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 and six months ended June 30, 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 (Palomar). 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). We also believe that showing operating revenues and margins excluding the June 2009 refund of gas cost savings to customers facilitates more meaningful comparisons of operating revenues and margins between 2008 and 2009. We use such non-GAAP (i.e. not generally accepted accounting principles) financial measures in analyzing our results of operations and believe that they provide useful information to investors and creditors in evaluating our financial condition.

Executive Summary

Results for the second quarter of 2009 include:

· Consolidated net income decreased 6 percent to $3.1 million in the second quarter of 2009, compared to $3.3 million in the second quarter of 2008;

· Net operating revenues (margin) increased 5 percent from $62.6 million to $65.9 million in 2009, but the margin gain was partially offset by a 3 percent increase in total operating expenses;

· Income from utility operations increased 20 percent from $7.5 million in 2008 to $9.0 million in 2009, while income from gas storage operations decreased 1 percent or less than $0.1 million;

· Cash flow from operations increased 45 percent from $138.1 million in 2008 to $199.8 million in 2009;

· Gas cost savings of $35.3 million were refunded to Oregon and Washington customers due to lower gas prices;

· Twelve-month customer growth rate declined to 0.8 percent; and

· A new five-year contract was executed with our bargaining unit employees, effective July 13, 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 hedged gas prices for the majority of our gas purchases for the current gas contract year that began on November 1, 2008, and we believe we have sufficient contracted supplies of natural gas to meet the needs of our core utility customers. During the six months ended June 30, 2009, the market price of natural gas continued to be below the prices embedded in our customers' rates through our annual purchased gas adjustment (PGA) tariff, which resulted in gas cost savings for customers and shareholders from purchases of gas where prices were not hedged. 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 been hedging gas prices for the next gas contract year, and to a certain extent for the next three years, based on current market prices for those future periods. We are also continuing to evaluate and develop other gas acquisition strategies to manage gas prices for customers beyond three years and efficiently meet demands. Based on today's hedge levels and current forward prices for natural gas, we expect to have a customer rate decrease of 15 to 20 percent effective November 1, 2009.

Economic weakness and financial market stress. Continued weakness in local and U.S. economies have resulted in significant negative pressure on consumer demand and business spending. These conditions have had a negative impact on our financial results including customer growth, margins, bad debt expense, and could have a negative impact on net pension and interest costs. For example, our 12-month customer growth rate slowed to 0.8 percent at June 30, 2009 compared to 2.5 percent at June 30, 2008. Based on current market conditions, we expect lower customer growth rates to continue and possibly decline more if economic conditions deteriorate further. However, due to a relatively low market penetration of natural gas in our service territory compared to the rest of the country, along with the forecast for long-term population growth in the Pacific Northwest, the potential for environmental initiatives in Oregon and Washington that could favor natural gas as an energy source, and our ongoing efforts to convert existing homes from other heating fuels to natural gas, we still have the potential to continue adding customers despite tough market conditions.

Our funding for strategic opportunities and other capital investments is dependent upon our ability to access capital markets and maintain working capital sufficient to meet operating requirements. In March 2009, and again in July 2009, we were able to issue long-term debt totaling $125 million at favorable rates (see Note 5). We continue to focus on: maintaining a strong balance sheet; providing sufficient liquidity; accessing capital markets as needed; managing critical business risks; and maintaining a balanced capital structure through the appropriate issuance of equity or long-term debt securities. 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 and liquidity position remain strong and afford us access to capital at reasonable costs. See Part I, Item 1A., "Risk Factors," and Part II, Item 7., "Financial Condition-Liquidity and Capital Resources," in our 2008 Form 10-K.

Performance Measures. In order to deal with these and other challenges affecting our business, we continue to refine our 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 the current economic and competitive challenges, we continue to evaluate and implement business strategies to improve efficiencies. Our goal is to integrate, consolidate and streamline operations and support our employees with new technology tools. 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 reduce the number of technology platforms and improve overall operating efficiencies by:

· integrating systems and data;

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

· improving monthly closing and financial reporting processes.

We initiated a project to automate the reading of gas meters (AMR) for the remaining two-thirds of our customers in 2008. Meters equipped with this new 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.

In 2009, we began to identify additional areas for further cost reductions based on work load declines primarily related to slower customer growth. We intend to mitigate the potential impact of the decline by aligning current staffing levels with work load demands and reducing operating costs. At this time, it is likely we will make reductions that equate to between 50 and 100 full-time positions, with a majority of those reductions made by the end of this fiscal year. See "Issues, Challenges and Performance Measures-Economic Weakness and Financial Market Stress," above.

These technology investments, workforce reductions and other initiatives are expected to facilitate process improvements, contribute to long-term operational efficiencies and reduce operating expenses 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. A decision on the application is expected to be received by the end of this year. Gill Ranch's provision of market-based rate storage services in California will be subject to CPUC regulation including, but not limited to, service terms and conditions, tariff compliance, securities issuances, lien grants and sales of property. Our share of the total project is estimated to be between $160 and $180 million. Our share represents 75 percent of the total cost of the initial development, which includes an estimated total 20 Bcf of gas storage capacity and approximately 27 miles of gas transmission pipeline. The initial development of gas storage at Gill Ranch is currently scheduled to be in-service by late 2010.

Pipeline Diversification. Currently, we depend on a single bi-directional interstate pipeline to ship gas supplies to our distribution 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 provide a new transmission pipeline interconnection with our gas distribution 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 other potential 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 gas delivery options and enhance the reliability of service to our utility customers by providing an alternate transportation path for gas purchases from western Canada and the U.S. Rocky Mountains. The west segment of Palomar would provide our utility customers with potential 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-Cash Flows-Investing Activities," below for further discussion on Palomar.

Earnings and Dividends

Three months ended June 30, 2009 compared to June 30, 2008:

Net income was $3.1 million, or $0.12 per share, for the three months ended June 30, 2009, compared to $3.3 million, or $0.12 per share, for the same period last year.

The primary factors contributing to the $0.2 million decrease in net income were:

· a $5.8 million net decrease in utility margin from sales and transportation customers, after weather and decoupling mechanism adjustments, primarily due to a rate decrease for lower depreciation rates and lower sales due to warmer weather and weak economic conditions (see Results of Operations - Business Segments-Utility Operations," below);

· a $4.3 million increase in operations and maintenance expense primarily due to higher pension expense, bonus accruals, and health care benefit expenses; and

· a $1.2 million decrease in other income reflecting a last year's gain from the sale of our investment in a leased aircraft in 2008.

Partially offsetting the above factors were:

· an $8.1 million increase in utility margin from our regulatory share of gas cost savings, reflecting a margin loss of $5.5 million in 2008 compared to a margin gain of $2.6 million in 2009; and

· a $2.6 million decrease in depreciation expense reflecting lower depreciation rates effective January 1, 2009, which was offset by a corresponding decrease in utility margin referred to above.

Six months ended June 30, 2009 compared to June 30, 2008:

Net income was $50.4 million, or $1.90 per share, for the six months ended June 30, 2009, compared to $46.5 million, or $1.75 per share, for the same period last year.

The primary factors contributing to the $4.0 million increase in net income were:

· a $16.9 million increase in utility margin from our regulatory share of gas cost savings, reflecting a margin loss of $5.8 million in 2008 compared to a margin gain of $11.1 million in 2009;

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

· a $4.8 million decrease in depreciation expense primarily from lower depreciation rates effective January 1, 2009.

Partially offsetting the above factors were:

· a $9.8 million increase in operations and maintenance expense primarily due to higher pension expense, bonus accruals, and health care benefit expenses; and

· a $6.6 million net decrease in utility margin from sales and transportation customers, after weather and decoupling mechanism adjustments, primarily due to a rate decrease for lower depreciation rates referred to above.

Dividends paid on our common stock were 39.5 cents per share in the second quarter of 2009, compared to 37.5 cents per share in the second quarter of 2008. In July 2009, the Board of Directors declared a quarterly dividend on our common stock of 39.5 cents per share, payable on August 14, 2009 to shareholders of record on July 31, 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

Regulatory Matters

Regulation and Rates

We are currently subject to regulation with respect to, among other matters, rates and systems of accounts set by the Oregon Public Utility Commission (OPUC), the Washington Utilities and Transportation Commission (WUTC) and the FERC. The OPUC and WUTC also regulate our issuance of securities. Approximately 90 percent of our utility gas volumes are 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 southwest Washington economies in general, and by the pace of growth in the residential and commercial markets in particular, 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 June 30, 2009 and 2008 and at December 31, 2008, the amounts deferred as regulatory assets and liabilities were as follows:

                                                                         Current
                                                          June 30,      June 30,      Dec. 31,
Thousands                                                   2009          2008          2008
Regulatory assets:
Unrealized loss on non-trading derivatives(1)             $  70,052     $   1,912     $ 136,735
Pension and other postretirement benefit obligations(2)       8,074         2,792         8,074
Other(4)                                                     11,053         1,044         2,510
Total regulatory assets                                   $  89,179     $   5,748     $ 147,319
Regulatory liabilities:
Gas costs payable                                         $  19,010     $  24,307     $   5,284
Unrealized gain on non-trading derivatives(1)                 5,293        53,999         4,592
Other(4)                                                      6,486         6,064        10,580
Total regulatory liabilities                              $  30,789     $  84,370     $  20,456

                                                                       Non-Current
                                                          June 30,      June 30,      Dec. 31,
Thousands                                                   2009          2008          2008
Regulatory assets:
Unrealized loss on non-trading derivatives(1)             $   8,844     $   2,732     $  21,646
Income tax asset                                             70,096        69,547        69,948
Pension and other postretirement benefit obligations(2)     109,833        26,203       113,869
Environmental costs - paid(3)                                41,362        32,087        36,135
Environmental costs - accrued but not yet paid(3)            28,689        32,072        29,969
Other(4)                                                     11,220        10,680        16,903
Total regulatory assets                                   $ 270,044     $ 173,321     $ 288,470
Regulatory liabilities:
Gas costs payable                                         $   3,758     $   1,263     $   1,868
Unrealized gain on non-trading derivatives(1)                   289         9,218           146
Accrued asset removal costs                                 231,880       214,044       223,716
Other(4)                                                      2,337         2,551         2,427
Total regulatory liabilities                              $ 238,264     $ 227,076     $ 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.

Rate Mechanisms

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

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

Under the new Oregon PGA incentive sharing mechanism, effective November 1, 2008, we are required to select, by August 1 of each year, either an 80 percent deferral or 90 percent deferral of higher or lower gas costs compared to PGA prices such that the impact on current earnings from the gas cost sharing is either 20 percent or 10 percent, respectively. We are also subject to an annual earnings review to see if the utility is earning over an allowed threshold. If utility earnings exceed a threshold level, then 33 percent of the excess 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 return on equity (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 current PGA year, we selected the 80 percent deferral. In August 2009, however, we selected the 90 percent deferral for the PGA year beginning November 1, 2009. The earnings threshold is 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. In July 2009, we received the final report from the OPUC on our 2008 earnings review, which resulted in a ROE of 9.6 percent. As this is below the earnings threshold, no refund will be made to customers as a result of the 2008 earnings review. 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. The OPUC also 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, these authorizations have been extended through January 25, 2010. 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 . . .