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 nine months ended September 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 refund of gas cost savings on customer bills in June and July 2009 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 our investors and creditors in evaluating our financial condition.

Executive Summary

Results for the third quarter of 2009 include:

· Consolidated earnings improved by $3.4 million or 33 percent, from a net loss of $10.1 million in the third quarter of 2008 to a net loss of $6.7 million in the third quarter of 2009;

· Net operating revenues (margin) increased 12 percent from $43.5 million in 2008 to $48.6 million in 2009;

· Earnings from utility operations improved 26 percent from a net loss of $12.3 million in 2008 to a net loss of $9.2 million in 2009;

· Earnings from gas storage operations increased 18 percent from net income of $1.9 million in 2008 to $2.3 million in 2009;

· Cash flow from operations increased 177 percent from $72.0 million in 2008 to $199.3 million in 2009;

· Twelve-month customer growth rate was 0.7 percent; and

· Our quarterly dividend increased 2 cents per share, or 5 percent, to 41.5 cents a share payable on November 13, 2009 to shareholders of record on October 30, 2009.

Issues, Challenges and Performance Measures

Managing the utility business in a period of gas price volatility. Natural gas commodity prices have the most significant impact on our customer rates and on our long-term competitive position against other energy sources such as oil and electricity. Over the last 15 months, daily Henry Hub spot market prices for natural gas in the U.S. ranged between a high of $13 per mmBtu in July 2008 and a low of $2 per mmBtu as recently as September 2009. Our gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage. As of October 31, 2009, gas prices were hedged for approximately 70 to 75 percent of our gas purchase volumes for the next gas contract year beginning November 1, 2009, and we believe we have sufficient contracted supplies to meet the needs of our core utility customers. In addition, we are currently hedged on gas prices for between 10 and 15 percent of our forecasted purchase volumes for the two gas contract years after October 31, 2010. Although spot gas prices were as low as $2 per mmBtu during the third quarter of 2009, the current forward price of natural gas remains at much higher levels between $5 and $7 per mmBtu over the next three years. Our Purchased Gas Adjustment (PGA) mechanism, along with gas price hedging strategies and physical gas supplies in storage, enables us to reduce earnings risk exposure due to higher gas costs. In addition to hedging gas prices over the next three years, we are also evaluating and developing other gas acquisition strategies to potentially manage gas price volatility for customers beyond three years.

Economic weakness. 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, reflecting slower customer growth, reduced industrial margins, increased bad debt expense, and higher pension costs. Our 12-month customer growth rate slowed to 0.7 percent at September 30, 2009 compared to 2.4 percent at September 30, 2008. We expect our customer growth rate to continue near current levels through year end, unless economic conditions deteriorate further. However, due to a relatively low market penetration of natural gas in our service territory and forecasts of long-term population growth in the Pacific Northwest, combined with the potential for environmental initiatives in Oregon and Washington that could favor natural gas as an energy source and our focused efforts to convert existing homes from other heating fuels to natural gas, we believe we are well positioned to continue adding customers despite challenging market conditions.

Capital market environment. The volatility in capital markets during 2008 and 2009 has caused general concern over the ability of many companies to obtain financing, manage credit exposures and maintain liquidity. Our ability to fund strategic investment opportunities as well as to meet utility capital expenditure and working capital requirements is dependent upon ongoing access to capital markets. Over the last 12 months, we were able to issue long-term debt totaling $125 million at reasonable rates (see Note 5), and we were able to add two short-term credit facilities totaling $30 million to provide temporary liquidity. Our capital market strategy has continued to focus on: maintaining a strong balance sheet; ensuring ample cash resources and daily liquidity; accessing capital markets at favorable times as needed; managing critical business risks; and maintaining a balanced capital structure through the appropriate issuance of equity or long-term debt securities. If in the future 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.

Strategies and Performance Measures. In order to deal with the challenges affecting our business, we continue to refine our strategic plan to map our course over the next several years. Our plan includes strategies for: further improving our core gas distribution business; growing our non-utility gas storage business; investing in new natural gas infrastructure in the region; and maintaining a leadership role within the gas utility industry by addressing long-term energy policies and pursuing business opportunities that support new clean energy 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 (non-utility 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.

Also in 2008, we initiated a project to automate the reading of gas meters (AMR) for the remaining two-thirds of our customers. 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. We expect to complete this project by the end of 2009. The total capital cost of this project is estimated to be up to $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).

We also initiated an automated dispatching system in 2008, which provides integrated planning and scheduling with global positioning system capabilities to more effectively collect and distribute data. We will continue to deploy this new technology in the field into 2010.

In mid-2009, we announced a voluntary severance program to our bargaining unit employees to further reduce staffing levels in response to work load declines related to slower customer growth and efficiency improvements. We are mitigating the potential impact of the decline by aligning current staffing levels with work load demands and reducing operating costs. We expect our voluntary severance program and attrition to result in reductions that equate to between 50 and 100 full-time positions, and to incur a charge in the fourth quarter of 2009 of approximately $1 million, which will be partially offset by savings from vacated positions prior to the end of the year. We also expect some additional reductions after the end of this fiscal year, but those reductions will most likely come from normal attrition. See "Issues, Challenges and Performance Measures-Economic weakness and Capital market environment," above.

Technology investments, workforce reductions and other initiatives discussed above 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 entered into a joint project agreement with Pacific Gas & Electric Company (PG&E) to develop an underground natural gas storage facility near Fresno, California. At that time, we formed a wholly-owned subsidiary, Gill Ranch, to plan and develop the project and to 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 (CPCN). In October 2009, we received an order from the CPUC approving our CPCN. 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 cost is estimated to be between $160 and $180 million, representing 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 the gas storage facility at Gill Ranch is currently scheduled to be in-service by August 2010.

We are currently in the process of hiring key staff for our gas storage businesses. While our primary focus for growing the gas storage business is on the current development at Gill Ranch, we also plan to continue expanding our interstate storage facilities at Mist, Oregon. This past quarter, we completed 3-D seismic surveys and initiated engineering work for a new 3 to 4 Bcf expansion at Mist. Pending a successful open season that will be conducted in the first quarter of 2010, we expect to move forward with the project next year and would target a 2011 in-service date. The total project cost estimates are between $45 million and $55 million. This estimated cost range includes the development of a second compression station and a pipeline gathering system at Mist that will enable future storage expansions.

Pipeline Diversification. Currently, we depend on a single bi-directional interstate pipeline to ship gas supplies to our utility distribution system. Palomar Gas Transmission, LLC, a wholly-owned subsidiary of Palomar Gas Holdings, LLC, (PGH), is seeking to build a new transmission pipeline that would provide a new gas transmission pipeline interconnection with our utility 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 not only 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 different regions in western Canada and the U.S. Rocky Mountains, but also provide potential access to other shippers in the region. 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 CPCN with the FERC. See "Financial Condition-Cash Flows-Investing Activities," below for further discussion on Palomar.

Earnings and Dividends

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

For the three months ended September 30, 2009, we had a net loss of $6.7 million, or 25 cents per share, compared to a net loss of $10.1 million, or 38 cents per share, for the same period last year.

The primary factors contributing to the lower third quarter net loss were:

· a $5.4 million increase in utility margin from our regulatory share of gas cost savings, reflecting a margin loss of $1.8 million in 2008 compared to a margin gain of $3.6 million in 2009;

· a net $1.3 million increase in utility operating income due to lower depreciation rates (see "Results of Operations-Regulatory Matters-Rate Mechanisms-Depreciation Study," below);

· a $1.0 million increase in income from gas storage operations; and

· a $0.6 million increase in other income reflecting income from equity investments.

Partially offsetting the above factors were:

· a $1.4 million increase in interest charges reflecting higher balances of long-term debt outstanding;

· a $0.7 million increase in general taxes due to higher payroll taxes; and

· a $2.8 million decrease in income tax benefit due to higher taxable income.

Nine months ended September 30, 2009 compared to September 30, 2008:

Net income was $43.7 million, or $1.64 per share, for the nine months ended September 30, 2009, compared to $36.3 million, or $1.37 per share, for the same period last year.

The primary factors contributing to the $7.4 million increase in net income were:

· a $22.2 million increase in utility margin from our regulatory share of gas cost savings, reflecting a margin loss of $7.5 million in 2008 compared to a margin gain of $14.7 million in 2009; and

· a $2.4 million increase from a regulatory adjustment for income taxes paid versus collected in rates.

Partially offsetting the above factors were:

· a $9.5 million increase in operations and maintenance expense primarily due to higher expenses for pension, bonus accruals, and health care benefits;

· a $2.4 million increase in interest charges, reflecting higher balances of long-term debt outstanding;

· a $5.6 million increase in income tax expense, primarily due higher taxable income; and

· a $0.9 million increase in general taxes, primarily due to higher payroll taxes.

Dividends paid on our common stock were 39.5 cents per share in the third quarter of 2009, compared to 37.5 cents per share in the third quarter of 2008. In October 2009, the Board of Directors declared a quarterly dividend on our common stock of 41.5 cents per share, payable on November 13, 2009 to shareholders of record on October 30, 2009, increasing the indicated annual dividend rate to $1.66 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, by the pace of growth in the residential and commercial markets in Oregon and southwest Washington 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 September 30, 2009 and 2008 and at December 31, 2008, current and non-current amounts deferred as regulatory assets and liabilities were as follows:

                                                                          Current
                                                          Sept. 30,      Sept. 30,      Dec. 31,
Thousands                                                    2009           2008          2008
Regulatory assets:
Unrealized loss on non-trading derivatives(1)             $   39,428     $  109,012     $ 136,735
Pension and other postretirement benefit obligations(2)        8,074          1,912         8,074
Other(3)                                                      12,804            831         2,510
Total regulatory assets                                   $   60,306     $  111,755     $ 147,319
Regulatory liabilities:
Gas costs payable                                         $   32,823     $   10,263     $   5,284
Unrealized gain on non-trading derivatives(1)                 13,924          5,131         4,592
Other(3)                                                      10,349          8,488        10,580
Total regulatory liabilities                              $   57,096     $   23,882     $  20,456

                                                                        Non-Current
                                                          Sept. 30,      Sept. 30,      Dec. 31,
Thousands                                                     2009           2008          2008
Regulatory assets:
Gas cost receivable                                       $        -     $      278     $       -
Unrealized loss on non-trading derivatives(1)                  1,660         11,300        21,646
Income tax asset                                              75,931         69,547        69,948
Pension and other postretirement benefit obligations(2)      107,815         25,728       113,869
Environmental costs - paid(4)                                 44,188         33,610        36,135
Environmental costs - accrued but not yet paid(4)             55,623         31,049        29,969
Other(3)                                                      11,597         11,156        16,903
Total regulatory assets                                   $  296,814     $  182,668     $ 288,470
Regulatory liabilities:
Gas costs payable                                         $    2,539     $        -     $   1,868
Unrealized gain on non-trading derivatives(1)                  3,711            195           146
Accrued asset removal costs                                  235,891        219,095       223,716
Other(3)                                                       2,174          2,637         2,427
Total regulatory liabilities                              $  244,315     $  221,927     $ 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) 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.

(4) 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.

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, gas purchases 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 2009, the OPUC and WUTC approved rate changes effective on November 1, 2009 under our PGA mechanisms. The effect of the rate changes was to decrease the average monthly bills of Oregon residential customers by 18 percent, partially offset by an increase of 2 percent in the public purpose charge, and to decrease the bills of Washington residential customers by 22 percent.

Under the current Oregon PGA incentive sharing mechanism, 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 incentive sharing is either 20 percent or 10 percent, respectively. In addition to the gas cost incentive sharing mechanism, we are also subject to an annual earnings review to determine if the utility is earning over an allowed threshold. If utility earnings exceed a specific earnings threshold level, then 33 percent of the amount above the threshold will be deferred for refund to customers. Under this provision, if we select the 80 percent deferral option, then we retain all of our earnings up to 150 basis points above the currently authorized return on equity (ROE). If we select the 90 percent deferral option, then we retain all of our earnings up to 100 basis points above the currently authorized ROE. We selected the 80 percent deferral option for the 2008-2009 PGA year. The earnings threshold after . . .