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. Yesx No¨

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

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

At ~~October 31, 2006, 27,504,896~~April 30, 2007, 26,987,803 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

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

The information presented in the interim consolidated financial statements is unaudited, but includes all material adjustments, including normal recurring accruals, that management considers necessary for a fair statement of the results for each period reported. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our ~~2005~~2006 Annual Report on Form 10-K ~~(2005~~(2006 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of the results for a full year.

Certain ~~amounts from~~ prior ~~years~~year balances on our consolidated balance sheet have been reclassified to conform ~~for comparison purposes, to~~with the current ~~financial statement~~ presentation. The current year’s presentation of the Consolidated Statements of Income includes the reclassification of revenue taxes as a component of net operating revenues. Revenue taxes are expenses primarily related to the utility’s franchise agreements and are based on gross operating revenues. Since revenue taxes are a direct cost of utility sales, the financial statement classification was changed to improve the presentation of net operating revenues and operating expenses. In prior years, revenue taxes were included under operating expenses as part of taxes other than income taxes. TheThese reclassifications had no impact on ~~the~~our prior year’s ~~income from~~consolidated results of operations and no material impact on financial condition or ~~net income.~~cash flows.

~~Share Based Payment.~~Accounting for Uncertainty in Income Taxes. ~~Effective Jan.~~On January 1, ~~2006,~~2007, we adopted ~~Statement of~~ Financial Accounting Standards ~~(SFAS)~~Board (FASB) Interpretation No. ~~123R, “Share Based Payment,~~48 (FIN 48), “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109,” ~~using~~which provides guidance for the ~~Modified Prospective Application method without restatement~~recognition and measurement of ~~prior periods. Prior~~a tax position taken or expected to be taken in a tax return. As a result of the implementation of ~~SFAS No. 123R,~~FIN 48, we ~~accounted~~recognized no change in our recorded assets or liabilities for ~~stock-based compensation using~~unrecognized income tax benefits. Based on our analysis of all material tax positions taken, management believes the ~~intrinsic value method prescribed in Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R~~technical merits of these positions are justified and expects that the full amount of the deductions taken and associated tax benefits will be allowed.

FIN 48 requires ~~companies to recognize compensation expense for all equity-based compensation awards issued to employees~~the evaluation of a tax position as a two-step process. We must determine whether it is more likely than not that ~~are expected to vest. Under this method, we began to amortize compensation cost for~~a tax position will be sustained upon examination, including the ~~remaining portion~~resolution of ~~outstanding awards for which the requisite service was not yet rendered at Jan. 1, 2006. Compensation cost for these awards was~~any related appeals or litigation processes, based on the ~~fair value~~technical merits of the ~~awards~~position. If the tax position meets the “more likely than not” recognition threshold, then the tax benefit is measured and recorded at the ~~grant date which was determined under the intrinsic value method. We determine the fair value~~largest amount that is greater than 50 percent likely of ~~and account for awards that are granted, modified or settled after Jan. 1, 2006~~being realized upon ultimate settlement. The re-assessment of our tax positions in accordance with ~~SFAS No. 123R. The adoption of SFAS No. 123R~~FIN 48 did not ~~have a~~result in any material ~~impact on~~change to our financial condition, results of operations or cash flows. ~~See Note 4 for a discussion~~For additional information regarding income taxes, see Part II, Item 7., “Application of ~~stock-based compensation.~~

Critical Accounting Policies and Estimates—Accounting for ~~Changes~~Income Taxes,” and ~~Error Corrections~~.~~Effective Jan. 1,~~Part II, Item 8., Note 8, in the 2006 ~~we adopted SFAS No. 154, “Accounting~~Form 10-K.

We are subject to U.S. federal income taxes as well as several state and local income taxes. All of our U.S. federal income tax matters audited by the Internal Revenue Service through the 2004 tax year were concluded during 2006 with no material adjustments. Also, substantially all material state and local income tax matters are closed for ~~Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which provides guidance on~~ the ~~accounting for and reporting of accounting changes and error corrections. The statement requires retrospective application to prior periods’ financial statements of changes~~years through 2002. Based upon our assessment in ~~accounting principles, unless it is impracticable~~

~~to determine~~connection with the period-specific effects or the cumulative effect of the change. The guidance provided in APB Opinion No. 20 for reporting the correction of an error in previously issued financial statements remains unchanged and requires the restatement of previously issued financial statements. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after Dec. 15, 2005. The adoption of ~~SFAS No. 154 did~~FIN 48, we do not believe there are any tax positions taken that would not be fully sustained upon audit.

We have also assessed the classification of interest and penalties, if any, related to income tax matters. Pursuant to the application of FIN 48, we have made an accounting election to treat interest and penalties related to income tax matters, if any, as a ~~material impact upon our financial condition, results~~component of ~~operations or cash flows.~~

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

~~Purchases and Sales of Inventory with the Same Counterparty.~~ In September 2005, the Financial Accounting Standards Board (FASB) Emerging Issues Task Force (EITF) reached a final consensus on Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” EITF 04-13 requires that two or more legally separate exchange transactions with the same counterparty be combined and considered a single arrangement for purposes of applying APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” when the transactions are entered into in contemplation of one another. EITF 04-13 is effective for new arrangements entered into, or modifications or renewals of existing arrangements, in interim or annual periods beginning after March 15, 2006. Adoption of this standard did not have a material impact on our financial condition, results of operations or cash flows.

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

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

Recent Accounting ~~for Uncertainty in Income Taxes.~~In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken in a tax return. Preparers must determinePronouncements

whether it is “more-likely-than-not” that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. Once it is determined that a position meets the more-likely-than-not recognition threshold, the position is measured to determine the amount of benefit to recognize in the financial statements. FIN 48 applies to all tax positions related to income taxes subject to SFAS No. 109, “Accounting for Income Taxes.” FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. We do not anticipate that the adoption of this statement will have a material effect on our financial condition, results of operations or cash flows.

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

~~Employers’ Accounting~~Fair Value Option for ~~Defined Benefit Pension~~Financial Assets and ~~Other Postretirement Plans.~~Liabilities.In ~~September 2006,~~February 2007, the FASB issued SFAS No. ~~158, “Employers’ Accounting~~159, “The Fair Value Option for ~~Defined Benefit Pension~~Financial Assets and ~~Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106~~Financial Liabilities,” which permits entities to choose to measure many financial instruments and ~~132(R).”~~certain other items at fair value. SFAS No. 158 requires balance sheet recognition of the overfunded or underfunded status of pension and other postretirement benefit plans. For pension plans, the liability will be based on the projected benefit obligation (PBO). Under SFAS No. 158, any actuarial gains and losses, prior service costs and transition assets or obligations that were not recognized under previous accounting standards must be recognized in accumulated other comprehensive income (AOCI) under common stock equity, net of tax, until they are amortized as a component of net periodic benefit cost. In addition, the measurement date, which is the date when plan assets and the benefit obligations are measured, is required to be the company’s fiscal year end. This measurement date change will have no effect on our plan assets or benefit liabilities because we have been using our fiscal year end, December 31, as our measurement date. SFAS No. 158159 is effective for ~~us for the~~ fiscal years ~~ending~~beginning after ~~Dec.~~November 15, ~~2006.~~

2007. We are evaluating the effect of the adoption and implementation of SFAS No. 158. We intend to request regulatory deferral approval from our state commissions for deferred asset recognition of AOCI related to the funded status of certain plans under SFAS No. 71, “Accounting for Certain Types of Regulation.” If regulatory asset deferral of AOCI is approved, then we will recognize the change in actuarial gains and losses, prior service costs and transition assets or obligations each year as an adjustment to the regulatory AOCI asset or liability account as these amounts are recognized as components of net periodic pension costs each year. In prior years, regulatory deferral recognition was not necessary for us because we had maintained plan assets in excess of accumulated benefit obligations (ABO) for certain plans, and under the previous accounting standards the recognition of the unfunded status was not required based on PBO. Based on our unfunded obligations as of Dec. 31, 2005, the adoption of SFAS No. 158 would increase pension and postretirement liabilities by approximately $41 million, decrease deferred income tax liabilities by approximately $31 million, reduce prepayments and other current assets related to the elimination of our $37 million prepaid pension asset and decrease total common stock equity by approximately $47 million. Alternatively, if regulatory deferral is approved, our regulatory AOCI assets would increase by $47 million and total common stock equity would decrease by a negligible amount. The adoption of SFAS No. 158159, which is not expected to have a material impact on our financial condition, results of operations or cash flows. ~~We also do not expect adoption~~

Basic earnings per share are computed based on the weighted average number of ~~SFAS No. 158 to effect our ability to meet financial debt covenants. By~~common shares outstanding during each period presented. Diluted earnings per share reflect the ~~time~~potential effects of ~~adoption at Dec.~~the exercise of stock options. Diluted earnings are calculated as follows:

For the three month period ended March 31, 2006, ~~actual plan performance and actuarial assumptions could~~9,000 common shares were excluded from the calculation of diluted earnings per share because the effect would have ~~a material impact on the actual amounts recorded.~~been antidilutive.

In connection with ~~the restatement of~~an amendment to NW Natural’s Restated Articles of Incorporation effective May 31, 2006, the par value of NW Natural’s common stock was eliminated. As a result, NW Natural’s “common stock” and “premium on common stock” account balances are now reflected on the balance sheet as “common stock.” At March 31, 2007, we had 60,000,000 common shares authorized and 27,109,891 common shares outstanding.

We have in place a Board approved repurchase program for our common stock. During the three months ended March 31, 2007, 206,700 shares of our common stock were purchased pursuant to this program. In April 2007, the Board extended the program through May 31, 2008, further increased the authorization from 2.6 million shares to 2.8 million shares and further increased the dollar limit from $85 million to $100 million.

~~Effective Jan. 1, 2006, we adopted SFAS No. 123R, “Share Based Payment,” to account for all stock-based compensation plans.~~ Our stock-based compensation plans consist of the Long-Term Incentive Plan (LTIP), the Restated Stock Option Plan (Restated SOP), the Employee Stock Purchase Plan (ESPP) and the Non-Employee Directors Stock Compensation Plan (NEDSCP). These plans are designed to promote stock ownership by employees and officers and, in the case of the NEDSCP, non-employee ~~directors (see~~directors. For additional information on our stock-based compensation, see Part II, Item 8., Note 4, in the 2006 Form 10-K.

In November 2005, ~~Form 10-K)~~the FASB issued FASB Staff Position No. SFAS 123(R)-3 (FSP 123(R)), “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards.” FSP 123(R) provides an elective alternative transition method for calculating the pool of excess tax benefits available to absorb tax deficiencies recognized subsequent to the adoption of FAS 123(R). Companies may take up to one year from the effective date of FSP 123(R) to evaluate the available transition alternatives and make a one-time election as to which method to adopt. We have adopted the long-form method for calculating the pool of excess tax benefits.

Long-Term Incentive Plan. A total of 500,000 shares of NW Natural’s common stock ~~has~~have been authorized for awards under the terms of the LTIP as stock bonus, restricted stock or performance-based stock awards. At Sept. 30, 2006, performance-based awards on 99,994 shares, based on meeting target performance levels, and restricted stock awards on 11,500 shares, including 10,500 shares subject to vesting requirements, were outstanding, withDuring the ~~remaining 388,506 shares available for future grants.~~

~~Performance-based Stock Awards.~~~~At Sept. 30, 2006, the aggregate number of~~quarter ended March 31, 2007, 42,000 performance-based shares ~~awarded and outstanding under our LTIP at the threshold, target and maximum levels~~ were ~~as follows:~~

For each of the performance periods shown above, awards will be based on total shareholder return relative to a peer group of gas distribution companies over the three-year performance period and on performance results relative to our core and non-core strategies. For awards granted prior to Jan. 1, 2006, we recognize compensation expense and liability for the LTIP awards based on performance levels achieved and expected to be achieved, and the estimated market value of the common stock as of the distribution date. For awards granted on or after Jan. 1, 2006, we recognize compensation expense in accordance with SFAS No. 123R, based on performance levels achieved and an estimated fair value using a binomial model. For the quarter and nine months ended Sept. 30, 2006, the amount accrued and expensed as compensation under the three LTIP grants was $0.6 million. On a cumulative basis, $0.9 million, $1.0 million and $0.1 million have been accrued for the 2004-06, 2005-07 and 2006-08 performance periods, respectively.

~~Restricted Stock Awards.~~~~Restricted stock awards also have been~~ granted under the ~~LTIP. A restricted stock award consisting~~LTIP, based on target-level awards, with a weighted-average grant date fair value of 5,000 shares was granted in 2004, which vests ratably over the period 2005-09. On July 26, 2006, a restricted stock award was granted consisting of 6,500 shares, which will vest ratably over the period 2007-09.$33.29 per share.

Restated Stock Option ~~Plan.~~Plan ~~We have reserved a total of 2,400,000 shares of common~~. In February 2007, we granted 100,600 stock ~~for issuance~~options under the Restated ~~SOP. At Sept. 30, 2006, options on 1,134,400 shares were available for grant and options to purchase 369,600 shares were outstanding. Options are granted~~SOP, with an exercise price equal to the closing market price of ~~the~~our common stock on the ~~day preceding the~~ date of grant, ~~have 10-year terms and vest ratably~~vesting over ~~a three- or~~the four-year period following ~~the~~ date of ~~grant. Shares issued under the Restated SOP upon the exercise~~grant and a term of ~~stock options are original issue shares.~~10 years and 7 days. The fair value ~~of our stock-based awards~~ was estimated as of the date of grant using the Black-Scholes option pricing model based on the following weighted-average assumptions:

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

During 2006, we implemented SFAS No. 123R and, therefore, the pro forma effect of stock-based options and ESPP is as reported. However, the following table presents the effect on net income and earnings per share of outstanding stock options and stock awards for the 2005 periods:

The weighted-average grant-date fair value of equity awards granted during 2005 and 2006 was $7.85 and $6.29, respectively. By Dec. 31, 2006, an additional 1,000 options will vest for a total of 214,700 exercisable options at year-end, assuming no additional option exercises or forfeitures.

During the three and nine months ended Sept. 30, 2006, pre-tax compensation expense amounted to $0.1 million and $0.5 million, respectively, relating to options granted under the Restated SOP. This expense was recognized in operations and maintenance expense under the fair value method in accordance with SFAS No. 123R. In addition, $0.1 million of pre-tax compensation expense related to the ESPP was recognized for the nine months ended Sept. 30, 2006. As of ~~Sept. 30, 2006,~~March 31, 2007, there was ~~$0.5~~$0.9 million of unrecognized compensation cost related to the unvested portion of outstanding stock option awards expected to be recognized over a period extending through ~~2009.~~2010.

In the nine months ended Sept. 30, 2006, 34,300 option shares were exercised with a total intrinsic value of $0.3 million. Cash of $1.1 million was received for these exercises and a $0.1 million related tax benefit was realized. The total intrinsic value of options exercised in the first nine months of 2005 was $1.2 million, and the total fair value of options that vested in the first nine months of 2006 and 2005 was $0.3 million and $0.5 million, respectively.

~~The following table summarizes additional information about stock options outstanding and exercisable at Sept. 30, 2006:~~

~~In June~~At March 31, 2007 and 2006 and December 31, 2006, we ~~redeemed $8.0 million of secured 6.05% Series B Medium-Term Notes at maturity.~~

We enter into forward contracts and other related financial transactions for the purchase of natural gas that qualify as derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149 ~~(collectively~~

(collectively referred to as SFAS No. 133). We ~~primarily~~ utilize derivative financial instruments primarily to manage commodity prices related to natural gas supply requirements (see Part II, Item 8., Note 11, in the ~~2005~~2006 Form 10-K).

At ~~Sept. 30,~~March 31, 2007 and 2006, ~~and 2005,~~ unrealized gains orand losses from mark-to-market valuations of our derivative instruments were primarily reported as regulatory liabilities or regulatory assets because the realized gains or losses at settlement are included in utility gas costs, pursuant to our regulatory Purchased Gas Adjustment (PGA) deferral ~~mechanisms.~~mechanism. The estimated fair ~~values~~value of unrealized gains and losses on derivative instruments outstanding, determined using a discounted cash flow model for swaps and indexed-price contracts and a Black-Scholes option pricing model for options, were as follows:

In the ~~third~~first quarter of ~~2006,~~2007, we realized net losses of ~~$12.4~~$7.6 million from the settlement of fixed-price financial swap contracts which were recorded as increases to the cost of gas, compared to net ~~gain~~gains of ~~$20.5~~$17.5 million in ~~2005.~~the same period of 2006. Realized losses from financial contracts in 2007 were more than offset by lower gas purchase costs from the underlying hedged floating rate physical supply contracts. The foreign ~~exchange~~currency gain or loss ~~on foreign currency forward contracts~~ is included in cost of gas at ~~settlement; therefore, no gain or loss was recorded from the settlement of those contracts.~~settlement.

As of ~~Sept. 30, 2006,~~March 31, 2007, all non-current natural gas ~~commodity price swap~~commodity-based derivative contracts mature no later than ~~Oct.~~October 31, 2008.

Our ~~primary~~core business is the local gas distribution segment, ~~“Utility,~~also referred to as the “utility,” ~~consists of~~which involves the distribution and sale of natural gas. Another business segment, ~~“Interstate Gas Storage,~~“gas storage,” represents natural gas storage services provided to ~~interstate~~intrastate and ~~intrastate~~interstate customers and includes asset optimization ~~activities performed by~~services under a contract with an ~~unaffiliated~~independent energy marketing company primarily through the use of commodity transactions and temporary releases of portions of NW Natural’s upstream pipeline transportation capacity and gas storage capacity (see Part II, Item 8., Note 2, in the 2005 Form 10-K).company. The remaining business segment, ~~“Other,~~“other,” primarily consists of ~~non-utility operating activities~~non-regulated investments in alternative energy projects in California, a Boeing 737-300 aircraft leased to Continental Airlines and ~~non-regulated investments.~~low-income housing units in Portland, Oregon. Our net investment in the aircraft was reclassified to current assets as of December 31, 2006, with the original lease term expiring in September 2007.

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

NW Natural maintains two qualified non-contributory defined benefit pension plans covering all regular employees with more than one year of service. In July 2006, the Board of Directors approved changes to the defined benefit pension plan covering non-bargaining unit employees, closing participation to any new employees hired on or after Jan. 1, 2007. For affected employees, we will provide an enhanced benefit under our existing Retirement K Savings Plan, which is a defined contribution plan under Internal Revenue Code Section 401(k).

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

See Part II, Item 8., Note 7, in the ~~2005~~2006 Form 10-K for ~~a discussion of the assumptions used in measuring these costs~~more information about our pension and other postretirement benefit ~~obligations).~~plans.

Thousands
   Pension Benefits
Other Postretirement
Benefits
      Three Months Ended Sept. 30,
   2006 2005 2006    2005
Service cost
   $ 1,784 $ 1,564 $ 142    $ 114
Interest cost
   3,761 3,377 322    308
Special termination benefits
   —   63 —      —
Expected return on plan assets
   (4,403 ) (3,776 ) —      —
Amortization of transition obligation
   —   —   103    103
Amortization of prior service cost
   245 361 48    —
Recognized actuarial loss
   805 599 —      72

Net periodic benefit cost
   $ 2,192 $ 2,188 $ 615    $ 597

Thousands
   Pension Benefits
Other Postretirement
Benefits
   Nine Months Ended Sept. 30,
   2006 2005 2006    2005
Service cost
   $ 5,706 $ 4,741 $ 417    $ 342
Interest cost
   11,277 9,903 888    924
Special termination benefits
   —   189 —      —
Expected return on plan assets
   (13,210 ) (10,837 ) —      —
Amortization of transition obligation
   —   —   309    309
Amortization of prior service cost
   735 807 146    —
Recognized actuarial loss
   2,638 1,562 —      216

Net periodic benefit cost
   $ 7,146 $ 6,365 $ 1,760    $ 1,791

~~We are~~During the three months ended March 31, 2007, we did not make and were not required to make cash contributions to our qualified non-contributory defined benefit plans, ~~in 2006,~~ but cash contributions in the form of ongoing benefit payments ~~will be required~~of $0.6 million were made for ~~the~~our unfunded, non-qualified supplemental pension plans and other postretirement benefit ~~plans in 2006.~~plans. See Part II, Item 8., Note 7, in the ~~2005~~2006 Form 10-K for a discussion of future payments.

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

addition to NW Natural, there are a number of other potentially responsible parties, each of which, in proceedings and negotiations with other potentially responsible parties and regulators, may influence the course of the remediation effort and associated cost estimates. The allocation of liabilities among the potentially responsible parties is often subject to dispute and highly uncertain. The events giving rise to environmental liabilities often occurred many decades ago, which complicates the determination of allocating liabilities among potentially responsible parties. Site investigations and remediation efforts often develop slowly over many years. To the extent reasonably estimable, we estimate the costs of environmental liabilities using current technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a more likely estimate within this range of probable cost, we record the liability at the lower end of this range. It is likely that changes in these estimates will occur throughout the remediation process for each of these sites due to uncertainty concerning our responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The status of each of the sites currently under investigation is provided below. Also, seeSee Part II, Item 8., Note 12, in the ~~2005~~2006 Form ~~10-K for a description~~10-K. The status of ~~these properties and further discussion.~~each site currently under investigation is provided below.

Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). ~~We have~~The Gasco site has been ~~investigating the Gasco site~~under investigation by us for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. In the ~~third~~first quarter of ~~2006, we accrued an additional $0.3~~2007, the estimated liability for this site increased $0.5 million related to ~~be used~~estimated liabilities for the ~~upgrade~~development of ~~the water treatment system in conjunction with~~proposed studies of in-water source control ~~replacement~~and completion of those studies. We have accrued a ~~well, ongoing consultant and investigation fees for in-river groundwater and source control studies and to cover cost estimates~~liability of ~~remedial alternatives identified in the Feasibility Scoping Plan and Ecological and Human Health Risk Assessment~~$6.2 million at March 31, 2007 for the ~~most contaminated portion of the site. The liability balance at Sept. 30, 2006 is $2.7 million,~~Gasco site, which is at the low end of the ~~probable~~range because no amount within the range is considered to be more likely than another and ~~reasonably estimable liability range. We are not able to estimate~~ the high end of ~~a liability range.~~the range cannot be estimated.

Siltronic site. We previously owned property adjacent to the Gasco site that is now is the location of a manufacturing plant owned by Siltronic Corporation (the Siltronic site). We ~~had previously agreed to an addendum to the Voluntary Clean-up Agreement~~are currently working with the ODEQ ~~which will require additional investigation~~to develop a study of ~~potential~~ manufactured gas plant wastes on the ~~Siltronic~~uplands portion of this site. ~~Since the scope of work is unknown, there is not enough information to reasonably estimate the additional liability. The additional amount accrued~~See “Regulatory and Insurance Recovery for ~~this work in the third quarter of 2006 was negligible.~~Environmental Matters,” below.

Portland Harbor site. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River ~~(the Portland~~(Portland Harbor) that includes the area adjacent to the Gasco site and the Siltronic site. The Portland Harbor was listed by the EPA as a Superfund site in 2000 and we were notified that we are a potentially responsible party. We then joined with other potentially responsible parties, referred to as the Lower Willamette Group, to fund environmental studies in the Portland Harbor. Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study (RI/FS). In the third quarter of 2006, we accrued an additional $0.7 million to reflect our current estimate of liability of $1.9 million related to the RI/FS for consultant fees, technical work and other costs. InformationCurrent information is not sufficient to reasonably estimate additional liabilities, if any, or the range of potential liabilities, for environmental remediation and monitoring after the RI/FS work plan is completed, except for the early action removal of a tar deposit in the river sediments discussed below.

In April 2004, we entered into an Administrative Order on Consent providing for early action removal of a deposit of tar in the ~~Willamette River~~river sediments adjacent to the Gasco site. ~~The~~We completed the removal of the tar deposit in the Portland Harbor ~~was completed~~ in October 2005, ~~and in November 2005,~~which was approved by the ~~EPA approved the completed project. In the third quarter~~EPA. The total cost of ~~2006, we accrued an additional $0.1 million to reflect our current estimate of liability of $0.9 million for costs related to the tar deposit,~~removal, including technical work, oversight, consultant ~~and~~fees, legal fees and ongoing ~~monitoring.~~monitoring, was about $10.3 million. To date ~~$9.4~~we have paid $9.3 million ~~has been spent for~~on work related to the removal of the tar ~~deposit.~~deposit with a remaining liability estimate of $1.0 million.

Central Gas Storage Tanks.~~On Sept. 22,~~In September 2006, we received notice from the ODEQ that our Central Service Center ~~has been~~in southeast Portland (the Central Service Center site) was assigned a high priority for further environmental investigation. Previously there were three manufactured gas storage tanks on the premises. The ODEQ believes there could be site contamination associated with releases of condensate from stored manufactured gas, or through historic gas handling practices. In the early 1990s, we excavated waste piles and much of the contaminated

surface soils and removed accessible waste from some of the abandoned piping. ~~A negligible~~We initially recorded a small accrual ~~was recorded~~ in September 2006 for the ODEQ site assessment and legal and technical costs to investigate and determine the appropriate action needed to be taken, if any. In early 2007, we received notice that the site has been added to the ODEQ’s list of sites where releases of hazardous substances have been confirmed and its list where additional investigation or cleanup is necessary. Additional costs are not currently estimable. We ~~intend to seek~~received regulatory authorization from the OPUC for the deferral of environmental costs related to this site (see “Regulatory and Insurance Recovery for Environmental Matters,” below).

Regulatory and Insurance Recovery for Environmental Matters. In May 2003, the ~~Oregon Public Utility Commission (OPUC)~~OPUC approved our request for deferral of environmental costs associated with specific sites, including the Gasco, Siltronic and Portland Harbor sites. The authorization, which ~~has been~~was extended through January ~~2007,~~2008 and expanded to include the Oregon Steel Mills site (discussed below) and the Central Service Center site (discussed above), allows us to defer and seek recovery of unreimbursed environmental costs in a future general rate case. ~~In April~~Beginning in 2006, the OPUC authorized us to accrue interest on deferred balances, ~~effective Jan. 27, 2006,~~ subject to an annual demonstration ~~to the OPUC~~ that we have maximized our insurance recovery or made substantial progress in securing insurance recovery for unrecovered environmental expenses. ~~As of Sept. 30, 2006, we have paid a cumulative total of $17.1 million relating to the covered sites since the effective date of the deferral authorization.~~

On a cumulative basis, we have recognized a total of ~~$27.7~~$33.2 million for environmental costs, including legal, investigation, monitoring and remediation costs. Of this total, ~~$22.0~~$26.8 million has been spent ~~to-date~~to date and ~~$5.7~~$6.4 million is reported as an outstanding liability. ~~During the third quarter~~At March 31, 2007, we had a regulatory asset of ~~2006, we increased regulatory assets by $1.1~~$28.3 million, which includes $21.9 million for paid expenditures and interest plus $6.4 million for additional environmental ~~cost estimates related~~accruals expected to sites authorized for deferral treatment, and at Sept. 30, 2006 we had a total environmental regulatory asset of $22.8 million, which includes $17.1 million of total expenditures to date and additional accruals of $5.7 million.be paid in the future. We believe the recovery of these ~~costs~~deferred charges is probable through the regulatory ~~process after first pursuing recovery of costs from insurance.~~process. We also have an insurance receivable of $1.1 million, which is not included in the regulatory asset amount. We intend to pursue recovery of ~~these~~this insurance receivable and environmental ~~costs~~regulatory deferrals from our general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. We consider insurance recovery of some portion of our environmental costs probable based on a combination of factors, including a review of the terms of our insurance policies, the financial condition of the insurance companies providing coverage, a review of successful claims filed by other utilities with similar gas manufacturing facilities, and Oregon ~~law, which~~legislation that allows an insured party to seek recovery of “all sums” from one insurance company. We have ~~notified~~initiated settlement discussions with a majority of our insurers but continue to anticipate that our overall insurance recovery effort will extend over several years.

The following table summarizes the ~~insurance companies but have not yet filed claims for recovery, nor have the insurance companies approved or denied coverage of these claims.~~regulatory assets and accrued liabilities relating to environmental matters at March 31, 2007 and 2006 and December 31, 2006:

We are subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings, including the matters described below, ~~and in Part II, Item 8., Note 12, in the 2005 Form 10-K,~~ cannot be predicted with certainty, we do not expect that the ultimate disposition of these matters will ~~have a material adverse effect on our financial condition, results of operations or cash flows.~~

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

On Feb. 23, 2006, we filed a motion for summary judgment on all claims. On June 30, 2006, an order was issued by the U.S. District Court for the District of Oregon dismissing the lawsuit with prejudice and denying all pending motions, if any, as moot. On July 27, 2006, Georgia-Pacific appealed this ruling to the Ninth Circuit Court of Appeals. We do not expect the outcome of this appeal to have a material adverse effect on our financial condition, results of operations or cash flows.

Independent Backhoe Operator Action.Since May 2004, five lawsuits have been filed against NW Natural by 11 independent backhoe operators who performed backhoe services for NW Natural under contract. These five lawsuits have been consolidated into one case, in which 10 plaintiffs remain (Law and Zuehlke, et. al. v. Northwest Natural Gas Co.,CV-04-728-KI, United States District Court, District of Oregon). Plaintiffs allege violation of the Fair Labor Standards Act for failure to pay overtime and also assert state wage and hour claims. Plaintiffs claim that they should have been considered “employees,” and seek overtime wages and interest in amounts to be determined, liquidated damages equal to the overtime award, civil penalties and attorneys’ fees and costs. Additionally, ~~with one exception,~~ plaintiffs ~~allege~~alleged that the failure to classify them as employees constituted a breach of contract ~~and a tort~~ under and with respect to certain employee benefits plans, programs and agreements. ~~With the one exception, plaintiffs seek~~Plaintiffs sought an unspecified amount of damages for the value of what they would have received under these employee benefit plans if they had been classified as employees. ~~We expect that~~In May 2007, the ~~remaining plaintiff will amend his complaint to include~~District Court granted our motion for Summary Judgment on plaintiffs’ breach of contract and ~~tort~~benefits claims. The ruling leaves only the overtime and wage and hour claims ~~for unspecified damages.~~

~~In October 2005,~~in the ~~court granted NW Natural’s motion to stay plaintiffs’ claims pending exhaustion~~case. Our estimate of the administrative review process with regard to each of the plans under which plaintiffs allege that they would have been eligible to receive benefits. The litigation is still stayed pending plaintiffs’ exhaustion of the administrative review process. There is insufficient information at this time to reasonably estimate the range ofremaining liability, if any, ~~from these claims.~~is not material. We ~~will continue to vigorously contest these claims and~~therefore do not expect ~~that~~ the outcome of this litigation ~~will~~to have a material adverse effect on our financial condition, results of operations or cash flows.

Oregon Steel Mills site. In 2004, ~~we were~~NW Natural was served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case,Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by NW

~~Natural’s~~our predecessor, Portland Gas & Coke Company, and ~~ten~~10 other third-party defendants were disposed of in a waste oil ~~in a~~ disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The Port’s complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. In March 2005, motions to dismiss by ~~NW Natural~~ourselves and other third-party defendants were denied on the basis that the failure of the Port to plead and prove that we were in violation of law was an affirmative defense that may be asserted at trial, but did not provide a sufficient basis for dismissal of the Port’s claim. No date has been set for trial and discovery is ongoing. We received regulatory authorization from the OPUC for the deferral of environmental costs related to this site (see “Regulatory and Insurance Recovery for Environmental Matters,” above). We do not expect that the ultimate disposition of this matter will have a material adverse effect on our financial condition, results of operations or cash flows.

~~Pipeline Safety Inspection.~~On Sept. 22, 2006, the Washington Utilities and Transportation Commission (WUTC) issued a Standard Natural Gas Pipeline Safety Inspection report on our facilities in Clark County, Washington. Based on the findings of the inspection report and regulatory action taken with other gas distribution companies, enforcement action is expected. We are in the process of taking corrective action and do not expect the impact of this action to have a material adverse effect on our financial condition, results of operations or cash flows.

~~For the three and nine months ended Sept. 30, 2006 and 2005, reported net income was equivalent to total comprehensive income.~~ Items that are excluded from net income and charged directly to common stock equity are included in accumulated other comprehensive income (loss), net of tax. The amount of accumulated other comprehensive loss in total common stock equity is ~~$1.9~~$2.3 million at ~~Sept. 30, 2006,~~March 31, 2007, which is related to ~~our minimum pension liability (see “Consolidated Statements~~employee benefit plan liabilities. The following table provides a reconciliation of ~~Capitalization,” above).~~net income to total comprehensive income for the three months ended March 31, 2007 and 2006.

Northwest Natural Gas Company (NW Natural) is a natural gas services company primarily engaged in the distribution of natural gas to residential, commercial and industrial customers, operating as a regulated utility business in Oregon and southwest Washington. The utility is our largest business segment with approximately 98 percent of consolidated total assets. Factors critical to the success of the utility include maintaining a safe and reliable distribution system, acquiring and distributing natural gas supplies and services at a competitive price, and being able to recover the operating and capital costs in the rates charged to customers.

We are also engaged in the delivery of interstate and intrastate gas storage services, operating as a non-utility business segment with the interstate service subject to Federal Energy Regulatory Commission (FERC) regulation. This segment, which represents approximately 2 percent of consolidated total assets, provides services to large customers using Mist storage and our transportation capacity. Asset optimization transactions are also entered into pursuant to an agreement with an independent energy marketing company. Factors critical to the ongoing success of this segment include being able to develop additional storage capacity in advance of core utility customers’ requirements at competitive market prices and being able to continue to optimize the value of our assets, with both storage and optimization being subject to state regulatory sharing agreements.

In addition to the utility and interstate gas storage business segments, the consolidated financial statements include the accounts of a wholly-owned subsidiary business, NNG Financial Corporation (Financial Corporation), and other non-regulated business activities, which together are referred to in this report as our Other business segment (see Note 7).

The following is management’s assessment of ~~our~~Northwest Natural Gas Company’s financial condition, including the principal factors that affect ~~our~~ results of operations. The discussion refers to our consolidated activities for the three ~~and nine~~ months ended ~~Sept. 30, 2006~~March 31, 2007 and ~~2005.~~2006. Unless otherwise indicated, references in this discussion to “Notes” are to the ~~notes~~Notes to ~~the~~Consolidated Financial Statements in this report.

The consolidated financial statements ininclude the accounts of Northwest Natural Gas Company, which principally consists of our regulated local gas distribution business, our regulated gas storage business, and our other non-regulated businesses, which includes our wholly-owned subsidiary business, NNG Financial Corporation (Financial Corporation). In this ~~report.~~ report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage business segment (gas storage) and our other non-regulated activities (other) (see Note 8).

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

In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. We believe this per share information is useful because it enables readers to better understand the impact of these factors on earnings. All references in this section to earnings per share ~~in this report~~ are on the basis of diluted shares ~~except where noted otherwise~~ (see Part II, Item 8., Note 1, “Earnings Per Share,” in the ~~2005~~2006 Form 10-K).

Our strategy in 2007 is to remain focused on profitably growing our regulated gas utility and gas storage businesses. The gas utility is our largest business segment with approximately 98 percent of consolidated total assets, which contributed 90 percent of consolidated net income in 2006. Factors critical to the success of the utility include maintaining a safe and reliable distribution system, acquiring an adequate supply of gas, providing distribution services at a competitive price, and being able to recover the operating and capital costs of the utility in the rates charged to customers. The utility is regulated by two state commissions, the Oregon Public Utility Commission (OPUC) and the Washington Utilities and Transportation Commission (WUTC).

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

Net income increased 17 percent during the first quarter of 2007 compared to the same period in 2006, from $41.0 million to $48.1 million;

Solid growth in net operating revenues from our regulated utility and gas storage businesses were major drivers to increased earnings in the first quarter of 2007, with an 11 percent increase in net operating revenues at both our utility and gas storage;

Operations and maintenance expense increased 2 percent in the first quarter of 2007, including incremental costs for seasonal employees and employee bonus accruals tied to improved financial results, which were largely offset by cost reductions from business process redesign initiatives that we began implementing in 2006;

Cash flow from operations increased 47 percent to $149.8 million, reflecting stronger operating results and an increase in cash flows from lower gas costs; and

Total debt decreased by $114.6 million in the first quarter of 2007, reflecting a $20 million redemption of long-term debt at maturity and a $94.6 million decrease in notes payable.

There are a number of issues and challenges that ~~directly~~ affect our ~~consolidated~~operations and financial ~~condition and results of operations.~~performance. The most significant challenge we face in the near term iscontinues to be managing the ~~impact~~utility business in a period of ~~volatile~~high gas ~~prices.~~prices, increased demand and increased market volatility. Our gas acquisition ~~policy and~~ strategy has been to secure sufficient supplies of natural gas to meet the needs of our utility’s firm customers, but equally important is our strategy to hedge gas prices for a significant portion of ~~the utility’s~~our annual purchase requirements based onupon the market outlook and ~~the~~our core utility’s load forecast. ~~We generally manage~~In 2005, we hedged about 90 percent of our winter supplies prior to when the hurricanes hit, which helped us avoid much of the spike in gas prices ~~using~~that fall and winter. In 2006, we hedged at a ~~combination of hedge strategies, including:~~

~~negotiating fixed prices directly with gas suppliers;~~

~~negotiating financial derivative instruments to swap from floating prices in physical supply contracts into fixed prices, or to cap the maximum ceiling prices with option contracts;~~lower level, and

~~purchasing and injecting physical supplies into storage to be withdrawn during peak-demand winter months or to reduce~~ as spot ~~purchase requirements when~~ gas prices ~~are~~fell later in the year we were able to take advantage of the lower gas costs, resulting in commodity savings shared by our utility customers and shareholders. Currently, we expect energy prices to remain slightly higher ~~during periods when market conditions are volatile.~~

~~The majority of~~than in the past few years, with higher gas prices already reflected in our ~~gas supplies come from Alberta and British Columbia, while~~customers’ bills for the ~~remainder comes from the U.S. Rocky Mountain region.~~current Purchased Gas Adjustment (PGA) period which extends through October 2007. We believe we have sufficient supplies of natural gas under contract to meet the needs of our firm customers, but ~~future~~further price increases could change our ~~competitive advantage~~earnings outlook and our ~~customers’ preference for natural gas. Higher~~competitive advantage. If high gas prices persist, it could significantly affect our ability to add residential and commercial customers and could result in industrial customers shifting their businesses’ energy needs to alternative fuel sources.

~~Other~~ To address these competitive issues, we are continually developing new gas acquisition strategies to manage gas prices and ~~challenges~~meet market demands, and we ~~could face in~~are working on initiatives intended to improve operational efficiencies throughout the ~~future include unpredictable weather conditions, adverse regulatory actions or policy changes, managing gas supplies, storage and transportation capacity, managing customer growth, maintaining~~company through a ~~competitive advantage and managing environmental, interest rate and credit risks~~comprehensive business process redesign effort (see Part II, Item 7., ~~“Issues,~~“Executive Summary—Issues, Challenges and Performance Measures,” ~~Part I, Item 1A., “Risk Factors,”~~ in the ~~2005~~2006 Form ~~10-K and Part II, Item 1A., “Risk Factors,” below)~~10-K).

To address some of the challenges, we recently initiated a company-wide restructuring of operations with the goal of significantly improving work processes, reducing operating expenses and capital costs and continuing to strive for excellence in customer service. Our focus has been on developing initiatives to achieve long-term strategic targets. The new operations model is expected to be implemented over the next several years and to include workforce reductions. These reductions are expected to be accomplished by primarily focusing on a combination of normal attrition and voluntary severance packages. We expect to incur costs of approximately $1.5 million to $2.0 million in the fourth quarter of 2006 related to a workforce reduction of an estimated 50-100 people, which we expect to be largely offset this year by a combination of cost reductions and gains from non-core asset sales.

Business Process Redesign. During 2006, we initiated a project to evaluate our business processes and costs against our peers and to redesign those processes where long-term efficiencies could be gained. We identified a number of areas where we could restructure our business to gain efficiencies, including more centralization, an increased focus on process orientation, and more standardized processes. As an example, in 2007 we will be developing the first phase of a new enterprise resource planning system to support our new business processes in a more standardized and automated environment. For more information regarding our redesign efforts, see Part II, Item 7., “Strategic Opportunities,” in the 2006 Form 10-K.

Pipeline Diversity.In September 2006, we announced that we ~~are~~were evaluating making an investment in a potential pipeline project that would connect TransCanada’s Gas Transmission Northwest (GTN) interstate transmission line to our local gas distribution system. We ~~have commenced a process~~are continuing to ~~determine if there is sufficient interest by potential customers to justify construction of the pipeline. If~~evaluate the project, ~~is determined to be viable, we would form~~and a partnership with GTN to build and own the pipeline. We would anticipate being a large customer of the proposed pipeline and GTN would be its operator. The pipeline would be intended to provide our utility and GTN’s customers with a source for more diversified delivery of gas supplies from the interstate system and enhance reliability. The decision on whether to proceed with the development planning and permitting of the

pipeline is expected to be made ~~in early 2007.~~later this year. No material contractual obligations related to the pipeline have been incurred as of ~~Sept. 30, 2006.~~March 31, 2007. If constructed, we expect commercial operation ~~could~~of the pipeline to commence byin 2011.

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

Our most critical estimates or judgments involve regulatory cost recovery, ~~unbilled revenues,~~revenue recognition, derivative instruments, pension assumptions, income taxes and environmental ~~and other~~

contingencies (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates,” in the ~~2005~~2006 Form 10-K). There have been no material changes to the information provided in ~~our 2005~~the 2006 Form 10-K with respect to the application of critical accounting policies and estimates. Management has discussed ~~its~~the estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board.

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

Net income was $48.1 million, or $1.76 a share, for the three months ended ~~Sept. 30, 2006 was a loss of $9.7~~March 31, 2007, compared to $41.0 million, or ~~35 cents per~~$1.48 a share, ~~compared to a loss of $8.7 million, or 31 cents per share, in~~for the same period ~~in 2005. The loss was primarily due to results from our utility segment, which contributed a loss~~last year.

First quarter of ~~$11.4 million, or 41 cents per share, to the 2006 third quarter results,~~2007 compared to ~~a loss of $10.5 million, or 38 cents per share in 2005. Net income from utility operations is typically a loss during the third quarter due~~2006:

Positive factors contributing to ~~the reduced use of natural gas in the summer. Interstate gas storage operations contributed $1.5 million to~~increased earnings in the third quarter of 2006, or 5 cents per share, compared to $1.6 million, or 6 cents per share, in the same period in 2005. Other non-utility business activities resulted in net income for the quarter of $0.2 million, or 1 cent per share, in both 2006 and in 2005.

~~Primary factors affecting third quarter earnings this year over last year include:~~were:

~~an increase in~~

increased utility ~~margin~~volumes and net operating revenues (margin) from sales to residential and commercial customers ~~of $0.8 million, primarily resulting from annual~~due to 2.8 percent customer growth, plus weather that was 2 percent colder than the first quarter of ~~3.4 percent, or 20,722 customers, largely offset by the change~~2006 (see “Results of Operations—Comparison of Gas Distribution Operations,” below);

increased margin from regulatory sharing of gas cost savings, from $1.8 million in the ~~regulatory decoupling deferral~~first quarter of 2006 to $9.8 million in 2007, and a $2.7 million gain from the reversal of a temporary loss taken in the fourth quarter of 2006 related to derivative contracts that settle in 2007; and

decreased interest costs due to ~~higher than expected average use per customer;~~lower short-term debt balances.

~~a decrease in utility margin from industrial customers of $0.4 million due to a few large customers switching to lower margin schedules;~~

an increase in actual line loss expense of $0.4 million, which is included in cost of gas, plus a decrease in the recovery of line loss expense in rates of $0.3 million, which is reflected in lower revenues, both of which are reflected in utility margin; and

~~increases in~~increased depreciation ~~expense of $0.7 million and interest charges of $0.5 million~~expenses related to ~~the increased capital costs of serving a growing customer base,~~higher utility plant in service, which were partially offset by ~~decreases~~revenue increases related to cost recovery of pipeline integrity and bare steel capital expenditures that are tracked into rates on an annual basis through the PGA filings in ~~operations~~Oregon; and ~~maintenance expense of $0.3 million and general taxes of $0.3 million.~~

For the nine months ended Sept. 30, 2006, net income increased 3 percent to $33.3 million, or $1.20 per share, compared to $32.4 million, or $1.17 per share, in the same period in 2005. Our utility operations contributed $28.2 million, or $1.02 per share, to earnings in the first nine months of 2006, compared to $28.4 million, or $1.03 per share, in 2005. Interstate gas storage operations contributed $4.8 million in the current period, or 17 cents per share, compared to $3.3 million, or 12 cents per share, in 2005. Other non-utility activities resulted in net income of $0.3 million, or 1 cent per share, compared to net income of $0.7 million, or 2 cents per share, in 2005.

~~Primary factors affecting year-to-date earnings this year over last year include:~~

an increase in utility margin from residential and commercial customers of $11.6 million, or 7 percent, primarily resulting from customer growth and higher average use per customer, partially offset by the regulatory decoupling deferral;

a decrease in utility margin from industrial customers of $0.7 million, or 3 percent, primarily due to a combination of customers switching to lower margin schedules and a $0.2 million net loss from a temporary mark-to-market contract adjustment;

~~an increase in utility margin of $1.9 million from higher gas purchase cost savings under the regulatory Purchased Gas Adjustment (PGA) incentive mechanism;~~

~~an increase in interstate gas storage margin of $2.9 million, or 40 percent, reflecting stronger demand for storage services and~~ increased ~~optimization activities; and~~

~~an increase in total operating expenses of $5.0 million, or 3 percent, reflecting a combination of higher payroll and employee benefit costs~~income tax expense related to ~~wage increases and bonuses,~~ higher ~~depreciation and general tax expenses related to customer growth and investment in plant assets, and higher bad debt expenses related to increased gas revenues.~~taxable income.

Dividends paid on our common stock were 35.5 cents a share and 34.5 cents ~~and 32.5 cents per~~a share in the ~~three-month~~three month periods ended ~~Sept. 30,~~March 31, 2007 and 2006, ~~and 2005, respectively, and $1.035 and $0.975 per share in the nine-month periods ended Sept. 30, 2006 and 2005,~~ respectively. In ~~October 2006,~~April 2007, the Board of Directors declared a quarterly dividend on our common stock ~~dividend rate was increased by 3 percent to~~of 35.5 cents per share payable ~~Nov.~~May 15, ~~2006~~2007 to shareholders of record on ~~Oct. 31, 2006.~~April 30, 2007. The current indicated annual dividend rate is $1.42 per share.

We ~~provide gas utility service in Oregon~~are subject to regulation with respect to, among other matters, rates, systems of accounts and ~~Washington, with Oregon representing over~~issuance of securities by the OPUC and the WUTC. Typically, about 90 percent of our utility ~~revenues.~~gas deliveries and operating revenues are derived from Oregon customers and the balance from Washington customers. Future earnings and cash flows from utility operations will be determined largely by ~~among other factors,~~the pace of continued growth in the residential and commercial markets and by our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory ~~treatment~~recovery for our utility gas costs, operating ~~expenses~~and maintenance costs and investments made in utility ~~plant (see~~plant. See Part II, Item 7., “Results of ~~Operations–~~ Operations—Regulatory Matters,” in the ~~2005~~2006 Form 10-K.

At March 31, 2007 and 2006, the amounts deferred as regulatory assets and liabilities were as follows:

Purchased Gas Adjustment.Rate changes are applied each year under the PGA tariff mechanisms in Oregon and Washington to reflect changes in the ~~costs~~expected cost of natural gas commodity ~~purchased under contracts~~purchases, including contractual arrangements to hedge the purchase price with ~~gas producers,~~financial derivatives (see

“Comparison of Gas Distribution Operations—Cost of Gas Sold,” below), interstate pipeline demand charges, the application of temporary rate adjustments to amortize balances in deferred regulatory accounts and the removal of temporary rate adjustments effective for the previous year. The Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC) approved rate increases on Oct. 25, 2006 that became effective on November 1, compared to October 1 in the prior year. The effect of the rate change is to increase the average monthly bills of Oregon residential sales customers by 3.5 percent and those of Washington residential customers by 3.0 percent.

Under the current PGA mechanisms, we collect an amount for purchased gas costs based on estimates included in rates. If the actual purchased gas costs ~~are higher than~~differ from the estimated amounts included in rates, then we are required to defer ~~a predetermined percentage of the higher costs~~that difference and ~~collect them in future rates. Similarly, when the actual purchased gas costs are lower than the amounts included in rates, the gas cost savings are not immediately returned~~pass it on to customers ~~but a predetermined percentage is deferred and credited~~as an adjustment to ~~customers in~~ future ~~periods.~~rates. As part of an incentive mechanism in Oregon, only 67 percent of the difference is deferred such that the impact on current earnings is either a charge to expense for 33 percent of the higher cost of gas sold, or a credit to expense for 33 percent of the lower cost of gas sold. In Washington, the PGA deferral is 100 percent of the higher or lower actual cost of gas sold.

~~In October 2006, the~~The OPUC ~~approved~~is currently conducting a modification to our PGA tariff, effective Nov. 1, 2006, which provides that we will use actual recoveries of gas costs in revenues billed (instead of using estimated gas costs incorporated in rates) compared to actual purchased gas costs to determine our PGA deferral. The effectformal review of the ~~new method~~PGA process used by local distribution companies covering gas portfolio requirements, incentive sharing levels and filing requirements among other items. The investigation is expected to be completed in early 2008. Implementation of ~~using actual recoveries of gas costs in amounts billed will be that~~ any changes ~~in line loss expense due~~ to ~~increases or decreases in unaccounted for gas volumes will be covered by~~ the ~~annual~~ PGA mechanism ~~such that these increases and decreases will~~is expected to be reflected in the PGA deferral amounts, However, consistent with our prior PGA sharing mechanism, 67 percent of any cost of gas price differences for Oregon volumes will be deferred for refund or recovery in customer rates in subsequent periods,effective with the ~~remaining 33 percent being included in current earnings.~~

~~Also in October 2006, the OPUC’s annual formal review~~Excess Earnings Test. The OPUC has a formalized process to test for excess utility earnings was disconnected from our annual PGA filings, so that our ability to pass through 100 percent of prudently incurred gas costs into rates would not be dependent upon a determination of any excess earnings.annually. We ~~will continue to be subject to the same excess earnings test requirement as before, in which we~~ are ~~allowed~~authorized to retain all of our earnings up to a threshold level equal to our authorized return on equity of 10.2 percent plus 300 basis points. ~~Revenues equivalent to 33 percent~~One-third of any earnings above ~~the threshold are required to~~that level will be refunded to customers. The excess earnings threshold is subject to adjustment up or down each year ~~based~~depending on movements in long-term interest rates.

~~Weather Normalization and Conservation Tariffs~~. In ~~October~~ 2006, the ~~OPUC authorized~~threshold after adjustment was 13.44 percent. We do not expect that any amounts will be required to be refunded to customers as a ~~change in~~result of the ~~annual start date for applying the weather normalization adjustment to customer bills. Previously, the start date was November 15 of each year. Now, the mechanism~~2006 earnings test, which will ~~start on December 1 and end on May 15 of each heating season. Also in October 2006,~~be reviewed by the OPUC ~~authorized a change in~~during the ~~conservation tariff, which includes a decoupling mechanism designed~~second quarter of 2007. In Washington, we are not subject to ~~adjust margin revenues up or down to offset changes in average residential~~an annual excess earnings test and ~~commercial~~100 percent of all prudently incurred gas costs are passed through into customer usage due to conservation efforts. This change, in combination with the change in our weather normalization mechanism, effectively extends the period for full decoupling from June through November of each year. Previously, full decoupling was in effect only from June through September of each year. For the remaining months of each year the decoupling mechanism is in effect but is applied only after revenues are weather normalized. These changes to our weather normalization and conservation tariffs provide for greater mitigation of our risk exposures due to variations in weather and customer consumption patterns.rates.

~~Geo-hazard Program.~~Integrated Resource Planning ~~We entered into~~. The OPUC and WUTC have implemented integrated resource planning (IRP) processes under which utilities develop plans defining alternative growth scenarios and resource acquisition strategies. On March 28, 2007, we filed a ~~stipulation~~draft IRP with the WUTC and are required to file a final IRP with the OPUC in 2001 for an enhanced pipeline safety program that included an accelerated bare steel replacement program and a geo-hazard safety program. The geo-hazard safety program included the identification, assessment and remediation of risks to piping infrastructure created by landslides, washouts, earthquakes or similar occurrences. The stipulation allowed us to receive deferred accounting rate treatment for all costs associated with the geo-hazard program. Although the authority to defer expenses for costs associated with this geo-hazard program is scheduled to expire on Dec. 31, 2006, we received approval from the OPUC to defer up to $2.5 million in 2007 related to a specific project.

~~Industrial Tariffs.~~ In August 2006, the OPUC and WUTC approved tariff changes to the service options for our major industrial accounts. The changes set out additional parameters that give us more certainty in the level of gas supplies we will need to acquire to serve this customer group. The parameters include an annual election period, special pricing provisions for out-of-cycle changes and the requirement that customers on our annual weighted average cost of gas tariff complete the term of their service election.15, 2007.

On June 30, 2006, the two interstate pipeline companies that provide natural gas transportation to our distribution system filed for general rate ~~increase cases~~increases with ~~FERC. Northwest Pipeline Corporation (Northwest Pipeline) filed for an overall cost of service increase of approximately $119.0 million (a 41 percent increase), including an increase in~~ the firm transportation rate of approximately 45 percent. If approved as filed, our firm gas transportation rates would increase by approximately $17.8 million annually. The major components in the increase relate to a significant capacity replacement project, other capacity displacement projects, increased rate of return and operation and maintenance expenses, and costs associated with accounting changes to expense pipeline integrity assessment costs. FERC has accepted Northwest Pipeline’s revised tariff sheets to become effective on January 1, 2007, subject to refund pending the outcome of further proceedings in the case.

GTN’s rate case proposes, among other things, an approximately 71 percent increase in firm transportation rates. If approved as filed, our transportation rates on that pipeline would increase by approximately $3.1 million. The primary reason for GTN’s filing was unsubscribed capacity on the

system due to significant capacity turnback and shipper defaults. FERC has accepted and suspended the GTN rates and tariff sheets to become effective on January 1, 2007, subject to refund pending further proceedings in the case.

~~Increases~~Federal Energy Regulatory Commission (FERC). Changes in interstate pipeline transportation ~~expenses~~charges are subject to our PGA ~~deferral~~ mechanism and are 100 percent passed-through to customers in both Oregon and Washington. Both of the filed general rate increases were reflected in our 2006 PGA filings. In March 2007, FERC approved Northwest Pipeline’s settlement proposal, resulting in a lower than expected increase to our pipeline transportation rates. Amounts currently being collected from our customers in excess of this amount will be deferred and returned to customers, which will reduce gross revenues and costs of sales but will have no impact on our net results of operations. See Part II, Item 7., “Results of Operations—Regulatory Matters—Interstate Pipeline Rate Cases,” in the 2006 Form 10-K.

~~During 2005,~~Under Oregon regulatory law, we are required to file a report in October each year that calculates the ~~Oregon legislature passed Senate Bill (SB) 408 relating~~difference between the amount of income taxes paid to governmental entities compared to the amount of taxes we collected ~~by utilities~~ in rates ~~on or after Jan. 1, 2006. This legislation requires~~in the ~~OPUC to establish an annual tax adjustment to ensure that Oregon utilities do not collect in rates~~previous year. For more ~~income taxes than they actually pay to government entities (see Part I, Item 1., “Regulation and Rates—Utility Regulation Legislation,” Part 1A., “Risk Factors,” and~~information regarding this requirement, see Part II, Item 7., “Results of Operations—Regulatory Matters—Utility Regulation Legislation,” in the ~~2005~~2006 Form ~~10-K). In September 2006,~~10-K.

Based on our assessment of the ~~OPUC approved final~~ rules ~~required~~developed to implement ~~SB 408. In October,~~the law, we ~~filed a required informational tax report comparing “taxes paid” to “authorized to collect in rates”~~estimate that our 2007 Tax Report for the ~~fiscal years 2003, 2004 and 2005. Based on~~2006 tax year will reflect a surcharge of about $1.6 million; that is, the ~~calculations required by the final rules, our “taxes paid” exceeded~~amount of income taxes paid to government entities will exceed the amount of taxes the utility collected in rates, thus creating a rate adjustment that requires a reimbursement from customers. It is anticipated that any

amounts due from customers for the 2006 tax year would not be realized until after June 1, 2008, pending a review by the OPUC. We have estimated that our 2008 Tax Report for the 2007 tax year will also reflect a surcharge. Based on results through March 31, 2007, we ~~were “authorized~~estimate the surcharge related to ~~collect in rates” by $0.6 million in 2003, $1.2 million in 2004 and $3.0 million in 2005. Because~~our first quarter to be about $2.8 million. We have determined that the recognition of this regulatory surcharge is uncertain because the OPUC has not completed its review of how the final rules ~~only apply to taxes collected on or after Jan. 1, 2006, there~~ will be ~~no adjustment~~applied to our ~~rates as~~2006 and 2007 financial results, our request for a ~~result of this informational tax report. Although~~Private Letter Ruling from the Internal Revenue Service is not complete and there are ongoing efforts in the current Oregon legislative session that could potentially change certain ~~aspects~~provisions of the ~~final rules related~~law. Due to ~~federal income tax rules are yet to be determined, we expect to file our tax report for~~ the ~~calendar year~~regulatory uncertainty, recovery in rates of the 2006 ~~in October~~and estimated 2007 ~~with any adjustment expected to occur in the second quarter of 2008. Based on~~surcharge is not considered probable at this time and these amounts have been reserved. Given our current corporate structure and level of non-utility investments and activities, we ~~do not~~ expect that ongoing compliance with ~~SB 408 to~~this law, as currently interpreted, will not have a material adverse effect on our financial condition, results of operations or cash flows.

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

The total cost of gas sold was $245.5 million in the first quarter of 2007, a decrease of $9.9 million or 4 percent compared to ~~Sept. 30, 2005:~~the first quarter of 2006. The cost per therm of gas sold includes current gas purchases, gas drawn from storage inventory, gains and losses from commodity hedges, margin from off-system gas sales, pipeline demand charges, seasonal demand cost balancing adjustments, regulatory gas cost deferrals and company gas use.

~~Other revenues~~Under the PGA tariff in the nine months ended Sept. 30, 2006 were $6.4 million lower than in the nine months ended Sept. 30, 2005 primarily due to a $5.4 million change in current decoupling deferral, a $2.9 million change in the amortization of decoupling deferral balances and a $0.8 million change in the amortization of Coos Bay distribution system deferrals, partially offsetOregon, our net income is affected by a ~~$1.3 million change~~sharing mechanism based on increases or decreases in ~~interstate~~purchased gas ~~storage credits and a $1.7 million change~~costs as compared to estimated gas costs included in ~~amortization expense related to deferrals for the South Mist pipeline extension~~customer rates (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate ~~Mechanisms,~~Mechanisms—Purchased Gas Adjustment,” in the ~~2005~~2006 Form ~~10-K for further discussion of regulatory revenue adjustments)~~10-K).

Although natural gas commodity prices have increased significantly over the last few years, prices have begun to decline recently, allowing more opportunity to purchase lower-priced spot market gas. During the third quarter and In the first ~~nine months~~quarter of ~~2006, the cost per therm~~2007, our share of gas ~~sold was~~

~~33 percent~~cost savings contributed $9.8 million to margin, compared to net savings and ~~28 percent higher, respectively, than~~a contribution to margin of $1.8 million in the comparable ~~2005 periods.~~2006 period. The net benefit to utility customers from aggregate gas cost ~~per therm of gas sold primarily includes current gas purchases, gas withdrawn from storage inventory and net gains and losses from financial commodity hedge contracts. Prior~~savings amounted to the last heating season, we locked in gas prices for approximately 90 percent of our commodity purchases before the disruptions caused by hurricanes Katrina and Rita, thereby avoiding a significant amount of the run-up in gas prices last fall and winter. Our rate increases last fall were much lower than those in other regions of the country due to our significant hedge position, but gas prices overall were still higher than in prior years, which accounted$21.7 million for the ~~higher cost per therm of gas sold this year as compared to last year.~~three months ended March 31, 2007.

We use a natural gas commodity-price hedge program under the terms of our Financial Derivatives Policy to help manage our ~~variable~~exposure to floating price ~~risk on~~ gas ~~purchases. During~~purchase contracts (see Part II, Item 7., “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” in the ~~three months ended Sept. 30,~~ 2006 ~~we recorded a~~Form 10-K, and Note 7, above). We realized net ~~loss~~losses of $7.6 million from our financial ~~hedge contracts~~hedges in the first quarter of ~~$12.4 million,~~2007, compared to ~~a net gain~~gains of ~~$20.5~~$17.5 million ~~during~~in the same period ~~in 2005. During~~of 2006. Gains and losses from the ~~nine months ended Sept. 30, 2006, we recorded a net loss~~financial hedging of $5.4 million from hedge contracts compared a gain of $30.3 million during the same period in 2005. Because our financial hedge contracts are directly related to variable-price risks in physical supply contracts which are included in PGA deferrals and annual regulatory rate changes, the resulting gains and lossesutility gas purchases generally are included in cost of gas, ~~as an offset to the higher or lower actual physical gas purchase costs. For the most part, financial hedge contract gains and losses~~which are factored into our PGA deferrals and annual rate changes, but to the extent that any utility gas hedge is entered into after the annual PGA ~~adjustment~~filing, then the gains and ~~have no material impact on net income.~~

Under our PGA tariff in Oregon, if the cost of gas purchased is higher or lower than the cost embedded in rates, net income is charged or credited for 33 percent of the difference and the remaining 67 percent is deferred for pass through to customers in future rates. Our gas purchases in the third quarter of 2006 were slightly lower than the costs embedded in rates, and our share of the lower costs increased margin by $0.2 million. For the third quarter of 2005, our gas costs were also lower than the gas costs embedded in rates, and our share of the lower costs increased margin by $0.2 million. In the first nine months of 2006, our share of gas cost savings contributed $3.7 million to margin, compared to net savings and a contribution to margin of $1.9 million in the comparable 2005 period. The net benefit to customers from these gas cost savings amounted to $0.3 million and $7.4 million for the three and nine months ended Sept. 30, 2006, respectively.

Based on our ongoing assessment of gas prices and market risks, we began moderating our hedge position earlier this year as compared to prior years. Typically, by the time we file for our annual PGA rate change, we have a high percentage of the next gas contract year’s estimated gas purchase requirements hedged. However, this year we went into the PGA with a lower than normal but still significant percentage of gas purchases hedged based on market conditions and gas price outlook. As gas prices began to decline in late August and early September, we increased our hedge positions, adding both to our storage levels with spot gas purchases and to our fixed-price financial swap portfolio to lock in gas prices on forward purchases. Our current overall hedge position for the upcoming gas contract year is below where we have been hedged over the past few years, and this may subject us to greater purchased gas cost variability in the future as compared to previous years (see Part II, Item 1A., “Risk Factors,” below). Variations in gas costslosses are subject to our PGA ~~mechanisms~~incentive sharing mechanism with 67 percent deferred and 33 percent recorded to current income. We recorded a $2.7 million credit to the cost of gas in the first quarter of 2007 related to the reversal of an unrealized loss on financial derivative contracts that were entered into during the fourth quarter of 2006, which was after the 2006 PGA filing (see ~~“Results~~Part II, Item 7., “Application of ~~Operations—Rate Mechanisms,~~Critical

Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” ~~above)~~in the 2006 Form 10-K). The fourth quarter 2006 temporary loss was largely reversed in the first quarter of 2007 as a majority of these derivative contracts settled.

Net income from our ~~interstate~~ gas storage business segment in the three ~~and nine~~ months ended ~~Sept. 30, 2006~~March 31, 2007 was ~~$1.5~~$1.8 million ~~and $4.8 million, respectively,~~ after regulatory sharing and income taxes, or ~~5 cents and 17~~7 cents per share, ~~respectively. This compares~~compared to net income of ~~$1.6~~$1.4 million, or ~~6 cents per share, and $3.3 million, or 12~~5 cents per share, in the three ~~and nine~~ months ended ~~Sept. 30, 2005, respectively. The~~March 31, 2006. This increase ~~in the nine month results~~ was primarily due to ~~interstate~~increased firm storage ~~capacity added during mid-year 2005~~services revenues and an increase in revenues from our asset optimization arrangement with an

~~unaffiliated~~ independent energy marketing company (see Part II, Item 7., “Results of Operations—Business Segments Other Than Local Gas Distribution—~~Interstate~~ Gas Storage,” in the ~~2005~~2006 Form 10-K). The segment also began providing intrastate services in February 2006. The total working gas capacity of the Mist underground gas storage facility has been revised from 13.9 Bcf to 14.0 Bcf to reflect reservoir performance and incremental growth in certain reservoir pools.

Third-party optimization is provided pursuant to a contract with an ~~unaffiliated~~independent energy marketing company, which assists in the optimization of the value of our assets primarily through the use of commodity transactions. In Oregon, we retain 80 percent of the pre-tax income from interstate storage services and optimization activities when the costs of the capacity used have not been included in utility rates, or 33 percent of the pre-tax income from such optimization when the capacity costs have been included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for crediting to our core utility customers. We have a similar sharing mechanism in Washington for pre-tax income derived from interstate storage services and third-party optimization.

The other business segment primarily consists of a wholly-owned subsidiary, Financial Corporation, as well as various other non-utility investments, including an investment in a leveraged aircraft lease (see Part II, Item 8., Note 2, “Consolidated Subsidiary Operations and Segment Information,” in the ~~2005~~2006 Form 10-K). Operating results from this segment for ~~both~~ the three months ended ~~Sept. 30, 2006 and 2005~~March 31, 2007 were net income of $0.2 ~~million. For~~million, compared to $0.1 million for the ~~nine~~three months ended ~~Sept. 30, 2006 and 2005 net income was $0.3 million and $0.7 million, respectively.~~March 31, 2006.

Our net investment ~~balances~~balance in Financial Corporation at ~~Sept. 30,~~March 31, 2007 and 2006 was $2.7 million and ~~2005 were $2.7 and $3.2~~$3.6 million, respectively. The ~~$0.5~~$0.9 million decrease primarily reflects lower cash investments due to a cash dividend paid to NW Natural in the second quarter of 2006. Our net investment balance in the leveraged aircraft lease at ~~Sept. 30,~~March 31, 2007 and 2006 ~~and 2005~~ was ~~$7.2~~$4.7 million and ~~$6.9~~$7.0 million, respectively, with the ~~increase~~decrease primarily due to ~~recognition~~the receipt in March 2007 of ~~earned~~the final payment due under the terms of the lease ~~revenues.~~agreement.

Operations and maintenance expenses in the ~~third~~first quarter of ~~2006~~2007 were ~~$25.6~~$28.8 million, representing a ~~$0.3 million, or 1 percent, decrease over the third quarter of 2005. The following summarizes the major factors that contributed to the decrease in operations and maintenance expense:~~

~~a $0.3 million decrease in bad debt expense due to an improvement in delinquencies and bad debt recoveries;~~

~~a $0.8 million decrease in repair costs and damage claims relating to our utility mains and services;~~

~~offset, in part, by a $0.9 million increase in payroll-related expenses resulting from pay increases and higher benefit costs.~~

~~Operations and maintenance expenses in the first nine months of 2006 increased $1.6~~$0.6 million, or 2 percent, ~~compared to~~increase over the first ~~nine months~~quarter of ~~2005.~~2006. The following summarizes the major factors that contributed to the increase in operations and maintenance expense:

a ~~$1.5~~$0.5 million increase in ~~payroll-related expenses resulting from pay increases~~other contract work primarily due to seasonal staffing for the call center; and ~~higher benefit costs;~~

a ~~$0.6~~$0.5 million increase in ~~bad debt expense related to increases in gross revenues~~benefit expenses for non-qualified pension plan costs and ~~delinquencies resulting from higher natural gas prices;~~for stock-based compensation;

~~a $0.6 million increase in corporate development and planning expenses;~~

~~a $0.6 million increase in stock option expense due to the required adoption of a new accounting rule related to share-based compensation (see Notes 2 and 4);~~

offset, in part, by a ~~$0.7~~$0.4 million decrease in ~~injury and property damage claims; and~~

~~an $0.8 million decrease in repair costs and damage claims relating~~bad debt expense due to ~~our utility mains and services.~~improved collection results.

General taxes, which are principally comprised of property taxes, payroll taxes and regulatory fees, ~~decreased $0.3~~increased $0.2 million, or 53 percent, in the three months ended ~~Sept. 30, 2006~~March 31, 2007 over the same period in ~~2005, but~~2006. Regulatory fees increased ~~$1.3~~$0.2 million, or 711 percent, in the ~~nine months ended Sept. 30,~~first quarter of 2007 compared to the first quarter of 2006 over the same period in 2005. Property taxes increased $0.1 million, or 2 percent, and $0.7 million, or 6 percent, in the three- and nine-month periods ended Sept. 30, 2006, respectively, over the same periods in 2005, due to utility plant additions in 2006 and 2005. Regulatory fees increased $0.6 million in the nine months ended Sept. 30, 2006 over the same period in 2005, reflecting increased gross operating ~~revenues, but these fees decreased by $0.4 million~~revenues. The change in property and payroll taxes was negligible in the ~~three months ended Sept. 30, 2006 over~~first quarter of 2007 compared to the ~~same period in 2005 primarily due to timing differences between this year and last year.~~first quarter of 2006.

Depreciation and amortization expense increased by ~~$0.7~~$1.0 million, or ~~5 percent, and $2.0 million, or 4~~6 percent, in the ~~three- and nine-month periods~~three-month period ended ~~Sept. 30, 2006, respectively,~~March 31, 2007, compared to the same ~~periods~~period in ~~2005.~~2006. The increased expense reflects ongoing capital expenditures for utility plant that were made primarily to meet continuing customer growth and to upgrade operating facilities.

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

~~Other~~The negligible increase in other income and expense – net ~~was $0.2 million lower~~ in the ~~third~~first quarter of ~~2006~~2007 compared to the same period in ~~2005, and $0.2 million higher in the nine months ended Sept. 30,~~ 2006 ~~compared to the same period in 2005. The increase in the nine-month period~~ was primarily due to ~~realized~~interest on deferred regulatory accounts that were higher because of increases in deferred environmental costs, and a decrease in other non-operating expenses, largely offset by reduced life insurance benefits from company-owned policies and earnings from non-utility equity investments, which were partially offset by interest charges on net regulatory liability account balances, as compared to interest income on net regulatory asset balances last year, and lower interest income on a reduced level of temporary cash investments.policies.

Interest charges – net of amounts capitalized ~~increased $0.5~~decreased $0.3 million, or ~~6 percent, and $1.5 million, or 6~~3 percent, in the ~~three- and nine-month periods~~quarter ended ~~Sept. 30,~~March 31, 2007 compared to the same period in 2006, ~~and 2005, respectively,~~ primarily due to ~~higher~~lower balances of total debt outstanding ~~and higher interest rates on short-term debt borrowing.~~resulting from cash flows tied to gas cost savings.

Income tax expense totaled $28.5 million in the first quarter of 2007 compared to $23.4 million in the first quarter of 2006. The effective ~~corporate~~tax rate was 37.2 percent in the first quarter of 2007 compared to 36.4 percent in the first quarter of 2006. The higher income tax ~~rate on~~expense in 2007 is due primarily to pre-tax book income ~~from operations was 35.9 percent~~of $76.5 million compared to $64.5 million for the ~~nine-month~~same period ~~ended Sept. 30,~~in 2006, ~~compared~~resulting in higher income tax expenses. The increase in effective tax rate in 2007 was largely due to ~~35.7 percent for the nine-month period ended Sept. 30, 2005.~~a decrease in tax benefits from a $0.9 million decrease in non-taxable gains on life insurance.

Our goal is to maintain a target capital structure comprised of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt. When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources also are used to meet long-term debt redemption requirements and short-term commercial paper maturities (see “Liquidity and Capital ~~Resources”~~Resources,” below). ~~Our consolidated capital structure at Sept. 30, 2006 and 2005 and at Dec. 31, 2005, including short-term debt, was as follows:~~

The increase in the common stock equity percentage in September 2006 compared to December 2005 is primarily due to increased earnings and strong cash flows, which has reduced the need to issue debt to fund capital expenditures. 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. Our consolidated capital structure at March 31, 2007 and 2006 and at December 31, 2006, including short-term debt, was as follows:

The common stock equity percentages in March 2007 and March 2006 were higher as compared to December 2006 primarily due to seasonal earnings and cash flows that reduced the combined long-term and short-term debt percentages.

In April 2007, the Board ~~has approved a~~authorized an increase to the share repurchase program ~~for~~of our common stock, now aggregating up to 2.8 million shares, or up to $100 million in value, from the ~~repurchase~~previous authorized levels of up to 2.6 million shares or up to $85 million in ~~value, of our common stock.~~value. Purchases under this program are made in the open market or through privately negotiated transactions. Since the program’s inception in 2000, we have repurchased 812,700 shares of common stock at a total cost of $24.7 million, including 47,100 shares at a total cost of $1.6 million in the first nine months of 2006 (seeSee “Financing Activities,” and Part II, Item 2., “Unregistered Sales of Equity Securities and Use of Proceeds,” ~~below) . The Board also approved a 3 percent increase in the common stock dividend rate, from 34.5 cents to 35.5 cents per share, effective Nov. 15, 2006.~~below.

At ~~Sept. 30, 2006,~~March 31, 2007, we had ~~$5.7~~$5.1 million of cash and cash equivalents compared to ~~$3.4~~$7.5 million at ~~Sept. 30, 2005.~~March 31, 2006 and $5.8 million at December 31, 2006. 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 totaling $200 million

~~which~~ and are available through ~~Sept.~~September 30, 2010 (see “Lines of Credit,” below, and Part II, Item 8., Note 6, in the ~~2005~~2006 Form 10-K). Proceeds from the issuance of long-term debt are used to finance capital expenditures and refinance maturing short-term or long-term debt.

Neither our Mortgage and Deed of Trust nor the indenture under which 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 counterparties under our Financial Derivatives ~~Policy, which~~Policy. These agreements 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, we believe we have sufficient liquidity to satisfy our anticipated cash requirements, including the contractual obligations and investing and financing activities discussed below.

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

Since ~~Dec.~~December 31, ~~2005, we entered into~~2006, our estimated future contractual obligations have increased by about $10 million primarily due to contracts to outsource a ~~new contract in the amount~~portion of ~~$12.4 million~~our construction work, including mains and services and locating services as well as for ~~the purchase and installation of automated meter reading (AMR) equipment. Besides this contract and other contracts entered into~~consulting on our low income energy efficiency programs, which are all in the ordinary course of ~~business, there were no material changes to~~ our ~~estimated future contractual obligations during the nine months ended Sept. 30, 2006.~~business. Our contractual obligations at ~~Dec.~~December 31, ~~2005~~2006 are described in Part II, Item 7., “Financial Condition—Liquidity and Capital Resources—Contractual Obligations,” in the ~~2005~~2006 Form 10-K.

Our primary source of short-term funds is from the sale of commercial paper notes payable. In addition to issuing commercial paper to meet seasonal working capital requirements, including the financing of gas purchases and accounts receivable, short-term debt is used to temporarily fund capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by committed bank lines of credit (see “Lines of Credit,” below, and Part II, Item 8., Note 6, in the ~~2005~~2006 Form 10-K). We had ~~$103.3~~$5.5 million in commercial paper notes outstanding at ~~Sept. 30, 2006,~~March 31, 2007, compared to ~~$72.5~~$50.4 million outstanding at ~~Sept. 30, 2005~~March 31, 2006 and ~~$126.7~~$100.1 million outstanding at ~~Dec.~~December 31, ~~2005.~~2006. Commercial paper balances are typically lower at the end of the ~~third~~first quarter compared to year-end ~~because year-end working capital balances tend~~due to ~~include increases in customer receivables~~collections from higher sales and the withdrawal of gas inventories from storage during the winter heating season, and this year’s outstanding balances were lower than last year primarily due to ~~seasonality.~~the gas cost savings discussed above in “Results of Operations—Comparison of Gas Distribution Operations—Cost of Gas Sold.”

We have agreements for unsecured lines of credit totaling $200 million with five commercial banks. The bank lines of credit (bank lines) are available and committed for a term of five years, from ~~Oct.~~October 1, 2005 to ~~Sept.~~September 30, 2010. There were no outstanding balances on these bank lines ~~of credit~~ at ~~Sept. 30,~~March 31, 2007 or 2006, or ~~2005, or~~ at ~~Dec.~~December 31, ~~2005.~~2006.

The bank lines require us to maintain an indebtedness to total capitalization ratio of 65 percent or less. Failure to comply with this covenant would entitle the banks to terminate their lending

commitments and to accelerate the maturity of any amounts outstanding. We were in compliance with this covenant at ~~Sept. 30,~~March 31, 2007 and 2006 and at ~~Dec.~~December 31, 2005, and with the equivalent covenant in the prior year’s lines of credit at Sept. 30, 2005. We also expect to be in compliance with this debt covenant at the end of this year, after including the effect of adopting Statement of Financial Accounting Standards (SFAS) No. 158 for the recognition of underfunded pension and postretirement benefit obligations (see Note 2).2006.

The table below summarizes our debt credit ratings from ~~two rating agencies,~~ Standard and Poor’s Rating Services (S&P) and Moody’s Investors Service (Moody’s).

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

In March 2007, we redeemed $20.0 million of secured 6.31% Series B Medium Term Notes at maturity. In June 2006, we redeemed $8.0 million of secured 6.05% Series B Medium-Term Notes at maturity.

Year-over-year changes in our operating cash flows are primarily affected by net income, gas prices, deferred income taxes, changes in working capital requirements, regulatory deferrals and other cash and non-cash adjustments to operating results. The overall change in cash flow from operating activities for the ~~nine~~three months ended ~~Sept. 30, 2006~~March 31, 2007 compared to the same period in ~~2005~~2006 was an increase of ~~$27.5 million, primarily due to a $20.0 million contribution to the qualified defined benefit pension plans in September 2005.~~$48.1 million. The major factors contributing to the cash flow changes in the first ~~nine~~three months of ~~2006~~2007 compared to the first ~~nine~~three months of ~~2005~~2006 are as follows:

an increase in net income added ~~$0.9~~$7.0 million to cash flow;

deferred gas costs, primarily related to gas cost savings realized in the first quarter of 2007, increased cash by $20.8 million with the regulatory liability account increasing in the first quarter of 2007 compared to the regulatory receivable increasing in the first quarter of 2006; this current liability balance is expected to reverse when those costs are reflected in utility rates under our PGA tariff to be effective later in 2007;

a decrease of $13.6 million in cash resulting from an increase in gas inventory ~~balances reduced cash flow by $18.4 million, primarily reflecting a net increase~~balance in ~~gas storage volumes and higher gas prices,~~2007 compared to 2006;

an ~~inventory~~ increase of ~~$32.3~~$16.1 million ~~during 2005;~~

~~no contributions~~due to ~~the qualified defined benefit pension plans in 2006 reflected a net increase in cash flow of $20.0 million compared to last year;~~

a decrease in accounts receivable and accrued unbilled revenue ~~- net increased 2006 cash flow by $113.8 million, or $34.5 million greater than~~reflecting improvement in the ~~$79.3~~collection of year-end balances between 2007 and 2006;

a decrease of $13.2 million in ~~2005,~~2007 compared to 2006 due to the ~~collection~~realization of ~~higher year-end balances, reflecting higher rates and colder weather;~~income taxes receivable in 2006;

a ~~decrease~~reduction in accounts payable ~~reduced~~increased cash ~~flow~~ by ~~$70.8~~$22.7 million in ~~2006 compared to a $20.8 million reduction in 2005,~~2007 primarily due to ~~the payment of higher year-end balances, primarily reflecting higher~~lower gas ~~invoice~~ prices ~~for December 2005 compared to December 2004;~~around year end 2006; and

an increase in ~~other adjustments, primarily related to a change in regulatory liabilities for decoupling,~~accrued interest and taxes payable increased cash flow by ~~$9.9~~$8.5 million in ~~2006,~~2007 compared to ~~a $1.9 million reduction of cash flow in 2005; and~~2006.

a decrease in other current and accrued liabilities reduced cash flow by $5.9 million partially related to decreased liabilities for industrial customer settlement charges at year-end 2005 and customer deposits.

We have lease and purchase commitments relating to operating activities that are financed with cash flows from operations (see “Liquidity and Capital Resources,” above, and Part II, Item 8., Note 12, in the 2005 Form 10-K).

Investing Activities

Cash requirements for investing activities in the first ~~nine~~three months of ~~2006~~2007 totaled ~~$64.4~~$19.1 million, ~~down~~up from ~~$66.5~~$16.2 million in the same period of ~~2005.~~2006. Cash requirements for ~~the acquisition and construction of~~ utility plant totaled ~~$67.4~~$18.6 million, up from ~~$65.2~~$17.0 million in the first ~~nine~~three months of ~~2005. The~~2007, with the increase ~~in utility plant spending in 2006 was~~ primarily related to ~~the AMR project and pipeline integrity costs in 2006 (see “Contractual Obligations,” above), which were~~our automated meter reading project. This increase was partially offset by lower capital spending ~~under our bare steel replacement program.~~on new residential and commercial services.

Investments in non-utility property during the first ~~nine~~three months of ~~2006~~2007 totaled ~~$0.8~~$3.1 million, ~~down~~up from ~~$5.5~~$0.1 million during the first ~~nine~~three months of ~~2005~~2006, due primarily to amounts related to the capital improvements toand expansion development at our ~~interstate~~ gas storage facilities in ~~2005.~~2007. In 2007, we also received a $2.7 million payment due under the airplane leveraged lease agreement.

~~In January 2005, Financial Corporation received proceeds from the sale of its limited partnership interests~~Our utility and non utility capital expenditures are now expected to total about $120 million in ~~three solar electric generation projects totaling $3.0 million.~~

~~In September 2006, we announced that we are evaluating a potential pipeline project that would connect GTN’s interstate transmission line to our~~2007, which includes estimates for an enterprise resource planning system and additional gas distribution system. If the project is determined to be viable, we would form a partnership with GTN to build and own the pipeline, which would require a material investment. However, the project’s status will not be confirmed until 2007, and no material contractual obligations have been committed as of Sept. 30, 2006. If it is determined to be viable, the project could potentially be operating by 2011 (see “Strategic Opportunities,” above).storage related capital expenditures.

Financing Activities

Cash used in financing activities in the first ~~nine~~three months of ~~2006~~2007 totaled ~~$59.2~~$131.5 million, up from ~~$30.1~~$85.2 million in the same period of ~~2005.~~2006. The primary factors contributing to the ~~$29.1~~$46.3 million increase

were differences in debt financings and increased common stock ~~repurchases. Common stock repurchases in 2006 totaled $1.6 million compared to $13.8 million in 2005.~~repurchase activity. Debt financing ~~activity~~ consisted of a net ~~$31.4~~decrease of $114.6 million ofin short-term and long-term debt ~~redemptions~~outstanding in ~~2006,~~the first three months of 2007, compared to ~~$45.5~~a net decrease of $76.3 million in ~~2005, and $50.0 million of new long-term debt issuance proceeds in 2005, compared to no new financing in~~ 2006.

Under our common stock repurchase program, we ~~have~~ purchased ~~47,100~~206,700 shares at a total cost of ~~$1.6~~$9.0 million in the first ~~nine months~~quarter of ~~2006,~~2007, compared to ~~377,900~~11,700 shares at a total cost of ~~$13.8~~$0.4 million in the first ~~nine months~~quarter of ~~2005.~~2006.

Pension Funding Status

~~In September 2006,~~Our policy is to fund the Financial Accounting Standards Board issued SFAS No. 158 related to accounting for pension and other postretirement benefits (see Note 2, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”). SFAS No. 158 is effective for years ending after Dec. 15, 2006 and will require us to recognize the overfunded or underfunded status of ourqualified defined benefit ~~postretirement plans as an asset or liability on the balance sheet. The issues surrounding the measurement of postretirement~~

benefit obligations are complex, including factors relating to expectations about the future. Under previous accounting rules, if the fair value of plan assets exceeded the accumulated benefit obligation (ABO), which is defined as the value of employee benefits accrued for services rendered based on current and past compensation levels, then a liability was not required to be recognized on the balance sheet. However, under new accounting rules the pension benefit obligation is required to be recognized based on the projected benefit obligation, which is defined as the value of employee benefits accrued for service rendered based on future wage increases, including an assumption that the plan will continue in effect. We are in the process of evaluating the obligation amount that will be required to be recognized as a liability on the balance sheet at the end of this year. Based on the funded status of our benefit obligations at the end of last year, we would increase pension and postretirement liabilities by approximately $41 million.

~~It is our policy to continue making contributions to the qualified~~ pension plans, as needed, based on tax regulations and funding requirements under federal law, including funding the amounts required by the Employee Retirement Income Security Act of 1974. In addition, it is our intent to contribute sufficient amounts as ~~are~~ needed on an actuarial basis to maintain funding targets ~~which generally provide for the fair value of plan assets to be equal to or greater than the plan’s ABO,~~ and to provide for the timely payment of future benefits under these plans. For more information on the funding status of our qualified retirement plans and other postretirement benefits, see Part II, Item 7., “Pension Cost and Funding Status of Qualified Retirement Plans,” and Part II, Item 8., Note 7, “Pension and Other Postretirement Benefits,” in the 2006 Form 10-K.

~~Contingencies~~Contingent Liabilities

Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of loss is reasonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies.” We update our estimates of loss contingencies and related disclosures when new information becomes available. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties, and we record accruals for loss contingencies based on an analysis of potential results, developedFor further discussion, see Part I, Item 7., “Contingent Liabilities,” in ~~consultation with outside counsel and consultants when appropriate. When information is sufficient to estimate only a range of potential liabilities, and no point within~~ the range is more likely than any other, we recognize an accrued liability at the lower end of the range and disclose the range (see Note 9). It is possible, however, that the range of potential liabilities could be significantly different than amounts currently accrued and disclosed, and our financial condition and results of operations could be materially affected by changes in assumptions or estimates related to these contingencies.2006 Form 10-K.

We develop estimates of environmental liabilities and related costs based on currently available information, existing technology and environmental regulations. These costs include investigation, monitoring, and remediation. We received regulatory approval to defer and seek recovery of costs related to certain sites and believe the recovery of these costs is probable through the regulatory process. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” we have recorded a regulatory asset for the amount expected to be recovered. We intend to pursue recovery of these environmental costs from our general liability insurance policies, and the regulatory asset will be reduced by the amount of any corresponding insurance recoveries. At ~~Sept. 30, 2006,~~March 31, 2007, a cumulative ~~$22.8~~$28.3 million in environmental cost deferrals has been recorded as a regulatory asset, consisting of ~~$17.1~~$21.9 million of costs paid to-date and ~~$5.7~~$6.4 million of accrued estimated future environmental expenditures. If it is determined that both the insurance recovery and future customer rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is ~~made. See~~made (see Note 9.10, above).

Ratios of Earnings to Fixed Charges

For the ~~nine months~~three- and ~~12 months~~12-months ended ~~Sept. 30, 2006~~March 31, 2007 and the ~~12 months~~12-months ended ~~Dec.~~December 31, ~~2005,~~2006, our ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were ~~2.77, 3.32~~8.86, 3.73 and ~~3.32,~~3.40, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income. Because a significant part of our business is of a seasonal nature, the ratio for the interim period is not necessarily indicative of the results for a full year.

Forward-Looking Statements

This report and other presentations made by us from time to time may contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as ~~amended.~~amended (Exchange Act.) Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and other statements that are other than statements of historical facts. Our expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis. However, each forward-looking statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause our actual results to differ materially from those projected, including:

prevailing state and federal governmental policies and regulatory actions, including those of the OPUC and the WUTC, with respect to allowed rates of return, industry and rate structure, purchased gas cost and investment recovery, acquisitions and dispositions of assets and facilities, operation and construction of plant facilities, present or prospective wholesale and retail competition, changes in tax laws and policies ~~related to recovery of taxes in rates~~ and changes in and compliance with environmental and safety laws, ~~and~~ regulations, policies and orders, and laws, regulations and orders with respect to the maintenance of pipeline integrity;

implementation by the OPUC of final rules interpreting Oregon legislation intended to ensure that utilities do not collect more income taxes in rates than they actually pay to government entities;

weather conditions, pandemic events and other natural phenomena, including earthquakes or other ~~geo-hazard~~geohazard events;

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

competition for retail and wholesale customers;

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

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

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

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

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

risks relating to the execution of our business process redesign;

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

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

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

unanticipated changes in operating expenses and capital expenditures;

~~our ability to achieve the cost savings expected from operations model design changes;~~

changes in estimates of potential liabilities relating to environmental contingencies;

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

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

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

legal and administrative proceedings and settlements.

All subsequent forward-looking statements, whether written or oral and whether made by or on behalf of NW Natural, also are expressly qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all such factors, nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including commodity supply risk, weather risk, and interest rate risk (see Item 7A. in the ~~2005~~2006 Form 10-K, ~~and below, and see~~ Note 6, above, and Part II, Item 1A., “Risk Factors,” below).

Commodity ~~Supply~~Price Risk

~~We enter into~~Natural gas commodity prices are subject to fluctuations due to unpredictable factors including weather, pipeline transportation congestion and other factors that affect short-term ~~medium-term~~supply and ~~long-term~~demand. Commodity-price financial swap and option contracts (financial hedge contracts) are used to convert certain natural gas supply contracts along with associated short-, medium- and long-term transportation capacity contracts. Historically, we have taken physical delivery of at least the minimum quantities specified in our natural gas supply contracts.from floating prices to fixed or capped prices. These financial hedge contracts are ~~primarily index-based. Our PGA mechanisms~~generally included in Oregon and Washington provide for the recovery from customers of actual commodity costs, except that, for Oregon customers, we absorb 33 percent of the higher cost of gas sold, or retain 33 percent of the lower cost, in either case as compared to the annual PGA price built into customer rates.

~~Based on our ongoing assessment of gas prices and market risks, we began moderating our hedge position earlier this year as compared to prior years. Typically, by the time we file for~~ our annual PGA ~~rate change, we have~~filing, subject to a ~~high percentage~~regulatory prudence review. At March 31, 2007 and 2006, notional amounts under these financial hedge contracts totaled $249.8 million and $418.1 million, respectively. If all of the financial hedge contracts had been settled on March 31, 2007, a gain of about $7.1 million would have been realized and recorded to a deferred regulatory account (see Note 7). We monitor the liquidity of our financial hedge contracts. Based on the existing open interest in the contracts held, we believe existing contracts to be liquid. All of our financial hedge contracts settle by October 31, 2008. The $7.1 million unrealized gain is an estimate of future cash flows that are expected to be paid as follows: $5.6 million in the next ~~gas contract year’s estimated gas purchase requirements hedged. However, this year we went into~~twelve months and $1.5 million during the ~~PGA with a lower than normal but still significant percentage of gas purchases hedged~~second twelve months. The amount realized will change based on market ~~conditions and gas price outlook. As gas~~ prices began to decline in late August and early September, we increased our hedge positions, adding both to our storage levels with spot gas purchases and to our fixed-price financial swap portfolio to lock in gas prices on forward purchases. Our current overall hedge position forat the ~~upcoming gas~~time contract year is below where we have been hedged over the past few years, and this may subject us to greater purchased gas cost variability in the future as compared to previous years (see Part II, Item 1A., “Risk Factors,” below). Variations in gas costssettlements are ~~subject to our PGA mechanisms (see “Results of Operations—Rate Mechanisms,” above).~~fixed.

Credit Risk

Credit exposure to financial derivative counterparties. Based on estimated fair value, our credit exposure to financial derivative counterparties relating to commodity ~~swap~~hedge contracts was ~~$29.1~~$7.3 million at ~~Sept. 30, 2006.~~March 31, 2007. Our Financial Derivatives Policy requires counterparties to have a minimum investment-grade credit rating at the time the derivative instrument is entered into, and the policy specifies limits on the contract amount and duration based on each counterparty’s credit rating. ~~There were no credit rating downgrades for any of our counterparties during the quarter.~~

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

Financial Derivative Position by Credit Rating
Unrealized Fair Value Gain (Loss)
      Sept. 30,    Dec. 31,
Thousands
   2006 2005    2005
AA/Aa
   (29,122 ) 317,032    172,315
BBB/Baa
   —   23,481    3,346

Total
   $ (29,122 ) $ 340,513    $ 175,661

~~Credit exposure to customers~~.Rate increases effective Nov. 1, 2006 are expected to increase our credit exposure to customers. We monitor and manage the credit exposure of our customers through the consistent application of credit policies and procedures which are designed to reduce credit risk. These policies and procedures include an ongoing review of credit risks, including changes in market conditions and customers’ payment patterns. Changes in credit risk may require us to obtain additional assurance, such as deposits, letters of credit, guarantees or prepayments to reduce our credit exposure.


	Financial Derivative Position by Credit Rating Unrealized Fair Value Gain (Loss)
Thousands	March 31, 2007		March 31, 2006		Dec. 31, 2006
AAA/Aaa	$	3,695	$	940	$	—
AA/Aa		3,381		25,465		(40,955	)
A/A		—		—		—
BBB/Baa		—		—		—

Total	$	7,076	$	26,405	$	(40,955	)

Item 4.

CONTROLS AND PROCEDURES

(a)	Evaluation of Disclosure Controls and Procedures

As of ~~Sept. 30, 2006,~~March 31, 2007, the principal executive officer and principal financial officer of NWNorthwest Natural Gas Company (NW Natural) have evaluated the effectiveness of the design and operation of ~~NW Natural’s~~our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the ~~Securities~~ Exchange ~~Act of 1934, as amended (Exchange~~ Act)). Based upon that evaluation, the principal executive officer and principal financial officer of NW Natural

have concluded that such disclosure controls and procedures are effective to ensure that information required to be disclosed by ~~NW Natural~~us and included in ~~NW Natural’s~~our reports filed with the Securities and Exchange Commission (Commission) under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms and are also effective to ensure that information required to be disclosed by us and included in our reports filed with or furnished to the ~~Securities and Exchange~~ Commission under the Exchange Act is accumulated and communicated to ~~NW Natural’s~~our management as appropriate to allow timely decisions regarding required disclosure.

(b)	Changes in Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Exchange Act Rule 13a-15(f). There ~~has~~have been no ~~change~~changes in ~~NW Natural’s~~our internal control over financial reporting that occurred during ~~NW Natural’s~~our most recent fiscal quarter that ~~has~~have materially affected, or isare reasonably likely to materially affect, ~~NW Natural’s~~our internal control over financial reporting.

The statements contained in Exhibit 31.1 and Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this Item 4.

PART II. OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

Litigation

For a discussion of certain pending legal proceedings, see Note 9,10, above.

Item 1A.

RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors,” in our Annual Report on Form 10-K for the year ended ~~Dec.~~December 31, ~~2005 and the updates to certain of those risk factors described below,~~2006 which could materially affect our business, financial condition or results of operations. The risks described in ~~our Annual Report on~~the 2006 Form 10-K ~~as updated below,~~ are not the only risks facing our company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our financial condition, results of operations or cash flows.

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

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

Notwithstanding our current rate structure, higher gas costs could result in increased pressure on the Public Utility Commission of Oregon (OPUC) or the Washington Utilities and Transportation Commission (WUTC) to seek other means to reduce rates to a level that could adversely affect our financial condition, results of operations or cash flows.

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

A large portion of the utility’s margin is derived from sales to space heating residential and commercial customers during each winter heating season. Current rates are based on an assumption of average weather. In Oregon, the effects of warmer or colder weather on utility margin are reduced through the operation of our weather normalization mechanism and conservation tariff. From June 1 through November 30, the operation of the conservation tariff largely offsets the risk of warmer weather and declining consumption. From December 1 through May 15, the weather normalization mechanism adjusts for the effects of weather in Oregon. However, 10 percent of eligible customers elected not to be covered by the mechanism. Also, approximately 10 percent of our residential and commercial customers are in Washington where we do not have a weather normalization mechanism or conservation tariff. As a result, we are not fully protected against warmer than average weather, which may have an adverse affect on our financial condition, results of operations or cash flows.

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

The following table provides information about purchases by us during the quarter ended ~~Sept. 30, 2006~~March 31, 2007 of equity securities that are registered pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES

Period

(a)
Total Number
of Shares
Purchased⁽¹⁾

(b)
Average
Price Paid
per Share

(c)
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs⁽²⁾

(d)
Maximum Dollar Value of
Shares that May Yet Be
Purchased Under the
Plans or Programs⁽²⁾
Balance forward
         812,700    $ 60,260,697
07/01/06 - 07/31/06
   2,109    $ 36.30    —      —
08/01/06 - 08/31/06
   23,859    $ 37.99    —      —
09/01/06 - 09/30/06
   1,864    $ 38.96    —      —

Total
   27,832    $ 37.93    812,700    $ 60,260,697


Period	(a) Total Number of Shares Purchased⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽²⁾	(d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs⁽²⁾
Balance forward				1,161,100	$	45,899,916

01/01/07—01/31/07	689	$	41.51	35,000		(1,505,208	)

02/01/07—02/28/07	23,132	$	42.26	2,500		(109,941	)

03/01/07—03/31/07	28,362	$	43.82	169,200		(7,402,423	)

Total	52,183	$	43.10	1,367,800	$	36,882,344

⁽¹⁾

During the quarter ended ~~Sept. 30, 2006, 26,934~~March 31, 2007, 23,960 shares of our common stock were purchased in the open market to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan (DSPP). In addition, ~~898~~28,223 shares of our common stock were purchased in the open market during the quarter under equity-based programs. During the three months ended ~~Sept. 30, 2006,~~March 31, 2007, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.

⁽²⁾

On May 25, 2000, we announced a program to repurchase up to 2 million shares, or up to $35 million in value, of NW Natural’s common stock through a repurchase program that has been extended annually. The purchases are made in the open market or through privately negotiated transactions. During the three months ended Sept. 30, 2006, no shares of our common stock were purchased pursuant to this program. Since the program’s inception, we have repurchased 812,700 shares of common stock at a total cost of $24.7 million. In April 2006, the Board extended the program through May 31, 2007 and increased the authorization from 2 million shares to 2.6 million shares and increased the dollar limit from $35 million to $85 million. During the three months ended March 31, 2007, 206,700 shares of our common stock were purchased pursuant to this program. Since the program’s inception, we have repurchased 1,367,800 shares of common stock at a total cost of $48.1 million through March 31, 2007. In April 2007, the Board extended the program through May 31, 2008 and further increased the authorization from 2.6 million shares to 2.8 million shares and further increased the dollar limit from $85 million to $100 million.

On ~~Sept.~~March 29, ~~2006,~~2007, we entered into a Stock Purchase Plan Engagement Agreement with our broker in order to establish a trading plan for our repurchase program that qualifies for the safe harbors provided by Rule 10b-18 and Rule 10b5-1 under the ~~Securities~~ Exchange ~~Act~~Act. The agreement expires on May 31, 2007, but management may elect to enter into new agreements in the future to achieve the objectives of ~~1934,~~our repurchase program.

On February 27, 2007, we commenced a voluntary oddlot program through Georgeson Inc. which offered shareholders holding accounts with less than 100 shares of common stock the opportunity to either sell their shares or purchase an additional number of shares to round up to 100 shares of common stock in the account at the average closing price of our common stock over the offering period. As of the end of the initial offering period on March 30, 2007, a net of 7,363 shares were made available for repurchase by us at the average closing price of $44.54 per share. These amounts are not reflected in the above table as ~~amended.~~the settlement date occurred on April 19, 2007. The extension period under the program expired on April 25, 2007.

Item 6.

EXHIBITS

See Exhibit Index attached hereto.

SIGNATURE

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


				NORTHWEST NATURAL GAS COMPANY
				(Registrant)

Dated: ~~Nov. 2, 2006~~May 4, 2007				/s/ Stephen P. Feltz
				Stephen P. Feltz
				Principal Accounting Officer
				Treasurer and Controller

NORTHWEST NATURAL GAS COMPANY

EXHIBIT INDEX

Quarterly Report on Form 10-Q

For Quarter Ended

~~September 30, 2006~~March 31, 2007


Document		Exhibit Number ~~Number~~
~~Executive Deferred Compensation Plan, 2007 Restatement~~		~~10.1~~

~~Deferred Compensation Plan for Directors and Executives, Restated as of January 1, 2007~~		~~10.2~~

~~Directors Deferred Compensation Plan, Restated as of January 1, 2007~~		~~10.3~~

Statement re: Computation of Per Share Earnings		11

Computation of Ratio of Earnings to Fixed Charges		12

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

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

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


		Page Number
~~Item 1.~~

Item 1.	Consolidated Financial Statements

	Consolidated Statements of Income for the three-month ~~and nine-month~~ periods ended ~~Sept. 30,~~March 31, 2007 and 2006 ~~and 2005~~	1

	Consolidated Balance Sheets at ~~Sept. 30,~~March 31, 2007 and 2006 and ~~2005 and Dec.~~December 31, ~~2005~~2006	2

	Consolidated Statements of Cash Flows for the ~~nine-month~~three-month periods ended ~~Sept. 30,~~March 31, 2007 and 2006 ~~and 2005~~	4

	Notes to Consolidated Financial Statements ~~of Capitalization at Sept. 30, 2006 and 2005 and Dec. 31, 2005~~	5

Item 2.	~~Notes to Consolidated Financial Statements~~	6

~~Item 2.~~	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1914

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4132

Item 4.	Controls and Procedures	4232

	PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	4334

Item 1A.	Risk Factors	4334

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4435

Item 6.	Exhibits	4435

	Signature	4536


	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,				Three Months Ended March 31,
Thousands, except per share amounts	2006			2005			2006		2005		2007		2006
Operating revenues:
Gross operating revenues	$	114,914		$	106,667		$	676,284	$	569,111	$	394,091	$	390,391
Less: Cost of sales		70,634			62,231			431,069		335,264		245,469		255,399
Revenue taxes		2,939			2,496			16,663		13,272		9,614		9,528

Net operating revenues		41,341			41,940			228,552		220,575		139,008		125,464

Operating expenses:
Operations and maintenance		25,640			25,988			81,796		80,164		28,839		28,247
General taxes		5,595			5,915			19,234		17,895		7,817		7,573
Depreciation and amortization		16,196			15,452			47,988		45,959		16,785		15,830

Total operating expenses		47,431			47,355			149,018		144,018		53,441		51,650

Income (loss) from operations		(6,090	)		(5,415	)		79,534		76,557
Other income and expense - net		314			550			1,242		1,020
Interest charges - net of amounts capitalized		9,781			9,253			28,820		27,287
Income from operations												85,567		73,814
Other income and expense—net												538		518
Interest charges—net of amounts capitalized												9,567		9,855

Income (loss) before income taxes		(15,557	)		(14,118	)		51,956		50,290
Income tax expense (benefit)		(5,833	)		(5,447	)		18,653		17,934
Income before income taxes												76,538		64,477
Income tax expense												28,463		23,444

Net income (loss)	$	(9,724	)	$	(8,671	)	$	33,303	$	32,356
Net income											$	48,075	$	41,033

Average common shares outstanding:
Basic		27,556			27,560			27,568		27,564		27,229		27,584
Diluted		27,669			27,630			27,686		27,626		27,385		27,632
Earnings (loss) per share of common stock:
Earnings per share of common stock:
Basic	$	(0.35	)	$	(0.31	)	$	1.21	$	1.17	$	1.77	$	1.49
Diluted	$	(0.35	)	$	(0.31	)	$	1.20	$	1.17	$	1.76	$	1.48


Thousands	Sept. 30, 2006 (Unaudited)			Sept. 30, 2005 (Unaudited)			Dec. 31, 2005			March 31, 2007 (Unaudited)			March 31, 2006 (Unaudited)			Dec. 31, 2006
Assets:
Plant and property:
Utility plant	$	1,939,673		$	1,857,053		$	1,875,444		$	1,981,639		$	1,890,633		$	1,963,498
Less accumulated depreciation		566,972			532,667			536,867			585,008			547,635			574,093

Utility plant - net		1,372,701			1,324,386			1,338,577			1,396,631			1,342,998			1,389,405

Non-utility property		41,662			39,450			40,836			45,767			40,953			42,652
Less accumulated depreciation and amortization		6,684			5,755			5,990			7,149			6,221			6,916

Non-utility property - net		34,978			33,695			34,846			38,618			34,732			35,736

Total plant and property		1,407,679			1,358,081			1,373,423			1,435,249			1,377,730			1,425,141

Other investments		55,695			57,939			58,451

Current assets:
Cash and cash equivalents		5,685			3,408			7,143			5,094			7,522			5,767
Accounts receivable		31,791			30,518			84,418			89,489			97,859			82,070
Accrued unbilled revenue		19,316			16,787			81,512			43,468			47,764			87,548
Allowance for uncollectible accounts		(2,060	)		(1,553	)		(3,067	)		(4,235	)		(4,526	)		(3,033	)
Gas inventory		94,808			90,961			77,256
Materials and supplies inventory		9,723			7,855			8,905
Income taxes receivable		12,052			21,145			13,234
Regulatory assets											10,135			25,556			31,509
Fair value of non-trading derivatives											13,698			16,317			5,109
Inventories:
Gas											41,828			35,906			68,576
Materials and supplies											9,501			9,808			9,552
Prepayments and other current assets		44,125			36,106			54,309			14,761			57,330			21,695

Total current assets		215,440			205,227			323,710			223,739			293,536			308,793

Regulatory assets:
Income tax asset		66,757			65,622			65,843
Deferred environmental costs		22,836			17,456			18,880
Deferred gas costs receivable		5,183			5,414			6,974
Unamortized costs on debt redemptions		6,564			6,987			6,881
Unrealized loss on non-trading derivatives		31,317			—			—

Investments, deferred charges and other assets:
Regulatory assets											158,864			100,361			164,771
Fair value of non-trading derivatives											3,734			27,284			1,448
Other investments											48,247			54,432			47,985
Other		—			4,182			—			8,526			9,102			8,718

Total regulatory assets		132,657			99,661			98,578

Other assets:
Fair value of non-trading derivatives		11,164			346,158			178,653
Other		8,781			8,748			9,216

Total other assets		19,945			354,906			187,869
Total investments, deferred charges and other assets											219,371			191,179			222,922

Total assets	$	1,831,416		$	2,075,814		$	2,042,031		$	1,878,359		$	1,862,445		$	1,956,856


Thousands	Sept. 30, 2006 (Unaudited)			Sept. 30, 2005 (Unaudited)			Dec. 31, 2005			March 31, 2007 (Unaudited)			March 31, 2006 (Unaudited)			Dec. 31, 2006
Capitalization and liabilities:
Capitalization:
Common stock	$	383,897		$	87,230		$	87,334		$	363,519		$	87,335		$	371,127
Premium on common stock		—			296,376			296,471			—			296,281			—
Earnings invested in the business		210,457			189,417			205,687			269,172			237,205			230,774
Unearned stock compensation		—			(703	)		(650	)
Accumulated other comprehensive income (loss)		(1,911	)		(1,818	)		(1,911	)		(2,324	)		(1,911	)		(2,356	)

Total common stock equity		592,443			570,502			586,931			630,367			618,910			599,545
Long-term debt		492,000			521,500			521,500			517,000			501,500			517,000

Total capitalization		1,084,443			1,092,002			1,108,431			1,147,367			1,120,410			1,116,545


Current liabilities:
Notes payable		103,300			72,500			126,700			5,500			50,400			100,100
Long-term debt due within one year		29,500			8,000			8,000			9,500			28,000			29,500
Accounts payable		64,511			81,711			135,287			92,185			91,185			113,579
Taxes accrued		12,071			10,867			12,725			43,116			25,876			21,230
Interest accrued		11,454			11,493			2,918			11,409			11,623			2,924
Regulatory liabilities											41,888			20,502			11,919
Fair value of non-trading derivatives											9,447			16,739			38,772
Other current and accrued liabilities		35,065			33,928			40,935			22,832			20,432			21,455

Total current liabilities		255,901			218,499			326,565			235,877			264,757			339,479

Regulatory liabilities:
Accrued asset removal costs		182,725			165,917			169,927
Unrealized gain on non-trading derivatives - net		—			338,667			171,777
Customer advances		2,245			1,733			1,847
Other		10,054			—			661

Total regulatory liabilities		195,024			506,317			344,212

Other liabilities:
Deferred income taxes		221,265			213,126			222,331
Deferred investment tax credits		4,527			5,415			5,069
Deferred credits and other liabilities:
Deferred income taxes and investment tax credits											207,648			225,047			210,084
Regulatory liabilities											208,333			203,244			202,982
Pension and other postretirement benefit liabilities											54,117			17,693			52,690
Fair value of non-trading derivatives		41,469			7,491			6,876			3,108			3,569			11,031
Other		28,787			32,964			28,547			21,909			27,725			24,045

Total other liabilities		296,048			258,996			262,823
Total deferred credits and other liabilities											495,115			477,278			500,832

Commitments and contingencies (see Note 9)		—			—			—
Commitments and contingencies (see Note 10)											—			—			—

Total capitalization and liabilities	$	1,831,416		$	2,075,814		$	2,042,031		$	1,878,359		$	1,862,445		$	1,956,856


	Nine Months Ended Sept. 30,						Three Months Ended March 31,
Thousands	2006			2005			2007			2006
Operating activities:
Net income	$	33,303		$	32,356		$	48,075		$	41,033
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization		47,988			45,959			16,785			15,830
Deferred income taxes and investment tax credits		(2,522	)		1,801			(3,381	)		(3,267	)
Undistributed earnings from equity investments		(314	)		(139	)		78			50
Allowance for funds used during construction		(546	)		(351	)
Deferred gas costs - net		1,791			4,137
Gain on sale of non-utility investments		—			(12	)
Contributions to qualified defined benefit pension plans		—			(20,000	)
Deferred gas savings (costs)—net								14,242			(6,548	)
Non-cash expenses related to qualified defined benefit pension plans		4,122			3,576			1,064			1,441
Deferred environmental costs		(4,700	)		(2,128	)		(2,800	)		(2,014	)
Income from life insurance investments		(2,196	)		(1,410	)		(480	)		(1,383	)
Other		9,940			(1,876	)		(2,940	)		4,512
Changes in working capital:
Accounts receivable and accrued unbilled revenue - net		113,816			79,324
Accounts receivable and accrued unbilled revenue—net								37,997			21,766
Inventories of gas, materials and supplies		(18,370	)		(32,339	)		26,799			40,447
Income taxes receivable		1,182			(5,175	)		—			13,234
Prepayments and other current assets		7,421			2,730			4,280			1,112
Accounts payable		(70,776	)		(20,767	)		(21,394	)		(44,102	)
Accrued interest and taxes		7,882			9,221			30,371			21,856
Other current and accrued liabilities		(5,870	)		(240	)		1,141			(2,231	)

Cash provided by operating activities		122,151			94,667			149,837			101,736


Investing activities:
Investment in utility plant		(67,390	)		(65,226	)		(18,609	)		(16,997	)
Investment in non-utility property		(793	)		(5,465	)		(3,104	)		(106	)
Proceeds from sale of non-utility investments		—			3,001
Proceeds from life insurance		3,930			296			—			964
Other		(164	)		944			2,660			(25	)

Cash used in investing activities		(64,417	)		(66,450	)		(19,053	)		(16,164	)


Financing activities:
Common stock issued, net of expenses		2,350			6,169			1,737			859
Common stock repurchased		(1,608	)		(13,827	)		(9,017	)		(398	)
Long-term debt issued		—			50,000
Long-term debt retired		(8,000	)		(15,528	)		(20,000	)		—
Change in short-term debt		(23,400	)		(30,000	)		(94,600	)		(76,300	)
Cash dividend payments on common stock		(28,534	)		(26,871	)		(9,677	)		(9,516	)
Other								100			162

Cash used in financing activities		(59,192	)		(30,057	)		(131,457	)		(85,193	)

Decrease in cash and cash equivalents		(1,458	)		(1,840	)
Cash and cash equivalents - beginning of period		7,143			5,248
Increase (decrease) in cash and cash equivalents								(673	)		379
Cash and cash equivalents—beginning of period								5,767			7,143

Cash and cash equivalents - end of period	$	5,685		$	3,408
Cash and cash equivalents—end of period							$	5,094		$	7,522

Supplemental disclosure of cash flow information:
Interest paid	$	20,293		$	18,414		$	1,101		$	970
Income taxes paid	$	20,020		$	21,939		$	9,000		$	—
Supplemental disclosure of non-cash financing activities:
Conversions to common stock:
7-1/4 % Series of Convertible Debentures	$	—		$	3,999


Thousands	Sept. 30, 2006 (Unaudited)					Sept. 30, 2005 (Unaudited)					Dec. 31, 2005
Common stock equity:
Common stock	$	383,897				$	87,230				$	87,334
Premium on common stock		—					296,376					296,471
Earnings invested in the business		210,457					189,417					205,687
Unearned compensation		—					(703	)				(650	)
Accumulated other comprehensive income (loss)		(1,911	)				(1,818	)				(1,911	)

Total common stock equity		592,443		55	%		570,502		52	%		586,931		53	%
Long-term debt:
Medium-Term Notes
First Mortgage Bonds:
6.050% Series B due 2006		—					8,000					8,000
6.310% Series B due 2007		20,000					20,000					20,000
6.800% Series B due 2007		9,500					9,500					9,500
6.500% Series B due 2008		5,000					5,000					5,000
4.110% Series B due 2010		10,000					10,000					10,000
7.450% Series B due 2010		25,000					25,000					25,000
6.665% Series B due 2011		10,000					10,000					10,000
7.130% Series B due 2012		40,000					40,000					40,000
8.260% Series B due 2014		10,000					10,000					10,000
4.700% Series B due 2015		40,000					40,000					40,000
7.000% Series B due 2017		40,000					40,000					40,000
6.600% Series B due 2018		22,000					22,000					22,000
8.310% Series B due 2019		10,000					10,000					10,000
7.630% Series B due 2019		20,000					20,000					20,000
9.050% Series A due 2021		10,000					10,000					10,000
5.620% Series B due 2023		40,000					40,000					40,000
7.720% Series B due 2025		20,000					20,000					20,000
6.520% Series B due 2025		10,000					10,000					10,000
7.050% Series B due 2026		20,000					20,000					20,000
7.000% Series B due 2027		20,000					20,000					20,000
6.650% Series B due 2027		20,000					20,000					20,000
6.650% Series B due 2028		10,000					10,000					10,000
7.740% Series B due 2030		20,000					20,000					20,000
7.850% Series B due 2030		10,000					10,000					10,000
5.820% Series B due 2032		30,000					30,000					30,000
5.660% Series B due 2033		40,000					40,000					40,000
5.250% Series B due 2035		10,000					10,000					10,000

		521,500					529,500					529,500
Less long-term debt due within one year		29,500					8,000					8,000

Total long-term debt		492,000		45	%		521,500		48	%		521,500		47	%

Total capitalization	$	1,084,443		100	%	$	1,092,002		100	%	$	1,108,431		100	%


Year Awarded	Performance Period	Threshold	Target	Maximum
2004	2004-06	5,130	27,000	54,000
2005	2005-07	6,333	33,332	66,664
2006	2006-08	7,536	39,662	79,324

	Total	18,999	99,994	199,988


	2006		2005
Risk-free interest rate	4.5	%	4.2	%
Expected Life (in years)	6.2		7.0
Expected market price volatility factor	22.8	%	24.6	%
Expected dividend yield	4.0	%	3.6	%


Pro Forma Effect of Stock-Based Options and ESPP: Thousands, except per share amounts	Three Months			Nine Months
	Ended Sept. 30, 2005
Net income (loss) as reported	$	(8,671	)	$	32,356
Deduct: Pro forma stock-based compensation expense determined under the fair value based method - net of related tax effects		(84	)		(247	)

Pro forma net income (loss) - basic and diluted	$	(8,755	)	$	32,109

Basic earnings (loss) per share
As reported	$	(0.31	)	$	1.17
Pro forma	$	(0.32	)	$	1.16
Diluted earnings (loss) per share
As reported	$	(0.31	)	$	1.17
Pro forma	$	(0.32	)	$	1.16


	Option Shares		Price per Share
	Option Shares		Range		Weighted-Average Exercise Price
Balance Outstanding at Dec. 31, 2005	308,500		$	20.25-38.30	$	29.26
Granted	97,800			34.29		34.29
Exercised	(34,300	)		20.25-31.34		27.20
Expired	(2,400	)		31.34-34.29		32.82

Balance Outstanding at Sept. 30, 2006	369,600		$	20.25-38.30	$	30.76

Exercisable at Dec. 31, 2005	189,500		$	20.25-32.02	$	27.63

Exercisable at Sept. 30, 2006	213,700		$	20.25-38.30	$	28.80


	Outstanding			Exercisable
Range of Exercise Prices	Stock Options	*(In millions)* Aggregate Intrinsic Value		Stock Options	*(In millions)* Aggregate Intrinsic Value		Weighted- Average Exercise Price		Weighted- Average Remaining Life in Years
$20.25 -38.30	369,600	$	3.1	213,700	$	2.2	$	28.80	5.8


	Sept. 30,						Dec. 31,
Thousands	2006			2005			2005			March 31, 2007						March 31, 2006						Dec. 31, 2006
										Current			Non- Current			Current			Non- Current			Current			Non- Current
Fair Value Gain (Loss):
Natural gas commodity-based derivative instruments:
Fixed-price financial swaps	$	(29,122	)	$	321,119		$	173,790		$	6,034		$	1,536		$	1,063		$	25,342		$	(33,965	)	$	(6,312	)
Fixed-price financial call options		—			19,394			1,871			(494	)		—			—			—			(678	)		—
Indexed-price physical supply		(2,342	)		(5,281	)		(5,454	)		(1,258	)		(910	)		(2,096	)		(1,627	)		1,115			(3,271	)
Fixed-price physical supply		—			3,158			820
Physical supply contracts with embedded options		43			—			567
Physical supply contracts											—			—			566			—			—			—
Foreign currency forward purchases		104			277			183			(31	)		—			45			—			(135	)		—

Total	$	(31,317	)	$	338,667		$	171,777		$	4,251		$	626		$	(422	)	$	23,715		$	(33,663	)	$	(9,583	)


	Three Months Ended Sept. 30,											Nine Months Ended Sept. 30,
Thousands	Utility			Interstate Gas Storage		Other			Total			Utility		Interstate Gas Storage		Other			Total
2006
Net operating revenues	$	38,085		$	3,211	$	45		$	41,341		$	218,476	$	9,961	$	115		$	228,552
Depreciation and amortization		15,975			221		—			16,196			47,327		661		—			47,988
Income (loss) from operations		(8,634	)		2,720		(176	)		(6,090	)		71,480		8,653		(599	)		79,534
Income from financial investments		399			—		255			654			2,196		—		314			2,510
Net income (loss)		(11,408	)		1,496		188			(9,724	)		28,258		4,762		283			33,303
Total assets at Sept. 30, 2006		1,784,762			35,844		10,810			1,831,416			1,784,762		35,844		10,810			1,831,416
2005
Net operating revenues	$	38,765		$	3,126	$	49		$	41,940		$	213,377	$	7,107	$	91		$	220,575
Depreciation and amortization		15,289			163		—			15,452			45,469		490		—			45,959
Income (loss) from operations		(8,196	)		2,766		15			(5,415	)		70,531		6,046		(20	)		76,557
Income from financial investments		436			—		68			504			1,410		—		139			1,549
Net income (loss)		(10,473	)		1,571		231			(8,671	)		28,383		3,313		660			32,356
Total assets at Sept. 30, 2005		2,028,389			34,697		12,728			2,075,814			2,028,389		34,697		12,728			2,075,814


	Three Months Ended March 31,
Thousands	Utility		Gas Storage		Other			Total
2007
Net operating revenues	$	135,549	$	3,410	$	49		$	139,008
Depreciation and amortization		16,563		222		—			16,785
Income from operations		82,595		2,941		31			85,567
Income (loss) from financial investments		480		—		(78	)		402
Net income		46,108		1,795		172			48,075
Total assets at March 31, 2007	$	1,831,806	$	39,004	$	7,549		$	1,878,359

2006
Net operating revenues	$	122,344	$	3,079	$	41		$	125,464
Depreciation and amortization		15,610		220		—			15,830
Income from operations		71,122		2,684		8			73,814
Income (loss) from financial investments		1,383		—		(50	)		1,333
Net income		39,463		1,449		121			41,033
Total assets at March 31, 2006	$	1,815,343	$	35,533	$	11,569		$	1,862,445


Thousands	Three Months Ended March 31,
	Pension Benefits						Other Postretirement Benefits
	2007			2006			2007			2006
Service cost	$	2,159		$	1,961		$	148		$	137
Interest cost		3,995			3,758			320			283
Expected return on plan assets		(4,636	)		(4,403	)		—			—
Amortization of loss		539			916			1			—
Amortization of prior service cost		245			245			49			49
Amortization of transition obligation		—			—			103			103

Net periodic benefit cost		2,302			2,477			621			572
Amount allocated to construction		(515	)		(700	)		(202	)		(187	)

Net amount charged to expense	$	1,787		$	1,777		$	419		$	385


	Non-Current Regulatory Assets						Non-Current Liabilities
	March 31,				Dec. 31,		March 31,				Dec. 31,
Millions	2007		2006		2006		2007		2006		2006
Gasco site	$	10.8	$	3.4	$	10.3	$	6.2	$	1.0	$	6.6
Siltronic site		0.5		0.3		0.5		0.1		—		0.1
Portland Harbor site		16.8		15.2		16.8		1.7		3.5		3.1
Oregon Steel Mills site		0.2		0.2		0.2		0.2		0.2		0.2

Total	$	28.3	$	19.1	$	27.8	$	8.2	$	4.7	$	10.0


	Three Months Ended Sept. 30,
Thousands, except degree day and customer data	2006					2005
Utility volumes - therms:
Residential and commercial sales		54,525		29	%		52,553		29	%
Industrial sales and transportation		131,533		71	%		128,860		71	%

Total utility volumes sold and delivered		186,058		100	%		181,413		100	%

Utility operating revenues - dollars:
Residential and commercial sales	$	78,619		70	%	$	66,696		64	%
Industrial sales and transportation		34,196		31	%		37,319		36	%
Other revenues		(1,168	)	(1	%)		(513	)	—

Total utility operating revenues		111,647		100	%		103,502		100	%
Cost of gas sold		70,623					62,241
Revenue taxes		2,939					2,496

Utility net operating revenues (margin)	$	38,085				$	38,765

Utility margin:⁽¹⁾
Residential sales	$	21,618		57	%	$	20,944		54	%
Commercial sales		10,293		27	%		10,182		26	%
Industrial - sales and transportation		7,682		20	%		8,078		21	%
Miscellaneous revenues		695		2	%		926		2	%
Other margin adjustments		(738	)	(2	%)		(552	)	(1	%)

Margin before weather normalization and decoupling		39,550		104	%		39,578		102	%
Weather normalization mechanism		—		—			(2	)	—
Decoupling mechanism		(1,465	)	(4	%)		(811	)	(2	%)

Utility margin	$	38,085		100	%	$	38,765		100	%

Customers - end of period:
Residential customers		562,752					543,118
Commercial customers		59,519					58,425
Industrial customers		937					943

Total number of customers - end of period		623,208					602,486

Actual degree days		79					101

Percent colder (warmer) than average⁽²⁾		(23	%)				(1	%)


	Nine Months Ended Sept. 30,
Thousands, except degree day data	2006					2005
Utility volumes - therms:
Residential and commercial sales		404,259		49	%		382,958		48	%
Industrial sales and transportation		419,313		51	%		407,365		52	%

Total utility volumes sold and delivered		823,572		100	%		790,323		100	%

Utility operating revenues - dollars:
Residential and commercial sales	$	533,584		80	%	$	439,497		78	%
Industrial sales and transportation		133,775		20	%		117,125		21	%
Other revenues		(1,206	)	0	%		5,213		1	%

Total utility operating revenues		666,153		100	%		561,835		100	%
Cost of gas sold		431,014					335,186
Revenue taxes		16,663					13,272

Utility net operating revenues (margin)	$	218,476				$	213,377

Utility margin:⁽¹⁾
Residential sales	$	133,522		61	%	$	125,356		59	%
Commercial sales		55,769		26	%		52,374		24	%
Industrial - sales and transportation		23,872		11	%		24,605		12	%
Miscellaneous revenues		3,343		2	%		4,046		2	%
Other margin adjustments		2,684		1	%		2,464		1	%

Margin before weather normalization and decoupling		219,190		101	%		208,845		98	%
Weather normalization mechanism		2,686		1	%		2,516		1	%
Decoupling mechanism		(3,400	)	(2	%)		2,016		1	%

Utility margin	$	218,476		100	%	$	213,377		100	%

Actual degree days		2,465					2,522

Percent colder (warmer) than average⁽²⁾		(7	%)				(5	%)


	Three months ended March 31,						Favorable/ (Unfavorable)
Thousands, except degree day and customer data	2007			2006			Favorable/ (Unfavorable)
Utility volumes—therms:
Residential sales		162,897			159,312			3,585
Commercial sales		96,804			95,325			1,479
Industrial—firm sales		15,917			24,038			(8,121	)
Industrial—firm transportation		43,471			29,742			13,729
Industrial—interruptible sales		25,664			42,564			(16,900	)
Industrial—interruptible transportation		67,738			56,955			10,783

Total utility volumes sold and delivered		412,491			407,936			4,555


Utility operating revenues—dollars:
Residential sales	$	227,138		$	214,314		$	12,824
Commercial sales		118,042			113,047			4,995
Industrial—firm sales		16,655			23,176			(6,521	)
Industrial—firm transportation		1,498			948			550
Industrial—interruptible sales		22,131			35,352			(13,221	)
Industrial—interruptible transportation		2,093			1,859			234
Other revenues		3,068			(1,440	)		4,508

Total utility operating revenues		390,625			387,256			3,369
Cost of gas sold		245,462			255,384			9,922
Revenue taxes		9,614			9,528			(86	)

Utility net operating revenues (margin)	$	135,549		$	122,344		$	13,205


Utility margin:
Residential sales	$	81,036		$	78,348		$	2,688
Commercial sales		32,338			31,777			561
Industrial—sales and transportation		8,379			8,486			(107	)
Miscellaneous revenues		1,639			1,503			136
Other margin adjustments		10,951			1,440			9,511

Margin before regulatory adjustments		134,343			121,554			12,789
Weather normalization mechanism		108			1,842			(1,734	)
Decoupling mechanism		1,098			(1,052	)		2,150

Utility margin	$	135,549		$	122,344		$	13,205


Customers—end of period:
Residential customers		579,746			563,178			16,568
Commercial customers		60,987			60,175			812
Industrial customers		953			944			9

Total number of customers—end of period		641,686			624,297			17,389

Actual degree days		1,852			1,814

Percent colder (warmer) than average⁽¹⁾		(1	)%		(3	)%


	Three Months Ended March 31,
Thousands	2007			2006
Other income and expense—net:
Gains from company-owned life insurance	$	480		$	1,383
Interest income		152			84
Other non-operating expense		(274	)		(603	)
Net interest income (expense) on deferred regulatory accounts		258			(296	)
Loss from equity investments of Financial Corporation		(78	)		(50	)

Total other income and expense—net	$	538		$	518


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


Period	(a) Total Number of Shares Purchased⁽¹⁾	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽²⁾	(d) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs⁽²⁾
Balance forward				812,700	$	60,260,697
07/01/06 - 07/31/06	2,109	$	36.30	—		—
08/01/06 - 08/31/06	23,859	$	37.99	—		—
09/01/06 - 09/30/06	1,864	$	38.96	—		—

Total	27,832	$	37.93	812,700	$	60,260,697