NORTHWEST NATURAL GAS CO - 10-K Annual Report

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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 [ X ]

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

As of June 30, 2004, the registrant had 27,335,881 shares of its Common Stock, $3 1/6 par value, 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 $826,438,828.

Indicate number of shares outstanding of each of registrant’s classes of common stock as of February 23, 2005:

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 2005 Annual Meeting of Shareholders, are incorporated by reference in Part III.

Basic earnings per share: earnings applicable to common stock for a period, divided by the average number of shares of common stock actually 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 distribution company; usually considered only by large industrial users.

Core utility customers: residential, commercial and industrial firm service customers on the Company’s distribution system.

Decoupling: a rate mechanism approved by the OPUC, which is designed to break the link between NW Natural’s earnings and the quantity of natural gas consumed by its customers. The design allows NW Natural 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 full 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 12º F, the coldest day in the last 20 years in NW Natural’s 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 if all securities convertible into common stock were converted and all options to purchase common stock at prices lower than the average price for the period were exercised.

Firm service: natural gas service offered to customers under contracts or rate schedules that provide for no service interruptions.

General rate case: a periodic filing with state regulators to establish equitable rates and balance the interests of all classes of customers with those of the Company and its shareholders. NW Natural’s most recent general rate cases were concluded in Oregon in 2003 and Washington in 2004.

Interruptible service: service offered to customers (usually large commercial or industrial) under contracts or rate schedules that allow for interruptions during times of peak demand.

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: in NW Natural’s case, the difference between gross sales revenue and the cost of gas included in the sale.

Purchased Gas Adjustment (PGA): purchased gas adjustment, also know as the gas tracker, is a mechanism for adjusting rates due to changes in gas costs and recovering from customers deferred gas cost imbalances caused by fluctuating 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 rate approved by a regulatory agency for company investments funded by common stock equity.

Storage: a means of maintaining gas in reserve for future demand, either through injection into a storage field, or storing it in the form of liquefied natural gas, or by holding it within the pipeline (known as line packing).

Therm: the basic unit of natural gas measurement, equal to 100,000 Btu’s. An average residential customer in NW Natural’s 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 only for use of the distribution system to transport it.

Underground storage: storage of natural gas by injection into underground rock formations for withdrawal during the winter heating season, such as at NW Natural’s Mist storage field.

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.

Northwest Natural Gas Company (NW Natural or the Company) was incorporated under the laws of Oregon in 1910. The Company and its predecessors have supplied gas service to the public since 1859. Since September 1997, it has been doing business as NW Natural.

NW Natural is principally engaged in the distribution of natural gas in Oregon and southwest Washington. In this report this principal business segment is referred to as local gas distribution (LDC) or utility. Local gas distribution involves purchasing gas from producers, transporting the gas over interstate pipelines from the supply basins to the Company’s service territory, and reselling the gas to customers at rates and terms approved by the Public Utility Commission of Oregon (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 97 percent of the Company’s consolidated assets are related to the local gas distribution segment. The OPUC has allocated to NW Natural as its 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. NW Natural also holds certificates from the WUTC granting it exclusive rights to serve portions of three southern Washington counties bordering the Columbia River. Gas service is provided in 120 cities and neighboring communities, in 15 Oregon counties, and 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 2004, NW Natural had 537,152 residential customers, 58,548 commercial customers and 935 industrial customers. Approximately 90 percent of the Company’s customers are located in Oregon and 10 percent reside 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.

The Interstate Gas Storage business segment is comprised of interstate storage services and third party optimization services. Approximately 2 percent of the Company’s consolidated assets are related to the Interstate Gas Storage business segment. For each of the years ended Dec. 31, 2004, 2003 and 2002, this business segment derived a majority of its revenues from fewer than five customers. The largest of these customers is served under a long-term contract.

Interstate Storage Services. NW Natural is engaged in providing natural gas storage and related transportation services to interstate customers using storage capacity that has been developed in advance of core utility customers’ (residential, commercial and industrial firm) requirements. These services began in 2001 when the Federal Energy Regulatory Commission (FERC) granted NW Natural a limited jurisdiction blanket certificate permitting it to provide firm and interruptible gas storage service and related transportation service to and from the Mist gas storage facility to customers in interstate commerce. The FERC limited jurisdiction certificate enables NW Natural to provide these services while retaining its exemption from full FERC jurisdiction under the Natural Gas Act pursuant to an order of the Federal Power Commission (now the FERC). Under agreements with the OPUC and WUTC, NW Natural shares with its core utility customers a portion of its net income before tax from interstate storage services.

Third Party Optimization Services. NW Natural has a contract with an independent energy marketing company that optimizes the value of NW Natural’s assets by engaging in trading activities using temporarily unused portions of its upstream pipeline transportation capacity and gas storage capacity (optimization services).

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

NW Natural has non-regulated subsidiary investments in NNG Financial Corporation (Financial Corporation) and Northwest Energy Corporation (Northwest Energy) (see “Subsidiaries,” below), a Boeing 737-300 aircraft leased to Continental Airlines and miscellaneous other non-regulated activities. Less than 1 percent of the Company’s consolidated assets are related to activities in the Other business segment.

The Company operated only one direct, active subsidiary during 2004, Financial Corporation. Financial Corporation, a wholly-owned subsidiary of the Company 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. On Jan. 31, 2005, Financial Corporation sold its limited partnership interests in three solar electric generating plants located in California. Financial 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. KB Pipeline operated the pipeline until Dec. 1, 2004, when a third party gas distribution company assumed responsibilities as operator. KB Pipeline resigned as pipeline operator, in part, because of anticipated increased obligations resulting from FERC’s final regulations implementing Standards of Conduct for Transmission Providers (Standards of Conduct). Those regulations govern the relationship between interstate natural gas pipelines and their energy affiliates or marketing functions and impose

obligations previously not applicable to KB Pipeline with regard to separation of duties and related matters. FERC granted KB Pipeline an exemption from most of the requirements of the Standards of Conduct; however, the remainder of the regulations continue to be applicable to KB Pipeline as a co-owner of the pipeline.

A second direct, wholly-owned subsidiary of the Company, Northwest Energy, also an Oregon corporation, was formed in 2001 to serve as the holding company of NW Natural and Portland General Electric Company (PGE) if the proposed acquisition of PGE had been completed. The Company’s agreement to purchase PGE was terminated in 2002. Northwest Energy had no operations in 2004 or 2003.

NW Natural meets the needs of its core utility customers through natural gas purchases from a variety of suppliers. NW Natural has a diverse portfolio of short-, medium- and long-term firm gas supply contracts that it supplements, during periods of peak demand, with gas from storage facilities either owned by or contractually committed to NW Natural.

To achieve those goals, NW Natural employs a gas purchasing strategy based upon (i) diversity of supply, (ii) liquidity, (iii) price risk management, (iv) asset optimization and (v) regulatory alignment.

Diversity of Supply. NW Natural’s 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 and transportation-only service.

There are three means by which NW Natural diversifies its gas supply acquisitions: (i) regional supply basin, (ii) contract types and (iii) contract duration.

The following table represents the actual and target sources of regional supply:

NW Natural believes that gas supplies available from suppliers in the western United States and Canada are adequate to serve its core utility customers for the foreseeable future, and that its cost of gas generally will track market prices.

NW Natural typically enters into gas purchase contracts for (i) year-round baseload, (ii) November–March (winter heating season) baseload, (iii) winter heating season contracts where NW Natural has the option to call on all, some or none of the supplies on a daily basis, and (iv) 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 NW Natural on a daily basis, and seasonal exchange purchase and sale contracts. NW Natural seeks to minimize amounts to be purchased on the spot market during the winter heating season to less than 10 percent. A variety of multi-year contract durations are used to avoid having to re-contract all supplies every year. NW Natural recently transitioned from a majority of long-term contracts to medium-term contracts, as the long-term contracts expired. See “Core Market Basic Supply,” below.

Liquidity. NW Natural purchases its gas supplies at liquid trading points to facilitate competition and transparent pricing. These trading points include NOVA Inventory Transfer (NIT) in Alberta, Sumas and Station 2 in British Columbia, and receipt points in the Rocky Mountains.

Price Risk Management. There are four general methods that NW Natural currently uses for managing gas commodity price risk: (i) negotiating fixed prices directly with gas suppliers, (ii) negotiating financial instruments that “swap” into a fixed price from a floating price contract, (iii) negotiating financial instruments that set a ceiling price on a floating price contract (e.g. call option) and (iv) buying gas and injecting it into storage. See “Cost of Gas,” below.

Asset Optimization. NW Natural uses its gas supply 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, the Mist storage facility provides flexibility in this regard. In addition to NW Natural’s own activities to economically manage its gas supply costs, the Company contracts 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. Because NW Natural does not earn a return on the gas commodity acquisition, risks associated with cost recovery are minimized through:

NW Natural’s cost of gas to supply its core utility market primarily consists of the purchase price paid to suppliers plus charges paid to pipelines to transport the gas to NW Natural’s distribution system. While the rates for pipeline transportation and storage services are subject to federal regulation, the purchase price of gas is not. Although pipeline rates have been relatively stable in recent years, natural gas commodity prices have increased dramatically due to growing demand for natural gas, especially for power generation, stagnant North American gas production, and surging alternate fuel prices. NW Natural is in a favorable position with respect to gas production because of the proximity of the Pacific Northwest to supply basins in western Canada and the Rocky Mountains, where some growth in gas production is expected to continue for the foreseeable future. Management believes growth in gas commodity supply into the North American market is needed to alleviate price pressures. NW Natural seeks to mitigate the effects of higher gas commodity prices and price volatility on core utility customers through the use of its underground storage facilities, by entering into gas commodity-based financial hedge contracts, and by crediting gas costs with margin revenues derived from off-system sales of commodity and released transportation capacity in periods when core utility customers do not fully utilize firm pipeline capacity and gas supplies.

NW Natural has an active natural gas commodity price hedge program that is intended to reduce commodity price risk. Under this program, the Company typically enters into commodity swap and call option agreements for the coming year and up to three years into the future, when natural gas prices may be lower. Gains (losses) from commodity hedges are treated for accounting and rate purposes as reductions (increases) to the cost of gas. The intended effect of this program is to lock in prices for between 85 percent and 95 percent of NW Natural’s gas supply portfolio for the following year, at prevailing market prices at the time the swap and call option agreements are entered into. Fixed prices have been secured for lesser amounts of gas purchases for the subsequent two years, which helps to stabilize costs and reduce variations in annual rate changes.

The effectiveness of NW Natural’s gas supply program is largely dependent on the sources from which the design day requirement is satisfied. 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 12º F, the coldest day in the last 20 years in NW Natural’s service territory. NW Natural assumes that all interruptible customers will be curtailed on the design day. NW Natural’s projected sources of delivery for design day firm utility customer sendout is 8.9 million therms. NW Natural is currently capable of meeting 63 percent of its firm customer design day requirements with storage and peaking capabilities. Optimal utilization of storage and peaking facilities on NW Natural’s design day reduces the dependency on firm transportation. On Jan. 5, 2004, NW Natural experienced a record firm customer sendout of 7.2 million therms, and a total sendout of 8.9 million therms, on a day that was approximately 9º F warmer than the design day temperature. That January 2004 cold weather event

lasted about ten days, and the actual firm customer sendout each day provided data indicating that load forecasting models required very little re-calibration. Accordingly, NW Natural believes that its supplies would be sufficient to meet firm customer demand if the Company were 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 2004-2005 winter heating season:

NW Natural believes the combination of the natural gas supply it can purchase under contract, its peaking supplies and the capacity held under contract on the interstate pipelines will be sufficient to satisfy the needs of existing customers and allow for growth in future years.

NW Natural purchases gas for its core utility customers from a variety of suppliers located in the western United States and Canada. About 75 percent of its annual supply comes from Canada, with the balance coming primarily from the U.S. Rocky Mountain region. At Jan. 1, 2005, NW Natural had 28 firm contracts with 14 suppliers with remaining terms ranging from three months to five years, which provide for a maximum of 3.1 million therms of firm gas per day during the peak winter heating season and 1.3 million therms per day during the remainder of the year. These contracts have a variety of pricing structures and purchase obligations. During 2004, NW Natural purchased 756 million therms of gas under the following contract durations:

The Company regularly renews or replaces its expiring long-term and medium-term contracts with new agreements with a variety of existing and new suppliers. No single contract amounts to more than 200,000 therms per day or 10 percent of the Company’s average daily contract volumes. Firm year-round supply contracts have terms ranging from one to ten years. All of the contracts use price formulas tied to monthly index prices, primarily at the NIT trading point in Alberta. NW Natural hedges a majority of its contracts each year using financial instruments as part of its gas purchasing strategy (see “Managing the Cost of Gas,” above).

In addition to the year-round contracts, NW Natural continues to contract in advance for firm gas supplies to be delivered only during the winter heating season primarily under short-term contracts. During 2003 and 2004, new short-term purchase agreements were entered into with eight suppliers. These agreements have a variety of pricing structures and provide for a total of up to 1.8 million therms per day during the 2004-2005 heating season. Two of these contracts, each providing up to 100,000 therms per day, also extend to the 2005-2006 heating season. NW Natural intends to enter into new purchase agreements in 2005 for equivalent volumes of gas with its existing or other similar suppliers as needed to replace short-term and one-year contracts that will expire during 2005.

NW Natural also buys gas on the spot market as needed to meet demand. NW Natural has flexibility under the terms of some of its firm supply contracts enabling it to purchase spot gas in lieu of firm contract volumes, thereby allowing it to take advantage of favorable pricing on the spot market from time to time.

NW Natural continues to purchase gas from a non-affiliated producer in the Mist gas field in Oregon. The production area is situated near NW Natural’s underground gas storage facility. The price for this gas is tied to NW Natural’s weighted average cost of gas. Current production is approximately 13,000 therms per day from about 18 wells, supplying less than 1 percent of NW Natural’s total annual purchase requirements. Production from these wells varies as existing wells are depleted and new wells are drilled.

NW Natural supplements its firm gas supplies with gas from Company-owned or contracted off-system storage facilities in which gas is stored during periods of low demand for use during periods of peak demand. In addition to enabling NW Natural to meet its peak demand, these facilities make it possible to lower the annual average cost of gas by allowing NW Natural to minimize its pipeline transportation contract demand and to purchase gas for storage during the summer months when prices are generally at their lowest.

NW Natural has contracts with Williams Gas Pipeline–West, also known as Northwest Pipeline, for firm gas storage services from an underground storage facility at Jackson Prairie near Centralia, Washington, and a liquefied natural gas (LNG) facility at Plymouth, Washington. Together, these facilities provide NW Natural 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 NW Natural’s service territory. All of these contracts have reached the end of their primary terms but NW Natural has exercised its renewal rights that allow for annual extensions at its option.

NW Natural owns and operates two LNG plants 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.

NW Natural also provides daily and seasonal peaking from its underground gas storage facility in the Mist gas field. This facility has a maximum daily deliverability of 3.9 million therms and a total seasonal working gas capacity of 12.9 Bcf. In September 2004, NW Natural completed and placed into service its South Mist Pipeline Extension (SMPE) project, which completed the transmission pipeline from its Mist gas storage field to growing portions of its distribution service area. Also in 2004, a total of 400,000 therms per day of Mist storage capacity that had been available for interstate storage

services was recalled and committed to use for core utility customers. This is the first instance of returning capacity that had been developed in advance of core utility customers needs for interstate storage services to core utility customers under the regulatory agreement with the OPUC. Under this agreement, storage capacity is recalled as needed and added to retail utility rate base at its original cost less accumulated depreciation. The core utility market now has 2.3 million therms per day of deliverability and 8.9 Bcf of working gas committed from the Mist storage facility.

In December 2004, NW Natural completed its latest expansion of the Mist gas storage facility. This investment of approximately $9.9 million increased the facility’s incremental capacity and total daily delivery capacity by approximately 22 percent to a total of 3.9 million therms per day. A little over half of the expansion replaced the capacity recalled to the core market as described above, and the remainder is used to serve growth in the interstate storage services market. Ultimately, this expansion is also available to serve the needs of NW Natural’s core utility customers. The expansion increased working gas capacity at Mist to 12.9 Bcf, with 4.0 Bcf allocated to interstate storage services. As the needs of core utility customers grow, existing interstate gas storage capacity will be transferred for use by core utility customers and tracked into retail rates. Newly developed interstate gas storage capacity can then be developed at Mist to replace this recalled storage.

NW Natural also has contracts with one electric generator and two industrial customers that together provide an additional 102,000 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.

Dependence on a Single Pipeline. NW Natural is directly connected to a single interstate pipeline, Northwest Pipeline. Although the Company is dependent on a single pipeline, the pipeline is bi-directional as it transports gas into the Portland metropolitan market from two directions: (i) the north, which brings supplies from British Columbia and Alberta supply basins and (ii) the east, which brings supplies from Alberta and the Rocky Mountain supply basins. The Company is investigating options to further diversify its pipeline transportation paths. The need for pipeline transportation diversity has been underscored by recent Northwest Pipeline ruptures and the resulting federal order in 2003 that requires Northwest Pipeline to replace its 26 inch mainline from the Canadian border to NW Natural’s service territory by December 2006.

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

Transportation Agreements. The largest of the 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.

The Company’s 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 Gas Transmission Northwest (GTN) systems in eastern Oregon to NW Natural’s 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. NW Natural’s total capacity on GTN and two upstream pipelines in Canada (Alberta Natural Gas Company and NOVA Corporation of Alberta, which, with GTN, are all now units of TransCanada PipeLines Limited) matches this amount of Northwest Pipeline capacity northward into Alberta, Canada.

NW Natural also has an agreement with Northwest Pipeline that extends through 2013 for 351,550 therms per day of firm transportation capacity. This agreement accesses gas supplies in the U.S. Rocky Mountain region.

NW Natural also has four long-term pipeline transportation contracts with other interstate transporters. The contract with Duke Energy Gas Transmission (formerly Westcoast Energy, Inc.) (Duke Energy GT) extends through October 2014 and provides approximately 600,000 therms per day of firm gas transportation from northern British Columbia to a connection with Northwest Pipeline at the U.S.-Canadian border. The contract with Terasen Gas (formerly BC Gas) extends through October 2020 and provides approximately 470,000 therms per day of firm gas transportation from southeastern British Columbia to the same connection with Northwest Pipeline at the U.S.-Canadian border. NW Natural’s capacity with Terasen Gas is matched with companion contracts for pipeline capacity on systems of Alberta Natural Gas Company and NOVA Corporation of Alberta that connect to the gas fields of Alberta, Canada.

Since Northwest Pipeline opened its system to the transportation of customer-owned gas in the late 1980s, many of NW Natural’s non-core customers (larger industrial interruptible customers with full or partial dual fuel capabilities) have switched from sales service to transportation service whereby they purchase gas directly from suppliers and ship the gas on NW Natural’s distribution system, and those of its upstream pipeline suppliers for a fee. The ability of industrial customers to switch between sales service and transportation service has made it possible for NW Natural to retain some of these customers. Periodic switching between sales and transportation service by these customers has had an adverse effect on NW Natural’s results of operations in certain years, and a positive effect in other years, as industrial customers have sought to find the most economical and reliable combination of gas supply and delivery services (see “Competition and Marketing,” below). In 2003 and 2004, NW Natural redesigned its industrial rates in Oregon and Washington, and as a result it expects less switching from higher-margin to lower-margin service contracts than it has experienced in the past.

NW Natural is subject to regulation with respect to, among other matters, rates, systems of accounts and issuance of securities by the OPUC and the WUTC. In 2004, 93 percent of NW Natural’s utility gas deliveries and 92 percent of its utility operating revenues were derived from Oregon customers and the balance from Washington customers.

NW Natural is exempt from the provisions of the Natural Gas Act (Hinshaw exemption) by order of FERC, except with respect to the terms and conditions associated with its interstate gas storage and related transportation services (see “Interstate Gas Storage,” above).

11.7 miles of the Company’s southern portion of SMPE went into service. The remaining $3.8 million for the southern portion of the SMPE went into effect on Oct. 1, 2004, upon the completion and placement into service of the last segment of the SMPE project. Recovery for the Company’s Coos County distribution system project of $1.2 million went into effect on Nov. 1, 2004, on a deferred basis. While not included in the rate case result, an additional annual rate recovery of $7.5 million associated with the northern portion of the SMPE project became effective October 1, 2004.

In November 2003, NW Natural filed a general rate case in Washington that proposed a revenue increase of $7.9 million per year from Washington operations through rate increases averaging 15 percent. In June 2004, the WUTC approved a settlement agreement entered into by the parties to NW Natural’s Washington general rate case, which became effective on July 1, 2004, authorizing a revenue increase of $3.5 million per year, or 6.5 percent. In addition, the settlement authorized NW Natural to include the SMPE cost of service in rates, subject to audit, concurrent with the annual Washington Purchased Gas Adjustment (PGA) filing, which became effective on Nov. 1, 2004. See “Rate Mechanisms,” below and Part II, Item 7., “Results of Operations—Regulatory Matters—General Rate Cases.”

In January 2005, the Company filed a rate case with the FERC proposing an update of maximum rates for the Company’s interstate storage services operation and new service offerings. The requested rate increase is designed to reflect costs related to the further development of the Mist gas storage facilities and costs associated with the SMPE project. This filing was made to satisfy FERC’s requirement that there be a cost and revenue review in three years following its original storage service rate authorization.

Weather normalization. In November 2003, NW Natural implemented a weather normalization mechanism in Oregon that is designed to stabilize margins from weather-sensitive residential and commercial customers by adjusting current billings based on temperature variances from average weather. The weather normalization mechanism approved by the OPUC is applied to NW Natural’s Oregon residential and commercial customers’ bills between Nov. 15 and May 15 of each heating season. The mechanism adjusts the margin component of customers’ rates to reflect “normal” weather using the 25-year average temperature for each day of the billing period. The mechanism is intended to stabilize the recovery of fixed costs and to reduce fluctuations in customers’ bills due to colder- or warmer-than-average weather. In October 2004, the mechanism was modified to limit the upward or downward adjustments to individual bills to certain specified ranges, with any excess amounts being deferred.

Purchased Gas Adjustment. In Oregon, NW Natural has a PGA tariff under which net income derived from Oregon operations may be affected within defined limits by changes in purchased gas costs. The PGA tariff provides for periodic revisions in rates resulting from changes in the Company’s cost of purchased gas. Costs included in the PGA adjustments are based on NW Natural’s projected gas requirements and negotiated gas prices for the upcoming gas supply contract year. Under its Washington PGA, NW Natural is permitted to track 100 percent of increases and decreases in gas commodity costs, with the result that net income is not directly affected by changes in commodity costs. In both Oregon and Washington, the PGA mechanism permits NW Natural to recover 100 percent of FERC-approved pipeline transportation costs. During the fourth quarter of 2004, the staff of the OPUC initiated a review of gas purchasing strategies for all three local gas distribution companies serving Oregon. The schedule, scope and potential findings, including whether the review will lead to formal proceedings before the OPUC, remain uncertain.

The Oregon PGA tariff provides that 67 percent of any difference between actual purchased gas costs and estimated purchased gas costs incorporated into rates will be deferred for amortization in subsequent periods. If actual gas commodity costs exceed those incorporated in rates, NW Natural subsequently will adjust its rates upward to recover 67 percent of the deficiency from core utility customers. Similarly, if actual gas commodity costs are lower than those reflected in rates, rates will be adjusted downward to distribute to core utility customers 67 percent of such gas commodity cost savings.

The OPUC has a formalized process that tests for excessive earnings in connection with gas utilities’ annual filings under their PGA mechanisms. The OPUC has confirmed NW Natural’s ability to pass through 100 percent of its prudently incurred gas costs into rates. Under this requirement, NW Natural is authorized to retain all of its earnings up to a threshold level equal to its authorized ROE 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 interest rates.

Conservation Tariff. Effective Oct. 1, 2002, the OPUC authorized NW Natural to implement a “conservation tariff,” which is a mechanism designed to recover lost margin due to changes in residential and commercial customers’ consumption patterns. The tariff is a partial decoupling mechanism that is intended to break the link between the Company’s earnings and the quantity of energy consumed by its customers, so the Company does not have an incentive to discourage customers’ conservation efforts.

The conservation tariff contains two components. The first, a “price elasticity” factor, adjusts for increases or decreases in consumption attributable to annual changes in commodity costs or periodic changes in the Company’s general rates. The second is a conservation adjustment calculated on a monthly basis to account for deviations between actual and expected volumes. Additional revenues or credits to customers produced by the conservation adjustment are booked to a deferral account that is reconciled as part of the Company’s annual PGA. Baseline consumption is based on customer consumption patterns as determined in the Oregon general rate case, adjusted for consumption resulting from new customers. The partial decoupling mechanism will expire at the end of September 2005 unless the OPUC approves an extension based on the results of an independent study to measure the mechanism’s effectiveness. Work on the independent study, which involves interested parties, is in process and is expected to be completed by the end of March 2005. The study is expected to provide the basis for the Company’s filing to renew the tariff.

As part of the proceeding approving the conservation tariff, NW Natural agreed to adopt certain service quality measures that establish the Company’s performance goal for minimizing complaints by customers where the Company is determined to be at fault. If NW Natural exceeds the prescribed level of at-fault complaints, it will be subject to penalties. Since inception, NW Natural has not incurred any penalties under these service quality measures.

Pipeline Integrity Cost Recovery. In July 2004, the OPUC approved NW Natural’s applications relating to the accounting treatment and full recovery for the cost of the pipeline integrity management program (IMP) as mandated by the Pipeline Safety Improvement Act of 2002 (Pipeline Safety Act) and related rules adopted by the U.S. Department of Transportation’s (DOT) Office of Pipeline Safety (see Part II, Item 7., “Financial Condition—Cash Flows—Investing Activities”). Under the applications as approved, NW Natural classifies its IMP costs as either capital expenditures or regulatory assets, accumulates the costs over each 12-month period ending June 30, and recovers the costs, subject to

audit, through rate changes effective on October 1 of each year commencing Oct. 1, 2004. The accounting and rate treatment for these costs extends through Sept. 30, 2008, and may be reviewed for potential extension after that date.

Combined Heat and Power (Gas Fired Distributed Generation) Tariff. On Dec. 21, 2004, the OPUC approved the Company’s request for a special tariff discount for new Combined Heat and Power (CHP) projects. The tariff provides a discount to CHP projects that use firm service. The modest discount, combined with other incentives, is expected to improve the prospects for the construction of new CHP projects in the Company’s service territory.

Open Pathway Tariff. The open pathway tariff, approved by the WUTC and the OPUC during the fourth quarter of 2004, requires developers to provide the Company with a trench for installation of mains and services in new developments. If a trench is not provided, the tariff requires the developer to pay trenching costs. In the past, provision of a trench or reimbursement was not required. Implementation of the tariff began in early 2005.

The OPUC and WUTC have implemented integrated resource planning processes under which utilities develop plans defining alternative growth scenarios and resource acquisition strategies. NW Natural submitted a draft of its fifth IRP in Oregon and Washington in October 2004. The Company expects to submit its IRP in final form during the first quarter of 2005, with acknowledgment in Oregon and acceptance in Washington expected during the second and third quarters of 2005, respectively. Elements of the plan include an evaluation of supply and demand resources; the consideration of uncertainties in the planning process and the need for flexibility to respond to changes; a primary goal of “least cost” service; and consistency with state energy policy. Although the OPUC’s order acknowledging an earlier IRP indicated the order did not constitute ratemaking approval of any specific resource acquisition or expenditure, the OPUC did indicate that it would give considerable weight in prudency reviews to utility actions that are consistent with acknowledged plans. Elements of NW Natural’s draft IRP demonstrate that the continued development of the Mist underground gas storage facility is the least-cost option for serving customer growth (see “Additions to Infrastructure,” below).

NW Natural expects a high level of capital expenditures for additions to infrastructure over the next five years, reflecting projected customer growth, system replacement, improvement and reinforcement projects and the development of additional gas storage facilities. NW Natural’s utility construction expenditures are estimated to total between $500 million and $600 million over the five-year period 2005 through 2009, including an estimated $110 million in 2005.

NW Natural continues to be one of the fastest growing gas utilities in the nation (see “Competition and Marketing,” below). In 2004, NW Natural grew its customer base by more than 3 percent for the 18^th year in a row, and in 2005 it expects to continue that trend with projected capital expenditures of $28 million for the addition of new customers.

NW Natural expects to have significant capital requirements during the next five years for system replacement, improvement and reinforcement projects. These include requirements pursuant to new federal legislation as well as expenditures under NW Natural’s ongoing pipeline safety program (see “Pipeline Safety,” below).

The extension of the pipeline from NW Natural’s Mist gas storage field, designed to move more gas into growing portions of its service area (see “Gas Supply—Core Utility Market Peaking Supply,” above), has an estimated total cost of $110 million. The project was completed in late September 2004; however, NW Natural continues to negotiate with some landowners regarding valuation of easements and rights-of-way obtained pursuant to condemnation proceedings during the course of construction. In some cases, compensation will be determined in individual court proceedings that have been scheduled through June 2005. The Company is unable to determine the likelihood of unfavorable outcomes of these matters, but believes that the aggregate amount of compensation ultimately paid will not materially affect the Company’s financial condition, results of operations or cash flows.

The Pipeline Safety Act requires operators of gas transmission pipelines to identify lines located in High Consequence Areas (HCAs) and develop IMPs 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 requires NW Natural to complete inspection of 50 percent of the highest risk pipelines located in its HCAs within the first five years, and the remaining covered pipelines within 10 years of the date of enactment. The Pipeline Safety Act also requires re-inspections of the covered pipelines every seven years from the date of the previous inspection for the life of the pipelines. In December 2003, the U.S. Department of Transportation issued a final rule that specifies the detailed requirements for transmission IMPs as mandated by the Pipeline Safety Act. See Part II., Item 7., “Financial Condition–Cash Flows–Investing Activities.” In 2004, NW Natural met the first major milestones required by the Pipeline Safety Act and IMP rules by commencing pipeline integrity assessments and meeting the following additional requirements before the required deadlines:

Effective Jan. 12, 2005, NW Natural assumed responsibilities as operator of the pipeline that transports gas to Coos County, Oregon. The requirements of the Pipeline Safety Act will also apply to NW Natural as operator of that pipeline.

NW Natural entered into a stipulation with the OPUC in 2001 for an enhanced pipeline safety program that includes an accelerated bare steel replacement program and a geo-hazard safety program. The bare steel replacement program accelerates the replacement of NW Natural’s bare steel piping over 20 years instead of 40 years. The geo-hazard safety program includes the identification, assessment and remediation of risks to piping infrastructure created by landslides, washouts, earthquakes or similar occurrences. The stipulation allowed NW Natural to receive deferred accounting rate treatment commencing Oct. 1, 2002, for costs associated with the bare steel replacement program exceeding $3 million per year and the actual costs associated with the geo-hazard safety program, expected to be approximately $1.5 million annually.

NW Natural has no direct competition in its service area from other natural gas distributors. For residential customers’ heating needs, however, NW Natural competes with electricity, fuel oil, propane and, to a lesser extent, wood. It also competes with electricity and fuel oil for commercial applications. In the industrial market, NW Natural competes with all forms of energy, including gas-to-gas competition from third-party sellers of natural gas. Competition among these forms of energy is based on price, reliability, efficiency and performance.

The competitive price advantage of natural gas over electricity declined in 2004 due to higher natural gas commodity prices and relatively stable electricity prices in both the residential and commercial markets. The current price advantage varies due to differences in retail electric rates between investor-owned utilities, where NW Natural has maintained a moderate price advantage, and the public utilities, where NW Natural’s price advantage, if any, is marginal. In 2004, although electricity prices continued to become more competitive primarily due to improving end use technology, 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 NW Natural’s Oregon service area. NW Natural expects to maintain a price advantage compared to electricity provided by the investor-owned electric utilities in its service territory, in part because a growing portion of the electricity sold by these utilities is generated from natural gas. Although the price advantage for natural gas compared to oil continued to be favorable in 2004, there were fewer residential conversions from heating oil to natural gas during 2004 due to volatile gas prices, weak economic conditions and a decline in the remaining inventory of potential oil conversion opportunities.

The relatively low market saturation of natural gas in residential single-family and attached dwellings in NW Natural’s service territory, estimated at approximately 50 percent, together with the price advantage of natural gas compared with electricity in some areas and its operating convenience over fuel oil, provides the potential for continuing growth in the residential and commercial conversion markets. In 2004, 17,725 net residential customers (after subtracting disconnected or terminated services) were added, including 5,224 units of existing residential housing that were converted from oil, electric or propane appliances to natural gas. The net total of all new customers added in 2004 was 18,485. This constituted a growth rate of 3.2 percent, which is about twice the national average for local gas distribution companies as reported by the American Gas Association.

Due to weather that was about 3 percent warmer in 2004 than in 2003 and 8 percent warmer than average, and a decrease in weather-sensitive customer consumption due to commodity price-related rate increases and continuing conservation efforts, natural gas sales volumes to residential and commercial customers in 2004 were about 1 percent lower than in 2003.

As a result of the deregulation and restructuring of the energy markets during the past decade, the natural gas industry, including producers, interstate pipelines and local gas distribution companies, has undergone many changes. Traditionally, local gas distribution companies sold a “bundled” product that included both the natural gas commodity and delivery to the 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 to their facilities. These changes were intended to promote competition where it is 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 NW Natural may contract with customers to deliver customer-owned gas. Transportation tariffs available to industrial customers are priced at the Company’s cost of providing transportation service. Generally, the Company is unaffected financially if industrial customers transport customer-owned gas rather than purchasing gas from NW Natural, as long as they remain on a tariff or contract with the same quality of service. 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 revenue from such customers. 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 NW Natural’s 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. NW Natural re-designed its industrial rates in Oregon and Washington as part of its 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. As a result, it expects less switching from higher-margin to lower-margin service contracts than it has experienced in the past.

NW Natural’s industrial base, which includes customers in the high-tech, forest products and other industries that are sensitive to economic conditions, showed improvement in 2004. Sales service continued to be strong in 2004 compared to previous years largely because spot prices in the gas commodity market were higher than the weighted average cost of gas embedded in NW Natural’s sales rates for the year. The mix within the industrial market between firm and interruptible service was different in 2004, with deliveries under industrial firm service tariffs constituting 43 percent of total industrial deliveries in 2004, compared to 39 percent in 2003.

NW Natural and certain of its largest industrial customers have entered into negotiated transportation service agreements. These 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, bypassing NW Natural’s gas distribution system. The agreements generally prohibit bypass during their terms. Due to the cost pressures that confront a number of NW Natural’s largest customers that compete in global markets, bypass continues to be a threat. Although NW Natural does not expect a significant number of its large customers to bypass its system in the foreseeable future, it may experience further deterioration of margin associated with customers’ transfers to contracts with pricing designed to be competitive with bypass.

NW Natural is authorized by the OPUC to make off-system commodity sales when seasonal demand is low. This often allows NW Natural to compete effectively with independent gas marketers.

Sixty-seven percent of the margin revenues (gross revenues less the actual cost of gas) generated from these sales are refunded to Oregon’s core utility customers through cost of gas savings, with the remaining balance reflected in net income.

The Company’s properties and facilities 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:

NW Natural owns 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 (the Gasco site), a property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation, formerly Wacker Siltronic Corporation (the Wacker site), and an area adjacent to the Gasco site and the Wacker site along a segment of the Willamette River (the Portland Harbor) that has been listed by the U.S. Environmental Protection Agency as a Superfund site for which the Company has been identified as one of a number of potentially responsible parties. The Company does not expect that the ultimate resolution of these matters will have a material adverse effect on its financial condition, results of operations or cash flows. See Note 12 to the accompanying Consolidated Financial Statements for a further discussion of potential environmental responses and related costs.

At Dec. 31, 2004, NW Natural had 1,288 employees, of which 875 were members of the Office and Professional Employees International Union (OPEIU), Local No. 11, AFL-CIO.

The Company files annual, quarterly and special reports and other information with the Securities and Exchange Commission (SEC). The Company makes available on its website (http://www.nwnatural.com), free of charge, its 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 soon as reasonably practicable after it electronically files such material with, or furnishes it to, the SEC.

The Company has 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 the Company’s website. The Company’s Corporate Governance Standards, Director Independence Standards, charters of each of the committees of the Board of Directors and additional information about NW Natural are also available on the website.

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

NW Natural’s natural gas distribution system consists of 12,925 miles of distribution and transmission mains. In addition, the distribution system includes service pipes, meters and regulators, and gas regulating and metering stations. The mains and feeder lines are located in municipal streets or alleys pursuant to valid franchise or occupation ordinances, in county 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. NW Natural also holds all necessary permits for the crossing of the Willamette River and a number of smaller rivers by its mains.

NW Natural owns service facilities in Portland, as well as various satellite service centers, garages, warehouses and other buildings necessary and useful in the conduct of its business. It leases office space in Portland for its corporate headquarters, which lease was renewed in 2003. District offices are maintained on owned or leased premises at convenient points in the distribution system. NW Natural owns LNG facilities in Portland and near Newport, Oregon.

NW Natural holds interests in 7,934 net acres of underground natural gas storage and 2,660 net acres of oil and gas leases in Oregon. NW Natural owns rights to depleted gas reservoirs near Mist, Oregon, that are continuing to be developed as underground gas storage facilities. It also holds 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 its system, NW Natural undertook an accelerated pipe replacement program in the 1980s under which it removed or replaced 100 percent of its cast iron mains by October 2000. In 2001, NW Natural initiated an accelerated pipe replacement program under which it will reduce the amount of bare steel mains in the system.

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

NW Natural’s Mortgage and Deed of Trust is a first mortgage lien on substantially all of the property constituting its utility plant.

On Oct. 16, 2003, Longview Fibre Company (Longview) filed suit in Federal Court (Longview Fibre Company v. Enerfin Resources Northwest Limited Partnership and Northwest Natural Gas Company (US District Court - Oregon District)) seeking a declaratory judgment regarding the continuing existence of a certain oil and gas lease in the Mist gas field between Longview and Enerfin Resources Northwest Limited Partnership (Enerfin). NW Natural holds a gas storage lease from Longview (the Cascade Lease), which covers the same land as the Enerfin lease, and grants the right to produce native oil and gas. Enerfin originally filed crossclaims against NW Natural alleging that NW Natural wrongly interfered with Enerfin’s attempts to continue its oil and gas lease with Longview; however, Enerfin agreed to dismiss those claims in a previous settlement with NW Natural. In that settlement, NW Natural subleased portions of the Cascade Lease to Enerfin for the purpose of producing native gas. In September 2004, NW Natural and Enerfin filed claims and counterclaims against Longview, and Longview filed claims and counterclaims against NW Natural and Enerfin. The claims that Longview made against NW Natural involved allegations of unpaid royalties under the Cascade Lease.

All parties to the Longview litigation entered into a Settlement Agreement, effective Jan. 11, 2005. As part of the settlement, Longview granted NW Natural an easement for use in producing oil and gas from the lands covered by the Cascade Lease. Other than payments made in respect of the easement, and royalty payments under the relevant leases and subleases, which were not material, no payments were made in connection with the Longview settlement. All claims were dismissed on Jan. 28, 2005 pursuant to the Settlement Agreement.

On May 28, 2004, a lawsuit was filed against the Company (Kerry Law, Arnold Zuehlke and Kenneth Cooper, on behalf of themselves and all others similarly situated v. Northwest Natural Gas Company (U.S. Dist. Ct. D. Or., Case No. CV-04-728-AS)) by three individuals alleging violation of the Fair Labor Standards Act for failure to pay overtime. The suit was subsequently amended to include state wage and hour claims. The plaintiffs are or have been independent backhoe operators who performed services for the Company under contract. In the lawsuit, the plaintiffs claim that they, and others similarly situated, should have been considered “employees” of the Company instead of independent contractors. The plaintiffs seek overtime and interest in amounts to be determined, liquidated damages equal to the overtime award, civil penalties and attorneys fees and costs. The plaintiffs sought to certify this case as a collective action under the Fair Labor Standards Act; however, on Oct. 5, 2004, plaintiffs’ motion for collective action certification was denied. As a result of this ruling, the case is proceeding with the three current plaintiffs, and any others who wish to join must do so individually. Although no other claims have been filed in this lawsuit, plaintiffs’ counsel has indicated to the court their intention to file additional claims seeking employee benefits allegedly due to plaintiffs. In addition, the claims in the lawsuit described below may be consolidated with this lawsuit. The Company intends to vigorously contest the claims. There is insufficient information at this point in the litigation to reasonably estimate the amount of liability, if any, from this claim.

who have performed services for the Company under contract. Like the plaintiffs in the claim described above, these plaintiffs allege that they should have been considered “employees” of the Company. They seek overtime wages under the Fair Labor Standards Act and interest in amounts to be determined, liquidated damages equal to the overtime award, civil penalties and attorneys fees and costs. In addition, the plaintiffs allege that failure to classify them as employees constituted a breach of contract under certain of the Company’s employee benefit programs, agreements and plans, which conferred employment-related compensation, rights and benefits. They seek an unspecified amount of damages for the value of what they would have received under these programs, agreements and plans if they had been classified as employees. The Company intends to vigorously contest the claims. There is insufficient information at this point in the litigation to reasonably estimate the amount of liability, if any, from this claim.

On Dec. 20, 2004, the Company was served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940’s and 1950’s petroleum wastes generated by the Company’s predecessor, Portland Gas & Coke Company, and nine other third-party defendants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The Port’s complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. NW Natural does not believe there are facts sufficient to constitute a claim against the Company.

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

There were no matters submitted to a vote of security holders, through the solicitation of proxies or otherwise, during the fourth quarter of the year ended Dec. 31, 2004.

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

The quarterly high and low trades for NW Natural’s common stock during the past two years were as follows:

The closing quotations for the common stock on Dec. 31, 2004 and 2003 were $33.74 and $30.75, respectively.

(B) As of Dec. 31, 2004, there were 9,359 holders of record of the Company’s common stock.

(C) NW Natural has paid quarterly dividends on its 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:

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

NW Natural’s Dividend Reinvestment and Stock Purchase Plan permits registered owners of common stock to reinvest all or a portion of their quarterly dividends in additional shares of common stock at the current market price. Shareholders also may invest cash on a monthly basis, up to $50,000 per calendar year, in additional shares at the current market price. During 2004, dividend reinvestments and optional cash investments under the Plan aggregated $4.8 million and resulted in the issuance of 157,124 shares of common stock. During the 27 years the Plan has been available, the Company has issued and sold 4,651,436 shares of common stock which produced $102.9 million in additional capital.

(D) The following table provides information about purchases by the Company during the quarter ended Dec. 31, 2004 of equity securities that are registered by the Company pursuant to Section 12 of the Exchange Act:

(1) During the three months ended Dec. 31, 2004 the Company accepted 6,355 shares of its common stock as payment for stock option exercises pursuant to the Company’s Restated Stock Option Plan.

(2) On May 25, 2000, the Company announced a program to repurchase up to 2 million shares, or up to $35 million in value, of NW Natural’s common stock pursuant to a repurchase program that has been extended annually. The purchases are made in the open market or through privately negotiated transactions. Since the program’s inception, the Company has repurchased 355,400 shares of common stock at a total cost of $8.2 million. On April 22, 2004, NW Natural’s Board of Directors extended the program through May 31, 2005.

The following table sets forth selected financial data concerning the Company’s operations and financial condition.

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.

The following is management’s assessment of Northwest Natural Gas Company’s financial condition including the principal factors that affect results of operations. The discussion refers to the consolidated activities of the Company for the three years ended Dec. 31, 2004. Unless otherwise indicated, references in this discussion to “Notes” are to the notes to the consolidated financial statements in this report.

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

Together these businesses are referred to herein as the “Company.” In this report, the term “utility” is used to describe the Company’s regulated gas distribution business and the term “non-utility” is used to describe its interstate gas storage business and other non-regulated activities (see Note 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. The Company believes this per share information is useful because it enables readers to better understand the impact of these factors on earnings. All references in this report to earnings per share are on the basis of diluted shares (see Note 1).

The Company’s strategy in 2004 was to strengthen its financial position and remain focused on profitably growing its regulated gas distribution business and interstate gas storage business.

There are a number of factors that affect the Company’s operations and financial performance. The most significant issues and challenges the Company expects to face in 2005 include high gas commodity prices, unpredictable weather conditions, the impact of regulatory actions or policy changes, managing gas supplies and storage capacity, maintaining a competitive advantage over alternate fuels, managing environmental risks and exposures, an uncertain economic recovery and higher interest rates. For a detailed listing of other risks facing the Company, see “Forward-Looking Statements” and “Quantitative and Qualitative Disclosures About Market Risk,” below.

In order to deal with these and other issues affecting the business, the Company’s strategic plan includes strategies for:

In addition to return on equity (ROE) and common equity ratio as key indicators of the Company’s operating performance and financial condition, other key performance measures the Company uses in monitoring progress against its goals are utility earnings per share, customer satisfaction ratings, new customer additions, operations and maintenance expense per customer, construction cost per meter installed, and non-revenue producing capital expenditures per customer.

Earnings applicable to common stock were $50.6 million, or $1.86 a diluted share, for the year ended Dec. 31, 2004, compared to $45.7 million, or $1.76 a share, and $41.5 million, or $1.62 a share, for the years ended Dec. 31, 2003 and 2002, respectively. Returns on average common equity for these three years were 9.4 percent, 9.3 percent and 8.7 percent, respectively. Primary factors affecting earnings, and the resulting positive (negative) impact include:

Dividends paid on common stock were $1.30 a share in 2004, compared to $1.27 a share in 2003 and $1.26 a share in 2002. The 2004 increase in dividends paid marks the 49^th consecutive year of dividend increases.

In preparing the Company’s financial statements using generally accepted accounting principles in the United States of America (GAAP), management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses and related disclosures in the financial

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

The Company’s most critical estimates or judgments involve regulatory cost recovery, unbilled revenues, derivative instruments, pension assumptions, income taxes and environmental contingencies. Management has discussed the estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board. The Company’s critical accounting policies and estimates are described below.

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

NW Natural is regulated by the Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC), which establish the Company’s 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, NW Natural uses the same accounting principles as other 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 regulation. For example, NW Natural accounts for the cost of gas using a deferral and cost recovery mechanism called the Purchased Gas Adjustment (PGA), 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 the Company to defer for recovery or refund in future periods. SFAS No. 71 requires the Company to account for these types of deferred expenses (or deferred revenues) as regulatory assets (or regulatory liabilities) on the balance sheet. When NW Natural is allowed to recover these expenses from or refund them to customers, it recognizes the expense or revenue on the income statement at the same time it realizes the adjustment to amounts included in utility rates and charged to customers.

The conditions a company must satisfy to adopt the accounting policies and practices of SFAS No. 71 applicable to regulated companies include:

NW Natural continues to apply SFAS No. 71 in accounting for its regulated utility operations. Future regulatory changes or changes in the competitive environment could result in the Company discontinuing the application of SFAS No. 71 for some or all of its regulated business. 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, NW Natural believes that it is reasonable to expect continued application of SFAS No. 71 for its regulated activities, and that all of its regulatory assets and liabilities at Dec. 31, 2004 and 2003 are recoverable or refundable through future customer rates.

Utility revenues, derived primarily from the sale and transportation of natural gas, are recognized when the 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 (unbilled revenues). Unbilled revenues are primarily based on the Company’s percentage estimate of its unbilled gas each month, which is dependent upon a number of factors that require management’s judgment. These factors include total gas receipts and deliveries, customer meter reading dates, customer usage patterns and weather. Unbilled revenue estimates are reversed the following month when actual billings occur. Estimated unbilled revenues at Dec. 31, 2004 and 2003 were $64.4 million and $59.1 million, respectively. The increase in unbilled revenues at year-end 2004 was primarily due to higher gas prices included in customer rates, partially offset by lower unbilled volumes reflecting warmer weather and decreases in customer usage due to higher prices. If the estimated percentage of unbilled gas at Dec. 31, 2004 were adjusted up (or down) by 1 percent, then the Company’s unbilled revenues, net operating revenues and net income would have increased (or decreased) by an estimated $1.0 million, $0.5 million and $0.3 million, respectively.

In November 2003, NW Natural implemented a weather normalization mechanism in Oregon that helps stabilize net operating revenues by adjusting current customer billings based on temperature variances from average weather (see “Results of Operations—Regulatory Matters—Rate Mechanisms,” below). Weather normalization is also included in unbilled revenues at the end of each accounting period using management’s judgments as discussed above.

Non-utility revenues, derived primarily from interstate storage services, are recognized upon delivery of the service to customers. Revenues from optimization of excess storage and transportation capacity are recognized over the life of the contract for guaranteed amounts under the contract, or are recognized as they are earned for amounts above the guaranteed value based on estimates provided by the independent energy marketing company.

In providing gas distribution services, NW Natural enters into forward contracts to buy and sell natural gas. These contracts qualify as normal purchases and normal sales under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” because they provide for a purchase or sale, and subsequent delivery, of natural gas in quantities that are probable of delivery over a reasonable period of time in the normal course of business (see Note 1, “Derivatives Policy”). Accordingly, these contracts are accounted for at the time of settlement and are not reflected on the Company’s balance sheet or income statement prior to settlement.

The Company has an established Derivatives Policy that sets forth the guidelines for using selected financial derivative products to support prudent risk management strategies within designated parameters (see Note 1). The policy specifically prohibits the use of derivatives for trading or speculative purposes. Hedging activities consist of natural gas commodity price and foreign currency exchange rate hedges which are accounted for as cash flow hedges. These contracts that qualify as derivative instruments are recorded on the balance sheet at fair value. Generally, most of these contracts are subject to regulatory deferral mechanisms, and as such any change in the fair value of these contracts is recorded as regulatory assets or regulatory liabilities pursuant to SFAS No. 71 (see Note 1, “Derivatives Policy”). The Company’s estimate of fair value is determined from period to period based on prices available from external sources and internal modeling based on index prices that are subject to market volatility. For estimated fair values at Dec. 31, 2004 and 2003, see Note 11.

The following table summarizes the realized gains and losses from commodity price and currency hedge transactions in the years ended Dec. 31, 2004, 2003 and 2002:

Realized gains (losses) from commodity price and foreign currency hedge 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 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).

The Company has two qualified, non-contributory defined benefit pension plans covering all regular employees with more than one year of service. These plans are funded through a trust dedicated to providing retiree pension benefits. The Company also has several non-qualified supplemental pension plans for eligible executive officers and certain key employees. These non-qualified plans are unfunded.

Net periodic pension cost (NPPC) and accumulated benefit obligations (ABO) are determined in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” using a number of key assumptions including the discount rate, the rate of compensation increases, retirement ages, mortality rates and the expected long-term return on plan assets (see “Financial Condition—Pension Cost (Income) and Funding Status,” below, and Note 7). These key assumptions have a significant impact on the amounts reported. NPPC consists of service costs, interest costs, the amortization of actuarial gains and losses, 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 NPPC volatility.

A number of factors are considered in developing pension assumptions, including an evaluation of relevant discount rates, expected long-term returns on plan assets, plan asset allocations, expected changes in wages and retirement benefits, analyses of current market conditions and input from actuaries and other consultants. For the Dec. 31, 2004 measurement date, the Company:

The change in discount rate was the primary factor contributing to the increase in the plans’ ABO from $205 million at Dec. 31, 2003 to $223 million at Dec. 31, 2004.

The Company believes its pension assumptions to be appropriate based on plan design and an assessment of market conditions. However, the following reflects the sensitivity of NPPC and ABO to changes in certain actuarial assumptions:

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

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 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 ratemaking policies of the OPUC and WUTC. Regulatory tax assets and liabilities are recorded to the extent the Company believes they will be recoverable from or refunded to customers in future rates. At Dec. 31, 2004 and 2003, the Company had regulatory assets representing differences between book and tax basis related to pre-1981 property of $64.7 million and $63.4 million, respectively, and has recorded an offsetting deferred tax liability for the same amounts (see Note 1). NW Natural believes 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.

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.” Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties. In the normal course of business, accruals are recorded for loss contingencies based on an analysis of potential results, developed in consultation with outside counsel when appropriate, including allowances for uncollectible accounts, environmental claims and property damage and personal injury claims. Where information is sufficient to estimate only a range of probable liability, and no point within the range is more likely than any other, the Company recognizes an accrued liability at the lower end of the range. It is possible, however, that future results of operations could be materially affected by changes in assumptions or estimates regarding these contingencies. With respect to environmental claims and related litigation costs, receivables are recorded for anticipated recoveries under insurance contracts based on amounts the Company estimates are probable of recovery. If these amounts are not recovered from insurance, the Company believes that recovery is probable from future utility rates based on current approval by the OPUC to defer these costs as a regulatory asset. See Note 12.

NW Natural provides gas utility service in Oregon and Washington, with Oregon representing over 90 percent of its revenues. Future earnings and cash flows from utility operations will be determined largely by the pace of continued growth in the residential and commercial markets and by NW Natural’s ability to remain price competitive in the large industrial market, to control expenses, and to obtain reasonable and timely regulatory ratemaking treatment for its operating and maintenance costs and investments made in utility plant.

NW Natural’s most recent general rate increase in Oregon, which was effective Sept. 1, 2003, authorized rates designed to produce a return on shareholders’ equity (ROE) of 10.2 percent. The OPUC approved a revenue increase of $13.9 million per year, of which $6.2 million went into effect on Sept. 1, 2003, and $2.7 million went into effect on a deferred basis on Nov. 12, 2003 as the first 11.7 miles of the Company’s southern portion of SMPE went into service. The remaining $3.8 million for the southern portion of the SMPE went into effect on Oct. 1, 2004, upon the completion and placement into service of the last segment of the SMPE project. Recovery for the Company’s Coos County distribution system project of $1.2 million went into effect on Nov. 1, 2004, on a deferred basis. While not included in the rate case result, an additional annual rate recovery of $7.5 million associated with the northern portion of SMPE became effective Oct. 1, 2004.

In November 2003, NW Natural filed a general rate case in Washington that proposed a revenue increase of $7.9 million per year from Washington operations through rate increases averaging 15 percent. In June 2004, the WUTC approved a settlement agreement entered into by the parties to NW Natural’s Washington general rate case, which became effective on July 1, 2004, authorizing a revenue increase of $3.5 million per year, or 6.5 percent. In addition, the settlement authorized NW Natural to include the SMPE cost of service of approximately $0.7 million per year in rates, subject to audit, concurrent with the annual Washington PGA filing which became effective on Nov. 1, 2004. See “Rate Mechanisms,” below.

Notwithstanding authorized revenue levels approved by the OPUC or the WUTC, actual revenues are dependent on weather, economic conditions, customer growth, competition and other factors affecting gas usage in NW Natural’s service area.

In January 2005, the Company filed a rate case with the Federal Energy Regulatory Commission (FERC) proposing an update of maximum rates for the Company’s interstate storage services operation and new service offerings. The requested new rates are designed to reflect the costs related to the further development of the Mist gas storage facilities and costs associated with the SMPE project. This filing was made to satisfy FERC’s requirement that there be a cost and revenue review in three years following its original storage service rate authorization.

Weather normalization. In November 2003, NW Natural implemented a weather normalization mechanism in Oregon that helps stabilize net operating revenues, or margin, by adjusting current customer billings based on temperature variances from average weather. The weather normalization mechanism approved by the OPUC is applied to Oregon residential and commercial

customers’ bills between Nov. 15 and May 15 of each heating season. The mechanism adjusts the margin component of customers’ rates to reflect “normal” weather using the 25-year average temperature for each day of the billing period. The mechanism is intended to stabilize fixed costs and to reduce fluctuations in customers’ bills due to colder- or warmer-than-average weather. In October 2004, the mechanism was modified to limit the upward or downward adjustments to individual bills to certain specified ranges, with any excess amounts being deferred (see “Residential and Commercial Sales,” below).

Purchased Gas Adjustment. Rate changes are applied each year under the PGA mechanisms in NW Natural’s tariffs in Oregon and Washington to reflect changes in the costs of natural gas commodity purchased under contracts with gas producers (see “Comparison of Gas Operations—Cost of Gas Sold,” below), the application of temporary rate adjustments to amortize balances in regulatory asset or liability accounts and the removal of temporary rate adjustments effective the previous year. Pursuant to the PGA tariffs, in September 2004, the OPUC approved rate increases effective Oct. 1, 2004 averaging 20.1 percent for Oregon residential sales customers, and in October 2004, the WUTC approved rate increases effective Nov. 1, 2004 averaging 19.5 percent for Washington residential sales customers. These rate increases include deferred revenue from the costs related to the SMPE project, which was completed and placed into service on Sept. 22, 2004. The Oregon increase of 20.1 percent consisted of recovery of gas costs (13.9 percent), temporary rate adjustments (2.5 percent, including deferrals for SMPE) and the recovery of SMPE costs of service (3.7 percent). The Washington increase of 19.5 percent consisted of the recovery of gas costs (12.0 percent), temporary rate adjustments (6.3 percent), and the recovery of SMPE costs (1.2 percent). The inclusion of SMPE costs in Oregon and Washington rates resulted in additional revenue increases totaling $14.7 million per year. During the fourth quarter of 2004, the staff of the OPUC initiated a review of gas purchasing strategies for all three local gas distribution companies serving Oregon. The schedule, scope and potential findings, including the matter of whether the review will lead to formal proceedings before the OPUC, remain uncertain.

In 2003, the OPUC approved a PGA rate increase averaging 3.5 percent for Oregon sales customers and the WUTC approved a PGA rate increase averaging 16.8 percent for Washington sales customers, both effective on Oct. 1, 2003. In 2002, the OPUC approved PGA rate decreases averaging 14 percent for Oregon sales customers and the WUTC approved PGA rate decreases averaging 25 percent for Washington sales customers, both effective on Oct. 1, 2002.

The OPUC has formalized a process that tests for excessive earnings in connection with gas utilities’ annual filings under their PGA mechanisms. The OPUC has confirmed NW Natural’s ability to pass through 100 percent of its prudently incurred gas costs into rates. Under this requirement, NW Natural is authorized to retain all of its earnings up to a threshold level equal to its authorized ROE 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 interest rates. No amounts were identified in this process for refund to customers with respect to 2003 or 2002 earnings results. NW Natural does not expect that amounts will be identified for refund with respect to its earnings in 2004, which will be reviewed by the OPUC in the second quarter of 2005.

Conservation Tariff. Effective Oct. 1, 2002, the OPUC authorized NW Natural to implement a “conservation tariff,” a mechanism designed to recover lost margin due to changes in residential and commercial customers’ consumption patterns. The tariff is a partial decoupling mechanism that breaks the link between the Company’s earnings and the quantity of energy consumed by its customers, so the Company does not have an incentive to discourage customers’ conservation efforts.

The conservation tariff includes two components. The first, a price elasticity factor, adjusts for increases or decreases in consumption attributable to annual changes in commodity costs or periodic changes in the Company’s general rates. The second is a conservation adjustment calculated on a monthly basis to account for deviations between actual and expected volumes. Additional revenues or credits to customers produced by the conservation adjustment are booked to a deferral account that is reconciled as part of the Company’s annual PGA. Baseline consumption is based on customer consumption patterns as determined in the 2003 Oregon general rate case, adjusted for consumption resulting from new customers. The partial decoupling mechanism will expire at the end of September 2005 unless the OPUC approves an extension based on the results of an independent study to measure the mechanism’s effectiveness. Work on the independent review, which involves interested parties, is in process and is expected to be completed by the end of March 2005. The study is expected to provide the basis for the Company’s filing to renew the tariff.

Pipeline Integrity Cost Recovery. In July 2004, the OPUC approved applications by NW Natural relating to the accounting treatment and full recovery for the Company’s cost of its pipeline integrity management program (IMP) as mandated by the Pipeline Safety Improvement Act of 2002 (Pipeline Safety Act) and related rules adopted by the U.S. Department of Transportation’s Office of Pipeline Safety (see “Financial Condition—Cash Flows—Investing Activities,” below). Under the applications as approved, NW Natural classifies its IMP costs as either capital expenditures or regulatory assets, accumulates the costs over each 12-month period ending June 30, and recovers the costs, subject to audit, through rate changes effective on October 1 of each year commencing Oct. 1, 2004. The approved accounting and rate treatment for these costs extends through Sept. 30, 2008, and may be reviewed for potential extension after that date. NW Natural will begin including IMP costs in rates in 2005.

Open Pathway Tariff. The open pathway tariff, approved by the OPUC on Dec. 7, 2004, requires developers to provide the Company with a trench for installation of mains and services in new developments. If a trench is not provided, the tariff requires the developer to pay NW Natural’s costs of trenching. In the past, provision of a trench or reimbursement was not required. Implementation of the tariff began in early 2005.

In August 2004, the OPUC approved a stipulation among NW Natural, the OPUC staff and two parties in the 2003 Oregon general rate case, providing for the settlement of issues raised in an investigation initiated by the OPUC in 2003. These issues relate to transactions or interests in certain properties involving NW Natural in the vicinity of its headquarters building in downtown Portland, and the use of some of these properties for employee parking. The primary effect of the stipulation was to reverse cost recovery as of Sept. 1, 2003, for certain properties that should not have been included in rate base in the 2003 Oregon general rate case, and for certain employee parking costs. Pursuant to the stipulation, NW Natural commenced paying refunds in the amount of $1.3 million to Oregon customers on Oct. 1, 2004, in connection with the annual Oregon PGA filing effective on that date. Approximately $0.3 million of that amount was charged to a reserve in 2003 and the first quarter of 2004; approximately $0.9 million was recognized as a reduction in other revenues in the second quarter of 2004; and the balance of $0.1 million was recognized as a reduction in other revenues in the third quarter of 2004. Effective Oct. 1, 2004, Oregon revenues were reduced by about $0.3 million per year to eliminate these costs from future rates. NW Natural agreed in the stipulation to undergo an audit in 2005 funded by the Company, which is expected to focus on ratemaking issues relating to the inclusion

of assets in rate base and NW Natural’s transactions with any affiliated interests. The OPUC staff informed the Company that the required audit will be performed during the third quarter of 2005.

The following table summarizes the composition of gas utility volumes and revenues for the three years ended Dec. 31:

NW Natural continued to grow its customer base, with a net increase of 18,485 customers during 2004. The growth rate for both 2004 and 2003 was 3.2 percent, compared to 3.5 percent in 2002. In the three years ended Dec. 31, 2004, more than 55,000 customers were added to the system, representing an average annual growth rate of 3.4 percent.

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

Typically, 80 percent or more of annual utility operating revenues are derived from gas sales to weather-sensitive residential and commercial customers. Although variations in temperatures between periods will affect volumes of gas sold to these customers, the effect on margin and net income was significantly reduced with the implementation of the weather normalization mechanism in Oregon beginning in November 2003 (see “Regulatory Matters—Rate Mechanisms,” above). This mechanism applies to meter readings of participating Oregon customers taken between Nov. 15 and May 15. Approximately 10 percent of NW Natural’s residential and commercial customers are in Washington, where the mechanism is not in effect, and about 8 percent of the eligible Oregon customers elected not to be covered by the mechanism, so the mechanism does not fully insulate the Company from utility earnings volatility due to weather. The mechanism contributed a net $9.0 million of margin, equivalent to 20 cents a share of earnings, in the twelve month period ended Dec. 31, 2004, making up a significant portion of the margin that otherwise would have been lost from warmer-than-average weather. In 2003, the mechanism contributed $1.9 million of margin, equivalent to 5 cents a share of earnings, in the two-months after becoming effective in November 2003.

Total utility operating revenues include accruals for gas delivered but not yet billed to customers (unbilled revenues) based on estimates of gas deliveries from that month’s meter reading dates to month end. Amounts reported as unbilled revenues reflect the increase or decrease in the balance of accrued unbilled revenues compared to the prior year-end. Weather conditions, rate changes and customer billing dates affect the balance of accrued unbilled revenue at the end of each month. At Dec. 31, 2004, accrued unbilled revenue was $64.4 million, compared to $59.1 million at Dec. 31, 2003.

The following table summarizes the delivered volumes and utility operating revenues in the industrial and electric generation markets:

Total volumes delivered to industrial and electric generation customers were 39 million therms, or 7 percent, higher in 2004 than in 2003, and utility operating revenues were up $37 million, or 50 percent. The higher volumes and revenues partially reflect an improving economy, but results primarily reflect a continued shift from transportation to sales volumes and the reclassification of a relatively large number of commercial customers to the industrial customer category over the past 24 months resulting from rate design changes in Oregon. Over the past two years, the number of industrial customers increased 30 percent from 2002 to 2003, and 24 percent from 2003 to 2004. Industrial rates in Oregon were redesigned as part of the general rate case in 2003, transferring $4.8 million of annual revenue requirement from industrial rates to residential and commercial rates in order to better reflect relative costs of service and to improve the competitiveness of the Company’s rates in the industrial market.

Total volumes delivered to industrial and electric generation customers were 18 million therms, or 3 percent, lower in 2003 than in 2002, and utility operating revenues were down $10 million, or 11 percent. Results from the industrial market in 2003 reflect weaker economic conditions during the year, and most of the incremental revenue decline was due to a shift from higher margin firm schedules to lower margin interruptible schedules and industrial rate decreases effective in September 2003.

The decline in volumes and operating revenues from the electric generation market primarily reflect the winding down of a temporary market that emerged in response to the 2001-2002 energy crisis. The volumes and operating revenues in 2002 were related to two customers served under contracts that went into effect in the second half of 2001 and expired at the end of the second quarter of 2002. Most of the revenues from these contracts were derived from fixed charges. A third electric generation customer used 3.0 million therms in 2002 under a contract with low volumetric charges.

Other revenues include miscellaneous fee income as well as revenue adjustments reflecting deferrals to, or amortizations from, regulatory asset or liability accounts other than deferrals relating to gas costs (see Note 1). Other revenues increased net operating revenues by $3.2 million in 2004, compared to $7.5 million in 2003 and $4.0 million in 2002. The following table summarizes other revenues by primary category for the three years ended Dec. 31, 2004, 2003 and 2002:

Other revenues in 2004 were $4.3 million lower than in 2003 primarily due to the change in decoupling deferrals under the decoupling mechanism (down $2.8 million) (see “Regulatory Matters—Rate Mechanisms,” above), the amortization of decoupling deferrals from prior periods (up $2.2 million) and an increase in other miscellaneous amortizations (up $1.6 million), partially offset by higher interstate storage credits from revenue sharing from the Company’s interstate gas storage services (up $2.3 million).

Other revenues in 2003 included positive contributions due to the change in decoupling deferrals (up $1.7 million), the amortization of income shared with customers from interstate gas storage services (up $1.8 million), and customer late payment and collection fees and miscellaneous revenues, partially offset by amortizations from regulatory accounts covering conservation programs and Year 2000 technology costs.

Natural gas commodity prices have fluctuated significantly in recent years. The effects of higher gas commodity prices and price volatility on core utility customers are mitigated through the use of underground storage facilities, gas commodity-price financial hedge contracts, and short-term

sales of gas commodity and transportation capacity to on-system or off-system customers in periods when core utility customers do not require the full firm pipeline capacity and gas supplies.

The Company regularly renews or replaces its expiring long-term and medium-term contracts with new agreements with a variety of existing and new suppliers. No single contract amounts to more than 200,000 therms per day or 10 percent of the Company’s average daily contract volumes. Firm year-round supply contracts have terms ranging from one to ten years. All of the contracts use price formulas tied to monthly index prices, primarily at the NOVA Inventory Transfer trading point in Alberta. NW Natural hedges a majority of its contracts each year using financial instruments as part of its gas purchase strategy.

The total cost of gas sold was $399.2 million in 2004, an increase of $76.1 million or 24 percent compared to 2003 and, 2003 was $29.9 million or 8 percent lower than 2002. The cost per therm of gas sold was 14 percent higher in 2004 than in 2003 and 9 percent lower in 2003 than in 2002. 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, demand cost balancing adjustments (demand equalization), regulatory deferrals and company use. Results for 2002 included an adjustment that reduced cost of gas by $29.5 million, a result of a refund to customers. Excluding this adjustment, cost per therm of gas sold was 16 percent lower in 2003 than in 2002, reflecting decreases in gas commodity prices effective in late 2002.

Results for 2002 also included adjustments reducing cost of gas relating to amounts of deferred expenses for the recovery of pipeline demand charges under the PGA mechanism. These adjustments contributed 7 cents a share to earnings in 2002, of which 6 cents a share applied to periods prior to 2002. The rate methodology represented in the adjustments continues to be applied in the Company’s accounting for pipeline demand charges.

NW Natural’s recorded amount of unaccounted-for gas was 0.51 percent of gas sendout in 2004, compared to 0.55 percent in 2003 and 0.75 percent in 2002. Unaccounted-for gas is the difference between the amount of gas the Company receives from all sources, including pipeline deliveries and withdrawals from storage, and the amount of gas it delivers to customers or other delivery points. Unaccounted-for gas may be caused in part by physical gas leakage, but it also may be due to cumulative inaccuracies in gas metering, estimates of unbilled gas or other causes. A normal amount of unaccounted-for gas is considered to be 0.50 percent of total gas sendout during a period, but the amounts may vary within a range around this estimate. During 2004, the lower estimated amount of unaccounted-for gas had the effect of increasing cost of gas and decreasing margin by $0.4 million as compared to 2003. During 2003, the lower estimated amount of unaccounted-for gas had the effect of reducing cost of gas and increasing margin by $1.2 million as compared to 2002. The estimated percentages of unaccounted-for gas in 2004 and 2003 were lower than 2002, partially due to improvements in gas measurement and estimating.

NW Natural uses a natural gas commodity-price hedge program under the terms of its Derivatives Policy to help manage its variable price gas commodity contracts (see “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” above). NW Natural recorded net hedging gains of $42.4 million from this program during 2004, compared to net hedging gains of $32.4 million in 2003 and net hedging losses of $75.5 million in 2002. Hedging gains and losses relating to gas commodity purchases are included in cost of gas and factored into NW Natural’s annual PGA rate changes, and therefore have no material impact on net income.

Under NW Natural’s PGA tariff in Oregon, net income is affected within defined limits by changes in purchased gas costs. NW Natural is allowed to collect an amount for purchased gas costs based on estimates that are included in current utility rates. If the actual purchased gas costs are higher than the amounts included in rates, NW Natural is not allowed to charge its customers currently for those higher gas costs but is allowed to defer the costs and collect them in the future. Similarly, when the actual purchased gas costs are lower than the amount included in rates, the savings are not immediately passed on to customers but are deferred and refunded in future periods. NW Natural absorbs 33 percent of the higher cost of gas sold, or retains 33 percent of the lower cost, in either case as compared to the projected costs built into rates. The remaining 67 percent of the higher or lower gas costs is recorded as deferred regulatory assets or liabilities for recovery from or refund to customers in future rates. In 2004 and 2003, NW Natural’s gas costs were slightly lower than the gas costs embedded in rates, with the effect that NW Natural’s share of the lower costs increased margin by $0.6 million and $0.3 million, equivalent to 1 cent a share and less than 1 cent a share of earnings, respectively. In 2002, NW Natural’s gas costs were much lower than the projected costs built into rates and the Company’s share of the savings realized from gas purchases contributed $10.8 million of margin, equivalent to 26 cents a share of earnings.

NW Natural uses gas supplies and transportation capacity that are not required for core utility residential, commercial and industrial firm customers to make off-system sales. Under the PGA tariff in Oregon, NW Natural retains 33 percent of the margins realized from its off-system gas sales and records the remaining 67 percent as a deferred regulatory asset or liability for recovery from or refund to customers in future rates. NW Natural’s share of margin from off-system gas sales in 2004 resulted in a loss of $0.3 million, equivalent to less than 1 cent a share. NW Natural’s share of margin from off-system gas sales in 2003 was $4.9 million, equivalent to 11 cents a share of earnings. Results for 2003 reflected a higher volume of off-system gas sales because of warmer weather in the first quarter and higher gas prices. NW Natural was able to use gas supplies that were available under contract for the winter season, but not required for delivery to core utility market customers, to make these off-system sales. NW Natural’s purchase price for this gas had been fixed through commodity swap and call option contracts entered into earlier at levels substantially below the market prices in 2003. NW Natural’s share of margin from off-system sales in 2002 was $0.9 million or 2 cents a share.

NW Natural earned net income from its non-utility interstate gas storage business segment in 2004, after regulatory sharing and income taxes, of $2.9 million or 11 cents a share, compared to $4.3 million or 17 cents a share in 2003 and $3.6 million or 14 cents a share in 2002 (see Note 2). Earnings from this business segment were lower in 2004 primarily due to a lower contribution from a contract with an independent energy marketing company that optimizes the value of NW Natural’s assets by engaging in trading activities using temporarily unused portions of its upstream pipeline transportation capacity and gas storage capacity. The lower contribution was primarily due to a change in market conditions in which gas price differentials were less volatile in 2004 compared to 2003.

In Oregon, NW Natural retains 80 percent of the pre-tax income from interstate storage services and optimization of storage and pipeline transportation capacity when the costs of such capacity have not been included in core utility rates, and 33 percent of the pre-tax income from such optimization when the capacity 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 NW Natural’s core utility customers. NW Natural has a similar sharing mechanism in Washington for revenue derived from third party optimization services.

Financial Corporation’s operating results in 2004 were net income of $0.2 million, compared to $0.7 million in 2003 and $1.2 million in 2002. The decrease in net income in 2004 compared to 2003 was primarily due to a $0.5 million write-down of its limited partnership interests in three solar electric generation projects. The write-down related to an agreement to sell these projects on Jan. 31, 2005. The decrease in net income in 2003 compared to 2002 was due to lower income from investments in limited partnerships in wind and solar electric generation projects in California.

The Company’s investment in Financial Corporation was $5.7 million at Dec. 31, 2004, compared to $5.5 million at Dec. 31, 2003.

Northwest Energy was formed in 2001 to serve as the holding company for NW Natural and PGE if the acquisition of PGE had been completed. Northwest Energy recorded nominal expenses for corporate development activities in 2004. Upon the termination of the proposed acquisition effort in 2002, Northwest Energy recorded a loss totaling $8.4 million (after tax) for the transaction costs incurred in connection with this effort. These charges were equivalent to 33 cents a share. Northwest Energy was inactive during both 2004 and 2003.

Operations and maintenance expenses increased $5.7 million, or 6 percent, in 2004 compared to 2003, and increased $11.3 million, or 13 percent, in 2003 compared to 2002. The following summarizes the major factors that contributed to changes in operations and maintenance expense:

Most of the cost increases NW Natural experienced in 2004 and 2003 were included in the rate increases approved in the Company’s general rate cases in Oregon and Washington (see “Regulatory Matters—General Rate Cases,” above).

Taxes other than income taxes, which are principally comprised of property, franchise and payroll taxes, increased $3.7 million, or 11 percent, in 2004 compared to 2003, and increased $1.0 million, or 3 percent, in 2003 compared to 2002. The following table summarizes the changes in taxes other than income taxes:

The increase in franchise taxes in 2004 is primarily related to the increase in total utility operating revenues resulting from higher gas rates (see “Comparison of Gas Distribution Operations,” above); the increase in payroll taxes is primarily related to the increase in payroll expense (see “Operations and Maintenance,” above); and the increase in property taxes is primarily related to increased utility plant in service (see Note 9).

The following table summarizes the increases in total plant and property and total depreciation and amortization for the three years ended Dec. 31, 2004:

The Company’s total depreciation and amortization expense increased by $3.1 million, or 6 percent, in 2004 and by $2.2 million, or 4 percent, in 2003. The increased expense for both years is primarily due to additional investments in utility property that were made to meet continuing customer growth, including the Company’s investment in the SMPE that was put into service in November 2003 and September 2004 (see “Financial Condition—Cash Flows—Investing Activities,” below).

Other income (expense) improved by $0.7 million in 2004. The increase was primarily due to reductions in interest charges on deferred regulatory account balances ($1.1 million) reflecting lower net credit balances outstanding in these accounts. This increase was partially offset by a decrease in gains from Company-owned life insurance ($0.6 million) due to decreases in the market value of equity-based life insurance investments.

Other income (expense) improved by $17.0 million in 2003, primarily due to the $13.9 million pre-tax charge in 2002 for costs incurred in the effort to acquire PGE. Excluding this charge, other income (expense) increased by $3.1 million in 2003. The increase was primarily due to reductions in interest charges on deferred regulatory account balances ($1.4 million) reflecting lower net credit balances outstanding in these accounts, and an increase in gains from Company-owned life insurance ($2.0 million) due to increases in the market value of equity-based life insurance investments, partially offset by a decrease in earnings from equity investments ($0.5 million) due to lower income from partnership investments held by Financial Corporation.

Interest charges-net of amounts capitalized in 2004 was $0.7 million, or 2 percent, higher than in 2003. The increase in 2004 was primarily due to higher balances of debt outstanding during the period. The increase was partially offset by lower average interest rates and higher amounts of Allowance for Funds Used During Construction (AFUDC) due to higher average balances of construction work in progress (CWIP). AFUDC represents the cost of funds used for CWIP (see Note 1). In 2004, AFUDC reduced interest expense by $1.0 million compared to reductions of $0.9 million in 2003 and $0.6 million in 2002. The average interest rate component of AFUDC, comprised of short-term and long-term borrowing rates, as appropriate, was 3.0 percent in 2004, 2.3 percent in 2003 and 2.8 percent in 2002.

Interest charges-net of amounts capitalized in 2003 was $1.0 million, or 3 percent, higher than in 2002, also due to higher balances of debt outstanding and to the inclusion of dividends paid in the second half of 2003 totaling $0.2 million on the Company’s redeemable preferred stock, due to their classification as interest expense upon the adoption of SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.”

The effective corporate income tax rates were 34.4 percent, 33.7 percent and 34.9 percent for the years ended Dec. 31, 2004, 2003 and 2002, respectively. The higher rate in 2004 reflects the effect of decreased tax benefits from a non-taxable gain on Company- and trust-owned life insurance ($0.6 million), decreased tax benefits attributed to tax adjustments recorded in the prior year ($0.3 million), decreased tax benefits resulting from a taxable gain on the surrender of certain Company-owned life insurance ($0.1 million) and the expiration of a federal low-income housing tax credit ($0.1 million), partially offset by the effect of increased tax benefits from an adjustment of the Company’s deferred income tax balances ($0.5 million). Excluding the impact of these tax benefits taken into account during 2004, the effective tax rate for 2004 would have been 35.0 percent. The lower tax rate for 2003 reflects increased tax benefits from a non-taxable gain on Company- and trust-owned life insurance. Excluding these benefits, the effective tax rate for 2003 would have been 35.0 percent. The tax rate for 2002 includes the effect of the tax benefits from the $13.9 million charge for PGE transaction costs. Excluding this charge, the effective tax rate for 2002 would have been 35.6 percent.

Redeemable preferred and preference stock dividend requirements decreased $0.3 million in 2004 compared to 2003 due to the redemption in November 2003 of all outstanding shares of the Company’s $7.125 Series of Redeemable Preferred Stock with an aggregate stated value of $7.5 million at the applicable early redemption price of 102.375 percent. No shares of redeemable preferred or preference stock were outstanding at any time during 2004.

Redeemable preferred and preference stock dividend requirements decreased $2.0 million in 2003 compared to 2002 due to the redemption in December 2002 of all of the outstanding shares ($25 million aggregate stated value) of the Company’s $6.95 Series of Redeemable Preference Stock pursuant to the mandatory redemption provisions applicable to that Series.

The Company’s goal is to maintain a target capital structure comprised of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt. When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources also are used to meet long-term debt redemption requirements and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below, and Notes 3 and 5). The Company’s consolidated capital structure at Dec. 31 was as follows:

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.

At Dec. 31, 2004, the Company had $5.2 million in cash and cash equivalents compared to $4.7 million at Dec. 31, 2003. Short-term liquidity is provided by cash from operations and from the sale of commercial paper notes, which are supported by committed bank lines of credit. The Company has available through Sept. 30, 2005 committed lines of credit totaling $150 million with four commercial banks (see “Lines of Credit,” below, and Note 6). Short-term debt balances typically are reduced toward the end of the winter heating season as a significant amount of the Company’s current assets, including accounts receivable and natural 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 and gas supply purchase and other contracts require an adequate source of funding. These capital and contractual expenditures are financed through cash from operations and from the issuance of short-term debt, which is periodically refinanced through the sale of long-term debt or equity securities.

To provide long-term financing, in February 2004 the Company filed a universal shelf registration with the Securities and Exchange Commission (SEC) providing for the issuance and sale of up to $200 million of securities, which may consist of secured debt (First Mortgage Bonds), unsecured debt, preferred stock or common stock. Concurrent with this shelf filing, the Company deregistered the $60 million of Medium-Term Notes (MTNs) remaining on its previous shelf registration. The $200 million universal shelf registration statement became effective in February 2004. In April 2004, the Company issued $40 million of common stock under the shelf registration, leaving $160 million available for the issuance of debt or equity securities (see “Financing Activities,” below).

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

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

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

NW Natural has paid quarterly dividends on its 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 the Company’s common stock are within the sole discretion of the Company’s Board of Directors. It is the intention of the Board of Directors to continue to pay cash dividends on the Company’s common stock on a quarterly basis. However, future dividends will be dependent upon NW Natural’s earnings, its financial condition and other factors.

The following table shows the Company’s contractual obligations by maturity and type of obligation. NW Natural also has obligations with respect to its pension and post-retirement medical benefit plans (see Note 7).

Other purchase commitments primarily consist of remaining balances under existing purchase orders and remaining payments due to a general contractor for the construction of the remaining portion of the SMPE project. 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 accelerate the maturities by $10 million in 2005 and by $20 million in each of 2007, 2008 and 2009. The interest coupon rate on the long-term debt issues with put options range between 6.52 percent and 7.05 percent.

On March 12, 2004, NW Natural employees who are members of the OPEIU, Local No. 11, approved a new labor agreement (Joint Accord) covering wages, benefits and working conditions that will expire on May 31, 2009. In accordance with the terms of the Joint Accord, beginning Jan. 1, 2005, the Company will commence making contributions to a multi-employer trust that will provide additional retirement benefits to its bargaining unit employees.

The Company’s primary source of short-term funds is from the sale of commercial paper notes payable. In addition to issuing commercial paper to meet seasonal working capital requirements, including the financing of gas purchases and accounts receivable, short-term debt is also used temporarily to fund capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. NW Natural’s outstanding commercial paper, which is sold under an agency agreement with a commercial bank, is supported by committed bank lines of credit (see “Lines of Credit,” below). NW Natural had $102.5 million in commercial paper notes outstanding at Dec. 31, 2004, compared to $85.2 million outstanding at Dec. 31, 2003.

Effective Oct. 1, 2004, NW Natural entered into lines of credit with Bank of America, N.A., JP Morgan Chase Bank, U.S. Bank National Association, and Wells Fargo Bank, totaling $150 million in aggregate. Half of the credit facility with each bank, or $75 million, is committed and available through Sept. 30, 2005, and the other $75 million is committed and available through Sept. 30, 2007. Bank of America, N.A., JP Morgan Chase Bank, and U.S. Bank National Association have each committed $20 million for each of their 2005 and 2007 lines of credit, and Wells Fargo Bank has committed $15 million for each of its 2005 and 2007 lines of credit.

Under the terms of these lines of credit, NW Natural pays commitment fees but is not required to maintain compensating bank balances. The interest rates on any outstanding borrowings under these lines of credit are based on current market rates. There were no outstanding balances on these lines of credit at Dec. 31, 2004 or 2003.

NW Natural’s lines of credit require that credit ratings be maintained in effect at all times and that notice be given of any change in its senior unsecured debt ratings. A change in NW Natural’s credit rating is not an event of default, nor is the maintenance of a specific minimum level of credit rating a condition to drawing upon the lines of credit. However, interest rates on any loans outstanding under NW Natural’s bank lines are tied to credit ratings, which would increase or decrease the cost of debt outstanding under these lines of credit, if any, when ratings are changed.

The lines of credit require the Company to maintain an indebtedness to total capitalization ratio of 65 percent or less and to maintain a consolidated net worth at least equal to 80 percent of its net worth at Sept. 30, 2004, plus 50 percent of the Company’s net income for each subsequent fiscal quarter. NW Natural was in compliance with the covenants as of Dec. 31, 2004, with an indebtedness to total capitalization ratio of 52 percent and a net worth of $568.5 million compared to a required $452.1 million. The Company was also in compliance with these covenants under

previous line of credit agreements in effect as of Dec. 31, 2003. Failure to comply with either of these covenants would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding.

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

In December 2004, NW Natural’s corporate credit rating was upgraded by S&P to “A+” from “A”, which also assigned NW Natural a business profile score of “1” on a scale of “1” to “10”, where “1” is the strongest score. Each of the rating agencies has assigned NW Natural an investment grade rating. These credit ratings and business profile scores are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommendation to buy, sell or hold the Company’s securities. Each rating should be evaluated independently of any other rating.

In 2003, the Company exercised early redemption provisions applicable to certain of its long-term debt, including all $4 million of the 7.50% Series B MTNs due 2023, all $11 million of the 7.52% Series B MTNs due 2023, and all $20 million of the 7.25% Series B MTNs due 2023. These MTNs were redeemed in the third quarter of 2003 at 103.75 percent, 103.76 percent and 103.65 percent of their respective principal amounts. In the fourth quarter of 2003, the Company also exercised early redemption provisions applicable to all of the remaining shares of its $7.125 Series of Redeemable Preferred Stock with an aggregate stated value of $7.5 million, at a redemption price equivalent to 102.375 percent. The Company redeemed the MTNs and the preferred stock with available cash or with the proceeds from sales of commercial paper, and re-financed this long-term debt and preferred stock through the sale of new long-term debt in the fourth quarter of 2003. Early redemption premiums are recognized as unamortized costs on debt redemptions pursuant to SFAS No. 71 and are amortized to expense over the life of the new debt.

Year-over-year changes in the Company’s operating cash flows are primarily affected by net income and non-cash adjustments to net income. In 2004, net income and non-cash adjustments to net income increased by $18 million, but the cash flow increase was offset by increases in working capital requirements within the utility segment resulting from warmer weather, higher prices of natural gas, and the timing of customer collections, payments for natural gas purchases and deferred gas cost

recoveries. In 2003, net income and non-cash adjustments to net income decreased by $18 million primarily due to a $13.9 million non-cash write-down of PGE acquisition costs.

The following table summarizes cash provided by operating activities for the years ended Dec. 31, 2004, 2003 and 2002:

The overall change in cash flow from operations was negligible in 2004 compared to 2003, but decreased by $16 million in 2003 compared to 2002. The significant factors contributing to the cash flow changes between years are as follows:

The Company has lease and purchase commitments relating to its operating activities that are financed with cash flows from operations (see “Liquidity and Capital Resources,” above, and Note 12).

The Job Creation and Worker Assistance Act of 2002 (the Assistance Act) combined with the Jobs and Growth Tax Relief Reconciliation Act of 2003 (the Reconciliation Act), allowed for an additional first-year tax depreciation deduction on the adjusted basis of “qualified property.” 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 additional first-year depreciation deduction is an acceleration of depreciation deductions that otherwise would have been taken in the later years of an asset’s recovery period. The accelerated depreciation provisions provided by both the Assistance Act and the Reconciliation Act expired at Dec. 31, 2004. The Company realized enhanced cash flow from reduced income taxes totaling an estimated $55 million during the effective period, based on plant investments made between Sept. 11, 2001 and Dec. 31, 2004.

Cash requirements for investing activities in 2004 totaled $136 million, up from $128 million in the same period of 2003. Cash requirements for the acquisition and construction of utility plant totaled $141 million, up from $125 million in 2003. The increase in cash requirements for utility construction in 2004 was primarily the result of higher capital expenditures relating to NW Natural’s SMPE project to extend the pipeline from its Mist gas storage field to serve growing portions of its service area ($22 million). The SMPE was completed and placed into service in September 2004. The total cost of the project was approximately $110 million, which includes amounts reflected in investing activities over the past few years. The cost of service associated with the SMPE project, net of deferred tax benefits, was included in customer rates starting in the fourth quarter of 2004.

Cash requirements for investing activities in 2003 totaled $128 million, up from $85 million in 2002. Cash requirements for the acquisition and construction of utility plant totaled $125 million, up from $80 million in 2002. The increase in cash requirements for utility construction in 2003 was primarily the result of higher capital expenditures relating to the SMPE project ($27 million), higher system improvements and support ($12 million) and other special projects to serve new customer load or new service areas ($9 million).

Investments in the Company’s pipeline integrity management program (IMP) were $1.6 million in 2004, compared to $0.9 million in 2003. IMP costs are estimated at approximately $50 million to $100 million over a ten-year period (see discussion below). IMP costs are classified as either capital expenditures or regulatory assets. The costs are accumulated over each 12-month period ending June 30, and the costs, subject to audit, are recovered through rate changes effective on Oct. 1 of each year commencing Oct. 1, 2004. The approved accounting and rate treatment for these costs extends through Sept. 30, 2008, and it may be reviewed for potential extension after that date.

Investments in non-utility property totaled $10.6 million in 2004, compared to $2.6 million in 2003. The higher investments in 2004 compared to 2003 were primarily for certain improvements to the Company’s gas pipeline system that were related to interstate gas storage services.

In December 2004, the Company received proceeds from the surrender of certain life insurance policies and proceeds from the settlement of life insurance benefits totaling $17.6 million.

During the five-year period 2005 through 2009, utility construction expenditures are estimated at between $500 million and $600 million. The level of capital expenditures over the next five years reflects projected high customer growth and system improvement projects resulting in part from requirements under the Pipeline Safety Improvement Act of 2002 (Pipeline Safety Act) (see below). A majority of the required funds is expected to be internally generated over the five-year period; the remainder will be funded through a combination of long-term debt and equity securities with short-term debt providing liquidity and bridge financing.

NW Natural’s utility and non-utility capital expenditures in 2005 are estimated to total $110 million, including $28 million for customer growth, $21 million for system improvement and support, $15 million for equipment, facilities and information technology, $10 million for IMP costs, $6 million for the SMPE and related gas storage projects, $9 million for utility and non-utility storage and $21 million for construction overhead.

In December 2003, the U.S. Department of Transportation’s Office of Pipeline Safety issued a rule that specifies the detailed requirements for transmission pipeline IMPs as mandated by the Pipeline Safety Act. The Pipeline Safety Act requires operators of gas transmission pipelines to identify lines located in High Consequence Areas (HCAs) and to develop IMPs to periodically inspect the integrity of the pipelines and make repairs or replacements as necessary to ensure the ongoing integrity of the pipelines. The legislation requires NW Natural to inspect the 50 percent highest risk pipelines located in its HCAs within the first five years, and to inspect the remaining covered pipelines within 10 years of the date of the enactment. The Pipeline Safety Act also requires re-inspections of the covered pipelines every seven years from the date of the previous inspection for the life of the pipelines.

Cash provided by financing activities in 2004 totaled $29 million, compared to $17 million in 2003. Factors contributing to the $12 million increase were the net proceeds ($38.5 million) from a common stock offering in April 2004 (see below), combined with last year’s redemption of the $7.125 Series of Preferred Stock ($8.4 million), offset by last year’s increase in long-term debt balances ($35.0 million).

Cash provided by financing activities in 2003 totaled $17 million, compared to cash used in financing activities in 2002 of $43 million. Factors contributing to the $60 million difference

were an increase in short-term debt in 2003 ($15.4 million) compared to a decrease in 2002 ($38.5 million) and the redemption of the $6.95 Series of Preference Stock in 2002 ($25 million), partially offset by a higher amount used for the retirement of long-term debt ($55 million in 2003 compared to $40.5 million in 2002) and the redemption, including the annual sinking fund, of the $7.125 Series of Preferred Stock in 2003 ($8.4 million).

NW Natural sold $90 million of its secured Medium-Term Notes, Series B (MTNs) in each of 2003 and 2002 and used the proceeds to redeem long-term debt ($55 million in 2003 and $40.5 million in 2002), to provide cash for investments in utility plant and to reduce short-term borrowings.

In April 2004, the Company issued and sold 1,290,000 shares of its common stock in an underwritten public offering, and used the net proceeds of $38.5 million from the offering to reduce short-term indebtedness by about $29 million and to fund, in part, NW Natural’s utility construction program. The offering of common stock was made pursuant to NW Natural’s universal shelf registration statement providing for the registration of $200 million of securities, which became effective in February 2004. After the common stock offering, approximately $160 million remains available under the shelf registration statement for the Company to issue additional securities, which may include First Mortgage Bonds and unsecured debt.

In 2000, NW Natural commenced a program to repurchase up to 2 million shares, or up to $35 million in value, of its common stock through a repurchase program that has been extended through May 2005. The purchases are made in the open market or through privately negotiated transactions. No shares were repurchased in 2003 or in 2004. Since the program’s inception the Company has repurchased 355,400 shares of common stock at a total cost of $8.2 million.

Net periodic pension cost (NPPC) is determined in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” (see “Application of Critical Accounting Policies—Accounting for Pensions,” above). The annual pension cost or income is allocated between operations and maintenance expense and construction overhead.

NPPC for the Company’s two qualified defined benefit plans totaled $6.6 million in 2004, an increase of $0.4 million over NPPC for these plans of $6.2 million in 2003. The increased NPPC was primarily due to the use of a lower discount rate (6.25 percent in 2004 compared to 6.75 percent in 2003) which had the effect of increasing the two plans’ accumulated benefit obligations.

During 2004, the Company contributed $5.3 million to its Retirement Plan for Non-Bargaining Unit Employees (NBU Plan) for plan year 2004, of which $1.0 million represented the minimum required funding. The Company was not required to make any contribution to its Retirement Plan for Bargaining Unit Employees (BU Plan) for that year. The Company’s funding policy is to contribute at least the minimum amount required by the Employee Retirement Income Security Act of 1974, as amended. For accounting expense recognition, the Company uses an asset valuation (market-related valuation) method that spreads variances between expected returns and actual investment returns over a three-year period, but for funding purposes the Company spreads these differences over a five-year period. In 2004, the Company made additional tax-deductible contributions to improve the funded status of its qualified pension plans. In 2005, no contributions are required to be made to fund either the NBU Plan or the BU Plan, and the Company does not anticipate making any additional voluntary contributions for the 2004 plan year.

The fair market value of the two plans’ assets increased to $186.8 million at Dec. 31, 2004, up from $168.3 million at Dec. 31, 2003. The increase included $22.5 million in investment gains and employer contributions of $8.3 million, which were offset in part by $11.2 million in withdrawals to pay benefits and $1.1 million in eligible expenses of the two plans. The present value of benefit obligations under the two plans increased from an estimated $192 million to $209 million during 2004, however, so the two plans remained under-funded in aggregate by about $22 million at Dec. 31, 2004.

NPPC for the NBU Plan and the BU Plan was $6.2 million in 2003, compared to net periodic pension income of $0.1 million in 2002. The increased NPPC in 2003 was largely due to investment losses in 2002, which are recognized over a three-year period, and to the use of a lower discount rate (6.75 percent in 2003 compared to 7.25 percent in 2002) which increased the plans’ accumulated benefit obligations. During 2004, the Company made a cash contribution of $2.9 million to the NBU Plan for the 2003 plan year, of which $1.9 million represented the minimum required funding. No contributions were required to be made to either the NBU Plan or the BU Plan for the 2002 plan year.

At Dec. 31, 2003, the fair market value of the assets of the NBU Plan and the BU Plan totaled $168.3 million, up from $143.2 million at Dec. 31, 2002. The increased market value included $36 million in investment gains, which was partially offset by $10 million in withdrawals to pay benefits and $0.9 million in eligible expenses of the plans. At Dec. 31, 2003, the present value of benefit obligations under the two plans totaled $192 million and thus were under-funded in aggregate by about $24 million.

Despite the increase in NPPC and the current under-funded status of the NBU Plan, NW Natural believes it will be able to maintain well-funded qualified pension plans. NW Natural does not expect its current or future cash contribution requirements to the two plans to have a material adverse effect on its liquidity or financial condition (see Note 7).

For the years ended Dec. 31, 2004, 2003 and 2002, the Company’s ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were 3.02, 2.84 and 2.85, 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.

The Company is subject to federal, state and local laws and regulations related to environmental matters. These evolving laws and regulations may require expenditures over a long timeframe to control environmental impacts. The Company believes that appropriate investigation or remediation is being undertaken at all the relevant sites. Based on existing knowledge, the Company does not expect that the ultimate resolution of these matters will have a material adverse effect on its financial condition, results of operations or cash flows. (See Note 12).

In May 2003, the OPUC approved NW Natural’s request for deferral of environmental costs associated with specific sites. The authorization, which has been extended through April 2005, allows NW Natural to defer and seek recovery of unreimbursed environmental costs in a future general

rate case. NW Natural has filed a request with the OPUC to extend this authority through January 2006. On a cumulative basis through Dec. 31, 2004, the Company paid out a total of $3.3 million relating to the sites since the effective date of the deferral authorization. (See Note 12).

NW Natural will first seek to recover the costs of investigation and remediation for which it may be responsible with respect to environmental matters, if any, from insurance. If these costs are not recovered from insurance, then NW Natural will seek recovery through future rates subject to approval by the OPUC. At Dec. 31, 2004, NW Natural had an $8.5 million receivable representing an estimate of the environmental costs it expects to incur and recover from insurance. (See Note 12).

The Company is exposed to various forms of market risk including commodity supply risk, weather risk, and interest rate risk. The following describes the Company’s exposure to these risks.

NW Natural enters into short-term, medium-term and long-term natural gas supply contracts, along with associated short-, medium- and long-term transportation capacity contracts. Historically, NW Natural has taken physical delivery of at least the minimum quantities specified in its 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. NW Natural’s PGA mechanism in Oregon and Washington provides for the recovery from customers of actual commodity costs, except that, for Oregon customers, NW Natural absorbs 33 percent of the higher cost of gas sold, or retains 33 percent of the lower cost, in either case as compared to the annual PGA price built into customer rates.

To the degree that market risks exist due to potential adverse changes in commodity prices, foreign exchange rates or counterparty credit quality in relation to these financial and physical contracts, the Company considers the risks to be:

The prices of natural gas commodity 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 included in the Company’s annual PGA filing, subject to a prudency review. At Dec. 31, 2004 and 2003, notional amounts under these commodity swap and call option contracts totaled $413.0 million and $304.1 million, respectively. At Dec. 31, 2004, five of these financial hedge contracts extended beyond Dec. 31, 2005. If all of the commodity-price swap and call option contracts had been settled on Dec. 31, 2004, a regulatory gain of $10.5 million would have been realized (see Note 11).

The costs of natural gas commodity 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 rates with respect to the purchases of natural gas from Canadian suppliers. At Dec. 31, 2004 and 2003, notional amounts under foreign currency forward contracts totaled $14.5 million and $6.4 million, respectively. As of Dec. 31, 2004, no foreign currency forward contracts extended beyond Dec. 31, 2005. If all of the foreign currency forward contracts had been settled on Dec. 31, 2004, a gain of $0.4 million would have been realized (see Note 11).

Certain suppliers that sell gas to NW Natural have either relatively low credit ratings or are not rated by major credit rating agencies. To manage this supply risk, the Company purchases gas from a number of different suppliers, with no single supplier accounting for more than 20 percent of the Company’s total purchases for a given monthly period. The Company also evaluates suppliers’ creditworthiness and maintains 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. These costs would be subject to the PGA sharing mechanism discussed above. Since most of the Company’s commodity supply contracts are priced at the monthly market index price, and the Company has significant storage flexibility, it is unlikely that a supplier default would have a materially adverse impact on the Company’s financial condition.

With respect to the financial counterparties the Company uses for entering into commodity price hedge contracts, NW Natural’s Derivatives Policy requires each counterparty to be at least two rating grades above non-investment grade. Because counterparty ratings are subject to change at any time, the Company could have contracts outstanding with counterparties whose ratings are non-investment grade. NW Natural’s counterparty credit exposure as of Dec. 31, 2004 was as follows:

Due to the volatility of natural gas commodity prices, the market value and credit exposure of certain derivative contracts could exceed the Company’s credit limits established in its Derivatives Policy. If such credit limits were exceeded, the Company would have the ability to require collateral from the counterparty and would not enter into any further contracts with that counterparty until it was within the limits. If a counterparty failed to perform under its contract, NW Natural could sustain a loss which would be included in the annual PGA adjustment, subject to a regulatory prudency review. Under certain circumstances, a counterparty default could result in a material loss. However, based on the Company’s current regulatory mechanism, the absence of any significant position with a single counterparty and the strength of the counterparties’ current credit ratings, any such loss is not expected to have a material impact on the Company’s financial condition.

The Company is exposed to weather risk primarily from its regulated utility business. A large portion of the Company’s net operating revenues (margin) is volume driven, and current rates are based on an assumption of normal weather. In 2003, the OPUC approved a weather normalization mechanism for residential and commercial customers. This mechanism affects customer bills between Nov. 15 through May 15 of each winter heating season, increasing or decreasing the margin component of customers’ rates to reflect “normal” weather using the 25-year average temperature for each day of the billing period. The mechanism is intended to stabilize the recovery of the 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 Dec. 31, 2004, about 8 percent of the Company’s Oregon customers had opted out. In addition to the Oregon customers opting out, the Company’s Washington customers are not covered by weather normalization. The combination of Oregon and Washington customers not covered by weather normalization mechanism is less than 20 percent of all residential and commercial customers.

The Company is 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 and, if permitted, the reduction of debt through optional redemption when interest rates are favorable. At Dec. 31, 2004 and 2003, the Company had no variable-rate long-term debt and no derivative financial instruments to hedge interest rates. Holders of certain long-term debt have put options that, if exercised, would accelerate maturities by $10 million in 2005 and by $20 million in each of 2007, 2008 and 2009.

This report and other presentations made by the Company from time to time may contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and other statements that are other than statements of historical facts. The Company’s expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis. However, each such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause the actual results of the Company to differ materially from those projected in such forward-looking statements: (i) prevailing state and federal governmental policies and regulatory actions, including those of the OPUC, the WUTC, the FERC and the U.S. Department of Transportation’s Office of Pipeline Safety, with respect to allowed rates of return, industry and rate structure, purchased gas cost and investment recovery, acquisitions and dispositions of assets and facilities, operation and construction of plant facilities, the maintenance of pipeline integrity, present or prospective wholesale and retail competition, changes in tax laws and policies and changes in and compliance with environmental and safety laws, regulations and policies; (ii) weather conditions and other natural phenomena; (iii) unanticipated population growth or decline, and changes in market demand caused by changes in demographic or customer consumption patterns; (iv) competition for retail and wholesale customers; (v) market conditions and pricing of natural gas relative to other energy sources; (vi) risks relating to the creditworthiness of customers, suppliers and financial counter parties; (vii) risks relating to dependence on a single pipeline transportation provider for natural gas supply; (viii) risks resulting from uninsured

damage to Company property, intentional or otherwise; (ix) unanticipated changes that may affect the Company’s liquidity or access to capital markets; (x) the Company’s ability to maintain effective internal controls over financial reporting in compliance with Section 404 of the Sarbanes-Oxley Act of 2002; (xi) unanticipated changes in interest or foreign currency exchange rates or in rates of inflation; (xii) economic factors that could cause a severe downturn in certain key industries, thus affecting demand for natural gas; (xiii) unanticipated changes in operating expenses and capital expenditures; (xiv) unanticipated changes in future liabilities relating to employee benefit plans; (xv) capital market conditions, including their effect on pension costs; (xvi) competition for new energy development opportunities; (xvii) 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 (xviii) legal and administrative proceedings and settlements. All subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, also are expressly qualified by these cautionary statements.

Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for the Company to predict all such factors, nor can it assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

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.

Management of the Company 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. The Company’s 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). The 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 involving the assets of the Company;

(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 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 the 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.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of Dec. 31, 2004. 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 the Company maintained effective internal control over financial reporting as of Dec. 31, 2004.

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of Dec. 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

We have completed an integrated audit of Northwest Natural Gas Company’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

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 (the “Company”) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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.

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8, that the Company maintained effective internal control over financial reporting as of December 31, 2004 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, 2004, 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). 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.

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

Together these businesses are referred to herein as the “Company.” In this report, the term “utility” is used to describe the regulated gas distribution business of the Company and the term “non-utility” is used to describe the interstate 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 the Company’s ownership interest is 50 percent or less and over which the Company does not exercise control are accounted for by the equity method or the cost method (see Note 9).

The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America 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.

The Company’s principal business is the distribution of natural gas, which is regulated by the Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC). Accounting records and practices 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.” NW Natural’s utility business segment is authorized by the OPUC and the WUTC to earn a reasonable return on invested capital.

In applying SFAS No. 71, NW Natural capitalizes 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. At Dec. 31, 2004 and 2003, the amounts deferred as regulatory assets and liabilities were net liabilities of $80.8 million and $89.4 million, respectively. The net amounts recognized at Dec. 31, 2004 and 2003 include $153.2 million and $135.6 million, respectively, of accumulated removal costs, which have been included in regulatory liabilities, in accordance with SFAS No. 143, “Accounting for Asset Removal Obligations.” See “New Accounting Standards–Adopted Standards,” below.

NW Natural believes that continued application of SFAS No. 71 for its regulated activities is appropriate and consistent with the current regulatory environment, and that all of its regulated assets and liabilities at Dec. 31, 2004 and 2003 are recoverable or refundable through future utility rates. NW Natural also believes that it will continue to be able to earn a reasonable rate of return or a carrying charge on its regulated assets, net of regulatory liabilities. If NW Natural 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 it would be required to write off the net unrecoverable balances against earnings.

Asset Retirement Obligations. Effective Jan. 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires the recognition of an Asset Retirement Obligation (ARO) for legal obligations associated with the retirement of tangible long-lived assets, including the recording of fair value of the liability, if reasonably estimable, for an ARO in the period in which it is incurred. The ARO liability is recorded and the cost is capitalized as part of the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The Company did not have any material legal obligations associated with the retirement of its tangible long-lived assets, except for certain assets with indefinite system lives for which the Company cannot estimate the ARO because the settlement date is indeterminable. The Company’s adoption of SFAS No. 143 resulted in a balance sheet reclassification of asset removal cost obligations from accumulated depreciation and amortization to regulatory liabilities. The adoption of SFAS No. 143 and the reclassification of asset removal cost obligations had no material impact on the Company’s financial condition, results of operations or cash flows (see “Plant and Property,” below, for a discussion of the Company’s policy on asset removal costs).

Financial Instruments with Equity and Debt Characteristics. Effective July 1, 2003, the Company adopted SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 establishes standards for how an issuer classifies and measures in its financial statements certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires an issuer to classify a financial instrument as a liability if that financial instrument embodies an obligation of the issuer. The adoption of SFAS No. 150 resulted in the Company’s reclassifying dividends of $0.2 million after July 1, 2003 on its redeemable preferred stock as interest expense. The Company redeemed its remaining shares of preferred stock outstanding during the fourth quarter of 2003. The adoption of SFAS No. 150 did not have a material impact on the Company’s financial condition, results of operations or cash flows.

Variable Interest Entities. In December 2003, the Financial Accounting Standards Board (FASB) revised FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities” (FIN 46R), to clarify the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements.” FIN 46R provides additional guidance for the identification and consolidation of variable interest entities (VIEs), and for financial reporting by enterprises involved with VIEs. The Company adopted the original provisions of FIN 46 during 2003, and adopted the additional guidance of FIN 46R in 2004. The Company has certain equity investments that are variable interests and some of these entities are potentially VIEs. However, because the Company is not the primary beneficiary, it is not required to consolidate the VIEs. The Company’s variable interests primarily consist of limited liability interests with investments in alternative energy projects, low income housing and other real estate. These investments were entered into between the years 1988 and 2000 and have been accounted for under the equity method or cost method. The Company’s maximum exposure to loss for these investments is $6.2 million at December 31, 2004, an amount that represents the Company’s current investment balance minus its minimum net realizable value. The Company’s investment risk is thus limited because all such investments are non-recourse to the Company. The adoption of FIN 46R had no material impact on the Company’s financial condition, results of operations or cash flows.

Medicare Prescription Drug, Improvement and Modernization Act. In May 2004, the FASB issued Staff Position (FSP) No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” (the Act). FSP No. FAS 106-2 provides specific guidance on accounting for the effects of the Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP No. FAS 106-2 also requires certain disclosures regarding the effects of a federal subsidy provided by the Act.

Effective July 1, 2004, the Company adopted FSP No. 106-2 with no material impact on the Company’s cash flows, accumulated postretirement benefit obligations or net periodic postretirement benefit costs. Based on current guidance and existing plan design, the Company, with input from its actuary, determined that the prescription drug benefit provided by the Company’s postretirement benefit plan did not qualify it for a federal subsidy. While the Company provides certain prescription drug benefits to retirees, it was determined that the Company’s contributions would be less than 40 percent of the plan’s expected claims cost, and therefore is not eligible for the subsidy in 2006, the first year the subsidy is available. The Company will continue to reevaluate its plan contributions and claims experience to determine whether the plan qualifies for the federal subsidy in future years.

Other Than Temporary Impairments. In March 2004, the Emerging Issues Task Force (EITF) ratified EITF No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF No. 03-1). EITF No. 03-1 provides guidance for evaluating whether an investment is impaired, whether the impairment is other than temporary, and the measurement of such impairment. The guidance also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures in annual financial statements about unrealized losses that have not been recognized as other-than-temporary impairments. The adoption of EITF 03-1, which was effective for reporting periods beginning after June 15, 2004, had no material impact on the Company’s financial condition, results of operations or cash flows.

Income Taxes. In December 2004, the FASB issued staff position (FSP) FSP SFAS No. 109-1, to provide guidance on the application of SFAS No. 109, “Accounting for Income Taxes,” to the provisions within the American Jobs Creation Act of 2004 (the Jobs Act) that provides a tax deduction on qualified production activities. The Jobs Act became effective on Oct. 23, 2004 and provides for a tax deduction of up to nine percent (when fully phased-in) of the lesser of (a) “qualified production activities income,” as defined in the Jobs Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). The Company has determined that application of the provisions within the Jobs Act will not have a material impact on the Company’s financial condition, results of operations or cash flows.

Inventory Costs. In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” SFAS No. 151 amends the guidance on inventory pricing to require that abnormal amounts of idle facility expense, freight, handling costs and wasted material be charged to current period expense rather than capitalized as inventory costs. SFAS No. 151 also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company is evaluating the impact this new standard may have on its financial statements, but it is expected that its implementation will not have a material impact upon the Company’s financial condition, results of operations or cash flows.

Share Based Payments. In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share Based Payment” (SFAS No. 123R), that requires companies to expense the fair value of employee stock options and similar awards. Under SFAS No. 123R, share based payment awards will be measured at fair value on the date of grant based on the estimated number of awards expected to vest. The estimated fair value will be recognized as compensation expense over the period an employee is required to provide service in exchange for the award, usually referred to as the vesting period. The expense would be adjusted for actual forfeitures that occur before vesting, but would not be adjusted for awards that expire or terminate after vesting. The Company is evaluating different option-pricing models to determine the most appropriate measure of fair value for its share based payment awards under the new standard. Disclosures of estimated fair value and compensation expense using the Black-Scholes option pricing model, and its corresponding impact on the financial statements, is provided in Note 4. The Company also is evaluating the effect of the adoption and implementation of SFAS No. 123R, which is not expected to have a material impact on the Company’s financial condition, results of operations or cash flows. SFAS No. 123R is effective for interim or annual reporting periods beginning after June 15, 2005. The Company expects to adopt the provisions of SFAS No. 123R in the first quarter of 2005.

Non-monetary Transactions. Also in December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of Accounting Principles Board (APB) Opinion No. 29, Accounting for Nonmonetary Transactions.” SFAS No. 153 redefines the types of nonmonetary exchanges that require fair value measurement. SFAS No. 153 is effective for nonmonetary transactions entered into on or after July 1, 2005. The Company is evaluating the impact of this statement, but adoption of this new accounting standard in 2005 is not expected to have a material impact on the Company’s financial condition, results of operations or cash flows.

Plant and property is stated at cost, including labor, materials and overhead (see Note 9). The cost of utility plant and interstate storage includes an allowance for funds used during construction in construction overhead to represent the net cost of borrowed funds used for construction purposes (see “Allowance for Funds Used During Construction,” below).

NW Natural’s 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 was approximately 3.4 percent for the year ended Dec. 31, 2004 and 3.5 percent for each of the years 2003 and 2002. The depreciation rate reflects the approximate economic life of the utility property.

Effective Jan. 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” Among other things, SFAS No. 143 requires that future asset retirement costs (removal costs) that meet the requirements of SFAS No. 71, as amended and supplemented, be classified as a regulatory liability. In accordance with long-standing industry practice, the Company accrues for future removal costs on many long-lived assets through a charge to depreciation expense allowed in rates. Prior to the adoption of SFAS No. 143, the resulting regulatory liabilities were recognized as accruals to accumulated depreciation. At the time when removal costs were incurred, accumulated depreciation was charged with the costs of removal and the book cost of the asset being retired. At Dec. 31, 2004 and 2003, the Company recognized accrued asset removal costs of $153.2 million and $135.6 million, respectively, through depreciation expense from accumulated depreciation and amortization. The Company’s estimate of accumulated removal costs was based on rates using its most recent depreciation study. The Company will continue to accrue future asset removal costs through depreciation expense, with a corresponding credit to regulatory liabilities – accrued asset removal costs. When the Company retires depreciable utility plant and equipment, it charges the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities – accrued asset removal costs. 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.

Certain additions to utility plant include an allowance for funds used during construction (AFUDC). AFUDC represents the cost of funds borrowed during construction and is calculated using actual commercial paper interest rates. If commercial paper 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 AFUDC. While cash is not realized currently from AFUDC, it is realized in future years through increased revenues from rate recovery resulting from higher rate base and higher depreciation expense. NW Natural’s composite AFUDC rates were 3.0 percent in 2004, 4.5 percent in 2003 and 2.8 percent in 2002.

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.

Utility revenues, derived primarily from the sale and transportation of natural 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 (unbilled revenues). Unbilled revenues are dependent upon a number of factors that require management judgment, including total gas receipts and deliveries, customer use and weather. Unbilled revenues are reversed the following month when actual billings occur. The Company’s accrued unbilled revenues at Dec. 31, 2004 and 2003 were $64.4 million and $59.1 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 are recognized over the life of the contract for guaranteed amounts under the contract, or are recognized as they are earned for amounts above the guaranteed value based on estimates provided by the independent energy marketing company (see Note 2).

Accounts receivable consist primarily of amounts due to NW Natural for gas sales and transportation services to residential, commercial and industrial customers, plus amounts due for interstate gas storage services and other miscellaneous receivables. With respect to these trade receivables, the Company establishes an allowance for uncollectible accounts (allowance) based on the aging of receivables, its 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 recovered. Inactive accounts are written-off against the allowance after 120 days past due or when deemed to be uncollectible. Differences between the Company’s 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, but these differences are not currently expected to have a material impact on the Company’s financial condition or results of operation.

Inventories, consisting primarily of natural gas in storage, are stated at the moving average cost. Regulatory treatment of gas inventories provides full recovery in rates for the value of gas inventory at the moving average cost. All other inventories are stated at the lower of average cost or net realizable value.

NW Natural’s Derivatives Policy sets forth the guidelines for using selected financial derivative products to support prudent risk management strategies within designated parameters. The Derivatives Policy allows for the use of derivatives to manage natural gas commodity prices related to natural gas purchases, foreign currency prices related to gas purchase commitments from Canada, oil or propane commodity prices related to gas sales and transportation services under rate schedules pegged to other commodities, and interest rates related to long-term debt maturing in less than five years or expected to be issued in future periods. NW Natural’s objective for using derivatives is to decrease the volatility of earnings and cash flows associated with changes in commodity prices, foreign currency prices and interest rates. The use of

derivatives is permitted only after the commodity price, exchange rate, and interest rate 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 (see Note 11). The Derivatives Policy is intended to prevent speculative risk. NW Natural does not enter into derivative instruments for trading purposes and believes that any increase in market risk created by holding derivatives should be offset by the exposures they modify.

In accounting for derivative activities, the Company applies 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). SFAS No. 133 requires that the Company recognize derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. SFAS No. 133 also 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 purchase and normal sale, other than a financial instrument or derivative instrument for which physical delivery is probable. Many of the Company’s gas supply and transportation contracts are derivative instruments as defined under SFAS No. 133, but qualify for the normal purchase and normal sale exception.

NW Natural designates its derivatives as fair value or cash flow hedges based upon the criteria established by SFAS No. 133. For fair value hedges, the gain or loss is recognized in earnings in the period of change. For cash flow hedges, the effective portion of the gain or loss is initially reported in accumulated other comprehensive income (OCI), unless the derivative is subject to deferral under NW Natural’s regulated tariffs with the OPUC or the WUTC. The ineffective portion of the gain or loss in a cash flow hedge is recognized in current earnings, but only to the extent that the amount is not covered under NW Natural’s regulatory deferral mechanisms. Effectiveness is measured by comparing changes in cash flows of the hedged item to gains or losses on derivative instruments.

NW Natural’s primary hedging activities, consisting of natural gas commodity price and foreign currency exchange rate hedges, are principally accounted for as cash flow hedges under SFAS No. 133 and are subject to regulatory deferral under SFAS No. 71. Unrealized gains and losses from mark-to-market valuations of these contracts are not recognized in current income but are reported as derivative assets or liabilities and offset by a corresponding deferred account balance included under “regulatory liabilities” or “regulatory assets.” Due to their regulatory deferral treatment, effective portions of changes in the fair value of these derivatives are not recorded in OCI but are recognized as a regulatory asset or liability.

The Company accounts for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” Under SFAS No. 109, the Company recognizes deferred income taxes for all temporary differences between the financial statement and tax basis of assets and liabilities at current income tax rates. Deferred tax liabilities and assets reflect the expected future tax consequences, based on enacted tax law, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts (see Note 8).

SFAS No. 109 also requires recognition of the additional deferred income tax assets and liabilities for temporary differences where regulators prohibit deferred income tax treatment for

ratemaking purposes. Consistent with rate and accounting orders of regulatory authorities, deferred income taxes are not currently collected for those temporary income tax differences where the prescribed regulatory accounting methods do not provide for current recovery in rates. NW Natural has recorded a regulatory tax asset for amounts pending recovery from customers in future rates, equivalent to $64.7 million and $63.4 million at Dec. 31, 2004 and 2003, respectively. These amounts are primarily based on differences between the book and tax bases of net utility plant in service.

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

Other income (expense) consists of interest income, gain on sale of assets, investment income of Financial Corporation, the costs incurred in connection with the Company’s effort to acquire Portland General Electric Company (PGE) from Enron Corp. and other miscellaneous income from merchandise sales, rents, leases and other items.

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:

For the years ended Dec. 31, 2004, 2003 and 2002, 201,800 shares, 77,500 shares and 84,000 shares, respectively, representing the number of stock options the exercise prices for which were greater than the average market prices for the Company’s common stock for such years, were excluded from the calculation of diluted earnings per share because the effect was antidilutive.

The Company applies APB Opinion No. 25, “Accounting for Stock Issued to Employees,” to account for its stock-based compensation plans. Accordingly, the Company does not recognize compensation expense for the fair value of its stock option grants. Instead, the Company has elected to continue using the intrinsic value method of accounting for stock options rather than adopting the fair value method of accounting. However, the Company does recognize compensation expense for the fair value of stock awards granted under its Long-Term Incentive Plan and the Non-Employee Directors Stock Compensation Plan in the period when the shares are earned (see “New Accounting Standards—Recent Accounting Pronouncements—Share Based Payments,” above, and Note 4).

At Dec. 31, 2004, the Company had two direct, wholly-owned subsidiaries, Financial Corporation and Northwest Energy. Northwest Energy was formed in 2001 to serve as the holding company for NW Natural and PGE if the acquisition of PGE had been completed. Since the acquisition of PGE was terminated, Northwest Energy has remained a non-active subsidiary of the Company.

The Company’s core business segment, Local Gas Distribution (LDC), involves the distribution and sale of natural gas. The Local Gas Distribution segment is also referred to as the “utility”. Another segment, Interstate Gas Storage, represents natural gas storage services provided to interstate customers, including 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, low-income housing in Portland, Oregon and Northwest Energy’s limited activities (see Note 9).

Interstate gas storage services are provided to off-system interstate customers using Company-owned storage capacity that has been developed in advance of core utility customers’ (residential, commercial and industrial firm) requirements. NW Natural retains 80 percent of the income before tax from gas storage services and credits the remaining 20 percent to a deferred regulatory account for sharing with its core utility customers. For each of the years ended Dec. 31, 2004, 2003 and 2002, this business segment derived a majority of its revenues from fewer than five customers. The largest of these customers is served under a long-term contract.

Results for the interstate gas storage segment also include revenues, net of amounts shared with core utility customers, from a contract with an independent energy marketing company that optimizes the use of NW Natural’s assets by engaging in trading activities using temporarily unused portions of its upstream pipeline transportation capacity and gas storage capacity. In Oregon, NW Natural retains 80 percent of the pre-tax income from the optimization of storage and pipeline transportation capacity when the costs of such capacity have not been included in core utility rates, and 33 percent of the pre-tax income from such capacity 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 NW Natural’s core utility customers. NW Natural has a similar sharing mechanism in Washington for revenue derived from interstate storage services and third party optimization services.

Financial Corporation has several financial investments, including investments as a limited partner in solar electric generating systems, windpower electric generating projects and low-income housing projects. Financial Corporation’s total assets were $7.6 million and $8.0 million at Dec. 31, 2004 and 2003, respectively.

On Jan. 31, 2005 Financial Corporation sold its limited partnership interests in three solar electric generating systems for approximately $3 million, which resulted in a $0.5 million write-down of these systems in the fourth quarter of 2004. These systems are located in the Mojave Desert in California. NW Natural invested in the projects between 1986 and 1988. Financial Corporation’s ownership interests ranged from 4.0 percent to 5.3 percent.

The following table presents summary financial information about the reportable segments for 2004, 2003 and 2002. Inter-segment transactions are insignificant.

At Dec. 31, 2004, NW Natural had reserved 106,699 shares of common stock for issuance under the Employee Stock Purchase Plan, 288,155 shares for future conversions of its 7¹/4% Convertible Debentures, 232,827 shares under its Dividend Reinvestment and Stock Purchase Plan, 1,659,470 shares under its Restated Stock Option Plan (see Note 4), and 3,000,000 shares under the Shareholder Rights Plan.

In April 2004, the Company issued and sold 1,290,000 shares of its common stock in an underwritten public offering and used the net proceeds of $38.5 million from the offering primarily to reduce short-term indebtedness and to fund, in part, NW Natural’s utility construction program.

On Nov. 14, 2003, NW Natural redeemed all of the remaining shares of its $7.125 Series of Redeemable Preferred Stock with an aggregate stated value of $7.5 million, at a redemption price equivalent to 102.375 percent with proceeds from sales of commercial paper. The Company re-financed the commercial paper with the sale of new long-term debt in the fourth quarter of 2003. The early redemption premium was recognized as an unamortized cost pursuant to SFAS No. 71 and is being amortized to expense over the life of the new debt.

On Dec. 31, 2002, NW Natural redeemed all 250,000 shares of its $6.95 Series of Redeemable Preference Stock with proceeds from the sale of commercial paper.

NW Natural’s Board of Directors approved a stock repurchase program in 2000 to purchase up to 2 million shares, or up to $35 million in value, of NW Natural’s common stock in the open market or through privately negotiated transactions. The repurchase program has been extended through May 2005. No shares were repurchased in 2003 or 2004. Since the program’s inception, the Company has repurchased 355,400 shares of common stock at a total cost of $8.2 million.

In May 2002, the shareholders approved an amendment to the Restated Stock Option Plan that increased the total number of shares authorized for option grants from 1,200,000 to 2,400,000 shares. At Dec. 31, 2004, options on 1,228,000 shares were available for grant and options on 431,470 shares were outstanding.

The following table shows the changes in the number of shares of NW Natural’s capital stock and the premium on common stock for the years 2004, 2003 and 2002:

NW Natural has 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. 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 year-end 2004, a total of 436,000 shares of common stock were available for award under the LTIP, assuming that current 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 restricted stock awards.

Performance-based Stock Awards. Since the Plan’s inception in 2001, through December 31, 2004, five performance-based stock awards have been granted, one based on a two-year performance period (2001-02) and four based on three-year performance periods (2001-03, 2002-04, 2003-05 and 2004-06). At Dec. 31, 2004, all performance-based stock awards other than those covering the 2003-05 and 2004-06 periods had lapsed because the performance-based measures were not achieved. If the performance-based measures are achieved, participants will also receive dividend equivalent cash payments equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share by the Company during the performance period.

At Dec. 31, 2004, the aggregate number of performance-based shares awarded and outstanding at the minimum, threshold, target and maximum levels were as follows:

For the 2003-05 performance period, a series of performance targets were established based on the Company’s average annual return on equity (ROE) for the performance period corresponding to award opportunities ranging from 0 percent to 200 percent of the target awards. No awards are payable unless the threshold annual average ROE level, tied to the Company’s authorized ROE, is achieved during the award period. The maximum awards are payable only upon the achievement of an average annual ROE 200 basis points above the Company’s authorized ROE. For the 2004-06 performance period, awards will be based on total shareholder return relative to a peer group of gas distribution companies over the three-year performance period and performance milestones relative to the Company’s core and non-core strategies.

Restricted Stock Awards. Restricted stock awards also have been granted under the LTIP. A restricted stock award consisting of 4,500 shares granted in 2001 lapsed in 2004, and a restricted stock award was granted in 2004 consisting of 5,000 shares that is scheduled to vest ratably over five years beginning in 2005.

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 NW Natural’s 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. Since inception in 1985, options on 1,303,721 shares of common stock have been granted at prices ranging from $11.75 to $32.02 per share, and options on 131,721 shares have expired.

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 subscription 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.

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 2004 or earlier years (see Note 1, “New Accounting Standards-Recent Accounting Pronouncements”). 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. 123, “Accounting for Stock-Based Compensation,” net income and earnings per share would have been reduced to the pro forma amounts shown below:

The fair value of each stock option is estimated on the grant date (there were no stock option grants in 2003) using the Black-Scholes option pricing model with the following weighted average assumptions:

The weighted average remaining life of outstanding stock options at December 31, 2004 was 7.3 years.

The characteristics of exercisable stock options at Dec. 31, 2004 were as follows:

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 Company 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 Jan. 1, 2005.

Prior to the latter amendment to the NEDSCP, if non-employee directors elected to receive their awards in stock, approximately $100,000 worth of the Company’s 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 Company stock were awarded an additional $20,000 worth of restricted Company stock, which vested in monthly installments in the fifth year following the award (after the previous award has fully vested). The Company

holds 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 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 the Company at the time of the award.

The following table presents the changes in unearned stock compensation for the years 2004 and 2003, which are reported as a reduction to total common equity in the consolidated balance sheets:

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

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 NW Natural’s utility property.

The 7¹/4% Series of Convertible Debentures may be converted at any time into 50¹/4 shares of common stock for each $1,000 face value ($19.90 per share).

The maturities on the long-term debt outstanding, for each of the 12-month periods through Dec. 31, 2009 amount to: $15 million in 2005; $8 million in 2006; $29.5 million in 2007, $5 million in 2008; and none in 2009. Holders of certain long-term debt have put options that, if exercised, would accelerate the maturities by $10 million in 2005 and $20 million in each of 2007, 2008 and 2009.

The Company’s primary source of short-term funds is commercial paper notes payable. NW Natural issues commercial paper under agency agreements with a commercial bank and such commercial paper is supported by its committed bank lines of credit (see below). At. Dec. 31, 2004 and 2003, the amounts and average interest rates of commercial paper debt outstanding were $102.5 million and 2.3 percent and $85.2 million and 1.1 percent, respectively.

NW Natural has lines of credit with four commercial banks totaling $150 million. Half of the credit facility with each bank, totaling $75 million, is committed and available through Sept. 30, 2005, and the other $75 million is committed and available through Sept. 30, 2007. Three of these commercial banks have each committed $20 million for each of their 2005 and 2007 lines of credit and the fourth commercial bank has committed $15 million for each of its 2005 and 2007 lines of credit.

The lines of credit require the Company to maintain an indebtedness to total capitalization ratio of 65 percent or less and to maintain a consolidated net worth at least equal to 80 percent of its net worth at Sept. 30, 2004, plus 50 percent of the Company’s net income for each subsequent fiscal quarter. Failure to comply with either of these covenants would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding. The Company was in compliance with both of these covenants at Dec. 31, 2004, and with the equivalent covenants in the prior year’s lines of credit at Dec. 31, 2003.

NW Natural maintains 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 its employees. Only the two qualified defined benefit pension plans have plan assets which are held in a qualified trust to fund retirement benefits.

The following table provides a reconciliation of the changes in benefit obligations and fair value of assets, as applicable, for the pension plans and other postretirement benefit plans over the three-year period ended Dec. 31, 2004, and a statement of the funded status and amounts recognized in the consolidated balance sheets, using measurement dates of Dec. 31, 2004, 2003 and 2002:

The Company’s qualified defined benefit pension plans had an accumulated benefit obligation in excess of plan assets at Dec. 31, 2004. The plans’ aggregate accumulated benefit obligation was $209 million, $192 million and $172 million at Dec. 31, 2004, 2003 and 2002, respectively, and the fair value of plan assets was $186.8 million, $168.3 million and $143.2 million, respectively. The fair value of plan assets increased from Dec. 31, 2003 to Dec. 31, 2004 due to $22.5 million in investment gains and employer contributions of $8.3 million, partially offset by $11.2 million in withdrawals to pay benefits and $1.1 million to pay eligible expenses of the plans. The combination of investment returns and cash contributions is expected to provide

sufficient funds to cover all benefit obligations of the plans. The Company is not required to make a cash contribution to either of its qualified pension plans for the 2005 plan year.

The Company’s investment policy and performance objectives for the qualified pension plan assets (plan assets) held in the Retirement Trust Fund was approved by the retirement committee which is composed of 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 (ERISA). 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 securities of NW Natural, and may be invested in separately managed accounts or in commingled or mutual funds. Re-balancing will take place at least annually, or when significant cash flows occur, in order to maintain the allocation of assets within the stated target allocation ranges. The Retirement Trust Fund is not currently invested in any NW Natural securities.

The Company’s pension plan asset allocation at Dec. 31, 2004 and 2003, and the target allocation and expected long-term rate of return by asset category for 2005 are as follows:

The Company’s non-qualified supplemental pension plans’ accumulated benefit obligations were $13.6 million, $13.0 million and $12.8 million at Dec. 31, 2004, 2003 and 2002, respectively. Although the plans are unfunded plans with no plan assets due to their nature as non-qualified plans, the Company indirectly funds its obligations with trust-owned life insurance.

The Company’s plans for providing postretirement benefits other than pensions also are unfunded plans. The aggregate benefit obligation for those plans was $22.7 million, $23.4 million and $18.5 million at Dec. 31, 2004, 2003 and 2002, respectively.

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 Dec. 31, 2004, 2003 and 2002, and the assumptions used in measuring these costs and benefit obligations:

The assumed annual increase in trend rates used in measuring postretirement benefits as of Dec. 31, 2004 were 10 percent for medical and 13 percent for prescription drugs. Medical costs were assumed to decrease gradually each year to a rate of 4.5 percent for 2012, while prescription drug costs were assumed to decrease gradually each year to a rate of 4.5 percent for 2013.

Assumed health care cost trend rates 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:

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 Dec. 31, 2004 and 2003, and estimated future payments:

NW Natural’s Retirement K Savings Plan (RKSP) is a qualified defined contribution plan under Internal Revenue Code Section 401(k). NW Natural also has 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. NW Natural’s matching contributions to these plans totaled $1.7 million in 2004, $1.6 million in 2003 and $1.4 million in 2002. Effective Jan. 1, 2002, the RKSP was amended to establish an Employee Stock Ownership Plan (ESOP) within the RKSP by converting the existing RKSP Company Stock Fund into an ESOP.

Effective Jan. 1, 2005, the Company will make a contribution of 25 cents per compensable hour on behalf of each union employee to the Western States Office and Professional Employees Pension Fund, which contributions will increase 3 percent each year, up to 30 cents per compensable hour.

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

The amount of income taxes paid in 2004 and 2003 decreased significantly as compared to the total provision for income taxes, primarily due to the effects of accelerated depreciation provisions provided by the Job Creation and Worker Assistance Act of 2002 (the Assistance Act) and the Jobs and Growth Tax Relief Reconciliation Act of 2003 (the 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 additional first-year depreciation deduction is an acceleration of depreciation deductions that otherwise would have been taken in the later years of an asset’s recovery period. The accelerated depreciation provisions provided by both the Assistance Act and the Reconciliation Act expired at Dec. 31, 2004. The Company realized enhanced cash flow from reduced income taxes totaling an estimated $55 million during the effective period, based on plant investments made between Sept. 11, 2001 and Dec. 31, 2004.

For the year ended Dec. 31, 2004, the Company had an estimated federal net operating loss (NOL) of $15.4 million and an Oregon NOL of $18.6 million, primarily due to the effects of accelerated tax depreciation provided by the Assistance Act and the Reconciliation Act. The federal NOL will be carried back to 2002 for a refund of taxes paid in prior years, and the Oregon NOL will be used to reduce future Oregon taxable income. The Oregon NOL will expire in 2019.

At Dec. 31, 2004 the Company had $1.6 million of alternative minimum tax credit carryforwards to offset regular federal income tax payable in future years. In addition, the Company had certain tax credits of approximately $0.7 million which are available to reduce certain federal and state income tax liabilities through 2011. The Company anticipates that it will be able to utilize all loss and credit carryforwards in future years.

The following table sets forth the major classifications of NW Natural’s utility plant and accumulated depreciation at Dec. 31:

Accumulated depreciation does not include $153.3 million and $135.6 million at Dec. 31, 2004 and 2003, respectively, which represent accrued asset removal costs and are reflected on the balance sheets as a regulatory liability (see Note 1).

The following table summarizes the Company’s investments in non-utility plant at Dec. 31:

The following table summarizes the Company’s 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 Dec. 31:

In 1987, the Company invested in a Boeing 737-300 aircraft, which is leased to Continental Airlines for 20 years under a leveraged lease agreement.

A Financial Corporation subsidiary, KB Pipeline Company (KB Pipeline), owns a 10 percent interest in an 18-mile interstate natural gas pipeline. KB Pipeline operated the pipeline for twelve years until Dec. 1, 2004, when a third party gas distribution company became the operator. KB Pipeline resigned as pipeline operator due, in part, to increased obligations resulting from final Federal Energy Regulatory Commission regulations implementing Standards of Conduct for Transmission Providers. Those regulations govern the relationship between interstate natural gas pipelines and their energy affiliates or marketing functions and impose obligations previously inapplicable to KB Pipeline with regard to separation of duties and related matters. FERC granted KB Pipeline an exemption from most of the requirements of the Standards of Conduct; however, the remainder of the regulations continue to be applicable to KB Pipeline as a co-owner of the pipeline.

At Dec. 31, 2004, Financial Corporation held ownership interests ranging from 4.0 to 5.3 percent in three solar electric generation plants located near Barstow, California. Power generated by these plants is sold to Southern California Edison Company under long-term contracts. Financial Corporation also has ownership interests ranging from 25 to 41 percent in wind power electric generation projects located near Livermore and Palm Springs, California. The wind-generated power is sold to Pacific Gas and Electric Company and Southern California Edison Company under long-term contracts. Financial Corporation sold its interests in the solar electric generation plants on Jan. 31, 2005 (see Note 2).

FASB Interpretation No. 46, “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.” The Company does not have any significant interests in variable interest entities for which it is a primary beneficiary.

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:

Fair value of the long-term debt was estimated using market prices on the valuation date for debt with similar credit ratings, maturities, interest rates and other terms.

NW Natural enters into short-term, medium-term and long-term natural gas purchase contracts with suppliers, including contracts tied to market-based index prices, and thus is exposed to changes in commodity prices. Natural gas prices are subject to fluctuations due to unpredictable factors including weather, inventory levels, pipeline transportation availability, and the economy, each of which affects short-term supply and demand. As part of its overall strategy to maintain an acceptable level of exposure to gas price fluctuations, NW Natural uses a targeted mix of fixed-rate and cap-protected derivative instruments to hedge the exposure under floating price gas supply contracts. Swap contracts are used to convert certain long-term gas purchase contracts from floating prices to fixed prices. Call option contracts are used to limit the maximum adverse impact from floating price contracts while retaining the potential favorable impact from declining gas prices. The prices embedded in these commodity hedge contracts are incorporated in annual rate changes under the PGA rate mechanisms, thereby limiting customers’ exposure to frequent changes in purchased gas costs. The estimated fair value of gains and losses from commodity hedge contracts are recorded as a derivative asset or liability, and are offset by a corresponding amount recorded to a deferred regulatory asset or liability account for the effective portion of each hedge contract. The actual gains and losses realized at settlement of the hedge contracts are used to offset the actual gas purchase cost from NW Natural’s physical supply contracts.

Certain natural gas purchases from Canadian suppliers are invoiced in Canadian dollars, including both commodity and demand charges, thereby exposing NW Natural to adverse changes in foreign currency rates. Foreign currency forward contracts are used to minimize the impact of fluctuations in currency rates. Foreign currency contracts for commodity costs are purchased on a month-to-month basis because the Canadian cost is priced at the average noonday exchange rate for each month. Foreign currency contracts for demand costs have terms ranging up to 24 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 longer-term currency contracts for demand charges are subject to a regulatory deferral tariff and, as such, are recorded as a derivative asset or liability which is offset by recording a corresponding amount to a deferred asset or liability account.

NW Natural did not use any derivative instruments to hedge oil or propane prices or interest rates during 2004, 2003 or 2002.

At Dec. 31, 2004, NW Natural had the following derivatives outstanding: a series of 24 fixed-price natural gas commodity price financial swap contracts; four fixed-price natural gas financial call option contracts; and 62 foreign currency forward purchase contracts. All of these contracts were designated as cash flow hedges covering exposures to commodity purchase and sale contracts. Unrealized gains and losses from mark-to-market valuations of these contracts are not recognized in current income but are reported as derivative assets or liabilities and offset by a corresponding deferred account balance under regulatory liabilities or regulatory assets because regulatory mechanisms include the realized gains or losses at settlement in utility gas costs subject to regulatory deferral treatment. NW Natural also had outstanding at Dec. 31, 2004 two natural gas physical supply contracts with embedded options which did not qualify as a normal purchase or normal sale. The physical supply contracts were entered into using excess gas storage and pipeline transportation capacity under the Company’s optimization program. The estimated fair values (unrealized gains and losses) and the notional amounts of derivative instruments outstanding were as follows:


	Dec. 31, 2004				Dec. 31, 2003
(Thousands)	Fair Value Gain (Loss)		Notional Amount		Fair Value Gain (Loss)		Notional Amount
Fixed-price natural gas financial swap contracts	$	11,983	$	375,975	$	23,285	$	284,317
Fixed-price natural gas financial call option contracts		(2,195)		28,357		366		19,761
Natural gas physical supply contracts with embedded options		24		4,250		-		-
Fixed-price natural gas financial swap contracts - gas storage		658		4,406		-		-
Foreign currency forward purchase contracts		442		14,460		234		6,417

Total	$	10,912	$	427,448	$	23,885	$	310,495

In 2004 and 2003, NW Natural realized net gains of $42.4 million and $32.4 million, respectively, from the settlement of natural gas commodity swap and call option contracts, which were recorded as decreases to the cost of gas, compared to net losses of $75.5 million during 2002, which were recorded as increases to the cost of gas. The currency exchange rate in all foreign currency forward purchase contracts is included in NW Natural’s 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 OCI.

The fair value of derivative instruments at Dec. 31, 2004 and 2003 (see table above) was determined using estimated or quoted market prices for the periods covered by the contracts. Market prices for the natural gas commodity-price swap and call option contracts were obtained from external sources. NW Natural reviews these third-party valuations for reasonableness using fair value calculations for other contracts with similar terms and conditions. The market prices for the foreign currency forward contracts were based on currency exchange rates quoted by The Bank of Canada.

As of Dec. 31, 2004, five of the natural gas commodity price swap contracts extended beyond Dec. 31, 2005, and two extended beyond Oct. 31, 2006. None of the natural gas commodity call option contracts extends beyond March 31, 2005.

The Company leases land, buildings and equipment under agreements that expire in various years through 2018. Rental expense under operating leases was $4.5 million, $4.9 million and $4.8 million for the years ended Dec. 31, 2004, 2003 and 2002, respectively. The table below reflects the future minimum lease payments due under non-cancelable leases at Dec. 31, 2004. Such payments total $60.8 million for operating leases. The net present value of payments on capital leases less imputed interest was $0.5 million. These commitments principally relate to the lease of the Company’s office headquarters, underground gas storage facilities, vehicles and computer equipment.

NW Natural has signed agreements providing for the reservation of firm pipeline capacity under which it must 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, NW Natural has entered into long-term sale agreements to release firm pipeline capacity. The aggregate amounts of these agreements were as follows at Dec. 31, 2004:

NW Natural’s total payments of fixed charges under capacity purchase agreements in 2004, 2003 and 2002 were $89.3 million, $86.7 million and $86.2 million, respectively. Included in the amounts for 2004, 2003 and 2002 were reductions for capacity release sales of $3.7 million, $3.7 million and $4.2 million, respectively. 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.

NW Natural owns or previously owned properties currently being investigated that may require environmental response. NW Natural has accrued all material loss contingencies relating to environmental matters that it believes to be probable of assertion and reasonably estimable. The Company continues to study the extent of its environmental liabilities, but due to the preliminary nature of the environmental investigations being conducted, the range of loss contingencies beyond the amounts currently accrued, and the probabilities thereof, cannot be reasonably estimated.

Gasco site. NW Natural owns property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). The Gasco site has been under investigation by NW Natural for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, the Company filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. NW Natural continues to work with the ODEQ to determine the appropriate remedial action from among the alternatives. Based upon the proposed actions in the draft plan, the Company estimates its range of remaining liability, including the cost of investigation, from among feasible alternatives, at between $1.3 million and $7 million.

Wacker site. NW Natural previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation, formerly Wacker Siltronic Corporation (the Wacker site). In 2000, the ODEQ issued an order requiring Wacker and NW Natural to determine the nature and extent of releases of hazardous substances to Willamette River sediments from the Wacker site. In 2004, consultant studies indicated that some benzene is present in the soil at the Wacker site. The ODEQ requested that NW Natural conduct further tests of groundwater and indoor air quality. The work plan for the implementation of the benzene indoor air-sampling program was approved by the ODEQ in November 2004. NW Natural recorded expenses in 2004 totaling $0.1 million for its estimated costs of investigation and initial remediation at the Wacker site.

Portland Harbor. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (the Portland Harbor) that includes the area adjacent to the Gasco site and the Wacker site. In 2000, the EPA listed the Portland Harbor as a Superfund site and notified the Company that it is a potentially responsible party. Subsequently, the EPA approved the Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study. NW Natural’s share of the estimated budget to complete the first phase of the work is $1.0 million, which is expected to be completed in 2007. The EPA has indicated that further study in a second phase will be required; however, the scope of the work to be completed in a second phase has yet to be determined.

In April 2004 the Company entered into an Administrative Order on Consent (AOC) providing for early action removal of a body of tar in the river sediments adjacent to the Gasco site. In July 2004, the EPA approved an initial work plan for the early action removal. The Company continues to negotiate with the EPA regarding the method and timing of the removal of the

body of tar. The Company currently estimates the removal cost to be in the range of $3.0 million to $5.0 million. In addition, the Company has agreed with the ODEQ to do additional work, if necessary, on the Gasco site in conjunction with the EPA early action remediation work.

During 2004, NW Natural accrued additional loss contingencies totaling $4.3 million for the above-described study work and the revised estimate of tar body remediation costs. NW Natural’s liability is based on its best estimate of probable costs, and if a specific amount is no more or less likely than another amount in the range of probable liability, then the Company recognizes its liability at the lower end of the range of probable liability. Currently available information is insufficient to determine either the total amount of liability, or the higher end of a range for NW Natural’s estimated share of potential future remediation related to the Portland Harbor site. The Company expects to receive additional information when the Remedial Investigation/Feasibility Study report is completed. A preliminary report is expected to be available during 2005.

Portland Gas site. The City of Portland notified NW Natural that it was planning a sewer improvement project that would include excavation within the former site of a gas manufacturing plant (the Portland Gas site) that was owned and operated by a predecessor of the Company between 1860 and 1913. The preliminary assessment of this site performed by a consultant for the EPA in 1987 indicated that it could be assumed that by-product tars may have been disposed of on site. The report concluded, however, that it is likely that waste residues from the plant, if present on the site, were covered by deep fill during construction of the nearby seawall bordering the Willamette River and probably have stabilized due to physical and chemical processes. Neither the City of Portland nor the ODEQ has notified NW Natural whether a further investigation or potential remediation might be required on the site in connection with the sewer project, which has commenced. Available information is insufficient to determine either the total amount of NW Natural’s liability or a probable range, if any, of potential liability.

Oregon Steel Mills site. On Dec. 20, 2004, the Company was served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940’s and 1950’s petroleum wastes generated by the Company’s predecessor, Portland Gas & Coke Company, and nine other third-party defendants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The Port’s complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. NW Natural does not believe there are facts sufficient to constitute a claim against the Company.

Corps of Engineers Notice of Noncompliance. On July 2, 2004, the U.S. Army Corps of Engineers (Corps) issued to the Company a Notice of Noncompliance (Notice) for discharges of drilling mud into three streams during drilling operations on the Company’s South Mist Pipeline Extension (SMPE) project. The Corps’ Notice claimed that the discharges violated the scope of work in permits for the drilling. The Company cooperated with the Corps in its investigation and worked closely with the Corps and other state and federal agencies to minimize impacts from the unintended discharges. The final disposition of this matter resulted in the payment of a nominal fine.

Regulatory and Insurance Recovery for Environmental Matters. In May 2003, the OPUC approved NW Natural’s request for deferral of environmental costs associated with specific sites, including the Gasco, Wacker, Portland Harbor and Portland Gas sites. The authorization, which has been extended through April 2005, allows NW Natural to defer and seek recovery of unreimbursed environmental costs in a future general rate case. On a cumulative basis through Dec. 31, 2004, the Company paid out a total of $3.3 million relating to the named sites since the effective date of the deferral authorization. NW Natural will first seek to recover the costs of investigation and remediation for which it may be responsible with respect to the Gasco, Wacker, Portland Harbor and Portland Gas sites, if any, from insurance. If these costs are not recovered from insurance, then NW Natural will seek OPUC approval to recover them through future rates. At Dec. 31, 2004, NW Natural had a receivable of $8.5 million representing an estimate of the environmental costs it expects to recover from insurance, consisting of $2.8 million for costs relating to the Gasco site, $5.5 million for costs relating to the Portland Harbor site and $0.2 million relating to the Oregon Steel Mills site.

On Jan. 27, 2005, NW Natural filed a request with the OPUC for authorization to defer costs associated with the Oregon Steel Mills site and to extend the deferral authority for the other named environmental sites through Jan. 26, 2006.

The following table summarizes the insurance receivables and the accrued liabilities relating to environmental matters at Dec. 31, 2004 and 2003.

On October 16, 2003, Longview Fibre Company (Longview) filed suit in Federal Court (Longview Fibre Company v. Enerfin Resources Northwest Limited Partnership and Northwest Natural Gas Company (US District Court - Oregon District)) seeking a declaratory judgment regarding the continuing existence of a certain oil and gas lease in the Mist gas field between Longview and Enerfin Resources Northwest Limited Partnership (Enerfin). NW Natural holds a gas storage lease from Longview (the Cascade Lease), which covers the same land as the Enerfin lease, and which grants the right to produce native oil and gas. Enerfin originally filed crossclaims against NW Natural alleging that NW Natural wrongly interfered with Enerfin’s attempts to continue its oil and gas lease with Longview; however, Enerfin agreed to dismiss those claims in a previous settlement with NW Natural. In that settlement, NW Natural subleased portions of the Cascade Lease to Enerfin for the purpose of producing native gas. In September 2004, NW Natural and Enerfin filed claims and counterclaims against Longview, and Longview filed claims and counterclaims against NW Natural and Enerfin. The claims that Longview made against NW Natural involved allegations of unpaid royalties under the Cascade Lease.

On Feb. 18, 2005, a lawsuit was filed against the Company (Kasey Cooper, Kevin Cooper, C.G. Nick Courtney, John V. Shooter, Ike Whittlesey and Roger Whittlesey v. Northwest Natural (U.S. Dist. Ct. D. Or., Case No. CV-05-241-KI)) by six additional individual independent backhoe operators who have performed services for the Company under contract. Like the plaintiffs in the claim described above, these plaintiffs allege that they should have been considered “employees” of the Company. They seek overtime wages under the Fair Labor Standards Act and interest in amounts to be determined, liquidated damages equal to the overtime award, civil penalties and attorneys fees and costs. In addition, the plaintiffs allege that failure to classify them as employees constituted a breach of contract under certain of the Company’s employee benefit programs, agreements and plans, which conferred employment-related compensation, rights and benefits. They seek an unspecified amount of damages for the value of what they would have received under these programs, agreements and plans if they had been classified as employees. The Company intends to vigorously contest the claims. There is insufficient information at this point in the litigation to reasonably estimate the amount of liability, if any, from this claim.

Mills. The Port’s complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. NW Natural does not believe there are facts sufficient to constitute a claim against the Company.

In connection with the construction of the SMPE, NW Natural continues to negotiate with some land owners regarding valuation of easements and rights-of-way obtained pursuant to condemnation proceedings. In some cases, compensation will be determined in individual court proceedings that have been scheduled through June 2005. The Company is unable to determine the likelihood of unfavorable outcomes of these matters, but believes that the aggregate amount of compensation ultimately paid will not be material to the Company’s financial condition, results of operations or cash flows.


Dollars	Quarter ended
(Thousands, except per share amounts)	March 31		June 30			Sept. 30			Dec. 31		Total
2004
Operating revenues	$	254,450	$	109,659		$	81,441		$	262,054	$	707,604
Net operating revenues		112,034		52,629			39,483			104,214		308,360
Net income (loss)		32,612		(716	)		(8,285	)		26,961		50,572
Basic earnings (loss) per share		1.26		(0.03	)		(0.30	)		0.98		1.87	*
Diluted earnings (loss) per share		1.24		(0.03	)		(0.30	)		0.97		1.86	*

2003
Operating revenues	$	206,539	$	117,489		$	69,481		$	217,747	$	611,256
Net operating revenues		98,588		58,549			39,465			91,464		288,066
Net income (loss)		26,404		4,462			(6,546	)		21,663		45,983
Basic earnings (loss) per share		1.03		0.17			(0.25	)		0.84		1.77	*
Diluted earnings (loss) per share		1.01		0.17			(0.25	)		0.83		1.76	*

As of Dec. 31, 2004, the principal executive officer and principal financial officer of the Company have evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act)). Based upon that evaluation, the principal executive officer and principal financial officer of the Company have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to the Company and its consolidated subsidiaries required to be included in the Company’s reports filed with or furnished to the Securities and Exchange Commission under the Exchange Act.

During 2004, the Company conducted an extensive effort to analyze and assess the effectiveness of its internal controls over financial reporting. The assessments were made by management under the supervision of the Company’s chief financial officer. During the course of its assessments, the Company identified areas of internal control that warranted improvement. As a result, the Company made the significant changes in its internal control over financial reporting during the fourth quarter, as summarized below.

The Company implemented a software system to manage the accounting for its fixed assets. The system interfaces with the Company’s general ledger, customer information system, payroll and construction work management system and is used to calculate depreciation expense and allowance for funds used during construction (AFUDC) for the financial statements. The fixed asset system implementation improved internal controls by providing:

The Company also implemented changes in internal controls over financial reporting in the area of gas supply. These changes consisted primarily of:

These changes were designed to ensure adequate separation of duties within the gas supply function.

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

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.

The Company filed a Form 8-K dated Feb. 11, 2005 reporting (i) the waiver of forfeiture provisions of the Non-Employee Directors Stock Compensation Plan relating to Company stock held in the account of Melody C. Teppola, a director of the Company who died on Dec. 6, 2004; (ii) an increase in director fees, including cash retainer and meeting fees; (iii) annual executive incentive compensation structure; and (iv) executive long-term incentive plan compensation structure.

On Feb. 23, 2005, the Organization and Executive Compensation Committee of the Board of Directors determined compensation for executive officers for 2005, including targets under the Executive Annual Incentive Plan and awards under the Long-Term Incentive Plan. On Feb. 24, 2005, the Board of Directors approved compensation for the chief executive officer, including his annual incentive award for 2004, salary for 2005, the target under the Executive Annual Incentive Plan and an award under the Long-Term Incentive Plan. For a summary of the compensation for the Company’s named executive officers, see Exhibit 10z (2) to this Form 10-K.

On Feb. 25, 2005, the Company announced that the Board of Directors elected Kenneth Thrasher to the Board. Since 2002, Mr. Thrasher has served as Chairman and Chief Executive Officer of Compli Corporation, a software solution provider for management of compliance in employment practices and corporate governance. Prior to joining Compli, Mr. Thrasher served 19 years in executive positions with Fred Meyer, Inc., including serving as President and Chief Executive Officer from 1999 to 2001 and as Executive Vice President and Chief Administrative Officer from 1997 to 1999. Mr. Thrasher serves on the board of directors of Friends of the Children, the Oregon Mentoring Initiative, the Portland Art Museum, the Leaders Roundtable and the Oregon Coast Aquarium. In 2001, he was appointed by the Oregon Governor as Chairperson of the Quality Education Commission, a position he continues to hold. He is also a co-chair of Portland State University’s capital endowment campaign. Mr. Thrasher earned a Bachelor of Science degree in Business Administration from Oregon State University.

Also on Feb. 25, 2005, the Company announced that the Board of Directors selected Richard L. Woolworth, retired Chairman and Chief Executive Officer of the Regence Group, to serve as Chairman of the Board, effective March 1, 2005, replacing Richard G. Reiten who had served as Chairman of the Board since 2000. Mr. Reiten will continue to serve as a member of the Board.

Information concerning the Company’s Board of Directors, its Committees and the Audit Committee financial expert contained in the Company’s definitive Proxy Statement for the May 26, 2005 Annual Meeting of Shareholders is hereby incorporated by reference.

Each executive officer serves successive annual terms; present terms end May 26, 2005. There are no family relationships among the Company’s executive officers.

The information concerning “Executive Compensation” contained in the Company’s definitive Proxy Statement for the May 26, 2005 Annual Meeting of Shareholders is hereby incorporated by reference. Information related to Executive Officers as of Dec. 31, 2004 is reflected in Part III, Item 10, above.

The following table sets forth information regarding compensation plans under which equity securities of the Company are authorized for issuance as of Dec. 31, 2004 (see Note 4 to the Consolidated Financial Statements):

The information captioned “Beneficial Ownership of Common Stock by Directors and Executive Officers” contained in the Company’s definitive Proxy Statement for the May 26, 2005 Annual Meeting of Shareholders is incorporated herein by reference.

¹ Shares issued pursuant to the LTIP do not include an exercise price, but are payable by the Company when the award criteria are satisfied. If the maximum awards were paid pursuant to the performance-based awards outstanding at Dec. 31, 2004, the number of shares shown in column (a) would increase by 59,000 shares and the number of shares shown in column (c) would decrease by 59,000 shares.

² At the participant’s election, deferred amounts may be credited to either a “cash account” or a Company “stock account.” If deferred amounts are credited to stock accounts, such accounts are credited with a number of shares based on the purchase price of the Common Stock on the next purchase date under the Company’s Dividend Reinvestment and Stock Purchase Plan, and such accounts are 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. The Company has contributed Common Stock to the trustee of the Umbrella Trust such that the Umbrella Trust holds the number of shares of Common Stock equal to the number of shares credited to all participants’ stock accounts. Effective Jan. 1, 2005, the EDCP and DDCP were replaced by the Deferred Compensation Plan for Directors and Executives.

³ The material features of this plan are more particularly described in Note 4 to the Consolidated Financial Statements included in this report.

The information captioned “Certain Relationships and Related Transactions” in the Company’s definitive Proxy Statement for the May 26, 2005 Annual Meeting of Shareholders is hereby incorporated by reference.

The information captioned “Selection of Registered Independent Public Accounting Firm” in the Company’s definitive Proxy Statement for the May 26, 2005 Annual Meeting of Shareholders is hereby incorporated by reference.

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.

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.


Exhibit Number		Document

* 3a.		Restated Articles of Incorporation, as filed and effective June 24, 1988 and amended December 8, 1992, December 1, 1993 and May 27, 1994 (incorporated herein by reference to Exhibit 3a. to Form 10-K for 1994, File No. 0-994).

*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).



*4g.		Rights Agreement, dated as of February 27, 1996, between the Company and Boatmen’s Trust Company (American Stock Transfer & Trust Company, successor), which includes as Exhibit A thereto the form of a Right Certificate and as Exhibit B thereto the Summary of Rights to Purchase Common Shares (incorporated herein by reference to Exhibit 1 to Form 8-A, dated February 27, 1996, File No. 0-994).

*4h.		Amendment No. 1, dated October 5, 2001, to Rights Agreement, dated February 27, 1996, between the Company and Boatmen’s Trust Company (American Stock Transfer & Trust Company, successor) (incorporated herein by reference to Exhibit 4 to Form 10-Q for quarter ended September 30, 2001, File No. 0-994).

*4i.		Form of Credit Agreement between Northwest Natural Gas Company and each of J.P. Morgan Chase Bank, U.S. Bank National Association, Bank of America N.A. and Wells Fargo Bank, dated as of October 1, 2004, including Form of Note (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated October 7, 2004, File No. 1-15973).

*4j.		Distribution Agreement, dated September 28, 2004, among the Company, Merrill Lynch, Pierce Fenner & Smith Incorporated, UBS Securities LLC, J.P. Morgan Securities Inc. and Piper Jaffray & Co. (incorporated herein by reference to Exhibit 1.1 to Form 8-K dated October 4, 2004, File No. 1-15973).

*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.

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 (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.

10b.(3)		Northwest Natural Gas Company Umbrella Trust for Directors, effective January 1, 1991, Restated as of December 1, 2001; Amendment No. 1 to Umbrella Trust for Directors, effective February 27, 2003; and Amendment No. 2 to Umbrella Trust for Directors, effective February 24, 2005.

10b.(4)		Northwest Natural Gas Company Umbrella Trust for Executives, effective January 1, 1988, Restated as of January 1, 2001; Amendment No. 1 to Umbrella Trust for Executives, effective February 27, 2003; and Amendment No. 2 to Umbrella Trust for Executives, effective February 24, 2005.

*10 c.		Restated Stock Option Plan, as amended effective May 23, 2002 (incorporated herein by reference to Exhibit 10(a) to Form 10-Q for quarter ended September 30, 2002, File No. 0-994).

*10e.		Executive Deferred Compensation Plan, effective as of January 1, 1987, Restated as of January 1, 2003 (incorporated herein by reference to Exhibit 10 e. to Form 10-K for 2002, File No. 0-994).

*10f.		Directors Deferred Compensation Plan, effective June 1, 1981, restated as of February 26, 2004 (incorporated herein by reference to Exhibit 10f. to Form 10-K for 2003, File No. 0-994).

*10f.(1)		Deferred Compensation Plan for Directors and Executives effective January 1, 2005 (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated November 17, 2004, File No. 1-15973).

*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 January 1, 2005 (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated September 28, 2004, File No. 1-15973).

10i-1		Summary of waiver of forfeiture provisions of Non-Employee Directors Stock Compensation Plan for a deceased director.

*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)

*10n.		Summary of Compensation Arrangements for Chairman of the Board, March 1, 2003 – February 28, 2005 (incorporated herein by reference to Exhibit 10n.-3 to Form 10-K for 2002, File No. 0-994).

*10o.		Form of amended and restated executive change in control severance agreement as entered into between the Company and each executive officer (incorporated herein by reference to Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2001, File No. 0-994).

*10o.(1)		Form of change in control letter agreement as entered into between the Company and each executive officer (incorporated herein by reference to Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 2001, File No. 0-994).

*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).

*10r.		Employment agreement dated May 11, 1999, between the Company and an executive officer (incorporated herein by reference to Exhibit 10 to Form 10-Q for the quarter ended June 30, 1999, File No. 0-994).

*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).

*10x.		Form of Restricted Stock Bonus Agreement as entered into between the Company and certain executive officers (incorporated herein by reference to Exhibit 10.3 to Form 8-K dated September 28, 2004, File No. 1-15973).



*10y.(1)		Retirement Agreement and Mutual Release of All Claims dated June 25, 2004 entered into between a former executive officer and the Company (incorporated herein by reference to Exhibit 10 to Form 10-Q for the quarter ended June 30, 2004, File No. 1-15973).

*10y.(2)		Amendment to Retirement Agreement and Mutual Release of All Claims between a former executive officer and the Company dated October 19, 2004 (incorporated herein by reference to Exhibit 10 to Form 10-Q for the quarter ended September 30, 2004, File No. 1-15973).

*10z.(1)		Summary of non-employee director compensation, effective Jan. 1, 2005 (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated Feb. 11, 2005, File No. 1-15973).

10z.(2)		Summary of 2005 compensation for named executive officers.

The Company agrees to furnish the Commission, upon request, a copy of certain instruments defining rights of holders of long-term debt of the Company or its consolidated subsidiaries which authorize securities thereunder in amounts which do not exceed 10% of the total assets of the Company.


Title of each class		Name of each exchange on which registered
Common Stock, $3 1/6 par value, and Common Share Purchase Rights		New York Stock Exchange

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

Title of each class		Shares outstanding on Dec. 31, 2004
Preferred Stock, without par value		None


		Page
PART I
	Glossary of Terms	3
Item 1.	Business	4
	General	4
	Business Segments	4
	Subsidiaries	5
	Gas Supply and Transportation	6
	Regulation and Rates	12
	Additions to Infrastructure	15
	Pipeline Safety	16
	Competition and Marketing	17
	Environmental Matters	19
	Employees	19
	Available Information	20

Item 2.	Properties	20

Item 3.	Legal Proceedings	21

Item 4.	Submission of Matters to a Vote of Security Holders	22

PART II

Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23

Item 6.	Selected Financial Data	25

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	56

Item 8.	Financial Statements and Supplementary Data	60

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	105

Item 9A.	Controls and Procedures	105

Item 9B.	Other Information	106

PART III

Item 10.	Directors and Executive Officers of the Registrant	107

Item 11.	Executive Compensation	107

Item 12.	Security Ownership of Certain Beneficial Owners and Management	108

Item 13.	Certain Relationships and Related Transactions	109

Item 14.	Principal Accountant Fees and Services	109

PART IV

Item 15.	Exhibits and Financial Statement Schedules	109

SIGNATURES		110


Regional Supply Basin

Region	2004 Actual	2004-09 Target
Alberta	26%	45	%
British Columbia	46%	30	%
U.S. Rockies	27%	25	%
Mist gas field	1%	<1	%

Total	100%


Sources of Supply	Therms (in millions)	Percent
Firm contracts	3.25	37
Off-system storage	1.06	12
Mist underground storage	2.30	26
Company-owned liquefied natural gas storage	1.80	20
Recall agreements	0.45	5

Total	8.86	100


Contract Duration		Percent of Purchases

Long-term (10 years or longer)		20
Medium-term (1 to 10 years)		39
Short-term (less than one year)		33
Spot (up to 30 days)		8

Total		100


	2004				2003
Quarter Ended	High		Low		High		Low
March 31	$	33.00	$	29.95	$	28.47	$	24.05
June 30		31.65		27.46		28.88		24.77
September 30		32.37		28.84		30.11		27.02
December 31		34.13		30.77		31.30		28.51


Payment Date	2004		2003

February 15	$	0.325	$	0.315
May 15		0.325		0.315
August 15		0.325		0.315
November 15		0.325		0.325

Total per share	$	1.300	$	1.270


	(a)	(b)		(c)	(d)
Period	Total Number of Shares Purchased(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2)
Balance forward				355,400	$	26,800,000
10/01/04-
10/31/04	-		-	-		-

11/01/04-
11/30/04	1,000	$	33.29	-		-

12/01/04-
12/31/04	5,355	$	33.80	-		-

Total	6,355	$	33.72	355,400	$	26,800,000


Thousands, except per share amounts and ratio of earnings to fixed charges	For the year ended Dec. 31,
	2004		2003		2002			2001			2000
Sales revenues:
Residential	$	381,526	$	328,464	$	354,735		$	329,905		$	280,642
Commercial		199,725		176,385		201,475			190,236			159,660
Industrial - firm		44,625		33,578		42,965			49,662			37,378
Industrial - interruptible		55,380		23,661		15,937			34,283			23,483
Unbilled revenues		3,849		14,474		(12,702	)		13,774			12,661

Total gas sales revenues		685,105		576,562		602,410			617,860			513,824
Transportation		12,655		17,962		26,020			20,637			21,491
Other		3,185		7,460		4,018			(2,325	)		(3,976	)

Total gross utility operating revenues		700,945		601,984		632,448			636,172			531,339
Cost of gas sold		399,176		323,128		353,034			364,699			273,978

Net utility operating revenues		301,769		278,856		279,414			271,473			257,361
Net non-utility operating revenues		6,591		9,210		8,130			4,538			589

Net operating revenues	$	308,360	$	288,066	$	287,544		$	276,011		$	257,950


Net income	$	50,572	$	45,983	$	43,792		$	50,187		$	50,224
Redeemable preferred and preference stock dividend requirements		-		294		2,280			2,401			2,456

Earnings applicable to common stock	$	50,572	$	45,689	$	41,512		$	47,786		$	47,768


Average common shares outstanding:
Basic		27,016		25,741		25,431			25,159			25,183
Diluted		27,283		26,061		25,814			25,612			25,638

Earnings per share of common stock:
Basic	$	1.87	$	1.77	$	1.63		$	1.90		$	1.90
Diluted	$	1.86	$	1.76	$	1.62		$	1.88		$	1.88

Dividends per share of common stock	$	1.30	$	1.27	$	1.26		$	1.245		$	1.24

Total assets - at end of period	$	1,732,195	$	1,585,379	$	1,467,277		$	1,550,653		$	1,385,414

Redeemable preferred stock	$	-	$	-	$	8,250		$	9,000		$	9,750
Redeemable preference stock	$	-	$	-	$	-		$	25,000		$	25,000

Long-term debt	$	484,027	$	500,319	$	445,945		$	378,377		$	400,790

Ratio of earnings to fixed charges		3.02		2.84		2.85			3.14			3.14


Thousands, except customer, degree day, usage and gas cost per therm data	2004			2003		2002			2001		2000
Capitalization - at end of period

Common stock equity	$	568,517		$	506,316	$	482,392		$	468,161	$	452,309
Redeemable preference stock		-			-		-			25,000		25,000
Redeemable preferred stock		-			-		8,250			9,000		9,750
Long-term debt		484,027			500,319		445,945			378,377		400,790

Total capitalization	$	1,052,544		$	1,006,635	$	936,587		$	880,538	$	887,849


Gas sales and transportation deliveries (therms):
Residential		356,199			343,534		357,091			350,065		356,375
Commercial		226,490			226,257		240,155			242,293		250,380
Industrial - firm		63,149			55,314		63,215			79,778		76,559
Industrial - interruptible		104,278			47,994		26,241			63,597		56,632
Unbilled therms		(7,764	)		12,099		(6,617	)		1,771		8,691

Total gas sales		742,352			685,198		680,085			737,504		748,637
Transportation		389,514			414,554		445,999			385,783		431,136

Total volumes delivered		1,131,866			1,099,752		1,126,084			1,123,287		1,179,773


Customers (average for period):
Residential		525,976			510,336		492,871			474,373		456,449
Commercial		57,973			56,504		55,416			54,628		53,617
Industrial - firm		629			362		350			377		375
Industrial - interruptible		178			98		74			141		118
Transportation		106			179		190			111		125

Total customers		584,862			567,479		548,901			529,630		510,684


Customer statistics:
Heat requirements
Actual degree days		3,853			3,952		4,232			4,325		4,416
25-year average degree days		4,202			4,236		4,255			4,265		4,273
Average annual use per customer in therms:
Residential		677			673		725			738		781
Commercial		3,907			4,004		4,334			4,435		4,670

Gas purchased cost per therm - net (cents)		56.60			46.99		51.07			47.19		37.68


(Thousands)	Change in Assumption		Impact on 2004 NPPC		Impact on ABO at Dec. 31, 2004
Discount rate	(0.25	%)	$	608	$	5,255
Expected long-term return on plan assets	(0.25	%)	$	403		N/A


(Thousands, except customers and degree days)	2004			2003			2002

Utility volumes - therms:
Residential and commercial sales		574,925	51%		581,890	53%		590,629	52%
Industrial sales and transportation		556,941	49%		517,862	47%		535,455	48%

Total utility volumes sold and delivered		1,131,866	100%		1,099,752	100%		1,126,084	100%


Utility operating revenues - dollars:
Residential and commercial sales	$	585,100	83%	$	519,323	86%	$	543,508	86%
Industrial sales and transportation		112,660	16%		75,201	13%		84,922	13%
Other revenues		3,185	1%		7,460	1%		4,018	1%

Total utility operating revenues	$	700,945	100%	$	601,984	100%	$	632,448	100%

Cost of gas sold		399,176			323,128			353,034

Utility net operating revenues (margin)	$	301,769		$	278,856		$	279,414


Total number of customers (end of year)		596,635			578,150			560,067

Actual degree days		3,853			3,952			4,232

Percent colder (warmer) than normal		(8%)			(7%)			(1%)
(25-year average degree days is used as normal)


(Thousands, except customer data)	2004	2003	2002

Utility volumes - therms:
Residential sales	356,199	343,534	357,091
Commercial sales	226,490	226,257	240,155
Change in unbilled sales	(7,764)	12,099	(6,617)

Total weather-sensitive utility volumes	574,925	581,890	590,629


(Thousands, except customers)	2004		2003		2002

Utility volumes - therms:
Industrial firm sales		63,149		55,314		63,215
Industrial interruptible sales		104,278		46,327		22,841
Electric generation sales and transportation		-		1,667		3,400
Transportation		389,514		414,554		445,999

Total utility volumes		556,941		517,862		535,455


Utility operating revenues - dollars:
Industrial firm sales	$	44,625	$	33,578	$	42,965
Industrial interruptible sales		55,380		23,655		11,346
Electric generation sales and transportation		-		6		4,591
Transportation		12,655		17,962		26,020

Total utility revenues	$	112,660	$	75,201	$	84,922

Total number of industrial sales and transportation customers (end of year)		935		754		578


	Increase (Decrease)
(Thousands)	2004			2003
Franchise taxes	$	2,215		$	(92	)
Payroll taxes		1,078			232
Property taxes		732			930
Other taxes		(342	)		(21	)

Total increase	$	3,683		$	1,049


Year ended December 31,	2004	2003
Common stock equity	48.7%	46.4%
Long-term debt	41.3%	45.8%
Short-term debt, including current maturities of long-term debt	10.0%	7.8%

Total	100.0%	100.0%


(Thousands)	Payments Due in Years Ending Dec. 31,
Contractual Obligations	2005		2006		2007		2008		2009		Thereafter		Total
Commercial paper	$	102,500	$	-	$	-	$	-	$	-	$	-	$	102,500
Long-term debt		15,000		8,000		29,500		5,000		-		441,527		499,027
Interest on long-term debt		33,213		32,561		31,085		30,268		30,052		373,744		530,923
Capital leases		230		189		97		29		-		-		545
Operating leases		4,491		4,136		3,967		3,836		3,834		38,908		59,172
Gas purchase contracts ⁽¹⁾		277,371		184,572		167,093		150,898		62,155		112,684		954,773
Gas pipeline commitments		62,988		57,800		58,981		57,234		50,702		271,796		559,501
Other purchase commitments		12,162		147		-		-		-		-		12,309

Total	$	507,955	$	287,405	$	290,723	$	247,265	$	146,743	$	1,238,659	$	2,718,750


Rating Agency	S&P	Moody’s	Fitch

Commercial Paper (short-term debt)	A-1	P-1	F1
Senior Secured (long-term debt)	A+	A2	A
Senior Unsecured (long-term debt)	A	A3	A-
Ratings Outlook	Stable	Stable	Stable


Thousands (year ended December 31)	2004		2003		2002
Net income	$	50,572	$	45,983	$	43,792
Non-cash adjustments to net income		69,216		55,835		76,303
Changes in operating assets and liabilities (working capital sources)		(12,049)		6,375		4,228

Cash provided by operating activities	$	107,739	$	108,193	$	124,323


(Thousands)	Credit Exposure
Investment grade counterparties	$	15,957
Non-investment grade counterparties		-

Total	$	15,957


		Page
1.	Management’s Report on Internal Control Over Financial Reporting	61

2.	Report of Independent Registered Public Accounting Firm	62

3.	Consolidated Financial Statements:

	Consolidated Statements of Income for the Years Ended December 31, 2004, 2003 and 2002	64

	Consolidated Balance Sheets at December 31, 2004 and 2003	65

	Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the Years Ended December 31, 2004, 2003 and 2002	67

	Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002	68

	Consolidated Statements of Capitalization at December 31, 2004 and 2003	69

	Notes to Consolidated Financial Statements	70

4.	Quarterly Financial Information (unaudited)	103

5.	Supplementary Data for the Years Ended December 31, 2004, 2003 and 2002:

	Financial Statement Schedule

	Schedule II – Valuation and Qualifying Accounts and Reserves	104


Thousands, except per share amounts (year ended December 31)	2004		2003		2002
Operating revenues:
Gross operating revenues	$	707,604	$	611,256	$	641,376
Cost of sales		399,244		323,190		353,832

Net operating revenues		308,360		288,066		287,544


Operating expenses:
Operations and maintenance		102,155		96,420		85,120
Taxes other than income taxes		38,808		35,125		34,076
Depreciation and amortization		57,371		54,249		52,090

Total operating expenses		198,334		185,794		171,286

Income from operations		110,026		102,272		116,258

Other income (expense)		2,828		2,150		(14,890)
Interest charges - net of amounts capitalized		35,751		35,099		34,132

Income before income taxes		77,103		69,323		67,236
Income tax expense		26,531		23,340		23,444


Net income		50,572		45,983		43,792
Redeemable preferred and preference stock dividend requirements		-		294		2,280

Earnings applicable to common stock	$	50,572	$	45,689	$	41,512


Average common shares outstanding:
Basic		27,016		25,741		25,431
Diluted		27,283		26,061		25,814

Earnings per share of common stock:
Basic	$	1.87	$	1.77	$	1.63
Diluted	$	1.86	$	1.76	$	1.62


Thousands (December 31)	2004		2003

Assets:
Plant and property:
Utility plant	$	1,794,972	$	1,657,589
Less accumulated depreciation		505,286		471,716

Utility plant - net		1,289,686		1,185,873

Non-utility property		33,963		23,395
Less accumulated depreciation and amortization		5,244		4,855

Non-utility property - net		28,719		18,540

Total plant and property		1,318,405		1,204,413


Other investments		60,618		73,845


Current assets:
Cash and cash equivalents		5,248		4,706
Accounts receivable, less allowance for uncollectible accounts of $2,434 in 2004 and $1,763 in 2003		60,675		48,499
Accrued unbilled revenue		64,401		59,109
Inventories of gas, materials and supplies		66,477		50,859
Income tax receivable		15,970		8,986
Prepayments and other current assets		24,346		23,675

Total current assets		237,117		195,834


Regulatory assets:
Income tax asset		64,734		63,449
Deferred gas costs receivable		9,551		-
Unamortized costs on debt redemptions		7,332		7,803
Other		3,321		6,020

Total regulatory assets		84,938		77,272


Other assets:
Fair value of non-trading derivatives		16,399		23,885
Other		14,718		10,130

Total other assets		31,117		34,015

Total assets	$	1,732,195	$	1,585,379


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, 2001	$	320,586	$	147,950	$	(372)	$	(375)	$	467,789
Net Income		-		43,792		-		-		43,792	$	43,792
Minimum pension liability adjustment - net of tax		-		-		-		(2,936)		(2,936)		(2,936)
Change in unrealized loss from price risk management activities - net of tax		-		-		-		227		227		227
Purchases of restricted stock		-		-		(891)		-		(891)
Restricted stock amortizations		-		-		552		-		552
Cash dividends paid:		-		-		-		-		-
Redeemable preferred and preference stock		-		(2,579)		-		-		(2,579)
Common stock		-		(32,024)		-		-		(32,024)
Issuance of common stock		6,533		-		-		-		6,533
Conversion of debentures		1,932		-		-		-		1,932
Common stock expense		-		(3)		-		-		(3)

Balance at Dec. 31, 2002		329,051		157,136		(711)		(3,084)		482,392	$	41,083

Net Income		-		45,983		-		-		45,983	$	45,983
Minimum pension liability adjustment - net of tax		-		-		-		2,068		2,068		2,068
Purchases of restricted stock		-		-		(328)		-		(328)
Restricted stock amortizations		-		-		310		-		310
Cash dividends paid:
Redeemable preferred stock		-		(392)		-		-		(392)
Common stock		-		(32,655)		-		-		(32,655)
Tax benefits from employee stock option plan		401		-		-		-		401
Issuance of common stock		7,930		-		-		-		7,930
Conversion of debentures		626		-		-		-		626
Common stock expense		-		(19)		-		-		(19)

Balance at Dec. 31, 2003		338,008		170,053		(729)		(1,016)		506,316	$	48,051

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
Cash dividends paid:
Common stock		-		(35,105)		-		-		(35,105)
Tax benefits from employee stock option plan		872		-		-		-		872
Issuance of common stock		47,148		-		-		-		47,148
Conversion of 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


Thousands, except share amounts (December 31)	2004			2003
Common stock equity:
Common stock - par value $3¹/6 per share, authorized 60,000,000 shares: outstanding - 2004, 27,546,720 shares; 2003, 25,938,002 shares	$	87,231		$	82,137
Premium on common stock		300,034			255,871
Earnings invested in the business		183,932			170,053
Unearned compensation		(862)			(729)
Accumulated other comprehensive income (loss)		(1,818)			(1,016)

Total common stock equity		568,517	54%		506,316	50%
Long-term debt:
Medium-Term Notes
First Mortgage Bonds:
6.340% Series B due 2005		5,000			5,000
6.380% Series B due 2005		5,000			5,000
6.450% Series B due 2005		5,000			5,000
6.050% Series B due 2006		8,000			8,000
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
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
Convertible Debentures
7¹/4% Series due 2012		4,527			5,819

		499,027			500,319
Less long-term debt due within one year		15,000			-

Total long-term debt		484,027	46%		500,319	50%

Total capitalization	$	1,052,544	100%	$	1,006,635	100%


Thousands, except per share amounts	2004		2003		2002

Net income	$	50,572	$	45,983	$	43,792
Redeemable preferred and preference stock dividend requirements		-		294		2,280

Earnings applicable to common stock - basic		50,572		45,689		41,512
Debenture interest less taxes		200		257		285

Earnings applicable to common stock - diluted	$	50,772	$	45,946	$	41,797


Average common shares outstanding - basic		27,016		25,741		25,431
Stock options		40		28		59
Convertible debentures		227		292		324

Average common shares outstanding - diluted		27,283		26,061		25,814


Earnings per share of common stock - basic	$	1.87	$	1.77	$	1.63

Earnings per share of common stock - diluted	$	1.86	$	1.76	$	1.62


Thousands	Utility		Interstate Gas Storage		Other		Total
2004
Net operating revenues	$	301,769	$	6,423	$	168	$	308,360
Depreciation and amortization		56,899		472		-		57,371
Other operating expenses		140,089		652		222		140,963
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
Total assets at Dec. 31, 2004		1,688,688		28,361		15,146		1,732,195

2003
Net operating revenues	$	278,856	$	9,036	$	174	$	288,066
Depreciation and amortization		53,798		451		-		54,249
Other operating expenses		130,619		804		122		131,545
Income from operations		94,439		7,781		52		102,272
Income from financial investments		3,406		-		474		3,880
Net income		40,913		4,312		758		45,983
Total assets at Dec. 31, 2003		1,551,817		19,036		14,526		1,585,379

2002
Net operating revenues	$	279,414	$	7,944	$	186	$	287,544
Depreciation and amortization		51,693		396		1		52,090
Other operating expenses		118,156		962		78		119,196
Income from operations		109,565		6,586		107		116,258
Income from financial investments		1,390		-		988		2,378
Loss provision for PGE transaction costs		-		-		(8,414)		(8,414)
Net income (loss)		47,280		3,646		(7,134)		43,792
Total assets at Dec. 31, 2002		1,432,777		16,403		18,097		1,467,277


	-------------------Shares--------------------			Premium on common stock (thousands)
	Common stock	Redeemable preference stock	Redeemable preferred stock	Premium on common stock (thousands)
Balance, Dec. 31, 2001	25,228,074	250,000	90,000	$	240,697
Sales to employees	42,862	-	-		748
Sales to stockholders	157,288	-	-		3,854
Exercise of stock options - net	61,020	-	-		1,105
Conversion of convertible debentures to common	97,069	-	-		1,624
Sinking fund purchases	-	-	(7,500)		-
Redemption	-	(250,000)	-		-

Balance, Dec. 31, 2002	25,586,313	-	82,500		248,028
Sales to employees	14,175	-	-		425
Sales to stockholders	178,714	-	-		4,347
Exercise of stock options - net	127,357	-	-		2,545
Conversion of convertible debentures to common	31,443	-	-		526
Sinking fund purchases	-	-	(7,500)		-
Early redemption	-	-	(75,000)		-

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
Repurchase	(4,500)	-	-		(41)

Balance, Dec. 31, 2004	27,546,720	-	-	$	300,034


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


	2004		2002
Expected life in years		7.0		7.0
Risk-free interest rate		3.6%		3.6%
Expected volatility		25.2%		29.1%
Dividend yield		4.1%		4.8%
Present value of options granted	$	24.55	$	20.49


			-------------Price per Share-------------
	Option Shares		Range		Weighted-Average Exercise Price
Balance outstanding, Dec. 31, 2001	387,091		$	20.25 - 27.875	$	22.79
Granted	163,750			26.07 - 27.850		26.35
Exercised	(68,827	)		20.25 - 27.875		21.74
Expired	(18,200	)		20.25 - 27.875		25.43
Balance outstanding, Dec. 31, 2002	463,814			20.25 - 27.875		24.10
Exercised	(140,470	)		20.25 - 27.875		21.14
Expired	(1,300	)		20.25		20.25
Balance outstanding, Dec. 31, 2003	322,044			20.25 - 27.875		25.35
Granted	202,800			31.34 - 32.020		31.40
Exercised	(92,074	)		20.25 - 27.875		24.39
Expired	(1,300	)		26.30 - 31.340		30.18
Balance outstanding, Dec. 31, 2004	431,470		$	20.25 - 32.020	$	28.38

Shares available for grant
Dec. 31, 2002	1,428,200
Shares available for grant
Dec. 31, 2003	1,429,500
Shares available for grant
Dec. 31, 2004	1,228,000


	Post-Retirement Benefits
	Pension Benefits						Other Postretirement Benefits
Thousands	2004		2003		2002		2004		2003		2002
Change in benefit obligation:
Benefit obligation at Jan. 1	$	205,352	$	185,124	$	166,751	$	23,379	$	18,457	$	16,987
Service cost		5,428		4,748		4,637		457		456		395
Interest cost		12,690		12,402		11,807		1,232		1,336		1,174
Special termination benefits		237		-		-		-		-		-
Expected benefits paid		(10,682)		(10,363)		(9,453)		(1,040)		(1,027)		(979)
Plan amendments		-		-		-		-		(111)		(300)
Net actuarial (gain) loss		9,923		13,441		11,382		(1,299)		4,268		1,180

Benefit obligation at Dec. 31		222,948		205,352		185,124		22,729		23,379		18,457

Change in plan assets:
Fair value of plan assets at Jan. 1		168,324		143,164		168,964		-		-		-
Actual return on plan assets		19,835		34,520		(17,082)		-		-		-
Employer contributions		9,310		1,003		735		1,040		1,027		979
Benefits paid		(10,682)		(10,363)		(9,453)		(1,040)		(1,027)		(979)

Fair value of plan assets at Dec. 31		186,787		168,324		143,164		-		-		-

Funded status:
Funded status at Dec. 31		(36,162)		(37,028)		(41,960)		(22,729)		(23,379)		(18,457)
Unrecognized transition obligation		-		-		-		3,292		3,703		4,226
Unrecognized prior service cost		5,146		6,240		7,371		-		-		-
Unrecognized net actuarial loss		33,897		32,156		42,060		6,717		8,304		4,437

Net amount recognized	$	2,881	$	1,368	$	7,471	$	(12,720)	$	(11,372)	$	(9,794)

Amounts recognized in the consolidated balance sheets at Dec. 31:
Prepaid benefit cost	$	12,745	$	11,113	$	17,339	$	-	$	-	$	-
Accrued benefit liability		(12,919)		(11,319)		(18,741)		(12,720)		(11,372)		(9,794)
Intangible asset		-		-		4,438		-		-		-
Other comprehensive loss		3,055		1,574		4,435		-		-		-

Net amount recognized	$	2,881	$	1,368	$	7,471	$	(12,720)	$	(11,372)	$	(9,794)


	Percent of Plan Assets Dec. 31,		Target Allocation	Expected Long-term Rate of Return
Asset Category	2004	2003	2005	2005
US Large Cap Equity	36.3%	40.2%	35%	9.00%
US Small/Mid Cap Equity	9.2%	7.3%	8%	9.50%
Non-US Equity	19.2%	16.0%	15%	9.00%
Fixed Income	19.8%	24.8%	25%	5.75%
Real Estate	3.6%	3.9%	4%	8.00%
Absolute Return	7.3%	7.8%	8%	9.00%
Real Return	4.6%	-	5%	8.25%

Weighted Average				8.25%


Thousands	1% Increase		1% Decrease
Effect on the total service and interest cost components of net periodic postretirement health care benefit cost	$	48	$	(47	)
Effect on the health care cost component of the accumulated postretirement benefit obligation	$	901	$	(815	)


Thousands
Employer Contributions by Plan Year		Pension Benefits		Other Benefits
2003	$	3,922	$	1,027
2004		6,390		1,040
2005 (estimated)		1,620		1,452
Benefit Payments
2002	$	9,453	$	979
2003		10,363		1,027
2004		10,682		1,040
Estimated Future Payments
2005	$	12,404	$	1,452
2006		12,817		1,561
2007		13,106		1,641
2008		13,892		1,738
2009		14,325		1,794
2010-2014		82,578		9,667