220 NW Second Avenue Portland, Oregon 97209 www.nwnatural.com Investing in growth 2003 Annual Report Corporate Information Common Stock Prices The Company’s common stock is listed and trades on the New York Stock Exchange using the symbol NWN. The quarterly high and low trading range during 2002 and 2003 was: Shareholder Information WASHINGTON Astoria Mist Vancouver Portland Molalla The Dalles Salem Lincoln City Newport Albany Eugene Coos Bay OREGON Legend Williams Gas Pipeline NW Natural gas transmission line Kelso Beaver (KB) Pipeline Proposed pipelines to Molalla and Coos Bay Service territory LNG plant District offices Mist underground storage Corporate Profile NW Natural is a 145-year-old natural gas local distribution company headquar- tered in Portland, Oregon. The Company has added customers at a rate of 3 percent or more per year for 17 consecutive years. NW Natural serves more than 578,000 customers in Oregon and southwest Washington, including the Portland- Vancouver metropolitan area, the Willamette Valley, the northern Oregon coast and the Columbia River Gorge. More than 200,000 customers have been added to NW Natural’s distribution system in the past 10 years. In keeping with its steady growth, the Company has increased annual dividends paid to shareholders every year for 48 con- secutive years. NW Natural purchases natural gas for its core market from a variety of suppliers in the western United States and Canada. In addition, the Company operates an underground gas storage facility in Columbia County, Oregon, and leases additional gas storage outside its service area. NW Natural operates two liquefied natural gas plants in its service area. The Company also is active in the interstate storage services market, providing storage capacity to Northwest energy companies that has been developed in advance of its need for core customers. On the cover: Twenty-four-inch diameter pipe to be used for NW Natural’s South Mist Pipeline Extension in a staging area south of Portland prior to installation. (See page 12) Financial Briefs Earnings Financial facts ($000): 2003 2002 Percent increase (decrease) Net operating revenues Net income Earnings aplicable to common stock 288,066 45,983 45,689 287,544 43,792 41,512 Financial ratios (%): Return on average common equity Capital structure at year-end Long-term debt Preferred stock Common stock equity Common stock Shareholder data: Common shareholders Average shares outstanding (000) Per share data ($): Basic earnings Diluted earnings Dividends paid on common stock Book value at year-end Market value at year-end Operating highlights 9.3 49.7 – 50.3 9,695 25,741 1.77 1.76 1.27 19.52 30.75 Gas sales and transportation deliveries (000 therms): Degree-days (25-year average, 4,238) Customers at year-end Number of utility employees 1,099,752 3,952 578,150 1,291 Dividends paid on common stock Payment date (per share) February 15 May 15 August 15 November 15 Total dividends paid 2003 $ 0.315 $ 0.315 $ 0.315 $ 0.325 _________ $ 1.270 _________ _________ 8.7 47.6 0.9 51.5 10,026 25,431 1.63 1.62 1.26 18.85 27.06 1,126,084 4,232 560,067 1,261 2002 $ 0.315 $ 0.315 $ 0.315 $ 0.315 _________ $ 1.260 _________ _________ 0 5 10 6 (3) 1 9 9 1 4 14 (2) (7) 3 2 DIVIDENDS PAID PER SHARE IN DOLLARS $1.27 $1.26 $1.25 $1.24 $1.23 $1.22 $1.21 $1.20 $1.19 $1.18 $1.17 98 99 00 01 02 03 In 2003, NW Natural increased its annual dividends paid per share for the 48th consecutive year, a growth record matched by few companies. EARNINGS PER SHARE IN DOLLARS $2.00 $1.75 $1.50 $1.25 $1.00 $0.75 $0.50 $0.25 98 99 00 01 02 03 DILUTED EARNINGS PER SHARE REDUCTION IN EARNINGS PER SHARE FROM INVESTMENT WRITEDOWNS: – 50 cents per share in 1998 due to asset impairment charges – 33 cents per share in 2002 due to a loss for PGE acquisition costs Diluted earnings were $1.76 per share in 2003, up 9 percent from $1.62 per share in 2002. y r e g a m I k c o t S x e d n I / d n u e r F d u B o t o h P 0 1 p n o t a e B e c u r B s r e c i f f O & d r a o B , r e t t e L l r e d o h e r a h S / t i a r t r o P d n a l r o B e i l r a h C y h p a r g o t o h P e r u t a e F s n o i t u o S l c i h p a r G n g i s e D k c o t s d e l c y c e r n o d e t n i r P r e t n e C s t r A c i h p a r G g n i t n i r P n g i s e D n o e h p a r G n o i t c u d o r P Notice of Annual Meeting The 2004 Annual Meeting will be held at 2 p.m. Thursday, May 27, at the DoubleTree Hotel Portland–Lloyd Center, Lloyd Center Ballroom, 1000 NE Multnomah, Portland, Oregon. A meeting notice and proxy state- ment will be sent to all shareholders in mid-April. Request for Publications The following publications may be obtained without charge by contacting the Corporate Secretary: Annual Report Form 10-K Form 10-Q Corporate Governance Standards Code of Ethics These publications, as well as other filings made with the Securities and Exchange Commission, also are available on NW Natural’s web site at www.nwnatural.com. Stock Transfer Agent and Registrar Effective March 22, 2004, for all Common Stock Issues: American Stock Transfer & Trust Company 59 Maiden Lane New York, NY 10038 Telephone: (888) 777-0321 Internet: www.amstock.com E-mail: info@amstock.com Trustee, Conversion and Interest Paying Agent For Convertible Debentures: The Bank of New York Corporate Debt Operations, Floor 7-E 101 Barclay Street New York, New York 10286 (800) 548-5075 Trustee and Bond Paying Agent For all bond issues: DB Services Tennessee Inc. Security Holder Relations P.O. Box 305050 Nashville, Tennessee 37230 (800) 735-7777 2003 Quarter 1 2 3 4 2002 Quarter 1 2 3 4 High 28.47 28.88 30.10 31.30 High 28.50 30.30 30.20 30.70 Low 24.05 24.77 27.02 28.51 Low 24.20 27.60 23.46 25.50 Dividend Reinvestment Plan Common shareholders of record may reinvest all or part of their dividends in additional shares under the Company’s plan. Cash purchases also may be made at the current market price under this plan, and no brokerage fees will be charged. A prospectus will be sent to any registered shareholder on request. Dividend Payment Dates February 13, 2004 May 14, 2004 August 13, 2004 November 15, 2004 Quarterly Financial Information (unaudited) Dollars (thousands except per share amounts) March 31 –———————––––— Quarter ended –––––———————— Dec. 31 Sept. 30 June 30 2003 Operating revenues Net operating revenues Net income (loss) Basic earnings (loss) per share Diluted earnings (loss) per share 2002 Operating revenues Net operating revenues Net income (loss) Basic earnings (loss) per share Diluted earnings (loss) per share $206,539 98,588 26,404 1.03 1.01 $278,563 110,666 34,447 1.34 1.32 $117,489 58,549 4,462 0.17 0.17 $101,873 56,564 (2,992) (0.14) (0.14) $69,481 39,465 (6,546) (0.25) (0.25) $78,717 38,059 (6,008) (0.26) (0.26) $217,747 91,464 21,663 0.84 0.83 $182,223 82,255 18,345 0.70 0.69 Total $611,256 288,066 45,983 1.77* 1.76* $641,376 287,544 43,792 1.63* 1.62* *Quarterly earnings per share are based upon the average number of common shares outstanding during each quarter. Because the average number of shares outstanding has changed in each quarter shown, the sum of quarterly earnings (loss) per share may not equal earnings per share for the year. Variations in earn- ings between quarterly periods are due primarily to the seasonal nature of the Company’s business. James R. Boehlke Investor Relations (503) 721-2451 (800) 422-4012, Ext. 2451 Linda R. Williams Shareholder Services (503) 220-2590 (800) 422-4012, Ext. 3402 jrb@nwnatural.com lrw@nwnatural.com NW Natural 220 N.W. Second Avenue Portland, Oregon 97209 (503) 226-4211 (800) 422-4012 www.nwnatural.com Contact the NW Natural Board Concerns may be directed to the non-management directors as follows: ■ Call 1-800-541-9967, or ■ Write to NW Natural Board of Directors, c/o Corporate Secretary, or ■ Email Directors@nwnatural.com Forward-looking Statements NW Natural’s future operating results will be affected by various uncertainties and risk factors, many of which are beyond the Com- pany’s control, including governmental policy and regulatory action, the competitive environment, economic factors and weather conditions. Some statements in this annual report may be forward-looking, and actual results may differ materially as a result of these uncertainties. For a more complete description of these uncertainties and risk factors, please refer to the Company’s filings with the Securities and Exchange Commis- sion on Forms 10-K and 10-Q. Contents Customer Growth Despite a weak economy, NW Natural grew its customer base by more than 3 percent in 2003, a rate more than double the national average. At the same time, the Company improved the profitability of its new customer acquisition. Technology Through employee ingenuity and technical expertise, NW Natural is steadily developing ways to improve productivity and, at the same time, serve customers better. From adapting technology to inventing its own, the Company is becoming more sophisticated in its operations. Page 8 Page 14 Investing in growth Regulation NW Natural’s earnings now are normalized for average weather. Weather normalization and other regulatory outcomes in 2003 have reduced the Company’s business risk. Page 10 1 Community Involvement At NW Natural, good corporate citizenship includes supporting critical programs that make a difference in local communities. The Company also adopted policies in 2003 to step up employee volunteerism. Page 16 Gas Storage With the South Mist Pipeline Extension and growth in interstate storage services, gas storage is becoming an ever-more-important element in the Company’s earnings and customer service. Page 12 Letter to Shareholders . . . . . . . . . . . . . . . . . . . . . 2 Interview with the Executive Vice President . . . . 5 Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Management’s Discussion & Analysis . . . . . . . . 19 Report of Independent Auditors . . . . . . . . . . . . . 30 Financial Statements . . . . . . . . . . . . . . . . . . . . . 31 Notes to Financial Statements . . . . . . . . . . . . . . 35 Eleven-Year Financial Review . . . . . . . . . . . . . . 46 Board of Directors . . . . . . . . . . . . . . . . . . . . . . . 54 Corporate Officers . . . . . . . . . . . . . . . . . . . . . . . 56 Corporate Information . . . . . . . . . . . . . . . . . . . . 57 Letter to Shareholders Sound investment for continued growth ment, weather normalization; ■ completed the first 11.7 miles of the South Mist Pipeline Extension below budget and on time for the 2003-04 heating season; ■ began construction on a natural gas distribution system to serve customers in Coos County, Oregon; ■ maintained high customer satis- faction ratings despite moderate rate increases; ■ expanded our gas storage business, earning 17 cents a share; ■ hit an all-time high stock price of $31.30 a share in December; and ■ increased the dividend on common stock by 3.2 percent, making 2003 the 48th consecutive year in which the Company’s dividend payments have increased. Knowing Who We Are NW Natural continues to focus on the strength of its core business. Over the past few years, we watched other energy companies diversify into unrelated fields, with generally disappointing results. We saw mergers and acquisitions come and go, many of them unsuccessful. We witnessed the rise and fall of Enron and the disappearance of many energy trading businesses. Through it all, NW Natural held true to its course as a growing, thriving natural gas local distribu- tion company. We concentrated on getting even better at what we do best. In considering any new business activity, we made sure it had a clear and direct link to our core competencies. We believe the key to providing high shareholder value is capital- izing on our core strengths. These include: 1. Technical expertise and knowledge of our industry; 2 NW Natural President and Chief Executive Officer Mark Dodson at the entry to Portland’s Classical Chinese Garden, in front of NW Natural headquarters. To Our Shareholders: In 2003, NW Natural built on its fundamental strengths as a natural gas distribution company, with shining results. It was a year devoted to the basics — remembering who we are, planning for the future and invest- ing in growth. During the year, we improved Company processes for adding customers profitably, reduced business risks, invested in both core and non-core business expansion, and set a clear course for the future. In 2003, NW Natural: ■ earned $1.76 a diluted share, within the range of our targeted earnings for the year; ■ added 18,083 customers, an increase of 3.2 percent, marking NW Natural’s 17th consecutive year of achieving customer growth at a rate of more than 3 percent; ■ successfully concluded the Com- pany’s Oregon general rate case, achieving recovery of higher costs for a wide range of expenses such as pension, health care and insurance, and, in a major positive develop- 2. A thorough understanding of our customers’ needs, and what it takes to satisfy them; 3. An ability to creatively and cost-effectively deploy technology; 4. Relentless pursuit of cost management; 5. Constructive regulatory relationships; and 6. A company-wide orientation to profitable growth. Aggressive but Profitable Growth Unlike natural gas LDCs in other parts of the country, NW Natural still has a relatively low market share — approximately 45 to 50 percent in the residential and commercial markets. At the same time, the vast majority of energy consumers continue to list natural gas as their fuel of choice. Our challenge is to capture this growth potential and increase our customer base without spending too much to do it. In recent years we have refined our processes for identifying opportunities to add customers and to bring revenue growth to the bottom line. The Company is improving the profitability of its customer growth in two ways: First, by becoming more savvy and sophisticated in targeting potential new customers. GAS SALES AND TRANSPORTATION DELIVERIES IN MILLIONS OF THERMS 1,350 1,200 1,050 900 750 600 450 300 150 93 94 95 96 97 98 99 00 01 02 03 RESIDENTIAL, COMMERCIAL AND INDUSTRIAL FIRM SALES INDUSTRIAL INTERRUPTIBLE SALES TRANSPORTATION Gas sales and transportation deliveries were 1.1 billion therms in 2003. In 2003, we refined our model for analyzing potential new customers to assure that we are pursuing only those we can acquire profitably. Second, NW Natural has reduced the cost of acquiring new customers. Over the past three years, our employees have lowered con- struction costs per customer by 17 percent through such means as joint trenching with other utilities and the development of new tech- nologies. This year, NW Natural pioneered the use of keyhole tech- nology for residential conversions — an approach that dramatically reduces the costs of installing a service by minimizing disruption to street surfaces. The Company’s disciplined approach to growth is paying off. Over the past few years, we have increased the profitability of our new customer additions signifi- cantly, and we believe we can do even better in the future. Reducing Business Risks Results of the Company’s Oregon general rate case included a mile- stone for NW Natural: weather normalization. The new WARM (Weather Adjusted Rate Mecha- nism) program, implemented in October, helps remove one of the major uncertainties in year-to-year earnings: weather variability. It gives us the ability to adjust customers’ wintertime bills to reflect normal vs. actual weather. WARM assures that NW Natural customers pay only what it costs the Company to serve them — no more and no less. In the process, it provides for a more stable and predictable earnings stream. Weather normalization is the perfect complement to another rate mechanism approved by Oregon regulators in 2002—the conservation tariff—which also smoothes earnings variability. The tariff protects NW Natural from much of the revenue lost when customers use energy more effi- ciently and in declining amounts. The conservation tariff stabilizes CUSTOMER GROWTH IN THOUSANDS 30 25 20 15 10 5 93 94 95 96 97 98 99 00 01 02 03 The Company added 18,083 new customers in 2003. The customer base has grown at an average annual rate of 4.5 percent over the past 10 years. margin revenues while helping to align the Company’s financial in- terests with customers’ conserva- tion goals. We believe NW Natural is the only natural gas distribution company in the nation that has both weather and consumption normalization. Prudent Investment In 2003, we made significant in- vestments in our future growth. The fourth quarter was a particularly busy time for construction projects that had been years in the planning. In March, NW Natural obtained the site certificate necessary to build a 62-mile extension of the 24-inch pipeline that extends from the Mist gas storage field to areas west and south of Portland. The pipeline is critical to NW Natural’s future growth, in that it enables us to serve burgeoning areas in and around the Portland metropolitan area. The Company’s project team and contractors completed the first 11.7 miles of the project under budget and nearly a month early, and had begun work on the next segment by year-end. We expect to have the entire pipeline operational in time for the 2004-05 heating season. Once completed, it will double our capacity to move natural gas into and out of Mist storage. At the same time, on the southern Oregon coast, the Company began 3 commissions in 2004 with detailed plans and resource needs for meeting pipeline safety mandates. Assuring Continued Success Going forward, your company is in a superb position to grow and prosper. Investors are seeing the value in lower-risk, higher-payout companies like NW Natural. While we are ideally positioned in today’s marketplace, we want to make sure that NW Natural will continue to be an investment of choice if the market shifts again. Our preparation for future growth will help assure continued strong performance in the years ahead. In closing, I would like to thank you for the honor and privilege of serving as CEO at NW Natural. In completing my first year in that role, I can confidently tell you: You have invested in a truly fine company. It is a standout in the region and a leader in its industry. I can also tell you that I have never seen a more dedicated, tal- ented group of employees than those at NW Natural. Whether helping out at the Food Bank or restoring heat in freezing tempera- tures, they are as committed a workforce as you will ever find. Thank you for your continued confidence in us. We look forward to another great year in 2004. Sincerely, Mark S. Dodson President and Chief Executive Officer March 31, 2004 4 building a local distribution system to serve Coos County, an area we have wanted to serve for more than 30 years. Funding from state and local sources made it possible for Coos County to build a pipeline over the mountains to connect with the interstate pipeline. In 2003, while the county was constructing the transmission line to link to the interstate pipeline, we were building the local distribution system. Completion of that system in 2004 will allow us to finally serve this county of 63,000 people. Setting Our Course for the Future In 2003, Company officers and employees completed a compre- hensive strategic planning process to map NW Natural’s course for the next several years. Nearly 100 em- ployees were involved in planning teams, research activities, focus groups and strategy development. The result was an ambitious new agenda for ramping up customer growth while also adding to Com- pany profits. Key strategies include: ■ further improving NW Natural’s ability to add customers profitably, and at a faster rate; ■ maintaining our reputation for exemplary service; ■ reducing business risks; ■ managing all costs, including capital; ■ holding all employees to high performance standards; and ■ judiciously growing beyond our local distribution business, where it complements our core assets and competencies. Primary opportunities for non- core growth are distributed energy and interstate gas storage services. We plan to develop and promote the market for combined heat and power and gas cooling technologies, primarily through partnerships for small projects. We will also analyze and target potential large cogenera- tion customers near our system. The Company is continuing to grow interstate storage services from within the core utility, as authorized by the Federal Energy Regulatory PROFITABILITY OF NEW RESIDENTIAL CUSTOMER ACQUISITIONS IN % ROE 14% 12% 10% 8% 6% 4% 2% 00 01 02 03 NW Natural has improved its return on equity from new resi- dential customers in the past three years by targeting the most profit- able customers and managing main extension costs. Commission. NW Natural’s gas storage business contributed 17 cents a share of earnings in 2003, compared to 14 cents a share in 2002. Storage capacity is being expanded incrementally and timed according to market demand. NW Natural will continue to make use of its core gas distribution system capacity to transport gas from the Mist storage field to the interstate system. Our goal is for interstate storage and related services to contribute 10 percent of corporate earnings by 2006. Challenges Ahead With the Company’s recent regu- latory successes, we have eliminated major uncertainties from our year- to-year earnings — in particular, weather variability and declining energy use. Minimizing these business risks puts NW Natural in a better position to deal with the issues to come. In the next few years, we think the most challenging external factors for NW Natural will be: 1) the pace and magnitude of economic recovery in the Pacific Northwest; and 2) the costs of complying with the federal 2002 Pipeline Safety Improvement Act. We will approach our regulatory Providing low-cost supplies Interview with Mike McCoy, Executive Vice President How have natural gas prices changed over the past year? Mr. McCoy: Nationally, we’re seeing continued volatility in gas prices because of the tight balance between supply and demand. That makes for a highly sensitive market. Even relatively small events — such as weather changes and plant shutdowns — can move the market. We’ve seen prices come down from where they were two years ago, but they are still relatively high. We expect the volatility to continue until there is a significant increase in supplies or a decrease in demand. How do your prices compare to your competitors’? Mr. McCoy: Despite commodity cost increases in the past few years, we are still able to sell natural gas in our service area with a significant price advantage compared to electricity. Our prices are competitive with heating oil as well. One way we keep our prices down is through our gas hedging strategies, which allow us to lock in our costs and minimize the Company’s exposure to daily, monthly and seasonal price volatility. What’s the gas supply picture for NW Natural? Mr. McCoy: Our gas supply picture is very positive, for several reasons. Most of our supplies are committed under multi-year contracts with reputable companies. We also own or contract for storage at five regional facilities, which together can supply more than half of our peak day requirements. Finally, Oregon and Washington regulators have been supportive of our long-term gas supply planning and contracting practices, which encourage stability and reliability. How does gas storage benefit the Company and its customers? Mr. McCoy: The primary advantage is that it helps us keep prices down. We purchase and store gas in the summer, typically when it’s less expensive, and use it to help meet peak loads in the winter, when gas is in higher demand and usually more expensive. By using stored gas in the winter we can reduce the amount of year-round pipeline capacity we must purchase for our customers’ needs. What growth opportunities does the Company see in gas storage or gas commodity services? Mr. McCoy: We are very optimistic about the prospects for growing our storage business, which includes two activities: interstate storage services, and asset optimization. The year 2003 was a good one for 5 Mike McCoy, Executive Vice President, Customer and Utility Operations, stands at the newly improved Molalla Gate Station, where the South Mist Pipeline Extension connects to the interstate pipeline. asset optimization, but looking ahead, we expect inter- state storage services to provide most of the earnings from this segment. Our Mist storage field will continue to be our primary focus for gas storage activities. However, NW Natural is considering whether to look more broadly at other storage opportunities. We are not planning to offer gas commodity trading services. Besides moving gas from storage, are there other benefits from the Company’s construction of the South Mist Pipeline Extension (SMPE)? Mr. McCoy: Yes. When complete, the SMPE will increase the takeaway capacity from Mist storage for both core customers and customers on the interstate pipeline system. It will provide a second direct connec- tion between our storage fields and Williams Gas Pipeline, which will allow us to increase injections as the field is expanded. Finally, the SMPE will reinforce our existing distribution system in the Portland area, helping to assure the safe and reliable delivery of natural gas to our customers. 6 Laying the foundation for future success 7 Nothing is more fundamental to a natural gas utility than pipelines. In 2003, NW Natural made major strides in expanding its distribution network (including the first phase of the South Mist Pipeline Extension, shown here) to serve current and future customers. But physical infrastructure is only one part of the Company’s service. Equally important are the right plans, processes and people. NW Natural is focused on growing its customer base and increasing returns to shareholders. To achieve those goals, the Company is refining its strategies, improving its operations and empowering its employees. With all forces pulling in the same direction, increased levels of profitable growth become achievable. Having the pipes is one thing. Having the people is another. NW Natural is investing in both to continue its 145-year legacy of superior service and industry-leading growth. Profitably growing our customer base Despite a slow economy, NW Natural met or nearly met its customer growth goals in every market segment in 2003. The Company added 18,083 customers during the year, for an increase of 3.2 percent. Residential new construction leads the way New construction in the residential market was the strongest growth sector for the Company, as 8 builders and first-time homebuyers continued to respond to low interest rates. Within NW Natural’s service area, Clark County, Washington, continues to have the highest growth rate. As the economic recovery picks up steam, robust residential growth is expected in other parts of the Company’s service area as well, particularly on the southern edges of the Portland metropolitan area and in the downtown core, where major multi- family housing projects are under construction. Residential conversions were hurt by the slow economy in 2003. Gas price volatility and job losses discouraged some homeowners from converting their heating systems. In 2003, 5,534 customers converted to gas from electricity or heating oil, compared to 6,209 conversions in 2002. The slow regional economy also meant a lag in commercial activity. Commercial new construction and conversions declined from 2002 but came close to the Company’s 2003 targets. Looking ahead, commercial redevelopment and revitalization are expected to present new growth opportunities for NW Natural. More commercial new construction is expected as well, once the Coos Bay District Manager Cal Grimmer (left) and Field Engineering Technician Lee Hockema review plans for laying natural gas pipe to serve the new Wal-Mart in Coos Bay, which will convert from propane to natural gas service. currently high vacancy rates for commercial devel- opment are reduced. the laborious manual processes required by the old system. NW Natural is also reducing construction costs. Over the past three years, employees lowered con- struction costs per customer by 17 percent, mainly through new technologies and improved processes. NW Natural’s market share in multifamily new construction (like the subdivision on Portland’s west side, shown below), has grown from 9 percent in 1996 to more than 70 percent in 2003. 9 In the industrial sector, the Company met its targets for 2003. The main opportunity for NW Natural in this sector is the development of the generation market, both large and small. Keeping Growth Profitable In 2003, NW Natural improved the profitability of its new customer acquisitions by targeting the most profitable sectors and customers for growth, and by more carefully managing main extensions. The Company is currently growing mostly along its existing distribution system. It has reduced the level of investment in main extensions, and is now targeting only those extensions that offer high levels of prof- itability. NW Natural is increasingly focused on batch customer acquisi- tions, rather than acquiring cus- tomers one at a time. The Company has refined its information systems to improve the accuracy and availability of information on both the cost side and revenue side of profitability analysis. In 2004, the Company will be installing a more sophisticated informa- tion system to replace Improving predictability of earnings of large commercial and industrial customers’ rates, developed with representatives of customer groups, that was implemented in late 2003. Many industrial customers saw their rates drop as a result of the restructuring. Altogether, the OPUC approved about $13.9 mil- lion per year in rate increases for NW Natural and an authorized return on equity of 10.2 percent. Weather Adjusted Rate Mechanism (WARM) The OPUC’s approval of WARM marked the start of a new chapter in NW Natural’s history. The weather normalization mechanism helps protect the Company from lower earnings due to warmer-than-average weather. Like the conserva- tion tariff, which protects Company revenues NW Natural’s earnings have typically fluctuated with weather variations, changing consumer usage patterns and the costs associated with major capital investments. In 2003, NW Natural secured regulato- ry changes that will help reduce its earnings variability from all of these factors. Adjusting for corporate expenses In August 2003, the Public Utility Commission of Oregon approved a general rate case settlement among NW Natural, the OPUC staff and customer groups. In its decision, the OPUC allowed the Company to include in its rates a variety of increased expenses, including insurance, health benefits and pension costs. The Commission authorized NW Natural to hire 20 additional customer service representatives to better serve the Company’s growing customer base. The OPUC also authorized the Company to include in rates the costs for the South Mist Pipeline Extension and a new natural gas distri- bution system in Coos County, once these projects are completed. The settlement further authorized a restructuring 10 from declining usage due to conservation, WARM reduces earnings volatility for NW Natural. Consumer advocates applauded the adoption of WARM because it helps ensure customers pay NW Natural what it costs to serve them — no more and no less. dential customer’s bill monthly. This means that during cold winters, customers will see the benefit of weather normalizing adjustments, rather than waiting for rates to be trued up in the following heating season. Keeping the pipes safe Residential customers were given the opportunity to opt out of WARM, but more than 90 percent of the Company’s Oregon customers were covered by the mechanism in its first year. NW Natural’s sophisticated customer informa- tion system allows the Company to adjust each resi- The natural gas industry faces major costs to comply with new federal pipeline safety regula- tions. The OPUC allowed rate coverage for NW Natural to conduct the research, planning and design work to meet federal pipeline integrity requirements. The Company is developing a detailed plan for compliance. Washington rate case NW Natural filed a general rate case in the state of Washington in November 2003. The filing includes a mechanism for decoupling rev- enues from usage — i.e., separating NW Natural’s margin from the vol- ume of gas sold. The mechanism would have an effect similar to WARM and the conservation tariff in Oregon. If approved by the Washington Utilities and Trans- portation Commission, the new mechanism would insulate investors from the effects of weather extremes in the State of Washington as well as changes in consumption patterns. 11 NW Natural customers Allen and Lois Wheeler enjoy convenience and cost savings by cooking with natural gas. Thanks to the Company’s new weather normalization mechanism, they also will benefit from more stable winter- time bills. Enhancing storage to serve customers What began in 1979 as an exploration near Mist, Ore., for a new peaking resource has grown into one of NW Natural’s and its customers’ most impor- tant assets. Each year, millions of dollars in gas sav- ings flow through to customers as the Company supplements pipeline gas with lower-cost stored gas to meet demand during peak periods. A big win: SMPE site certificate In 2003, NW Natural gained clearance to build a major enhancement to its storage facilities: a 62-mile, 24-inch diameter pipeline that strengthens the links between the storage field and fast-growing neighborhoods in the Portland area. After years of planning, and almost two years after submitting the application, in March 2003 the Company received a site certifi- cate from the Oregon Energy Facility Siting Council for the South Mist Pipeline Extension. Property owners appealed EFSC’s decision to the Oregon 12 Supreme Court, which ruled in favor of NW Natural on Nov. 6. Before making its final decision, the court denied the appellants’ request for a construc- tion stay, thus allowing the Company to begin building the first segment of the pipeline in August 2003. The SMPE will increase gas delivery capacity to the Company’s service area, reinforcing the distri- bution system in rapidly growing parts of the Portland metropolitan area and adding a second connection to the interstate pipeline system. Building in record time On Aug. 18, construction crews began building the 11.7 miles of the South Mist Pipeline Extension between the Molalla gate station and the Aurora Airport south of Portland. The construction project, which benefited from exceptional planning and management along with unusually dry weath- er, was completed three weeks ahead of schedule and approximately $2 million under budget. Gas began flowing through the pipe on Nov. 6. The completion of the SMPE’s first phase and the upgrade of the Willamette Valley Feeder at the end of 2003 positioned the Company well to serve cus- tomers during cold weather conditions in early January 2004, resulting in record system sendout. The improvements allowed NW Natural to provide service at levels required by the Company’s contract with SP Newsprint, which, with the addition of two 40 MW gas-powered turbines, has become NW Natural’s largest volume customer. New wells planned NW Natural continues to plan expansions of its underground storage facilities. In anticipation of a growing customer base — both core and inter- state — the Company expects to install wells at new and existing reservoirs in the Mist storage field. The Company also plans to add equipment at Miller Station, the control center for gas storage at Mist. In 2004, NW Natural will continue to upgrade its infrastruc- ture (below) for injecting and withdrawing natural gas from the Company’s storage reservoirs. The South Mist Pipeline Extension will give SP Newsprint in Newberg a more reliable source of natural gas at the pres- sure needed to run the plant’s gas-fired turbines. Above, Denny Henderson (left), NW Natural’s general manager of industrial/commercial solutions, observes SP operations with Dennis Lakey, SP’s manager of power and utilities. 13 Using technology creatively NW Natural has had roughly the same number of employees for the past 10 years, while adding 200,000 customers. What’s the Company’s secret? Its wise and creative use of technology. In 2003, NW Natural developed and adapted var- ious technologies to serve customers better, reduce costs and work more efficiently. Customer Relationship Management System During the year, NW Natural surpassed most other utilities’ technology by designing its own Cus- tomer Relationship Management System (CRMS). The system integrates programs that previously ran separately. With CRMS, Consumer Services employees can use one integrated system to sign up new customers for service, start the installation process and send new sales leads to vendors and contractors. Marketing staff also can access the system’s integrated database to target promotions to certain market segments. Engineers and distribution crews use CRMS to read system maps, learn about soil conditions and find other information to plan the most cost-effective construction process. A key element of CRMS is an updated Geographical Information System that is one of the most advanced in the utility industry. Keyhole innovation NW Natural’s technological breakthrough of the year was keyhole technology — the arthroscopy of pipe installation — for residential conversions. Crews use keyhole tools to connect service lines to polyethylene gas mains through a 12-inch diameter hole in the street, avoiding the disruption and expense of trenching. This technology, designed for NW Natural based on an employee’s drawing on a napkin, not only saves time and money on service installations, but also allows the Company to serve customers that otherwise would have been unprofitable to connect. Use of keyhole tools elimi- nates the cost of a backhoe and about half a day’s crew time. NW Natural began using keyhole technology in June 2003 on a pilot basis. Since then, the Company has obtained additional sets of tools and has trained employees in several districts. NW Natural also has ordered tools to expand the use of keyhole technol- ogy beyond polyethylene pipe. 14 were equipped with laptop comput- ers, completing the first step in bring- ing computer technology to approxi- mately 600 field employees. In the first quarter of 2004, field employees involved in inspection, engineering and gas supply were “wired” for the first time. Currently, the computers give crews access to Mapframe, which pro- vides detailed maps of the Company’s distribution system. As the year pro- gresses, NW Natural will be able to update Mapframe daily based on data entered by crew members. Ultimately, online construction reports will provide field employees the key information they need to plan the most efficient use of crews and equipment. Computerized informa- tion also will help crews anticipate maintenance needs and assure the long-term safety and reliability of the system. 15 Clark County Distribution Crew Leader Clark Apodaca and Pipe Joiner Wendy McDowell install a new residential service using keyhole technology pioneered by NW Natural. In 2003, NW Natural used keyhole technology to install about 75 services — a number that is expect- ed to grow rapidly in 2004, along with the con- struction cost savings. For example, crews use key- hole tools to install services when a trench would be deep enough to require shoring. Field Office Technology As of Dec. 31, 2003, all NW Natural crew trucks In addition to adopting new technologies, NW Natural regu- larly upgrades its existing technology where needed. Below, LNG Operator Linda Butterfield uses an improved computer system at the Company’s liquefied natural gas plant in Portland. Building community partnerships NW Natural takes pride in being actively involved in the communities it serves. The Company recog- nizes that its success depends on the health and vitality of its service area. In 2003, the Company strengthened its commit- ment to community involvement through new plans and initiatives. New Community Involvement Plan Last year, the NW Natural Board of Directors approved a new Community Involvement Plan. To strengthen the impact of the Company’s charita- ble dollars, the plan focused on one philanthropic priority: Helping Families and Kids at Risk. A high percentage of the Company’s corporate contribu- tions are now funneled to this area. Under the plan, NW Natural is using a new method to determine its annual corporate contributions 16 to the Black United Fund of Oregon, Earth Share and United Way through the Company’s annual Charitable Giving Campaign. In each of its districts, NW Natural will contribute an amount equal to the total employee contributions made to each organi- zation in that district. Employee contributions are matched dollar for dollar up to a limit of $10,000 per employee. The Community Involvement Plan also commits NW Natural to promoting ethnic and cultural diver- sity in the workplace and expanding opportunities for minorities. As a first step, NW Natural entered into a partnership with De La Salle North Catholic High School. De La Salle students (more than 40 percent of whom are African American) earn money to pay most of their tuition through the school’s innovative work-studies program. Four De La Salle students are working at NW Natural during the 2003/2004 school year. Employee volunteerism Last year, the Company ramped up efforts to encourage employees and retirees to volunteer in their communities. To oversee these efforts, NW Natural selected an employee to serve as volunteer coordinator. The coordinator organized an employee volunteer fair in September to kick off the new volunteerism initiative. Some 175 employees attended. As part of its Community Involvement Plan, NW Natural announced it would target one or more agencies for direct dollar contributions and employee volunteerism. In 2003, a year when Oregon ranked number one in hunger among the 50 states, the Company named The Oregon Food Bank as its “Signature Program.” It also chose Habitat for Humanity, The Oregon Children’s Foundation and Tualatin Valley Centers as Programs of Focus. In August, NW Natural placed an insert in its bills asking customers to donate to The Oregon Food Bank. The response far exceeded expectations: Customers sent in more than $124,000. In October, NW Natural helped raise another $291,000 for The Oregon Food Bank as the presenting sponsor of a gala fundraising event with Oregon’s governor. The money the Company raised will help the Food Bank leverage more than $4 million worth of food for distribution in Oregon and affiliated Washington food pantries. By providing its distinctive blue tents for community events, NW Natural becomes a highly visible sponsor of gatherings like the Oregon Jamboree (below), a country music festival held in August in Sweet Home, Oregon. NW Natural employees help Habitat for Humanity construct eight homes for low-income families in September during a nine-day Blitz Build. From left to right are Consumer Services employees Von Summers, Tim Abshire, Phil Damiano, Jeremy Anderson and on rooftop, Darrell Nelson and Lance Cheeley. 17 Glossary Basic earnings per share: earnings applicable to common stock for a period, divided by the average number of shares of common stock actually outstanding during that period. Bcf: one billion cubic feet, a volumetric measure of natural gas, roughly equal to 10 million therms. Book value: the common stock equity on the company’s balance sheet, which was $506 million for NW Natural at year-end 2003. The book value divided by the number of shares of common stock outstanding equals book value per share, or $19.52 for NW Natural at year-end 2003. BTU: British thermal unit, a basic unit of thermal energy measurement. One Btu equals the energy required to raise one pound of water one degree Fahrenheit. One hundred thousand Btus equal one therm. Bypass: a direct connection to the interstate gas pipeline which circumvents the pipes of the local distribution com- pany; usually considered only by large industrial users. CIS: customer information system. NW Natural’s computer- ized CIS is used for customer orders, bills, account histories and collections. Demand charge: a component in all gas rates that covers the cost of securing pipeline capacity to meet peak demand, whether that full capacity is used or not. Deregulation: in the energy industry, a broad term that generally refers to changes in industry structure intended to provide consumers more direct access to competitive forces in the commodity markets. 18 Diluted earnings per share: earnings applicable to com- mon stock for a period, divided by the average number of shares of stock that would be outstanding if all securities convertible into common stock were converted and all options to purchase common stock at prices lower than the average price for the period were exercised. Distributed generation: the generation of electricity on a smaller scale than centralized power stations, using new gas-fired technologies such as fuel cells and micro-turbines for onsite commercial or residential use. DRIP: dividend reinvestment plan enabling participating shareholders to further invest in the Company by directly re- investing dividends into the purchase of additional shares. FERC: Federal Energy Regulatory Commission, the agency with regulatory jurisdiction over interstate natural gas transportation. Firm service: natural gas service offered to customers under contracts or rate schedules that provide for no service inter- ruptions. General rate case: a periodic filing with state regulators to establish equitable rates and balance the interests of all classes of customers with those of the Company and its shareholders. NW Natural’s most recent general rate case was concluded in Oregon in 2003. Interruptible service: service offered to customers (usually large industrial or commercial) under contracts or rate schedules that allow for interruptions during times of peak demand. Heating degree-days: units of measure that reflect temper- ature-sensitive consumption of natural gas, calculated by subtracting the average of a day’s high and low tempera- ture from 65 degrees Fahrenheit. LNG: liquefied natural gas, the cryogenic liquid form of nat- ural gas. At temperatures below minus 258 degrees Fahrenheit, natural gas can be stored in a liquid form which is 600 times more dense than its gaseous form. LDC: a local distribution company, such as NW Natural, that is mainly involved in the final distribution and sale of natural gas to customers. Margin: in NW Natural’s case, the difference between gross sales revenue and the cost of gas included in the sale. Market value: also known as market capitalization. The market value of a company is the number of shares of common stock outstanding multiplied by the market price per share. Mcf: one thousand cubic feet, a volumetric measure of natural gas, roughly equal to 10 therms. Natural gas: a naturally occurring, flammable hydrocarbon found in porous underground formations, primarily consist- ing of methane (CH4). OPUC: the Public Utility Commission of Oregon, a three- member panel appointed by the Governor that has regula- tory authority over public utilities in Oregon. PGA: purchased gas adjustment, or gas tracker, a mecha- nism for adjusting rates due to changes in gas costs and recovering from customers deferred gas cost imbalances caused by fluctuating gas commodity costs. Therm: the basic unit of natural gas measurement, equal to 100,000 Btus. An average residential customer in NW Natural’s service area uses about 662 therms in an average weather year. Throughput: the amount of natural gas transported through a distribution system in any given period. Transportation customer: typically a large industrial cus- tomer that secures its own natural gas supply and pays only for use of the distribution system to transport it. Underground storage: storage of natural gas by injection into underground rock formations for withdrawal during the winter heating season, such as at NW Natural’s Mist storage field. WARM: Weather Adjusted Rate Mechanism, a weather- normalizing rate mechanism approved by the OPUC in 2003 which allows NW Natural to adjust customers’ bills during the heating season to reduce variations in margin recovery due to deviations from average temperatures. WUTC: the Washington Utilities and Transportation Commission, a three-member panel appointed by the Governor that has regulatory authority over public utilities in Washington. Management’s Discussion and Analysis The following is management’s assessment of Northwest Natural Gas Company’s financial condition including the principal factors that affect results of operations. The discussion refers to the con- solidated activities of the Company for the three years ended Dec. 31, 2003. Unless otherwise indicated, references in this discussion to “Notes” are to the notes to the consolidated financial statements. The consolidated financial statements include: Regulated utility: ■ Northwest Natural Gas Company (NW Natural) Non-regulated wholly owned subsidiaries of NW Natural: ■ NNG Financial Corporation (Financial Corporation), and its whol- ly owned subsidiaries ■ Northwest Energy Corporation (Northwest Energy), and its whol- ly owned subsidiary Together these businesses are referred to herein as the “Company” (see “Results of Operations-Non-utility Operations,” 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 the Company’s earnings and are reported net of tax. The Company believes this per share information is useful because it enables readers to better understand the impact of these factors on the Company’s earnings. All references in this report to earnings per share are on the basis of diluted shares (see Note 1). EXECUTIVE SUMMARY Highlights Among its accomplishments in 2003, the Company: ■ grew its utility customer base by more than 3 percent for the 17th year in a row, adding 18,083 customers to its gas distribution sys- tem during the year; ■ increased earnings from its business segment for interstate gas storage services from 14 cents a share in 2002 to 17 cents a share in 2003; ■ secured a permit for the construction of a major extension of its pipeline from the Mist storage field to the Portland metropolitan area and completed the first 11.7-mile segment of the pipeline exten- sion, below budget and on time for the 2003-04 heating season; ■ successfully completed its general rate case in Oregon with a result that included phased rate increases, the recovery of costs relating to its gas storage investments and higher operating expens- es, and approval of a new weather normalization mechanism; ■ secured reliable and adequate gas supplies during a time of volatile wholesale pricing, at costs that required only relatively small rate increases for customers; and ■ paid dividends on common stock of $1.27 a share, making 2003 the 48th consecutive year in which the Company’s dividend pay- ments have increased. Issues, Challenges and Performance Measures Issues and challenges the Company expects to face in 2004 include the effects and uncertainties relating to a general rate case in Washington; volatile gas commodity prices; continuing weak eco- nomic conditions in Oregon and Washington; completion of the remaining portion of the pipeline extension from NW Natural’s Mist gas storage field including the acquisition of rights-of-way necessary to build the pipeline; and higher capital and operating costs due to federal mandates in the area of pipeline integrity. In order to deal with these and other issues affecting the busi- ness, in 2003 NW Natural completed a new strategic plan to map the Company’s course during the next several years. The plan in- cludes strategies for further improving NW Natural’s ability to add customers both profitably and at a rapid pace; maintaining NW Natural’s reputation for exemplary service; reducing business risk; managing all costs, including capital costs; holding all employees to high performance standards; and judiciously growing beyond the Company’s local distribution business where it would complement core assets and competencies. Among the key performance meas- ures the Company will use in monitoring progress against its goals in these areas are utility earnings per share, customer satisfaction ratings, new customer additions, operations and maintenance expense per customer, construction cost per meter connected, and non-revenue producing capital expenditures per customer. EARNINGS AND DIVIDENDS The Company’s earnings applicable to common stock in 2003 were $45.7 million, compared to $41.5 million in 2002 and $47.8 mil- lion in 2001. Earnings were $1.76 a share in 2003, compared to $1.62 a share in 2002 and $1.88 a share in 2001. Net operating revenues in 2003 were about the same as in 2002, but higher amounts for other income ($17 million) in 2003 more than offset higher operating expenses ($14.5 million). Earnings for 2002 were reduced by charges of $13.9 million (before tax) representing the Company’s transaction costs incurred in its efforts to acquire Portland General Electric Company (PGE) from Enron. Excluding these charges, earnings per share from consolidated operations in 2002 would have been $1.95 a share. Earnings for 2001 were the highest on record for the Company. NW Natural earned $1.57 a diluted share from gas utility operations in 2003, compared to $1.76 a share in both 2002 and 2001. Weather conditions in its service territory in 2003 were 7 percent warmer than the 25-year average and 7 percent warmer than 2002. Temperatures in 2002 were very close to average but were 2 percent warmer than 2001. Weather in 2001 was 1 percent colder than average. Results in 2003 from the Company’s non-utility operations were earnings of 19 cents a share, including 17 cents a share from NW Natural’s gas storage business segment and 2 cents a share from sub- sidiary and other non-utility operations (see “Results of Operations – Non-utility Operations,” below). Non-utility results for 2002 were a loss of 14 cents a share, including earnings of 14 cents a share from the gas storage segment, a loss of 33 cents a share relating to the Company’s efforts to purchase PGE, and earnings of 5 cents a share from other subsidiary and non-utility operations. Non-utility results for 2001 were earnings of 12 cents a share, including 8 cents a share from the gas storage segment. For the 48th consecutive year, the Company’s dividends paid on common stock increased in 2003. Dividends paid on common stock were $1.27 a share in 2003 compared to $1.26 a share in 2002 and $1.245 a share in 2001. APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES In preparing the Company’s financial statements using general- ly accepted accounting principles in the United States of America (GAAP), management exercises judgment in the selection and appli- cation of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, rev- enues, expenses and related disclosures in the financial statements. Management considers its critical accounting policies to be those which are most important to the representation of the Company’s financial condition and results of operations and which require man- agement’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially dif- ferent amounts if the Company reported under different conditions or using different assumptions. The Company’s most critical estimates or judgments involve reg- ulatory cost recovery, unbilled revenues, derivative instruments, pension assumptions, and environmental contingencies. Manage- ment has discussed the estimates and judgments used in the appli- cation of critical accounting policies with the Audit Committee of N W N A T U R A L 19 Management’s Discussion and Analysis 20 the Board. The Company’s critical accounting policies and estimates are described below. Regulatory Accounting NW Natural is regulated by the Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC), which establish rules governing the Com- pany’s utility rates and services, and to a certain extent set forth the accounting treatment for certain regulatory transactions. In gener- al, NW Natural uses the same accounting principles as other non- regulated companies reporting under GAAP. However, certain accounting principles, primarily Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” require different accounting treatment for regulated companies to show the effects of regulation. For example, NW Natural accounts for the cost of gas using a deferral and cost recovery mech- anism called the Purchased Gas Adjustment (PGA), which is approved annually by the OPUC and WUTC (see “Results of Operations – Cost of Gas Sold,” below). There are other expenses or revenues that the OPUC or WUTC may require the Company to defer and recov- er or refund in future periods. SFAS No. 71 requires the Company to account for these types of deferred expenses (or deferred rev- enues) as regulatory assets (or regulatory liabilities) on the balance sheet. When NW Natural is allowed to recover these expenses from or refund them to customers, it recognizes the expense or revenue on the income statement at the same time it realizes the adjustment to amounts included in utility rates and charged to customers. The conditions a regulated company must satisfy to apply the accounting policies and practices of SFAS No. 71 include: ■ an independent regulator sets rates; ■ the regulator sets the rates to cover specific costs of delivering serv- ice; and ■ the service territory lacks competitive pressures to reduce rates below the rates set by the regulator. NW Natural applies SFAS No. 71 in accounting for its regulated utility operations. The Company periodically assesses whether it can continue to apply SFAS No. 71. If NW Natural should determine in the future that all or a portion of its regulatory assets and liabil- ities no longer meet the criteria for continued application of SFAS No. 71, then it would be required to write off the net unrecoverable balances of its regulatory assets and liabilities as a charge to income. Revenue Recognition Utility revenues, derived primarily from the sale and transporta- tion of natural gas, are recognized when the gas is delivered to and received by the customer. Revenues are accrued for gas delivered to customers but not yet billed based on estimates of gas deliveries from the last meter reading date to month end (unbilled revenues). Unbilled revenues are dependent upon a number of factors that require management’s judgment, including total gas receipts and deliveries, customer usage patterns and weather. Unbilled revenue estimates are reversed the following month when actual billings occur. NW Natural’s unbilled revenues at Dec. 31, 2003 and 2002 were $59.1 million and $44.1 million, respectively. In November 2003, NW Natural implemented a weather nor- malization mechanism in Oregon that helps stabilize the Company’s net operating revenues by adjusting current customer billings based on temperature variances from average weather (see “Results of Oper- ations – Regulatory Matters – Rate Mechanisms,” below). Non-utility revenues, derived primarily from gas storage services, are recognized upon delivery of the service to customers. Revenues from optimization of excess storage and transportation capacity are recognized over the life of the contract for guaranteed amounts under the contract, or are recognized as earned for amounts above the guaranteed value. Accounting for Derivative Instruments and Hedging Activities The Company’s Derivatives Policy sets forth the guidelines for using selected financial derivative products to support prudent risk management strategies within designated parameters (see Note 1). The policy specifically prohibits the use of derivatives for trading or speculative purposes. The Company’s primary hedging activities consist of natural gas commodity price and foreign currency exchange rate hedges, which are accounted for as cash flow hedges. The Company’s commodity and foreign currency hedge trans- actions are included in the annual PGA mechanism, and as such all gains and losses are subject to regulatory deferral under SFAS No. 71 (see “Regulatory Accounting,” above). The following table sum- marizes the realized gains and losses from NW Natural’s commod- ity and currency hedge transactions in 2003, 2002 and 2001: (Thousands) 2003 2002 2001 Gains (losses) on commodity swap contracts Gains (losses) on commodity option contracts Subtotal Gains on currency contracts Total gains (losses) on commodity and currency contracts $ 29,660 $ (73,922) $ 44,191 13,383 (1,601) 2,723 ________ ________ ________ 57,574 32,383 (75,523) 824 521 4,129 ________ ________ ________ $ 36,512 $ (75,002) $ 58,398 ________ ________ ________ ________ ________ ________ Realized gains (losses) from commodity and foreign currency hedge contracts are recorded as reductions (increases) to the cost of gas and are included in the calculation of annual PGA rate changes. Unrealized gains and losses resulting from mark-to-market valuations are not recognized in current income or other comprehensive income, but are reported as regulatory liabilities or regulatory assets, which are offset by a corresponding balance in non-trading derivative assets or liabilities (see Note 11). Accounting for Pensions NW Natural has two qualified non-contributory defined benefit pension plans covering all regular employees with more than one year of service. These plans are funded through a trust dedicated to providing retirement benefits. Net periodic pension costs and accu- mulated benefit obligations are determined in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” (see “Financial Con- dition – Pension Cost (Income) and Funding Status,” below, and Note 7), using a number of assumptions including the discount rate, the rate of compensation increases, retirement ages, mortality rates and expected long-term return on plan assets. These assumptions have a significant impact on the amounts reported. NW Natural’s pension cost consists of service costs, interest costs, amortization of actuarial gains and losses, expected returns on plan assets and, in part, on a market-related valuation of assets. Variances between expected returns and actual investment returns are recognized over a three- year period from the year in which they occur, thereby reducing year-to-year volatility. The Company considers a number of factors in developing its pen- sion assumptions, including an evaluation of relevant discount rates, expected long-term returns on plan assets, plan asset allocations, expected changes in wages and retirement benefits, analyses of cur- rent market conditions and input from actuaries and other consult- ants. For the Dec. 31, 2003 measurement date, the Company: ■ decreased its discount rate assumption from 6.75 percent to 6.25 percent; ■ lowered its salary and wage increase assumption from a range of 4.25-5.00 percent to a range of 4.00-4.75 percent; and ■ increased its expected long-term return on plan assets from 8.00 percent to 8.25 percent. Changes in these factors were the primary contributors to a net increase in the Company’s accumulated benefit obligation from $172 million at Dec. 31, 2002, to $192 million at Dec. 31, 2003. N W N A T U R A L The Company believes its pension assumptions to be appropri- ate based upon the above factors. However, if the discount rate were changed by one-quarter percentage point, the net periodic pension cost would be changed by approximately $0.6 million. If the expect- ed return on plan assets were changed by one-quarter percentage point, the net periodic pension cost would be changed by approxi- mately $0.4 million. Contingencies The Company records loss contingencies as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties. In the normal course of business, the Company records accruals for loss contingencies based on an analysis of potential results, developed in consultation with outside counsel when appropriate, including allowances for uncollectible accounts, environmental claims and property damage and person- al injury claims. It is possible, however, that future results of oper- ations could be materially affected by changes in assumptions or esti- mates regarding these contingencies. With respect to environmental claims, the Company records receivables for anticipated recoveries under insurance contracts, or from future utility rates, when recov- ery is probable. See Note 12. RESULTS OF OPERATIONS Regulatory Matters NW Natural provides gas utility service in Oregon and Washington, with Oregon representing over 90 percent of its revenues. Future earn- ings and cash flows from utility operations will be determined large- ly by the pace of continued growth in the residential and commer- cial markets and by NW Natural’s ability to remain price competitive in the large industrial market, to control expenses, and to obtain rea- sonable and timely regulatory ratemaking treatment for investments made in utility plant. General Rate Cases In August 2003, the OPUC entered an order covering all of the issues in NW Natural’s first Oregon general rate case since 1999. The order included, among other things, (i) the settlement of NW Natural’s cost of service, including operations and maintenance expenses, (ii) projected investments for the prospective test year, (iii) a capi- tal structure including 49.5 percent common equity, (iv) a return on common shareholders’ equity (ROE) of 10.2 percent, (v) a rate re- design that shifted $4.8 million of margin revenue requirement from industrial rate schedules to residential and commercial rate sched- ules, and (vi) the adoption of a weather normalization mechanism. The order authorized a revenue increase of $13.9 million per year, of which $6.2 million went into effect on Sept. 1, 2003 and $2.8 mil- lion went into effect on a deferred basis on Nov. 12, 2003 as the first 11.7 miles of the Company’s South Mist Pipeline Extension (SMPE) was placed into service. The remainder will go into effect as all or portions of the SMPE project and the Company’s Coos County dis- tribution system project are completed and go into service in 2004 (see “Financial Condition – Investing Activities,” below). NW Natural’s most recent general rate increase in Washington, which was fully effective in October 2001, authorized rates designed to produce an ROE of 10.8 percent. The WUTC approved a revenue increase of $4.3 million per year, or 12.1 percent. In November 2003, NW Natural filed a new general rate case in Washington. The filing proposes a revenue increase of $7.9 million per year from Washington operations through rate increases aver- aging 15 percent. The proposed rates are designed to produce an ROE of 11 percent and to recover increases in NW Natural’s cost of service including costs for expansion of the Mist gas storage system and con- struction of a new service center in Vancouver; higher expenses in areas such as pensions, health benefits and insurance; and revenue declines due to changes in customers’ consumption patterns. NW Natural also is proposing a decoupling mechanism for residential and commercial customers that includes weather normalization, and a re-design of industrial rates. The schedule for the case provides for settlement conferences in April 2004, the filing of WUTC staff and intervenor testimony in May, hearings in July and a decision by the WUTC determining new rates by the end of October 2004. The Company is unable to determine the extent to which its proposals will be accepted by the WUTC. Rate Mechanisms The weather normalization mechanism approved by the OPUC will be applied to NW Natural’s Oregon residential and commercial customers’ bills between Nov. 15 and May 15 of each heating sea- son, beginning November 2003. The mechanism adjusts the mar- gin component of customers’ rates to reflect “normal” weather using the 25-year average temperature for each day of the billing period. The mechanism is intended to stabilize the recovery of fixed costs and reduce fluctuations in customers’ bills due to colder- or warmer- than-average weather. Rate changes are applied each year under the PGA mechanisms in NW Natural’s tariffs in Oregon and Washington to reflect changes in the costs of natural gas commodity purchased under contracts with gas producers (see “Comparison of Gas Operations – Cost of Gas Sold,” below), the application of temporary rate adjustments to amortize balances in regulatory asset or liability accounts and the removal of temporary rate adjustments effective the previous year. In 2003, the OPUC approved a rate increase averaging 3.5 percent for Oregon sales customers and the WUTC approved a rate increase averaging 16.8 percent for Washington sales customers, both effec- tive on Oct. 1, 2003. In 2002, the OPUC approved PGA rate decreas- es averaging 14 percent for NW Natural’s Oregon sales customers and the WUTC approved PGA rate decreases averaging 25 percent for NW Natural’s Washington sales customers, both effective on Oct. 1, 2002. In 2001, the OPUC approved PGA rate increases aver- aging 22 percent for Oregon sales customers and the WUTC approved PGA rate increases averaging 21 percent for Washington sales cus- tomers, both effective on Oct. 1, 2001. In an order issued in 1999, the OPUC formalized a process that tests for excessive earnings in connection with gas utilities’ annual filings under their PGA mechanisms. The OPUC confirmed NW Natural’s ability to pass through 100 percent of its prudently incurred gas costs into rates. Under this order, NW Natural is authorized to retain all of its earnings up to a threshold level equal to its author- ized ROE plus 300 basis points. One-third of any earnings above that level will be refunded to customers. The excess earnings threshold is subject to adjustment up or down each year depending on move- ments in interest rates. No amounts were identified in this process for refund to customers with respect to NW Natural’s earnings results in 2002 or 2001. NW Natural does not expect there will be amounts identified for refund with respect to its earnings in 2003, which will be reviewed by the OPUC in the second quarter of 2004. In 2002, the OPUC approved a rate mechanism designed to sta- bilize margin revenues in the face of above- or below-normal con- sumption patterns. NW Natural believes that reductions in recent years in its customers’ gas consumptions per degree-day (see “Comparison of Gas Operations – Residential and Commercial,” below) were caused by increases in the cost of purchased gas that were passed on to customers as rate increases, and to efforts through- out the region to conserve energy. The mechanism adjusts for rate changes according to the impact of price elasticity, starting with small increases to residential and commercial rates that became effective on Oct. 1, 2002. These rate changes contributed an estimated $3.5 million of margin, equivalent to 8 cents a share of earnings, dur- N W N A T U R A L 21 Management’s Discussion and Analysis ing the fourth quarter of 2002 and an estimated $6.5 million of mar- gin, equivalent to 15 cents a share of earnings, during the first eight months of 2003 before the Oregon general rate increase took effect. In addition, the OPUC authorized NW Natural to implement a partial decoupling mechanism effective Oct. 1, 2002. Decoupling mechanisms are used to break the link between a utility’s earnings and the energy consumed by its customers so the utility does not have an incentive to discourage customers’ conservation efforts. The decoupling mechanism works by adding margin revenues dur- ing periods when customer consumptions are lower than baseline consumption or by deducting margin revenues when consumptions are higher than the baseline. Under the partial decoupling mecha- nism, NW Natural uses a balancing account to defer and subse- quently amortize 90 percent of the margin differentials between baseline usage by its residential and commercial customers and weather-normalized actual usage by these customers. The deferred amounts are treated as adjustments to be refunded or collected in future periods. Baseline consumption is based on customer con- sumption patterns determined in the Oregon general rate case, adjusted for consumptions resulting from new customers. The par- tial decoupling mechanism will expire at the end of September 2005 unless the OPUC approves an extension based on the results of an independent study to measure the mechanism’s effectiveness. In connection with the OPUC’s approval of the decoupling mech- anism, NW Natural agreed to adopt certain service quality measures that establish the Company’s performance goal for minimizing com- plaints by customers where the Company is determined to be at fault. If NW Natural exceeds the prescribed level of at-fault com- plaints, it will be subject to penalties. NW Natural was not subject to penalties relating to these measures in 2003. Comparison of Gas Operations The following table summarizes the composition of gas utility vol- 22 umes and revenues for the three years ended Dec. 31: (Thousands, except customers and degree-days) 2003 2002 2001 Utility gas sales and transportation volumes – therms: Residential and commercial sales Unbilled volumes 569,791 12,099 ________ 597,246 (6,617) ________ 592,358 1,771 ________ Weather-sensitive volumes Industrial firm sales Industrial interruptible sales Total gas sales Transportation deliveries Total volumes sold and delivered 581,890 53% 590,629 52% 594,129 53% 7% 55,314 47,994 6% ________ _____ ________ _____ ________ _____ 685,198 62% 680,085 60% 737,504 66% 414,554 38% 445,999 40% 385,783 34% ________ _____ ________ _____ ________ _____ 5% 63,215 4% 26,241 6% 79,778 2% 63,597 1,099,752 100% 1,126,084 100% 1,123,287 100% ________ _____ ________ _____ ________ _____ ________ _____ ________ _____ ________ _____ Utility operating revenues – dollars: Residential and commercial sales Unbilled revenues $ 504,849 14,474 ________ $ 556,210 (12,702) ________ $ 520,141 13,774 ________ Weather-sensitive revenues Industrial firm sales Industrial interruptible sales Total gas sales Transportation revenues Other revenues Total utility operating revenues Cost of gas sold Utility net operating revenues (margin) 6% 42,965 4% 15,937 519,323 86% 543,508 86% 533,915 84% 8% 33,578 5% 23,661 ________ _____ ________ _____ ________ _____ 576,562 96% 602,410 95% 617,860 97% 3% 3% 26,020 17,962 – 4,018 1% 7,460 ________ _____ ________ _____ ________ _____ 4% 20,637 1% (2,325) 7% 49,662 2% 34,283 $ 601,984 100% $ 632,448 100% $ 636,172 100% ________ _____ ________ _____ ________ _____ ________ _____ ________ _____ ________ _____ $ 323,128 ________ ________ $ 364,699 ________ ________ $ 353,034 ________ ________ $ 278,856 ________ ________ $ 279,414 ________ ________ $ 271,473 ________ ________ Total number of customers (end of period) Actual degree-days 25-year average degree-days 578,150 ________ ________ 3,952 ________ ________ 4,238 ________ ________ 560,067 ________ ________ 4,232 ________ ________ 4,257 ________ ________ 540,931 ________ ________ 4,325 ________ ________ 4,267 ________ ________ NW Natural refunded deferred gas cost savings to its Oregon cus- tomers through billing credits in June 2002. These refunds were the customers’ 67 percent portion of gas cost savings realized between October 2001 and March 2002, which had been deferred, with inter- est, pursuant to NW Natural’s PGA tariff in Oregon (see “Cost of Gas Sold,” below). The refunds reduced gross operating revenues dur- ing 2002 by $30.4 million, and reduced both cost of gas and deferred gas costs payable by $29.5 million. The refunds also reduced margin by about $0.9 mil- lion, but this amount was almost entirely offset by corresponding reductions in franchise tax expense and uncollectible accounts expense such that the effect of the refunds on net in- come was negligible. Residential and Commercial Sales WEATHER-SENSITIVE OPERATING REVENUES AND DEGREE-DAYS IN MILLIONS OF DOLLARS 3,952 degree- days 4,325 degree- days 4,232 degree- days $550 $575 $525 $500 $475 $450 $425 $400 $544 $534 $519 01 02 03 WEATHER-SENSITIVE REVENUES DEGREE-DAYS NW Natural continued to grow its customer base, with a net increase of 18,083 customers during 2003. This represents a growth rate of 3.2 percent, com- pared to 3.5 percent in 2002 and 3.3 percent in 2001. In the three years ended Dec. 31, 2003, more than 54,000 customers were added to the system, rep- resenting an average annual growth rate of 3.5 percent. Weather-sensitive operating reve- nues have been at record levels over the past three year period. Weather conditions in 2003 were 7 percent warmer than the 25-year average. The volumes of gas sold to residential and commercial customers were 1 percent lower in 2003 than in 2002, reflecting warmer weath- er that was partially offset by customer growth and the price elas- ticity effects of lower rates. Related revenues were 4 percent lower in 2003 than in 2002. Excluding the impact of gas cost refunds total- ing $30.4 million to Oregon customers during 2002, related rev- enues were $54.6 million, or 10 percent, lower in 2003 than in 2002, primarily due to lower rates effective Oct. 1, 2002 (see “Regulatory Matters – Rate Mechanisms,” above). The volumes of gas sold to res- idential and commercial customers were 1 percent lower in 2002 than in 2001, reflecting warmer weather as well as lower consumption patterns by customers due to higher gas commodity prices includ- ed in rates in previous years. Excluding the impact of the refunds to Oregon customers during 2002, related revenues increased 7 per- cent, primarily due to PGA rate increases effective Oct. 1, 2001. Typically, 80 percent or more of NW Natural’s annual operating revenues are derived from gas sales to weather-sensitive residential and commercial customers. Accordingly, variations in temperatures between periods will affect volumes of gas sold to these customers. Weather conditions in 2003 were 7 percent warmer than average. Temperatures were very close to average in 2002 and 1 percent cold- er than average in 2001. Weather in 2003 was 7 percent warmer than 2002 and 2002 was 2 percent warmer than 2001. Average weath- er conditions are calculated from the most recent 25 years of tem- perature data measured by heating degree-days. In November 2003, NW Natural implemented a weather nor- malization mechanism that will be applied to Oregon residential and commercial customers’ bills between Nov. 15 and May 15 of each heat- ing season (see “Regulatory Matters – Rate Mechanisms,” above). Customers may opt out of the mechanism during a defined period each year; less than 10 percent of NW Natural’s Oregon residential N W N A T U R A L and commercial customers opted out during its first heating season. The mechanism contributed $2.1 million of margin in the fourth quarter of 2003 due to warmer-than-average weather. The contribu- tion was equivalent to 5 cents a share of earnings, making up a sig- nificant portion of the weather-related margin loss in that quarter. In order to match revenues with related purchased gas costs, NW Natural records unbilled revenues for gas delivered and sold to customers, but not yet billed, through the end of the period. Amounts reported as unbilled revenues reflect the increase or decrease in the balance of unbilled revenues over the prior year-end. Weather con- ditions, rate changes and customer billing dates from one period to the next affect year-end balances. Industrial Sales and Transportation The following table summarizes the delivered volumes and util- ity net operating revenues (margin) in the industrial and electric generation markets: (Thousands) 2003 2002 2001 Delivered volumes – therms: Industrial sales and transportation Electric generation Total volumes Utility net operating revenues – dollars: Industrial sales and transportation Electric generation Total margin 519,265 1,667 ________ 520,932 ________ ________ 531,195 3,400 ________ 534,595 ________ ________ 486,116 42,867 ________ 528,983 ________ ________ $ 37,693 6 ________ $ 37,699 ________ ________ $ 40,666 4,584 ________ $ 45,250 ________ ________ $ 43,251 4,721 ________ $ 47,972 ________ ________ Total volumes delivered to industrial and electric generation cus- tomers were 3 percent lower in 2003 than in 2002, and 1 percent high- er in 2002 than in 2001. Combined margins from these customers were 17 percent lower in 2003 than in 2002 and 6 percent lower in 2002 than in 2001. Excluding electric generation customers, volumes delivered to end-use industrial sales and transportation customers were 2 per- cent lower and margin was 7 percent lower in 2003 than in 2002. Results from the industrial market in 2003 reflect weak economic con- ditions during the year, as well as some cost-related changes in the design of industrial rates in the Oregon general rate case that reduced industrial margins in the fourth quarter. Volumes delivered to indus- trial customers were 9 percent higher in 2002 than in 2001, but mar- gin was 6 percent lower. The decline in margin from these customers in 2002 was due to migrations of some industrial customers from high- er margin firm service to lower margin interruptible service and to plant shutdowns or cutbacks in the manufacturing sector because of economic conditions. NW Natural re-designed its industrial rates in Oregon as part of its general rate case in 2003, transferring $4.8 million of annual revenue requirement from industrial rates to res- idential and commercial rates in order to better reflect relative costs of service and to become more competitive in the industrial market. In the electric generation market, margin was negligible in 2003 but was $4.6 million and $4.7 million in 2002 and 2001, respective- ly, equivalent to 11 cents a share in each year. More than 90 percent of the margin, but only about 14 percent of the gas deliveries, in 2002 and 2001 was from two customers that were served under contracts that went into effect in the second half of 2001 and expired at the end of the second quarter of 2002. Most of the margin from these contracts was from fixed charges. A third electric generation customer used 3.0 million therms in 2002 and 36.8 million therms in 2001 under contracts with low volumetric charges. Other Revenues Other revenues include revenues and revenue adjustments from sources other than the sale and transportation of gas (see Note 1), including deferrals to and amortizations from regulatory asset and liability accounts and miscellaneous customer fees. In 2003, other revenues contributed $7.5 million to utility operating revenues com- pared to $4.0 million in 2002 and a negative $2.3 million in 2001. Other revenues in 2003 included positive contributions due to amortizations of regulatory accounts covering customer consump- tion under NW Natural’s decoupling mechanism (see “Regulatory Matters – Rate Mechanisms,” above), amortizations of income shared with customers from interstate gas storage services, and customer late payment and collection fees and miscellaneous revenues, par- tially offset by amortizations from regulatory accounts covering con- servation programs and Year 2000 costs. The following table summarizes other revenues by primary cat- egory in 2003, 2002 and 2001: (Thousands) Rate adjustments: Decoupling deferrals Decoupling amortizations Interstate storage amortization Conservation programs amortization Year 2000 amortization Miscellaneous revenues: Customer fees Other Total other revenues Cost of Gas Sold 2003 2002 2001 $ 3,466 (783) 3,057 (2,408) (949) $ 1,720 – 1,212 (2,074) (1,539) $ – – – (4,941) (1,236) 2,919 2,158 ________ $ 7,460 ________ ________ 3,115 1,584 ________ $ 4,018 ________ ________ 2,991 861 ________ $ (2,325) ________ ________ Natural gas commodity prices have fluctuated dramatically in recent years. NW Natural has sought to mitigate the effect of higher gas commodity prices and price volatility on core utility customers through the use of its underground storage facilities, by entering into gas commodity-based financial hedge contracts, and by mak- ing short-term sales of gas commodity and transportation capacity to on-system or off-system customers in periods when core utility customers do not fully utilize firm pipeline capacity and gas supplies. In 2003, the Company replaced all of its expiring long-term con- tracts with supply contracts for gas purchases of similar aggregate volume levels. All of the new contracts have terms of five years or less and contain commodity price provisions that are tied directly to monthly market index prices for the term of the contract. The Company enters into financial hedge contracts that are intended to have the effect of converting these monthly market index prices into fixed prices for most of its gas purchases under these contracts. The cost per therm of gas sold was 9 percent lower in 2003 than in 2002, and 5 percent higher in 2002 than in 2001. The cost per therm of gas sold includes current gas purchases, gas drawn from storage inventory, gains or losses from commodity hedges, margin from off- system gas sales, demand cost balancing adjustments (demand equal- ization), regulatory deferrals and company use. Results for 2002 included an adjustment that reduced cost of gas by $29.5 million (see “Comparison of Gas Operations,” above). Excluding this adjustment, cost per therm of gas sold was 16 percent lower in 2003 than in 2002, reflecting decreases in gas commodity prices effective in late 2002, and 14 percent higher in 2002 than in 2001, reflecting increases in gas commodity prices effective in late 2001. Results for 2002 also included adjustments reducing cost of gas relating to amounts of deferred expenses for the recovery of pipeline demand charges under NW Natural’s PGA mechanism. These adjust- ments contributed 7 cents a share to earnings in 2002, of which 6 cents a share applied to periods prior to 2002. The rate methodology rep- resented in the adjustments continues to be applied in the Company’s accounting for pipeline demand charges. NW Natural’s recorded amount of unaccounted-for gas was 0.55 percent of gas sendout in 2003, compared to 0.75 percent in 2002. Unaccounted-for gas is the difference between the amount of gas the Company receives from all sources, including pipeline deliveries and withdrawals from storage, and the amount of gas it delivers to cus- tomers or other delivery points. Unaccounted-for gas may be caused in part by physical gas leakage, but it also may be due to cumulative inaccuracies in gas metering, estimates of unbilled gas or other 23 N W N A T U R A L 24 Management’s Discussion and Analysis causes. NW Natural considers a normal amount of unaccounted-for gas to be 0.50 percent of its total gas sendout during a period, but the amount may vary within a range around this estimate. During 2003, the lower estimated amount of unaccounted-for gas had the effect of reducing cost of gas and increasing margin by $1.2 million as compared to 2002. NW Natural uses a natural gas commodity-price hedge program under the terms of its Derivatives Policy to help manage its variable price gas commodity contracts (see “Application of Critical Account- ing Policies and Estimates – Accounting for Derivative Instruments and Hedging Activities,” above). NW Natural recorded net hedging gains of $32.4 million from this program during 2003, compared to net hedging losses of $75.5 million in 2002 and net hedging gains of $57.6 million in 2001, with negligible impact on net income in any of those years. Hedging gains and losses relating to gas commodity purchases are included in cost of gas and factored into NW Natural’s annual PGA rate adjustments. Under NW Natural’s PGA tariff in Oregon, net income from Oregon operations is affected within defined limits by changes in pur- chased gas costs. NW Natural is allowed to collect an amount for purchased gas costs based on estimates that are included in current utility rates. If the actual purchased gas costs are higher than the amounts included in rates, NW Natural is not allowed to charge its customers currently for those higher gas costs but is allowed to defer the costs and collect them in the future. Similarly, when the actual purchased gas costs are lower than the amount included in rates, the savings are not immediately passed on to customers but are deferred and refunded in future periods. NW Natural absorbs 33 percent of the higher cost of gas sold, or retains 33 percent of the lower cost, in either case as compared to the projected costs built into rates. The remaining 67 percent of the higher or lower gas costs is recorded as deferred regulatory assets or liabilities for recovery from or refund to customers in future rates. NW Natural’s gas costs in 2003 were slightly lower than the gas costs embedded in rates, with the effect that NW Natural’s share of the lower costs increased margin by $0.3 million, equivalent to less than 1 cent a share of earnings. In 2002 and 2001, NW Natural’s gas costs were much lower than the projected costs built into rates and the Company’s share of the sav- ings realized from gas purchases contributed $10.8 million and $4.1 million of margin, equivalent to 26 cents a share and 10 cents a share of earnings, respectively. Due to the warm weather and the reduced gas requirements of its industrial sales customers during 2003, NW Natural was able to use gas supplies that were under contract for the winter season, but were not required for delivery to core market customers, to make off-system gas sales. The Company’s purchase prices for this gas had been locked in through commodity swap and call option agreements entered into in the prior year at levels lower than mar- ket prices during 2003. Under the PGA tariff, the margin from these sales is treated as a reduction to cost of gas, with the effect that 67 percent is deferred for refund to NW Natural’s customers and the remaining 33 percent is retained by the Company. NW Natural’s share of the margin from off-system gas sales in 2003 was $4.9 mil- lion, equivalent to 11 cent a share of earnings, compared to margin of $0.9 million or 2 cents a share of earnings in 2002 and margin of $1.0 million or 2 cents a share of earnings in 2001. Non-utility Operations At Dec. 31, 2003 and 2002, the Company’s non-utility operations consisted of gas storage operations and two wholly-owned sub- sidiaries, Financial Corporation and Northwest Energy. Of the sub- sidiaries, only Financial Corporation had active operations during 2002 and 2003. Gas Storage NW Natural realized net income from its non-utility gas storage business segment in 2003, after regulatory sharing and income tax- es, of $4.3 million or 17 cents a share, compared to $3.6 million or 14 cents a share in 2002 and $2.1 million or 8 cents a share in 2001. Gas storage services include sales to off-system interstate cus- tomers using storage capacity that has been developed in advance of core utility customers’ requirements. NW Natural retains 80 per- cent of the income before tax from gas storage services and credits the remaining 20 percent to a deferred regulatory account for dis- tribution to its core utility customers. Results for the gas storage business segment also include rev- enues, net of amounts shared with core utility customers, from a con- tract with an independent energy trading company that seeks to optimize the use of NW Natural’s assets by trading temporarily un- used portions of its gas storage capacity and upstream pipeline transportation capacity. NW Natural retains 80 percent of the pre- tax income from the optimization of storage and pipeline trans- portation capacity when the costs of such capacity have not been included in core utility rates, or 33 percent of the pre-tax income from such capacity when the costs have been included in core utility rates. The remaining 20 percent and 67 percent, respectively, are cred- ited to a deferred regulatory account for distribution to NW Natural’s core utility customers. Financial Corporation Financial Corporation’s operating results in 2003 were net income of $0.7 million, compared to $1.2 million in 2002 and $0.7 million in 2001. The decrease in net income in 2003 compared to 2002 was primarily due to lower income from investments in limited part- nerships in wind and solar electric generation projects in California, and lower miscellaneous receivables. The increase in net income in 2002 compared to 2001 was due to higher income from these invest- ments. The Company’s investment in Financial Corporation at Dec. 31, 2003, was $5.5 million, compared to $9.1 million and $7.9 mil- lion at Dec. 31, 2002 and 2001, respectively. The reduced investment in Financial Corporation at Dec. 31, 2003, was primarily due to a $4.2 million cash dividend that Financial Corporation paid to NW Natural in the fourth quarter of 2003. Northwest Energy Northwest Energy was formed in 2001 to serve as the holding company for NW Natural and PGE if the acquisition of PGE had been completed. Northwest Energy recorded nominal expenses for cor- porate development activities in 2003. Upon the termination of the proposed acquisition effort in 2002, Northwest Energy recorded a loss totaling $8.4 million (after tax) for the transaction costs incurred in connection with this effort. These charges were equivalent to 33 cents a share. Operating Expenses Operations and Maintenance Operations and maintenance expenses of $96.4 million in 2003 were $11.3 million, or 13 percent, higher than in 2002. The increase was primarily due to higher operating payroll costs from added positions and wage, salary, vacation and bonus increases ($4.1 million), high- er pension costs including the impact of changes in actuarial assump- tions ($3.1 million) (see “Financial Condition – Pension Cost (Income) and Funding Status,” below), higher premiums for health care and prescription drug coverage ($0.9 million), higher renewal premiums on business risk insurance ($0.9 million), higher employee benefit costs ($0.8 million), higher professional services fees ($0.7 million), and higher expenses relating to workers compensation ($0.5 million) and other operating costs ($1.2 million). These cost increases were partially offset by a decrease in uncollectible accounts expense ($0.9 million) due to lower net write-offs of accounts receivable com- pared to 2002, when customer bills and subsequent write-offs were N W N A T U R A L impacted by higher gas prices and colder weather. Most of the cost increases NW Natural experienced in 2003 were recognized in the rate increases resulting from the Company’s general rate case in Oregon (see “Regulatory Matters – General Rate Cases,” above). Operations and maintenance expenses of $85.1 million in 2002 were $1.2 million, or 1 percent, higher than in 2001. The increase in 2002 resulted primarily from higher pension costs ($2.5 million), higher premiums for health care and prescription drug coverage ($1.0 million), higher payroll costs due to wage and salary increas- es and incentive bonus accruals ($0.8 million) and higher renewal premiums on business risk insurance ($0.3 million), partially offset by a litigation reserve in 2001 ($1.7 million), lower information tech- nology expenses ($1.0 million) and lower uncollectible accounts expense ($0.5 million). Taxes Other Than Income Taxes Taxes other than income taxes, which are principally comprised of property, franchise and payroll taxes, increased $1.0 million, or 3 percent, in 2003 over 2002. Property taxes increased $0.9 million, or 7 percent, due to utility plant additions and slightly higher prop- erty tax rates. Franchise taxes, regulatory fees and payroll tax expens- es accounted for the remaining $0.1 million increase. In 2002, taxes other than income taxes increased $1.8 million, or 6 percent, over 2001. Property taxes increased $1.6 million, or 13 percent, due to utility plant additions and higher property tax rates. Depreciation and Amortization The following table summarizes the increases in total plant and property and total depreciation and amortization for the three years ended Dec. 31, 2003: (Thousands) 2003 2002 2001 Plant and property: Utility plant: Depreciable Non-depreciable, including construction work in progress Non-utility property: Depreciable Non-depreciable, including construction work in progress Total plant and property Depreciation and amortization: Utility plant Non-utility property Total depreciation and amortization expense Average depreciation rate $ 1,598,485 $ 1,498,903 $ 1,434,009 31,070 41,062 __________ __________ __________ 1,465,079 1,539,965 __________ __________ __________ 60,604 1,659,089 22,353 20,832 18,203 1,042 23,395 – __________ __________ __________ 18,203 __________ __________ __________ $ 1,682,484 $ 1,560,797 $ 1,483,282 __________ __________ __________ __________ __________ __________ – 20,832 $ 53,798 $ 51,693 $ 49,413 227 __________ __________ __________ 397 451 $ 54,249 $ 52,090 $ 49,640 __________ __________ __________ __________ __________ __________ 3.5% __________ __________ __________ __________ __________ __________ 3.5% 3.5% The Company’s total depreciation and amortization expense in- creased by $2.2 million, or 4 percent, in 2003 and by $2.5 million, or 5 percent, in 2002. The increased expense for both years is pri- marily due to additional investments in utility property that were made to meet continuing customer growth and to expand the use of the Company’s Mist gas storage system (see “Financial Condition – Cash Flows – Investing Activities,” below). As a percentage of average depreciable plant and property, both total depreciation and amortization expense and utility deprecia- tion and amortization expense was 3.5 percent in each of 2003, 2002 and 2001. Non-utility depreciation and amortization expense as a per- centage of average depreciable non-utility property was 2.1 percent in 2003, 2.0 percent in 2002 and 1.7 percent in 2001. Other Income (Expense) Other income (expense) improved by $17.0 million in 2003, pri- marily due to the $13.9 million pre-tax charge for costs incurred in 2002 for the effort to acquire PGE. Excluding this charge, the Com- pany’s other income (expense) increased by $3.1 million in 2003. The increase was primarily due to reductions in interest charges on deferred regulatory account balances ($1.4 million) reflecting low- er net credit balances outstanding in these accounts, and an increase in gains from Company-owned life insurance ($2.0 million) due to increases in market value of equity-based life insurance investments, partially offset by a decrease in earnings from equity investments ($0.5 million) due to lower income from partnership investments held by Financial Corporation. Other income (expense) decreased $16.2 million in 2002 com- pared to 2001, primarily due to the $13.9 million charge relating to the charge for PGE transaction costs. Excluding this charge, other income (expense) decreased $2.3 million in 2002, primarily due to higher interest accrued on deferred regulatory account balances ($2.6 million), an increase in miscellaneous non-operating expenses ($0.6 million) and a decrease in miscellaneous non-operating income ($0.3 million), partially offset by an increase in earnings from Finan- cial Corporation’s investments ($1.3 million). Interest Charges – Net The Company’s net interest expense in 2003 was $1.0 million, or 3 percent, higher than in 2002. Interest expense in 2003 includ- ed dividends paid in the second half of 2003 totaling $0.2 million on the Company’s redeemable preferred stock, which were classified as interest expense upon the adoption of SFAS No. 150 (see Note 1). The increase in interest expense in 2003 was primarily due to high- er balances of debt outstanding during the period. The increase was partially offset by lower average interest rates and higher amounts of Allowance for Funds Used During Construction (AFUDC) due to higher average balances of construction work in progress (CWIP). The Company’s net interest expense in 2002 was $0.3 million, or 1 percent, higher than in 2001, also due to higher balances of debt outstanding. AFUDC represents the cost of funds used for construction work in progress (see Note 1). In 2003, AFUDC reduced interest expense by $0.9 million compared to reductions of $0.6 million in 2002 and $1.0 million in 2001. The average interest rate component of AFUDC, comprised of short-term and long-term borrowing rates as appro- priate, was 2.3 percent in 2003, 2.8 percent in 2002 and 6.2 percent in 2001. Income Taxes The effective corporate income tax rates were 33.7 percent and 34.9 percent for the years ended Dec. 31, 2003 and 2002, respectively. The lower tax rate for 2003 reflects increased tax benefits from a non- taxable gain on Company- and trust-owned life insurance. Excluding these benefits, the effective tax rate for 2003 would have been 35.0 percent. The tax rate for 2002 includes the effect of the tax benefit from the $13.9 million charge for PGE transaction costs. Excluding this charge, the effective tax rate for 2002 would have been 35.6 per- cent compared to 35.4 percent for 2001 (see Note 8). Redeemable Preferred and Preference Stock Dividend Requirements Redeemable preferred and preference stock dividend require- ments decreased $2.0 million in 2003. In November 2003, NW Natural redeemed all of the outstanding shares of its $7.125 Series of Redeemable Preferred Stock with an aggregate stated value of $7.5 million at the applicable early redemption price of 102.375 per- cent. In December 2002, NW Natural redeemed all 250,000 out- standing shares ($25 million aggregate stated value) of its $6.95 Series of Redeemable Preference Stock pursuant to the mandatory redemption provisions applicable to that Series. Dividend require- ments for the preferred and preference stock decreased by $0.1 mil- lion in both 2002 and 2001 due to annual sinking fund redemptions. At Dec. 31, 2003, no shares of redeemable preferred or preference stock were outstanding. 25 N W N A T U R A L 26 Management’s Discussion and Analysis FINANCIAL CONDITION Capital Structure The Company’s goal is to maintain a capital structure comprised of 45 to 50 percent common stock equity, up to 5 percent preferred stock and 45 to 50 percent short-term and long-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 and preferred stock redemption requirements and to pay down outstanding com- mercial paper (see “Liquid- ity and Capital Resources,” below, and Notes 3 and 5). Liquidity and Capital Resources CAPITAL STRUCTURE IN MILLIONS OF DOLLARS $1,000 $1,200 $200 $800 $600 $400 03 02 01 DEBT PREFERRED STOCK COMMON EQUITY At Dec. 31, 2003, the Company had $4.7 million in cash and cash equiva- lents compared to $7.3 mil- lion at Dec. 31, 2002. Short- term liquidity is provided by cash from operations and from the sale of com- mercial paper notes, which are supported by commer- cial bank lines of credit. The Company has available through Sept. 30, 2004, committed lines of credit with four commercial banks (see “Lines of Credit,” below, and Note 6). The Company’s long-term goal is to maintain a capital structure of 45 to 50 percent common stock equity. NW Natural’s capital expenditures are primarily related to utili- ty construction resulting from customer growth and system improve- Contractual Obligations ments (see “Cash Flows – Investing Activities,” below). In addition, NW Natural has certain contractual commitments under capital leases, operating leases and gas supply purchase and other con- tracts that require an adequate source of funding. These capital and contractual expenditures are financed through cash from operations and from the issuance of short-term debt, which is periodically refi- nanced through the sale of long-term debt or equity securities. In October 2002, the Company filed a registration statement with the Securities and Exchange Commission (SEC) registering $150 million of Medium-Term Notes, Series B (MTNs). This filing became effective in January 2003. Pursuant to this registration statement, dur- ing 2003 the Company issued $90 million of MTNs and used the pro- ceeds to pay down outstanding commercial paper balances and to fund, in part, NW Natural’s ongoing utility construction program (see “Financing Activities,” below). In February 2004, the Company filed a universal shelf registration statement with the SEC for the regis- tration of $200 million of securities, which may include First Mort- gage Bonds, unsecured debt, preferred stock and common stock. Concurrent with the February 2004 shelf filing, the Company with- drew from registration the $60 million of MTNs remaining on its pre- vious shelf registration. The $200 million universal shelf registration statement became effective in February 2004. Neither NW Natural’s Mortgage and Deed of Trust nor the inden- tures under which other long-term debt is issued contain credit rat- ing triggers or stock price provisions that require the acceleration of debt repayment. Also, there are no rating triggers or stock price pro- visions contained in contracts or other agreements with third par- ties, except for agreements with certain counter-parties under NW Natural’s Derivatives Policy which require the affected party to pro- vide substitute collateral such as cash, guaranty or letter of credit if credit ratings are lowered to non-investment grade, or in some cas- es if the mark-to-market value exceeds a certain threshold. Off-Balance Sheet Arrangements The Company has no material off-balance sheet financing arrange- ments. The following table shows the Company’s contractual obligations by maturity and type of obligation. NW Natural also has obligations with respect to its pension and post-retirement medical benefit plans (see Note 7). (Thousands) Commercial paper Long-term debt Capital leases Operating leases Gas supply commitments SMPE commitments Other purchase commitments Total –––––––––––––––––––––––– Payments Due in Years Ending Dec. 31, ––––––––––––––––––––––– 2008 2004 2006 2005 2007 $ 85,200 – 125 4,289 52,515 22,696 14,330 __________ $ 179,155 __________ __________ $ – 15,000 114 3,767 56,759 – 95 __________ $ 75,735 __________ __________ $ – 8,000 81 3,754 53,991 – – __________ $ 65,826 __________ __________ $ – 29,500 15 3,686 53,991 – – __________ $ 87,192 __________ __________ $ – 5,000 – 3,626 52,463 – – __________ $ 61,089 __________ __________ Thereafter $ – 442,819 – 55,326 294,464 – – __________ $ 792,609 __________ __________ Total $ 85,200 500,319 335 74,448 564,183 22,696 14,425 __________ $ 1,261,606 __________ __________ SMPE commitments in 2004 primarily consist of obligations NW Natural has to a general contractor to complete the construction of the remaining portion of the SMPE project. A construction contract is in place for one segment of the pipeline and an additional con- tract is currently being negotiated for the remainder of the project. Other purchase commitments primarily consist of remaining balances under existing purchase orders. These and other contractual obli- gations are financed through cash from operations and from the issuance of short-term debt, which is periodically refinanced through the sale of long-term debt or equity securities. Holders of certain MTNs have put options that, if exercised, would accelerate the maturity of long-term debt by $10 million in 2005, $20 million in 2007 and $20 million in 2008. Commercial Paper The Company’s primary source of short-term funds is commer- cial paper notes payable. Both NW Natural and Financial Corporation issue commercial paper under agency agreements with a commer- cial bank. NW Natural’s commercial paper is supported by its com- mitted bank lines of credit (see “Lines of Credit,” below), while Financial Corporation’s commercial paper is supported by commit- ted bank lines of credit and the guaranty of NW Natural (see Note 6). NW Natural had $85.2 million in commercial paper notes out- standing at Dec. 31, 2003, compared to $69.8 million outstanding at Dec. 31, 2002. Financial Corporation had no commercial paper notes outstanding at Dec. 31, 2003 or 2002. Lines of Credit NW Natural has lines of credit with four commercial banks total- ing $150 million. Half of the credit facility with each bank, totaling $75 million, is committed and available through Sept. 30, 2004, and the other $75 million is committed and available through Sept. 30, N W N A T U R A L 2005. NW Natural may be unable to draw upon the two-year por- tions of the credit lines, totaling $75 million, until filings are made or approvals received from the OPUC or the WUTC with respect to its notes relating to the two-year commitments. NW Natural expects that it will be able to make the necessary filings or secure such approvals, if required. In addition, Financial Corporation has available through Sept. 30, 2004, committed lines of credit with two commercial banks total- ing $10 million. Financial Corporation’s lines are supported by the guaranty of NW Natural. Under the terms of these lines of credit, NW Natural and Financial Corporation pay commitment fees but are not required to maintain compensating bank balances. The interest rates on borrowings under these lines of credit, if any, are based on current market rates. There were no outstanding balances on either the NW Natural or Financial Corporation lines of credit at Dec. 31, 2003 or 2002. NW Natural’s lines of credit require that credit ratings be main- tained in effect at all times and that notice be given of any change in its senior unsecured debt ratings. A change in NW Natural’s cred- it rating is not an event of default, nor is the maintenance of a spe- cific minimum level of credit rating a condition to drawing upon the lines of credit. However, interest rates on any loans outstanding under NW Natural’s bank lines are tied to credit ratings, which would increase or decrease the cost of bank debt, if any, when rat- ings are changed. The lines of credit require the Company to maintain an indebt- edness to total capitalization ratio of 65 percent or less and to main- tain a consolidated net worth at least equal to 80 percent of its net worth at Sept. 30, 2003, plus 50 percent of the Company’s net income for each subsequent fiscal quarter. Failure to comply with either of these covenants would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts out- standing. The Company was in compliance with both of these covenants at Dec. 31, 2003, and with the equivalent covenants in the prior year’s lines of credit at Dec. 31, 2002. Optional Redemptions of Long-Term Debt and Redeemable Preferred Stock In 2003, the Company exercised early redemption provisions applicable to certain of its long-term debt, including all $4 million of the 7.50% Series B MTNs due 2023, all $11 million of the 7.52% Series B MTNs due 2023, and all $20 million of the 7.25% Series B MTNs due 2023. These MTNs were redeemed in the third quarter of 2003 at 103.75 percent, 103.76 percent and 103.65 percent of their respective principal amounts. In the fourth quarter of 2003, the Company also exercised early redemption provisions applicable to all of the remaining shares of its $7.125 Series of Redeemable Pre- ferred Stock with an aggregate stated value of $7.5 million, at a redemption price equivalent to 102.375 percent. The Company redeemed the MTNs and the preferred stock with available cash or with the proceeds from sales of commercial paper, and re-financed this long-term debt and preferred stock through the sale of new long-term debt in the fourth quarter of 2003. Early redemption pre- miums are recognized as unamortized costs on debt redemptions pursuant to SFAS No. 71 and are amortized to expense over the life of the new debt. Cash Flows Operating Activities Operations provided net cash of $107 million in 2003 compared to $124 million in 2002. The 14 percent decrease was due to a de- crease in cash from operations before working capital changes ($19 million), partially offset by an increase in working capital ($2.1 mil- lion). The decrease in cash from operations before working capital changes compared to 2002 was primarily due to non-cash adjust- ments to net income in 2002, including the loss recorded for PGE costs ($13.9 million), combined with a decrease in other assets and liabilities ($27.2 million) compared to an increase in 2002, and a decrease in deferred gas costs ($5.6 million), partially offset by an adjustment to reverse the minimum pension liability recorded in 2002 ($5.0 million), a larger increase in deferred income taxes and investment tax credits ($18.7 million), higher net income from oper- ations ($2.2 million) and higher depreciation and amortization ($2.2 million). The increase in working capital was primarily due to an increase in accrued interest and taxes compared to a decrease in 2002 ($25.9 million), a decrease in inventories compared to an increase in 2002 ($15.9 million), a larger increase in accounts payable ($7.9 million) and a larger decrease in other current assets and liabilities ($4.4 million), partially offset by increases in accounts receivable ($23.1 million) and in accrued unbilled revenue ($28.7 million), in both cases compared to decreases in 2002. NW Natural’s refunds to customers of approximately $30.4 mil- lion of deferred gas cost savings in 2002 (see “Results of Operations – Comparison of Gas Operations,” above) reduced cash flows from operations by that amount, but the reduction was more than offset by the other factors affecting cash flows cited above. Continuing operations provided net cash of $124 million in 2002 compared to $72 million in 2001. The 73 percent increase was due to increased cash from operations before working capital changes ($5.7 million) and lower working capital requirements ($47 million). The increase in cash from operations before working capital changes was due to an increase in deferred income taxes and investment tax credits in 2002 compared to a reduction in 2001 ($22.5 million), the loss provision for the PGE transaction costs ($13.9 million) and higher depreciation and amortization ($2.4 million), largely offset by a small increase in deferred gas cost payables in 2002 compared to a large swing from net gas cost receivables to payables in 2001 ($26.5 million), and lower net income in 2002 ($6.4 million). The decrease in working capital requirements was due to an increase in accounts payable in 2002 compared to a decrease in 2001 ($44 mil- lion), a decrease in accrued unbilled revenue in 2002 compared to an increase in 2001 ($26 million), and a decrease in accounts receiv- able in 2002 compared to an increase in 2001 ($22 million), partially offset by a decrease in accrued interest and taxes in 2002 compared to an increase in 2001 ($40 million) and a larger increase in inven- tories in 2002 ($6.2 million). The Company has lease and purchase commitments relating to its operating activities that are financed with cash flows from oper- ations (see “Liquidity and Capital Resources,” above, and Note 12). The Job Creation and Worker Assistance Act of 2002 (the Assis- tance Act) combined with the Jobs and Growth Tax Relief Recon- ciliation Act of 2003 (the Reconciliation Act), allows an additional first-year tax depreciation deduction on the adjusted basis of “qual- ified property.” The Assistance Act provides for an additional depre- ciation deduction equal to 30 percent of an asset’s adjusted basis. The Reconciliation Act increased this first-year additional depreci- ation deduction to 50 percent of an asset’s adjusted basis. The addi- tional first-year depreciation deduction is an acceleration of depre- ciation deductions that otherwise would have been taken in the later years of an asset’s recovery period. In general, the extra first- year depreciation deduction is available for most personal proper- ty acquired after Sept. 10, 2001, and before Sept. 11, 2004. The Com- pany anticipates enhanced cash flow from reduced income taxes, totaling an estimated $30 million to $50 million, during the effec- tive period, based on actual and projected plant investments between Sept. 11, 2001 and Sept. 10, 2004. Investing Activities Cash requirements for investing activities in 2003 totaled $127 mil- lion, up from $84 million in 2002. Cash requirements for acquisition and construction of utility plant totaled $125 million, up from $80 N W N A T U R A L 27 28 Management’s Discussion and Analysis million in 2002. The increase in cash requirements for utility con- struction in 2003 was primarily the result of higher capital expen- ditures relating to NW Natural’s SMPE project ($27 million), higher system improvements and support ($12 million) and other special proj- ects to serve new customer load or new service areas ($8.9 million). Cash requirements for investing activities in 2002 totaled $84 mil- lion, down from $87 million in 2001, primarily due to lower amounts of cash used for investments in non-utility property ($6.9 million) and for the PGE transaction ($5.2 million), partially offset by high- er amounts of cash used for the construction of utility plant ($7.6 million) and lower cash proceeds from the sale of assets ($2.8 mil- lion). Cash requirements for utility construction in 2002 totaled $80 million, up from $72 million in 2001, primarily as a result of capital expenditures related to NW Natural’s pipeline safety program ($4.7 million) and special projects expanding service to existing customers or into new service areas ($3.4 million). Investments in non-utility property totaled $2.6 million in both 2003 and 2002, including expenditures in both years for certain improvements to the Company’s gas pipeline system that were pri- marily related to interstate storage services. During the five-year period 2004 through 2008, utility construc- tion expenditures are estimated at between $500 million and $600 million. The level of capital expenditures over the next five years reflects projected customer growth, the SMPE project and system im- provement projects resulting in part from requirements under the Pipeline Safety Improvement Act of 2002 (Pipeline Safety Act) (see below). An estimated 60 percent of the required funds are expect- ed to be internally generated over the five-year period; the remain- der will be funded through a combination of long-term debt and equity securities with short-term debt providing liquidity and bridge financing. NW Natural’s utility capital expenditures in 2004 are estimated to total $165 million, including $31 million for customer growth, $38 million for system improvement and support, $71 million for the SMPE and related gas storage projects, $8 million for the construc- tion of a gas distribution system in Coos County, Oregon and $17 million for construction overhead. The SMPE project has a scheduled completion date in late 2004. NW Natural must obtain easements and rights-of-way for the con- struction of the pipeline and may need to use condemnation pro- ceedings to secure some of them. NW Natural entered into a stipulation with the OPUC in 2001 for an enhanced pipeline safety program that includes an accelerated bare steel replacement program and a geo-hazard safety program. The bare steel replacement program accelerates the replacement of NW Natural’s bare steel piping over 20 years instead of 40 years. The geo-hazard safety program includes the identification, assessment and remediation of risks to piping infrastructure created by landslides, washouts, earthquakes or similar occurrences. The stipulation allowed NW Natural to receive deferred accounting rate treatment commencing Oct. 1, 2002, for costs associated with the programs exceeding $3 million per year, expected to be approximately $1.5 mil- lion annually. In December 2003, the U.S. Department of Transportation’s Office of Pipeline Safety issued a rule that specifies the detailed require- ments for transmission pipeline integrity management programs (IMPs) as mandated by the Pipeline Safety Act. The Pipeline Safety Act requires operators of gas transmission pipelines to identify lines located in High Consequence Areas (HCAs) and to develop IMPs to periodically inspect the integrity of the pipelines and make repairs or replacements as necessary to ensure the ongoing integrity of the pipelines. The legislation requires NW Natural to complete inspec- tion of the 50 percent highest risk pipelines located in its HCAs within the first five years, and the remaining covered pipelines with- in 10 years of the date of the enactment. The Pipeline Safety Act also requires re-inspections of the covered pipelines every seven years thereafter for the life of the pipelines. The capital and operating costs of compliance with the legislation and rules, and the account- ing and regulatory treatments for these costs, are uncertain. Currently, however, NW Natural estimates that its IMP will cost $5 million to $8 million in 2004 and $5 million to $15 million per year beginning in 2005, totaling $50 million to $100 million over the next 10 years. Financing Activities Cash provided by financing activities in 2003 totaled $17 million, compared to cash used in financing activities in 2002 of $43 million. Factors contributing to the $60 million difference were an increase in short-term debt in 2003 ($15.4 million) compared to a decrease in 2002 ($38.5 million) and the redemption of the $6.95 Series of Preference Stock in 2002 ($25 million), partially offset by a higher amount used for the retirement of long-term debt ($55 million in 2003 compared to $40.5 million in 2002) and the redemption of the $7.125 Series of Preferred Stock in 2003 ($8.4 million). Cash used in financing activities in 2002 totaled $43 million, compared to cash provided by financing activities in 2001 of $15 mil- lion. Factors contributing to the $58 million difference were a reduc- tion in short-term debt in 2002 ($38 million) compared to an increase in 2001 ($52 million), the redemption of the $6.95 Series of Preference Stock in 2002 ($25 million), and a higher amount used for the retire- ment of long-term debt ($40.5 million in 2002 compared to $20 mil- lion in 2001), partially offset by an increase in long-term debt issued ($90 million in 2002 compared to $18 million in 2001) and a reduc- tion in common stock repurchased ($5.8 million). NW Natural sold $90 million of its secured Medium-Term Notes, Series B (MTNs) in each of 2003 and 2002 and used the proceeds to redeem long-term debt ($55 million in 2003 and $40.5 million in 2002), provide cash for investments in utility plant and reduce short- term borrowings. In 2000, NW Natural commenced 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 extend- ed through May 2004. The purchases are made in the open market or through privately negotiated transactions. No shares were repur- chased in 2002 or in 2003. Since the program’s inception the Com- pany has repurchased 355,400 shares of common stock at a total cost of $8.2 million. Pension Cost (Income) and Funding Status Net periodic pension cost is determined in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” (see “Application of Critical Accounting Policies – Accounting for Pensions,” above). The annual pension cost or income is allocated between operations and maintenance expense and construction overhead. Net periodic pension cost for the Company’s qualified defined benefit pension plans was $6.2 million in 2003, compared to net pen- sion income of $0.1 million and $4.1 million in 2002 and 2001, respectively. The increase in pension cost was largely due to invest- ment losses in 2001 and 2002, which are recognized over a three- year period, and to lower discount rates which had the effect of in- creasing accumulated benefit obligations. The Company is required to make a cash contribution of at least $1.9 million, and may make an additional contribution up to a total of $6.8 million, to its non- bargaining employee pension plan for the 2003 plan year, payable by Sept. 15, 2004. No cash contributions to the qualified plans were required for the 2002 or 2001 plan years. The fair value of the plan assets increased to $168 million at Dec. 31, 2003, from $143 million at Dec. 31, 2002, including $36 million in investment gains, par- tially offset by $10 million in withdrawals to pay benefits and $0.9 million in eligible expenses of the plans. The present value of ben- efit obligations under the plans increased from an estimated $172 N W N A T U R A L At Dec. 31, 2003, differences between notional values and fair values with respect to NW Natural’s open positions in derivative financial instruments were not material to the Company’s financial position or results of operations because of the treatment of these instruments in regulatory mechanisms relating to gas costs (see “Results of Operations – Comparison of Gas Operations – Cost of Gas,” above, and Notes 1 and 11). To the degree that market risks exist due to potential adverse changes in commodity prices, foreign exchange rates and interest rates in relation to these financial and physical contracts, the Company considers the risks to be: Commodity Price Risk The prices of natural gas commodity are subject to fluctuations due to unpredictable factors including weather, pipeline transpor- tation congestion and other factors that affect short-term supply and demand. Commodity swap and call option contracts (also known as financial hedge contracts) are used to convert certain natural gas pur- chase contracts from floating prices to fixed prices. At Dec. 31, 2003 and 2002, notional amounts under these commodity swap and call option contracts totaled $304.1 million and $180.6 million, respec- tively. At Dec. 31, 2003, five of these commodity hedge contracts ex- tended beyond Dec. 31, 2004. If all of the commodity swap and call option contracts had been settled on Dec. 31, 2003, a regulatory gain of $23.7 million would have been realized (see Note 11). Foreign Currency Risk The costs of natural gas commodity and certain pipeline servic- es purchased from Canadian suppliers are subject to changes in the value of Canadian currency in relation to U.S. currency. Foreign cur- rency forward contracts are used to hedge against fluctuations in ex- change rates with respect to purchases of natural gas from Canadian suppliers. At Dec. 31, 2003 and 2002, notional amounts under for- eign currency forward contracts totaled $6.4 million and $15.5 mil- lion, respectively. As of Dec. 31, 2003, no foreign currency forward contracts extended beyond Dec. 31, 2004. If all of the foreign cur- rency forward contracts had been settled on Dec. 31, 2003, a gain of $0.2 million would have been realized (see Note 11). Interest Rate Risk Interest rate risk relates to new debt financing needed to fund cap- ital requirements, including maturing debt securities, and to the issuance of commercial paper. Interest rate risk is managed through the issuance of fixed-rate debt with varying maturities and the reduc- tion of debt through optional redemption when interest rates are favorable. No derivative financial instruments to hedge interest rates were in place at Dec. 31, 2003 or 2002. 29 million to $192 million over that period, however, so the plans re- mained under-funded by about $24 million at Dec. 31, 2003. Despite the decline from a position of pension income in 2001 and 2002 to a position of pension expense in 2003, and the reduc- tions in recent years in the funded status of the plans, NW Natural believes it will be able to maintain well-funded pension plans. NW Natural does not expect its current or future cash contributions to the plans to have a material adverse effect on its liquidity or finan- cial condition. Ratios of Earnings to Fixed Charges For the years ended Dec. 31, 2003, 2002 and 2001, the Company’s ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were 2.83, 2.74 and 3.01, respective- ly. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebted- ness, dividends on all preferred and preference stock, the amortiza- tion of debt expense and discount or premium and the estimated interest portion of rentals charged to income. CONTINGENT LIABILITIES Environmental Matters The Company is subject to federal, state and local laws and reg- ulations related to environmental matters. These evolving laws and regulations may require expenditures over a long timeframe to con- trol environmental impacts. The Company believes, at this time, that appropriate investigation or remediation is being undertaken at all the relevant sites. Based on existing knowledge, the Company does not expect that the ultimate resolution of these matters will have a material adverse effect on its financial condition, results of opera- tions or cash flows. See Note 12. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company’s primary market risk exposures associated with activities involving derivative financial instruments and other finan- cial instruments are natural gas commodity price risk, foreign cur- rency exchange risk and interest rate risk. Derivative financial instru- ments are used as tools to mitigate certain of these market risks (see Notes 1 and 11). Such instruments are used for hedging purposes, not for trading purposes. Market risks associated with the deriva- tive financial instruments are monitored by management personnel who do not directly enter into these contracts and by the Audit Committee of the Board of Directors. Physical and Financial Commodity, Foreign Currency and Interest Rate Transactions NW Natural enters into short-term and long-term natural gas purchase contracts with demand and commodity fixed-price and floating-price components, along with associated short-term and long-term natural gas transportation contracts. Foreign currency for- ward contracts are used to hedge against foreign exchange rate fluc- tuations on purchases made under these contracts that are denom- inated in Canadian dollars. Historically, NW Natural has taken physical delivery of at least the minimum quantities specified in its natural gas purchase con- tracts. The contracts are subject to annual re-pricing, a process that is intended to reflect anticipated market price trends during the next year. NW Natural’s PGA mechanism in Oregon provides for the recovery from customers of actual commodity costs in comparison with established benchmark costs, except that NW Natural absorbs 33 percent of the higher cost of gas sold, or retains 33 percent of the lower cost, in either case as compared to projections. N W N A T U R A L Report of Independent Auditors To the Board of Directors and Shareholders of Northwest Natural Gas Company: In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of earnings invested in the business, of cash flows and of capitalization present fairly, in all material respects, the financial position of Northwest Natural Gas Company (doing business at NW Natural) and its subsidiaries (the “Company”) at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audits. We conduct- ed our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material mis- statement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial state- ment presentation. We believe that our audits provide a reasonable basis for our opinion. Portland, Oregon February 26, 2004 30 N W N A T U R A L Consolidated Statements of Income Thousands, except per share amounts (year ended December 31) Operating revenues: Gross operating revenues Cost of sales Net operating revenues Operating expenses: Operations and maintenance Taxes other than income taxes Depreciation and amortization Total operating expenses Income from operations Other income (expense) Interest charges – net of amounts capitalized Income before income taxes Income tax expense Net income Redeemable preferred and preference stock dividend requirements Earnings applicable to common stock Average common shares outstanding: Basic Diluted Earnings per share of common stock: Basic Diluted See Notes to Consolidated Financial Statements. 2003 2002 2001 $ 611,256 323,190 __________ 288,066 $ 641,376 353,832 __________ 287,544 $ 650,252 374,241 __________ 276,011 96,420 35,125 54,249 __________ 185,794 __________ 102,272 2,150 35,099 __________ 69,323 23,340 __________ 45,983 294 __________ $ 45,689 __________ __________ 85,120 34,076 52,090 __________ 171,286 __________ 116,258 (14,890) 34,132 __________ 67,236 23,444 __________ 43,792 2,280 __________ $ 41,512 __________ __________ 83,920 32,240 49,640 __________ 165,800 __________ 110,211 1,334 33,805 __________ 77,740 27,553 __________ 50,187 2,401 __________ $ 47,786 __________ __________ 25,741 26,061 25,431 25,814 25,159 25,612 $ 1.77 $ 1.76 $ 1.63 $ 1.62 $ 1.90 $ 1.88 31 Consolidated Statements of Earnings Invested in the Business and Comprehensive Income 2003 2002 2001 $ 157,136 45,983 $ 45,983 Thousands (year ended December 31) Earnings invested in the business: Balance at beginning of year Net income Cash dividends paid: Redeemable preferred and preference stock Common stock Common stock repurchased Common stock expense Balance at end of year Accumulated other comprehensive income (loss): Balance at beginning of year Other comprehensive income (loss) – net of tax: (392) (32,655) – (19) _________ $ 170,053 _________ _________ $ (3,084) $ 43,792 $ 147,950 43,792 (2,579) (32,024) – (3) _________ $ 157,136 _________ _________ $ (375) $ 50,187 $ 134,189 50,187 (2,410) (31,307) (2,688) (21) _________ $ 147,950 _________ _________ $ – Minimum pension liability adjustment Change in unrealized loss from price risk management activities Comprehensive income Balance at end of year See Notes to Consolidated Financial Statements. 2,068 2,068 (2,936) (2,936) (148) (148) – _________ $ (1,016) _________ _________ – _________ $ 48,051 _________ _________ 227 _________ $ (3,084) _________ _________ 227 _________ $ 41,083 _________ _________ (227) _________ $ (375) _________ _________ (227) _________ $ 49,812 _________ _________ N W N A T U R A L Consolidated Balance Sheets Thousands (December 31) Assets: Plant and property: Utility plant Less accumulated depreciation Utility plant – net Non-utility property Less accumulated depreciation and amortization Non-utility property – net Total plant and property Other investments Current assets: Cash and cash equivalents Accounts receivable, less allowance for uncollectible accounts of $1,763 in 2003 and $1,815 in 2002 Accrued unbilled revenue Inventories of gas, materials and supplies Prepayments and other current assets Total current assets Regulatory assets: Income tax asset Unamortized costs on debt redemptions Other Total regulatory assets Other assets: Investment in life insurance Fair value of non-trading derivatives Other Total other assets Total assets 32 Capitalization and liabilities: Capitalization Common stock Premium on common stock Earnings invested in the business Unearned stock compensation Accumulated other comprehensive income (loss) Total common stock equity Redeemable preferred stock Long-term debt Total capitalization Current liabilities: Notes payable Accounts payable Long-term debt due within one year Taxes accrued Interest accrued Other current and accrued liabilities Total current liabilities Regulatory liabilities: Accrued asset removal costs Customer advances Deferred gas costs payable Unrealized gain on non-trading derivatives Total regulatory liabilities Other liabilities: Deferred income taxes Deferred investment tax credits Other Total other liabilities Commitments and contingencies (see Note 12) Total capitalization and liabilities See Notes to Consolidated Financial Statements. N W N A T U R A L 2003 2002 $ 1,659,089 471,716 ___________ 1,187,373 ___________ 23,395 4,855 ___________ 18,540 ___________ 1,205,913 ___________ 12,635 ___________ $ 1,539,965 435,601 ___________ 1,104,364 ___________ 20,832 4,404 ___________ 16,428 ___________ 1,120,792 ___________ 12,703 ___________ 4,706 52,213 59,109 50,859 32,661 ___________ 199,548 ___________ 7,328 46,936 44,069 58,030 36,934 ___________ 193,297 ___________ 63,449 7,803 6,020 ___________ 77,272 ___________ 47,975 6,508 7,040 ___________ 61,523 ___________ 59,710 23,885 12,369 ___________ 95,964 ___________ $ 1,591,332 ___________ ___________ 54,916 12,426 11,620 ___________ 78,962 ___________ $ 1,467,277 ___________ ___________ $ 82,137 255,871 170,053 (729) (1,016) ___________ 506,316 – 500,319 ___________ 1,006,635 ___________ $ 81,023 248,028 157,136 (711) (3,084) ___________ 482,392 8,250 445,945 ___________ 936,587 ___________ 85,200 86,029 – 8,605 2,998 31,589 ___________ 214,421 ___________ 69,802 74,436 20,000 7,822 2,902 30,045 ___________ 205,007 ___________ 135,638 1,564 5,627 23,885 ___________ 166,714 ___________ 125,197 1,791 10,635 12,426 ___________ 150,049 ___________ 171,797 6,945 24,820 ___________ 203,562 ___________ – ___________ $ 1,591,332 ___________ ___________ 141,732 7,824 26,078 ___________ 175,634 ___________ – ___________ $ 1,467,277 ___________ ___________ Consolidated Statements of Cash Flows Thousands (year ended December 31) Operating activities: Net income from operations Adjustments to reconcile net income to cash provided by operations: Depreciation and amortization (Gain) loss on sale of assets Loss for PGE acquisition costs Minimum pension liability adjustment Unrealized gain (loss) from price risk management activities Deferred income taxes and investment tax credits Undistributed (earnings) losses from equity investments Allowance for funds used during construction Deferred gas costs – net Other Cash from operations before working capital changes Changes in operating assets and liabilities: Accounts receivable – net of allowance for uncollectible accounts Accrued unbilled revenue Inventories of gas, materials and supplies Accounts payable Accrued interest and taxes Other current assets and liabilities Cash provided by operating activities Investing activities: Acquisition and construction of utility plant assets Investment in non-utility property PGE acquisition costs Proceeds from sale of assets Other investments Cash used in investing activities Financing activities: Common stock issued Common stock repurchased Redeemable preferred and preference stock retired Long-term debt issued Long-term debt retired Change in short-term debt Cash dividend payments: Redeemable preferred and preference stock Common stock Common stock expense Cash provided by (used in) financing activities Decrease in cash and cash equivalents Cash and cash equivalents – beginning of year Cash and cash equivalents – end of year Supplemental disclosure of cash flow information: Cash paid during the period for: Interest and preferred dividends Income taxes Supplemental disclosure of non-cash financing activities: Conversion to common stock: 7-1/4% Series of Convertible Debentures See Notes to Consolidated Financial Statements. N W N A T U R A L 2003 2002 2001 $ 45,983 $ 43,792 $ 50,187 54,249 10 – 2,068 – 29,186 (474) (1,734) (5,008) (22,599) __________ 101,681 (5,277) (15,040) 7,171 11,593 1,145 5,533 __________ 106,806 __________ 52,090 (221) 13,873 (2,936) 227 10,450 (988) (550) 546 4,582 __________ 120,865 17,786 13,680 (8,693) 3,738 (24,725) 1,176 __________ 123,827 __________ 49,640 – – (148) (227) (12,088) 321 (959) 27,062 1,345 __________ 115,133 (3,969) (12,130) (2,454) (40,000) 15,435 (494) __________ 71,521 __________ (124,660) (2,563) – 18 542 __________ (126,663) __________ (79,530) (2,629) (4,316) 500 1,848 __________ (84,127) __________ (71,943) (9,554) (9,557) 3,256 529 __________ (87,269) __________ 33 8,331 – (8,428) 90,000 (55,000) 15,398 6,533 – (25,750) 90,000 (40,500) (38,489) 5,157 (5,792) (750) 18,000 (20,000) 52,028 (392) (32,655) (19) __________ 17,235 __________ (2,579) (32,024) (3) __________ (42,812) __________ (2,410) (31,307) (21) __________ 14,905 __________ (2,622) 7,328 __________ $ 4,706 __________ __________ (3,112) 10,440 __________ $ 7,328 __________ __________ (843) 11,283 __________ $ 10,440 __________ __________ $ 35,210 $ 13,940 $ 34,640 $ 33,474 $ 33,034 $ 25,201 $ 626 $ 1,932 $ 413 Consolidated Statements of Capitalization Thousands, except share amounts (December 31) Common stock equity: Common stock – par value $3-1/6 per share, authorized 60,000,000 shares: outstanding – 2003, 25,938,002 shares; 2002, 25,586,313 shares Premium on common stock Earnings invested in the business Unearned compensation Accumulated other comprehensive income (loss) Total common stock equity Redeemable preferred stock, authorized 1,500,000 shares: $7.125 Series, stated value $100 per share; outstanding – 2003, none; 2002, 82,500 shares 2003 2002 $ 82,137 255,871 170,053 (729) (1,016) ___________ 506,316 $ 81,023 248,028 157,136 (711) (3,084) ___________ 482,392 50% 51% – 0% 8,250 1% 34 Long-term debt: Medium-Term Notes First Mortgage Bonds: 6.400% Series B due 2003 6.340% Series B due 2005 6.380% Series B due 2005 6.450% Series B due 2005 6.050% Series B due 2006 6.310% Series B due 2007 6.800% Series B due 2007 6.500% Series B due 2008 4.110% Series B due 2010 7.450% Series B due 2010 6.665% Series B due 2011 7.130% Series B due 2012 8.260% Series B due 2014 7.000% Series B due 2017 6.600% Series B due 2018 8.310% Series B due 2019 7.630% Series B due 2019 9.050% Series A due 2021 5.620% Series B due 2023 7.250% Series B due 2023 7.500% Series B due 2023 7.520% Series B due 2023 7.720% Series B due 2025 6.520% Series B due 2025 7.050% Series B due 2026 7.000% Series B due 2027 6.650% Series B due 2027 6.650% Series B due 2028 7.740% Series B due 2030 7.850% Series B due 2030 5.820% Series B due 2032 5.660% Series B due 2033 Convertible Debentures 7-1/4% Series due 2012 Less long-term debt due within one year Total long-term debt Total capitalization See Notes to Consolidated Financial Statements. – 5,000 5,000 5,000 8,000 20,000 9,500 5,000 10,000 25,000 10,000 40,000 10,000 40,000 22,000 10,000 20,000 10,000 40,000 – – – 20,000 10,000 20,000 20,000 20,000 10,000 20,000 10,000 30,000 40,000 20,000 5,000 5,000 5,000 8,000 20,000 9,500 5,000 – 25,000 10,000 40,000 10,000 40,000 22,000 10,000 20,000 10,000 – 20,000 4,000 11,000 20,000 10,000 20,000 20,000 20,000 10,000 20,000 10,000 30,000 – 5,819 ___________ 500,319 – ___________ 500,319 ___________ 6,445 ___________ 465,945 20,000 ___________ 445,945 ___________ 50% ______ $ 1,006,635 ___________ ___________ 100% $ 936,587 ___________ ______ ___________ ______ 48% ______ 100% ______ ______ N W N A T U R A L Notes to Consolidated Financial Statements 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: Organization and Principles of Consolidation The consolidated financial statements include the accounts of: Regulated utility: ■ Northwest Natural Gas Company (NW Natural) Non-regulated wholly-owned subsidiaries of NW Natural: ■ NNG Financial Corporation (Financial Corporation), and its wholly-owned subsidiaries ■ Northwest Energy Corporation (Northwest Energy), and its wholly-owned subsidiary Together these businesses are referred to herein as the Company (see Note 2). Intercompany accounts and transactions have been eliminated. Investments in corporate joint ventures and partnerships in which the Company’s ownership interest is 50 percent or less and over which the Company does not exercise control are accounted for by the equity method or the cost method (see Note 9). Certain amounts from prior years have been reclassified to con- form, for comparison purposes, with the current financial statement presentation. These reclassifications had no impact on prior year consolidated results of operations. Use of Estimates The preparation of financial statements in conformity with gen- erally accepted accounting principles in the United States of America requires management to make estimates and assump- tions that affect reported amounts in the consolidated financial statements and accompanying notes. Actual amounts could differ from those estimates, and changes would be reported in future periods. Management believes that the estimates and assumptions used are reasonable. Industry Regulation The Company’s principal business is the distribution of natural gas, which is regulated by the Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commis- sion (WUTC). Accounting records and practices conform to the requirements and uniform system of accounts prescribed by these regulatory authorities in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” In applying SFAS No. 71, NW Natural capitalizes certain costs and revenues as regulatory assets and liabilities pursuant to orders of the OPUC or WUTC in general rate or expense deferral pro- ceedings, to provide for recovery of revenues or expenses from, or refunds to, utility customers in future periods. At Dec. 31, 2003 and 2002, the amounts deferred as regulatory assets and liabilities were net liabilities of $89.4 million and $88.5 million, respectively. The net amounts recognized at Dec. 31, 2003 and 2002 include $135.6 million and $125.2 million, respectively, of accumulated removal costs, which have been reclassified from accumulated depreciation to regulatory liabilities at Dec. 31, 2003, in accordance with SFAS No. 143, “Accounting for Asset Removal Obligations” (see “New Accounting Standards,” below). In addition, the “Income tax asset” balance increased by $15.5 million primarily reflecting the grossed- up tax benefit of removal costs passed through in rate base after Dec. 31, 1992. If NW Natural should determine that all or a portion of these regulatory assets or liabilities no longer meet the criteria for con- tinued application of SFAS No. 71, then it would be required to write off the net unrecoverable balances against earnings. New Accounting Standards Adopted Standards Effective Jan. 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 re- quires the recognition of an Asset Retirement Obligation (ARO) for legal obligations associated with the retirement of tangible long- lived assets, including the recording of fair value of the liability, if reasonably estimable, for an ARO in the period in which it is in- curred. The ARO liability is recorded and the cost is capitalized as part of the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the relat- ed asset. The Company did not have any material legal obliga- tions associated with the retirement of its tangible long-lived assets, except for certain assets with indefinite system lives for which the Company cannot estimate the ARO because the settlement date is indeterminable. However, the Company’s adoption of SFAS No. 143 did result in a balance sheet reclassification of asset removal cost obligations from accumulated depreciation and amortization to regulatory liabilities (see “Plant and Property,” below, for a dis- cussion of the Company’s policy on asset removal costs). Also effective Jan. 1, 2003, the Company adopted SFAS No. 145, “Rescission of FASB Statement Nos. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections,” and SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activi- ties,” which replaces Emerging Issues Task Force Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 145, which updates, clarifies and simplifies existing accounting pronouncements, addresses the reporting of debt extinguishments and accounting for certain lease modifications that have economic effects that are similar to sale- leaseback transactions. SFAS No. 146 requires companies to rec- ognize costs associated with exit or disposal activities, such as lease termination costs and certain employee severance costs, when they are incurred rather than at the date of a commitment to an exit or disposal plan. The primary effect of applying SFAS No. 146, which was effective for all exit or disposal activities initiated after Dec. 31, 2002, is on the timing of recognition of costs associated with exit or disposal activities. The adoption of SFAS Nos. 145 and 146 did not have a material impact on the Company’s financial con- dition or results of operations. Also effective Jan. 1, 2003, the Company adopted the disclosure requirements of SFAS No. 148, “Accounting for Stock-Based Com- pensation – Transition and Disclosure – an amendment to FASB Statement No. 123,” but continues to account for its stock-based compensation plans using the intrinsic value method prescribed in Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees,” rather than adopt a fair value method of accounting for its stock-based employee compensation. SFAS No. 148 provides alternative methods of transition for a vol- untary change to the fair value method. In addition, SFAS No. 148 requires prominent disclosures in annual and interim financial statements about the accounting method used for stock-based employee compensation and its effect on reported results. SFAS No. 148 encourages, but does not require, companies to record com- pensation expense using the fair value method of accounting. The adoption of SFAS No. 148 did not have a material impact on the Company’s financial condition or results of operations, and it would not have had a material impact if the Company had elected to adopt a fair value method of accounting for stock-based compen- sation (see “Stock-Based Compensation,” below, and Note 4). Effective July 1, 2003, the Company adopted SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedg- ing Activities.” SFAS No. 149 primarily amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” to clarify the definition of a derivative and to require derivative instruments that include up-front cash payments to be classified as financing activity in the statement of cash flows. SFAS No. 149 N W N A T U R A L 35 36 Notes to Consolidated Financial Statements is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have a material impact on the Company’s financial condition or results of operations. Also effective July 1, 2003, the Company adopted SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 establishes standards for how an issuer classifies and measures in its financial statements certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires an issuer to classify a financial instrument as a liability if that financial instrument embodies an obligation of the issuer. The adoption of SFAS No. 150 resulted in the Company’s reclassifying dividends of $0.2 million after July 1, 2003 on its redeemable preferred stock as interest expense, thus affecting the Company’s reported net income for 2003. The Com- pany redeemed its last remaining shares of preferred stock out- standing during the fourth quarter of 2003. The adoption of SFAS No. 150 did not have a material impact on the Company’s financial condition or results of operations. In December 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits, an amendment of FASB State- ments No. 87, 88, and 106.” SFAS No. 132 requires that expand- ed disclosures on pension and other postretirement benefit plans be included in financial statements for fiscal years ending on or after Dec. 15, 2003. The Company has adopted SFAS No. 132. See Note 7. In November 2002, the FASB issued FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN 45 clarifies the requirements of FASB Statement No. 5, “Accounting for Contingencies,” relating to the guarantor’s account- ing for, and disclosure of, the issuance of certain types of guaran- tees. A guarantor must recognize a liability for the fair value of an obligation assumed under a guarantee and provide additional dis- closures about the obligations associated with guarantees issued. In connection with the settlement of litigation involving leases in the Mist gas storage field, NW Natural agreed to defend and indem- nify a party against claims relating to the validity and enforce- ability of certain transferred leases. However, NW Natural has no obligation to defend or indemnify the party from any claims for re- covery of punitive or other exemplary damages. The Company has provided no other guarantees of indebtedness of others. Accordingly, the application of FIN 45 did not have a material impact on the Company’s financial condition or results of operations. In January 2003, the FASB issued FIN 46, “Consolidation of Var- iable Interest Entities.” FIN 46 provides guidance on the identifi- cation of, and the financial reporting for, entities over which con- trol is achieved through means other than voting rights, known as “variable interest entities.” FIN 46 provides guidance for deter- mining whether consolidation is required. Certain variable inter- est entities must be consolidated by the primary beneficiary if the equity investors in the entity do not have the characteristics of a con- trolling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 was effective imme- diately for all new variable interest entities created or acquired after Jan. 31, 2003. The Company did not have any significant interests in any variable interest entities during any of the current report- ing periods. The application of FIN 46 had no material impact on the Company’s financial condition or results of operations. Plant and Property Plant and property is stated at cost, including labor, materials and overhead (see Note 9). The cost of utility plant and interstate storage includes an allowance for funds used during construction in construction overhead to represent the net cost of borrowed funds used for construction purposes (see “Allowance for Funds Used During Construction,” below). NW Natural’s provision for depreciation of utility property is computed under the straight-line, age-life method in accordance with independent engineering studies and as approved by regu- latory authorities. The average depreciation rate was approxi- mately 3.5 percent for each of the years 2003, 2002 and 2001. The depreciation rate reflects the approximate economic life of the utility property. Effective Jan. 1, 2003, the Company adopted SFAS No. 143 (see “New Accounting Standards,” above). Among other things, SFAS No. 143 requires that future asset retirement costs (removal costs) that meet the requirements of SFAS No. 71, as amended and sup- plemented, be classified as a regulatory liability. In accordance with long-standing industry practice, the Company accrues for future removal costs on many long-lived assets through a charge to depreciation expense allowed in rates. Prior to the adoption of SFAS No. 143, the resulting regulatory liabilities were recognized as accruals to accumulated depreciation. At the time when removal costs were incurred, accumulated depreciation was charged with the costs of removal and the book cost of the asset being retired. Upon the adoption of SFAS No.143, the Company reclassified on its Dec. 31, 2003 and 2002 consolidated balance sheets $135.6 mil- lion and $125.2 million, respectively, of previously accrued asset removal costs recovered through rates from accumulated depreci- ation and amortization to regulatory liabilities – accrued asset removal costs. This reclassification is based on the Company’s estimate of accumulated removal costs using its most recent depre- ciation study. The Company will continue to accrue future asset removal costs through depreciation expense, with a correspon- ding credit to regulatory liabilities – accrued asset removal costs. When the Company retires depreciable utility plant and equip- ment, it will charge the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred will be charged to regulatory liabilities – accrued asset removal costs. No gain or loss is recognized upon normal retire- ment. In the rate setting process, the accrued asset removal costs are treated as a reduction to the net rate base. Allowance for Funds Used During Construction Certain additions to utility plant include an allowance for funds used during construction (AFUDC). AFUDC represents the cost of funds borrowed during construction and is calculated using actu- al commercial paper interest rates. If commercial paper borrowings are less than the total costs of construction work in progress, then a composite rate of interest on all debt, shown as a reduction to interest charges, and a return on equity funds, shown as other in- come, is used to compute AFUDC. While cash is not realized cur- rently from AFUDC, it is realized in future years through increased revenues from rate recovery resulting from higher rate base and higher depreciation expense. NW Natural’s composite AFUDC rates were 4.5 percent in 2003, 2.8 percent in 2002 and 6.2 percent in 2001. Cash and Cash Equivalents For purposes of reporting cash flows, cash and cash equivalents include cash on hand and highly liquid temporary investments with original maturity dates of three months or less. Revenue Recognition Utility revenues, derived primarily from the sale and trans- portation of natural gas, are recognized when the gas is delivered to and received by the customer. Revenues include accruals for gas delivered but not yet billed to customers based on estimates of gas deliveries from meter reading dates to month end (unbilled rev- enues). Unbilled revenues are dependent upon a number of factors that require management judgment, including total gas receipts and N W N A T U R A L deliveries, customer use and weather. Unbilled revenues are reversed the following month when actual billings occur. The Company’s accrued unbilled revenues at Dec. 31, 2003 and 2002 were $59.1 million and $44.1 million, respectively. Non-utility revenues, derived primarily from gas storage serv- ices, are recognized upon delivery of the service to customers. Revenues from optimization of excess storage and transportation capacity are recognized over the life of the contract for guaranteed amounts under the contract, or are recognized as earned for amounts above the guaranteed value. Inventories Inventories, consisting primarily of natural gas in storage, are stated at the lower of average cost or net realizable value. Derivatives Policy NW Natural’s Derivatives Policy sets forth the guidelines for using selected financial derivative products to support prudent risk management strategies within designated parameters. The Deriva- tives Policy allows for the use of derivatives to manage natural gas commodity prices related to natural gas purchases, foreign currency prices related to gas purchase commitments from Canada, oil or propane commodity prices related to gas sales and transportation services under rate schedules pegged to other commodities, and interest rates related to long-term debt maturing in less than five years or expected to be issued in future periods. NW Natural’s objective for using derivatives is to decrease the volatility of earnings and cash flows associated with changes in commodity prices, foreign cur- rency prices and interest rates. The use of derivatives is permitted only after the commodity price, exchange rate, and interest rate exposures have been identified, are determined to exceed accept- able tolerance levels and are considered to be unavoidable because they are necessary to support normal business activities (see Note 11). The Policy is intended to prevent speculative risk. NW Natural does not enter into derivative instruments for trading purposes and believes that any increase in market risk created by holding derivatives should be offset by the exposures they modify. In accounting for derivative activities, the Company applies SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” (collectively referred to as SFAS No. 133). SFAS No. 133 requires that the Company recognize derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. SFAS No. 133 also requires that changes in the fair value of a derivative be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133 pro- vides an exception for contracts intended for normal purchase and normal sale, other than a financial instrument or derivative instru- ment for which physical delivery is probable. Many of the Com- pany’s gas supply and transportation contracts are considered deriv- ative instruments as defined under SFAS No. 133, but qualify for the normal purchase and normal sale exception. NW Natural designates its derivatives as fair value or cash flow hedges based upon the criteria established by SFAS No. 133. For fair value hedges, the gain or loss is recognized in earnings in the period of change. For cash flow hedges, the effective portion of the gain or loss is initially reported in accumulated other comprehen- sive income (OCI), unless the derivative is subject to deferral under NW Natural’s regulated tariffs with the OPUC or the WUTC. The ineffective portion of the gain or loss in a cash flow hedge is rec- ognized in current earnings, but only to the extent that the amount is not covered under NW Natural’s regulatory deferral mechanism. Effectiveness is measured by comparing changes in cash flows of the hedged item to gains or losses on derivative instruments. NW Natural’s primary hedging activities, consisting of natural gas commodity price and foreign currency exchange rate hedges, are principally accounted for as cash flow hedges under SFAS No. 133 and are subject to regulatory deferral under SFAS No. 71. Unrealized gains and losses from mark-to-market valuations of these contracts are not recognized in current income but are reported as derivative assets or liabilities and offset by a corresponding deferred account balance included under “regulatory liabilities” or “regulatory assets.” Due to their regulatory deferral treatment, effective portions of changes in the fair value of these derivatives are not recorded in OCI but are recognized as a regulatory asset or liability. Income Taxes The Company accounts for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes.” Under SFAS No. 109, the Company recognizes deferred income taxes for all temporary differences between the financial statement and tax basis of assets and liabilities at current income tax rates. Deferred tax liabilities and assets reflect the expected future tax consequences, based on enacted tax law, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts (see Note 8). SFAS No. 109 also requires recognition of the additional deferred income tax assets and liabilities for temporary differences where regulators prohibit deferred income tax treatment for ratemaking purposes. Consistent with rate and accounting orders of regulato- ry authorities, deferred income taxes are not currently collected for those temporary income tax differences where the prescribed reg- ulatory accounting methods do not provide for current recovery in rates. NW Natural has recorded a regulatory tax asset for amounts pending recovery from customers in future rates, equivalent to $63.4 million and $48 million at Dec. 31, 2003 and 2002, respec- tively. These amounts are primarily based on differences between the book and tax bases of net utility plant in service. Investment tax credits on utility plant additions and leveraged leases, which reduce income taxes payable, are deferred for finan- cial statement purposes and are amortized over the life of the relat- ed plant or lease. Investment and energy tax credits generated by non-regulated subsidiaries are amortized over a period of one to five years. Other Income (Expense) Other income (expense) consists of interest income, gain on sale of assets, investment income of Financial Corporation, the costs incurred in connection with the Company’s effort to acquire Portland General Electric Company (PGE) from Enron Corp. and other miscellaneous income from merchandise sales, rents, leas- es and other items. Earnings Per Share 37 Basic earnings per share are computed based on the weighted average number of common shares outstanding each year. Diluted earnings per share reflect the potential effects of the conversion of convertible debentures and the exercise of stock options. Diluted earnings are calculated as follows: Thousands, except per share amounts 2003 2002 2001 Net income $ 45,983 $ 43,792 $ 50,187 Redeemable preferred and preference stock dividend requirements Debenture interest less taxes Average common shares outstanding – basic Earnings applicable to common stock – basic 2,280 294 ________ ________ 41,512 45,689 285 257 ________ ________ Earnings applicable to common stock – diluted $ 45,946 $ 41,797 ________ ________ ________ ________ 25,431 25,741 59 28 324 292 ________ ________ 26,061 25,814 ________ ________ ________ ________ $ 1.77 $ 1.63 ________ ________ ________ ________ Earnings per share of common stock – diluted $ 1.76 $ 1.62 ________ ________ ________ ________ Stock options Convertible debentures Average common shares outstanding – diluted Earnings per share of common stock – basic 2,401 ________ 47,786 370 ________ $ 48,156 ________ ________ 25,159 32 421 ________ 25,612 ________ ________ $ 1.90 ________ ________ $ 1.88 ________ ________ N W N A T U R A L Notes to Consolidated Financial Statements 38 For the years ended Dec. 31, 2003, 2002 and 2001, 77,500 shares, 84,000 shares and 138,491 shares, respectively, representing the number of stock options the exercise prices for which were greater than the average market prices for the Company’s common stock for such years, were excluded from the calculation of diluted earn- ings per share because the effect was antidilutive. Stock-Based Compensation The Company applies APB Opinion No. 25, “Accounting for Stock Issued to Employees,” to account for its stock-based compensation plans. Accordingly, the Company does not recognize compensation expense for the fair value of its stock option grants. Instead, the Company has elected to continue using the intrinsic value method of accounting for stock options rather than adopting the fair val- ue method of accounting. However, the Company does recognize compensation expense for the fair value of stock awards granted under its Long-Term Incentive Plan and Non-Employee Directors Stock Compensation Plan in the period when shares are earned (see Note 4). 2 CONSOLIDATED SUBSIDIARY OPERATIONS AND SEG- MENT INFORMATION: At Dec. 31, 2003, the Company had two direct, wholly-owned subsidiaries, Financial Corporation and Northwest Energy. North- west Energy was formed in 2001 to serve as the holding company for NW Natural and PGE if the acquisition of PGE had been com- pleted. Since the acquisition of PGE has been terminated, Northwest Energy remains a non-active subsidiary of the Company. The Company’s core business is the distribution and sale of nat- ural gas (“Utility” segment). Another segment, “Gas Storage,” rep- resents natural gas storage services provided to interstate customers, including asset optimization services under a contract with an in- dependent energy trading company. The remaining business seg- ment, “Other,” primarily consists of non-regulated investments in alternative energy projects in California (see “Financial Corporation,” below), a Boeing 737-300 aircraft leased to Continental Airlines and Northwest Energy’s limited acquisition activities (see Note 9). Gas Storage Gas storage services are provided to off-system interstate cus- tomers using Company-owned storage capacity that has been devel- oped in advance of core utility customers’ (residential, commercial and industrial firm) requirements. NW Natural retains 80 percent of the income before tax from gas storage services and credits the remaining 20 percent to a deferred regulatory account for sharing with its core utility customers. Results for the gas storage segment also include revenues, net of amounts shared with core utility customers, from a contract with an independent energy trading company that seeks to opti- mize the use of NW Natural’s assets by trading temporarily unused portions of its gas storage capacity and upstream pipeline trans- portation capacity. NW Natural retains 80 percent of the pre-tax income from the optimization of storage and pipeline transporta- tion capacity when the costs of such capacity have not been includ- ed in core utility rates, or 33 percent of the pre-tax income from such capacity when the costs have been included in core utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for distribution to NW Natural’s core utility customers. Financial Corporation Financial Corporation has several financial investments, includ- ing investments as a limited partner in solar electric generating sys- tems, windpower electric generating projects and low-income hous- ing projects. Financial Corporation’s total assets were $8.0 million and $11.6 million at Dec. 31, 2003 and 2002, respectively. Segment Information Summary The following table presents summary financial information about the reportable segments for 2003, 2002 and 2001. Inter-seg- ment transactions are insignificant. Gas Storage Thousands Utility Other Total 2003 Net operating revenues Depreciation and amortization Other operating expenses Income from operations Income from financial investments Net income Total assets at Dec. 31, 2003 2002 Net operating revenues Depreciation and amortization Other operating expenses Income from operations Income from financial investments Loss provision for PGE transaction costs Net income (loss) Total assets at Dec. 31, 2002 2001 Net operating revenues Depreciation and amortization Other operating expenses (income) Income from operations Income (loss) from financial investments Net income Total assets at Dec. 31, 2001 3 CAPITAL STOCK: Common Stock $ 278,856 $ 9,036 $ 174 $ 288,066 54,249 131,545 102,272 3,880 45,983 14,526 1,591,332 53,798 130,619 94,439 3,406 40,913 1,558,342 451 804 7,781 – 4,312 18,464 – 122 52 474 758 $ 279,414 $ 7,944 $ 186 $ 287,544 52,090 119,196 116,258 2,378 51,693 118,156 109,565 1,390 396 962 6,586 – 1 78 107 988 – 47,280 1,432,776 – 3,646 16,403 (8,414) (8,414) (7,134) 43,792 18,098 1,467,277 $ 271,473 $ 4,368 $ 170 $ 276,011 49,640 116,160 110,211 49,413 115,708 106,352 227 489 3,652 – (37) 207 1,646 47,233 1,506,787 – 2,112 14,243 (321) 842 1,325 50,187 29,623 1,550,653 At Dec. 31, 2003, NW Natural had reserved 134,240 shares of common stock for issuance under the Employee Stock Purchase Plan, 353,059 shares for future conversions of its 7-1/4% Conver- tible Debentures, 389,951 shares under its Dividend Reinvestment and Stock Purchase Plan, 1,751,544 shares under its Restated Stock Option Plan (see Note 4), and 3,000,000 shares under the Share- holder Rights Plan. Redeemable Preferred Stock On Nov. 14, 2003, NW Natural redeemed all of the remaining shares of its $7.125 Series of Redeemable Preferred Stock with an aggregate stated value of $7.5 million, at a redemption price equiv- alent to 102.375 percent with proceeds from sales of commercial paper. The Company re-financed the commercial paper with the sale of new long-term debt in the fourth quarter of 2003. The early re- demption premium from the redemption of the $7.125 Series was recognized as an unamortized cost pursuant to SFAS No. 71 and will be amortized to expense over the life of the new debt. Redeemable Preference Stock On Dec. 31, 2002, NW Natural redeemed all 250,000 shares of its $6.95 Series of Redeemable Preference Stock with proceeds from the sale of commercial paper. Stock Repurchase Program NW Natural’s Board of Directors approved a stock repurchase program in 2000 to purchase up to 2 million shares, or up to $35 million in value, of NW Natural’s common stock in the open mar- ket or through privately negotiated transactions. The repurchase program has been extended through May 2004. No shares were repurchased in 2002 or 2003. Since the program’s inception, the Company has repurchased 355,400 shares of common stock at a total cost of $8.2 million. Restated Stock Option Plan In May 2002, the shareholders approved an amendment to the Restated Stock Option Plan that increased the total number of shares authorized for option grants from 1,200,000 to 2,400,000 N W N A T U R A L shares. At Dec. 31, 2003, options on 1,429,500 shares were avail- able for grant and options on 322,044 shares were outstanding. The following table shows the changes in the number of shares of NW Natural’s capital stock and the premium on common stock for the years 2003, 2002 and 2001: ––––––––––––– Shares ––––––––––––– Premium on common Redeemable Redeemable stock preferred stock (thousands) Common preference stock stock Balance, Dec. 31, 2000 Sales to employees Sales to stockholders Exercise of stock options – net Conversion of convertible debentures to common Stock repurchases Sinking fund purchases Balance, Dec. 31, 2001 Sales to employees Sales to stockholders Exercise of stock options – net Conversion of convertible debentures to common Sinking fund purchases Redemption Balance, Dec. 31, 2002 Sales to employees Sales to stockholders Exercise of stock options – net Conversion of convertible debentures to common Sinking fund purchases Early redemption Balance, Dec. 31, 2003 25,233,424 30,952 177,624 12,289 250,000 – – – 97,500 $ 238,215 498 3,854 110 – – – 20,485 (246,700) – __________ 25,228,074 42,862 157,288 61,020 – – – ________ 250,000 – – – 343 (2,323) – ________ _________ 240,697 748 3,854 1,105 – – (7,500) 90,000 – – – 97,069 – – __________ 25,586,313 14,175 178,714 127,357 – – (250,000) ________ – – – – 1,624 – – ________ _________ 248,028 425 4,347 2,545 – (7,500) – 82,500 – – – 31,443 – – __________ 25,938,002 __________ __________ – – – ________ – ________ ________ – (7,500) (75,000) 526 – – ________ _________ – $ 255,871 ________ _________ ________ _________ 4 STOCK-BASED COMPENSATION: NW Natural has the following stock-based compensation plans: the Long-Term Incentive Plan (LTIP); the Restated Stock Option Plan (Restated SOP); the Employee Stock Purchase Plan (ESPP); and the Non-Employee Directors Stock Compensation Plan (NEDSCP). These plans are designed to promote stock ownership in NW Natural by employees, officers and, in the case of the NEDSCP, non-employ- ee directors. NW Natural’s shareholders approved the LTIP effective Jan. 1, 2001, to provide a flexible, competitive compensation program for eligible officers. An aggregate of 500,000 shares of common stock was authorized for grants under the LTIP as stock bonus, restrict- ed stock or performance-based stock awards. Shares awarded under the LTIP are purchased on the open market. Through Dec. 31, 2003, NW Natural has granted four performance-based awards, one based on a two-year performance period (2001-02) and three based on three-year performance periods (2001-03, 2002-04 and 2003-05), and one restricted stock award. The aggregate target awards for each of the 2001-02 and the 2001-03 performance-based award periods were 26,000 shares and the maximum awards were 52,000 shares; the aggregate target and maximum awards for the 2002-04 award period were 29,000 and 58,000 shares, respective- ly; and the aggregate target and maximum awards for the 2003-05 award period were 32,000 and 64,000 shares, respectively. Final awards depend on the attainment of certain return on equity per- formance goals. At Dec. 31, 2003, the two-year and three-year per- formance-based awards that started in 2001 lapsed because the performance-based measures were not achieved. The restricted stock award consists of 4,500 shares granted in 2001 with a vest- ing period of 65 months. The LTIP stock awards are compensatory awards for which compensation expense is recognized based on the market value of performance shares earned, or a pro rata amor- tization over the vesting period for the restricted stock award. The Restated SOP authorizes an aggregate of 2,400,000 shares of common stock for issuance as incentive or non-statutory stock options. These options may be granted only to officers and key employees designated by a committee of NW Natural’s Board of Directors. All options are granted at an option price not less than the market value at the date of grant and may be exercised for a period not exceeding 10 years from the date of grant. Option hold- ers may exchange shares they have owned for at least six months, at the current market price, to purchase shares at the option price. Since inception in 1985, options on 1,100,921 shares of common stock have been granted at prices ranging from $11.75 to $27.875 per share, and options on 130,421 shares have expired. In accordance with APB No. 25, no compensation expense is rec- ognized for options granted under the Restated SOP or shares issued under the ESPP. If compensation expense for awards under these two plans had been determined based on fair value at the grant dates using the method prescribed by SFAS No. 123, “Accounting for Stock-Based Compensation,” net income and earnings per share would have been reduced to the pro forma amounts shown below: Pro Forma Effect of Stock Options: Thousands, except per share amounts 2003 2002 2001 Net income as reported $ 45,983 $ 43,792 $ 50,187 Pro forma stock-based compensation expense determined under the fair value based method – net of tax Pro forma net income Redeemable preferred and preference stock Pro forma earnings applicable to common stock – basic Debenture interest less taxes Pro forma earnings applicable to common stock – diluted Basic earnings per share As reported Pro forma Diluted earnings per share As reported Pro forma (279) ________ 45,704 (294) ________ (478) ________ 43,314 (2,280) ________ (338) ________ 49,849 (2,401) ________ 45,410 257 ________ 41,034 285 ________ 47,448 370 ________ $ 45,667 ________ ________ $ 41,319 ________ ________ $ 47,818 ________ ________ $ 1.77 $ 1.76 $ 1.63 $ 1.61 $ 1.90 $ 1.89 $ 1.76 $ 1.75 $ 1.62 $ 1.60 $ 1.88 $ 1.87 39 The fair value of each stock option grant is estimated on the grant date (there were no stock option grants in 2003) using the Black- Scholes option pricing model with the following weighted average assumptions: 2002 2001 Expected life in years Risk-free interest rate Expected volatility Dividend yield Present value of options granted 7.0 3.6% 29.1% 4.8% 7.0 5.2% 31.0% 4.9% $ 20.49 $ 17.34 Information regarding the Restated SOP’s activity is summarized as follows: Balance outstanding, Dec. 31, 2000 Granted Exercised Expired Balance outstanding, Dec. 31, 2001 Granted Exercised Expired Balance outstanding, Dec. 31, 2002 Exercised Expired Balance outstanding, Dec. 31, 2003 Shares available for grant Dec. 31, 2001 Shares available for grant Dec. 31, 2002 Shares available for grant Dec. 31, 2003 Options 416,005 15,000 (12,289) (31,625) ________ 387,091 163,750 (68,827) (18,200) ________ 463,814 (140,470) (1,300) ________ 322,044 373,750 1,428,200 1,429,500 ––––––– Price per Share ––––––– Weighted- Average Range Exercise Price $ 20.17 – 27.875 24.91 20.17 – 20.920 20.25 – 27.875 20.25 – 27.875 26.07 – 27.850 20.25 – 27.875 20.25 – 27.875 20.25 – 27.875 20.25 – 27.875 20.25 $ 22.75 24.91 20.36 24.31 22.79 26.35 21.74 25.43 24.10 21.14 20.25 20.25 – 27.875 $ 25.35 N W N A T U R A L 40 Notes to Consolidated Financial Statements The weighted average remaining contractual life of outstanding stock options at Dec. 31, 2003 was 6.5 years. The characteristics of exercisable stock options at Dec. 31, 2003 were as follows: Range of Exercise Prices $20.25 – $27.875 Exercisable Stock Options 213,144 Weighted– Average Exercise Price $ 24.86 The ESPP allows employees to purchase common stock at 85 percent of the closing price on the trading day immediately pre- ceding the subscription date, which is set annually. Each eligible employee may purchase up to $24,000 worth of stock through payroll deduction over a six to 12-month period. Effective Feb. 26, 2004, the NEDSCP was amended to permit non-employee directors to receive awards either in cash or in Com- pany stock. If non-employee directors elect to receive their awards in stock, approximately $100,000 worth of the Company’s common stock is awarded upon joining the Board. These stock awards are subject to vesting and to restrictions on sale and transferability. The shares vest in monthly installments over the five calendar years fol- lowing the award. On Jan. 1 of each year following the initial award, non-employee directors who elect to receive awards in Company stock are awarded an additional $20,000 worth of restricted Com- pany stock, which vests in monthly installments in the fifth year following the award (after the previous award has fully vested). The Company holds the certificates for the restricted shares until the non-employee director ceases to be a director. Participants receive all dividends and have full voting rights on both vested and unvest- ed shares. All awards vest immediately upon a change in control of the Company. Any unvested shares are considered to be un- earned compensation, and thus are forfeited if the recipient ceas- es to be a director. The shares are purchased in the open market by the Company at the time of the award. The following table presents the changes in unearned stock compensation for the years 2003 and 2002, which are reported as a reduction to total common equity in the consolidated balance sheets: 2002 Thousands 2003 Unearned stock compensation: Balance at beginning of year Purchases of restricted stock Restricted stock amortizations Balance at end of year $ 711 328 (310) ________ $ 729 ________ ________ $ 372 891 (552) ________ $ 711 ________ ________ Under a separate plan, non-employee directors also may elect to invest their cash fees and retainers for board service in shares of the Company’s common stock. 5 LONG-TERM DEBT: The issuance of first mortgage debt, including secured medium- term notes, under the Mortgage and Deed of Trust (Mortgage) is limited by property additions, adjusted net earnings and other pro- visions of the Mortgage. The Mortgage constitutes a first mortgage lien on substantially all of NW Natural’s utility property. The 7-1/4% Series of Convertible Debentures may be convert- ed at any time into 50-1/4 shares of common stock for each $1,000 face value ($19.90 per share). The maturities on the long-term debt and redeemable preferred stock outstanding, for each of the 12-month periods through Dec. 31, 2008 amount to: none in 2004; $15 million in 2005; $8 million in 2006; $29.5 million in 2007; and $5 million in 2008. Holders of certain Medium-Term Notes (MTNs) have put options that, if exer- cised, would accelerate the maturity of long-term debt by $10 mil- lion in 2005, $20 million in 2007 and $20 million in 2008. 6 NOTES PAYABLE AND LINES OF CREDIT: The Company’s primary source of short-term funds is com- mercial paper notes payable. Both NW Natural and Financial Cor- poration issue commercial paper under agency agreements with a commercial bank. NW Natural’s commercial paper is supported by its committed bank lines of credit (see below), while Financial Cor- poration’s commercial paper is supported by committed bank lines of credit and the guaranty of NW Natural. The amounts and aver- age interest rates of commercial paper debt outstanding at Dec. 31 were as follows: Thousands NW Natural Financial Corporation Total –––––––– 2003 –––––––– Rate Amount –––––––– 2002 –––––––– Rate Amount $ 85,200 – ________ $ 85,200 ________ ________ 1.1% $ 69,802 – ________ $ 69,802 ________ ________ – 1.4% – NW Natural has lines of credit with four commercial banks total- ing $150 million. Half of the credit facility with each bank, totaling $75 million, is committed and available through Sept. 30, 2004, and the other $75 million is committed and available through Sept. 30, 2005. NW Natural may be unable to draw upon the two-year por- tions of the credit lines, totaling $75 million, until filings are made or approvals received from the OPUC or the WUTC with respect to its notes relating to the two-year commitments. NW Natural expects that it will be able to make the necessary filings or secure such approvals, if required. Financial Corporation has available through Sept. 30, 2004, committed lines of credit with two commercial banks totaling $10 million. Financial Corporation’s lines are supported by the guar- anty of NW Natural. Under the terms of these lines of credit, NW Natural and Fin- ancial Corporation pay commitment fees but are not required to maintain compensating bank balances. The interest rates on bor- rowings under these lines of credit, if any, are based on current mar- ket rates. There were no outstanding balances on either the NW Natural or Financial Corporation lines of credit as of Dec. 31, 2003 or 2002. NW Natural’s lines of credit require that credit ratings be main- tained in effect at all times and that notice be given of any change in its senior unsecured debt ratings. A change in NW Natural’s cred- it rating is not an event of default, nor is the maintenance of a spe- cific minimum level of credit rating a condition to drawing upon the lines of credit. However, interest rates on any loans outstand- ing under NW Natural’s bank lines are tied to credit ratings, which would increase or decrease the cost of bank debt, if any, when rat- ings are changed. The lines of credit require the Company to maintain an indebt- edness to total capitalization ratio of 65 percent or less and to maintain a consolidated net worth at least equal to 80 percent of its net worth at Sept. 30, 2003, plus 50 percent of the Company’s net income for each subsequent fiscal quarter. Failure to comply with either of these covenants would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding. The Company was in compliance with both of these covenants at Dec. 31, 2003, and with the equivalent covenants in the prior year’s lines of credit at Dec. 31, 2002. 7 PENSION AND OTHER POSTRETIREMENT BENEFITS: NW Natural maintains two qualified non-contributory defined benefit pension plans covering all regular employees with more than one year of service, a non-qualified supplemental pension plan for eligible executive officers and other postretirement benefit plans for its employees. Only the two qualified defined benefit pension plans have plan assets. Those assets are held in a qualified trust to fund retirement benefits. N W N A T U R A L The following table provides a reconciliation of the changes in benefit obligations and fair value of assets, as applicable, for the pension plans and other postretirement benefit plans over the three-year period ended Dec. 31, 2003, and a statement of the funded status and amounts recognized in the consolidated balance sheets, using measurement dates of Dec. 31, 2003, 2002 and 2001: Post-Retirement Benefits Thousands Change in benefit obligation: Benefit obligation at Jan. 1 Service cost Interest cost Expected benefits paid Plan amendments Net actuarial (gain) loss Benefit obligation at Dec. 31 Change in plan assets: Fair value of plan assets at Jan. 1 Actual return on plan assets Employer contributions Benefits paid Fair value of plan assets at Dec. 31 Funded status: Funded status at Dec. 31 Unrecognized transition obligation Unrecognized prior service cost Unrecognized net actuarial (gain) loss Net amount recognized Amounts recognized in the consolidated balance sheets at Dec. 31 Prepaid benefit cost Accrued benefit liability Intangible asset Other comprehensive loss Net amount recognized ––––––––––––––– Pension Benefits ––––––––––––––– 2001 2003 2002 ––––––––– Other Postretirement Benefits ––––––––– 2001 2003 2002 $ 185,124 4,748 12,402 (10,363) – 13,441 _________ 205,352 _________ 143,164 34,520 1,003 (10,363) _________ 168,324 _________ (37,028) – 6,240 32,156 _________ $ 1,368 _________ _________ $ 11,113 (11,319) – 1,574 _________ $ 1,368 _________ _________ $ 166,751 4,637 11,807 (9,453) – 11,382 _________ 185,124 _________ 168,964 (17,082) 735 (9,453) _________ 143,164 _________ (41,960) – 7,371 42,060 _________ $ 7,471 _________ _________ $ 17,339 (18,741) 4,438 4,435 _________ $ 7,471 _________ _________ $ 146,802 3,964 11,332 (9,152) 1,838 11,967 _________ 166,751 _________ 190,451 (13,077) 742 (9,152) _________ 168,964 _________ 2,212 351 8,575 (2,956) _________ $ 8,182 _________ _________ $ 17,211 (9,346) 169 148 _________ $ 8,182 _________ _________ $ 18,457 456 1,336 (1,027) (111) 4,268 _________ 23,379 _________ – – 1,027 (1,027) _________ – _________ (23,379) 3,703 – 8,304 _________ $ (11,372) _________ _________ $ – (11,372) – – _________ $ (11,372) _________ _________ $ 16,987 395 1,174 (979) (300) 1,180 _________ 18,457 _________ – – 979 (979) _________ – _________ (18,457) 4,226 – 4,437 _________ $ (9,794) _________ _________ $ – (9,794) – – _________ $ (9,794) _________ _________ $ 14,069 325 1,116 (942) – 2,419 _________ 16,987 _________ – – 942 (942) _________ – _________ (16,987) 4,795 172 3,405 _________ $ (8,615) _________ _________ $ – (8,615) – – _________ $ (8,615) _________ _________ The Company’s pension plan asset allocation at Dec. 31, 2003 and 2002, and the target allocation and expected long-term rate of return by asset category for 2004 are as follows: 41 Asset Category US Large Cap Equity US Small/Mid Cap Equity Non-US Equity Fixed Income Real Estate Absolute Return Weighted Average Percentage of Plan Assets Dec. 31, 2003 40.2% 7.3% 16.0% 24.8% 3.9% 7.8% 2002 36.3% 4.3% 17.1% 34.7% 2.0% 5.6% Expected Long-Term Rate of Return 2004 Target Allocation 2004 40% 8% 15% 25% 40% 8% 9.00% 9.50% 9.00% 6.00% 8.00% 9.00% 8.25% The Company’s non-qualified supplemental pension plan’s accu- mulated benefit obligation was $13.0 million, $12.8 million and $10.7 million at Dec. 31, 2003, 2002 and 2001, respectively. Although this plan is an unfunded plan with no plan assets due to its nature as a non-qualified plan, the Company indirectly funds its obliga- tions with trust-owned life insurance. The amount of life insurance coverage is designed to provide sufficient returns to cover the ben- efit obligations and other costs of the plan. The Company’s plans for providing postretirement benefits other than pensions also are unfunded plans. The aggregate ben- efit obligation for those plans was $23.4 million, $18.5 million and $17.0 million at Dec. 31, 2003, 2002 and 2001, respectively. The Company’s qualified defined benefit pension plans had an accumulated benefit obligation in excess of plan assets at Dec. 31, 2003. The plans’ aggregate accumulated benefit obligation was $192 million, $172 million and $156 million at Dec. 31, 2003, 2002 and 2001, respectively, and the fair value of plan assets was $168 million, $143 million and $169 million, respectively. The fair val- ue of plan assets increased from Dec. 31, 2002 to Dec. 31, 2003 due to $36 million in investment gains, partially offset by $10 million in withdrawals to pay benefits and $0.9 million to pay eligible expenses of the plans. The combination of investment returns and cash contributions is expected to provide sufficient funds to cov- er all benefit obligations of the plans. The Company is required to make a cash contribution of at least $1.9 million, and may make an additional contribution up to a total of $6.8 million, to its non- bargaining employee pension plan for the 2003 plan year, payable by Sept. 15, 2004. The Company’s investment policy and performance objectives for the qualified pension plan assets (plan assets) held in the North- west Natural Gas Company Retirement Trust Fund was approved by a retirement committee composed of management employees. The policy sets forth the guidelines and objectives governing the investment of plan assets. Plan assets are invested for total return with appropriate consideration for liquidity and portfolio risk. All investments are expected to satisfy the requirements of the rule of prudent investments as set forth under the Employee Retirement Security Act of 1974 (ERISA). The approved asset classes are cash and short-term investments, fixed income, common stock and con- vertible securities, absolute return strategies, real estate and invest- ments in securities of NW Natural, and may be invested in sepa- rately managed accounts or in commingled or mutual funds. Re-balancing will take place at least annually, or when significant cash flows occur, in order to maintain the allocation of assets with- in the stated target allocation ranges. The Retirement Trust Fund is not currently invested in any NW Natural securities. N W N A T U R A L Notes to Consolidated Financial Statements The following tables provide the components of net periodic benefit cost (income) for the pension and other postretirement bene- fit plans for the years ended Dec. 31, 2003, 2002 and 2001, and the assumptions used in measuring these costs and benefit obligations: ––––––––– Other Postretirement Benefits ––––––––– 2001 ––––––––––––––– Pension Benefits ––––––––––––––– 2001 Thousands 2003 2003 2002 2002 Service cost Interest cost Expected return on plan assets Amortization of transition obligation Amortization of prior service cost Recognized actuarial (gain) loss Net periodic benefit cost (income) Assumptions: Discount rate for net periodic benefit cost (NPBC) Rate of increase in compensation for NPBC Expected long-term rate of return for NPBC Discount rate for determination of funded status Rate of increase in compensation for funded status Expected long-term rate of return for funded status $ 4,748 12,402 (12,232) – 1,132 1,058 _________ $ 7,108 _________ _________ $ 4,637 11,807 (16,335) 351 1,204 (216) _________ $ 1,448 _________ _________ $ 3,964 11,332 (17,198) 351 1,284 (2,464) _________ $ (2,731) _________ _________ 7.25% 6.75% 7.50% 4.25 – 5.00% 4.25 – 5.00% 4.25 – 5.00% 9.00% 7.25% 4.00 – 4.75% 4.25 – 5.00% 4.25 – 5.00% 9.00% 8.00% 6.25% 9.00% 6.75% 8.25% 8.00% $ 456 1,336 – 411 – 401 _________ $ 2,604 _________ _________ 6.75% n/a n/a 6.25% n/a n/a $ 395 1,174 – 436 6 147 _________ $ 2,158 _________ _________ 7.25% n/a n/a 6.75% n/a n/a $ 325 1,116 – 436 19 75 _________ $ 1,971 _________ _________ 7.50% n/a n/a 7.25% n/a n/a The assumed annual trend rates used in measuring postretire- ment benefits as of Dec. 31, 2003 were 9 percent for medical and 14 percent for prescription drugs. Medical costs were assumed to decrease gradually each year to a rate of 4.5 percent for 2008, while prescription drug costs were assumed to decrease gradually each year to a rate of 4.5 percent for 2013. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one per- centage point change in assumed health care cost trend rates would have the following effects: Thousands 1% Decrease 1% Increase 42 Effect on the total service and interest cost components of net periodic postretirement health care benefit cost Effect on the health care component of the accumulated postretirement benefit obligation $ 71 $ (67) $ 955 $ (858) The following table provides information regarding employer contributions and benefit payments for the pension and other postretirement benefit plans for the years ended Dec. 31, 2003 and 2002, and estimated future payments: Thousands Employer Contributions by Plan Year 2002 2003 2004 (estimated) Benefit Payments 2002 2003 Estimated Future Benefit Payments 2004 2005 2006 2007 2008 2009 – 2013 Pension Benefits $ 735 2,949 3,007 $ 9,440 10,363 $ 11,667 12,224 12,698 12,965 13,811 78,915 Other Postretirement Benefits $ 979 1,027 1,509 $ 979 1,027 $ 1,509 1,555 1,674 1,770 1,883 10,312 NW Natural’s Retirement K Savings Plan (RKSP) is a qualified defined contribution plan under Internal Revenue Code Section 401(k). NW Natural also has a non-qualified deferred compensa- tion plan for eligible officers and senior managers. These plans are designed to enhance the retirement program of employees and to assist them in strengthening their financial security by provid- ing an incentive to save and invest regularly. NW Natural’s match- ing contributions to these plans totaled $1.6 million in 2003, $1.4 million in 2002 and $1.3 million in 2001. Effective Jan. 1, 2002, the RKSP was amended to establish an Employee Stock Ownership Plan (ESOP) within the RKSP by con- verting the existing RKSP Company Stock Fund into an ESOP. This amendment allowed the Company to claim a tax benefit of $0.2 mil- lion in both 2003 and 2002 for the dividends paid on the Company’s common stock held by the ESOP. In order to claim this deduction, the Company was required to allow RKSP participants the option of receiving the dividends paid on the Company’s common stock in the ESOP account in cash rather than having the dividends auto- matically reinvested (see Note 8). 8 INCOME TAXES: A reconciliation between income taxes calculated at the statu- tory federal tax rate and the tax provision reflected in the finan- cial statements is as follows: Thousands 2003 2002 2001 Computed income taxes based on statutory federal income tax rate of 35% Increase (reduction) in taxes resulting from: $ 24,263 $ 23,533 $ 27,209 Difference between book and tax depreciation Current state income tax, net of federal tax benefit Federal income tax credits Amortization of investment tax credits Gains on Company and trust-owned life insurance Removal costs Reversal of amounts provided in prior years Other – net Total provision for income taxes Total income taxes paid 222 222 222 2,310 (357) (879) 2,299 (362) (858) 2,672 (362) (855) (1,192) (487) (925) (573) (226) (240) 124 (90) ________ ________ $ 23,340 $ 23,444 ________ ________ ________ ________ $ 13,940 $ 33,474 ________ ________ ________ ________ (576) (508) (72) (177) ________ $ 27,553 ________ ________ $ 25,201 ________ ________ The provision for income taxes consists of the following: Thousands 2003 2002 2001 Income taxes currently payable: Federal State Total Deferred taxes – net: Federal State Total Investment and energy tax credits restored: From utility operations From subsidiary operations Total Total provision for income taxes Percentage of pretax income $ 10,011 $ 9,377 1,175 1,239 ________ ________ 10,616 11,186 ________ ________ $ 32,682 5,912 ________ 38,594 ________ 10,747 2,286 ________ 13,033 ________ 11,476 2,210 ________ 13,686 ________ (8,606) (1,580) ________ (10,186) ________ (801) (800) (78) (58) ________ ________ (879) (858) ________ ________ $ 23,340 $ 23,444 ________ ________ ________ ________ 33.7% 34.9% ________ ________ ________ ________ (800) (55) ________ (855) ________ $ 27,553 ________ ________ 35.4% ________ ________ N W N A T U R A L Deferred tax assets and liabilities are comprised of the following: 2002 2003 Thousands Deferred tax liabilities: Plant and property Regulatory income tax assets Regulatory liabilities Other deferred liabilities Total Deferred tax assets: Regulatory assets Minimum pension liability Other deferred assets Total Net accumulated deferred income tax liability $ 113,781 $ 96,525 47,975 319 6,569 ________ 151,388 ________ 63,449 – 6,109 _________ 183,339 _________ 970 – 557 1,883 7,773 10,015 _________ ________ 9,656 11,542 _________ ________ $ 171,797 $ 141,732 ________ _________ ________ _________ Tax benefits of $1.3 million associated with charges for mini- mum pension liabilities in 2002 were reversed in OCI for the year ended Dec. 31, 2003. 9 PROPERTY AND INVESTMENTS: The following table sets forth the major classifications of NW Natural’s utility plant and accumulated depreciation at Dec. 31: Thousands ––––––––– 2003 ––––––––– ––––––––– 2002 ––––––––– Average Depreciation Rate Average Depreciation Rate Amount Amount Utility plant in service Transmission and distribution $ 1,347,402 107,547 Utility storage 87,107 General 56,429 Intangible and other ___________ 1,598,485 12,778 47,826 ___________ 1,659,089 (471,176) __________ $ 1,187,373 ___________ ___________ Gas stored long-term Construction work in progress Accumulated depreciation Utility plant – net Total utility plant 3.4% 2.7% 6.3% 4.3% 3.5% 3.3% $ 1,254,624 107,110 2.7% 83,878 6.0% 5.1% 53,291 __________ 3.5% 1,498,903 11,301 29,761 __________ 1,539,965 (435,601) ________ $ 1,104,364 __________ __________ Accumulated depreciation does not include $135.6 million and $125.2 million at Dec. 31, 2003 and 2002, respectively, due to the reclassification of accumulated depreciation relating to removal costs in accordance with SFAS No. 143 (see Note 1). The following table summarizes the Company’s investments in non-utility plant at Dec. 31: Thousands Non-utility storage Dock, land, oil station and other Construction work in progress Total non-utility plant Less accumulated depreciation Non-utility plant – net 2003 2002 $ 18,507 $ 17,037 3,795 3,846 – 1,042 ________ _________ 20,832 23,395 4,404 4,855 ________ _________ $ 18,540 $ 16,428 ________ _________ ________ _________ The following table summarizes the Company’s partnership and joint venture investments accounted for under the equity or cost methods, and its investment in an aircraft leveraged lease, at Dec. 31: Thousands 2003 2002 Aircraft leveraged lease Gas pipeline and other Electric generation Total other investments $ 6,438 $ 6,489 2,880 2,950 3,264 3,317 _________ ________ $ 12,635 $ 12,703 ________ _________ ________ _________ In 1987, the Company invested in a Boeing 737-300 aircraft, which is leased to Continental Airlines for 20 years under a lever- aged lease agreement. A Financial Corporation subsidiary, KB Pipeline Company, has a 10 percent ownership interest in an 18-mile interstate natural gas pipeline and is the operator of this pipeline. In December 2003, KB Pipeline gave notice to the pipeline co-owners that it is resigning as pipeline operator effective in June 2004 due to increased obli- gations resulting from the Federal Energy Regulatory Commission’s final regulations implementing Standards of Conduct for Transmis- sion Providers. Those regulations govern the relationship between interstate natural gas pipelines and their energy affiliates or mar- keting functions and impose obligations previously inapplicable to KB Pipeline with regard to separation of duties and related mat- ters. The regulations will continue to be applicable to KB Pipeline as a co-owner after its resignation as Pipeline operator. Financial Corporation has ownership interests ranging from 4.0 to 5.3 percent in solar electric generation plants located near Barstow, California. Power generated by these plants is sold to Southern California Edison Company under long-term contracts. Financial Corporation also has ownership interests ranging from 25 to 41 percent in wind power electric generation projects locat- ed near Livermore and Palm Springs, California. The wind-gener- ated power is sold to Pacific Gas and Electric Company and Southern California Edison Company under long-term contracts. 10 FAIR VALUE OF FINANCIAL INSTRUMENTS: The estimated fair value for NW Natural’s financial instruments has been determined using available market information and appro- priate valuation methodologies. The following are financial instru- ments whose carrying values are sensitive to market conditions: –––– Dec. 31, 2002 –––– Estimated Carrying Fair Value Amount –––– Dec. 31, 2003 –––– Carrying Estimated Amount Fair Value Thousands Redeemable preferred stock Long-term debt including amount due within one year $ – $ – $ 8,250 $ 8,333 $ 500,319 $ 562,688 $ 465,945 $ 518,495 Fair value of the redeemable preferred stock and long-term debt was estimated using market prices in effect on the valuation date. Interest rates for debt with similar terms and remaining maturities were used to estimate fair value for long-term debt issues. 43 11 USE OF FINANCIAL DERIVATIVES: NW Natural enters into short-term and long-term natural gas purchase contracts with suppliers, including contracts tied to float- ing prices. As such, NW Natural is exposed to changes in com- modity prices. Natural gas prices are subject to fluctuations due to unpredictable factors including weather, inventory levels, pipeline transportation availability, and the economy, each of which affects short-term supply and demand. As part of its overall strategy to maintain an acceptable level of exposure to gas price fluctuations, NW Natural uses a targeted mix of fixed-rate and cap-protected derivative instruments to hedge the exposure under floating price gas supply contracts. Swap contracts are used to convert certain long-term gas purchase contracts from floating prices to fixed prices. Call option contracts are used to limit the maximum adverse impact from floating price contracts while retaining the potential favorable impact from declining gas prices. The prices embedded in these commodity hedge contracts are incorporated in NW Natural’s annual rate changes under its Purchased Gas Adjustment rate mechanisms, thereby limiting customers’ exposure to frequent changes in purchased gas costs. The estimated fair value of gains and losses from commodity hedge contracts are recorded as a derivative asset or liability, and are offset by a corresponding amount recorded to a deferred regulatory asset or liability account for the effective portion of each hedge contract. The actual gains and losses realized at settlement of the hedge contracts are used to offset the actual purchase cost from NW Natural’s physical sup- ply contracts. N W N A T U R A L Notes to Consolidated Financial Statements Certain natural gas purchases from Canadian suppliers are invoiced in Canadian dollars, including both commodity and demand charges, thereby exposing NW Natural to adverse changes in foreign currency rates. Foreign currency forward contracts are used to minimize the impact of fluctuations in currency rates. Foreign currency contracts for commodity costs are purchased on a month-to-month basis because the Canadian cost is priced at the average noonday exchange rate for each month. Foreign cur- rency contracts for demand costs have terms ranging up to 24 months. The gains and losses on the shorter-term currency con- tracts for commodity costs are recognized immediately in cost of gas. The gains and losses on the longer-term currency contracts for demand charges are subject to a regulatory deferral tariff and, as such, are recorded as a derivative asset or liability which is offset by a corresponding amount to a deferred asset or liability account. NW Natural did not use any derivative instruments to hedge oil or propane prices or interest rates during 2003, 2002 or 2001. At Dec. 31, 2003, NW Natural had the following derivatives outstanding covering its exposures to commodity and foreign cur- rency prices: a series of 20 natural gas price swap contracts, three natural gas call option contracts, and 77 foreign currency forward contracts. Each of these contracts was designated as a cash flow hedge. The estimated fair values and the notional amounts of derivative instruments (unrealized gains and losses) outstanding were as follows: Thousands –––– Dec. 31, 2002 –––– –––– Dec. 31, 2003 –––– Notional Fair Value Fair Value Notional Amount Gain (Loss) Amount Gain (Loss) Fixed-price natural gas commodity swap contracts Fixed-price natural gas call option contracts Physical natural gas supply contract with embedded derivative Foreign currency forward purchase contracts Total $ 23,285 $ 284,317 $ 11,422 $ 159,724 366 19,761 – – 717 448 18,084 2,754 234 15,525 (161) _________ _________ _________ ________ $ 23,885 $ 310,495 $ 12,426 $ 196,087 ________ _________ _________ _________ ________ _________ _________ _________ 6,417 In 2003, NW Natural realized net gains of $32.4 million from the settlement of natural gas commodity swap and call option con- tracts, which were recorded as decreases to the cost of gas, com- pared to net losses of $75.5 million during 2002 and net gains of $57.6 million during 2001. The currency exchange rate in all for- eign currency forward purchase contracts is included in NW Natural’s cost of gas at settlement; therefore, no gain or loss was recorded from the settlement of those contracts. The change in value of cash flow hedge contracts, not included in regulatory recovery, is included in OCI. The fair value of derivative instruments at Dec. 31, 2003 (see table above) was determined using estimated or quoted market prices for the periods covered by the contracts. Market prices for the natural gas commodity-price swap and call option contracts were obtained from external sources. NW Natural reviews these third-party valuations for reasonableness using fair value calcula- tions for other contracts with similar terms and conditions. The mar- ket prices for the foreign currency forward contracts were based on currency exchange rates quoted by The Bank of Canada. As of Dec. 31, 2003, NW Natural had five natural gas commod- ity price swap contracts extending beyond Dec. 31, 2004, but none extends beyond Oct. 31, 2005. None of the natural gas commodi- ty call option contracts extends beyond March 31, 2004. 44 12 COMMITMENTS AND CONTINGENCIES: Lease Commitments The Company leases land, buildings and equipment under agreements that expire in various years through 2018. Rental expense under operating leases was $4.9 million, $4.8 million and $4.7 million for the years ended Dec. 31, 2003, 2002 and 2001, respectively. The table below reflects the future minimum lease pay- ments due under non-cancelable leases at Dec. 31, 2003. Such pay- ments total $74.5 million for operating leases. The net present val- ue of payments on capital leases less imputed interest was $0.3 million. These commitments principally relate to the lease of the Company’s office headquarters, underground gas storage facili- ties, vehicles and computer equipment. Later years Millions 2004 2005 2006 2007 2008 Operating leases Capital leases Minimum lease payments $ 4.3 0.1 _____ $ 4.4 _____ _____ $ 3.8 0.1 _____ $ 3.9 _____ _____ $ 3.8 0.1 _____ $ 3.9 _____ _____ $ 3.7 – _____ $ 3.7 _____ _____ $ 3.6 – _____ $ 3.6 _____ _____ $ 55.3 – _____ $ 55.3 _____ _____ Pipeline Capacity Purchase and Release Commitments NW Natural has signed agreements providing for the avail- ability of firm pipeline capacity under which it must make fixed monthly payments for contracted capacity. The pricing compo- nent of the monthly payment is established, subject to change, by U.S. or Canadian regulatory bodies. In addition, NW Natural has entered into long-term sale agreements to release firm pipeline capacity. The aggregate amounts of these agreements were as fol- lows at Dec. 31, 2003: Thousands 2004 2005 2006 2007 2008 2009 through 2023 Total Less: Amount representing interest Total at present value Pipeline Capacity Purchase Pipeline Capacity Release Agreements Agreements $ 56,296 $ 3,781 3,782 3,781 3,782 3,781 6,933 ________ 25,840 3,463 ________ $ 22,377 ________ ________ 60,540 57,772 57,773 56,245 301,397 _________ 590,023 128,151 _________ $ 461,872 _________ _________ NW Natural’s total payments of fixed charges under capacity pur- chase agreements in 2003, 2002 and 2001 were $86.7 million, $86.2 million and $86.5 million, respectively. Included in the amounts for 2003, 2002 and 2001 were reductions for capacity release sales of $3.7 million, $4.2 million and $3.8 million, respectively. In addi- tion, per-unit charges are required to be paid based on the actual quantities shipped under the agreements. In certain take-or-pay pur- chase commitments, annual deficiencies may be offset by prepay- ments subject to recovery over a longer term if future purchases exceed the minimum annual requirements. Environmental Matters NW Natural owns property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). The Gasco site has been under investigation by NW Natural for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. On June 30, 2003, the Company filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. NW Natural will work with the ODEQ to determine the appropriate remedial action from among the alternatives. Based upon the proposed actions in the draft plan, the Company estimates its range of remaining liability, including the cost of investigation, from feasible alternatives, at N W N A T U R A L In May 2003, the OPUC approved NW Natural’s request for deferral of environmental costs associated with specific sites, including the Gasco, Wacker, Portland Gas and Portland Harbor sites. The authorization, effective for a 12-month period begin- ning April 7, 2003, allows NW Natural to defer and seek recovery of unreimbursed environmental costs in a future general rate case. The Company recorded a cumulative deferral of $1.0 million in envi- ronmental costs related to these specific sites in 2003. Additionally, on a cumulative basis through Dec. 31, 2003, the Company has accrued environmental costs totaling $8.0 million relating to the sites, including $5.9 million that has already been disbursed. NW Natural has accrued all material loss contingencies relat- ing to environmental matters that it believes to be probable of assertion and reasonably estimable. Due to the preliminary nature of these environmental investigations, the range of any addition- al possible loss contingency cannot be currently estimated. NW Natural will first seek to recover the costs of further investigation and remediation for which it may be responsible with respect to the Gasco site, the Wacker site, the Portland Harbor site and the Portland Gas site, if any, from insurance. If these costs are not recovered from insurance, then NW Natural will seek recovery through future rates. At Dec. 31, 2003, NW Natural had a $3.7 mil- lion receivable representing an estimate of the environmental costs NW Natural expects to incur and recover from insurance, includ- ing $2.5 million for costs relating to the Gasco site and $1.25 mil- lion for costs relating to the Portland Harbor site. Enron Gas Supply Contract On Oct. 16, 2003, NW Natural received a demand letter from Enron North America Corp. (Enron) seeking payment of $1.1 mil- lion allegedly owed pursuant to a gas supply contract between NW Natural and Enron, which was in effect when Enron filed for bankruptcy in December 2001. The contract was terminated when Enron filed for bankruptcy, and NW Natural does not believe that any amounts are owed to Enron under the contract. 45 between $1.5 million and $7 million. At Dec. 31, 2003, NW Natural recorded liabilities totaling $1.5 million outstanding, regulatory deferred costs of $0.2 million, and a $2.5 million insurance receiv- able, for its estimated costs of investigation and interim remedia- tion at the Gasco site, including consultants’ fees, ODEQ oversight reimbursement and legal fees. NW Natural previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Wacker Siltronic Corporation (the Wacker site). In 2000, the ODEQ issued an order requiring Wacker and NW Natural to determine the nature and extent of releases of hazardous substances to Willamette River sediments from the Wacker site. NW Natural has completed the majority of the studies required under the ODEQ work plan and the agency is reviewing data generated by the studies. At Dec. 31, 2003, NW Natural recorded liabilities totaling $0.3 million for its estimated costs of the investigation and initial remediation on the Wacker site, nearly all of which had been spent as of Dec. 31, 2003. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (the Portland Harbor) that includes the area adja- cent to the Gasco site and the Wacker site. In 2000, the EPA listed the Portland Harbor as a Superfund site and notified the Company that it is a potentially responsible party. Between 2000 and 2003, NW Natural recorded liabilities totaling $2.6 million, of which $1.9 million had been spent as of Dec. 31, 2003. The amount of NW Natural’s liability is based on estimates of the Company’s share of the lower end of a range of probable liability for the costs of the Remedial Investigation/Feasibility Study for the Portland Harbor. Available information is insufficient to determine either the total amount of liability for investigation and remediation of the Portland Harbor or the higher end of a range for NW Natural’s estimated share of that liability. On March 1, 2004, the Company received a letter from the EPA requesting that the Company enter into a con- sent order relating to removal of certain contaminants in the riverbed adjacent to the Gasco site. The Company is reviewing the EPA’s request and has not determined what its response will be, or what a reasonable estimate of the cost would be for any action the Com- pany might take in response to the request. The City of Portland notified NW Natural that it was planning a sewer improvement project that would include excavation with- in the former site of a gas manufacturing plant (the Portland Gas site) that was owned and operated by a predecessor of the Company between 1860 and 1913. The preliminary assessment of this site performed by a consultant for the EPA in 1987 indicated that it could be assumed that by-product tars may have been disposed of on site. The report concluded, however, that it is likely that waste residues from the plant, if present on the site, were covered by deep fill dur- ing construction of the nearby seawall bordering the Willamette River and probably have stabilized due to physical and chemical processes. Neither the City of Portland nor the ODEQ has notified NW Natural whether a further investigation or potential remedi- ation might be required on the site in connection with the sewer project, which has commenced. Available information is insuffi- cient to determine either the total amount of NW Natural’s liabil- ity or a probable range, if any, of potential liability. N W N A T U R A L Comparative Consolidated Income Statements Thousands, except per share amounts (year ended December 31) Operating revenues: Gross operating revenues* Cost of sales* Net operating revenues* Operating expenses: Operations and maintenance Taxes other than income taxes Depreciation, depletion and amortization 93% 4% 3% 1990 Total operating expenses Income from continuing operations UTILITY GAS REVENUES BY CUSTOMER CLASS 2003 87% 2% 11% Other income (expense)* Interest charges – net Income before income taxes Income taxes Net income from continuing operations Discontinued segment Income from discontinued segment – net of tax Gain on sale of discontinued segment – net of tax Net income Redeemable preferred and preference stock dividend requirements Earnings applicable to common stock Average common shares outstanding Basic Diluted Basic earnings per share of common stock: From continuing operations From discontinued segment From gain on sale of discontinued segment Total basic earnings per share Diluted earnings per share of common stock: From continuing operations From discontinued segment From gain on sale of discontinued segment Total diluted earnings per share Dividends per share of common stock RESIDENTIAL, COMMERCIAL AND INDUSTRIAL FIRM INDUSTRIAL INTERRUPTIBLE TRANSPORTATION Revenues from residential, commercial and industrial firm sales customers have consistently exceeded 87 percent of total gas revenues since 1990. NET INCOME IN MILLIONS OF DOLLARS 46 $70 $60 $50 $40 $30 $20 $10 93 94 95 96 97 98 99 00 01 02 03 NET INCOME REDUCTION OF NET INCOME FROM INVESTMENT WRITEDOWNS: – $10.8 million loss for Financial Corporation and $1.7 million loss for Canor for asset impairment charges in 1998 – $8.4 million loss (after tax) from PGE acquisition costs in 2002 The Company earned $46.0 million in net income in 2003. 2003 2002 $ 611,256 323,190 __________ 288,066 $ 641,376 353,832 __________ 287,544 96,420 35,125 54,249 __________ 185,794 __________ 102,272 __________ 2,150 35,099 __________ 69,323 23,340 __________ 45,983 85,120 34,076 52,090 __________ 171,286 __________ 116,258 __________ (14,890) 34,132 __________ 67,236 23,444 __________ 43,792 – – __________ 45,983 – – __________ 43,792 294 __________ $ 45,689 __________ __________ 2,280 __________ $ 41,512 __________ __________ 25,741 26,061 25,431 25,814 $ 1.77 – – __________ $ 1.77 __________ __________ $ 1.76 – – __________ $ 1.76 __________ __________ $ 1.27 __________ __________ $ 1.63 – – __________ $ 1.63 __________ __________ $ 1.62 – – __________ $ 1.62 __________ __________ $ 1.26 __________ __________ See Notes to Consolidated Financial Statements. *Interest on deferred regulatory accounts for years prior to 1998 was reclassified from gross operating revenues or cost of sales to other income (expense). N W N A T U R A L 2001 2000 1999 1998 1997 1996 1995 1994 1993 $ 650,252 374,241 __________ 276,011 $ 532,110 274,160 __________ 257,950 $ 455,834 212,197 __________ 243,637 $ 404,390 173,424 __________ 230,966 $ 351,709 130,599 __________ 221,110 $ 370,826 141,842 __________ 228,984 $ 355,627 142,025 __________ 213,602 $ 367,861 162,199 __________ 205,662 $ 358,452 138,751 __________ 219,701 83,920 32,240 49,640 __________ 165,800 __________ 110,211 __________ 1,334 33,805 __________ 77,740 27,553 __________ 50,187 77,817 28,351 47,440 __________ 153,608 __________ 104,342 __________ 3,860 33,561 __________ 74,641 26,829 __________ 47,812 73,209 24,652 51,008 __________ 148,869 __________ 94,768 __________ 4,816 30,052 __________ 69,532 24,591 __________ 44,941 78,226 21,939 43,937 __________ 144,102 __________ 86,864 __________ (13,723) 31,586 __________ 41,555 14,604 __________ 26,951 73,864 19,952 39,051 __________ 132,867 __________ 88,243 __________ 4,138 28,469 __________ 63,912 21,034 __________ 42,878 76,204 21,597 37,971 __________ 135,772 __________ 93,212 __________ 6,891 26,711 __________ 73,392 27,118 __________ 46,274 72,018 24,181 40,594 __________ 136,793 __________ 76,809 __________ 9,055 25,679 __________ 60,185 22,120 __________ 38,065 70,881 24,263 38,058 __________ 133,202 __________ 72,460 __________ 8,393 24,919 __________ 55,934 20,473 __________ 35,461 70,723 25,561 39,683 __________ 135,967 __________ 83,734 __________ 1,116 25,107 __________ 59,743 22,096 __________ 37,647 – – __________ 50,187 – 2,412 __________ 50,224 355 – __________ 45,296 350 – __________ 27,301 181 – __________ 43,059 519 – __________ 46,793 – – __________ 38,065 – – __________ 35,461 – – __________ 37,647 2,401 __________ $ 47,786 __________ __________ 2,456 __________ $ 47,768 __________ __________ 2,515 __________ $ 42,781 __________ __________ 2,577 __________ $ 24,724 __________ __________ 2,646 __________ $ 40,413 __________ __________ 2,723 __________ $ 44,070 __________ __________ 2,806 __________ $ 35,259 __________ __________ 2,983 __________ $ 32,478 __________ __________ 3,488 __________ $ 34,159 __________ __________ 25,159 25,612 25,183 25,638 24,976 25,468 24,233 24,763 22,698 23,248 22,391 22,963 21,817 22,428 19,943 20,577 19,611 20,296 47 $ 1.90 – – __________ $ 1.90 __________ __________ $ 1.88 – – __________ $ 1.88 __________ __________ $ 1.245 __________ __________ $ 1.80 – 0.10 __________ $ 1.90 __________ __________ $ 1.79 – 0.09 __________ $ 1.88 __________ __________ $ 1.24 __________ __________ $ 1.70 0.01 – __________ $ 1.71 __________ __________ $ 1.69 0.01 – __________ $ 1.70 __________ __________ $ 1.225 __________ __________ $ 1.01 0.01 – __________ $ 1.02 __________ __________ $ 1.01 0.01 – __________ $ 1.02 __________ __________ $ 1.22 __________ __________ $ 1.77 0.01 – __________ $ 1.78 __________ __________ $ 1.75 0.01 – __________ $ 1.76 __________ __________ $ 1.205 __________ __________ $ 1.95 0.02 – __________ $ 1.97 __________ __________ $ 1.92 0.02 – __________ $ 1.94 __________ __________ $ 1.20 __________ __________ $ 1.62 – – __________ $ 1.62 __________ __________ $ 1.60 – – __________ $ 1.60 __________ __________ $ 1.18 __________ __________ $ 1.63 – – __________ $ 1.63 __________ __________ $ 1.61 – – __________ $ 1.61 __________ __________ $ 1.173 __________ __________ $ 1.74 – – __________ $ 1.74 __________ __________ $ 1.72 – – __________ $ 1.72 __________ __________ $ 1.167 __________ __________ N W N A T U R A L NET UTILITY PLANT IN MILLIONS OF DOLLARS $1,100 $1,000 $900 $800 $700 $600 $500 $400 $300 93 94 95 96 97 98 99 00 01 02 03 Utility plant, net of removal cost regulatory liabilities, continued to increase in 2003 as a result of customer growth and investments in technology and gas storage. CAPITALIZATION IN MILLIONS OF DOLLARS 48 $1050 $900 $750 $600 $450 $300 $150 93 94 95 96 97 98 99 00 01 02 03 COMMON EQUITY PREFERRED AND PREFERENCE STOCK LONG-TERM DEBT $32.7 million in cash dividends were paid to common share- holders in 2003, $8.3 million in Preferred Stock and $55 million in Medium-Term Notes were retired, and $90 million in Medium-Term Notes were issued. Comparative Consolidated Balance Sheets Thousands of dollars (December 31) Assets: Plant and property: Utility plant Less accumulated depreciation** Utility plant – net Non-utility property Less accumulated depreciation and depletion Non-utility property – net Total plant and property Other investments Current assets: Cash and cash equivalents Accounts receivable – net Accrued unbilled revenue Inventories of gas, materials and supplies Investment in discontinued segment Property held for sale Prepayments and other current assets Total current assets Regulatory tax assets Deferred gas costs receivable Unrealized loss on non-trading derivatives Deferred debits and other Total assets Capitalization and liabilities: Capitalization: Common stock equity Redeemable preference stock Redeemable preferred stock Long-term debt: First mortgage bonds Unsecured debt Total long-term debt Total capitalization Minority interest Current liabilities: Notes payable Accounts payable Long-term debt due within one year Taxes accrued Interest accrued Other current and accrued liabilities Total current liabilities Deferred investment tax credits Deferred income taxes Fair value of non-trading derivatives Deferred gas costs payable Accrued asset removal costs** Other Total capitalization and liabilities 2003 2002 $ 1,659,089 $ 1,539,965 435,601 ___________ ___________ 1,104,364 ___________ ___________ 20,832 4,404 ___________ ___________ 16,428 ___________ ___________ 1,120,792 ___________ ___________ 12,703 ___________ ___________ 471,716 1,187,373 23,395 4,855 18,540 1,205,913 12,635 4,706 52,213 59,109 50,859 7,328 46,936 44,069 58,030 32,661 199,548 63,449 – – 109,787 36,934 ___________ ___________ 193,297 ___________ ___________ 47,975 ___________ ___________ – ___________ ___________ – ___________ ___________ 92,510 ___________ ___________ $ 1,591,332 $ 1,467,277 ___________ ___________ ___________ ___________ $ 506,316 $ 482,392 – 8,250 – – 439,500 6,445 ___________ ___________ 445,945 ___________ ___________ 936,587 ___________ ___________ – 494,500 5,819 500,319 1,006,635 – 85,200 86,029 – 8,605 2,998 31,589 214,421 6,945 171,797 – 5,627 135,638 50,269 69,802 74,436 20,000 7,822 2,902 30,045 ___________ ___________ 205,007 ___________ ___________ 7,824 ___________ ___________ 141,732 ___________ ___________ – ___________ ___________ 10,635 ___________ ___________ 125,197 ___________ ___________ 40,295 ___________ ___________ $ 1,591,332 $ 1,467,277 ___________ ___________ ___________ ___________ *Deferred gas costs were included in deferred debits or regulatory accounts prior to 1995. **Removal costs were reclassified from accumulated depreciation to regulatory liabilities and other accrued asset removable costs. N W N A T U R A L 2001 2000 1999 1998 1997 1996 1995 1994 1993 $ 1,465,079 $ 840,030 $ 1,164,499 198,939 283,495 398,668 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 641,091 881,004 1,066,411 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 52,422 18,203 42,764 20,646 22,843 4,007 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 22,118 14,196 29,579 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 663,209 910,583 1,080,607 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 34,574 35,126 23,233 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ $ 1,055,112 $ 969,075 239,493 729,582 53,807 16,997 36,810 766,392 37,882 $ 908,238 216,711 691,527 49,586 24,456 25,130 716,657 37,097 $ 1,331,415 337,995 993,420 8,548 7,654 894 994,314 16,557 $ 1,239,690 313,149 926,541 89,050 29,927 59,123 985,664 16,714 $ 1,406,970 371,437 1,035,533 8,649 3,451 5,198 1,040,731 14,526 260,089 795,023 45,689 19,388 26,301 821,324 34,723 10,440 64,722 57,749 49,337 11,283 60,753 45,619 46,883 7,383 47,476 34,258 21,258 6,731 39,420 23,911 17,385 8,219 40,833 22,340 14,439 7,782 34,385 21,493 14,254 8,068 42,152 20,320 14,958 4,198 43,972 25,890 16,838 16,412 28,086 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 107,310 210,334 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 62,130 48,469 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ * – ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ – 111,641 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 38,156 76,369 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ $ 1,550,653 $ 951,705 $ 905,379 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 17,226 104,673 56,860 28,628 – 58,859 $ 1,282,704 $ 1,194,729 12,396 90,310 60,430 – – 43,472 $ 1,064,921 $ 998,486 22,834 187,372 49,515 16,973 – 76,297 $ 1,385,414 16,105 126,480 56,860 27,795 – 69,191 12,483 98,314 57,940 – – 52,620 10,041 95,539 60,430 * – 41,982 10,013 43,349 31,550 33,919 29,163 16,712 18,349 183,055 51,060 20,950 – 76,878 $ 1,342,814 $ 468,161 25,000 9,000 $ 452,309 25,000 9,750 $ 429,596 25,000 10,564 $ 412,404 25,000 11,499 $ 366,265 25,000 12,429 $ 346,778 25,000 13,749 $ 323,552 25,000 14,840 $ 274,408 26,252 15,950 $ 258,565 26,633 17,041 49 215,000 57,931 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 272,931 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 575,170 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ – 234,000 57,076 291,076 607,686 – 238,000 41,945 279,945 643,337 – 236,000 35,838 271,838 657,365 – 324,000 20,303 344,303 747,997 – 377,000 19,379 396,379 861,539 – 347,000 19,738 366,738 815,641 16,322 382,000 18,790 400,790 887,849 – 370,000 8,377 378,377 880,538 – 72,548 108,291 44,318 70,698 – 40,000 6,757 22,539 4,438 3,658 10,180 28,396 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 138,241 273,582 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 14,567 8,682 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 104,300 130,424 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ – 111,868 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ * 10,089 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 56,343 115,631 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 16,758 19,839 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ $ 1,064,921 $ 998,486 $ 951,705 $ 905,379 $ 1,550,653 ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ ___________ 89,317 58,775 16,000 4,656 6,058 21,390 196,196 11,949 139,953 – – 83,112 15,522 $ 1,282,704 $ 1,194,729 56,263 110,698 20,000 8,066 2,696 23,638 221,361 9,538 141,656 – – 106,701 18,309 $ 1,385,414 94,149 68,163 10,000 4,101 4,673 39,153 220,239 10,393 136,150 – – 98,391 16,102 $ 1,342,814 53,654 48,517 1,000 6,584 4,570 11,757 126,082 13,530 112,433 – * 62,401 29,573 50,058 64,795 26,000 3,196 5,396 19,418 168,863 11,668 123,625 – 8,058 76,052 19,290 87,264 56,039 10,000 7,486 6,204 23,477 190,470 11,248 140,310 – – 90,968 17,745 28,832 41,784 21,000 10,281 4,617 13,204 119,718 12,493 118,692 – 19,914 69,209 15,123 N W N A T U R A L YEAR-END MARKET PRICE & BOOK VALUE PER SHARE IN DOLLARS $35 $30 $25 $20 $15 $10 93 94 95 96 97 98 99 00 01 02 03 BOOK VALUE PER SHARE EXCESS OF MARKET PRICE OVER BOOK VALUE PER SHARE The year-end market-to-book ratio averaged 1.54x over the past 10 years. Total return to shareholders from dividends paid and market appreciation averaged 8.4 percent per year for this period. Comparative Financial Statistics Common stock Ratios – year-end: Price/earnings ratio Dividend yield at year-end rate – % Dividend payout – % Return on average common equity – % Per share data – ($): Basic earnings Diluted earnings Dividends paid Dividend rate at year-end Book value at year-end Market price: High Low Year-end Average Number of shares of common stock outstanding (000): Year-end Average Coverage data – times earned Fixed charges – Securities and Exchange Commission Fixed charges – Standard & Poor’s Utility plant 2003 2002 17.3 4.1 71.8 9.3 1.77 1.76 1.27 1.30 19.52 31.30 24.05 30.75 27.724 25,938 25,741 2.83 2.89 16.6* 4.7 77.3* 8.7* 1.63* 1.62* 1.26 1.26 18.85* 30.70 23.46 27.06 27.577 25,586 25,431 2.74* 3.29 HIGH/LOW MARKET PRICE PER SHARE (IN DOLLARS) Capital expenditures (000) Depreciation – % of average depreciable utility plant Accumulated depreciation – % of depreciable utility plant $ 124,660 3.5 38.0 $ 79,530 3.5 37.3 50 $35 $30 $25 $20 $15 $10 Capital structure – year-end (%) (Exclusive of current portion of long-term debt) First mortgage bonds Unsecured debt Total long-term debt Redeemable preferred stock Redeemable preference stock Common stock equity Total capital structure 49.7 – __________ 49.7 __________ – – 50.3 __________ 100.0 __________ __________ 46.9 0.7 __________ 47.6 __________ 0.9 – 51.5 __________ 100.0 __________ __________ 93 94 95 96 97 98 99 00 01 02 03 Effective tax rate HIGH LOW YEAR-END Price per share at year-end increased 34 percent in 10 years. Effective tax rate – % of pretax income 34% 35% *Includes losses of $0.50 per share in 1998 due to asset write-downs for Financial Corporation and Canor and loss of $0.33 per share in 2002 for PGE acquisition costs. N W N A T U R A L 2001 2000 1999 1998 1997 1996 1995 1994 1993 13.4 4.9 65.5 10.4 1.90 1.88 1.245 1.26 18.56 26.69 21.65 25.50 23.666 25,228 25,159 3.01 3.30 13.9 4.7 65.3 10.8 1.90 1.88 1.24 1.24 17.93 27.50 17.75 26.50 22.147 25,233 25,183 3.00 3.16 12.9 5.6 71.6 10.2 1.71 1.70 1.225 1.24 17.12 27.88 19.50 21.94 24.629 25,092 24,976 2.97 3.19 25.4* 4.7 119.6* 6.4* 1.02* 1.02* 1.22 1.22 16.59* 30.75 24.25 25.88 27.248 24,853 24,233 2.12* 2.72 17.4 3.9 67.7 11.3 1.78 1.76 1.205 1.22 16.02 31.25 23.125 31.00 25.292 22,864 22,698 2.84 3.05 12.2 5.0 60.9 13.0 1.97 1.94 1.20 1.20 15.37 25.75 20.833 24.00 23.054 22,555 22,391 3.32 3.71 13.6 5.5 73.1 11.8 1.62 1.60 1.18 1.20 14.55 22.67 18.667 22.00 20.750 22,243 21,817 2.95 2.87 12.1 6.0 72.1 12.2 1.63 1.61 1.173 1.173 13.63 24.33 19.00 19.67 21.250 20,129 19,943 2.87 2.98 13.1 5.1 67.0 13.7 1.74 1.72 1.167 1.173 13.08 25.33 19.00 22.83 22.167 19,766 19,611 2.96 3.47 $ 71,943 3.5 35.8 $ 80,444 3.5 34.9 $ 109,144 4.0 33.4 $ 80,022 3.9 33.2 $ 115,886 3.8 32.6 $ 83,400 3.8 33.2 $ 67,163 4.2 32.8 $ 77,668 4.1 31.7 $ 70,404 4.1 31.1 51 42.0 1.0 __________ 43.0 __________ 1.0 2.8 53.2 __________ 100.0 __________ __________ 44.1 1.0 __________ 45.1 __________ 1.1 2.8 51.0 __________ 100.0 __________ __________ 43.6 2.3 __________ 45.9 __________ 1.2 2.9 50.0 __________ 100.0 __________ __________ 42.6 2.4 __________ 45.0 __________ 1.4 3.1 50.5 __________ 100.0 __________ __________ 43.3 2.7 __________ 46.0 __________ 1.7 3.3 49.0 __________ 100.0 __________ __________ 35.9 5.5 __________ 41.4 __________ 2.1 3.8 52.7 __________ 100.0 __________ __________ 37.0 6.5 __________ 43.5 __________ 2.3 3.9 50.3 __________ 100.0 __________ __________ 38.5 9.4 __________ 47.9 __________ 2.6 4.3 45.2 __________ 100.0 __________ __________ 37.4 10.1 __________ 47.5 __________ 3.0 4.6 44.9 __________ 100.0 __________ __________ 35% 36% 35% 35% 33% 37% 37% 37% 37% N W N A T U R A L NUMBER OF CUSTOMERS SERVED BY EACH OPERATING EMPLOYEE 800 700 600 500 400 300 200 100 93 94 95 96 97 98 99 00 01 02 03 Each operating employee served an average 724 customers in 2003, a 54 percent increase from the 469 customers served per employee in 1993. COST OF PURCHASED GAS IN CENTS PER THERM 52 $0.55 $0.50 $0.45 $0.40 $0.35 $0.30 $0.25 $0.20 $0.15 $0.10 $0.05 03 93 94 95 96 97 98 99 00 01 02 Cost of gas, including demand charges, decreased 8 percent in 2003 but was 103 percent higher than 10 years ago. HEAT REQUIREMENTS IN HEATING DEGREE-DAYS 4,700 4,500 4,300 4,100 3,900 3,700 3,500 93 94 95 96 97 98 99 00 01 02 03 DEGREE-DAYS 25-YEAR AVERAGE DEGREE-DAYS Weather conditions in NW Natural’s service area have been warmer than the rolling 25-year average in seven of the past 10 years. Comparative Operating Statistics Selected Utility Data Customers at year-end Residential Commercial Industrial firm Industrial interruptible Total sales customers Transportation customers Total customers Gas sales and transportation deliveries (000 therms) Residential Commercial Industrial firm Industrial interruptible Total gas sales Transportation Unbilled therms Total volumes delivered Operating revenues and cost of sales (000) Sales revenues: Residential Commercial Industrial firm Industrial interruptible Total gas sales revenues Transportation Unbilled revenues Other Total utility operating revenues Cost of gas Net utility operating revenues Non-utility net operating revenues Net operating revenues Customer data Heat requirements: Actual degree-days 25-year average degree-days Average use per customer in therms: Residential Commercial Average rate per therm (cents): Residential Commercial Industrial firm Industrial interruptible Total sales Gas purchases (000 therms) Gas purchased cost per therm – net (cents) Average sendout cost of gas (cents) Maximum day firm sendout (000 therms) Maximum day total sendout (000 therms) Payroll (000) Operating Construction and other Total Utility employees Number of customers served by each operating employee 2003 2002 519,427 57,969 478 165 __________ 578,039 111 __________ 578,150 __________ __________ 343,534 226,257 55,314 47,994 __________ 673,099 414,554 12,099 __________ 1,099,752 __________ __________ $ 328,464 176,385 33,578 23,661 __________ 562,088 17,962 14,474 7,460 __________ 601,984 323,128 __________ 278,856 9,210 __________ $ 288,066 __________ __________ 503,402 56,087 306 31 __________ 559,826 241 __________ 560,067 __________ __________ 357,091 240,155 63,215 26,241 __________ 686,702 445,999 (6,617) __________ 1,126,084 __________ __________ $ 354,735 201,475 42,965 15,937 __________ 615,112 26,020 (12,702) 4,018 __________ 632,448 353,034 __________ 279,414 8,130 __________ $ 287,544 __________ __________ 3,952 4,238 673 4,004 4,232 4,257 725 4,334 95.6 78.0 60.7 49.3 83.5 __________ 99.3 83.9 68.0 61.7 89.6 __________ 708,796 46.99 47.16 4,851 6,310 708,796 51.07 51.91 4,249 6,172 $ 43,993 27,450 __________ $ 71,443 __________ __________ 1,291 724 $ 42,268 26,044 __________ $ 68,312 __________ __________ 1,261 714 *Interest on deferred regulatory accounts for years prior to 1998 was reclassified from to other income (expense). N W N A T U R A L 2001 2000 1999 1998 1997 1996 1995 1994 1993 485,207 55,096 383 148 __________ 540,834 97 __________ 540,931 __________ __________ 350,065 242,293 79,778 63,597 __________ 735,733 385,783 1,771 __________ 1,123,287 __________ __________ 468,087 54,684 384 126 __________ 523,281 125 __________ 523,406 __________ __________ 356,375 250,380 76,559 56,632 __________ 739,946 431,136 8,691 __________ 1,179,773 __________ __________ 447,659 52,870 388 115 __________ 501,032 131 __________ 501,163 __________ __________ 352,969 252,382 84,630 52,938 __________ 742,919 480,570 (9,343) __________ 1,214,146 __________ __________ $ 329,905 190,236 49,662 34,283 __________ 604,086 20,637 13,774 (2,325) __________ 636,172 364,699 __________ 271,473 4,538 __________ $ 276,011 __________ __________ $ 280,642 159,660 37,378 23,483 __________ 501,163 21,491 12,661 (3,976) __________ 531,339 273,978 __________ 257,361 589 __________ $ 257,950 __________ __________ $ 242,952 139,425 35,857 17,182 __________ 435,416 21,351 (2,671) 1,194 __________ 455,290 212,021 __________ 243,269 368 __________ $ 243,637 __________ __________ 425,606 51,159 411 108 __________ 477,284 123 __________ 477,407 __________ __________ 315,686 229,124 87,275 51,521 __________ 683,606 446,165 8,645 __________ 1,138,416 __________ __________ $ 205,388 117,889 34,303 15,337 __________ 372,917 19,958 8,314 2,617 __________ 403,806 173,242 __________ 230,564 402 __________ $ 230,966 __________ __________ 407,061 50,315 403 122 __________ 457,901 120 __________ 458,021 __________ __________ 306,356 225,249 84,523 53,929 __________ 670,057 440,452 3,615 __________ 1,114,124 __________ __________ $ 177,835 100,677 27,025 13,944 __________ 319,481 22,029 1,647 7,884 __________ 351,041 130,381 __________ 220,660 450 __________ $ 221,110 __________ __________ 385,213 47,309 407 119 __________ 433,048 121 __________ 433,169 __________ __________ 306,310 225,115 91,122 63,261 __________ 685,808 410,062 3,759 __________ 1,099,629 __________ __________ $ 183,802 104,582 30,672 17,097 __________ 336,153 22,533 1,627 9,824 __________ 370,137 141,789 __________ 228,348 636 __________ $ 228,984 __________ __________ 363,903 45,402 410 143 __________ 409,858 91 __________ 409,949 __________ __________ 256,462 196,723 82,958 84,173 __________ 620,316 379,116 4,946 __________ 1,004,378 __________ __________ $ 165,662 99,079 31,268 24,113 __________ 320,122 16,650 1,173 9,411 __________ 347,356 142,025 __________ 205,331 8,271 __________ $ 213,602 __________ __________ 346,950 44,078 401 142 __________ 391,571 67 __________ 391,638 __________ __________ 260,218 201,925 81,348 89,899 __________ 633,390 364,461 (7,519) __________ 990,332 __________ __________ $ 176,510 108,452 34,443 27,361 __________ 346,766 14,702 (5,571) 429 __________ 356,326 162,437 __________ 193,889 11,773 __________ $ 205,662 __________ __________ 329,157 42,657 396 153 __________ 372,363 64 __________ 372,427 __________ __________ 267,818 209,642 80,588 66,370 __________ 624,418 415,367 3,844 __________ 1,043,629 __________ __________ $ 168,217 103,476 31,340 18,884 __________ 321,917 17,892 5,153 2,625 __________ 347,587 138,751 __________ 208,836 10,865 __________ $ 219,701 __________ __________ 4,325 4,267 738 4,435 4,418 4,274 781 4,670 4,256 4,274 810 4,851 4,011 4,283 749 4,540 4,092 4,299 777 4,670 4,427 4,312 823 4,874 3,779 4,340 726 4,420 4,020 4,365 776 4,680 4,452 4,372 844 5,029 94.2 78.5 62.2 54.0 82.1 __________ 78.7 63.8 48.8 41.5 67.7 __________ 68.8 55.2 42.4 32.5 58.6 __________ 65.1 51.5 39.3 29.6 54.6 __________ 58.0 44.7 32.0 25.9 47.7 __________ 60.0 46.5 33.7 27.0 49.0 __________ 64.6 50.4 37.7 28.6 51.6 __________ 67.8 53.7 42.3 30.4 54.7 __________ 62.8 49.4 38.9 28.5 51.6 __________ 739,620 47.19 49.45 4,247 5,996 745,582 37.68 36.60 4,691 5,814 773,258 27.85 28.90 4,144 6,211 712,602 25.09 25.03 6,414 7,446 702,820 24.05 19.35 4,447 5,744 692,894 22.25 20.56 5,997 7,422 640,976 20.67 22.71 4,375 5,717 642,607 23.44 25.95 3,920 5,291 628,172 23.11 22.08 4,069 5,607 $ 40,856 25,626 __________ $ 66,482 __________ __________ 1,284 671 $ 38,979 24,756 __________ $ 63,735 __________ __________ 1,315 646 $ 38,066 24,322 __________ $ 62,388 __________ __________ 1,275 643 $ 37,573 24,625 __________ $ 62,198 __________ __________ 1,303 611 $ 35,669 24,630 __________ $ 60,299 __________ __________ 1,337 583 $ 34,037 22,920 __________ $ 56,957 __________ __________ 1,304 560 $ 33,669 22,074 __________ $ 55,743 __________ __________ 1,288 533 $ 33,888 20,795 __________ $ 54,683 __________ __________ 1,338 478 $ 33,539 21,056 __________ $ 54,595 __________ __________ 1,293 469 N W N A T U R A L 53 Board of Directors Scott Gibson C. Scott Gibson, 51, is President of Gibson Enterprises, a company that manages private investments in Lake Oswego, Oregon. Mr. Gibson joined the NW Natural Board in 2002. He is a member of the Public Affairs and Environmental Policy Committee, Strategic Planning Committee, and Organization and Executive Compensation Committee. Tod Hamachek The Chair of the Strategic Planning Committee, Tod R. Hamachek, 58, has served on the NW Natural Board since 1986. Mr. Hamachek is also a member of the Board’s Audit and Governance Committees. He is Chairman and Chief Executive Officer of Penwest Pharma- ceuticals Company, a firm that develops pharmaceutical drug delivery products and technologies in Danbury, Connecticut. Randall Papé A member of the Board since 1996, Randall C. Papé, 53, chairs the Finance Committee. Mr. Papé is President and Chief Executive Officer of The Papé Group, Inc., headquartered in Eugene, Oregon, which specializes in the sales and service of capital equipment. He serves on the Board’s Governance Committee and the Public Affairs and Environmental Policy Committee. Richard Reiten Chairman of the Board Richard G. Reiten, 64, has been a member of the Board since 1996. Mr. Reiten serves on the Finance Committee, Public Affairs and Environmental Policy Committee, and Strategic Planning Committee. Robert Ridgley Retired Chairman Robert L. Ridgley, 70, has served on the NW Natural Board since 1984. Mr. Ridgley is a member of the Finance Committee, Public Affairs and Environmental Policy Committee, and Strategic Planning Committee. Melody Teppola A managing partner of National Builders Hardware Company in Portland, Melody C. Teppola, 61, has served on the NW Natural Board since 1987. National Builders Hardware is a regional and national distributor of builders’ hard- Timothy Boyle Timothy P. Boyle, 54, is President and Chief Executive Officer of Columbia Sportswear Company located in Portland, Oregon. He was elected to the NW Natural Board of Directors in 2003, and serves on the Finance Committee, Strategic Planning Committee, and Organization and Executive Compensation Committee. John Carter A member of the NW Natural Board since 2002, John D. Carter, 58, chairs the Board’s Governance Committee. He is also a member of the Audit and Finance Committees. Mr. Carter is a principal with Goldschmidt, Imeson, and Carter, a strategic planning and public affairs consulting firm in Portland, Oregon. Mark Dodson NW Natural’s President and Chief Executive Officer is Mark S. Dodson, 59. He has served on the Board since 2003. 54 Below: (left to right) Russell Tromley, John Carter, Richard Woolworth, Timothy Boyle, Mark Dodson, Richard Reiten, Scott Gibson, Melody Teppola, Robert Ridgley, Tod Hamachek and Randall Papé. ware, decorative plumbing and wood- working machinery located in Portland, Oregon. Ms. Teppola chairs the Board’s Public Affairs and Environmental Policy Committee and is a member of the Audit and Governance Committees. Russell Tromley The Chair of the Organization and Executive Compensation Committee is Russell F. Tromley, 64. He has served on the Board since 1994, and is a member of the Audit and Governance Committees. Mr. Tromley is President and Chief Executive Officer of Tromley Industrial Holdings, Inc., a company in Tualatin, Oregon, that manufactures foundry equipment and distributes nonferrous metals. Richard Woolworth Elected to the Board in 2000, Richard L. Woolworth, 62, chairs the Audit Committee. He also serves on the Gov- ernance Committee and the Organiza- tion and Executive Compensation Committee. Mr. Woolworth is the Retired Chairman and CEO of The Regence Group, a regional affiliation of health plans in Portland, Oregon. The following mission and values statements were adopted by NW Natural in 2003 as part of the Company’s new Strategic Plan. Mission “We bring warmth, comfort and convenience to people’s lives and help businesses and communities succeed.” Core Values Integrity Integrity means being honest and ethical in everything we do, and being true to our word. It includes fiscal responsibility, trustworthiness and principled behavior. Integrity is fundamental to the Company’s image, reputation and success. Service Ethic NW Natural employees are driven by a desire to help others. Whether their customers are external or internal, employees are responsive in solving people’s problems. Employees take pride in the Company’s service reputation. A service ethic also under- lies the Company’s commitment to reliable and efficient operations. Caring Employees respect each other professionally and care about each other personally. They enjoy a sense of teamwork, family and fun. At the same time, they value indi- vidual performance. The Company provides guidance and discipline to help each employee do his or her best. Caring is also reflected in NW Natural’s diversity efforts, and its community involvement and employee volunteerism. Safety Safety is critically important in all aspects of the Company’s operation. Employees are dedicated to safe work practices. The Company goes out of its way to educate con- sumers and the public on the safe use of natural gas. NW Natural also meets or exceeds all regulatory requirements for pipeline safety. 55 56 NW Natural officers gather at The Oregon Food Bank, selected in 2003 as the Company’s Signature Program for philanthropic giving and employee volunteerism. From left to right are: Lea Anne Doolittle, Gregg Kantor, Richelle Luther, Mike McCoy, Steve Feltz, Mark Dodson, C.J. Rue, Beth Ugoretz and Bruce DeBolt. Bruce R. DeBolt, 56 [1980] Senior Vice President, Finance, and Chief Financial Officer (1990- ) Senior Vice President, Finance and Administration and General Counsel (1987-1990) Vice President and General Counsel (1983-1987) Mark S. Dodson, 59 [1997] President, Chief Executive Officer (2003- ) President, Chief Operating Officer (2001-2002) General Counsel (1997-2002) Senior Vice President, Public Affairs (1997-2001) Corporate Officers Lea Anne Doolittle, 48 [2000] Vice President, Human Resources (2000- ) Director of Compensation, PacifiCorp (1993-2000) Stephen P. Feltz, 48 [1982] Treasurer and Controller (1999- ) Assistant Treasurer and Manager, General Accounting (1996-1999) Gregg S. Kantor, 46 [1996] Senior Vice President, Public and Regulatory Affairs (2003- ) Vice President, Public Affairs and Communications (1998-2002) Director, Public Affairs and Communications (1996-1997) Richelle T. Luther, 35 [2002] Assistant Secretary (2002- ) Associate, Stoel Rives LLP (1997-2002) Michael S. McCoy, 60 [1969] Executive Vice President, Customer and Utility Operations (2000- ) Senior Vice President, Customer and Utility Operations (1999-2000) Senior Vice President, Customer Services (1992-1999) C. J. Rue, 58 [1974] Secretary (1982- ) Assistant Treasurer (1987- ) Beth A. Ugoretz, 48 [2002] Senior Vice President, General Counsel (2003- ) Executive Vice President, KinderCare Learning Centers, Inc. (1997-2000) Senior Vice President, General Counsel and Secretary, Red Lion Hotels, Inc. (1993-1996) [Date joined NW Natural] Corporate Information Common Stock Prices The Company’s common stock is listed and trades on the New York Stock Exchange using the symbol NWN. The quarterly high and low trading range during 2002 and 2003 was: Shareholder Information WASHINGTON Astoria Mist Vancouver Portland Molalla The Dalles Salem Lincoln City Newport Albany Eugene Coos Bay OREGON Legend Williams Gas Pipeline NW Natural gas transmission line Kelso Beaver (KB) Pipeline Proposed pipelines to Molalla and Coos Bay Service territory LNG plant District offices Mist underground storage Corporate Profile NW Natural is a 145-year-old natural gas local distribution company headquar- tered in Portland, Oregon. The Company has added customers at a rate of 3 percent or more per year for 17 consecutive years. NW Natural serves more than 578,000 customers in Oregon and southwest Washington, including the Portland- Vancouver metropolitan area, the Willamette Valley, the northern Oregon coast and the Columbia River Gorge. More than 200,000 customers have been added to NW Natural’s distribution system in the past 10 years. In keeping with its steady growth, the Company has increased annual dividends paid to shareholders every year for 48 con- secutive years. NW Natural purchases natural gas for its core market from a variety of suppliers in the western United States and Canada. In addition, the Company operates an underground gas storage facility in Columbia County, Oregon, and leases additional gas storage outside its service area. NW Natural operates two liquefied natural gas plants in its service area. The Company also is active in the interstate storage services market, providing storage capacity to Northwest energy companies that has been developed in advance of its need for core customers. On the cover: Twenty-four-inch diameter pipe to be used for NW Natural’s South Mist Pipeline Extension in a staging area south of Portland prior to installation. (See page 12) Financial Briefs Earnings Financial facts ($000): 2003 2002 Percent increase (decrease) Net operating revenues Net income Earnings aplicable to common stock 288,066 45,983 45,689 287,544 43,792 41,512 Financial ratios (%): Return on average common equity Capital structure at year-end Long-term debt Preferred stock Common stock equity Common stock Shareholder data: Common shareholders Average shares outstanding (000) Per share data ($): Basic earnings Diluted earnings Dividends paid on common stock Book value at year-end Market value at year-end Operating highlights 9.3 49.7 – 50.3 9,695 25,741 1.77 1.76 1.27 19.52 30.75 Gas sales and transportation deliveries (000 therms): Degree-days (25-year average, 4,238) Customers at year-end Number of utility employees 1,099,752 3,952 578,150 1,291 Dividends paid on common stock Payment date (per share) February 15 May 15 August 15 November 15 Total dividends paid 2003 $ 0.315 $ 0.315 $ 0.315 $ 0.325 _________ $ 1.270 _________ _________ 8.7 47.6 0.9 51.5 10,026 25,431 1.63 1.62 1.26 18.85 27.06 1,126,084 4,232 560,067 1,261 2002 $ 0.315 $ 0.315 $ 0.315 $ 0.315 _________ $ 1.260 _________ _________ 0 5 10 6 (3) 1 9 9 1 4 14 (2) (7) 3 2 DIVIDENDS PAID PER SHARE IN DOLLARS $1.27 $1.26 $1.25 $1.24 $1.23 $1.22 $1.21 $1.20 $1.19 $1.18 $1.17 98 99 00 01 02 03 In 2003, NW Natural increased its annual dividends paid per share for the 48th consecutive year, a growth record matched by few companies. EARNINGS PER SHARE IN DOLLARS $2.00 $1.75 $1.50 $1.25 $1.00 $0.75 $0.50 $0.25 98 99 00 01 02 03 DILUTED EARNINGS PER SHARE REDUCTION IN EARNINGS PER SHARE FROM INVESTMENT WRITEDOWNS: – 50 cents per share in 1998 due to asset impairment charges – 33 cents per share in 2002 due to a loss for PGE acquisition costs Diluted earnings were $1.76 per share in 2003, up 9 percent from $1.62 per share in 2002. y r e g a m I k c o t S x e d n I / d n u e r F d u B o t o h P 0 1 p n o t a e B e c u r B s r e c i f f O & d r a o B , r e t t e L l r e d o h e r a h S / t i a r t r o P d n a l r o B e i l r a h C y h p a r g o t o h P e r u t a e F s n o i t u o S l c i h p a r G n g i s e D k c o t s d e l c y c e r n o d e t n i r P r e t n e C s t r A c i h p a r G g n i t n i r P n g i s e D n o e h p a r G n o i t c u d o r P Notice of Annual Meeting The 2004 Annual Meeting will be held at 2 p.m. Thursday, May 27, at the DoubleTree Hotel Portland–Lloyd Center, Lloyd Center Ballroom, 1000 NE Multnomah, Portland, Oregon. A meeting notice and proxy state- ment will be sent to all shareholders in mid-April. Request for Publications The following publications may be obtained without charge by contacting the Corporate Secretary: Annual Report Form 10-K Form 10-Q Corporate Governance Standards Code of Ethics These publications, as well as other filings made with the Securities and Exchange Commission, also are available on NW Natural’s web site at www.nwnatural.com. Stock Transfer Agent and Registrar Effective March 22, 2004, for all Common Stock Issues: American Stock Transfer & Trust Company 59 Maiden Lane New York, NY 10038 Telephone: (888) 777-0321 Internet: www.amstock.com E-mail: info@amstock.com Trustee, Conversion and Interest Paying Agent For Convertible Debentures: The Bank of New York Corporate Debt Operations, Floor 7-E 101 Barclay Street New York, New York 10286 (800) 548-5075 Trustee and Bond Paying Agent For all bond issues: DB Services Tennessee Inc. Security Holder Relations P.O. Box 305050 Nashville, Tennessee 37230 (800) 735-7777 2003 Quarter 1 2 3 4 2002 Quarter 1 2 3 4 High 28.47 28.88 30.10 31.30 High 28.50 30.30 30.20 30.70 Low 24.05 24.77 27.02 28.51 Low 24.20 27.60 23.46 25.50 Dividend Reinvestment Plan Common shareholders of record may reinvest all or part of their dividends in additional shares under the Company’s plan. Cash purchases also may be made at the current market price under this plan, and no brokerage fees will be charged. A prospectus will be sent to any registered shareholder on request. Dividend Payment Dates February 13, 2004 May 14, 2004 August 13, 2004 November 15, 2004 Quarterly Financial Information (unaudited) Dollars (thousands except per share amounts) March 31 –———————––––— Quarter ended –––––———————— Dec. 31 Sept. 30 June 30 2003 Operating revenues Net operating revenues Net income (loss) Basic earnings (loss) per share Diluted earnings (loss) per share 2002 Operating revenues Net operating revenues Net income (loss) Basic earnings (loss) per share Diluted earnings (loss) per share $206,539 98,588 26,404 1.03 1.01 $278,563 110,666 34,447 1.34 1.32 $117,489 58,549 4,462 0.17 0.17 $101,873 56,564 (2,992) (0.14) (0.14) $69,481 39,465 (6,546) (0.25) (0.25) $78,717 38,059 (6,008) (0.26) (0.26) $217,747 91,464 21,663 0.84 0.83 $182,223 82,255 18,345 0.70 0.69 Total $611,256 288,066 45,983 1.77* 1.76* $641,376 287,544 43,792 1.63* 1.62* *Quarterly earnings per share are based upon the average number of common shares outstanding during each quarter. Because the average number of shares outstanding has changed in each quarter shown, the sum of quarterly earnings (loss) per share may not equal earnings per share for the year. Variations in earn- ings between quarterly periods are due primarily to the seasonal nature of the Company’s business. James R. Boehlke Investor Relations (503) 721-2451 (800) 422-4012, Ext. 2451 Linda R. Williams Shareholder Services (503) 220-2590 (800) 422-4012, Ext. 3402 jrb@nwnatural.com lrw@nwnatural.com NW Natural 220 N.W. Second Avenue Portland, Oregon 97209 (503) 226-4211 (800) 422-4012 www.nwnatural.com Contact the NW Natural Board Concerns may be directed to the non-management directors as follows: ■ Call 1-800-541-9967, or ■ Write to NW Natural Board of Directors, c/o Corporate Secretary, or ■ Email Directors@nwnatural.com Forward-looking Statements NW Natural’s future operating results will be affected by various uncertainties and risk factors, many of which are beyond the Com- pany’s control, including governmental policy and regulatory action, the competitive environment, economic factors and weather conditions. Some statements in this annual report may be forward-looking, and actual results may differ materially as a result of these uncertainties. For a more complete description of these uncertainties and risk factors, please refer to the Company’s filings with the Securities and Exchange Commis- sion on Forms 10-K and 10-Q. 220 NW Second Avenue Portland, Oregon 97209 www.nwnatural.com Investing in growth 2003 Annual Report