3.3 million at December 31, 2006 and 2005,

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respectively. On January 31, 2005, Financial Corporation sold its limited partnership interests in three solar electric generating systems for approximately $3 million.

Segment Information Summary

The following table presents summary financial information about the reportable segments for 2006, 2005 and 2004. Inter-segment transactions are insignificant.

Thousands	Utility		Gas Storage		Other			Total
2006
Net operating revenues	$	327,267	$	12,761	$	148		$	340,176
Depreciation and amortization		63,552		883		-			64,435
Income from operations		126,366		9,870		526			136,762
Income from financial investments		2,609		-		191			2,800
Net income		56,653		5,982		780			63,415
Total assets at Dec. 31, 2006		1,912,021		35,970		8,865			1,956,856
2005
Net operating revenues	$	315,248	$	9,609	$	136		$	324,993
Depreciation and amortization		60,935		710		-			61,645
Income (loss) from operations		118,794		8,158		(5	)		126,947
Income from financial investments		1,856		-		57			1,913
Net income		52,759		4,557		833			58,149
Total assets at Dec. 31, 2005		1,994,868		34,574		12,862			2,042,304
2004
Net operating revenues	$	284,904	$	6,423	$	168		$	291,495
Depreciation and amortization		56,899		472		-			57,371
Income (loss) from operations		104,781		5,299		(54	)		110,026
Income from financial investments		2,855		-		181			3,036
Net income		47,090		2,880		602			50,572

3.         CAPITAL STOCK:

Common Stock

At December 31, 2006, we had reserved 244,406 shares of common stock for issuance under the Employee Stock Purchase Plan, 753,934 shares under our Dividend Reinvestment and Direct Stock Purchase Plan and 1,469,000 shares under our Restated Stock Option Plan (see Note 4).

In connection with the restatement of our Restated Articles of Incorporation, effective May 31, 2006, the par value of our common stock was eliminated. As a result, at December 31, 2006, our “common stock” and “premium on common stock” account balances are reflected on the balance sheet as “common stock.”

Expiration of Common Share Purchase Rights

In February 2006, our Board of Directors decided to allow all of the common stock purchase rights (Rights) issued under the Rights Agreement, dated as of February 27, 1996, as amended, to expire in accordance with their terms at the close of business on March 15, 2006.

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Stock Repurchase Program

Our publicly announced stock repurchase program allows us to purchase up to 2.6 million shares, or up to $85.0 million in total, of our common stock in the open market or through privately negotiated transactions. A total of 395,500 and 410,200 shares were repurchased under this program in 2006 and 2005, respectively; however, no shares were repurchased in 2004.

Restated Stock Option Plan

There are 2,400,000 shares authorized for option grants under the Restated Stock Option Plan. At December 31, 2006, options on 1,135,000 shares were available for grant and options on 334,000 shares were outstanding.

Convertible Debentures

In August 2005, we redeemed all of our outstanding Convertible Debentures, 7-1/4% Series due 2012, at 100 percent of their principal amount plus accrued interest to the date of redemption. During 2005, debentures with an aggregate principal amount of $4.0 million were converted into shares of common stock on or prior to the redemption date at the rate of 50.25 shares for each $1,000 principal amount of debentures and $0.5 million of debentures were redeemed.

Summary of Changes in Common Stock

The following table shows the changes in the number of shares of our common stock outstanding and the premium on common stock for the years 2006, 2005 and 2004:

	Shares		Premium on common stock (thousands)
Balance, Dec. 31, 2003	25,938,002		$	255,871
Sales to public	1,290,000			35,905
Sales to employees	27,541			605
Sales to stockholders	157,124			4,323
Exercise of stock options - net	73,649			2,285
Conversion of convertible debentures to common	64,904			1,086
Lapse of restricted stock award	(4,500	)		(41	)
Balance, Dec. 31, 2004	27,546,720		$	300,034
Sales to employees	30,896			741
Sales to stockholders	113,925			3,741
Exercise of stock options - net	97,068			2,241
Conversion of convertible debentures to common	200,887			3,360
Repurchase	(410,200	)		(13,646	)
Balance, Dec. 31, 2005	27,579,296		$	296,471
Repurchase	(395,500	)		(1,461	)
Sales to employees	31,397			-
Exercise of stock options - net	68,548			285
Change to no-par common stock	-			(295,295	)
Balance, Dec. 31, 2006	27,283,741		$	-

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4.          STOCK-BASED COMPENSATION:

We have the following stock-based compensation plans: the Long-Term Incentive Plan (LTIP); the Restated Stock Option Plan (Restated SOP); the Employee Stock Purchase Plan (ESPP); and the Non-Employee Directors Stock Compensation Plan (NEDSCP). These plans are designed to promote stock ownership in NW Natural by employees and officers and, in the case of the NEDSCP, by non-employee directors.

Long-Term Incentive Plan. The LTIP is intended to provide a flexible, competitive compensation program for eligible officers and key employees. An aggregate of 500,000 shares of common stock was authorized for grants under the LTIP as stock bonus, restricted stock or performance-based stock awards. Shares awarded under the LTIP are purchased on the open market.

At December 31, 2006, 375,060 shares of common stock were available for award under the LTIP, assuming that outstanding performance based grants are awarded at the target level. The LTIP stock awards are compensatory awards for which compensation expense is recognized based on the market value of performance shares earned, or a pro rata amortization over the vesting period for the outstanding restricted stock awards.

Performance-based Stock Awards. Since the LTIP’s inception in 2001 through December 31, 2006, performance-based stock awards have been granted annually based on three-year performance periods. At December 31, 2006, certain performance-based stock award measures had been achieved for the 2004-06 award period. Accordingly, participants will receive 40,446 shares of common stock and a dividend equivalent cash payment equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share during the performance period. For the 12 months ended December 31, 2006, we accrued and expensed $0.9 million related to the 2004-06 performance-based stock award. At December 31, 2006, on a cumulative basis, $1.7 million has been accrued for the 2004-06 performance period.

At December 31, 2006, the aggregate number of performance-based shares granted and outstanding at the threshold, target and maximum levels were as follows:

Year Awarded	Performance Period	Number of Performance Share Awards
		Threshold	Target	Maximum
2005	2005-07	6,333	33,332	66,664
2006	2006-08	7,536	39,662	79,324
	Total	13,869	72,994	145,988

The threshold level estimates future payout assuming the minimum award payable other than no payout for each component of the formula in the Long-Term Incentive Plan. For each of these performance periods, awards will be based on total shareholder return relative to a peer group of gas distribution companies over the three-year performance period and on performance results achieved relative to specific core and non-core strategies. Compensation expense is recognized in accordance with SFAS No. 123R, based on performance levels achieved and an estimated fair value using a Black-Scholes or binomial model. The weighted-average grant date fair value of unvested shares at December 31, 2006 and 2005 was $30.65 and $42.86, respectively. The

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weighted-average grant date fair value of shares vested during the year was $40.15 and granted during the year was $18.63. For the 12 months ended December 31, 2006, the amount accrued and expensed as compensation under these LTIP grants was $1.0 million. At December 31, 2006, on a cumulative basis, $1.5 million has been accrued for the 2005-07 and 2006-08 performance periods.

Restricted Stock Awards. Restricted stock awards also have been granted under the LTIP. A restricted stock award was granted in 2004 consisting of 5,000 shares that will vest ratably over the period 2005-09, and a restricted stock award was granted in 2006 consisting of 6,500 shares that will vest ratably over the period 2007-09. A total of 2,000 restricted stock award shares were vested at December 31, 2006. Compensation expense is recognized ratably over the vesting period.

Restated Stock Option Plan. The Restated SOP authorizes an aggregate of 2,400,000 shares of common stock for issuance as incentive or non-statutory stock options. These options may be granted only to officers and key employees designated by a committee of our Board of Directors. All options are granted at an option price not less than the market value at the date of grant and may be exercised for a period not exceeding 10 years from the date of grant. Option holders may exchange shares they have owned for at least six months, at the current market price, to purchase shares at the option price. We use original issue shares upon exercise of options under the plan (see Note 3.)

Employee Stock Purchase Plan. The ESPP allows employees to purchase common stock at 85 percent of the closing price on the trading day immediately preceding the initial offering date, which is set annually. Each eligible employee may purchase up to $24,000 worth of stock through payroll deductions over a six- to 12-month period. We use original issue shares upon exercise of options under the plan (see Note 3.)

In accordance with APB Opinion No. 25, no compensation expense was recognized for options granted under the Restated SOP or shares issued under the ESPP during 2005 or earlier years (see Note 1, “New Accounting Standards—Adopted Standards—Share Based Payment”). If compensation expense for awards under these two plans had been determined based on fair value at the grant dates using the method prescribed by SFAS No. 123R, net income and earnings per share would have been reduced to the pro forma amounts shown below:

Pro Forma Effect of Stock-Based Options and ESPP: Thousands, except per share amounts	2005			2004
Net income as reported	$	58,149		$	50,572
Add:       Stock based compensation expense included in reported net income - net of related tax effects		613			96
Deduct: Pro forma stock-based compensation expense determined under the fair value based method - net of related tax effects		(940	)		(519	)
Pro forma earnings applicable to common stock - basic		57,822			50,149
Debenture interest less taxes		-			200
Pro forma earnings applicable to common stock—diluted	$	57,822		$	50,349
Basic earnings per share
As reported	$	2.11		$	1.87
Pro forma	$	2.10		$	1.86
Diluted earnings per share
As reported	$	2.11		$	1.86
Pro forma	$	2.09		$	1.85

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The fair value of each stock option is estimated on the grant date using the Black-Scholes option pricing model with the following weighted average assumptions:

	2006	2005	2004
Risk-free interest rate	4.5%	4.2%	3.6%
Expected Life (in years)	6.2	7.0	7.0
Expected market price volatility factor	22.8%	24.6%	25.2%
Expected dividend yield	4.0%	3.6%	4.1%
Present value of options granted	$26.00	$27.87	$24.55

The simplified formula for “plain vanilla” options was utilized to determine the expected life as defined and permitted by Staff Accounting Bulletin No. 107. The risk-free interest rate was based on the implied yield currently available on U.S. Treasury zero-coupon issues with a life equal to the expected life of the options. Historical data was employed in order to estimate the volatility factor, measured on a daily basis, for a period equal to the duration of the expected life of the option awards. The dividend yield was based on management’s current estimate for dividend payout at the time of grant. A forfeiture rate of 3 percent was applied to the calculation of compensation expense. We expense the total cost of stock option awards granted to retirement eligible employees at the date of grant in accordance with SFAS No. 123R and the retirement provisions of our plan.

Information regarding the Restated SOP’s activity for the three years ended December 31, 2006 is summarized as follows:

			Price per Share
	Option Shares		Range	Weighted-Average Exercise Price
Balance outstanding, Dec. 31, 2003	322,044		$20.25 - 27.875	$	25.35
Granted	202,800		31.34 - 32.02		31.40
Exercised	(92,074	)	20.25 - 27.875		24.39
Forfeited	(1,300	)	26.30 - 31.34		30.18
Balance outstanding, Dec. 31, 2004	431,470		20.25 - 32.02		28.38
Granted	9,000		34.95 - 38.30		37.18
Exercised	(121,170	)	20.25 - 31.34		26.59
Forfeited	(10,800	)	27.60 - 31.34		30.79
Balance outstanding, Dec. 31, 2005	308,500		20.25 - 38.30		29.26
Granted	97,800		34.29		34.29
Exercised	(69,300	)	20.25 - 31.34		27.15
Forfeited	(3,000	)	31.34 - 34.29		32.52
Balance outstanding, Dec. 31, 2006	334,000		$20.25 - 38.30	$	31.14
Shares available for grant
Dec. 31, 2004	1,228,000
Shares available for grant
Dec. 31, 2005	1,229,800
Shares available for grant
Dec. 31, 2006	1,135,000

The weighted average remaining life of outstanding stock options at December 31, 2006 was 7.10 years.

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The weighted-average grant-date fair value of equity awards granted during 2005 and 2006 was $7.85 and $6.29, respectively. At December 31, 2006, a total of 179,700 options were exercisable.

During the year ended December 31, 2006, pre-tax compensation expense amounted to $0.6 million relating to options granted under the Restated SOP. This expense was recognized in operations and maintenance expense under the fair value method in accordance with SFAS No. 123R. In addition, $0.2 million of pre-tax compensation expense related to the ESPP was recognized for the year. As of December 31, 2006, there was $0.4 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards expected to be recognized over a period extending through 2009.

In the year ended December 31, 2006, 69,300 option shares were exercised with a total intrinsic value of $0.8 million. Cash of $2.2 million was received for these exercises and a $0.3 million related tax benefit was realized. The total intrinsic value of options exercised in the years ended December 31, 2005 and 2004 was $1.2 million and $0.7 million, respectively, and the total fair value of options that vested was $0.4 million in both 2006 and 2005 and $0.6 million in 2004.

The following table summarizes additional information about stock options outstanding and exercisable at December 31, 2006:

	Outstanding			Exercisable
Range of Exercise Prices	Stock Options	(In millions) Aggregate Intrinsic Value		Stock Options	(In millions) Aggregate Intrinsic Value		Weighted- Average Exercise Price		Weighted- Average Remaining Life in Years
$20.25 - 38.30	334,000	$	3.8	179,700	$	2.4	$	29.16	5.9

In accordance with SFAS No. 123R, we capitalize a portion of the expense recognized in relation to stock based compensation. The following table summarizes the effects of stock based compensation resulting from the application of SFAS No. 123R granted under our LTIP, SOP and ESPP:

Thousands, except per share amounts	2006
Operations and maintenance	$	2,304
Stock-based compensation effect on income before taxes		2,304
Income taxes		(898	)
Net stock-based compensation effect on net income	$	1,406
Effect on basic earnings per share	$	0.05
Effect on diluted earnings per share	$	0.05
Effect on cash flow from operations	$	(1,136	)
Effect on cash flow from financing activities	$	1,280

Non-Employee Directors Stock Compensation Plan. In February 2004, the NEDSCP was amended to permit non-employee directors to receive stock awards either in cash or in our stock. As a result of modifications to the directors’ compensation arrangements, the NEDSCP was further amended in September 2004 to eliminate any further awards, either in cash or stock, on and after January 1, 2005.

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Prior to the latter amendment to the NEDSCP, if non-employee directors elected to receive their awards in stock, approximately $100,000 worth of common stock was awarded upon joining the Board. These stock awards were subject to vesting and to restrictions on sale and transferability. The shares vested in monthly installments over the five calendar years following the award. On January 1 of each year following the initial award, non-employee directors who elected to receive their awards in stock were awarded an additional $20,000 worth of restricted stock, which vested in monthly installments in the fifth year following the award (after the previous award had fully vested). We hold the certificates for the restricted shares until the non-employee director ceases to be a director. Participants receive all dividends and have full voting rights on both vested and unvested shares. All awards vest immediately upon the death of a director or upon a change in control of the Company. Any unvested shares are considered to be unearned compensation, and thus are forfeited if the recipient ceases to be a director. The shares were purchased in the open market by us at the time of the award. During 2006, 7,848 shares vested under the plan and no forfeitures occurred. At December 31, 2006, 11,071 shares remain unvested, all of which are scheduled to vest by December 31, 2008. The weighted-average grant-date fair value of unvested shares at December 31, 2006 and 2005 was $28.92 and $29.02, respectively.

Changes in unearned stock compensation in 2006 resulted from purchases of restricted stock related to the restricted stock grant under the LTIP for $0.2 million, offset by restricted stock amortizations of $0.3 million. In 2005, the change in unearned stock compensation consisted of $0.2 million of restricted stock amortizations.

Under a separate plan, prior to January 1, 2005, non-employee directors could elect to invest their cash fees and retainers for board service in shares of common stock. Under a new deferral plan effective January 1, 2005, such fees and retainers will be deferred to a cash account. Cash account balances may be transferred to and invested in a stock account at the election of the director up to four times per year.

5.         LONG-TERM DEBT:

The issuance of first mortgage debt, including secured medium-term notes, under the Mortgage and Deed of Trust (Mortgage), is limited by property additions, adjusted net earnings and other provisions of the Mortgage. The Mortgage constitutes a first mortgage lien on substantially all of our utility property.

The maturities on the long-term debt outstanding, for each of the 12-month periods through December 31, 2011 amount to: $29.5 million in 2007; $5 million in 2008; none in 2009; $35 million in 2010; and $10 million in 2011. Holders of certain long-term debt have put options that, if exercised, would accelerate the maturities by $20 million in each of 2007, 2008 and 2009.

In December 2006, we issued and sold $25 million of 5.15% Series B secured Medium Term Notes (MTNs) due 2016. Proceeds from this sale were used, in part, to repay short-term debt and fund our ongoing utility construction program.

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

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In July 2005, we redeemed three series of maturing MTNs aggregating $15 million in principal amount. The series redeemed were the 6.34% Series B, the 6.38% Series B and the 6.45% Series B, each with a principal balance outstanding of $5 million due in July 2005.

6.         NOTES PAYABLE AND LINES OF CREDIT:

Our primary source of short-term funds is from the sale of commercial paper notes payable. In addition to issuing commercial paper to meet seasonal working capital requirements, including the financing of gas purchases, gas inventories and accounts receivable, short-term debt is used temporarily to fund capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our commercial paper program is supported by committed bank lines of credit (see below). At December 31, 2006 and 2005, the amounts and average interest rates of commercial paper debt outstanding were $100.1 million and 5.3 percent and $126.7 million and 4.3 percent, respectively. We have not issued commercial paper in an aggregate amount outstanding in excess of our committed lines of credit.

In September 2005, we entered into an agreement for unsecured lines of credit totaling $200 million with five commercial banks, replacing the existing $150 million credit facilities. The bank lines of credit (bank lines) are available and committed for a term of five years, beginning October 1, 2005 and expiring on September 30, 2010. Our bank lines are used primarily as back-up support for the notes payable under our commercial paper borrowing program. Commercial paper borrowing provides the liquidity to meet our working capital and external financing requirements. Under the terms of these bank lines, we pay upfront fees and annual commitment fees but are not required to maintain compensating bank balances. The interest rates on outstanding loans, if any, under these bank lines are based on then-current market interest rates. All principal and unpaid interest under the bank lines is due and payable on September 30, 2010.

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

The bank lines also require us to maintain an indebtedness to total capitalization ratio of 65 percent or less. Failure to comply with this covenant would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at December 31, 2006, with an indebtedness to total capitalization ratio of 51.9 percent.

7.         PENSION AND OTHER POSTRETIREMENT BENEFITS:

We maintain two qualified non-contributory defined benefit pension plans covering all regular employees with more than one year of service, several non-qualified supplemental pension plans for eligible executive officers and certain key employees and other postretirement benefit plans for employees. Only the two qualified defined benefit pension plans have plan assets,

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which are held in a qualified trust to fund retirement benefits. Effective January 1, 2007, the Retirement Plan for Non-Bargaining Unit Employees and the Welfare Benefits Plan for Non-Bargaining Unit Employees was closed to anyone hired or rehired after December 31, 2006. Instead, newly hired or rehired non-bargaining unit employees will be provided an enhanced Retirement K Savings Plan (401k) benefit. Benefits provided to bargaining unit employees are not affected by these changes.

The following table provides a reconciliation of the changes in benefit obligations and fair value of plan assets, as applicable, for the pension and other postretirement benefit plans over the three-year period ended December 31, 2006, and a summary of the funded status and amounts recognized in the consolidated balance sheets using measurement dates of December 31, 2006, 2005 and 2004:

	Postretirement Benefits
	Pension Benefits									Other Benefits
Thousands	2006			2005			2004			2006			2005			2004
Reconciliation of change in benefit obligation:
Obligation at January 1	$	267,854		$	222,948		$	205,352		$	20,398		$	22,729		$	23,379
Service cost		7,745			6,322			5,428			555			767			457
Interest cost		14,901			13,203			12,690			1,184			1,248			1,232
Special termination benefits		-			-			237			-			-			-
Expected benefits paid		(13,183	)		(12,866	)		(10,682	)		(1,015	)		(1,173	)		(1,040	)
Plan amendments		-			1,408			-			15			2,384			-
Change in assumptions		(9,208	)		31,642			-			133			2,215			-
Net actuarial (gain) or loss		1,301			5,197			9,923			1,166			(7,772	)		(1,299	)
Obligation at December 31	$	269,410		$	267,854		$	222,948		$	22,436		$	20,398		$	22,729
Reconciliation of change in plan assets:
Fair value of plan assets at January 1	$	218,555		$	186,787		$	168,324		$	-		$	-		$	-
Actual return on plan assets		30,088			12,558			19,835			-			-			-
Employer contributions		1,058			32,076			9,310			1,015			1,173			1,040
Benefits paid		(13,183	)		(12,866	)		(10,682	)		(1,015	)		(1,173	)		(1,040	)
Fair value of plan assets at December 31	$	236,518		$	218,555		$	186,787		$	-		$	-		$	-
Funded status:
Funded status at December 31	$	(32,892	)	$	(49,299	)	$	(36,162	)	$	(22,436	)	$	(20,397	)	$	(22,728	)
Unrecognized transition obligation		-			-			-			2,469			2,880			3,292
Unrecognized prior-service cost		5,512			6,492			5,146			2,063			2,243			-
Unrecognized net actuarial loss		45,862			69,766			33,897			2,288			988			6,717
Net amount recognized	$	18,482		$	26,959		$	2,881		$	(15,616	)	$	(14,286	)	$	(12,719	)

In September 2006, the FASB issued SFAS No. 158 (see Note 1, “New Accounting Standards—Adopted Standards”). SFAS No. 158 requires balance sheet recognition of the overfunded or underfunded status of pension and other postretirement benefit plans. For pension plans, the liability is based on the projected benefit obligation. Under SFAS No. 158, any actuarial gains and losses, prior service costs and transition assets or obligations that were not recognized under previous accounting standards must be recognized in AOCI under common stock equity, net of tax, until they are amortized as a component of net periodic benefit cost. We consider the recognition of the underfunded status of the qualified defined

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benefit plans and postretirement benefit plans to be subject to regulatory deferral under SFAS No. 71. The unrecognized net gains and losses, prior service costs and transition obligations relating to our qualified defined benefit pension and postretirement benefit plans were recognized as regulatory assets at December 31, 2006. An estimated $3.5 million consisting of actuarial gains of $1.9 million, prior service costs of $1.2 million and transition obligations of $0.4 million for the qualified plans will be amortized from the regulatory asset to net periodic benefit cost in 2007. The gains and losses, prior service costs and transition obligations related to our non-qualified supplemental pension plans are recognized in AOCI, net of tax, under common stock equity because these expenses are not the basis for regulatory recovery; however, these amounts are not material. In 2007, an estimated $0.2 million consisting of actuarial gains of $0.2 million and negligible prior service costs for the non-qualified plans will be amortized from AOCI to net periodic benefit cost.

The adoption of SFAS No. 158 did not have a material impact on our results of operations, cash flows or our ability to meet our financial debt covenants. The following table provides a summary of the changes in the statement of financial position at December 31, 2006 due to the application of SFAS No. 158:

				Adjustments
Thousands	Before Application of SFAS No. 158			Adoption of SFAS No. 158			Regulatory Deferral		After Application of SFAS No. 158
Minimum pension liability 1	$	3,173		$	(3,173	)	$	-	$	-
Pension benefit liabilities - current		-			1,134			-		1,134
Pension benefit liabilities - non-current		10,174			21,583			-		31,757
Postretirement benefit liability - current		-			1,503			-		1,503
Postretirement benefit liability - non-current		15,616			5,317			-		20,933
Deferred income taxes and investment tax credits		210,316			(21,442	)		21,210		210,084
Regulatory asset		-			-			54,425		54,425
Prepaid pension asset		28,657			(28,657	)		-		-
Accumulated other comprehensive income		(1,992	)		(33,579	)		33,215		(2,356	)
Total assets		1,931,088			(28,657	)		54,425		1,956,856
Total liabilities		814,179			4,922			21,210		840,311
Total capitalization		1,116,909			(33,579	)		33,215		1,116,545

¹ The minimum pension liability before the adoption of SFAS No. 158 includes a current year adjustment of $0.1 million, net of tax.

Our qualified defined benefit pension plans had a projected benefit obligation in excess of plan assets at December 31, 2006. The plans’ aggregate projected benefit obligations were $255 million, $254 million and $209 million at December 31, 2006, 2005 and 2004, respectively, and the fair value of plan assets was $236.5 million, $218.6 million and $186.8 million, respectively. The projected benefit obligations at December 31, 2006 decreased by $9.3 million, reflecting the increase in the discount rate assumptions and increased by $0.3 million, reflecting retirement and withdrawal rates updated for actual experience. The projected benefit obligations at December 31, 2005 increased $26.6 million from December 31, 2004 due to the use of updated mortality rates and increased $8.1 million due to a decrease in the discount rate. The combination of investment returns and future cash contributions is expected to provide sufficient funds to cover all future benefit obligations of the plans.

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The assumed discount rates were determined independently for each pension and other postretirement benefit plan based on the Citigroup Above Median Curve (Citigroup curve) using high quality bonds (rated AA- or higher by Standard & Poors or Aa3 or higher by Moody’s Investor Service). The Citigroup curve was applied to match the estimated cash flows to reflect the timing and amount of future benefit payments for these plans.

The expected long-term rate of return on plan assets was developed as a weighted average of the expected earnings for the target asset portfolio. In developing the expected long-term rate of return assumption, consideration was given to the historical performance of each asset class in which the plans’ assets are invested and the target asset allocation for plan assets.

Our Investment Policy and Performance Objectives for the qualified pension plan assets held in the Retirement Trust Fund were approved by the retirement committee which is composed of senior management employees. The policy sets forth the guidelines and objectives governing the investment of plan assets. Plan assets are invested for total return with appropriate consideration for liquidity and portfolio risk. All investments are expected to satisfy the requirements of the rule of prudent investments as set forth under the Employee Retirement Income Security Act of 1974. The approved asset classes are cash and short-term investments, fixed income, common stock and convertible securities, absolute and real return strategies, real estate and investments in our common stock. Plan assets may be invested in separately managed accounts or in commingled or mutual funds. Re-balancing will take place periodically as needed, or when significant cash flows occur, in order to maintain the allocation of assets within the stated target ranges. Our expected long-term rate of return is based upon historical index returns by asset class, adjusted by a factor based on our historical return experience. The Retirement Trust Fund is not currently invested in any NW Natural securities.

Our pension plan asset allocation at December 31, 2006 and 2005, and the target allocation and expected long-term rate of return by asset category, are as follows:

	Percentage of Plan Assets Dec. 31,		Target	Expected Long-term
Asset Category	2006	2005	Allocation	Rate of Return
US Large Cap Equity	19.2%	19.8%	20%	8.50%
US Small/Mid Cap Equity	13.9%	14.2%	15%	9.50%
Non-US Equity	23.5%	19.7%	20%	8.75%
Fixed Income	15.6%	19.3%	15%	5.50%
Real Estate	7.7%	6.2%	8%	7.75%
Absolute Return Strategies	14.3%	14.2%	15%	9.00%
Real Return	5.8%	6.6%	7%	7.75%
Weighted Average				8.25%

Our non-qualified supplemental pension plans’ benefit obligations were $13.9 million, $13.5 million and $13.6 million at December 31, 2006, 2005 and 2004, respectively. These plans are not subject to regulatory deferral and the changes in actuarial gains and losses, prior service costs and transition assets or obligations for these plans were recognized in AOCI under common stock equity, net of tax, until they are amortized as a component of net periodic benefit cost. Although the plans are unfunded plans with no plan assets due to their nature as non-qualified plans, we indirectly fund our obligations with trust-owned life insurance.

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Our plans for providing postretirement benefits other than pensions also are unfunded plans, but are subject to regulatory deferral. The gains and losses, prior service costs and transition assets or obligations for these plans were recognized as a regulatory asset. The accumulated postretirement benefit obligation for those plans was $22.4 million, $20.4 million and $22.7 million at December 31, 2006, 2005 and 2004, respectively.

Net periodic benefit costs consist of service costs, interest costs, the amortization of actuarial gains and losses, the expected returns on plan assets and, in part, on a market-related valuation of assets. The market-related valuation reflects differences between expected returns and actual investment returns, which are recognized over a three-year period from the year in which they occur, thereby reducing year-to-year net periodic benefit cost volatility.

The following tables provide the components of net periodic benefit cost for the qualified and non-qualified pension and other postretirement benefit plans for the years ended December 31, 2006, 2005 and 2004 and the assumptions used in measuring these costs and benefit obligations:

	Pension Benefits									Other Postretirement Benefits
Thousands		2006			2005			2004			2006		2005		2004
Service cost	$	7,745		$	6,322		$	5,428		$	556	$	767	$	457
Interest cost		14,901			13,203			12,689			1,184		1,248		1,232
Expected return on plan assets		(17,611	)		(14,449	)		(13,284	)		-		-		-
Amortization of transition obligations		-			-			-			411		411		411
Amortization of prior service costs		979			1,077			1,094			195		142		-
Amortization of net loss		3,520			2,082			1,631			1		173		288
Net periodic benefit cost	$	9,534		$	8,235		$	7,558		$	2,347	$	2,741	$	2,388
Assumptions for net periodic benefit cost:
Discount rate		5.75%			6.00%			6.25%			5.75%		6.00%		6.25%
Rate of increase in compensation		4.0%-5.0%			4.0%-5.0%			4.0%-5.0%			n/a		n/a		n/a
Expected long-term rate of return		8.25%			8.25%			8.25%			n/a		n/a		n/a
Assumptions for funded status:
Discount rate		6.0%-6.05%			5.75%			6.00%			5.91%		5.75%		6.00%
Rate of increase in compensation		4.0%-5.0%			4.0%-5.0%			4.0%-5.0%			n/a		n/a		n/a
Expected long-term rate of return		8.25%			8.25%			8.25%			n/a		n/a		n/a

The assumed annual increase in trend rates used in measuring postretirement benefits as of December 31, 2006 were 9 percent for medical and 12 percent for prescription drugs. Medical costs were assumed to decrease gradually each year to a rate of 4.5 percent by 2013, while prescription drug costs were assumed to decrease gradually each year to a rate of 4.5 percent by 2014.

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Assumed health care cost trend rates can have a significant effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects:

Thousands	1% Increase		1% Decrease
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost	$	23	$	(21	)
Effect on health care cost component of the accumulated postretirement benefit obligation	$	613	$	(628	)

The following table provides information regarding employer contributions and benefit payments for the two qualified pension plans, the non-qualified pension plans and the other postretirement benefit plans for the years ended December 31, 2006 and 2005, and estimated future payments:

Thousands
Employer Contributions by Plan Year		Pension Benefits		Other Benefits
For 2005	$	12,497	$	1,173
For 2006		1,527		1,015
For 2007 (estimated)		1,655		1,571
Benefit Payments
2004	$	10,682	$	1,040
2005		12,866		1,173
2006		13,183		1,015
Estimated Future Payments
2007	$	13,139	$	1,571
2008		13,818		1,596
2009		14,513		1,626
2010		15,615		1,685
2011		16,221		1,753
2012-2016		93,212		9,002

Our Retirement K Savings Plan (RKSP) is a qualified defined contribution plan under Internal Revenue Code Section 401(k). We also have non-qualified deferred compensation plans for eligible officers and senior managers. These plans are designed to enhance the retirement program of employees and to assist them in strengthening their financial security by providing an incentive to save and invest regularly. Our matching contributions to these plans totaled $1.8 million in 2006 and $1.7 million in both 2005 and 2004. The RKSP includes an Employee Stock Ownership Plan.

In addition, in 2005 we began making contributions on behalf of each union employee to the Western States Office and Professional Employees Pension Fund, a multi-employer plan. In both 2006 and 2005, these contributions amounted to $0.5 million.

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8.         INCOME TAXES:

A reconciliation between income taxes calculated at the statutory federal tax rate and the tax provision reflected in the consolidated financial statements is as follows:

Thousands, except percentages	2006			2005			2004
Income taxes at federal statutory rate	$	34,877		$	31,804		$	26,986
Increase (decrease):
Current state income tax, net of federal tax benefit		3,655			2,913			2,554
Federal income tax credits		-			(210	)		(210	)
Amortization of investment and energy tax credits		(994	)		(956	)		(920	)
Differences required to be flowed-through by regulatory commissions		(704	)		(704	)		(704	)
Gains on Company and trust-owned life insurance		(913	)		(650	)		(955	)
Other - net		155			187			172
Reversal of amounts provided in prior years		158			336			(392	)
Total provision for income taxes	$	36,234		$	32,720		$	26,531
Federal statutory tax rate		35.0%			35.0%			35.0%
Increase (decrease):
Current state income tax, net of federal tax benefit		3.7%			3.2%			3.3%
Federal income tax credits		0.0%			-0.2%			-0.3%
Amortization of investment and energy tax credits		-1.0%			-1.1%			-1.2%
Differences required to be flowed-through by regulatory commissions		-0.7%			-0.8%			-0.9%
Gains on Company and trust-owned life insurance		-0.9%			-0.7%			-1.2%
Other - net		0.2%			0.2%			0.2%
Reversal of amounts provided in prior years		0.1%			0.4%			-0.5%
Effective tax rate		36.4%			36.0%			34.4%
The provision for income taxes consists of the following:
Thousands	2006			2005			2004
Current tax expense (benefit)	$	52,621		$	23,034		$	(10,718	)
Deferred tax expense (benefit)		(15,393	)		10,642			38,170
Deferred investment and energy tax credits		(994	)		(956	)		(920	)
Total provision for income taxes	$	36,234		$	32,720		$	26,531
Total income taxes paid	$	31,270		$	28,479		$	2,500

The amount of income taxes paid in 2006 and 2005 increased significantly as compared to the total income taxes paid in 2004. This was primarily due to the effects of the accelerated bonus depreciation provisions of the Job Creation and Worker Assistance Act of 2002 (Assistance Act) and of the Jobs and Growth Tax Relief Reconciliation Act of 2003 (Reconciliation Act). The Assistance Act provided for an additional depreciation deduction equal to 30 percent of an asset’s adjusted basis. The Reconciliation Act increased this first-year additional depreciation deduction to 50 percent of an asset’s adjusted basis. The accelerated depreciation provisions provided by the Acts expired December 31, 2004. We realized current tax benefits totaling an estimated $57 million during the effective period, based on plant investments made between September 11, 2001 and December 31, 2004. The accelerated depreciation provisions in 2004 were the primary factors resulting in net operating losses (NOL) for tax purposes.

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The following table summarizes the total provision for income taxes for the regulated utility and other non-regulated business segments for the three years ended December 31:

Thousands	2006			2005			2004
Regulated utility:
Federal
Current	$	40,979		$	17,848		$	(10,794	)
Deferred		(12,472	)		8,690			35,213
Deferred investment and energy tax credits		(756	)		(784	)		(800	)
		27,750			25,755			23,618
State
Current		7,490			1,650			(1,094	)
Deferred		(2,338	)		2,855			5,027
		5,152			4,504			3,933
Total charged to regulated utility		32,902			30,259			27,551
Non-regulated business segments:
Federal
Current		3,807			3,581			1,187
Deferred		(714	)		(1,189	)		(1,610	)
Deferred investment and energy tax credits		(238	)		(172	)		(120	)
		2,855			2,220			(543	)
State
Current		346			(44	)		(17	)
Deferred		131			285			(460	)
		477			241			(478	)
Total charged to non-regulated business segments		3,331			2,461			(1,020	)
Total provision for income taxes	$	36,234		$	32,720		$	26,531

The following table summarizes the tax effect of significant items comprising our deferred income tax accounts for the two years ended December 31:

Thousands	2006			2005
Deferred tax liabilities (assets)
Utility plant and equipment	$	150,648		$	146,681
Utility regulatory balances		-			3,045
Utility other deferred tax differences		-			1,769
Non-regulated deferred tax differences		3,893			6,121
Deferred tax liabilities		154,540			157,616
Utility regulatory balances		(10,039	)		-
Utility other deferred tax differences		(4,053	)		-
Deferred tax assets		(14,092	)		-
		140,448			157,616
Regulatory income tax assets		67,141			65,843
Minimum pension liability		(1,413	)		(1,128	)
Deferred income taxes		206,177			222,331
Deferred investment tax credits		3,907			5,069
Deferred income taxes and investment tax credits	$	210,084		$	227,400

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We have determined that the utility is more likely than not to realize all recorded deferred tax assets as of December 31, 2006.

The following is a reconciliation of the change in our deferred tax balance for the year ended December 31:

Thousands	2006
Deferred tax expense (benefit), above	$	(15,393	)
Increase in differences required to be flowed-through		1,298
Decrease in minimum pension liability included in OCI		(285	)
Decrease in deferred taxes associated with asset held for sale		(1,942	)
Decrease in deferred investment tax credits		(994	)
Change in deferred income tax accounts	$	(17,316	)

We calculate our deferred tax assets and liabilities under SFAS No. 109, which requires recording deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported differently for income tax purposes than for financial reporting purposes. Deferred tax provisions are not recorded in the income statement for certain temporary differences where regulators require that we flow through deferred income tax benefits or expenses in the ratemaking process of the regulated utility.

A deferred income tax charge associated with accruals of minimum pension liability was included in AOCI.

The Internal Revenue Service (IRS) completed its audit of our consolidated income tax returns for the years 2002-2004 in the second quarter of 2006. The focus of the examination was the $35.8 million NOL generated in 2004 and carried back to 2002. This loss was primarily due to the deductions claimed for a pension contribution and accelerated depreciation provided by both the Assistance Act and the Reconciliation Act discussed above. A federal refund of $8.3 million was received in October 2005. In conjunction with recording the refund, we recorded additional federal and state income tax credits of $4.2 million. In addition to the NOL, the IRS examined income tax positions taken with respect to various other ordinary business transactions. We reached agreement with the IRS for certain income tax positions such that a notice of proposed adjustment was issued. As a result of this agreement, we recorded an immaterial income tax benefit of $0.1 million.

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9.         PROPERTY AND INVESTMENTS:

The following table sets forth the major classifications of our utility plant and accumulated depreciation at December 31:

	2006					2005
Thousands, except percentages	Amount			Weighted Average Depreciation Rate		Amount			Weighted Average Depreciation Rate
Transmission and distribution	$	1,657,466		3.3	%	$	1,575,545		3.2	%
Utility storage		110,721		2.6	%		109,908		2.6	%
General		92,946		2.6	%		90,780		3.1	%
Intangible and other		68,088		8.6	%		66,354		8.4	%
Gas stored long-term		12,850		0.0	%		13,078		0.0	%
Utility plant in service		1,942,071		3.4	%		1,855,665		3.4	%
Assets held for future use		-					1,833
Construction work in progress		21,427					17,946
Total utility plant		1,963,498					1,875,444
Accumulated depreciation		(574,093	)				(536,867	)
Utility plant-net	$	1,389,405				$	1,338,577

Accumulated depreciation does not include $187.4 million and $169.9 million at December 31, 2006 and 2005, respectively, which represent accrued asset removal costs reflected on the balance sheets as regulatory liabilities (see Note 1., “Plant and Property and Accrued Asset Removal Costs”).

The following table summarizes our investments in non-utility plant at December 31:

	2006					2005
Thousands, except percentages	Amount			Weighted Average Depreciation Rate		Amount			Weighted Average Depreciation Rate
Non-utility storage	$	34,652				$	34,486
Other		4,820					4,953
Non-utility plant in service		39,472		2.5	%		39,439		2.6	%
Construction work in progress		3,180					1,397
Total non-utility plant		42,652					40,836
Less accumulated depreciation		(6,916	)				(5,990	)
Non-utility plant – net	$	35,736				$	34,846

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The following table summarizes our other long-term investments, including financial investments in life insurance policies accounted for at fair value based on cash surrender values, equity investments in certain partnerships and joint ventures accounted for under the equity or cost methods, and a leveraged lease investment in an aircraft, at December 31:

Thousands	2006		2005
Life insurance cash surrender value	$	45,234	$	46,555
Aircraft leveraged lease		-		6,884
Real estate partnership		-		1,502
Note receivable		526		1,237
Gas pipeline and other		1,369		1,434
Electric generation		856		839
Total other investments	$	47,985	$	58,451

Aircraft Leveraged Lease. In 1987, we invested in a Boeing 737-300 aircraft, which is leased to Continental Airlines for 20 years under a leveraged lease agreement, which expires in March 2007. We have reclassified these amounts into current assets due to our expectation of selling the asset in 2007.

Real Estate Partnership. In 2006, we sold our investment in a real estate partnership and received $1.8 million in cash, realizing a gain of $0.3 million on the sale.

Gas Pipeline. A wholly-owned subsidiary of Financial Corporation, KB Pipeline Company, owns a 10 percent interest in an 18-mile interstate natural gas pipeline.

Electric Generation. At December 31, 2006, Financial Corporation held ownership interests ranging from 25 to 41 percent in wind power electric generation projects located in California. The wind-generated power is sold to Pacific Gas and Electric Company and Southern California Edison Company under long-term contracts. In January 2005, Financial Corporation sold its limited partnership interests in three electric generating systems (see Note 2).

FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” provides guidance for determining whether consolidation is required for entities over which control is achieved through means other than voting rights, know as “variable interest entities.” We do not have any significant interests in variable interest entities. See Note 1, “New Accounting Standards—Adopted Standards—Variable Interest Entities.”

10.       FAIR VALUE OF FINANCIAL INSTRUMENTS:

The estimated fair value of NW Natural’s financial instruments has been determined using available market information and appropriate valuation methodologies. The following are financial instruments whose carrying values are sensitive to market conditions:

	Dec. 31, 2006				Dec. 31, 2005
Thousands	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt including amount due within one year	$	546,500	$	595,564	$	529,500	$	579,382

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Fair value of the long-term debt was estimated using market prices in effect on the valuation date. Interest rates for debt with similar terms and remaining maturities were used to estimate fair value for long-term debt issues.

11.       USE OF FINANCIAL DERIVATIVES:

We enter into forward contracts and other related financial transactions for the purchase of natural gas that qualify as derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149 (collectively referred to as SFAS No. 133). We primarily utilize derivative financial instruments to manage commodity prices related to natural gas supply requirements.

In the normal course of business, we generally enter into index-price physical forward natural gas commodity purchase (gas supply) contracts to meet the requirements of core utility customers. We also enter into financial derivatives, up to prescribed limits, to hedge price variability related to the physical contracts. Derivatives entered into prudently for future gas years prior to the PGA filing receive SFAS No. 71 regulatory deferral treatment. Derivatives contracts entered into for core utility customer requirements after the annual PGA rate has been set are subject to the PGA incentive sharing mechanism, whereby 67 percent of the changes in fair value are deferred as regulatory assets or liabilities and the remaining 33 percent is recorded to the income statement. During the fourth quarter of 2006, we entered into a number of financial derivatives after our PGA filing. The unrealized mark-to-market losses on these hedges totaled $9.5 million, of which $2.9 million was subject to sharing and was recorded as a loss, with the remainder deferred.

The mark-to-market adjustment at December 31, 2006 for all derivatives was a total unrealized loss of $43.2 million consisting of the following: unrealized losses of $40.3 million on swap contracts, $0.7 million on option contracts, $2.1 million on indexed-price physical supply contracts and $0.1 million on foreign exchange forwards.

Certain natural gas purchases from Canadian suppliers are payable in Canadian dollars, including both commodity and demand charges, which exposes us to adverse changes in foreign currency rates. Foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for our commodity and commodity-related demand charges paid in Canadian dollars. Foreign currency contracts for commodity costs are purchased on a month-to-month basis because the Canadian cost is priced at the average noon-day exchange rate for each month. Foreign currency contracts for demand costs have terms ranging up to 12 months. The gains and losses on the shorter-term currency contracts for commodity costs are recognized immediately in cost of gas. The gains and losses on the currency contracts for demand charges are not recognized in current income but are subject to a regulatory deferral tariff and, as such, are recorded as a derivative asset or liability. These forward contracts qualify for cash flow hedge accounting treatment under SFAS No. 133. The mark-to-market adjustment at December 31, 2006 was an unrealized loss of $0.1 million. These unrealized gains and losses were subject to regulatory deferral and, as such, were recorded as a derivative asset or liability which is offset by recording a corresponding amount to a regulatory asset or regulatory liability account resulting in a nominal loss which was deferred to a regulatory account.

We did not use any derivative instruments to hedge oil or propane prices or interest rates during 2006, 2005 or 2004.

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At December 31, 2006 and 2005, unrealized gains or losses from mark-to-market valuations of our derivative instruments were primarily reported as regulatory liabilities or regulatory assets because the realized gains or losses at settlement are included in utility gas costs, pursuant to regulatory deferral mechanisms. The estimated fair values of unrealized gains and losses on derivative instruments outstanding, determined using a discounted cash flow model for swaps and indexed-price contracts and a Black-Scholes model for options, were as follows:

	Fair Value Gains (Losses)
Thousands	Dec. 31, 2006						Dec. 31, 2005
	Current			Non-Current			Current		Non-Current
Natural gas commodity-based derivative instruments:
Fixed-price financial swaps	$	(33,965	)	$	(6,313	)	$	159,373	$	14,417
Fixed-price financial options		(678	)		-			1,871		-
Indexed-price physical supply		1,115			(3,271	)		846		(6,300	)
Fixed-price physical supply		-			-			820		-
Physical options		-			-			567		-
Foreign currency forwards		(135	)		-			183		-
Total	$	(33,663	)	$	(9,584	)	$	163,660	$	8,117

In 2006, we realized a net loss of $20.0 million from the settlement of fixed-price financial swap contracts which were recorded as increases to the cost of gas. Net realized gains from the settlement of such contracts in 2005 and 2004 were $88.9 million and $42.4 million, respectively, and were recorded as decreases to the cost of gas. Realized losses in 2006 were offset by lower gas purchase costs from the underlying hedged floating rate physical supply contracts. The currency exchange rate in all foreign currency forward purchase contracts is included in our cost of gas at settlement; therefore, no gain or loss was recorded from the settlement of those contracts. Any change in value of cash flow hedge contracts that is not included in regulatory recovery is included in other comprehensive income.

As of December 31, 2006, all of the natural gas commodity price swap contracts mature by October 31, 2008 and all of the natural gas commodity call option contracts mature by April 30, 2007.

12.       COMMITMENTS AND CONTINGENCIES:

Lease Commitments

We lease land, buildings and equipment under agreements that expire in various years through 2045. Rental expense under operating leases was $4.4 million, $4.1 million and $4.5 million for the years ended December 31, 2006, 2005 and 2004, respectively. The table below reflects the future minimum lease payments due under non-cancelable leases at December 31, 2006. Such payments total $55.9 million for operating leases. The net present value of payments on capital leases less imputed interest was $0.6 million. These commitments relate principally to the lease of our office headquarters, underground gas storage facilities, vehicles and computer equipment.

Millions	2007		2008		2009		2010		2011		Later years
Operating leases	$	4.2	$	4.1	$	4.1	$	4.1	$	4.1	$	35.3
Capital leases		0.3		0.2		0.1		-		-		-
Minimum lease payments	$	4.5	$	4.3	$	4.2	$	4.1	$	4.1	$	35.3

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Gas Purchase and Pipeline Capacity Purchase and Release Commitments

We have signed agreements providing for the reservation of firm pipeline capacity under which we are required to make fixed monthly payments for contracted capacity. The pricing component of the monthly payment is established, subject to change, by U.S. or Canadian regulatory bodies. In addition, we have entered into long-term sale agreements to release firm pipeline capacity. We also enter into gas purchase agreements. The aggregate amounts of these agreements were as follows at December 31, 2006:

Thousands	Gas Purchase Agreements		Pipeline Capacity Purchase Agreements		Pipeline Capacity Release Agreements
2007	$	283,180	$	86,129	$	5,105
2008		177,943		75,953		5,105
2009		98,807		70,093		5,105
2010		47,263		70,339		4,254
2011		25,828		70,059		-
2012 through 2026		73,179		198,863		-
Total		706,200		571,436		19,569
Less: Amount representing interest		59,737		100,411		1,663
Total at present value	$	646,463	$	471,025	$	17,906

Our total payments of fixed charges under capacity purchase agreements in 2006, 2005 and 2004 were $69.2 million, $83.1 million and $89.3 million, respectively. Included in the amounts for 2006, 2005 and 2004 were reductions for capacity release sales of $3.7 million in each year. In addition, per-unit charges are required to be paid based on the actual quantities shipped under the agreements. In certain take-or-pay purchase commitments, annual deficiencies may be offset by prepayments subject to recovery over a longer term if future purchases exceed the minimum annual requirements.

Environmental Matters

We own, or have previously owned, properties that may require environmental remediation or action. We accrue all material loss contingencies relating to these properties that we believe to be probable of assertion and reasonably estimable. We continue to study the extent of our potential environmental liabilities, but due to the numerous uncertainties surrounding the course of environmental remediation and the preliminary nature of several environmental site investigations, the range of potential loss beyond the amounts currently accrued, and the probabilities thereof, cannot be reasonably estimated. We regularly review our remediation liability for each site where we may be exposed to remediation responsibilities. The costs of environmental remediation are difficult to estimate. A number of steps are involved in each environmental remediation effort, including site investigations, remediation, operations and maintenance, monitoring and site closure. Each of these steps may, over time, involve a number of alternative actions, each of which can change the course of the effort. In certain cases, in addition to ourselves, there are a number of other potentially responsible parties, each of which, in proceedings and negotiations with other potentially responsible parties and regulators, may influence the course of the remediation effort. The allocation of liabilities among the potentially

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responsible parties is often subject to dispute and can be highly uncertain. The events giving rise to environmental liabilities often occurred many decades ago, which complicates the determination of allocating liabilities among potentially responsible parties. Site investigations and remediation efforts often develop slowly over many years. To the extent reasonably estimable, we estimate the costs of environmental liabilities using current technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of probable cost, we record the liability at the lower end of this range. It is likely that changes in these estimates will occur throughout the remediation process for each of these sites due to uncertainty concerning our responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives. The status of each of the sites currently under investigation is provided below.

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 2006, the estimated liability for this site increased $7.2 million due to updated estimates for the completion of the Feasibility Study and Work Plan, the design and treatment system for pilot wells and the construction of a containment wall for source control. We have accrued a liability of $6.4 million for the Gasco site, which is at the low end of the range because no amount within the range is considered to be more likely than another and the high end of the range cannot be estimated.

Siltronic (formerly Wacker) site. We previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation (formerly Wacker Siltronic Corporation) (the Siltronic site). We are currently working with the ODEQ to develop a study of manufactured gas plant wastes on the uplands at this site. The amount of the additional accrual was deferred to a regulatory asset account pursuant to an order of the OPUC (see “Regulatory and Insurance Recovery for Environmental Matters,” below).

Portland Harbor site. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (Portland Harbor) that includes the area adjacent to the Gasco site and the Siltronic site. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and we were notified that we are a potentially responsible party. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS). As a result of the EPA’s requests for additional data after reviewing the data collected to date at the site, an additional accrual of $1.3 million was recorded in 2006 for the additional studies, regulatory oversight and related legal costs. Current information is not sufficient to reasonably estimate additional liabilities, if any, or the range of potential liabilities, for environmental remediation and monitoring after the RI/FS work plan is completed, except for the early action removal of a tar deposit in the river sediments discussed below.

In April 2004, 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

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removal of the tar deposit in the Portland Harbor in October 2005 and on November 5, 2005, the EPA approved the completed project. The estimated cost for the removal, including technical work, oversight, consultants, legal fees and ongoing monitoring, is $10.3 million. To date we have spent $9.8 million on work related to the removal of the tar deposit with a remaining liability of $0.5 million.

Central Gas Storage Tanks. On September 22, 2006, we received notice from the ODEQ that our Central Service Center has been 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, or through 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. A negligible accrual was recorded in September 2006 for the ODEQ site assessment and legal and technical costs to investigate and determine the appropriate action, if any. In February 2007, we received notice that the site has been added to the ODEQ’s list of sites where releases of hazardous substances have been confirmed and its list where it has been determined that additional investigation or cleanup is necessary. Possible costs are not currently estimable; however, we intend to seek regulatory authorization for the deferral of environmental costs related to this site (see “Regulatory and Insurance Recovery for Environmental Matters,” below).

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

Regulatory and Insurance Recovery for Environmental Matters. In May 2003, the OPUC approved our request for deferral of environmental costs associated with specific sites, including the Gasco, Siltronic and Portland Harbor sites. The authorization, which was extended through January 2007 and expanded to include the Oregon Steel Mills site, allows us to defer and seek recovery of unreimbursed environmental costs in a future general rate case. In April 2006, the OPUC authorized us to accrue interest on deferred balances effective January 27, 2006, subject to an annual demonstration that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. An application for extension of the regulatory approval to defer environmental costs and accrued interest is pending. As of December 31, 2006, we have paid a cumulative total of $19.1 million relating to the named sites since the effective date of the deferral authorization.

On a cumulative basis, we have recognized a total of $32.7 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, $24.0 million has been spent to-date and $8.7 million is reported as an outstanding liability. At December 31, 2006, we had a regulatory asset of $27.8 million which includes $19.1 million of total expenditures to date and accruals for an additional estimated cost of $8.7 million. We believe the recovery of these costs is probable through the regulatory process. We also have an insurance receivable of $1.1 million, which is not included in the regulatory asset amount. We intend to pursue recovery of these environmental costs from 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 some portion 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

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successful claims filed by other utilities with similar gas manufacturing facilities, and Oregon legislation that allows an insured party to seek recovery of “all sums” from one insurance company. As of January 2007, we have entered into settlement discussions with six of our major insurers, and expect to add another four insurers within the next several months. We anticipate that our overall insurance recovery effort will extend over several years.

The following table summarizes the regulatory assets and accrued liabilities relating to environmental matters at December 31, 2006 and 2005:

	Regulatory Asset				Accrued Liability
Millions		2006		2005		2006		2005
Gasco site	$	10.3	$	3.2	$	6.4	$	1.4
Siltronic site		0.5		0.3		-		-
Portland Harbor site		16.8		15.1		2.1		4.9
Oregon Steel Mills site		0.2		0.2		0.2		0.1
Total	$	27.8	$	18.8	$	8.7	$	6.4

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, including the matters described below, cannot be predicted with certainty, we do not expect that the ultimate disposition of these matters will have a material adverse effect on our financial condition, results of operations or cash flows.

Georgia-Pacific Corporation vs. Northwest Natural Gas Company. On February 3, 2006, Georgia-Pacific Corporation (Georgia-Pacific) filed suit against NW Natural (Georgia-Pacific Corporation v. Northwest Natural Gas Company, Case No. CV06-151-PK, United States District Court, District of Oregon), alleging that we offered to sell natural gas to Georgia-Pacific under the interruptible sales service provisions of Rate Schedule 32 at a commodity rate set at our Weighted Average Cost of Gas. Georgia-Pacific further alleged that it accepted this offer and that we failed to perform as promised when, in October 2005, we notified Georgia-Pacific that we would have to charge Georgia-Pacific the incremental costs of acquiring gas on the open market. Georgia-Pacific also alleged breach of contract, promissory estoppel, fraudulent misrepresentation and breach of the duty of good faith and fair dealing.

On February 23, 2006, we filed a motion for summary judgment on all claims. On June 30, 2006, an order was issued by the U.S. District Court for the District of Oregon dismissing the lawsuit with prejudice and denying all pending motions, if any, as moot. On July 27, 2006, Georgia-Pacific appealed this ruling to the Ninth Circuit Court of Appeals. We have reached agreement with Georgia-Pacific on settlement terms and the lawsuit has been dismissed.

Independent Backhoe Operator Action. Since May 2004, five lawsuits have been filed against NW Natural by independent backhoe operators who performed backhoe services for NW Natural under contract. These five lawsuits have been consolidated into one case, in which 10 plaintiffs remain (Law and Zuehlke, et. al. v. Northwest Natural Gas Co., CV-04-728-KI, United States District Court, District of Oregon). Plaintiffs allege violation of the Fair Labor Standards Act for failure to pay overtime and also assert state wage and hour claims. Plaintiffs claim that they should have been considered “employees,” and seek overtime wages and

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interest in amounts to be determined, liquidated damages equal to the overtime award, civil penalties and attorneys’ fees and costs. Additionally, plaintiffs allege that the failure to classify them as employees constituted a breach of contract under and with respect to certain employee benefits plans, programs and agreements. Plaintiffs seek an unspecified amount of damages for the value of what they would have received under these employee benefit plans if they had been classified as employees. There is insufficient information at this time to reasonably estimate the range of liability, if any, from these claims. We will vigorously contest these claims and do not expect the outcome of this litigation to have a material adverse effect on our results of operations or financial condition.

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

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NORTHWEST NATURAL GAS COMPANY

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	Quarter ended
Thousands, except per share amounts	March 31		June 30		Sept. 30			Dec. 31		Total
2006
Operating revenues	$	390,391	$	170,979	$	114,914		$	336,888	$	1,013,172
Net operating revenues		125,464		61,747		41,341			111,624		340,176
Net income (loss)		41,033		1,994		(9,724	)		30,112		63,415
Basic earnings (loss) per share		1.49		0.07		(0.35	)		1.10		2.30	*
Diluted earnings (loss) per share		1.48		0.07		(0.35	)		1.09		2.29	*
2005
Operating revenues	$	308,777	$	153,667	$	106,667		$	341,375	$	910,486
Net operating revenues		120,986		57,649		41,940			104,418		324,993
Net income (loss)		39,887		1,140		(8,671	)		25,793		58,149
Basic earnings (loss) per share		1.45		0.04		(0.31	)		0.94		2.11	*
Diluted earnings (loss) per share		1.43		0.04		(0.31	)		0.93		2.11	*

* Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Because the average number of shares outstanding has changed in each quarter shown, the sum of quarterly earnings (loss) per share may not equal earnings per share for the year. Variations in earnings between quarterly periods are due primarily to the seasonal nature of our business.

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NORTHWEST NATURAL GAS COMPANY

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

COLUMN A	COLUMN B		COLUMN C				COLUMN D		COLUMN E
	Balance at beginning of period		Additions				Deductions		Balance at end of period
			Charged to costs and expenses		Charged to other accounts		Net Write-offs
Thousands (year ended Dec. 31)
2006
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts	$	3,067	$	3,036	$	0	$	3,070	$	3,033
2005
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts	$	2,434	$	3,034	$	0	$	2,401	$	3,067
2004
Reserves deducted in balance sheet from assets to which they apply:
Allowance for uncollectible accounts	$	1,763	$	3,312	$	0	$	2,641	$	2,434

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

As of December 31, 2006, the principal executive officer and principal financial officer of the Company have evaluated 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 (Exchange Act)). Based upon that evaluation, the principal executive officer and principal financial officer of NW Natural have concluded that such disclosure controls and procedures are effective to ensure that information required to be disclosed by us and included in our reports filed with or furnished to the Securities and Exchange Commission under the Exchange Act is accumulated and communicated to our management as appropriate to allow timely decision 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 our most recent fiscal quarter 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 9A.

Management’s Report on Internal Control Over Financial Reporting and The Report of Independent Registered Public Accounting Firm appear under Item 8.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE

Information concerning our Board of Directors, its Committees and the Audit Committee financial expert contained in NW Natural’s definitive Proxy Statement for the May 24, 2007 Annual Meeting of Shareholders is hereby incorporated by reference. The information concerning “Section 16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance” contained in our definitive Proxy Statement for the May 24, 2007 Annual Meeting of Shareholders is hereby incorporated by reference.

Name	Age at Dec. 31, 2006	Positions held during last five years
Mark S. Dodson	61	President and Chief Executive Officer (2003-    ); President, Chief Operating Officer and General Counsel (2001-2002).
Michael S. McCoy	63	Executive Vice President, Customer and Utility Operations (2000-2006).
Gregg S. Kantor	49	Executive Vice President (2006 -    ); Senior Vice President, Public and Regulatory Affairs (2003-2006); Vice President, Public Affairs and Communications (1998-2002).
David H. Anderson	45	Senior Vice President and Chief Financial Officer (2004-    ); Chief Financial Officer, TXU Gas Company (2004); Senior Vice President, Principal Accounting Officer and Controller (2003-2004); Vice President of Investor Relations and Shareholder Services, TXU Corp. (1997-2003).
Margaret D. Kirkpatrick	52	Vice President and General Counsel (2005-    ); Partner, Stoel Rives LLP (1991- 2005).
Lea Anne Doolittle	51	Vice President, Human Resources (2000-    ).
J. Keith White	53	Vice President, Business Development and Energy Supply (2007-    ); Managing Director, Gas Operations and Wholesale Services (2005-2006); Managing Director and Chief Strategic Officer (2003-2005); Director, Strategic Development (2003); Director, Corporate and Business Development (2001-2003); Director, Business Development (1998-2001).
David R. Williams	53	Vice President, Utility Services (2007-    ); Director, Acquire Customers (2006); Director, Gas Operations (2005-2006); General Manager, Utility Operations (1999-2004)
Grant M. Yoshihara	51	Vice President, Utility Operations (2007-    ); Managing Director, Utility Services (2005-2006); General Manager, Consumer Services (2003-2004); General Manager, Marketing, Development and Utility Operations (2000-2002).
Stephen P. Feltz	51	Treasurer and Controller (1999-    ).
C. J. Rue	61	Secretary (1982-    ); Assistant Treasurer (1987-    ).
Richelle T. Luther	38	Assistant Secretary (2002-    ); Associate, Stoel Rives LLP (1997-2002).

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Each executive officer serves successive annual terms; present terms end on May 24, 2007. There are no family relationships among our executive officers.

NW Natural has adopted a Code of Ethics for all employees, including our chief executive officer, chief financial officer and principal accounting officer, and a Financial Code of Ethics that applies to senior financial employees, both of which are available on our website at www.nwnatural.com.

ITEM 11. EXECUTIVE COMPENSATION

The information concerning “Executive Compensation” and “Report of the Organization and Executive Compensation Committee on Executive Management Compensation” contained in our definitive Proxy Statement for the May 24, 2007 Annual Meeting of Shareholders is hereby incorporated by reference. Information related to Executive Officers as of December 31, 2006 is reflected in Part III, Item 10, above.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth information regarding compensation plans under which equity securities of NW Natural are authorized for issuance as of December 31, 2006 (see Note 4 to the Consolidated Financial Statements):

	(a)	(b)		(c)
	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders:
Long-Term Incentive Plan (LTIP) (Target Award)1	84,494		n/a	375,060
Restated Stock Option Plan	334,000	$	31.14	1,135,000
Employee Stock Purchase Plan	23,303	$	35.17	221,103
Equity compensation plans not approved by security holders:
Executive Deferred Compensation Plan (EDCP)2	7,700		n/a	n/a
Directors Deferred Compensation Plan (DDCP)2	77,751		n/a	n/a
Deferred Compensation Plan for Directors and Executives (DCP)3	17,510		n/a	n/a
Non-Employee Directors Stock Compensation Plan4	n/a		n/a	n/a
Total	544,758			1,731,163

The information captioned “Beneficial Ownership of Common Stock by Directors and Executive Officers” contained in the our definitive Proxy Statement for the May 24, 2007 Annual Meeting of Shareholders is incorporated herein by reference.

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¹ Shares issued pursuant to the LTIP do not include an exercise price, but are payable by us when the award criteria are satisfied. If the maximum awards were paid pursuant to the performance-based awards outstanding at December 31, 2006, the number of shares shown in column (a) would increase by 72,994 shares and the number of shares shown in column (c) would decrease by 72,994 shares.

² Prior to January 1, 2005, deferred amounts were credited, at the participant’s election, to either a “cash account” or a “stock account.” If deferred amounts were credited to stock accounts, such accounts were credited with a number of shares of NW Natural common stock based on the purchase price of the common stock on the next purchase date under our Dividend Reinvestment and Direct Stock Purchase Plan, and such accounts were credited with additional shares based on the deemed reinvestment of dividends. At the election of the participant, deferred balances in the stock accounts are payable after termination of Board service or employment in a lump sum, in installments over a period not to exceed 10 years in the case of the DDCP, or 15 years in the case of the EDCP, or in a combination of lump sum and installments. We have contributed common stock to the trustee of the Umbrella Trusts such that the Umbrella Trusts hold approximately the number of shares of common stock equal to the number of shares credited to all participants’ stock accounts.

³ Effective January 1, 2005, the EDCP and DDCP were replaced by the Deferred Compensation Plan for Directors and Executives (DCP). The DCP continues the basic provisions of the EDCP and DDCP under which deferred amounts are credited to either a “cash account” or a “stock account.” Stock accounts represent a right to receive shares of NW Natural common stock on a deferred basis, and such accounts are credited with additional shares based on the deemed reinvestment of dividends. Effective January 1, 2007, cash accounts are credited quarterly with interest at a rate equal to Moody’s Average Corporate Bond Yield, while EDCP and DDCP cash accounts continue to be credited quarterly with interest at a rate equal to Moody’s Average Corporate Bond Yield plus two percentage points. For the EDCP and the DDCP only, the crediting rate is subject to a six percent minimum rate. Our obligation to pay deferred compensation in accordance with the terms of the DCP will generally become due on retirement, death, or other termination of service, and will be paid in a lump sum or in installments of five or ten years as elected by the participant in accordance with the terms of the DCP. The right of each participant in the DCP is that of a general, unsecured creditor of the Company.

⁴ The material features of this plan are more particularly described in Note 4 to the Consolidated Financial Statements included in this report.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information captioned “Transactions with Related Persons” and “Corporate Governance” in the Company’s definitive Proxy Statement for the May 24, 2007 Annual Meeting of Shareholders is hereby incorporated by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information captioned “2006 and 2005 Audit Firm Fees” in the Company’s definitive Proxy Statement for the May 24, 2007 Annual Meeting of Shareholders is hereby incorporated by reference.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this report:

1. A list of all Financial Statements and Supplemental Schedules is incorporated by reference to Item 8.

2. List of Exhibits filed:

Reference is made to the Exhibit Index commencing on page 118.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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
Date: February 28, 2007	By:	/s/ Mark S. Dodson
		Mark S. Dodson, President         and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

SIGNATURE	TITLE		DATE
/s/ Mark S. Dodson	Principal Executive Officer and Director		February 28, 2007
Mark S. Dodson, President and Chief Executive Officer
/s/ David H. Anderson	Principal Financial Officer		February 28, 2007
David H. Anderson Senior Vice President and Chief Financial Officer
/s/ Stephen P. Feltz	Principal Accounting Officer		February 28, 2007
Stephen P. Feltz Treasurer and Controller
/s/ Timothy P. Boyle	Director	)
Timothy P. Boyle		)
		)
	Director	)
Martha L. Byorum		)
		)
/s/ John D. Carter	Director	)
John D. Carter		)
		)
/s/ C. Scott Gibson	Director	)
C. Scott Gibson		)
		)
/s/ Tod R. Hamachek	Director	)
Tod R. Hamachek		)
		)
/s/ Randall C. Papé	Director	)	February 28, 2007
Randall C. Papé		)
		)
/s/ Richard G. Reiten	Director	)
Richard G. Reiten		)
		)
/s/ Kenneth Thrasher	Director	)
Kenneth Thrasher		)
		)
/s/ Russell F. Tromley	Director	)
Russell F. Tromley		)

117

EXHIBIT INDEX

To

Annual Report on Form 10-K

For Fiscal Year Ended

December 31, 2006

Exhibit Number	Document
3a.	Restated Articles of Incorporation, as filed and effective May 31, 2006 and amended May 31, 2006.
*3b.	Bylaws as amended July 22, 2004 (incorporated herein by reference to Exhibit 3 to Form 10-Q for quarter ended June 30, 2004, File No. 1-15973.
*4a.	Copy of Mortgage and Deed of Trust, dated as of July 1, 1946, to Bankers Trust and R. G. Page (to whom Stanley Burg is now successor), Trustees (incorporated herein by reference to Exhibit 7(j) in File No. 2-6494); and copies of Supplemental Indentures Nos. 1 through 14 to the Mortgage and Deed of Trust, dated respectively, as of June 1, 1949, March 1, 1954, April 1, 1956, February 1, 1959, July 1, 1961, January 1, 1964, March 1, 1966, December 1, 1969, April 1, 1971, January 1, 1975, December 1, 1975, July 1, 1981, June 1, 1985 and November 1, 1985 (incorporated herein by reference to Exhibit 4(d) in File No. 33-1929); Supplemental Indenture No. 15 to the Mortgage and Deed of Trust, dated as of July 1, 1986 (filed as Exhibit 4(c) in File No. 33-24168); Supplemental Indentures Nos. 16, 17 and 18 to the Mortgage and Deed of Trust, dated, respectively, as of November 1, 1988, October 1, 1989 and July 1, 1990 (incorporated herein by reference to Exhibit 4(c) in File No. 33-40482); Supplemental Indenture No. 19 to the Mortgage and Deed of Trust, dated as of June 1, 1991 (incorporated herein by reference to Exhibit 4(c) in File No. 33-64014); and Supplemental Indenture No. 20 to the Mortgage and Deed of Trust, dated as of June 1, 1993 (incorporated herein by reference to Exhibit 4(c) in File No. 33-53795).
*4d.	Copy of Indenture, dated as of June 1, 1991, between the Company and Bankers Trust Company, Trustee, relating to the Company’s Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4(e) in File No. 33-64014).
*4e.	Officers’ Certificate dated June 12, 1991 creating Series A of the Company’s Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4e. to Form 10-K for 1993, File No. 0-994).
*4f.	Officers’ Certificate dated June 18, 1993 creating Series B of the Company’s Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4f. to Form 10-K for 1993, File No. 0-994).
*4f.(1)	Officers’ Certificate dated January 17, 2003 relating to Series B of the Company’s Unsecured Medium-Term Notes and supplementing the Officers’ Certificate dated June 18, 1993 (incorporated herein by reference to Exhibit 4f.(1) to Form 10-K for 2002, File No. 0-994).

118

*4i.	Form of Credit Agreement between Northwest Natural Gas Company and each of JPMorgan Chase Bank, NA, U.S. Bank National Association, Bank of America, NA, Wells Fargo Bank, NA and Wachovia Bank, National Association, dated as of October 1, 2005, including Form of Note (incorporated herein by reference to Exhibit 10.1 to Form 10-Q dated November 3, 2005, File No. 1-15973).
4j.	Distribution Agreement, dated September 28, 2004 as amended and restated on December 7, 2006, among the Company, Merrill Lynch, Pierce Fenner & Smith Incorporated, UBS Securities LLC, J.P. Morgan Securities Inc. and Piper Jaffray & Co.
*4k.	Form of Secured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated October 4, 2004, File No. 1-15973).
*4l.	Form of Unsecured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.2 to Form 8-K dated October 4, 2004, File No. 1-15973).
*10j.	Transportation Agreement, dated June 29, 1990, between the Company and Northwest Pipeline Corporation (incorporated herein by reference to Exhibit 10j. to Form 10-K for 1993, File No. 0-994).
*10j.(1)	Replacement Firm Transportation Agreement, dated July 31, 1991, between the Company and Northwest Pipeline Corporation (incorporated herein by reference to Exhibit 10j.(2) to Form 10-K for 1992, File No. 0-994).
*10j.(2)	Firm Transportation Service Agreement, dated November 10, 1993, between the Company and Pacific Gas Transmission Company (incorporated herein by reference to Exhibit 10j.(2) to Form 10-K for 1993, File No. 0-994).
*10j.(3)	Service Agreement, dated June 17, 1993, between Northwest Pipeline Corporation and the Company (incorporated herein by reference to Exhibit 10j.(3) to Form 10-K for 1994, File No. 0-994).
*10j.(5)	Firm Transportation Service Agreement, dated June 22, 1994, between Pacific Gas Transmission Company and the Company (incorporated herein by reference to Exhibit 10j.(5) to Form 10-K for 1995, File No. 0-994).
*10j.(6)	Firm Service Agreement between the Company and Westcoast Energy Inc., dated as of April 1, 2003 (incorporated herein by reference to Exhibit 10 to Form 10-Q for quarter ended March 31, 2003, File No. 0-994).
11	Statement re computation of per share earnings.
12	Statement re computation of ratios of earnings to fixed charges.
23	Consent of PricewaterhouseCoopers LLP.
31.1	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.

119

31.2	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Executive Compensation Plans and Arrangements:
*10b.	Executive Supplemental Retirement Income Plan (2004 Restatement) (incorporated herein by reference to Exhibit 10.2 to Form 8-K dated September 28, 2004, File No. 1-15973).
*10b.(1)	Supplemental Executive Retirement Plan, effective September 1, 2004 restated December 1, 2006 (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated December 20, 2004, File No. 1-15973).
*10b.(2)	Northwest Natural Gas Company Supplemental Trust, effective January 1, 2005, restated as of December 15, 2005 (incorporated herein by reference to Exhibit 10.7 to Form 8-K dated December 16, 2005, File No. 1-15973).
*10b.(3)	Northwest Natural Gas Company Umbrella Trust for Directors, effective January 1, 1991, restated as of December 15, 2005 (incorporated herein by reference to Exhibit 10.5 to Form 8-K dated December 16, 2005, File No. 1-15973).
*10b.(4)	Northwest Natural Gas Company Umbrella Trust for Executives, effective January 1, 1988, restated as of December 15, 2005 (incorporated herein by reference to Exhibit 10.6 to Form 8-K dated December 16, 2005, File No. 1-15973).
*10b.(5)	Amended and Restated ESRIP Change in Control Appendix to the Executive Supplemental Retirement Income Plan, as amended and effective December 14, 2006 (incorporated herein by reference to Exhibit 10.4 to Form 8-K dated December 19, 2006, File No. 1-15973).
10c.	Restated Stock Option Plan, as amended effective December 14, 2006.
*10c.(1)	Form of Restated Stock Option Plan Agreement (incorporated herein by reference to Exhibit 10.3 to Form 10-Q dated November 3, 2005, File No. 1-15973).
*10e.	Executive Deferred Compensation Plan, effective as of January 1, 1987, restated as of January 1, 2007 (incorporated herein by reference to Exhibit 10.6 to Form 8-K dated December 19, 2006, File No. 1-15973).
*10f.	Directors Deferred Compensation Plan, effective June 1, 1981, restated as of January 1, 2007 (incorporated herein by reference to Exhibit 10.7 to Form 8-K dated December 19, 2006, File No. 1-15973).
*10f.(1)	Deferred Compensation Plan for Directors and Executives effective January 1, 2005, restated as of January 1, 2007 (incorporated herein by reference to Exhibit 10.2 to Form 10-Q dated November 2, 2006, File No. 1-15973).

120

*10g.	Form of Indemnity Agreement as entered into between the Company and each director and executive officer (incorporated herein by reference to Exhibit 10g. to Form 10-K for 1988, File No. 0-994).
*10i.	Non-Employee Directors Stock Compensation Plan, as amended effective December 15, 2005 (incorporated herein by reference to Exhibit 10.2 to Form 8-K dated December 16, 2005, File No. 1-15973).
*10k.	Executive Annual Incentive Plan, effective January 1, 2003 (incorporated herein by reference to Exhibit 10 k. to Form 10-K for 2002, File No. 0-994)
*10o.	Form of amended and restated executive change in control severance agreement between the Company and each executive officer other than Mark S. Dodson (incorporated herein by reference to Exhibit 10.2 to Form 8-K dated December 19, 2006, File No. 1-15973).
*10o.-1	Amended and restated executive change in control severance agreement dated December 14, 2006 between the Company and Mark S. Dodson (incorporated herein by reference to Exhibit 10.3 to Form 8-K dated December 19, 2006, File No. 1-15973).
*10p.	Employment Agreement dated July 2, 1997, between the Company and an executive officer (incorporated herein by reference to Exhibit 10(a) for Form 10-Q for the quarter ended September 30, 1997, File No. 0-994).
*10p.-1	Amendment dated December 18, 1997 to employment agreement dated July 2, 1997, between the Company and an executive officer (incorporated herein by reference to Exhibit 10p.-1 to Form 10-K for 1997, File No. 0-994).
*10p.-2	Amendment dated September 24, 1998 to employment agreement dated July 2, 1997, as previously amended, between the Company and an executive officer (incorporated herein by reference to Exhibit 10(g) to Form 10-Q for the quarter ended September 30, 1998, File No. 0-994).
*10p.-3	Employment Agreement dated December 20, 2002, between the Company and an executive officer (incorporated herein by reference to Exhibit 10p.-3 to Form 10-K for 2002, File No. 0-994).
*10p.-4	Amendment dated December 14, 2006 to employment agreement dated December 20, 2002 between the Company and Mark S. Dodson (incorporated herein by reference to Exhibit 10.8 to Form 8-K dated December 19, 2006, File No. 1-15973).
*10v.	Northwest Natural Gas Company Long-Term Incentive Plan, as amended and restated effective July 26, 2001 (incorporated herein by reference to Exhibit 10(c) to Form 10-Q for the quarter ended June 30, 2001, File No. 0-994).
*10w.	Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.8 to Form 8-K dated December 16, 2005, File No. 1-15973).

121

*10w.(1)	Form of Long-Term Incentive Award Agreement under the Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated February 21, 2007, File No. 1-15973).
*10x.	Form of Restricted Stock Bonus Agreement under the Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.9 to Form 8-K dated December 16, 2005, File No. 1-15973).
*10x.(1)	Restricted Stock Bonus Agreement with an executive officer dated July 26, 2006 (incorporated by reference to Exhibit 10.1 to Form 8-K dated July 28, 2006, File No. 1-15973).
*10z.(1)	Summary of non-employee director compensation, effective January 1, 2005 (incorporated herein by reference to Form 8-K dated October 3, 2006, File No. 1-15973).
*10aa.	Form of Consent dated December 14, 2006 entered into by each executive officer (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated December 19, 2006, File No. 1-15973).

* Incorporated herein by reference as indicated

122

EX-3.(A)

Exhibit 3A

RESTATED ARTICLES OF INCORPORATION

OF

NORTHWEST NATURAL GAS COMPANY

(These Restated Articles of Incorporation of Northwest Natural Gas Company supersede its theretofore existing Restated Articles of Incorporation and all amendments thereto.)

ARTICLE I

The name of this corporation is NORTHWEST NATURAL GAS COMPANY, and its duration shall be perpetual.

ARTICLE II

The purposes of the corporation are to engage in any lawful activity for which corporations may be organized under the Oregon Business Corporation Act.

ARTICLE III

A. The aggregate number of shares of capital stock which the corporation shall have authority to issue is 63,500,000 shares, divided into 3,500,000 shares of Preferred Stock, issuable in series as hereinafter provided, and 60,000,000 shares of Common Stock.

B. A statement of the preferences, limitations and relative rights of each class of capital stock of the corporation, namely, the Preferred Stock and the Common Stock, of the variations in the relative rights and preferences as between series of the Preferred Stock, insofar as the same are fixed by these Restated Articles of Incorporation, and of the authority vested in the board of directors of the corporation to establish series of Preferred Stock and to fix and determine the variations in the relative rights and preferences as between series insofar as the same are not fixed by these Restated Articles of Incorporation, is as follows:

Preferred Stock

1. The shares of the Preferred Stock may be divided into and issued in series. Each series shall be so designated as to distinguish the shares thereof from the shares of all other series of the Preferred Stock and all other classes of capital stock of the corporation. To the extent that these Restated Articles of Incorporation shall not have established series of the Preferred Stock and fixed and determined the variations in the relative rights and preferences as between series, the board of directors shall have authority, and is hereby expressly vested with authority, to divide the Preferred Stock into series and, within the limitations set forth in these Restated Articles of Incorporation and such limitations as may be provided by law, to fix and determine the relative rights and preferences of any series of the Preferred Stock so established. Such action by the board of directors shall be expressed in a resolution or resolutions adopted by it prior to the issuance of shares of each series, which resolution or resolutions shall also set forth the distinguishing designation of the particular series of the Preferred Stock established thereby. Without limiting the generality of the foregoing, authority is hereby expressly vested in the board of directors so to fix and determine with respect to any series of the Preferred Stock:

(a) The rate of dividend and the relative preference of each series in the payment of dividends;

(b) The price at which and the terms and conditions on which shares may be redeemed;

(c) The amount payable upon shares in the event of voluntary and involuntary liquidation and the relative preference of each series on liquidation;

(d) Sinking fund provisions, if any, for the redemption or purchase of shares;

(e) The terms and conditions, if any, on which shares may be converted if the shares of any series are issued with the privilege of conversion; and

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(f) Any other relative right or preference as permitted by law.

All shares of the Preferred Stock of the same series shall be identical except that shares of the same series issued at different times may vary as to the dates from which dividends thereon shall be cumulative; and all shares of the Preferred Stock, irrespective of series, shall constitute one and the same class of stock and shall be identical except as to the designation thereof, the date or dates from which dividends on shares thereof shall be cumulative, and the relative rights and preferences set forth above in clauses (a) through (f) of this subdivision, as to which there may be variations between different series. Except as otherwise may be provided by law or by the resolutions establishing any series of Preferred Stock in accordance with the foregoing provisions of this subdivision, whenever the written consent, affirmative vote, or other action on the part of the holders of the Preferred Stock may be required for any purpose, such consent, vote or other action shall be taken by the holders of the Preferred Stock as a single class irrespective of series and not by different series.

2. The holders of shares of the Preferred Stock of each series shall be entitled to receive dividends, when and as declared by the board of directors, out of any funds legally available for the payment of dividends, at the annual rate fixed and determined with respect to each series either by these Restated Articles of Incorporation or in accordance with subdivision III. B. 1., and no more, payable quarterly on the 15th day of February, May, August and November in each year or on such other date or dates as the board of directors shall determine in the resolutions establishing such series. Such dividends shall be cumulative in the case of shares of each series either from the date of issuance of shares of such series or from the first day of the current dividend period within which shares of such series shall be issued, as the board of directors shall determine, so that if dividends on all outstanding shares of each particular series of the Preferred Stock, at the annual dividend rates fixed and determined either by these Restated Articles of Incorporation or in accordance with subdivision III. B. 1., shall not have been paid or declared and set apart for payment for all past dividend periods and for the then current dividend periods, the deficiency shall be fully paid or dividends equal thereto declared and set apart for payment at said rates before any dividends on the Common Stock shall be paid or declared and set apart for payment. No interest, or sum of money in lieu of interest, shall be payable in respect of any dividend payment or payments which may be in arrears.

3. In the event of any dissolution, liquidation or winding up of the corporation, before any distribution or payment shall be made to the holders of the Common Stock, the holders of the Preferred Stock of each series then outstanding shall be entitled to be paid out of the net assets of the corporation available for distribution to its shareholders the respective amounts per share fixed and determined with respect to each series either by these Restated Articles of Incorporation or in accordance with subdivision III. B. 1., and no more. If upon dissolution, liquidation or winding up of the corporation, whether voluntary or involuntary, the net assets of the corporation available for distribution to its shareholders shall be insufficient to pay the holders of all outstanding shares of Preferred Stock of all series the full amounts to which they shall be respectively entitled as aforesaid, the net assets of the corporation so available for distribution shall be distributed to the holders of Preferred Stock in accordance with the relative preferences of each series of Preferred Stock established either by these Restated Articles of Incorporation or in accordance with subdivision III. B. 1. For the purposes of this subdivision, any dissolution, liquidation or winding up which may arise out of or result from the condemnation or purchase of all or a major portion of the properties of the corporation by (i) the United States Government or any authority, agency or instrumentality thereof (ii) a State of the United States or any political subdivision, authority, agency or instrumentality thereof, or (iii) a district, cooperative or other association or entity not organized for profit, shall be deemed to be an involuntary dissolution, liquidation or winding up; and a consolidation, merger or amalgamation of the corporation with or into any other corporation or corporations shall not be deemed to be a dissolution, liquidation or winding up of the corporation, whether voluntary or involuntary.

4. The holders of shares of the Preferred Stock shall have no right to vote in the election of directors or for any other purpose, except as may be otherwise provided by law or by resolutions establishing any series of Preferred Stock in accordance with subdivision III. B. 1. Holders of Preferred Stock shall be entitled to notice of each meeting of shareholders at which they shall have any right to vote, but shall not be entitled to notice of any other meeting of shareholders.

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Common Stock

5. Subject to the limitations set forth in subdivisions III. B. 2. (and subject to the rights of any class of stock hereafter authorized), dividends may be paid upon the Common Stock when and as declared by the board of directors of the corporation out of any funds legally available for the payment of dividends.

6. Subject to the limitations set forth in subdivisions III. B. 3. (and subject to the rights of any other class of stock hereafter authorized), upon any dissolution, liquidation or winding up of the corporation, whether voluntary or involuntary, the net assets of the corporation shall be distributed ratably to the holders of the Common Stock.

7. Except as may be otherwise provided by law or by the resolutions establishing any series of Preferred Stock in accordance with subdivision III. B. 1., the holders of the Common Stock shall have the exclusive right to vote for the election of directors and for all other purposes. In the election of directors of the corporation, every holder of record of any share or shares of the Common Stock of the corporation shall have the right to cast as many votes for one candidate as shall equal the number of such shares multiplied by the number of directors to be elected, or to distribute such number of votes among any two or more candidates for such election.

8. Upon the issuance for money or other consideration of any shares of capital stock of the corporation, or of any security convertible into capital stock of the corporation, no holder of shares of the capital stock, irrespective of the class or kind thereof, shall have any preemptive or other right to subscribe for, purchase or receive any proportionate or other amount of such shares of capital stock, or such security convertible into capital stock, proposed to be issued; and the board of directors may cause the corporation to dispose of all or any of such shares of capital stock, or of any such security convertible into capital stock, as and when said board may determine, free of any such right, either by offering the same to the corporation’s then shareholders or by otherwise selling or disposing of such shares of other securities, as the board of directors may deem advisable.

ARTICLE IV

A. The business and affairs of the corporation shall be managed by a board of directors. Except as provided in subdivision B. below, the number of members of the board, their classifications and terms of office, and the manner of their election and removal shall be as follows:

1. The number of directors shall be that number, not less than nine or more than thirteen, determined from time to time by resolution adopted by affirmative vote of a majority of the entire board of directors. The directors shall be divided into three classes, designated Class I, Class II, and Class III. Each class shall consist, as nearly as possible, of one-third of the total number of directors. At the 1984 annual meeting of shareholders, Class I directors shall be elected for a one-year term, Class II directors for a two-year term, and Class III directors for a three-year term. At each succeeding annual meeting of shareholders, successors to directors whose terms expire at that annual meeting shall be of the same class as the directors they succeed, and shall be elected for three-year terms. If the number of directors should be changed by resolution of the board of directors, any increase or decrease shall be apportioned among the classes so as to maintain the number of directors in each class as nearly equal as possible, but in no case shall a decrease in the number of directors shorten the term of any incumbent director.

2. A director shall hold office until the annual meeting for the year in which his or her term shall expire and until his or her successor shall have been elected and qualified, subject, however, to prior death, resignation, retirement or removal from office. Any newly created directorship resulting from an increase in the number of directors and any other vacancy on the board of directors, however caused, may be filled by the affirmative vote of a majority of the directors then in office, although less than a quorum, or by a sole remaining director.

3. One or more of the directors may be removed with or without cause by the affirmative vote of the holders of not less than two-thirds of the shares entitled to vote thereon at a meeting of the shareholders called

3

expressly for that purpose; provided, however, that for as long as the corporation shall have cumulative voting, if fewer than all the directors should be candidates for removal, no one of them shall be removed if the votes cast against his or her removal would be sufficient to elect him or her if then cumulatively voted at an election of the class of directors of which he or she shall be a part.

4. No person, except those persons nominated by the board, shall be eligible for election as a director at any annual or special meeting of shareholders unless a written request that his or her name be placed in nomination shall be received from a shareholder of record entitled to vote at such election by the secretary of the corporation not later than the latter of (a) the thirtieth day prior to the date fixed for the meeting, or (b) the tenth day after the mailing of notice of that meeting, together with the written consent of the nominee to serve as a director.

B. Notwithstanding the provisions of subdivision A. above, whenever the holders of any one or more classes of the capital stock of the corporation shall have the right, voting separately as a class or classes, to elect directors at an annual or special meeting of shareholders, the election, term of office, filling of vacancies and other features of such directorships shall be governed by the provisions of these Restated Articles of Incorporation applicable thereto. Directors so elected shall not be divided into classes unless expressly provided by such provisions, and during their prescribed terms of office, the board of directors shall consist of such directors in addition to the directors determined as provided in subdivision A. above.

C. This Article IV may not be repealed or amended in any respect unless such action shall be approved by the affirmative vote of the holders of not less than two-thirds of the shares entitled to vote at an election of directors determined as provided in subdivision A. above, at a meeting of the shareholders called expressly for that purpose.

ARTICLE V

A. For purposes of this Article V:

1. The term “Affiliate”, as used to indicate a relationship with a specified “Persons” (as hereinafter defined), shall mean a Person that directly or indirectly through one or more intermediaries, controls, or is controlled by, or is under common control with, the Person specified.

2. The term “Associate”, as used to indicate a relationship with a specified Person, shall mean (a) any Person (other than the corporation) of which such specified Person is a director, officer, partner, trustee, guardian, fiduciary or official or is, directly or indirectly, the beneficial owner of 10% or more of any class of equity securities or any beneficial interest, (b) any Person who is a director, officer, partner, trustee, guardian, fiduciary or official or is, directly or indirectly, the beneficial owner of 10% or more of any class of equity securities or any beneficial interest of or in such specified Person (other than the corporation), and (c) any relative or spouse of such specified Person, or any relative of such spouse who has the same home as such specified Person.

3. The term “Beneficial Owner” shall have the meaning set forth in Rule 13d-3 of the General Rules and Regulations under the Securities Exchange Act of 1934 as in effect on April 9, 1984; provided, however, that, notwithstanding the provisions of such Rule, a Person shall be deemed to be the Beneficial Owner of any share of the capital stock of the corporation that such Person shall have the right to acquire at any time pursuant to any agreement, contract, arrangement or understanding, or upon exercise of conversion rights, warrants or options, or otherwise, and any such share of capital stock shall be deemed to be outstanding for purposes of subdivision V.A.9.

4. The term “Business Transaction” shall include, without limitation, (a) any merger, consolidation or plan of exchange of the corporation, or any Person controlled by or under common control with the corporation, with or into any “Related Person” (as hereinafter defined), (b) any merger, consolidation or plan of exchange of a Related Person with or into the corporation or any Person controlled by or under common control with the corporation, (c) any sale, lease, exchange, transfer or other disposition (in one transaction or a series of transactions) including without limitation a mortgage or any other security device, of all or

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any “Substantial Part” (as hereinafter defined) of the property and assets of the corporation, or any Person controlled by or under common control with the corporation, to or with a Related Person, (d) any purchase, lease, exchange, transfer or other acquisition (in one transaction or a series of transactions), including without limitation a mortgage or any other security device, of all or any Substantial Part of the property and assets of a Related Person, by or with the corporation or any Person controlled by or under common control with the corporation, (e) any recapitalization of the corporation that would have the effect of increasing the voting power of a Related Person, (f) the issuance, sale, exchange or other disposition of any securities of the corporation, or of any Person controlled by or under common control with the corporation, by the corporation or by any Person controlled by or under common control with the corporation, (g) any liquidation, spinoff, splitoff, splitup or dissolution of the corporation, and (h) any agreement, contract or other arrangement providing for any of the transactions described in this subdivision.

5. The term “Continuing Director” shall mean a director who was a director of the corporation on April 9, 1984 and a director who shall become a director subsequent thereto whose election, or whose nomination for election by the shareholders, shall have been approved by a vote of a majority of the then Continuing Directors.

6. The term “Highest Purchase Price” shall mean, with respect to the shares of any class or series of the capital stock of the corporation, the highest amount of consideration paid by a Related Person for a share of the same class and series at any time regardless of whether the share was acquired before or after such Related Person became a Related Person; provided, however, that the Highest Purchase Price shall be appropriately adjusted to reflect the occurrence of any reclassification, recapitalization, stock split, reverse stock split or other readjustment in the number of outstanding shares of that class or series, or the declaration of a stock dividend thereon. The Highest Purchase Price shall include any brokerage commissions, transfer taxes and soliciting dealers’ fees paid by such Related Person with respect to any shares of the capital stock acquired by such Related Person.

7. The term “Other Consideration” shall include, without limitation, capital stock to be retained by the shareholders of the corporation in a Business Transaction in which the corporation shall be the survivor.

8. The term “Person” shall mean any natural person, corporation, partnership, trust, firm, association, government, governmental. agency or any other entity whether acting in an individual, fiduciary or other capacity.

9. The term “Related Person” shall mean (a) any Person which, together with its Affiliates and Associates, shall be the Beneficial Owner in the aggregate of 10 percent or more of the capital stock of the corporation, and (b) any Affiliate or Associate (other than the corporation or a wholly owned subsidiary of the corporation) of any such Person. Two or more Persons acting in concert for the purpose of acquiring, holding or disposing of the capital stock of the corporation shall be deemed to be a “Related Person”. A Related Person shall be deemed to have acquired a share of capital stock at the time when such Related Person became the Beneficial Owner thereof. With respect to the shares of the capital stock of the corporation owned by any Related Person, if the price paid for such shares cannot be determined by a majority of the Continuing Directors, the price so paid shall be deemed to be the market price of the shares in question at the time when such Related Person became the Beneficial Owner thereof.

10. The term “Substantial Part” shall mean 10% or more of the fair market value of the total assets of a Person, as reflected on the most recent balance sheet of such Person available to the Continuing Directors on the date of mailing of the notice of the meeting of shareholders called for the purpose of voting with respect to a Business Transaction involving the assets constituting any such Substantial Part.

B. The corporation shall not enter into any Business Transaction with a Related Person or in which a Related Person shall have an interest (except proportionately as a shareholder of the corporation) without first obtaining both (1) the affirmative vote of the holders of not less than two-thirds of the outstanding shares of the capital stock of the corporation not held by such Related Person, and (2) the determination of a majority of the Continuing Directors that the cash or fair market value of the property, securities or Other Consideration to be received per share by the holders, other than such Related Person, of the shares of each class or series of the

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capital stock of the corporation in such Business Transaction shall not be less than the Highest Purchase Price paid by such Related Person in acquiring any of its holdings of shares of the same class or series, unless the Continuing Directors by a majority vote shall either (a) have expressly approved the acquisition of the shares of the capital stock of the corporation that caused such Related Person to become a Related Person, or (b) have expressly approved such Business Transaction.

C. For the purposes of this Article V, a majority of the Continuing Directors shall have the power to make a good faith determination, on the basis of information known to them, of: (1) the number of shares of capital stock of the corporation of which any Person shall be the Beneficial Owner, (2) whether a Person is an Affiliate or Associate of another Person, (3) whether a Person has an agreement, contract, arrangement or understanding with another Person as to the matters referred to in subdivision V.A.3. or clause (h) of subdivision V.A.4., (4) the Highest Purchase Price paid by a Related Person for shares of any class or series of the capital stock, (5) whether the assets subject to any Business Transaction constitute a Substantial Part, (6) whether any Business Transaction is one in which a Related Person has an interest (except proportionately as a shareholder of the corporation), and (7) such other matters with respect to which a determination may be required under this Article V.

D. In determining whether to give their approval as provided in subdivision V.B., the Continuing Directors shall give due consideration to all relevant factors involved, including, without limitation, (1) the value of the corporation in a freely negotiated transaction and its future value as an independent entity, (2) the recognition of gain or loss to the corporation for tax purposes or the postponement of such recognition in a tax-free transaction, (3) the anticipated developments of the business of the corporation not yet reflected in the price of its shares, and (4) the impact on employees, customers, suppliers and the public generally within the geographical area it serves.

E. This Article V may not be repealed or amended in any respect unless such action shall be approved by the affirmative vote of the holders of not less than two-thirds of the capital stock of the corporation not held by a Related Person at a meeting of the shareholders called expressly for that purpose.

ARTICLE VI

No director of the corporation shall be personally liable to the corporation or its shareholders for monetary damages for conduct as a director; provided that this Article VI shall not eliminate the liability of a director for any act or omission for which such elimination of liability is not permitted under the Oregon Business Corporation Act. No amendment to the Oregon Business Corporation Act that further limits the acts or omissions for which elimination of liability is permitted shall affect the liability of a director for any act or omission which occurs prior to the effective date of such amendment.

ARTICLE VII

The corporation shall indemnify to the fullest extent then permitted by law any person who is made, or threatened to be made, a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative, investigative or otherwise (including an action, suit or proceeding by or in the right of the corporation) by reason of the fact that the person is or was a director or officer of the corporation or is or was serving at the request of the corporation as a director or officer of another corporation, partnership, joint venture, trust or other enterprise against all judgments, amounts paid in settlement, fines and such expenses (including attorneys’ fees), actually and reasonably incurred in connection therewith. This Article shall not be deemed exclusive of any other provisions for indemnification of directors and officers that may be included in any statute, bylaw, agreement, vote of shareholders or directors or otherwise, both as to action in any official capacity and as to action in another capacity while holding an office.

As amended May 31, 2006.

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EX-4.(J)

Exhibit 4J

Northwest Natural Gas Company

$160,000,000

Medium-Term Notes, Series B

Distribution Agreement

September 28, 2004, amended and

restated on December 7, 2006       

Merrill Lynch, Pierce, Fenner & Smith

Incorporated

4 World Financial Center

15th Floor

New York, New York 10080

UBS Securities LLC

677 Washington Blvd.

Stamford, Connecticut 06901

J.P. Morgan Securities Inc.

270 Park Avenue

New York, New York 10017

Piper Jaffray & Co.

800 Nicollet Mall

Minneapolis, Minnesota 55402

Ladies and Gentlemen:

Northwest Natural Gas Company, an Oregon corporation (the “Company”), proposes to issue and sell from time-to-time not to exceed $160,000,000 of its First Mortgage Bonds, designated Secured Medium-Term Notes, Series B (the “Secured Notes”), and its Unsecured Medium-Term Notes, Series B (the “Unsecured Notes”, and, together with the Secured Notes, the “Securities”). Prior to December 7, 2006, $50,000,000 of the Securities have been previously offered and sold. The Secured Notes will be issued under the Company’s Mortgage and Deed of Trust, dated as of July 1, 1946, to Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) (the “Mortgage Trustee” or the “Trustee”) and R.G. Page (Stanley Burg, successor), as trustees, as supplemented (such Mortgage and Deed of Trust as supplemented being hereinafter referred to as the “Mortgage” or the “Indenture”). The Unsecured Notes will be issued under an indenture, dated as of June 1, 1991 (the “Note Indenture” or the “Indenture”), between the Company and Deutsche Bank Trust Company Americas, as trustee (the “Indenture Trustee” or the “Trustee”).

The Securities shall have the maturities, interest rates, if any, redemption provisions and other terms set forth in the Prospectus referred to below, as it may be amended or supplemented from time-to-time, and any final term sheet relating to an offering of a particular issuance of securities, containing information that describes the final terms of such Securities or such offering (“the “Term Sheet”). The Securities will be issued, and the terms thereof established, from time-to-time, by the Company in accordance with the respective Indentures.

The Company represents, warrants, covenants and agrees with each of you and with each other person which shall become a party to this agreement (individually, an “Agent,” and collectively, the “Agents”) and each Agent, severally and not jointly, covenants and agrees with the Company as follows:

1. Representations and Warranties of the Company. The Company represents and warrants to each Agent that:

(a) The Company is a corporation duly organized and validly existing under the laws of the State of Oregon, and is qualified to do business as a foreign corporation in the State of Washington, with power (corporate and other) to own its properties and conduct its business as described in the Prospectus and the Pricing Disclosure Package (as defined below) (if applicable), each referred to below;

(b) A registration statement on Form S-3 (Registration No. 333-112604) (the “Registration Statement”), in respect of $200,000,000 of the Company’s securities (which may include the Company’s First Mortgage Bonds designated Secured Medium-Term Notes Series B, and Unsecured Medium-Term Notes Series B) has been filed with the Securities and Exchange Commission (the “Commission”) under the Securities Act of 1933, as amended (the “Act”), in the form heretofore delivered or to be delivered (excluding the exhibits thereto but including the documents incorporated by reference in the prospectus included therein) to such Agent, and such Registration Statement in such form has been declared effective by the Commission and no stop order suspending its effectiveness has been issued and no proceeding for that purpose has been initiated or threatened by the Commission (any preliminary prospectus included in the Registration Statement being hereinafter called a “Preliminary Prospectus”). The Registration Statement, including all exhibits thereto and including the documents incorporated by reference in the prospectus included therein, and including any prospectus supplement relating to the Securities that is filed with the Commission and deemed by virtue of Rule 430B to be part of the registration statement at the applicable time of effectiveness or deemed effectiveness, but excluding Forms T-1 and T-2, each as amended at the time such part of the registration statement or any post-effective amendment became effective, each is hereinafter called the “Registration Statement”; the prospectus included as a part of the Registration Statement (including the Prospectus Supplement, dated September 28, 2004, and any other prospectus supplement relating to the Securities), in the form in which it most recently has been filed with the Commission on or prior to the date of this Agreement, is hereinafter called the “Prospectus”; any reference herein to any Preliminary Prospectus or the

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Prospectus shall be deemed to refer to and include the documents filed by the Company under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and incorporated therein by reference as of the date of such Preliminary Prospectus or the Prospectus, as the case may be; any reference to any amendment or supplement to any Preliminary Prospectus or the Prospectus, including any supplement to the Prospectus that sets forth only the terms of a particular issue of the Securities (a “Pricing Supplement”), shall be deemed to refer to and include the documents filed by the Company under the Exchange Act and incorporated therein by reference as of the date of such amendment or Pricing Supplement; any reference to the Prospectus as amended or supplemented shall be deemed to refer to and include the Prospectus as then amended or supplemented (including the applicable Pricing Supplement) in relation to a particular issue of Securities to be sold pursuant to this Agreement, in the form filed with the Commission pursuant to Rule 424(b) under the Act, including any documents filed by the Company under the Exchange Act and incorporated therein by reference as of the date of such amendment or supplement; “Pricing Disclosure Package” means the Prospectus, including all amendments and supplements thereto and any preliminary Pricing Supplement as of the Applicable Time (as defined below), and each Term Sheet prepared pursuant to Section 5(p) and any other free-writing prospectus (as defined in Rule 405 under the Act) that has been prepared by or on behalf of the Company relating to such Securities as of such Applicable Time; and “Applicable Time” means the time and date set forth in the Terms Agreement (as defined below) for an issue of Securities, or if the Company does not enter into a Terms Agreement with respect to a sale of Securities, the time and date of each acceptance by the Company of any offer to purchase Securities hereunder (whether through an Agent as agent or to an Agent as principal);

(c) The documents incorporated by reference in the Prospectus and in the Pricing Disclosure Package (if applicable), when filed with the Commission or, if later, when they became effective, conformed in all material respects with the requirements of the Act or the Exchange Act, as applicable, and the applicable rules and regulations of the Commission thereunder; none of such documents when so filed or when such documents became effective, as the case may be, included an untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; any future documents so filed or incorporated by reference in the Prospectus or any Pricing Disclosure Package, or any amendment or supplement to either thereof, when filed with the Commission or, if later, when effective, will conform in all material respects with the applicable requirements of the Act or the Exchange Act, as applicable, and the rules and regulations of the Commission thereunder, and when such documents are filed or become effective, as the case may be, they will not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided, however, that the Company makes no representations or warranties as

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to information contained in or omitted from the Prospectus as amended or supplemented or any Pricing Disclosure Package in reliance upon and in conformity with information furnished in writing to the Company by any Agent specifically for use therein;

(d) The Registration Statement when it became effective conformed, and the Prospectus conforms, and any amendment or supplement thereto will conform, in all material respects, with the provisions of the Act and the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”), and the rules and regulations of the Commission thereunder; and the Registration Statement when it became effective did not (and as of the applicable effective date and on each of the dates and times referred to in clause (a) of Section 6 will not), the Prospectus, the Prospectus (including any preliminary Pricing Supplement) together with the Term Sheet, and the Pricing Disclosure Package (if applicable) does not (and on each of the dates and times referred to in clause (a) of Section 6 will not) and any amendment or supplement to the Prospectus, as of its date and on each of the dates referred to in clause (a) of Section 6, will not, contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading; provided, however, that the Company makes no representations or warranties as to information contained in or omitted from any such document in reliance upon and in conformity with information furnished in writing to the Company by any Agent specifically for use therein;

(e) The Company is not an “ineligible issuer” in connection with the offering pursuant to Rules 164, 405 and 433 under the Act. Any free writing prospectus that the Company is required to file pursuant to Rule 433(d) under the Act has been, or will be, filed with the Commission in accordance with the requirements of the Act and the applicable rules and regulations of the Commission thereunder. Each free writing prospectus that the Company has filed, or is required to file, pursuant to Rule 433(d) under the Act or that was prepared by or on behalf of or used or referred to by the Company complies or will comply in all material respects with the requirements of the Act and the applicable rules and regulations of the Commission thereunder. Any such free writing prospectus did not or will not, as of its issue date and through the time the Securities are sold by the Agents, include any information that conflicts with the information contained in the Registration Statement and the Prospectus; and any such free writing prospectus, when taken together with the information contained in the Registration Statement and the Prospectus, did not, when issued or filed pursuant to Rule 433, and does not contain an untrue statement of a material fact or omit to state a material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided, however, that the Company makes no representations or warranties as to information contained in or omitted from the free writing prospectus in reliance upon and in conformity with information furnished in writing to the Company by any Agent specifically for use therein; except for any free writing prospectuses each furnished to the applicable Agent before first use, the Company has not prepared, used or referred to, and will not, without such Agent’s consent, prepare, use or refer to any free writing prospectus.

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(f) Except as set forth in or contemplated by the Prospectus, since the date as of which information is given in the Prospectus (if applicable) (i) there has not been any material adverse change in the condition of the Company and its subsidiaries taken as a whole, financial or otherwise, (ii) there has not been any transaction entered into by the Company or any of its subsidiaries which is material to the Company and its subsidiaries taken as a whole, other than transactions in the ordinary course of business, and (iii) neither the Company nor any of its subsidiaries has incurred any contingent obligation which is material to the Company and its subsidiaries taken as a whole;

(g) The Securities have been duly authorized, and, when issued and authenticated pursuant to their respective Indentures and delivered pursuant to this Agreement and any Terms Agreement (as defined in Section 3 hereof), will have been duly executed, authenticated, issued and delivered, will constitute valid and legally binding obligations of the Company, enforceable in accordance with their terms, except as their enforceability may be limited by laws and principles of equity relating to or affecting generally the enforcement of creditors’ rights, including without limitation, bankruptcy and insolvency laws, and will be entitled to the benefits provided by their respective Indentures (which will be substantially in the form filed as exhibits to the Registration Statement); the Indentures have been duly authorized and qualified under the Trust Indenture Act, constitute valid and legally binding instruments, enforceable in accordance with their terms, except as their enforceability may be limited by laws and principles of equity relating to or affecting generally the enforcement of creditors’ rights, including without limitation, bankruptcy and insolvency laws; and the Indentures conform, and the Securities of each issue, when issued, will conform, in all material respects, to the descriptions thereof in the Prospectus, as amended or supplemented, and the Pricing Disclosure Package (if applicable) with respect to such issue;

(h) The issue and sale of the Securities, the compliance by the Company with all of the provisions of the Securities, the Indentures, this Agreement and any Terms Agreement, and the consummation by the Company of the transactions herein and therein contemplated will not result in a breach or violation of any of the terms or provisions of, or constitute a default under, any indenture, mortgage, deed of trust, loan agreement or other agreement or instrument to which the Company is a party or by which the Company is bound or to which any of the property of the Company is subject, nor will such action result in any violation of the provisions of any statute or the Restated Articles of Incorporation, as amended, or the Bylaws, as amended, of the Company or any order, rule or regulation of any court or any regulatory authority or other governmental agency or body having jurisdiction over the Company or any of its properties; and no consent, approval, authorization, order, registration or qualification of or with any court or governmental agency or body is required by the Company for the solicitation of offers to purchase Securities and the issue and sale of the Securities or the

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consummation by the Company of the other transactions contemplated by the Indentures, this Agreement or any Terms Agreement, except such as have been obtained at or prior to the Commencement Date (as defined in Section 4 hereof), will have been obtained under the Act, the Trust Indenture Act and the public utility laws of the State of Oregon and such as may be required to be obtained under the public utility laws of the State of Washington and such as may be required under state securities or Blue Sky laws in connection with the solicitation by such Agent of offers to purchase Securities from the Company and with purchases of Securities by such Agent as principal, as the case may be, in each case in the manner contemplated hereby; and

(i) Other than as set forth or contemplated in the Prospectus, there are no legal or governmental proceedings pending to which the Company is a party or to which any property of the Company is subject, which, if determined adversely to the Company, would individually or in the aggregate have a material adverse effect on the consolidated financial position, stockholders’ equity or consolidated results of operations of the Company, and, to the best of the Company’s knowledge, no such proceedings are threatened.

(j) The Company’s internal control over financial reporting includes policies and procedures that are designed to (1) provide for the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions concerning the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles in the United States of America; (3) provide reasonable assurance that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (4) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

(k) The Company employs disclosure controls and procedures that are designed to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and is accumulated and communicated to the Company’s management, including its principal executive and principal financial officer, as appropriate, to allow timely decisions regarding disclosure.

2. Obligations of the Agents and the Company.

(a) Subject to the terms and conditions hereof and to the reservation by the Company of the right to sell Securities directly on its own behalf, the Company hereby (i) appoints each of Merrill Lynch, Pierce, Fenner & Smith Incorporated, UBS Securities LLC, J.P. Morgan Securities Inc. and Piper Jaffray & Co. as an agent of the Company for the purpose of soliciting and receiving offers to purchase Securities from the Company and (ii) reserves the right, from time to

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time, to appoint additional agents for the purpose of soliciting and receiving offers to purchase Securities from the Company; provided that each such additional agent shall be required to become a party to this Agreement and undertake the obligations of an Agent hereunder pursuant to an Additional Agent Appointment Agreement (“Additional Agent Appointment Agreement”) substantially in the form of Exhibit 1 hereto.

(b) On the basis of the representations and warranties herein, and subject to the terms and conditions hereof, each of the Agents, as agent of the Company, severally and not jointly, agrees to use its reasonable best efforts to solicit and receive offers to purchase particular issues of the Securities from the Company upon the terms and conditions set forth in the Prospectus as amended or supplemented with respect thereto and in any applicable Pricing Disclosure Package. Each Agent will promptly advise the Company by telephone or other appropriate means of all reasonable offers to purchase Securities, other than those rejected by such Agent. The Company shall not, without the consent of each Agent, which consent shall not unreasonably be withheld, solicit or accept offers to purchase, or sell, any debt securities with a maturity, at the time of original issuance, of from nine months to 30 years, except (i) pursuant to this Agreement, (ii) pursuant to a private placement not constituting a public offering under the Act, or (iii) in connection with a firm commitment underwriting pursuant to an underwriting agreement that does not provide for a continuous offering. However, the Company, subject to Section 5(f) hereof, reserves the right to sell, and may solicit and accept offers to purchase, Securities directly on its own behalf, and, in the case of any such sale not resulting from a solicitation made by an Agent, no commission will be payable with respect to such sale.

(c) Procedural details relating to the issue and delivery of Securities, the solicitation of offers to purchase Securities and the payment therefor, unless an Agent and the Company shall otherwise agree, shall be as set forth in the Administrative Procedure attached hereto as Annex I (the “Administrative Procedure”). The provisions of the Administrative Procedure shall apply to all transactions contemplated hereunder other than those made pursuant to a Terms Agreement. Each Agent and the Company shall perform the respective duties and obligations specifically provided to be performed by each of them in the Administrative Procedure. The Company will furnish to the Trustees a copy of the Administrative Procedure as from time to time in effect.

(d) The Company reserves the right, in its sole discretion, to instruct the Agents to suspend, at any time, for any period of time or permanently, the solicitation of offers to purchase the Securities. As soon as practicable, but in any event not later than one business day after receipt of instructions from the Company, the Agents will suspend solicitation of offers to purchase Securities from the Company until such time as the Company has advised the Agents that such solicitation may be resumed.

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(e) The Company agrees to pay each Agent a commission, at the time of settlement (each a “Settlement Date”) of any sale of a Security by the Company as a result of a solicitation made by such Agent, in an amount, unless otherwise agreed, equal to the following applicable percentage of the principal amount of such Security sold:

Range of Maturities	Commission (percentage of aggregate principal amount of Securities sold)
From 9 months to less than 1 year	.125%
From 1 year to less than 18 months	.150%
From 18 months to less than 2 years	.200%
From 2 years to less than 3 years	.250%
From 3 years to less than 4 years	.350%
From 4 years to less than 5 years	.450%
From 5 years to less than 6 years	.500%
From 6 years to less than 7 years	.550%
From 7 years to less than 10 years	.600%
From 10 years to less than 15 years	.625%
From 15 years to less than 20 years	.675%
From 20 years to 30 years	.750%

(f) Each of the several Agents represents and agrees that it will make no offer that would constitute a Free Writing Prospectus (as defined in Rule 405 under the Securities Act) that is required to be filed by the Company pursuant to Rule 433 under the Securities Act other than a Term Sheet in accordance with Section 5(p), unless the Company and such Agents otherwise agree in connection with a particular offering of Securities.

3. Sales to Agents as Principal. Each sale of Securities to an Agent, as principal, shall be made in accordance with the terms of this Agreement and (unless the Company and such Agent shall otherwise agree) a separate agreement (each a “Terms Agreement”), which will provide for the sale of such Securities to, and the purchase thereof by, such Agent, as principal. A Terms Agreement may be either (i) a written agreement substantially in the form of Annex II hereto, or (ii) an oral agreement between any Agent and the Company confirmed in writing by such Agent. A Terms Agreement may also specify certain provisions relating to the reoffering of such Securities by such Agent. Each Terms Agreement shall specify the principal amount of Securities to be purchased by an Agent pursuant thereto, the price to be paid to the Company for such Securities, any provisions relating to the rights of, and defaults by, any underwriters acting together with such Agent in the reoffering of the Securities, the time and date of delivery of and payment for such Securities (each, a “Time of Delivery”) and place of delivery of such Securities, and any requirements for opinions of counsel, accountants’ letters and officers’ certificates pursuant to Section 5 hereof. Each purchase of Securities, unless otherwise agreed shall be at a discount equivalent to the commission payable

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to an Agent, acting as agent, with respect to a sale of Securities of identical maturity, as set forth in Section 2(e) hereof). The Agent may engage the services of any other broker or dealer in connection with the resale of the Securities purchased as principal and may allow any portion of the discount received in connection with such purchase from the Company to be paid to such brokers and dealers. The commitment of an Agent to purchase Securities as principal, whether pursuant to a Terms Agreement or otherwise, shall be deemed to have been made on the basis of the representations and warranties of the Company herein contained and, to the extent not otherwise agreed upon in a Terms Agreement or otherwise, shall be subject to the terms and conditions herein set forth.

4. Commencement. At 11:00 a.m., New York City time, on September 28, 2004, the Distribution Agreement, dated September 28, 2004 (“Original Distribution Agreement”), among the Company and the Agents was executed (such time and date being referred to herein as the “Commencement Date”), the Agents were furnished at the offices of Thelen Reid & Priest LLP, 875 Third Avenue, New York, New York, with the following:

(a) An opinion of Simpson Thacher & Bartlett LLP, counsel to the Agents, dated the Commencement Date, with respect to such matters as such Agents reasonably requested, which opinion relied as to all matters governed by Oregon law, upon the opinion of Beth A. Ugoretz, Esq., General Counsel for the Company, referred to in Section 4(b) hereof and, as to all matters governed by Washington law, upon the opinion of Stoel Rives LLP referred to in Section 4(d) hereof;

(b) An opinion of Beth A. Ugoretz, Esq., dated the Commencement Date, in form and substance reasonably satisfactory to such Agents, to the effect set forth in Annex III to the Original Distribution Agreement, which opinion relied, as to all matters governed by New York law, the Act, the Exchange Act and the Trust Indenture Act, upon the opinion of Thelen Reid & Priest LLP referred to in Section 4(c) hereof and, as to certain matters governed by Washington law, upon the opinion of Stoel Rives LLP referred to in Section 4(d) hereof;

(c) An opinion of Thelen Reid & Priest LLP, dated the Commencement Date, in form and substance reasonably satisfactory to such Agents, to the effect set forth in Annex IV to the Original Distribution Agreement, which opinion relied as to all matters governed by Oregon law, upon the opinion of Beth A. Ugoretz, Esq., referred to in Section 4(b) hereof and, as to all matters governed by Washington law, upon the opinion of Stoel Rives LLP referred to in Section 4(d) hereof;

(d) An opinion of Stoel Rives LLP, dated the Commencement Date, in form and substance reasonably satisfactory to such Agents, to the effect set forth in Annex V to the Original Distribution Agreement;

(e) A letter from PricewaterhouseCoopers LLP, the Company’s independent registered public accounting firm, dated the Commencement Date, in form and substance reasonably satisfactory to such Agents and subject to compliance with the requirements of Statements on Auditing Standards issued by the American Institute of Certified Public Accountants (“SAS”), to the effect set forth in Annex VI to the Original Distribution Agreement; and

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(f) A certificate of the President or any Vice President of the Company, dated the Commencement Date, in form reasonably satisfactory to such Agents, (i) as to the accuracy of the representations and warranties of the Company herein at and as of the Commencement Date, (ii) as to the performance by the Company in all material respects of all of its obligations hereunder to be performed at or prior to the Commencement Date, (iii) as to the matters set forth in Section 1(e) hereof, (iv) as to the absence of any stop order of the Commission suspending the effectiveness of the Registration Statement or any pending or contemplated proceedings for such purpose, (v) as to the full force and effect of the authorizing order of the Oregon Public Utility Commission (the “OPUC”) referred to in Section 7(a) hereof, and (vi) as to such other matters as such Agents reasonably requested.

5. Covenants of the Company. The Company covenants and agrees with each Agent:

(a) (i) To make no amendment or supplement to the Registration Statement, the Prospectus or the Pricing Disclosure Package (other than a Pricing Supplement or a free-writing prospectus consisting of a Term Sheet) (A) prior to the Commencement Date, which any Agent shall reasonably disapprove by notice to the Company promptly after receipt of the proposed form thereof or (B) after the date of any agreement by an Agent, pursuant to a Terms Agreement or otherwise, to purchase Securities as principal and prior to the related Time of Delivery which such Agent shall reasonably disapprove by notice to the Company promptly after receipt of the proposed form thereof; (ii) to prepare, with respect to each particular issue of Securities to be sold through or to such Agent pursuant to this Agreement, a Terms Agreement or otherwise, a Pricing Supplement with respect to such Securities in a form reasonably satisfactory to such Agent and to file such Pricing Supplement in accordance with Rule 424(b) under the Act; (iii) to make no amendment or supplement to the Registration Statement, the Prospectus or the Pricing Disclosure Package, other than a Pricing Supplement or a free writing prospectus consisting of a Term Sheet, without affording such Agent a reasonable opportunity for review thereof and comment thereon; (iv) to timely file all reports and any definitive proxy or information statements required to be filed by the Company with the Commission pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act for so long as the delivery of a prospectus is required (or in lieu thereof the notice referred to in Rule 173(a) under the Act) in connection with the offering or sale of the Securities, and during such same period to advise such Agent, promptly after the Company receives notice thereof, of the time when any amendment to the Registration Statement has been filed or has become effective or any supplement to the Prospectus or the Pricing Disclosure Package or any amended Prospectus or Pricing Disclosure Package (other than any Pricing Supplement that relates to Securities not purchased through or by such Agent) has been filed with the Commission, of the issuance by the Commission of any stop

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order or of any order preventing or suspending the use of any prospectus relating to the Securities, of the suspension of the qualification of the Securities for offering or sale in any jurisdiction, of the initiation or threatening of any proceeding for any such purpose, or of any request by the Commission for the amendment or supplement of the Registration Statement or Prospectus or for additional information; (v) to promptly make every reasonable effort to comply with all requests of the Commission for additional information; and (vi) in the event of the issuance of any such stop order or of any such order preventing or suspending the use of any such prospectus or suspending any such qualification, to use its best efforts to obtain its withdrawal;

(b) From time-to-time, to take such action as such Agent reasonably may request to qualify the Securities for offering and sale under the securities laws of such jurisdictions as may be approved by the Company and to comply with such laws so as to permit the continuance of sales and dealings therein for as long as may be necessary to complete the distribution or sale of the Securities; provided, however, that in connection therewith the Company shall not be required to qualify as a foreign corporation or to file a general consent to service of process in any jurisdiction, or to comply with any other requirement reasonably deemed by the Company to be unduly burdensome; provided, further, that the provisions of this subsection (b) shall not apply so long as the Securities are “covered securities” within the meaning of Section 18 of the Act and any rules and regulations thereunder;

(c) To furnish such Agent with copies of the Registration Statement and each amendment thereto, the Prospectus and each amendment or supplement thereto, other than any Pricing Supplement (except as provided in the Administrative Procedure), in the form in which it is filed with the Commission pursuant to Rule 424(b) under the Act, and with copies of the documents incorporated by reference therein (other than exhibits incorporated by reference in the Registration Statement), each in such quantities as such Agent may reasonably request from time-to-time; and, if the delivery of a prospectus (or in lieu thereof the notice referred to in Rule 173(a) under the Act) is required at any time in connection with the offering or sale of the Securities to or through an Agent pursuant to this Agreement and if, at such time, any event shall have occurred as a result of which the Prospectus as then amended or supplemented or the Pricing Disclosure Package as then amended or supplemented, as the case may be, would include an untrue statement of a material fact or omit to state any material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading, or, if for any other reason it shall be necessary during such period to amend or supplement the Prospectus or the Pricing Disclosure Package or to file under the Exchange Act any document incorporated by reference in the Prospectus in order to comply with the Act, the Exchange Act or the Trust Indenture Act or to ensure that the information included in any free writing prospectus does not conflict with information contained in the Registration Statement or the Prospectus, to notify such Agent and request such Agent, in its capacity as agent of the Company, to suspend

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solicitation of offers to purchase Securities from the Company (and, if so notified, such Agent shall cease such solicitations as soon as practicable, but in any event not later than one business day later); and if the Company shall decide to amend or supplement the Registration Statement, the Prospectus or the Pricing Disclosure Package, to so advise such Agent promptly by telephone (confirmed in writing) and to prepare and cause to be filed promptly with the Commission an amendment or supplement to the Registration Statement, the Prospectus or the Pricing Disclosure Package or to file any document incorporated by reference in the Prospectus or the Pricing Disclosure Package that will correct such statement or omission or conflict or effect such compliance; provided that, (i) should such event relate solely to activities of any Agent (except any termination of any Agent’s services hereunder), such Agent shall assume the expense of preparing and furnishing any such amendment or supplement; (ii) if, during such period, such Agent shall continue to own Securities purchased from the Company as principal or such Agent otherwise shall be required to deliver a prospectus (or the notice referred to in Section 173(a) of the Act) in respect of transactions in the Securities, the Company shall promptly prepare and file with the Commission such an amendment or supplement; and (iii) if such Agent shall be required to deliver a prospectus (or the notice referred to in Section 173(a) of the Act) in connection with sales of any Securities purchased by it as principal at any time nine months or more after the date of such purchase and (A) there shall be, as a result of such purchase, no Securities remaining to be sold under the Registration Statement or (B) the Company, pursuant to Section 2(d) hereof, shall have instructed the Agents, during such nine month period, to suspend permanently the solicitation of offers to purchase the Securities, such Agent shall assume the expense of preparing and furnishing any such amendment or supplement in connection with the sales of any Securities purchased by such Agent as principal. (For the purposes of this Section 5(c), the Company shall be entitled to assume that a Prospectus shall no longer be required to be delivered under the Act from and after the date six months from the date of the purchase by an Agent as principal of the particular issuance of Securities to which it relates, unless it shall have received notice from such Agent to the contrary);

(d) To make generally available to its security holders as soon as practicable, but in any event not later than eighteen months after (i) the effective date of the Registration Statement, (ii) the effective date of each post-effective amendment to the Registration Statement, and (iii) the date of each filing by the Company with the Commission of an Annual Report on Form 10-K that is incorporated by reference in the Registration Statement, an earning statement of the Company and its subsidiaries (which need not be audited) in accordance with Section 11(a) of the Act and the rules and regulations of the Commission thereunder (including, at the option of the Company, Rule 158);

(e) For the period ending five years from the date any Securities are sold by the Company pursuant to an offer solicited by such Agent under this Agreement, to furnish to such Agent copies of all reports or other communications (financial or other) furnished to stockholders, and deliver to such Agent (i) as soon as they are

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available, copies of any reports and financial statements furnished to or filed with the Commission pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act, (ii) copies of all registration statements filed under the Act (other than those in respect of shareholder or employee plans), and (iii) such additional information concerning the business and financial condition of the Company as such Agent may from time to time reasonably request (such financial statements to be on a consolidated basis to the extent the accounts of the Company and its subsidiaries are consolidated in reports furnished to its stockholders generally or to the Commission);

(f) That, from the date of any Terms Agreement or other agreement with such Agent to purchase Securities as principal and to and including the earlier of (i) the termination of the trading restrictions for the Securities purchased thereunder, as notified to the Company by such Agent and (ii) the related Time of Delivery, the Company, without the prior written consent of such Agent, will not offer, sell, contract to sell or otherwise dispose of any debt securities of the Company in a public offering which both have a maturity of from nine months to 30 years and are substantially similar to the Securities;

(g) That each acceptance by the Company of an offer to purchase Securities procured by such Agent, as agent, and each agreement by the Company, pursuant to a Terms Agreement or otherwise, to sell Securities to such Agent, as principal, shall be deemed to be an affirmation to such Agent that the representations and warranties of the Company contained in or made pursuant to this Agreement are true and correct as of the date of such acceptance or agreement, as the case may be, as though made as of such date, and an undertaking that such representations and warranties will be true and correct as of the Settlement Date for the Securities relating to such acceptance or as of the Time of Delivery relating to such sale, as the case may be, as though made as of such date (except that such representations and warranties shall be deemed to relate to the Registration Statement and the Prospectus as amended and supplemented relating to such Securities);

(h) That, reasonably in advance of (i) each date as of which an Agent reasonably requests an opinion or opinions of Simpson Thacher & Bartlett LLP, counsel to the Agents, or other counsel to the Agents reasonably satisfactory to the Company, or (ii) each time that the Company sells Securities to such Agent as principal pursuant to a Terms Agreement or other agreement and such Agent requests an opinion or opinions by Simpson Thacher & Bartlett LLP, counsel to the Agents, or other counsel to the Agents reasonably satisfactory to the Company, the Company shall furnish to such counsel such papers and information as they may reasonably request to enable them to furnish to such Agent a letter in form reasonably satisfactory to such Agent, to the effect that such Agent may rely on the opinion of such counsel referred to in Section 4(a) hereof, to the same extent as though it was dated the date of such letter (except that the statements in such opinion shall be deemed to relate to the Registration Statement and the Prospectus as amended and supplemented to the date of such letter and, if such letter is being furnished in connection with clause (ii) above, the applicable

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Pricing Disclosure Package), or in lieu of such a letter, an opinion of the same tenor as the opinion of such counsel referred to in Section 4(a) hereof, but modified to relate to the Registration Statement and the Prospectus as amended and supplemented to such date and the Pricing Disclosure Package, if applicable;

(i) That each time that (x) the Registration Statement, the Prospectus or the Pricing Disclosure Package shall be amended or supplemented (other than by a Term Sheet, other free writing prospectus or Pricing Supplement related to the Securities or by an amendment or supplement providing solely for a change in the interest rates of the Securities or similar changes and, unless the Agents shall otherwise specify, other than by an amendment or supplement which relates exclusively to an offering of debt securities other than the Securities), (y) a document incorporated by reference in the Prospectus as amended or supplemented (other than a Current Report on Form 8-K, unless the Agents shall otherwise specify) shall be filed under the Act or Exchange Act (unless waived by the Agents), or (z) the Company sells Securities to such Agent, as principal, pursuant to a Terms Agreement or other agreement and such Terms Agreement or other agreement specifies the delivery of an opinion, letter or certificate under this Section 5(i) as a condition to the purchase of Securities pursuant to such Terms Agreement or other agreement, the Company shall furnish or cause to be furnished to such Agent:

(i) a letter from C.J. Rue, Esq., counsel for the Company, or other counsel for the Company reasonably satisfactory to such Agent, dated the date of such amendment, supplement, incorporation or Time of Delivery relating to such sale, as the case may be, in form reasonably satisfactory to such Agent, to the effect that such Agent may rely on the opinion of such counsel referred to in Section 4(b) hereof (which letter shall reflect any modifications to the opinion delivered at the Commencement Date which are reflected in the opinion attached as Annex III hereto) to the same extent as though it were dated the date of such letter (except that the statements in such opinion shall be deemed to relate to the Registration Statement and the Prospectus as amended and supplemented to the date of such letter, excluding, in the case of the statements in the paragraph next following paragraph 14 of such opinion, all documents filed by the Company under the Exchange Act and incorporated by reference into the Registration Statement and Prospectus during or prior to the fiscal year which is the subject of the Company’s most recent Annual Report on Form 10-K) or, in lieu of such a letter, an opinion of the same tenor as the opinion of such counsel referred to in Section 4(b) hereof (which opinion shall reflect any modifications to the opinion delivered at the Commencement Date which are reflected in the opinion attached as Annex III hereto), but modified to relate to the Registration Statement and the Prospectus as so amended and supplemented to such date (provided that if such letter or opinion is being furnished pursuant to clause (z) above, it shall also address the applicable Pricing Disclosure Package);

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(ii) a letter of Thelen Reid Brown Raysman & Steiner LLP, New York, New York, counsel for the Company, or other counsel for the Company reasonably satisfactory to such Agent, dated the date of such amendment, supplement, incorporation or Time of Delivery relating to such sale, as the case may be, in form reasonably satisfactory to such Agent, to the effect that such Agent may rely on the opinion of such counsel referred to in Section 4(c) hereof (which letter shall reflect any modifications to the opinion delivered at the Commencement Date which are reflected in the opinion attached as Annex IV hereto) to the same extent as though it were dated the date of such letter (except that the statements in such opinion shall be deemed to relate to the Registration Statement and the Prospectus as amended and supplemented to the date of such letter, excluding, in the case of the statements in the paragraph next following paragraph 10 of such opinion, all documents filed by the Company under the Exchange Act and incorporated by reference into the Registration Statement and the Prospectus during or prior to the fiscal year which is the subject of the Company’s most recent Annual Report on Form 10-K) or, in lieu of such letter, an opinion of the same tenor as the opinion of such counsel referred to in Section 4(c) hereof (which opinion shall reflect any modifications to the opinion delivered at the Commencement Date which are reflected in the opinion attached as Annex IV hereto), but modified to relate to the Registration Statement and the Prospectus as so amended and supplemented to such date (provided that if such letter or opinion is being furnished pursuant to clause (z) above, it shall also address the applicable Pricing Disclosure Package);

(iii) a letter of Stoel Rives LLP, Portland, Oregon, special Washington counsel for the Company, or other special Washington counsel for the Company reasonably satisfactory to such Agent, dated the date of such amendment, supplement, incorporation or Time of Delivery relating to such sale, as the case may be, in form reasonably satisfactory to such Agent, to the effect that such Agent may rely on the opinions of such counsel referred to in Sections 4(d) (which letter shall reflect any modifications to the opinion delivered at the Commencement Date which are reflected in the opinion attached as Annex V hereto) and 5(n) hereof to the same extent as though they were dated the date of such letter or, in lieu of such letter, an opinion of the same tenor as the opinions of such counsel referred to in Sections 4(d) (which opinion shall reflect any modifications to the opinion delivered at the Commencement Date which are reflected in the opinion attached as Annex V hereto) and 5(n) hereof; and

(iv) a certificate executed by the President or any Vice President of the Company, dated the date of such supplement, amendment, incorporation or Time of Delivery relating to such sale, as the case may be, in such form as shall be reasonably satisfactory to such Agent, to the effect that the statements contained in the certificate referred to in Section 4(f) hereof are true and correct at such date as though made as of such date (except that

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such statements shall be deemed to relate to the Registration Statement and the Prospectus as amended and supplemented to such date and, if such certificate is being furnished pursuant to clause (z) above, the applicable Pricing Disclosure Package) or, in lieu of such certificate, a certificate of the same tenor as the certificate referred to in Section 4(f) hereof, but modified to relate to the Registration Statement and the Prospectus as amended and supplemented to such date and the Pricing Disclosure Package, if applicable;

(j) That each time that (x) the Registration Statement, the Prospectus or the Pricing Disclosure Package shall be amended or supplemented to include additional financial information (unless waived by the Agents), or (y) the Company sells Securities to such Agent as principal pursuant to a Terms Agreement or other agreement and such Terms Agreement or other agreement specifies the delivery of a letter under this Section 5(j) as a condition to the purchase of Securities pursuant to such Terms Agreement or other agreement, and subject to compliance with the requirements of SAS issued by the American Institute of Certified Public Accountants, the Company shall furnish or cause to be furnished to such Agent a letter of PricewaterhouseCoopers LLP or other independent registered public accounting firm for the Company reasonably satisfactory to the Agent, dated the date of such amendment, supplement, incorporation or Time of Delivery relating to such sale, as the case may be, in form reasonably satisfactory to such Agent, to the effect that such Agent may rely upon the letter of such accountants referred to in Section 4(e) hereof to the same extent as though it were dated the date of such subsequent letter (except the statements in such former letter shall be deemed to relate to the financial statements included or incorporated in the Registration Statement and Prospectus as amended and supplemented to the date of such latter letter and the Pricing Disclosure Package, if applicable), or, in lieu of such latter letter, a letter of the same tenor as the letter referred to in Section 4(e) hereof, but modified to relate to the Registration Statement and the Prospectus as amended or supplemented to the date of such letter and the Pricing Disclosure Package, if applicable, with such changes as may be necessary to reflect changes in the financial statements and other information derived from the accounting records of the Company, to the extent such financial statements and other information are available as of a date not more than five business days prior to the date of such letter;

(k) To offer to any person who has agreed to purchase Securities as the result of an offer to purchase solicited by such Agent, as agent, the right to refuse to purchase and pay for such Securities if, at the Settlement Date for such Securities, any condition set forth in Section 6 hereof shall not have been satisfied (it being understood that the judgment of such person with respect to the impracticability or inadvisability of such purchase of Securities shall be substituted, for purposes of this Section 5(k), for the judgment of such Agent with respect thereto);

(l) To pay or cause to be paid the following: (i) the fees and expenses of the Company’s counsel and accountants in connection with the registration of the

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Securities under the Act and all other expenses in connection with the preparation, printing and filing of the Registration Statement, any Preliminary Prospectus, the Prospectus, each Pricing Disclosure Package, any free writing prospectus prepared by or on behalf of, used by, or referred to by the Company and any Pricing Supplements and all other amendments and supplements thereto and the mailing and delivering of copies thereof to such Agent; (ii) the fees and expenses of counsel for the Agents in connection with the establishment and update of the program contemplated hereby, any opinions to be rendered by such counsel hereunder and the transactions contemplated hereunder; (iii) the cost of preparing this Agreement, any Terms Agreement and any other documents approved by the Company in connection with the offering, purchase, sale and delivery of the Securities; (iv) the fees, not to exceed $5,000, and expenses of counsel for the Agents in connection with the qualification of the Securities for offering and sale under state securities laws as provided in Section 5(b) hereof and the preparation of any blue sky and legal investment memoranda; (v) any fees charged by securities rating services for rating the Securities; (vi) any filing fees incident to any required review by the National Association of Securities Dealers, Inc. of the terms of the sale of the Securities; (vii) the cost of preparing the Securities; (viii) the fees and expenses of the Trustees and any agent of any Trustee and any transfer or paying agent of the Company and the fees and disbursements of counsel for any Trustee or any such agent in connection with any Indenture and the Securities; (ix) any advertising expenses connected with the solicitation of offers to purchase and the sale of Securities so long as such advertising expenses have been approved by the Company; and (x) all other costs and expenses incident to the performance of the Company’s obligations hereunder which are not otherwise specifically provided for in this Section; provided, however, that, except as provided in Sections 8 and 9 hereof, such Agent shall pay all other expenses it incurs, including any expenses that may be incurred by it or for its account pursuant to the proviso of Section 5(c) hereof;

(m) To advise each Agent, promptly after the Company receives notice thereof, of the downgrading, or the issuance of a notice of any intended or potential downgrading, of the ratings of the Securities by either Moody’s Investors Service or Standard & Poor’s Rating Services;

(n) That prior to the solicitation of offers to purchase any Securities, and the issuance and sale of such Securities, the Company will obtain from the Washington Utilities and Transportation Commission (the “WUTC”) one or more orders establishing compliance with the public utility laws of the State of Washington in respect of the issuance and sale of all such Securities in accordance with the terms and conditions of this Agreement, and the Company shall furnish or cause to be furnished to each Agent and Agents’ counsel:

(i) a copy of such order or orders;

(ii) a certificate of the President or any Vice President of the Company dated on or after the date of each such order, as to the full force and effect of

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each such order and representing and warranting that, in respect of the portion of the Securities to which such order or orders pertain, no further consent, approval, authorization or order of the WUTC is required for the solicitation of offers to purchase Securities and the issuance and sale of the Securities or the consummation by the Company of the other transactions contemplated by the Indentures, this Agreement or any Terms Agreement in the manner contemplated by such order or orders; and

(iii) a letter of Stoel Rives LLP, Portland, Oregon, special Washington counsel for the Company, or other special Washington counsel for the Company reasonably satisfactory to such Agent, dated on or after the date of each such order, in form and substance reasonably satisfactory to such Agent, to the effect set forth in Annex VII hereto;

(o) If all of the Securities registered pursuant to the Registration Statement being offered pursuant to this Agreement have not been sold prior to December 1, 2008, prior to such date the Company will file a new shelf registration statement and take any other action necessary to permit the public offering of the Securities to continue without interruption. If such new registration statement is an automatic shelf registration statement as defined in Rule 405 under the Act, the Company will be a well-known seasoned issuer (as defined in Rule 405 under the Act) eligible to use the registration statement as an automatic shelf registration statement and the Company will not have received notice that the Commission objects to the use of the registration statement as an automatic shelf registration statement. References in this Agreement to the Registration Statement shall include any such new registration statement after it becomes effective;

(p) Unless otherwise agreed to by the Company and such Agent, to prepare a Term Sheet relating to each offering of the Securities hereunder containing information that describes the final terms of the Securities being offered, in the form attached hereto as Annex VIII or as otherwise agreed to by the Company and such Agent and to file such Term Sheet within the period required by Rule 433(d)(5)(ii) under the Act following the date the final terms have been established; and

(q) To file promptly all material required to be filed by the Company with the Commission pursuant to Rule 433(d) under the Act.

6. Conditions to Agents’ Obligations. The obligation of an Agent, as agent of the Company, at any time (each a “Solicitation Time”), to solicit offers to purchase the Securities and the obligation of an Agent to purchase Securities as principal, pursuant to a Terms Agreement or otherwise, shall be subject, in such Agent’s discretion, to the conditions that:

(a) all of the representations and warranties of the Company herein (and, in the case of an obligation of an Agent under a Terms Agreement or other agreement with an Agent to purchase Securities as principal, in or incorporated in such agreement by reference) were true and correct (i) on the Commencement Date; (ii) each time that the Registration Statement or the Prospectus shall be amended or

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supplemented, (iii) each time a document incorporated by reference in the Prospectus as amended or supplemented shall be filed by the Company under the Act or Exchange Act, (iv) at each Applicable Time, (v) at each Settlement Date, and (vi) at each Time of Delivery of Securities so to be purchased by such Agent, as principal, as the case may be,

(b) prior to such Solicitation Time or such Time of Delivery, as the case may be, the Company shall have performed all of its obligations hereunder theretofore to be performed,

(c) all requests for additional information on the part of the Commission shall have been complied with to the reasonable satisfaction of such Agent,

(d) there shall be in full force and effect orders of the OPUC and the WUTC which permit the issuance and sale of the Securities in accordance with the terms and conditions of this Agreement,

(e) no stop order suspending the effectiveness of the Registration Statement shall have been issued and no proceedings for that purpose shall be pending before, or to the knowledge of the Company contemplated by, the Commission, and

(f) there shall not have occurred: (i) a suspension or material limitation of trading in securities generally on the New York Stock Exchange or in any securities of the Company on the New York Stock Exchange or any relevant exchange or a material disruption in securities settlement or clearance services in the United States; (ii) a general moratorium on commercial banking activities in New York declared by either Federal or New York State authorities; (iii) any material adverse change in the financial markets in the United States, any outbreak of hostilities or escalation thereof or other calamity or crisis or material adverse change in national financial or economic conditions, in each case, the effect of which, in the reasonable judgment of such Agent, makes it impracticable or inadvisable to proceed with the solicitation of offers to purchase Securities or the purchase of Securities from the Company as principal on the terms and in the manner contemplated by this Agreement and, if applicable, any Terms Agreement or other agreement; or (iv) unless known to such Agent prior to such Solicitation Time, any downgrading, or any notice shall have been given of any intended or potential downgrading, of the Securities by either Moody’s Investors Service or Standard & Poor’s Rating Services.

In addition to the foregoing, the obligation of an Agent to purchase Securities as principal, pursuant to a Terms Agreement or other agreement, shall be subject, in such Agent’s discretion, to the further condition that there shall not have been, since the date of such Terms Agreement or other agreement or since the respective dates as of which information is given in the Registration Statement, any material adverse change in the condition, financial or otherwise, or in the earnings, business affairs or business prospects of the Company and its subsidiaries considered as one enterprise, whether or not arising in the ordinary course of business.

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7. Conditions to Company’s Obligations.

(a) The obligation of the Company to sell and deliver any Security pursuant hereto, to a Terms Agreement or otherwise shall be subject to the condition that, after the acceptance by the Company of an offer to purchase such Security procured by an Agent, as agent, or the agreement by the Company, pursuant to a Terms Agreement or otherwise, to sell such Security to an Agent, as principal, and prior to the Time of Delivery or the Settlement Date, as the case may be, with respect to such purchase or sale, neither the OPUC nor the WUTC shall have issued an order revoking its then existing order or orders permitting the issuance and sale of the Securities through each Agent, as agent, on the terms set forth herein or to each Agent, as principal, pursuant to a Terms Agreement or other agreement.

(b) If the condition specified in Section 7(a) hereof shall not have been fulfilled, the obligation of the Company to sell Securities hereunder or under a Terms Agreement or other agreement may be terminated by the Company; and neither the Company nor any Agent shall have any liability to the other, except for (i) the obligation of the Company to pay certain expenses to the extent provided for in Section 5(l) hereof, (ii) the obligation of the Company to pay commissions and hold the Agents harmless as provided in Section 9 hereof (and, for purposes of said Section 9, such a failure of such condition to be fulfilled shall be considered a default by the Company on its obligation to deliver such Securities), and (iii) any liability under Section 8 hereof.

8. Indemnification.

(a) The Company will indemnify and hold harmless each Agent against any losses, claims, damages or liabilities, joint or several, to which such Agent may become subject, under the Act or otherwise, insofar as such losses, claims, damages or liabilities or actions in respect thereof arise out of or are based upon an untrue statement or alleged untrue statement of a material fact contained in the Registration Statement, any Preliminary Prospectus, the Prospectus, the Prospectus as amended or supplemented, any Pricing Disclosure Package, any Issuer Free Writing Prospectus (as defined in Rule 433(h)) or arise out of or are based upon the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading, and will reimburse such Agent for any legal or other expenses reasonably incurred by it, as incurred, in connection with investigating or defending any such loss, claim, damage, liability or action; provided, however, that the Company shall not be liable in any such case to the extent that any such loss, claim, damage or liability or action in respect thereof arises out of or is based upon an untrue statement or alleged untrue statement or omission or alleged omission made in the Registration Statement, any Preliminary Prospectus, the Prospectus, the Prospectus as amended or supplemented, any Pricing Disclosure Package or any Issuer Free Writing Prospectus in reliance upon and in conformity with written information furnished to the Company by such Agent specifically for use therein.

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(b) Each Agent will indemnify and hold harmless the Company against any losses, claims, damages or liabilities to which the Company may become subject, under the Act or otherwise, insofar as such losses, claims, damages or liabilities or actions in respect thereof arise out of or are based upon an untrue statement or alleged untrue statement of a material fact contained in the Registration Statement, any Preliminary Prospectus, the Prospectus, the Prospectus as amended or supplemented, any Pricing Disclosure Package or any Issuer Free Writing Prospectus, or arise out of or are based upon the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading, in each case to the extent, but only to the extent, that such untrue statement or alleged untrue statement or omission or alleged omission was made in the Registration Statement, any Preliminary Prospectus, the Prospectus, the Prospectus as amended or supplemented, any Pricing Disclosure Package or any Issuer Free Writing Prospectus in reliance upon and in conformity with written information furnished to the Company by such Agent specifically for use therein, and will reimburse the Company for any legal or other expenses incurred by the Company, as incurred, in connection with investigating or defending any such loss, claim, damage or liability or action. Each Agent hereby furnishes to the Company in writing expressly for use in the Registration Statement, any Preliminary Prospectus, the Prospectus and the Prospectus as amended or supplemented (i) the first sentence in the fifth paragraph on the cover page of the Prospectus relating to the offerings of Medium-Term Notes by the Agents, as principal, and (ii) under “Plan of Distribution,” the second and third paragraphs, the third and last sentences of the seventh paragraph, the eighth, ninth, tenth and eleventh paragraphs and the statements relating to the Agents in the twelfth paragraph.

(c) Promptly after receipt by an indemnified party under Section 8(a) or Section 8(b) of notice of the commencement of any action, such indemnified party shall, if a claim in respect thereof is to be made against the indemnifying party under such Section, notify the indemnifying party in writing of the commencement thereof; but the omission so to notify the indemnifying party shall not relieve it from any liability which it may have to any indemnified party otherwise than under such Section. In case any such action shall be brought against any indemnified party and it shall notify the indemnifying party of the commencement thereof, the indemnifying party shall be entitled to participate therein and, to the extent that it shall wish, jointly with any other indemnifying party similarly notified, to assume the defense thereof, with counsel satisfactory to such indemnified party (who shall not, except with the consent of the indemnified party, be counsel to the indemnifying party); provided, however, in no event shall such indemnifying parties be obligated to retain more than one counsel (and necessary local counsel), in addition to counsel for such indemnifying parties, to represent the indemnified parties, and after notice from the indemnifying party to such indemnified party of its election so to assume the defense thereof, the indemnifying party shall not be liable to such indemnified party under such Section for any legal expenses of other counsel or any other expenses, in each case subsequently incurred by such indemnified party, in connection with the defense thereof other than reasonable

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costs of investigation. Each indemnified party may also participate at its own expense in the defense of any such action. No indemnifying party shall, without the prior written consent of the indemnified party, effect any settlement of any pending or threatened proceeding in respect of which any indemnified party is or could have been a party and indemnity could have been sought hereunder by such indemnified party, unless such settlement includes (i) an unconditional release of such indemnified party from all liability on claims that are the subject matter of such proceeding and (ii) no statement as to or an admission of fault, culpability or failure to act by or on behalf of an indemnified party.

(d) If the indemnification provided for in Section 8(a) or Section 8(b) hereof is unavailable or insufficient to hold harmless an indemnified party in respect of any losses, claims, damages or liabilities (or actions in respect thereof) referred to therein, then each indemnifying party shall contribute to the amount paid or payable by such indemnified party as a result of such losses, claims, damages or liabilities (or actions in respect thereof) in such proportion as is appropriate to reflect any relevant equitable considerations including the relative fault of the Company on the one hand and each Agent on the other in connection with the statements or omissions which resulted in such losses, claims, damages or liabilities (or actions in respect thereof), and relative benefit of the Company on the one hand and each Agent on the other. Relative fault shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact required to be stated therein or necessary in order to make the statements therein not misleading relates to information supplied by the Company on the one hand or by any Agent on the other and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission. The relative benefits received by the Company on the one hand and each Agent on the other shall be deemed to be in the same proportion as the total net proceeds from the sale of Securities (before deducting expenses) received by the Company bear to the total commissions or discounts received by such Agent in respect thereof. The Company and each Agent agree that it would not be just and equitable if contribution pursuant to this Section 8(d) were determined (i) with respect only to any losses, claims, damages or liabilities referred to in Section 8(a) hereof, by per capita allocation (even if all Agents were treated as one entity for such purpose) or (ii) by any method of allocation which does not take account of the equitable considerations referred to above in this Section 8(d). The amount paid or payable by an indemnified party as a result of the losses, claims, damages or liabilities (or actions in respect thereof) referred to above in this Section 8(d) shall be deemed to include any legal or other expenses reasonably incurred by such indemnified party in connection with investigating or defending any such action or claim. Notwithstanding the provisions of this Section 8(d), no Agent shall be required to contribute any amount which exceeds the total price at which the Securities purchased by or through it were offered by it to the public less the amount of any damages which it shall have otherwise paid or become liable to pay by reason or any untrue or alleged untrue statement or omission or alleged omission. No person guilty of fraudulent misrepresentation (within the meaning

22

of Section 11(f) of the Act) shall be entitled to contribution from any person who was not guilty of such fraudulent misrepresentation. The obligations of each of the Agents under this Section 8(d) to contribute are several and are not joint.

(e) The obligations of the Company under this Section 8 shall be in addition to any liability which the Company may otherwise have and shall extend, upon the same terms and conditions, to each person, if any, who controls any Agent within the meaning of the Act. The obligations of each Agent under this Section 8 shall be in addition to any liability which such Agent may otherwise have and shall extend, upon the same terms and conditions, to each director of the Company, to each officer of the Company who has signed the Registration Statement and to each person, if any, who controls the Company within the meaning of the Act.

9. Nonperformance. Each Agent, in soliciting offers to purchase Securities from the Company and in performing the other obligations of such Agent hereunder (other than in respect of any purchase by an Agent as principal pursuant to a Terms Agreement or otherwise), is acting solely as agent for the Company and not as principal. Each Agent will make reasonable efforts to assist the Company in obtaining performance by each purchaser whose offer to purchase Securities from the Company was solicited by such Agent and has been accepted by the Company, but such Agent shall not have any liability to the Company in the event such purchase is not consummated for any reason. If the Company shall default on its obligation to deliver Securities to a purchaser whose offer it has accepted, the Company shall (i) hold each Agent harmless against any loss, claim or damage arising from or as a result of such default by the Company and (ii) notwithstanding such default, pay to the Agent that solicited such offer any commission to which it would be entitled in connection with such sale.

10. Survival of Agreement. The respective indemnities, agreements, representations, warranties and other statements by any Agent and the Company set forth in or made pursuant to this Agreement shall remain in full force and effect regardless of any investigation (or any statement as to the results thereof) made by or on behalf of any Agent or any controlling person of any Agent or the Company, or any officer or director or any controlling person of the Company, and shall survive each delivery of and payment for any of the Securities.

11. Suspension or Termination. The provisions of this Agreement relating to the solicitation of offers to purchase Securities from the Company may be suspended or terminated at any time by the Company as to any Agent or by any Agent as to such Agent upon the giving of written notice of such suspension or termination to such Agent or the Company, as the case may be. In the event of such suspension or termination with respect to any Agent, this Agreement shall remain in full force and effect with respect to (i) any Agent as to which such suspension or termination has not occurred, (ii) the rights and obligations of any party which have previously accrued or which relate to Securities which are already issued, agreed to be issued or the subject of a pending offer at the time of such suspension or termination, (iii) Sections 2(e), 5(d), 5(e), 5(l), 8, 9 and 10 hereof, and (iv) the obligations of the Company to amend or supplement the Prospectus, so long as any Agent continues to hold Securities as principal.

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12. Notices. Except as otherwise specifically provided herein or in the Administrative Procedure, all statements, requests, notices and advices hereunder shall be in writing or by telephone, if promptly confirmed in writing, and if to Merrill Lynch, Pierce, Fenner & Smith Incorporated, shall be sufficient in all respects when delivered or sent by facsimile transmission or registered mail to 4 World Financial Center, 15th Floor, New York, New York 10080, Attention: MTN Product Management, Facsimile Transmission No. 212-449-2234, Telephone No. 212-449-7476, if to UBS Securities LLC, shall be sufficient in all respects when delivered or sent by facsimile transmission or registered mail to 677 Washington Blvd., Stamford, Connecticut 06901, Facsimile Transmission No. 203-719-0495, Attention: Fixed Income Syndicate, if to J.P. Morgan Securities Inc., shall be sufficient in all respects when delivered or sent by facsimile transmission or registered mail to 270 Park Avenue, 8th Floor, New York, New York 10017, Facsimile Transmission No. 212-834-6081, Attention: Medium Term Notes Desk and if to Piper Jaffray & Co., shall be sufficient in all respects when delivered or sent by facsimile transmission or registered mail to 800 Nicollet Mall, Minneapolis, Minnesota 55402, Facsimile Transmission No. 612-313-3117, Telephone No: 612-303-1824, Attention: Debt Capital Markets; if to the Company, shall be sufficient in all respects when delivered or sent by facsimile transmission or registered mail to One Pacific Square, 220 N.W. Second Avenue, Portland, Oregon 97209, Attention: Chief Financial Officer, with a copy to the General Counsel, Facsimile Transmission No. 503-220-2584, Telephone No. 503-220-2406; and if to any additional Agent, as set forth in the Additional Agent Appointment Agreement relating to such Agent.

13. Benefit of Agreement. This Agreement, any Additional Agent Appointment Agreement and any Terms Agreement shall be binding upon, and inure solely to the benefit of, each Agent which is a party hereto and thereto and the Company, and to the extent provided in Section 8 and Section 10 hereof, the officers and directors of the Company and any person who controls any Agent or the Company, and their respective personal representatives, successors and assigns, and no other person shall acquire or have any right under or by virtue of this Agreement, any Additional Agent Appointment Agreement or any Terms Agreement. No purchaser of any of the Securities through or from any Agent hereunder shall be deemed a successor or assign by reason of such purchase.

14. Timing. Time shall be of the essence in this Agreement, any Additional Agent Appointment Agreement and any Terms Agreement. As used herein, the term “business day” shall mean any day when banks in New York City are not authorized or obligated by law or executive order to remain closed.

15. Governing Law. This Agreement, any Additional Agent Appointment Agreement and any Terms Agreement shall be governed by and construed in accordance with the laws of the State of New York.

16. Descriptive Headings. The descriptive headings of the several paragraphs of this Agreement are inserted for convenience only and do not constitute a part of this Agreement.

17. Relationship. The Company acknowledges and agrees that the Agents are acting solely in the capacity of arm’s length contractual counterparties to the Company with

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respect to the offering of the Securities as contemplated by this Agreement and not as financial advisors or fiduciaries to the Company in connection herewith. Additionally, none of the Agents is advising the Company as to any legal, tax, investment, accounting or regulatory matters in any jurisdiction in connection with the offering of the Securities as contemplated by this Agreement. Any review by the Agents of the Company in connection with the offering of the Securities contemplated by this Agreement and the transactions contemplated by this Agreement will not be performed on behalf of the Company.

18. Execution in Counterparts. This Agreement, any Additional Agent Appointment Agreement and any Terms Agreement may be executed by any one or more of the parties hereto and thereto in any number of counterparts, each of which shall be an original, but all of such respective counterparts shall together constitute one and the same instrument.

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If the foregoing is in accordance with your understanding, please sign and return to us three counterparts hereof, whereupon this letter and the acceptance by each of you hereof shall constitute a binding agreement between the Company and each of you in accordance with its terms.

Very truly yours,

NORTHWEST NATURAL GAS COMPANY

By:

Title:

Accepted as of the date hereof:

MERRILL LYNCH, PIERCE, FENNER & SMITH

INCORPORATED

By:

Title:

UBS SECURITIES LLC

By:

Title:

By:

Title:

J.P. MORGAN SECURITIES INC.

By:

Title:

PIPER JAFFRAY & CO.

By:

Title:

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ANNEX I

Northwest Natural Gas Company

Administrative Procedure

This Administrative Procedure relates to the Securities defined in the Distribution Agreement, dated September 28, 2004, amended and restated on December 7, 2006 (the “Distribution Agreement”), amongst Northwest Natural Gas Company (the “Company”), on the one hand, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, UBS Securities LLC, J.P. Morgan Securities Inc., Piper Jaffray & Co. and each other person which shall become a party thereto (each, an “Agent” and, together, the “Agents”), on the other. Defined terms used herein and not defined herein shall have the meanings given such terms in the Distribution Agreement or the Indentures. An Agent, in relation to a purchase of a Security by a purchaser solicited by such Agent, is referred to herein as the “Selling Agent” and, in relation to a purchase of a Security by such Agent as principal other than pursuant to a Terms Agreement, as the “Purchasing Agent”. As used herein, the term “business day” shall mean any day when banks in New York City are not authorized or obligated by law or executive order to remain closed.

The procedures to be followed with respect to the settlement of sales of Securities directly by the Company to purchasers solicited by an Agent, as agent, are set forth below. The terms and settlement details related to a purchase of Securities by an Agent, as principal, from the Company will be set forth in a Terms Agreement, pursuant to the Distribution Agreement, unless the Company and such Agent otherwise shall agree.

The Company will advise each Agent in writing of those persons with whom such Agent is to communicate regarding offers to purchase Securities and the related settlement details.

Order No. 04 248 dated May 11, 2004, of the Oregon Public Utility Commission (the “OPUC”) authorizes the issuance and sale of the Securities, subject to the conditions set forth in such order. In addition, such order of the OPUC authorizes the issuance and sale by the Company (i) only of Securities bearing interest at fixed rates, established within the maximum all-in spreads over Benchmark Treasury Yields for various maturities (determined in accordance with said orders as of the time the commitment to purchase any Securities is received by the Company and the Agent) and (ii) of Securities to Agents, as principal, at 100% of the principal amount thereof less a percentage not to exceed the commission applicable to an agency sale of Securities of the same maturity. Prior to the solicitation of offers to purchase any Securities, and the issuance and sale of such Securities, the Company will obtain one or more orders of the Washington Utilities and Transportation Commission (the “WUTC”) establishing compliance with applicable statutory provisions with respect to the issuance and sale of such Securities and establishing conditions with respect thereto.

As stated in the Company’s Prospectus Supplement dated September 28, 2004 and the accompanying Prospectus dated February 18, 2004, if the terms of any Security, as determined by the Company, provide that such Security will be redeemable at the option of the Company, such Security will be made redeemable in whole or in part.

Procedure for Rate Changes:

When a decision has been reached to change the interest rate on or other variable terms with respect to any Securities being offered for sale, the Company will promptly advise the Agents and the Agents will forthwith suspend solicitation of offers to purchase such Securities. The Agent will telephone the Company with recommendations as to the changed interest rates or other variable terms. At such time as the Company advises the Agents of the new interest rates or other variable terms, the Agent may resume solicitation of offers to purchase such Securities. Until such time only “indications of interest” may be recorded.

Acceptance or Rejection of Offers by Company:

Each Agent will promptly advise the Company by telephone or other appropriate means of all reasonable offers to purchase Securities, other than those rejected by such Agent. Each Agent, in its discretion reasonably exercised, may reject any offer received by it, in whole or in part. Each Agent also may make offers to the Company to purchase Securities as a Purchasing Agent. The Company, in its sole discretion, may accept any offer to purchase Securities and may reject any such offer, in whole or in part.

The Company will promptly notify the Selling Agent or Purchasing Agent, as the case may be, of its acceptance or rejection of an offer to purchase Securities. If the Company accepts an offer to purchase Securities, it will confirm such acceptance in writing to the Selling Agent or Purchasing Agent, as the case may be.

Settlement:

The receipt of immediately available funds by the Company in payment for a Security and the authentication and delivery of such Security will, with respect to such Security, constitute “Settlement.”

All offers solicited by a Selling Agent or made by a Purchasing Agent and accepted by the Company will be settled on a date (the “Settlement Date”) which shall be the third business day after the date of acceptance of such offer, unless the Company and the purchaser shall agree to settle (a) on any other business day after the acceptance of such offer or (b) with respect to an offer accepted by the Company prior to 10:00 a.m., New York City time, on the date of such acceptance.

Settlement Procedures:

A. After the acceptance of an offer by the Company, the Selling Agent or Purchasing Agent, as the case may be, will communicate the following details of the terms of such offer (the “Sale Information”) to the Company by telephone (confirmed in writing) or by facsimile transmission or other acceptable written means:

(1) Principal amount of Securities to be purchased;

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(2) Issue Price (“Issue Price” shall mean (i) in the case of a sale in which an Agent shall act as a Selling Agent, the price to the purchaser or (ii) in the case of a sale to an Agent as Purchasing Agent, that Purchasing Agent’s reoffering price);

(3) Selling Agent’s commission or, if applicable, Purchasing Agent’s discount (spread between the reoffering price and Purchasing Agent’s purchase price);

(4) Net proceeds to the Company: (2) minus (3);

(5) Method of and specified funds for payment of purchase price;

(6)	(a)	Fixed Rate Securities:
		(i)	interest rate
		(ii)	interest payment dates
		(iii)	regular record dates;
	(b)	Floating Rate Securities:
		(i)	interest rate basis
		(ii)	initial interest rate
		(iii)	spread or spread multiplier, if any
		(iv)	interest rate reset dates
		(v)	interest rate reset period
		(vi)	interest payment dates
		(vii)	initial interest payment date
		(viii)	interest payment period
		(ix)	regular record dates
		(x)	index maturity
		(xi)	calculation agent
		(xii)	maximum and minimum interest rates, if any
		(xiii)	calculation date
		(xiv)	interest determination dates;
(7)	(a)	Trade Date;
	(b)	Interest Commencement Date (Settlement Date unless otherwise noted; “Issue Date” on Secured Notes);
	(c)	Time of delivery;
(8)	Closing location;
(9)	Maturity date;
(10)	If redeemable at the Company’s option:
	(a)	whether redeemable (i) in whole or (ii) in whole or in part;

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	(b)	whether redeemable at (i) fixed redemption prices or (ii) a make-whole redemption price;
	(c)	if redeemable at fixed redemption prices:
		(i)	initial redemption date
		(ii)	redemption limitation date
		(iii)	each redemption price and period;
	(d)	if redeemable at a make-whole redemption price, the make-whole spread;
(11)	Sinking fund or other retirement provisions;
(12)	If repayable at the holder’s option:
	(a)	repayment date;
	(b)	repayment price;
	(c)	election period;
(13)	The name of the Selling Agent or Purchasing Agent, as the case may be;
(14)	Exact name, address and taxpayer identification number of party to be the registered owner;
(15)	Party to whom Securities are to be delivered;
(16)	Denominations of certificates to be delivered at settlement;
(17)	The name of the Company’s bank and the account number for payment of the purchase price;
(18)	Whether the Securities to be purchased are Secured Notes or Unsecured Notes;
(19)	Any other significant terms of the Securities or their offer or sale.

B. After receiving such settlement information from the Agent, the Company will advise the Trustee of the above settlement information. The Company will prepare a Pricing Supplement to the Prospectus and deliver copies to the Agent and will cause the Trustee to issue, authenticate and deliver Securities.

If an identical Pricing Supplement has not been previously filed with the Securities and Exchange Commission (the “SEC”), the Company will arrange to have transmitted promptly via EDGAR one copy of the Pricing Supplement (with the appropriate paragraph under Rule 424(b) and the Registration No. inscribed in the upper right corner) to the SEC, within the applicable time period provided in Rule 424(b).

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One copy of the Pricing Supplement (with a copy of the cover letter sent to the SEC if a filing with the SEC is required) will be sent by facsimile to the Agents involved in such issue as soon as practicable but in no event later than 12:00 noon on the second day after the Trade Date at each of the following numbers:

ADP IDS

1155 Long Island Ave.

Edgewood, New York 11717

Attn: Charmany Hill

Telephone No: 631-254-7118

Facsimile No: 631-254-7132

and

Merrill Lynch, Pierce, Fenner & Smith

Incorporated

Merrill Lynch World Headquarters

4 World Financial Center

15th Floor

New York, New York 10080

Attn: MTN Product Management

Facsimile No: 212-449-2234

Telephone No: 212-449-7476

and

UBS Securities LLC

677 Washington Blvd.

Stamford, Connecticut 06901

Attn: Fixed Income Syndicate

Facsimile No: 203-719-0495

Telephone No: 203-719-1088

and

J.P. Morgan Securities Inc.

270 Park Avenue, 8th Floor

New York, New York 10017

Attn: Medium Term Notes Desk

Facsimile No: 212-834-6081

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and

Piper Jaffray & Co.

800 Nicollet Mall

Minneapolis, Minnesota 55402

Attention: Debt Capital Markets

Facsimile No. 612-313-3117

Telephone No: 612-303-1824

The Company shall supply the Agents as soon as practicable but in no event later than the Settlement Date with an adequate supply of Prospectus Supplements and the accompanying Prospectuses and Pricing Supplements at the above addresses.

In addition, the Company will make any required filings with the OPUC and WUTC in respect of the Securities that are issued.

Suspension of Solicitation; Amendment or Settlement:

Subject to its representations, warranties and covenants contained in the Distribution Agreement, the Company may instruct the Agents to suspend solicitation of purchases at any time. Upon receipt of such instructions, the Agents will forthwith suspend solicitation of offers to purchase from the Company until such time as the Company has advised them that solicitation of offers to purchase may be resumed. If the Company decides to amend or supplement the Prospectus (other than to change interest rates or other variable terms with respect to the offering of the Securities), it will promptly advise the Agents and will furnish the Agents and their counsel with copies of the proposed amendment or supplement.

In the event that at the time the solicitation of offers to purchase from the Company is suspended (other than to change interest rates or other variable terms) there shall be any orders outstanding which have not been settled, the Company will promptly advise the Agents and the Trustee whether such orders may be settled and whether copies of the Prospectus as theretofore amended and/or supplemented as in effect at the time of the suspension may be delivered in connection with the settlement of such orders. The Company will have the sole responsibility for such decision and for any arrangements which may be made in the event that the Company determines that such orders may not be settled or that copies of such Prospectus may not be so delivered.

Delivery of Confirmation and Prospectus to Purchaser by Selling Agent:

The Selling Agent will deliver to the purchaser of a Security a written confirmation of the sale and delivery and payment instructions. In addition, the Selling Agent will deliver or convey to such purchaser or its agent the Prospectus as amended or supplemented (including the Pricing Supplement) relating to such Security prior to delivery to such purchaser or its agent of, or together with, the earlier to be delivered of (a) the confirmation of sale or (b) the Security.

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Instruction from Company to Trustee for Preparation of Securities:

After receiving the Sale Information from the Selling Agent or Purchasing Agent, as the case may be, the Company will communicate such Sale Information to the Mortgage Trustee or the Indenture Trustee, as the case may be, by telephone (confirmed in writing, by facsimile transmission or by other acceptable written means).

The Company will instruct such Trustee by telephone (confirmed in writing, by facsimile transmission or by other acceptable written means) to authenticate and deliver the Securities no later than 2:15 p.m., New York City time, on the Settlement Date. Such instruction will be given by the Company prior to 3:00 p.m., New York City time, on the business day prior to the Settlement Date, unless the Settlement Date is the date of acceptance by the Company of the offer to purchase Securities, in which case such instruction will be given by the Company to the Trustee by 10:00 a.m., New York City time, on the Settlement Date.

Procedures for Book-Entry Securities:

In connection with Securities issued in book-entry form and maintained in the book-entry system of The Depository Trust Company (“DTC”), (i) the Company and the Trustee shall act in accordance with the letters of representation (relating to the Secured Notes and the Unsecured Notes, respectively) from the Company and the Trustee to DTC, as the same may be amended, supplemented or otherwise modified from time to time, and (ii) the Trustee shall act in accordance with one or more Medium-Term Note Certificate Agreements, relating to the Securities, between the Trustee and DTC, as the same may be amended, supplemented or otherwise modified from time to time, and in accordance with its obligations as a participant in DTC.

The beneficial owner of a Security issued in book-entry form (or one or more indirect participants in DTC designated by such owner) will designate one or more participants in DTC (with respect to such Security issued in book-entry form, the “Participants”) to act as agent for such beneficial owner in connection with the book-entry system maintained by DTC, and DTC will record in book-entry form, in accordance with instructions provided by such Participants, a credit balance with respect to such Security issued in book-entry form in the account of such Participants. The ownership interest of such beneficial owner in such Security issued in book-entry form will be recorded through the records of such Participants or through the separate records of such Participants and one or more indirect participants in DTC.

Transfers of a Book-Entry Security will be accomplished by book entries made by DTC and, in turn, by Participants (and in certain cases, one or more indirect participants in DTC) acting on behalf of beneficial transferors and transferees of such Book-Entry Security.

Beneficial interests in the Securities may be purchased, owned and transferred only in denominations of $1,000 or any integral multiple of $1,000.

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Preparation and Delivery of Securities by Trustee and Receipt of Payment Therefor:

Certificated Securities

The Company will instruct the Mortgage Trustee or the Indenture Trustee, as the case may be, to:

(i) Prepare each Security and appropriate receipts that will serve as the documentary control of the transaction.

(ii) In the case of a sale of Securities to a purchaser solicited by a Selling Agent, by 2:15 p.m., New York City time, on the Settlement Date, deliver the Securities to such Selling Agent, at the address listed below, for the benefit of the purchaser of such Securities against delivery by such Selling Agent of a receipt therefor. (On the Settlement Date, such Selling Agent will deliver payment for such Securities in immediately available funds to the Company’s account at a bank designated by the Company and included as a part of the Sale Information provided by the Selling Agent in an amount equal to the net proceeds to the Company; provided that the Selling Agent reserves the right to withhold payment for which it shall not have received funds from the purchaser.)

(iii) In the case of a sale of Securities to a Purchasing Agent, by 2:15 p.m., New York City time, on the Settlement Date, deliver the Securities to such Purchasing Agent, at the address listed below, against delivery of payment therefor. (On the Settlement Date, such Purchasing Agent will deliver payment for such Securities in immediately available funds to the Company’s account at a bank designated by the Company and included as a part of the Sale Information provided by the Purchasing Agent in an amount equal to the net proceeds to the Company.)

(iv) Complete the 4-ply Security and deliver three copies thereof as follows:

1. Security with Agent’s customer confirmation.

2. Copy 1 - for Trustee.

3. Copy 2 - for Agent.

4. Copy 3 - for Company.

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(v) With respect to each sale, deliver the Securities and Copies 1 and 2 thereof to the appropriate Agent at the following address:

Merrill Lynch, Pierce, Fenner & Smith

Incorporated

55 Water Street

3rd Floor Plaza Level, DTC New York Window

New York, New York 10041

Attn: Morna Noel

Facsimile No: 212-855-2457

or

UBS Securities LLC

677 Washington Blvd.

Stamford, Connecticut 06901

Attn: Fixed Income Syndicate

Facsimile No: 203-719-0495

or

J.P. Morgan Securities Inc.

270 Park Avenue, 8th Floor

New York, New York 10017

Attn: Medium Term Notes Desk

Facsimile No: 212-834-6081

or

Piper Jaffray & Co.

800 Nicollet Mall

Minneapolis, Minnesota 55402

Attention: Debt Capital Markets

Facsimile No. 612-313-3117

Telephone No: 612-303-1824

as the case may be, or to any other Agent as directed by such Agent. (The Agent will acknowledge receipt of the Security, will keep Copy 2 and will return Copy 1 to the Trustee. Delivery of the Security by the Trustee will be made only against such acknowledgment of receipt. Prior to the first settlement date, the Trustee or the Company shall have sent a letter to Merrill Lynch Clearance Operations, UBS Securities LLC, J.P. Morgan Securities Inc., Piper Jaffray & Co. or any other Agent, as the case may be, containing standard wire instructions for the net proceeds of each Security, addressed as follows:

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Merrill Lynch, Pierce, Fenner & Smith

Incorporated

4 World Financial Center

15th Floor

New York, New York 10080

Facsimile No: 212-449-2234

or

UBS Securities LLC

677 Washington Blvd.

Stamford, Connecticut 06901

Attn: Fixed Income Syndicate

Facsimile No: 203-719-0495

or

J.P. Morgan Securities Inc.

270 Park Avenue, 8th Floor

New York, New York 10017

Attn: Medium Term Notes Desk

Facsimile No: 212-834-6081

or

Piper Jaffray & Co.

800 Nicollet Mall

Minneapolis, Minnesota 55402

Attention: Debt Capital Markets

Facsimile No. 612-313-3117

Telephone No: 612-303-1824

as the case may be, or as directed by such other Agent.)

(vi) Send Copy 3 to the Company.

Book-Entry Securities

A. The Company will assign a CUSIP number to the Book-Entry Security representing such Security and then advise the Trustee by electronic transmission of the Sale Information received from the Agent, such CUSIP number and the name of such Agent.

B. The Trustee will communicate to DTC and the Agent through DTC’s Participant Terminal System, a pending deposit message specifying the following settlement information:

(1) The following Sale Information with respect to each Security:

(a) Taxpayer identification number of the purchaser.

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(b) Principal amount of the Security.

(c) Fixed Rate Securities:

(i) interest rate;

(ii) interest payment dates; and

(iii) regular record dates.

(d) Floating Rate Securities:

(i) interest rate basis;

(ii) initial interest rate;

(iii) spread or spread multiplier, if any;

(iv) interest rate reset dates;

(v) interest rate reset period;

(vi) interest payment dates;

(vii) interest payment period;

(viii) regular record dates;

(ix) index maturity;

(x) calculation agent;

(xi) maximum and minimum interest rates, if any;

(xii) calculation date; and

(xiii) interest determination dates.

(e) Issue price.

(f) Trade date.

(g) Interest Commencement Date, which shall be the Settlement Date unless otherwise noted (“Issue Date” on Secured Notes).

(h) Maturity date.

(i) Net proceeds to the Company.

(j) Agent’s commission.

(k) Redemption provisions, if any.

(l) Repayment provisions, if any.

(2) Identification numbers of the participant accounts maintained by DTC on behalf of the Trustee and the Agent.

(3) Identification as a Fixed Rate Book-Entry Security or Floating Rate Book-Entry Security.

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(4) Initial Interest Payment Date for such Security, number of days by which such date succeeds the related record date for DTC purposes (or, in the case of Floating Rate Securities which reset daily or weekly, the date five calendar days preceding the Interest Payment Date) and, if then calculable, the amount of interest payable on such Interest Payment Date (which amount shall have been confirmed by the Trustee).

(5) CUSIP number of the Book-Entry Security representing such Security.

(6) Whether such Book-Entry Security represents any other Securities issued or to be issued in book-entry form.

C. The Company will complete and deliver to the Trustee a Book-Entry Security representing such Security in a form that has been approved by the Company, the Agents and the Trustee.

D. The Company will (by telecopy followed by an original copy) provide the Trustee with an opinion regarding the authentication of such Security and certified copies of governmental approvals specified in such opinion.

E. The Trustee will authenticate the Book-Entry Security representing such Security.

F. DTC will credit such Security to the participant account of the Trustee maintained by DTC.

G. The Trustee will enter a Same-Day Funds Settlement System (“SDFS”) deliver order through DTC’s Participant Terminal System instructing DTC (i) to debit such Security to the Trustee’s participant account and credit such Security to the participant account, maintained by DTC, of the Agent which presented to the Company the offer to purchase such Security which was accepted by the Company (the “Presenting Agent”) and (ii) to debit the settlement account of the Presenting Agent and credit the settlement account of the Trustee maintained by DTC, in an amount equal to the price of such Security less such Agent’s commission.

H. The Presenting Agent will enter an SDFS deliver order through DTC’s Participant Terminal System instructing DTC (i) to debit such Security to the Presenting Agent’s participant account and credit such Security to the participant account of the Participants maintained by DTC and (ii) to debit the settlement accounts of such Participants and credit the settlement account of the Presenting Agent maintained by DTC, in an amount equal to the initial public offering price of such Security.

I. Transfer of funds in accordance with SDFS deliver orders described in Settlement Procedures F and G will be settled in accordance with SDFS operating procedures in effect on the Settlement Date.

J. The Trustee will credit to an account of the Company maintained at the Trustee funds available for immediate use in the amount transferred to the Trustee in accordance with Settlement Procedure G.

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K. The Trustee will send a copy of the Book-Entry Security by first class mail to the Company together with a statement setting forth the principal amount of Securities Outstanding as of the related Settlement Date after giving effect to such transaction and all other offers to purchase Securities of which the Company has advised the Trustee but which have not yet been settled.

L. The Agent will confirm the purchase of such Security to the purchaser either by transmitting to the Participant with respect to such Security a confirmation order through DTC’s Participant Terminal System or by mailing a written confirmation to such purchaser.

M. Settlement Procedures Timetable:

(1) For orders of Securities accepted by the Company, Settlement Procedures A through K shall be completed as soon as possible but not later than the respective times (New York City time) set forth below:

Settlement Procedure	Time
A	11:00 a.m. on the trade date
B	2:00 p.m. on the trade date
C	3:00 p.m. on the Business Day before Settlement Date
D-E	9:00 a.m. on Settlement Date
F	10:00 a.m. on Settlement Date
G-H	No later than 2:00 p.m. on Settlement Date
I	4:45 p.m. on Settlement Date
J-K	5:00 p.m. on Settlement Date

(2) If a sale is to be settled more than one Business Day after trade date, Settlement Procedures A and B may, if necessary, be completed at any time prior to the specified times on the first Business Day after such trade date. In connection with a sale which is to be settled more than one Business Day after the trade date, if the initial interest rate for a Floating Rate Security is not known at the time that the Sale Information is given by the Presenting Agent to the Company, Settlement Procedures A and B shall be completed as soon as such rates have been determined, but no later than 11:00 a.m. and 2:00 p.m., New York City time, respectively, on the second Business Day before the Settlement Date. Settlement Procedure H is subject to extension in accordance with any extension of Fedwire closing deadlines and in the other events specified in the SDFS operating procedures in effect on the Settlement Date.

(3) If settlement of a Security issued in book-entry form is rescheduled or canceled, the Trustee will deliver to DTC, through DTC’s Participant Terminal System, a cancellation message to such effect by no later than 2:00 p.m., New York City time, on the Business Day immediately preceding the scheduled Settlement Date.

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Failure of Purchaser to Pay Selling Agent:

Certificated Securities

If a purchaser shall fail to make payment to the Selling Agent for any Security, the net proceeds to the Company which, theretofore, shall have been paid by the Selling Agent to the Company, the Selling Agent will promptly notify the Mortgage Trustee or the Indenture Trustee, as the case may be, and the Company of such failure by telephone, promptly confirmed in writing or by facsimile transmission or by other acceptable written means. The Selling Agent promptly will return such Security to such Trustee. Promptly upon receipt of such Security by such Trustee, the Company will return to the Selling Agent an amount equal to the amount previously paid to the Company in respect of such Security. Such Trustee will cancel any Security in respect of which such a failure shall occur, make appropriate entries in its records and, unless otherwise instructed by the Company, destroy such Security.

Book-Entry Securities

If the Trustee fails to enter an SDFS deliver order with respect to a Book-Entry Security issued in book-entry form pursuant to paragraph F above, the Trustee may deliver to DTC, through DTC’s Participant Terminal System, as soon as practicable a withdrawal message instructing DTC to debit such Security to the participant account of the Trustee maintained at DTC. DTC will process the withdrawal message, provided that such participant account contains a principal amount of the Book-Entry Security representing such Security that is at least equal to the principal amount to be debited. If withdrawal messages are processed with respect to all the Securities represented by a Book-Entry Security, the Trustee will mark such Book-Entry Security “canceled”, make appropriate entries in its records and send such canceled Book-Entry Security to the Company. The CUSIP number assigned to such Book-Entry Security shall, in accordance with CUSIP Service Bureau procedures, be canceled and not immediately reassigned. If withdrawal messages are processed with respect to a portion of the Securities represented by a Book-Entry Security, the Trustee will exchange such Book-Entry Security for two Book-Entry Securities, one of which shall represent the Book-Entry Securities for which withdrawal messages are processed and shall be canceled immediately after issuance, and the other of which shall represent the other Securities previously represented by the surrendered Book-Entry Security and shall bear the CUSIP number of the surrendered Book-Entry Security.

If the purchase price for any Book-Entry Security is not timely paid to the Participants with respect to such Security by the beneficial purchaser thereof (or a person, including an indirect participant in DTC acting on behalf of such purchaser), such Participants and, in turn, the related Agent may enter SDFS deliver orders through DTC’s Participant Terminal System reversing the orders entered pursuant to paragraphs F and G above, respectively. Thereafter, the Trustee will deliver the withdrawal message and take the related actions described in the preceding paragraph. If such failure shall have occurred for any reason other than default by the applicable Agent to perform its obligations hereunder or under the Distribution Agreement, the Company will reimburse such Agent on an equitable basis for its loss of the use of funds during the period when the funds were credited to the account of the Company.

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Notwithstanding the foregoing, upon any failure to settle with respect to a Book-Entry Security, DTC may take any actions in accordance with its SDFS operating procedures then in effect. In the event of a failure to settle with respect to a Security that was to have been represented by a Book-Entry Security also representing other Securities, the Trustee will provide, in accordance with paragraphs C and D above, for the authentication and issuance of a Book-Entry Security representing such remaining Securities and will make appropriate entries in its records.

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ANNEX II

Northwest Natural Gas Company

Medium-Term Notes

Terms Agreement

[Merrill Lynch, Pierce, Fenner & Smith

Incorporated

4 World Financial Center

15th Floor

New York, New York 10080]

[UBS Securities LLC

677 Washington Blvd.

Stamford, Connecticut 06901]

[J.P. Morgan Securities Inc.

270 Park Avenue

New York, New York 10017]

[Piper Jaffray & Co.

800 Nicollet Mall

Minneapolis, Minnesota 55402]

[Name of additional Agents, if any]

Ladies and Gentlemen:

Subject to the terms and conditions set forth herein and, to the extent provided below, in the Distribution Agreement, dated September 28, 2004, amended and restated on December 7, 2006 (the “Distribution Agreement”), amongst Northwest Natural Gas Company (the “Company”), on the one hand, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, UBS Securities LLC, J.P. Morgan Securities Inc., Piper Jaffray & Co. and each other person which shall become a party to the Distribution Agreement (each an “Agent” and, together, the “Agents”), on the other, the Company proposes to issue and sell to [Merrill Lynch, Pierce, Fenner & Smith Incorporated] [UBS Securities LLC] [J.P. Morgan Securities Inc.] [Piper Jaffray & Co.] [Name of other Agent] the Securities (as defined in the Distribution Agreement) specified in the Schedule hereto (the “Purchased Securities”), at the time, place and purchase price and upon the terms and conditions set forth in such Schedule. Each of the provisions of the Distribution Agreement not specifically related to the solicitation by the Agents, as agents of the Company, of offers to purchase Securities is incorporated herein by reference, and shall be deemed to be part of this Terms Agreement to the same extent as if such provisions had been set forth herein. Each reference in the Distribution Agreement to the Pricing Disclosure Package shall be deemed to refer to the items specified next to the caption “Pricing Disclosure Package” in the Schedule hereto.

Each of the representations and warranties set forth in the Distribution Agreement shall be deemed to have been made by the Company at and as of the date of this Terms Agreement, except that each such representation and warranty which makes reference to the Prospectus shall be deemed to be a representation and warranty as of the date of the Distribution Agreement in relation to the Prospectus (as therein defined), and also a representation and warranty as of the date of this Terms Agreement in relation to the Prospectus as amended and supplemented with respect to the Purchased Securities.

A supplement to the Prospectus relating to the Purchased Securities, in the form heretofore delivered to and approved by you, is now proposed to be filed with the Commission in accordance with Rule 424(b) under the Act and the Term Sheet [and                 ] specified next to the caption “Pricing Disclosure Package” in the Schedule hereto is now proposed to be filed with the Commission in accordance with Rule 433 under the Act.

Subject to the terms and conditions set forth herein and to those of the Distribution Agreement incorporated herein by reference, the Company agrees to issue and sell to [Merrill Lynch, Pierce, Fenner & Smith Incorporated] [UBS Securities LLC] [J.P. Morgan Securities Inc.] [Piper Jaffray & Co.] [Name of other Agent] and [Merrill Lynch, Pierce, Fenner & Smith Incorporated] [UBS Securities LLC] [J.P. Morgan Securities Inc.] [Piper Jaffray & Co.] [Name of other Agent] agrees to purchase from the Company the Purchased Securities, at the time and place, in the principal amount and at the purchase price set forth in the Schedule hereto.

If the foregoing is in accordance with your understanding, please sign and return to us three counterparts hereof, whereupon this letter, including those provisions of the Distribution Agreement incorporated herein by reference, shall constitute a binding agreement between you and the Company.

NORTHWEST NATURAL GAS COMPANY

By:

Title:

Accepted as of the date hereof:

[MERRILL LYNCH, PIERCE, FENNER & SMITH INCORPORATED]
By:
Title:	]
[UBS SECURITIES LLC
By:
Title:	]

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By:
Title:	]
[J.P. MORGAN SECURITIES INC.
By:
Title:	]
[PIPER JAFFRAY & CO.
By:
Title:	]

[Name of other Agent, if any]

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Schedule to Annex II

Title of Purchased Securities:

Aggregate Principal Amount: $

Price to Public:

Purchase Price by [Merrill Lynch, Pierce, Fenner & Smith Incorporated] [UBS Securities LLC] [J.P. Morgan Securities Inc.] [Piper Jaffray & Co.] [Name of other Agent]:

% of the principal amount of the Purchased Securities [, plus accrued interest from             

to              ] [and accrued amortization of discount from              to              ]

Method of and Specified Funds for Payment of Purchase Price:

[By certified or official bank check or checks, payable to the order of the Company, in [[New York Clearing House] [immediately available] funds]

[By wire transfer to a bank account specified by the Company in [next day] [immediately available] funds]

Indenture: [Mortgage] [Note Indenture]

Interest Commencement Date which shall be the Settlement Date unless otherwise noted (“Issue Date” on Secured Notes):

Pricing Disclosure Package: 1. Prospectus, dated February 18, 2004

2. Prospectus Supplement, dated September 28, 2004

3. [Preliminary Pricing Supplement, dated                     ]

4. [Term Sheet, dated                         ]

5. [Other]

Time of Delivery:

Closing Location:

Stated Maturity Date:

Interest Rate or Rates (or Method of Determining Interest):

Interest Payment Dates: [months and dates]

Initial Interest Payment Date:

Regular Record Dates:

Redeemable at Company’s Option: Yes      No    

In Whole: Yes      No    

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In Part: Yes      No    

Fixed Redemption Prices          / Make-Whole Redemption Price         

Fixed Redemption Prices:

Initial Redemption Date:

Redemption Limitation Date:

Initial Redemption Price:

Reduction Percentage:

Make-Whole Redemption Price:

Make-Whole Spread:

Sinking Fund or Other Retirement Provisions, if any:

Repayable at Option of Holder: Yes       No     

Repayment Date:

Repayment Price:

Election Period:

Documents to be Delivered as a Condition to the Closing:

[(1) The opinion of counsel to the Agents referred to in Section 5(h)]

[(2) The opinion of counsel to the Company referred to in Section 5(i)(i)]

[(3) The opinion of counsel to the Company referred to in Section 5(i)(ii)]

[(4) The opinion of counsel to the Company referred to in Section 5(i)(iii)]

[(5) The accountants letter referred to in Section 5(j)]

[(6) The officers certificate referred to in Section 5(i)(iv)]

Other Provisions (including Syndicate Provisions, if applicable):

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ANNEX III

[Letterhead of C.J. Rue, Esq.]

            [Date]

Merrill Lynch, Pierce, Fenner & Smith

Incorporated

4 World Financial Center

15th Floor

New York, New York 10080

UBS Securities LLC

677 Washington Blvd.

Stamford, Connecticut 06901

J.P. Morgan Securities Inc.

270 Park Avenue

New York, New York 10017

Piper Jaffray & Co.

800 Nicollet Mall

Minneapolis, Minnesota 55402

Ladies and Gentlemen:

With reference to the issuance and sale from time-to-time by Northwest Natural Gas Company (the “Company”), pursuant to the Distribution Agreement, dated September 28, 2004, amended and restated on December 7, 2006 (the “Agreement”), between the Company and each of you, of not to exceed $160,000,000 in aggregate principal amount of (i) the Company’s First Mortgage Bonds, designated Secured Medium-Term Notes, Series B (the “Secured Notes”) to be issued under the Company’s Mortgage and Deed of Trust, dated as of July 1, 1946, to Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) (the “Corporate Trustee”) and R.G. Page (Stanley Burg, successor), as trustees, as supplemented by twenty supplemental indentures (such Mortgage and Deed of Trust, as so supplemented, being hereinafter called the “Mortgage”), and (ii) the Company’s Unsecured Medium-Term Notes, Series B (the “Unsecured Notes”), to be issued under the Company’s Indenture, dated as of June 1, 1991 (the “Indenture”), to Deutsche Bank Trust Company Americas, as trustee (the “Indenture Trustee”) (the Secured Notes and the Unsecured Notes being hereinafter collectively referred to as the “Notes”), and the appointment of each of you as agents of the Company pursuant to the Agreement for the purposes of soliciting and receiving offers to purchase Notes, as agents, and purchasing Notes, as principals, from the Company, please be advised that, as counsel for the Company, I have participated in the preparation of or

reviewed (a) the Restated Articles of Incorporation, as amended, and Bylaws, as amended, of the Company; (b) the Mortgage; (c) the Indenture; (d) the Agreement; (e) the registration statement (File No. 333-112604) (the “Registration Statement”), filed by the Company with the Securities and Exchange Commission (the “SEC”) for the registration under the Securities Act of 1933, as amended (the “1933 Act”), of $200,000,000 of the Company’s securities (which may include the Notes), and for the qualification under the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”), of the Mortgage and the Indenture, which Registration Statement became effective on February 18, 2004; (f) the prospectus, dated February 18, 2004, constituting a part of the Registration Statement in the form in which the Registration Statement became effective, or if such prospectus has been amended or supplemented subsequent to such effectiveness, as so amended and supplemented, including the documents incorporated therein by reference pursuant to Item 12 of Form S-3, as supplemented by the prospectus supplement relating to the Notes, dated September 28, 2004, filed with the Commission pursuant to Rule 424(b) under the Securities Act (together, the “Prospectus”); (g) the proceedings before the Oregon Public Utility Commission (the “OPUC”) and the Washington Utilities and Transportation Commission (the “WUTC”) relating to the issuance and sale of the Notes; and (h) the records of various corporate and other proceedings relating to the authorization, issuance and sale of the Notes. I have also examined such other documents and satisfied myself as to such other matters as I have deemed necessary in order to render this opinion. I have not examined the Notes, except specimens thereof.

In preparation of this opinion, I have examined originals or photostatic certified copies of such certificates, agreements, documents and other papers, and have made such inquiries and investigations of law, as I deemed appropriate and necessary for the opinion hereinafter set forth. In my examination, I have assumed the authenticity of all documents submitted to me as certified or photostatic copies and the authenticity of the originals of such latter documents. As to certain matters of fact material to the opinion expressed herein, I have relied upon certificates of various corporate officers of the Company and public officials. I assume the accuracy of the material and factual matters contained therein.

I am of the opinion that:

1. The Company is a validly organized and existing corporation under the laws of the State of Oregon, is authorized to transact business in the State of Washington, and has corporate power to own its properties and conduct its business as described in the Prospectus.

2. The Company holds valid and subsisting franchises, licenses, permits and consents, free from burdensome restrictions and adequate for the conduct of its business, as and to the extent set forth in the Prospectus.

3. The Agreement has been duly and validly authorized, executed and delivered by the Company.

4. The Mortgage and the Indenture have been duly and validly authorized by all necessary corporate action, have been duly and validly executed and delivered, and are valid and binding instruments enforceable in accordance with their terms, subject, as to enforcement, to laws and principles of equity relating to or affecting generally the enforcement of creditors rights, including, without limitation, bankruptcy and insolvency.

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5. The Mortgage constitutes a first security interest on all of the personal properties and fixtures owned by the Company that are described in the Mortgage and are intended to be subject to the lien thereof, subject only to Excepted Encumbrances (as defined in the Mortgage); and the description in the Mortgage of such properties and fixtures is adequate to constitute the Mortgage a security interest thereon.

6. The Company has good and sufficient title to all of the real properties owned by the Company that are described in the Mortgage and intended to be subject to the lien thereof, subject only to Excepted Encumbrances (as defined in the Mortgage) and to minor defects and irregularities of the nature customarily found in properties of like size and character; the description in the Mortgage of such properties is adequate to constitute the Mortgage a lien thereon; and the Mortgage is a valid first mortgage lien on such properties, subject to the exceptions noted above in this paragraph (6).

7. The form of the Secured Notes has been duly authorized and has been established in conformity with the provisions of the Mortgage; the form of the Unsecured Notes bearing interest at a fixed rate, has been duly authorized and has been established in conformity with the provisions of the Indenture; and the form of the Unsecured Notes, bearing interest at a variable rate or not bearing interest, when set forth in a Company Order or Orders (as defined in the Indenture) or established by procedures acceptable to the Indenture Trustee specified in a Company Order or Orders, will have been duly authorized and will have been established in conformity with the provisions of the Indenture.

8. The Secured Notes have been duly authorized by the resolutions adopted by the Company’s Board of Directors on May 27, 1993, September 26, 1996, April 24, 1997, February 26, 1998, April 27, 2000, April 25, 2002 and December 18, 2003 (the “Board Resolutions”), and when the terms of the Secured Notes shall have been determined as contemplated by and in accordance with the Mortgage, the Board Resolutions and written orders or instructions evidencing determinations by officers of the Company, such terms will have been duly authorized by the Company and will have been established in conformity with the terms of the Mortgage.

9. The Unsecured Notes have been duly authorized by the Board Resolutions, and when the terms of the Unsecured Notes shall have been determined as contemplated by and in accordance with the Indenture, the Board Resolutions and, to the extent required by the Indenture and the Board Resolutions, by Officers’ Certificates (as defined in the Indenture), Company Orders and procedures acceptable to the Indenture Trustee specified in such Company Orders, such terms will have been duly authorized by the Company and will have been established in conformity with the terms of the Indenture.

10. The Notes, when (a) executed by the Company, (b) completed, authenticated and delivered by the Corporate Trustee or the Indenture Trustee, as the case may be, (c) issued and delivered by the Company and (d) paid for, all as contemplated by and in accordance with the Mortgage, in the case of Secured Notes, the Indenture, in the case of Unsecured Notes, the

III-3

Board Resolutions, and (to the extent required by the Mortgage or the Indenture and the Board Resolutions) Officers’ Certificates, Company Orders, procedures acceptable to the Indenture Trustee specified in such Company Orders, written orders or instructions evidencing determinations by the officers of the Company, the Agreement, the Administrative Procedure (as defined in the Agreement), and Terms Agreements (as defined in the Agreement), if any, will be duly issued under the Mortgage or the Indenture, as the case may be, and will constitute valid and legally binding obligations of the Company, entitled to the benefits provided by the Mortgage or the Indenture, as the case may be, and enforceable in accordance with their terms, subject, as to enforcement, to laws and principles of equity relating to or affecting generally the enforcement of creditors’ rights, including, without limitation, bankruptcy and insolvency, and, in the case of the Secured Notes, entitled to the benefit of the security afforded by the Mortgage.

11. The issuance and sale of the Notes, the compliance by the Company with all of the provisions of the Notes, the Mortgage, the Indenture and the Agreement and the consummation of the transactions contemplated by the Agreement will not result in a breach or violation of any of the terms and provisions of, or constitute a default under, any statute, any indenture, mortgage, deed of trust or other agreement or instrument known to me to which the Company is a party or by which it is bound or to which any of the property of the Company is subject, the Company’s Restated Articles of Incorporation, as amended, or Bylaws, as amended, or any order, rule or regulation known to me of any court or governmental agency or body having jurisdiction over the Company or any of its properties.

12. The OPUC has issued orders authorizing the issuance and sale by the Company of the Notes; and no further approval, authorization, consent or other order of any public board or body (other than in connection or in compliance with the provisions of the securities or blue sky laws of any jurisdiction and other than orders of the WUTC establishing compliance with applicable statutory provisions) is legally required for the issuance and sale of the Notes on the terms and conditions set forth in the Agreement.

13. The statements of Oregon and Federal law (other than the 1933 Act, the Securities Exchange Act of 1934 and the Trust Indenture Act), and legal conclusions based thereon, contained in, or in the documents incorporated by reference in, the Prospectus have been reviewed by me and are correct (except to the extent that any statement contained in a document incorporated or deemed to be incorporated by reference in the Prospectus may be deemed to be modified or superseded in the Prospectus or in any other subsequently filed document which also is or is deemed to be incorporated by reference in the Prospectus).

14. Except as described in the Prospectus, there are no pending material legal or governmental proceedings and, to my knowledge, no material threatened legal or governmental proceedings, to which the Company is a party or of which any of the property of the Company is the subject, other than ordinary routine litigation incidental to the kind of business conducted by the Company.

In the course of the preparation by the Company of the Registration Statement and the Prospectus, I had conferences with certain officers and employees of the Company, but I have made no independent verification of the accuracy or completeness of the representations and statements made to me by such person or the information included by the Company in the

III-4

Registration Statement and the Prospectus, and take no responsibility therefor, except as set forth in paragraph 12 hereof. However, my examination of the Registration Statement and the Prospectus and my discussions in the above-mentioned conferences did not disclose to me any information which causes me to believe that, when the Registration Statement became effective, it contained an untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein not misleading, or that, as of the date of this opinion, the Prospectus includes an untrue statement of a material fact or omits to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided, that I do not express any belief as to the financial statements or other financial or statistical data contained in the Registration Statement or the Prospectus, or as to the Forms T-1 or T-2, or as to any information contained therein furnished to the Company in writing by any of you expressly for use therein.

This opinion is limited to the facts and law at the date hereof. In rendering the opinions set forth in paragraphs 10, 11 and 12 above, I have necessarily assumed that, at the time of any issuance, sale and delivery of a Note (i) the Board of Directors of the Company (or any committee thereof acting pursuant to authority properly delegated to such committee by the Board of Directors) has not taken any action to rescind or otherwise reduce its prior authorization of the issuance of the Notes and an officer of the Company, as stated in the resolutions of the Board of Directors (or any such committee) relating to the Notes, has executed and delivered such Notes, (ii) the WUTC has issued an order or orders establishing compliance with applicable statutory provisions with respect to the issuance and sale of such Note, (iii) the orders of the OPUC and the WUTC with respect to the Notes being sold remain in full force and effect and have not been modified or amended by the OPUC or the WUTC, respectively, and the Company complies with the terms of such orders, and (iv) the order of the SEC with respect to the Registration Statement, the Mortgage and the Indenture remains in full force and effect and has not been modified or amended by the SEC.

I do not express any opinion herein concerning any law other than the laws of the State of Oregon and the Federal laws of the United States. In rendering this opinion, I have relied, with your consent, as to certain matters of Washington law, upon the opinion of even date herewith addressed to you by Stoel Rives LLP, special Washington counsel to the Company, and, as to all matters governed by the laws of the State of New York, the 1933 Act, the Securities Exchange Act of 1934 and the Trust Indenture Act, upon the opinion of even date herewith addressed to you by Thelen Reid Brown Raysman & Steiner LLP, New York, New York, counsel for the Company.

You, the Trustees and, as to matters governed by the laws of the State of Oregon, Thelen Reid Brown Raysman & Steiner LLP and your counsel, Simpson Thacher & Bartlett LLP, may rely upon this opinion in connection with the issuance and sale of the Notes. Neither you nor any of them may rely upon this opinion for any other purpose, and no other person may rely upon this opinion for any purpose without, in each case, my prior written consent.

Very truly yours,

C.J. Rue, Esq.

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ANNEX IV

[Letterhead of Thelen Reid Brown Raysman & Steiner LLP]

            [Date]

Merrill Lynch, Pierce, Fenner & Smith

Incorporated

4 World Financial Center

15th Floor

New York, New York 10080

UBS Securities LLC

677 Washington Blvd.

Stamford, Connecticut 06901

J.P. Morgan Securities Inc.

270 Park Avenue

New York, New York 10017

Piper Jaffray & Co.

800 Nicollet Mall

Minneapolis, Minnesota 55402

Ladies and Gentlemen:

With reference to the issuance and sale from time-to-time by Northwest Natural Gas Company (the “Company”), pursuant to the Distribution Agreement, dated September 28, 2004, amended and restated on December 7, 2006 (the “Agreement”), between the Company and each of you, of not to exceed $160,000,000 in aggregate principal amount of (i) the Company’s First Mortgage Bonds, designated Secured Medium-Term Notes, Series B (the “Secured Notes”), to be issued under the Company’s Mortgage and Deed of Trust, dated as of July 1, 1946, to Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) (the “Corporate Trustee”) and R.G. Page (Stanley Burg, successor), as trustees, as supplemented by twenty supplemental indentures (such Mortgage and Deed of Trust, as so supplemented, being hereinafter called the “Mortgage”), and (ii) the Company’s Unsecured Medium-Term Notes, Series B (the “Unsecured Notes”), to be issued under the Company’s Indenture, dated as of June 1, 1991 (the “Indenture”), to Deutsche Bank Trust Company Americas, as trustee (the “Indenture Trustee”) (the Secured Notes and the Unsecured Notes being hereinafter collectively referred to as the “Notes”), and the appointment of each of you as agents of the Company pursuant to the Agreement for the purposes of soliciting and receiving offers to purchase Notes, as agents, and purchasing Notes, as principals, from the Company, please be advised that, as counsel to the Company, we have participated in the preparation of or reviewed (a) the Restated Articles of Incorporation, as amended, and Bylaws, as amended, of the

Company; (b) the Mortgage; (c) the Indenture; (d) the Agreement; (e) the registration statement (File No. 333-112604) (the “Registration Statement”), filed by the Company with the Securities and Exchange Commission (the “SEC”) for the registration under the Securities Act of 1933, as amended (the “1933 Act”), of $200,000,000 of the Company’s securities (which may include the Notes), and for the qualification under the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”), of the Mortgage and the Indenture, which Registration Statement became effective on February 18, 2004; (f) the prospectus, dated February 18, 2004, constituting a part of the Registration Statement in the form in which the Registration Statement became effective, or if such prospectus has been amended or supplemented subsequent to such effectiveness, as so amended and supplemented, including the documents incorporated therein by reference pursuant to Item 12 of Form S-3, as supplemented by the prospectus supplement relating to the Notes, dated September 28, 2004, filed with the Commission pursuant to Rule 424(b) under the Securities Act (together, the “Prospectus”); (g) the records of the proceedings before the Oregon Public Utility Commission (the “OPUC”) and the Washington Utilities and Transportation Commission (the “WUTC”) relating to the issuance and sale of the Notes; and (h) the records of various corporate and other proceedings relating to the authorization, issuance and sale of the Notes. We have also examined such other documents and satisfied ourselves as to such other matters as we have deemed necessary in order to render this opinion. We have not examined the Notes, except specimens thereof.

In the preparation of this opinion, we have examined originals or photostatic or certified copies of such certificates, agreements, documents and other papers, and have made such inquiries and investigations of law, as we deemed appropriate and necessary for the opinion hereinafter set forth. In our examination, we have assumed the authenticity of all documents submitted to us as originals, the conformity to original documents of all documents submitted to us as certified or photostatic copies and the authenticity of the originals of such latter documents. As to certain matters of fact material to the opinion expressed herein, we have relied upon certificates of various corporate officers of the Company and public officials. We assume the accuracy of the material and factual matters contained therein.

We are of the opinion that:

1. The Company is a validly organized and existing corporation under the laws of the State of Oregon, and is authorized to transact business in the State of Washington.

2. The Agreement has been duly and validly authorized, executed and delivered by the Company.

3. The Mortgage and the Indenture have been duly and validly authorized by all necessary corporate action, have been duly and validly executed and delivered, have been duly qualified under the Trust Indenture Act, and are valid and binding instruments enforceable in accordance with their terms, subject, as to enforcement, to laws and principles of equity relating to or affecting generally the enforcement of creditors’ rights, including, without limitation, bankruptcy and insolvency.

4. The form of the Secured Notes has been duly authorized and has been established in conformity with the provisions of the Mortgage and conforms to the description

IV-2

thereof contained in the Prospectus; the form of the Unsecured Notes, bearing interest at a fixed rate, has been duly authorized and has been established in conformity with the provisions of the Indenture and conforms to the description thereof contained in the Prospectus; and the form of the Unsecured Notes, bearing interest at a variable rate or not bearing interest, when set forth in a Company Order or Orders (as defined in the Indenture) or established by procedures acceptable to the Indenture Trustee specified in a Company Order or Orders, will have been duly authorized and will have been established in conformity with the provisions of the Indenture.

5. The Secured Notes have been duly authorized by the resolutions adopted by the Company’s Board of Directors on May 27, 1993, September 26, 1996, April 24, 1997, February 26, 1998, April 27, 2000, April 25, 2002 and December 18, 2003 (the “Board Resolutions”), and when the terms of the Secured Notes shall have been determined as contemplated by and in accordance with the Mortgage, the Board Resolutions and written orders or instructions evidencing determinations by Officers of the Company, such terms will have been duly authorized by the Company and will have been established in conformity with the terms of the Mortgage.

6. The Unsecured Notes have been duly authorized by the Board Resolutions, and when the terms of the Unsecured Notes shall have been determined as contemplated by and in accordance with the Indenture, the Board Resolutions and, to the extent required by the Indenture and the Board Resolutions, by Officers’ Certificates (each, as defined in the Indenture), Company Orders and procedures acceptable to the Indenture Trustee specified in such Company Orders, such terms will have been duly authorized by the Company and will have been established in conformity with the terms of the Indenture.

7. The Notes, when (a) executed by the Company, (b) completed, authenticated and delivered by the Corporate Trustee or the Indenture Trustee, as the case may be, (c) issued and delivered by the Company and (d) paid for, all as contemplated by and in accordance with the Mortgage, in the case of the Secured Notes, the Indenture, in the case of Unsecured Notes, the Board Resolutions, and (to the extent required by the Mortgage or the Indenture and the Board Resolutions) Officers’ Certificates, Company Orders, procedures acceptable to the Indenture Trustee specified in such Company Orders, written orders or instructions evidencing determinations by the officers of the Company, the Agreement, the Administrative Procedure (as defined in the Agreement) and Terms Agreements (as defined in the Agreement), if any, will be duly issued under the Mortgage or the Indenture, as the case may be, and will constitute valid and legally binding obligations of the Company, entitled to the benefits provided by the Mortgage or the Indenture, as the case may be, and enforceable in accordance with their terms, subject, as to enforcement, to laws and principles of equity relating to or affecting generally the enforcement of creditors’ rights, including, without limitation, bankruptcy and insolvency, and, in the case of the Secured Notes, entitled to the benefit of the security afforded by the Mortgage.

8. The issuance and sale of the Notes, the compliance by the Company with all of the provisions of the Notes, the Mortgage, the Indenture and the Agreement and the consummation of the transactions contemplated by the Agreement will not result in a breach or violation of any of the terms and provisions of, or constitute a default under, the Mortgage and the Indenture or the Company’s Restated Articles of Incorporation, as amended, or Bylaws, as amended.

IV-3

9. The OPUC has issued orders authorizing the issuance and sale by the Company of the Notes; and no further approval, authorization, consent or other order of any public board or body (other than in connection or in compliance with the provisions of the securities or blue sky laws of any jurisdiction and other than orders of the WUTC establishing compliance with applicable statutory provisions) is legally required for the issuance and sale of the Notes through each of you, as agent, on the terms and conditions set forth in the Agreement.

10. The Registration Statement has become effective under the 1933 Act, and, to our knowledge, no stop order suspending the effectiveness thereof has been issued and no proceedings for that purpose are pending before or have been proposed by the SEC; the Mortgage and the Indenture have been duly qualified under the Trust Indenture Act; the Registration Statement at the time it became effective complied, and the Prospectus (excluding the documents incorporated therein by reference) as of the date of this opinion complies, as to form, in all material respects with the requirements of the 1933 Act, the Trust Indenture Act (except with respect to the Forms T-1 and Form T-2, upon which we express no opinion) and the rules and regulations of the SEC thereunder; and the documents incorporated by reference in the Prospectus pursuant to Item 12 of Form S-3 (other than the financial statements and other financial or statistical data contained therein, upon which we express no opinion), as of their respective dates of filing, complied as to form in all material respects with the requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the rules and regulations of the SEC thereunder.

In the course of the preparation by the Company of the Registration Statement and the Prospectus, we had conferences with certain officers and employees of the Company, with the counsel for the Company and with you and your counsel, but we made no independent verification of the accuracy or completeness of the representations and statements made to us by such persons or the information included by the Company in the Registration Statement and the Prospectus and take no responsibility therefor, except insofar as set forth in paragraph 4 hereof. In passing upon the form of the Registration Statement and the Prospectus we have, therefore, assumed the accuracy and completeness of such representations, statements and information, except as aforesaid. However, our examination of the Registration Statement and the Prospectus and our discussions in the above-mentioned conferences did not disclose to us any information which gives us reason to believe that, when the Registration Statement became effective, it contained an untrue statement of a material fact or omitted to state a material fact required to be stated therein or necessary to make the statements therein not misleading, or that, as of the date of this opinion, the Prospectus includes an untrue statement of a material fact or omits to state a material fact necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading; provided, that we do not express any belief as to the financial statements or other financial or statistical data contained in the Registration Statement or the Prospectus, or as to the Forms T-1 or T-2, or as to any information contained therein furnished to the Company in writing by any of you expressly for use therein.

This opinion is limited to the facts and law at the date hereof. In rendering the opinions set forth in paragraphs 7 and 9 above, we have necessarily assumed that, at the time of

IV-4

any issuance, sale and delivery of a Note (i) the Board of Directors of the Company (or any committee thereof acting pursuant to authority properly delegated to such committee by the Board of Directors) has not taken any action to rescind or otherwise reduce its prior authorization of the issuance of the Notes and an officer of the Company, as stated in the resolutions of the Board of Directors (or any such committee) relating to the Notes, has executed and delivered such Notes, (ii) the WUTC has issued an order or orders establishing compliance with applicable statutory provisions with respect to the issuance and sale of such Note, (iii) the orders of the OPUC and the WUTC with respect to the Notes being sold remain in full force and effect and have not been modified or amended by the OPUC or the WUTC, respectively, and the Company complies with the terms of such orders and (iv) the order of the SEC with respect to the Registration Statement, the Mortgage and the Indenture remains in full force and effect and has not been modified or amended by the SEC.

We do not express any opinion herein concerning any law other than the laws of the State of Oregon, the State of Washington and the Federal laws of the United States. Accordingly, in rendering this opinion, we have relied, with your consent, as to all matters governed by the laws of the State of Oregon, upon the opinion of even date herewith addressed to you by C.J. Rue, Esq., counsel for the Company, and, as to all matters governed by the laws of the State of Washington, upon the opinion of Stoel Rives LLP, special Washington counsel to the Company. We understand that you are relying upon the opinions of C.J. Rue, Esq., and Stoel Rives LLP as to all matters governed by the laws of the State of Oregon and Washington, as the case may be, including titles to property and franchises and the lien of the Mortgage, upon which we express no opinion.

You, the Trustees, and as to matters governed by the laws of the State of New York and the 1933 Act, the Exchange Act and the Trust Indenture Act, C.J. Rue, Esq., may rely upon this opinion in connection with the issuance and sale of the Notes. Neither you nor any of them may rely upon this opinion for any other purpose, and no other person may rely upon this opinion for any purpose without, in each case, our prior written consent.

Very truly yours,

THELEN REID BROWN RAYSMAN &

STEINER LLP

IV-5

ANNEX V

[Letterhead of Stoel Rives LLP]

            [Date]

Merrill Lynch, Pierce, Fenner & Smith

Incorporated

4 World Financial Center

15th Floor

New York, New York 10080

UBS Securities LLC

677 Washington Blvd.

Stamford, Connecticut 06901

J.P. Morgan Securities Inc.

270 Park Avenue

New York, New York 10017

Piper Jaffray & Co.

800 Nicollet Mall

Minneapolis, Minnesota 55402

Ladies and Gentlemen:

With reference to the issuance and sale from time-to-time by Northwest Natural Gas Company (the “Company”), pursuant to the Distribution Agreement, dated September 28, 2004, amended and restated on December 7, 2006 (the “Agreement”), between the Company and each of you, of not to exceed $160,000,000 in aggregate principal amount of (i) the Company’s First Mortgage Bonds, designated Secured Medium-Term Notes, Series B (the “Secured Notes”) to be issued under the Company’s Mortgage and Deed of Trust, dated as of July 1, 1946, to Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) (the “Corporate Trustee”) and R.G. Page (Stanley Burg, successor), as trustees, as supplemented by twenty supplemental indentures (such Mortgage and Deed of Trust, as so supplemented, being hereinafter called the “Mortgage”), and (ii) the Company’s Unsecured Medium-Term Notes, Series B (the “Unsecured Notes”), to be issued under the Company’s Indenture, dated as of June 1, 1991 (the “Indenture”), to Deutsche Bank Trust Company Americas, as trustee (the “Indenture Trustee”) (the Secured Notes and the Unsecured Notes being hereinafter collectively referred to as the “Notes”), and the appointment of each of you as agents of the Company pursuant to the Agreement for the purposes of soliciting and receiving offers to purchase Notes, as agents, and purchasing Notes, as principals, from the Company, please be advised that, as special Washington counsel to the Company, we have reviewed (a) the

Mortgage; (b) the Indenture; (c) the Agreement; and (d) the proceedings before the Washington Utilities and Transportation Commission (the “WUTC”) relating to the issuance and sale of the Notes. We have also examined such other documents and satisfied ourselves as to such other matters as we have deemed necessary in order to render this opinion. We have not examined the Notes, except for forms thereof.

In preparation of this opinion, we have examined originals or photostatic copies of such certificates, agreements, documents and other papers, and have made such inquiries and investigations of law, as we deemed appropriate and necessary for the opinion hereinafter set forth. In our examination, we have assumed the authenticity of all documents submitted to us as certified or photostatic copies and the authenticity of the originals of such latter documents. We have also assumed that the Mortgage, the Indenture and the Agreement have been duly authorized, executed and delivered by, and are legally binding on, each of the parties thereto.

As to certain matters of fact material to the opinion expressed herein, we have relied upon certificates of various corporate officers of the Company and public officials. We assume the accuracy of the material and factual matters contained therein.

Based upon the foregoing and subject to the following qualifications, we are of the opinion that:

1. The Company is authorized to transact business in the State of Washington.

2. The Mortgage constitutes a first security interest on all of the personal properties and fixtures owned by the Company in the State of Washington that are described in the Mortgage and are intended to be subject to the lien thereof, subject only to Excepted Encumbrances (as defined in the Mortgage); and the description in the Mortgage of such properties and fixtures is adequate to constitute the Mortgage a security interest thereon.

3. The Company has good and sufficient title to all of the real properties owned by the Company in the State of Washington that are described in the Mortgage and intended to be subject to the lien thereof, subject only to Excepted Encumbrances (as defined in the Mortgage) and to minor defects and irregularities of the nature customarily found in properties of like size and character; the description in the Mortgage of such properties is adequate to constitute the Mortgage a lien thereon; and the Mortgage is a valid first mortgage lien on such properties, subject to the exceptions noted above in this paragraph 3.

4. The issuance and sale of the Notes, the compliance by the Company with all of the provisions of the Notes, the Mortgage, the Indenture and the Agreement and the consummation of the transactions contemplated by the Agreement will not violate any law, rule or regulation of the State of Washington or any political subdivision thereof known to us to be applicable to the Company.

This opinion is limited to the facts and law at the date hereof. In rendering the opinions set forth in paragraph 4 above, we have necessarily assumed that, at the time of any issuance, sale and delivery of a Note (i) the Board of Directors of the Company (or any committee thereof acting pursuant to authority properly delegated to such committee by the Board of Directors) has not taken any action to rescind or otherwise reduce its prior authorization

V-2

of the issuance of the Notes and an officer of the Company, as stated in the resolutions of the Board of Directors (or any such committee) relating to the Notes, has executed and delivered such Notes, (ii) the WUTC has issued an order or orders establishing compliance with applicable statutory provisions with respect to the issuance and sale of such Note, and (iii) that each such order of the WUTC with respect to the Notes being sold remains in full force and effect and has not been modified or amended by the WUTC and the Company complies with the terms of each such order.

We do not express any opinion herein concerning any laws other than the laws of the State of Washington.

In giving the foregoing opinions, we express no opinion as to any securities or blue sky laws of any jurisdiction.

You, the Trustees, C.J. Rue, Esq., counsel for the Company, Thelen Reid Brown Raysman & Steiner, counsel to the Company, and your counsel, Simpson Thacher & Bartlett LLP, as to matters governed by the laws of the State of Washington, may rely upon this opinion in connection with the issuance and sale of the Notes. Neither you nor any of them may rely upon this opinion for any other purpose, and no other person may rely upon this opinion for any purpose without, in each case, our prior written consent.

Very truly yours,

STOEL RIVES LLP

V-3

ANNEX VI

[Contents of Letter of Independent Registered Public Accounting Firm]

The letter of each independent registered public accounting firm will state in effect that, for the periods during which such firm was the independent registered public accounting firm for the Company:

1. They are an independent registered public accounting firm with respect to the Company within the meaning of the Act and the applicable published Rules and Regulations;

2. In their opinion, the financial statements examined by them and incorporated by reference in the Registration Statement comply as to form in all material respects with the applicable accounting requirements of the Exchange Act and the published rules and regulations thereunder;

3. On the basis of limited procedures, not constituting an examination made in accordance with generally accepted auditing standards, including a reading of the latest available interim financial statements of the Company, if any, a reading of the minute books of the Company since December 31, 2005, inquiries of officials of the Company responsible for financial and accounting matters and such other inquiries and procedures as may be specified in such letter, nothing came to their attention that caused them to believe that:

(a)(1) the latest interim consolidated financial statements included or incorporated by reference in the Registration Statement do not comply as to form in all material respects with the applicable accounting requirements of the Exchange Act and the published rules and regulations thereunder as they apply to Form 10-Q or (2) said interim consolidated financial statements are not in conformity with generally accepted accounting principles applied on a basis substantially consistent with that of the audited consolidated financial statements incorporated by reference in the Registration Statement;

(b) at the date of the latest available interim balance sheet of the Company and at a subsequent specified date not more than five days prior to the Time of Delivery, there has been any change in the capital stock (except for (i) shares of the Company’s Common Stock issued under the Company’s Dividend Reinvestment Plan, Restated Stock Option Plan or Employee Stock Purchase Plan and (ii) shares of Common Stock repurchased pursuant to the Company’s Repurchase Program) or any increase in the long-term debt of the Company, or any decrease in net assets, in each case as compared with amounts shown in the balance sheet as of the date of the latest financial statements incorporated by reference in the Registration Statement, except in each case for changes, increases or decreases which the Registration Statement discloses have occurred or may occur, which were occasioned by the declaration of dividends or which are described in such letter; or

(c) for the latest period for which financial information is available subsequent to the latest financial statements included or incorporated by reference in the Prospectus, there were any decreases in operating revenues, net income and earnings available for common stock, as compared to the corresponding period in the prior year,

except in each case for decreases which the Registration Statement discloses have occurred or may occur, which were occasioned by the declaration of dividends or which are described in such letter; and

4. They have performed certain other specified procedures with respect to certain amounts and percentages set forth in the Registration Statement or in the documents incorporated by reference therein, as have been requested by your counsel and approved by the Company, and have found them to be in agreement with the records of the Company and the computations to be arithmetically correct.

VI-2

ANNEX VII

[Letterhead of Stoel Rives LLP]

            [Date]

Merrill Lynch, Pierce, Fenner & Smith

Incorporated

4 World Financial Center

15th Floor

New York, New York 10080

UBS Securities LLC

677 Washington Blvd.

Stamford, Connecticut 06901

J.P. Morgan Securities Inc.

270 Park Avenue

New York, New York 10017

Piper Jaffray & Co.

800 Nicollet Mall

Minneapolis, Minnesota 55402

Ladies and Gentlemen:

With reference to the issuance and sale from time-to-time by Northwest Natural Gas Company (the “Company”), pursuant to the Distribution Agreement, dated September 28, 2004, amended and restated on December 7, 2006 (the “Agreement”), between the Company and each of you, of not to exceed $160,000,000 in aggregate principal amount of (i) the Company’s First Mortgage Bonds, designated Secured Medium-Term Notes, Series B (the “Secured Notes”) to be issued under the Company’s Mortgage and Deed of Trust, dated as of July 1, 1946, to Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company) (the “Corporate Trustee”) and R.G. Page (Stanley Burg, successor), as trustees, as supplemented by twenty supplemental indentures (such Mortgage and Deed of Trust, as so supplemented, being hereinafter called the “Mortgage”), and (ii) the Company’s Unsecured Medium-Term Notes, Series B (the “Unsecured Notes”), to be issued under the Company’s Indenture, dated as of June 1, 1991 (the “Indenture”), to Deutsche Bank Trust Company Americas, as trustee (the “Indenture Trustee”) (the Secured Notes and the Unsecured Notes being hereinafter collectively referred to as the “Notes”), and the appointment of each of you as agents of the Company pursuant to the Agreement for the purposes of soliciting and receiving offers to purchase Notes, as agents, and purchasing Notes, as principals, from the Company, please be advised that, as special Washington counsel to the Company, we have reviewed (a) the

Mortgage; (b) the Indenture; (c) the Agreement; and (d) the proceedings before the Washington Utilities and Transportation Commission (the “WUTC”) relating to the issuance and sale of the Notes. We have also examined such other documents and satisfied ourselves as to such other matters as we have deemed necessary in order to render this opinion. We have not examined the Notes, except for forms thereof.

In preparation of this opinion, we have examined originals or photostatic copies of such certificates, agreements, documents and other papers, and have made such inquiries and investigations of law, as we deemed appropriate and necessary for the opinion hereinafter set forth. In our examination, we have assumed the authenticity of all documents submitted to us as certified or photostatic copies and the authenticity of the originals of such latter documents. We have also assumed that the Mortgage, the Indenture and the Agreement have been duly authorized, executed and delivered by, and are legally binding on, each of the parties thereto.

As to certain matters of fact material to the opinion expressed herein, we have relied upon certificates of various corporate officers of the Company and public officials. We assume the accuracy of the material and factual matters contained therein.

Based upon the foregoing and subject to the following qualifications, we are of the opinion that the WUTC has issued an order dated                 , 200   in Docket     -            , establishing compliance with applicable statutory provisions with respect to the issuance and sale by the Company of up to $             aggregate principal amount of the Notes; and under the laws of the State of Washington, no further approval, authorization, consent or other order of any public board or body is legally required for the issuance and sale of such Notes through each of you, as agent, on the terms and conditions set forth in the Agreement.

This opinion is limited to the facts and law at the date hereof. In rendering the opinions set forth above, we have necessarily assumed that, at the time of any issuance, sale and delivery of a Note (i) the Board of Directors of the Company (or any committee thereof acting pursuant to authority properly delegated to such committee by the Board of Directors) has not taken any action to rescind or otherwise reduce its prior authorization of the issuance of the Notes as stated in the resolutions of the Board of Directors (or any such committee) relating to the Notes, and an officer of the Company has executed and delivered such Notes and (ii) each order of the WUTC with respect to the Notes being sold remains in full force and effect and has not been modified or amended by the WUTC and the Company complies with the terms of each such order.

We are members of the bar of the State of Washington and do not express any opinion herein concerning any laws other than the laws of the State of Washington.

In giving the foregoing opinions, we express no opinion as to any securities or blue sky laws of any jurisdiction.

You, the Trustees, C.J. Rue, Esq., counsel for the Company, Thelen Reid Brown Raysman & Steiner LLP, counsel to the Company, and your counsel, Simpson Thacher & Bartlett LLP, as to matters governed by the laws of the State of Washington, may rely upon this opinion in connection with the issuance and sale of the Notes. Neither you nor any of them may rely upon this opinion for any other purpose, and no other person may rely upon this opinion for any purpose without, in each case, our prior written consent.

Very truly yours,

STOEL RIVES LLP

VII-2

ANNEX VIII

Filing under Rule 433

Dated                                     

Registration No. 333-112604

$160,000,000

NORTHWEST NATURAL GAS COMPANY

Secured Medium-Term Notes, Series B

(A Series of First Mortgage Bonds)

and

Unsecured Medium-Term Notes, Series B

Due from Nine Months to 30 Years from Date of Issue

CUSIP No.: 66765R	Stated interest rate (%):         %
Secured          Unsecured	Maturity date:
Principal amount ($): $	Original issue date:
Issue price (%):	Interest payment dates:              and             , commencing
Net proceeds to Company ($):
	Redeemable: Yes      No          In whole
Repayable at the option of holder: Yes      No	In whole or in part
	Fixed redemption price: Yes      No
Repayment Date:
	Initial redemption date:
Repayment Price:
	Initial redemption price:
Election Period:
	Reduction Percentage:
Selling Agent(s):
	Redemption limitation date:
Type of Transaction:
	Make-Whole Redemption Price: Yes      No
[Agency Transaction] [Principal Transaction]
	Make-Whole Spread:

[The issuer has filed a registration statement (including a prospectus) with the Securities and Exchange Commission for the offering to which this communication relates. Before you invest, you should read the prospectus in that registration statement and other documents the issuer has filed with the Securities and Exchange Commission for more complete information about the issuer and this offering. You may get these documents for free by visiting EDGAR on the Securities and Exchange Commission’s Web site at www.sec.gov. Alternatively, the issuer, any underwriter or any dealer participating in the offering will arrange to send you the prospectus if you request it by calling [Merrill Lynch, Pierce, Fenner & Smith Incorporated toll-free at             ,] [UBS Securities LLC toll-free at                 ,] [J.P. Morgan Securities Inc. toll-free at             ] [Piper Jaffray & Co. toll-free at                 .]]

VIII-1

Exhibit 1

Northwest Natural Gas Company

$                    

Medium-Term Notes, Series B

                ,         

Merrill Lynch, Pierce, Fenner & Smith

Incorporated

4 World Financial Center

15th Floor

New York, New York 10080

UBS Securities LLC

677 Washington Blvd.

Stamford, Connecticut 06901

J.P. Morgan Securities Inc.

270 Park Avenue

New York, New York 10017

Piper Jaffray & Co.

800 Nicollet Mall

Minneapolis, Minnesota 55402

[Insert Names of Additional Existing Agents, if any]

[Insert Name of New Agent]

Ladies and Gentlemen:

Reference is hereby made to the Distribution Agreement, dated September 28, 2004, amended and restated on December 7, 2006 (the “Distribution Agreement”), a copy of which has previously been delivered to you, between Northwest Natural Gas Company, an Oregon corporation (the “Company”), and each of Merrill Lynch, Pierce, Fenner & Smith Incorporated, UBS Securities LLC, J.P. Morgan Securities Inc., Piper Jaffray & Co. and [Insert Names of Additional Existing Agents, if any], with respect to the issue and sale by the Company of its First Mortgage Bonds, designated Secured Medium-Term Notes, Series B, and its Unsecured Medium-Term Notes, Series B (collectively, the “Securities”). Capitalized terms used herein without definition shall have the meanings assigned to them in the Distribution Agreement.

Subject to the terms and conditions set forth in the Distribution Agreement, the Company hereby appoints [Insert Name of New Agent] as agent of the Company for the purpose of soliciting and receiving offers to purchase the Securities. In connection with such appointment, [Insert Name of New Agent] is hereby entitled to the benefits and subject to the duties of an Agent under the terms and conditions of the Distribution Agreement (including the Administrative Procedures) and by its execution hereof is hereby made a party to the Distribution Agreement. In connection with such appointment, [Insert Name of New Agent] shall receive as of the date hereof: [To be agreed upon by the Company and the New Agent]

Any communication under the Distribution Agreement will be made in accordance with Section 12 of the Distribution Agreement, and if to [Insert Name of New Agent] shall be sufficient in all respects when delivered or sent by facsimile transmission or registered mail to [Insert Address of New Agent], attention: [Insert Name], facsimile transmission number [Insert New Agent Number].

This Agreement may be executed in any number of counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.

If the foregoing correctly sets forth our agreement, please indicate your acceptance hereof in the space provided for that purpose below.

Very truly yours,

NORTHWEST NATURAL GAS COMPANY

By:

Title:

The foregoing Agreement is hereby confirmed and accepted as of the date hereof.

[INSERT NAME OF NEW AGENT]

By:

Title:

2

EX-10.(C)

Exhibit 10C

NORTHWEST NATURAL GAS COMPANY

RESTATED STOCK OPTION PLAN

(as amended as of December 14, 2006)

1. Purpose. The purpose of this Restated Stock Option Plan, formerly referred to as the 1985 Stock Option Plan (the “Plan”), is to enable Northwest Natural Gas Company (the “Company”) to attract and retain experienced and able employees and to provide additional incentive to these employees to exert their best efforts for the Company and its shareholders.

2. Shares Subject to the Plan. Except as provided in paragraph 10, the total number of shares of the Company’s Common Stock, $3- ¹/6 par value per share (“Common Stock”), covered by all options granted under the Plan shall not exceed 2,400,000 authorized but unissued or reacquired shares. If any option under the Plan expires or is cancelled or terminated and is unexercised in whole or in part, the shares allocable to the unexercised portion shall again become available for options under the Plan.

3. Duration of the Plan. The Plan shall continue until options have been granted and exercised with respect to all of the shares available for the Plan under paragraph 2 (subject to any adjustments under paragraph 10), unless sooner terminated by action of the Board of Directors. The Board of Directors has the right to suspend or terminate the Plan at any time except with respect to then outstanding options.

4. Administration.

4.1 Board of Directors. The Plan shall be administered by the Board of Directors, which shall determine and designate from time to time the employees to whom options shall be granted and the number of shares, option price, the period of each option, the time or times at which options may be exercised, and any other term of the grant, all of which shall be set forth in an option agreement between the Company and the optionee. Subject to the provisions of the Plan, the Board of Directors may from time to time adopt rules and regulations relating to administration of the Plan, and the interpretation and construction of the provisions of the Plan by the Board of Directors shall be final and conclusive.

4.2 Committee. The Board of Directors may delegate to any committee of the Board of Directors (the “Committee”) any or all authority for administration of the Plan. Members of the Committee are not eligible to receive an option pursuant to the Plan while on the Committee. If a Committee is appointed, all references to the Board of Directors in the Plan shall mean and relate to the Committee except (i) as otherwise provided by the Board of Directors and (ii) that only the Board of Directors may terminate or amend the Plan as provided in paragraphs 3 and 11.

5. Eligibility; Grants.

5.1 Eligibility. Options may be granted under the Plan only to officers and other employees (including employees who are directors) of the Company or any parent or subsidiary of the Company.

5.2 Grants. Options granted under the Plan may be Incentive Stock Options as defined in §422 of the Internal Revenue Code of 1986, as amended (“IRC”), or Non-Statutory Stock Options. A Non-Statutory Stock Option means an option other than an Incentive Stock Option. The Board of Directors has the sole discretion to determine which options shall be Incentive Stock Options and which options shall be Non-Statutory Stock Options, and, at the time of grant, it shall specifically designate each option granted under the Plan as an Incentive Stock Option or a Non-Statutory Stock Option. In the case of Incentive Stock Options, all terms shall be consistent with the requirements of the IRC and applicable regulations. No Incentive Stock Option may be granted under the Plan on or after the tenth anniversary of the last action by the Board of Directors approving an increase in the number of shares available for issuance under the Plan, which action was subsequently approved within 12 months by the shareholders.

6. Limitation on Amount of Grants. No employee may be granted options under the Plan for more than 200,000 shares of Common Stock in any fiscal year.

7. Option Price. The option price per share under each option granted under the Plan shall be determined by the Board of Directors, but the option price for an Incentive Stock Option and a Non-Statutory Stock Option shall be not less than 100 percent of the fair market value of the shares covered by the option on the date the option is granted. Except as otherwise expressly provided, for purposes of the Plan, the fair market value shall be deemed to be the closing sales price for the Common Stock as reported by the New York Stock Exchange and published in the Wall Street Journal for the date the option is granted, or such other fair market value of the Common Stock as determined by the Board of Directors of the Company.

8. Duration of Options. Each option granted under the Plan shall continue in effect for the period fixed by the Board of Directors, except that no Incentive Stock Option shall be exercisable after the expiration of 10 years from the date it is granted and no Non-Statutory Stock Option shall be exercisable after the expiration of 10 years plus seven days from the date it is granted.

9. Nonassignability. Except as otherwise provided by the Board of Directors, each option granted under the Plan by its terms shall be nonassignable and nontransferable by the optionee except by will or by the laws of descent and distribution of the state or country of the optionee’s domicile at the time of death, and each option by its terms shall be exercisable during the optionee’s lifetime only by the optionee.

10. Changes in Capital Structure. If the outstanding shares of Common Stock are increased or decreased or changed into or exchanged for a different number or kind of shares or other securities of the Company or of another corporation, by reason of any reorganization, merger, consolidation, plan of exchange, recapitalization, reclassification, stock split-up,

2

combination of shares, or dividend payable in shares, appropriate adjustment shall be made by the Board of Directors in the number and kind of shares for the purchase of which options may be granted under the Plan and in all other share amounts set forth in the Plan. Any such adjustment made by the Board of Directors shall be conclusive.

11. Amendment of Plan. The Board of Directors may at any time and from time to time modify or amend the Plan in such respects as it deems advisable because of changes in the law while the Plan is in effect or for any other reason. After the Plan has been approved by the shareholders and except as provided in the applicable option agreement, however, no change in an option already granted to an employee shall be made without the written consent of such employee. Furthermore, unless approved at an annual meeting or a special meeting by a vote of shareholders in accordance with Oregon law, no amendment or change shall be made in the Plan (a) increasing the total number of shares which may be purchased under the Plan, (b) changing the minimum purchase price specified in the Plan, (c) increasing the maximum option period, or (d) materially modifying the requirements for eligibility for participation in the Plan.

12. Approvals. The obligations of the Company under the Plan are subject to the approval of the Oregon Public Utility Commission, the Washington Utilities and Transportation Commission, and such other state and federal authorities or agencies with jurisdiction in the matter. The Company will use its best efforts to take steps required by state or federal law or applicable regulations, including rules and regulations of the Securities and Exchange Commission and any stock exchange on which the Company’s shares may then be listed, in connection with the granting of any option under the Plan, the issuance or sale of any shares purchased on exercise of any option under the Plan, or the listing of such shares on said exchange. The foregoing notwithstanding, the Company shall not be obligated to issue or deliver shares of Common Stock under the Plan if the Company is advised by its legal counsel that such issuance or delivery would violate applicable state or federal laws. The Company shall not be obligated to register shares issuable on exercise of options under the Securities Act of 1933.

13. Employment Rights. Nothing in the Plan or any option granted pursuant to the Plan shall confer on any optionee any right to be continued in the employment of the Company or to interfere in any way with the right of the Company by whom such optionee is employed to terminate such optionee’s employment at any time, with or without cause.

3

EX-11

EXHIBIT 11

NORTHWEST NATURAL GAS COMPANY

Statement Re: Computation of Per Share Earnings

Thousands, except per share amounts

(Unaudited)

	12 Months Ended December 31,
	2006		2005		2004
Net income	$	63,415	$	58,149	$	50,572
Convertible debenture interest less taxes		—		—		200
Net income - diluted	$	63,415	$	58,149	$	50,772
Average common shares outstanding - basic		27,540		27,564		27,016
Stock-based compensation		117		57		40
Convertible debentures		—		—		227
Average common shares outstanding - diluted		27,657		27,621		27,283
Earnings per share of common stock - basic	$	2.30	$	2.11	$	1.87
Earnings per share of common stock - diluted	$	2.29	$	2.11	$	1.86

For the years ended December 31, 2006, 2005 and 2004, 105,600 shares, 6,000 shares and 201,800 shares, respectively, represent the number of stock options which were excluded from the calculation of diluted earnings per share because the effect was antidilutive.

EX-12

EXHIBIT 12

NORTHWEST NATURAL GAS COMPANY

Statement Re: Ratio of Earnings to Fixed Charges

Thousands, except per share amounts

(Unaudited)

	Year Ended Dec. 31,
	2006		2005		2004		2003		2002
Fixed Charges, as defined:
Interest on Long-Term Debt	$	34,651	$	34,330	$	33,776	$	33,258	$	32,264
Other Interest		4,648		2,665		2,184		2,048		1,620
Amortization of Debt Discount and Expense		716		808		773		696		799
Interest Portion of Rentals		1,465		1,357		1,489		1,622		1,578
Total Fixed Charges, as defined	$	41,480	$	39,160	$	38,222	$	37,624	$	36,261
Earnings, as defined:
Net Income	$	63,415	$	58,149	$	50,572	$	45,983	$	43,792
Taxes on Income		36,234		32,720		26,531		23,340		23,444
Fixed Charges, as above		41,480		39,160		38,222		37,624		36,261
Total Earnings, as defined	$	141,129	$	130,029	$	115,325	$	106,947	$	103,497
Ratio of Earnings to Fixed Charges		3.40		3.32		3.02		2.84		2.85

EX-23

EXHIBIT 23

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 33-63017, 333-46430, 333-55002, 333-70218, 333-100885, and 333-120955, 333-134973 and 333-139819, and Post-Effective Amendment No. 1 to Registration Statement No. 2-76276) and in the Registration Statements on Form S-3 (Nos. 33-53795, 333-68184, 333-112604, and 333-123898, and Post-Effective Amendment No. 1 to Registration Statement Nos. 33-1304 and 33-20384) of Northwest Natural Gas Company of our report dated February 28, 2007 relating to the consolidated financial statements, financial statement schedule, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Portland, Oregon

February 28, 2007

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Mark S. Dodson, certify that:

1. I have reviewed this annual report on Form 10-K of Northwest Natural Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2007

/s/ Mark S. Dodson

Mark S. Dodson

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, David H. Anderson, certify that:

1. I have reviewed this annual report on Form 10-K of Northwest Natural Gas Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 28, 2007

/s/ David H. Anderson

David H. Anderson

Senior Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

NORTHWEST NATURAL GAS COMPANY

Certificate Pursuant to Section 906

of Sarbanes – Oxley Act of 2002

Each of the undersigned, MARK S. DODSON, the President and Chief Executive Officer, and DAVID H. ANDERSON, the Senior Vice President and Chief Financial Officer, of NORTHWEST NATURAL GAS COMPANY (the Company), DOES HEREBY CERTIFY that:

1. The Company’s Annual Report on Form 10-K for the year ended December 31, 2006 (the Report) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. Information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company.

IN WITNESS WHEREOF, each of the undersigned has caused this instrument to be executed this 28th day of February 2007.

/s/ Mark S. Dodson

President and

Chief Executive Officer

/s/ David H. Anderson

Senior Vice President and

Chief Financial Officer

A signed original of this written statement required by Section 906 has been provided to Northwest Natural Gas Company and will be retained by Northwest Natural Gas Company and furnished to the Securities and Exchange Commission or its staff upon request.