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

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

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

Executive Summary

Highlights of the first quarter of 2009 include:

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

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

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

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

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

Issues, Challenges and Performance Measures

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

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

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

We believe that, despite the current economic and credit market environment, our financial condition, including our liquidity position, is strong and we can access capital at reasonable costs. See Part I, Item 1A., "Risk Factors," and

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

Strategic Opportunities

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

· the integration of systems and data;

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

· improved monthly closing and financial reporting processes.

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

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

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

Earnings and Dividends

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

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

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

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

Partially offsetting the above factors were:

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

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

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

Application of Critical Accounting Policies and Estimates

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

· regulatory cost recovery and amortizations;

· revenue recognition;

· derivative instruments and hedging activities;

· pensions;

· income taxes; and

· environmental contingencies.

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

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

Results of Operations

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

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

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

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

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

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

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

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

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

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

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

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

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

· an evaluation of supply and demand resources;

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

· a primary goal of "least cost" service.

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

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

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

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

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

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