Northwest Natural Company
Annual Report 2004

Plain-text annual report

220 NW Second Avenue Portland, Oregon 97209 www.nwnatural.com N W N a t u r a l 2 0 0 4 A n n u a l R e p o r t 2004 Annual Report Ahead of the curve Corporate Profile NW Natural is a 146-year-old natural gas local distribution company headquartered in Portland, Oregon. The Company has added customers at a rate of 3 percent or more per year for 18 consecutive years. NW Natural serves about 600,000 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 distribu- tion system in the past 10 years. In keeping with its steady growth, the Company has increased annual dividends paid to shareholders every year for 49 consecutive years. NW Natural purchases natural gas for its core market from a variety of suppliers in the western United States and Canada. The Company also operates an underground gas storage facility in Columbia County, Oregon, and contracts for additional gas storage outside its service area. NW Natural operates two liquefied natural gas plants in its service area. The Company also provides interstate storage services to other energy companies in the Northwest interstate market, using capacity that has been developed in advance of its core customers’ needs. Service Territory Earnings Financial facts ($000): Net operating revenues Net income Earnings aplicable to common stock Financial ratios (%): Return on average common equity Capital structure at year-end Long-term debt Preferred and preference stock Common stock equity Common stock Shareholder data: Common shareholders Average shares outstanding (000) Per share data ($): Basic earnings Diluted earnings Dividends paid on common stock Book value at year-end Market value at year-end Operating highlights Gas sales and transportation deliveries (000 therms) Degree days (25-year average, 4,202) Customers at year-end Number of utility employees Dividends paid on common stock Payment date (per share) February 15 May 15 August 15 November 15 Total dividends paid 2004 2003 Percent increase (decrease) 7 10 11 1 (3) 5 6 6 2 6 10 3 (3) 3 – 308,360 50,572 50,572 288,066 45,983 45,689 9.4 46.0 – 54.0 9.3 49.7 – 50.3 9,359 27,016 9,695 25,741 1.87 1.86 1.30 20.64 33.74 1.77 1.76 1.27 19.52 30.75 1,131,866 1,099,752 3,952 578,150 1,291 3,853 596,635 1,288 2004 2003 $ 0.325 $ 0.315 $ 0.325 $ 0.315 $ 0.325 $ 0.315 $ 0.325 $ 0.325 ________ ________ $ 1.300 $ 1.270 ________ ________ ________ ________ Astoria Mist WASHINGTON 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 Coos County Pipeline Service territory LNG plant District offices Mist underground storage $1.30 $1.29 $1.28 $1.27 $1.26 $1.25 $1.24 $1.23 $1.22 $1.21 $1.20 DIVIDENDS PAID PER SHARE IN DOLLARS DILUTED EARNINGS PER SHARE IN DOLLARS $2.00 $1.75 $1.50 $1.25 $1.00 $0.75 $0.50 $0.25 On the cover: A NW Natural truck strikes out for new territory — the southern Oregon coast. Coos County residents welcomed natural gas service to their communities in 2004. Annual dividends paid per share in 2004 increased for the 49th consecutive year, a growth record matched by few companies. Diluted earnings per share were $1.86 per share in 2004, up 6 percent over 2003. 99 00 01 02 03 04 99 00 01 02 03 04 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 r e d l 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 o e v n e C 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 Corporate Information Notice of Annual Meeting The 2005 Annual Meeting will be held at 2 p.m., Thursday, May 26, in the Colonel Lindbergh Room of the Embassy Suites Hotel, 319 S.W. Pine Street, Portland, Oregon. A meeting notice and proxy statement will be sent to all shareholders in mid-April. Stock Transfer Agent and Registrar For the Common Stock: American Stock Transfer & Trust Company 59 Maiden Lane New York, New York 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 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 15, 2005 May 13, 2005 August 15, 2005 November 15, 2005 Common Stock Prices The Company’s common stock is listed and trades on the New York Stock Exchange (NYSE) under the symbol NWN. The quarterly high and low trading range during 2003 and 2004 was: 2004 Quarter 1 2 3 4 High $ 33.00 31.65 32.37 34.13 Low $ 29.95 27.46 28.84 30.77 2003 Quarter 1 2 3 4 High $ 28.47 28.88 30.11 31.30 Low $ 24.05 24.77 27.02 28.51 Certifications The Chief Executive Officer certified to the NYSE on June 7, 2004 that, as of that date, he was not aware of any violation by the Company of NYSE’s corporate governance listing standards, and the Company has filed with the Securities and Exchange Commission, as exhibits 31.1 and 31.2 to its Annual Report on Form 10-K for the year ended Dec. 31, 2004, the certificates of the Chief Executive Officer and the Chief Financial Officer of the Company certifying the quality of the Company’s public disclosure. 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 Director Independence Standards Code of Ethics Board Committee Charters 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. Quarterly Financial Information (unaudited) Dollars (thousands except per share amounts) March 31 ———————— Quarter ended ———————— June 30 Sept. 30 Dec. 31 Total 2004 Operating revenues Net operating revenues Net income (loss) Basic earnings (loss) per share Diluted earnings (loss) per share 2003 Operating revenues Net operating revenues Net income (loss) Basic earnings (loss) per share Diluted earnings (loss) per share $ 254,450 $ 106,659 $ 112,034 32,612 1.26 1.24 52,629 (716) (0.03) (0.03) 81,441 $ 262,054 $ 704,604 308,360 39,483 50,572 (8,285) 1.87* (0.30) 1.86* (0.30) 104,214 26,961 0.98 0.97 $ 206,539 $ 117,489 $ 98,588 26,404 1.03 1.01 58,549 4,462 0.17 0.17 69,481 $ 217,747 $ 611,256 288,066 91,464 39,465 45,983 21,663 (6,546) 1.77* 0.84 (0.25) 1.76* 0.83 (0.25) *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 may not equal earnings per share for the year. Variations in earnings between quarterly periods are due primarily to the seasonal nature of the Company’s business. Shareholder Information James R. Boehlke Investor Relations (503) 721-2451 (800) 422-4012, Ext. 2451 jrb@nwnatural.com Carol M. Frary Shareholder Services (503) 220-2590 (800) 422-4012, Ext. 3412 cmf@nwnatural.com 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 Company’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 Commission on Forms 10-K and 10-Q. Ahead of the curve The right source of energy affects so many lives in so many ways. By providing the best in natural gas service, NW Natural enhances the lives of everyone from chefs, to swimmers, to children playing in the park. In 2004, even horses stood to benefit. Because we manage our business ahead of the curve, we put our customers a step ahead as well. New Technology p10 “ The microturbine in our Swim Pavilion not only operates faultlessly, but its performance is beyond our expectations. It’s a working example we use to teach students about the potential for energy conservation and efficiency.” – Dr. Richard Bettega Associate Vice President for Facilities, Lewis & Clark College Coos Bay Opening p8 “ The cost of propane has been ridiculous, heinous and prohibitive. Fuel is my biggest expense in the winter. Propane costs me hundreds of dollars a month. I’ve been saying for over a year, ‘I can’t wait until NW Natural gets here.’” – Elizabeth Kinzie Owner, Elizabeth’s South Mist Pipeline p14 “ NW Natural’s crews were wonderful and very efficient. They cleared 16 trees and moved the logs to our back pasture where we’ll use them to develop a cross-country course for event competition. We could not have done this without their help.” – Vicky Carr Owner and President, Sherwood Forest Equestrian Center, Inc. Energy Efficiency p12 “ NW Natural’s employees are great: professional, helpful and always ready to serve with knowledge and good humor. With their help, we’ve turned a pizza oven into a model for energy conservation and sustainable business practices.” – David Yudkin Owner, Hot Lips Pizza Letter to Shareholders 2 Interview with the Senior Vice President 5 18 Management’s Discussion & Analysis Management’s Report on Internal Control Report of Independent Registered Public Accounting Firm Financial Statements Notes to Financial Statements Eleven-Year Financial Review Board of Directors Corporate Officers Corporate Information 32 33 34 39 54 62 64 65 Customer Growth p16 “We’ve worked with NW Natural on all our River District projects—nine buildings in seven years! Gas cooktops and fireplaces are the type of valued features that draw customers to our condominium developments.” – Sue Miller Vice President and Project Specialist, Hoyt Street Properties Letter to Shareholders Earning the right to grow Mark Dodson, President and CEO, at the site of the Sherwood, Oregon, intertie of the South Mist Pipeline Extension. Completed five weeks ahead of schedule, it was the largest capital project in company history and is now included in Oregon and Washington rates. T o Our Shareholders: In 2004, the years of planning and hard work paid off. NW Natural saw the culmination of several landmark construction projects and key regulatory changes. Each required years of planning and analy- sis. Each demanded solid execution. Each added to our earnings and cash flows in 2004 and will continue to in- crease our value in the years ahead. NW Natural has dedicated itself to getting ahead of the curve and has succeeded in many ways. The evidence of that can be seen not just in the Company’s 2004 performance but also in the strong platform for growth it has created for 2005 and beyond. Highlights of the year In 2004, NW Natural: ■ Earned $1.86 a diluted share, com- pared to $1.76 in 2003, a solid 5.7 percent increase; 2 ■ Completed the South Mist Pipeline extension — and began recovering its costs in rates; ■ Successfully completed a general rate case in Washington; ■ Began serving customers in Coos County, Oregon; ■ Offset most of the negative impacts of warm weather and conservation through the new Weather Adjusted Rate Mechanism and the Conservation Tariff; ■ Reached an agreement in Oregon to recover and earn on investments needed to comply with federal pipeline integrity rules; ■ Negotiated a new five-year labor agreement; ■ For the 18th year in a row, achieved an annual customer growth rate of more than 3 percent; and ■ Increased annual dividends paid to shareholders for the 49th consecutive year. Milestone projects completed In 2004, we proved that great planning brings results—especially when it’s followed by great execution. We demonstrated this with the completion of two long-term initiatives: a 40-year dream to bring natural gas over the Oregon Coast Range to Coos County, and the more-than- six-year pursuit of a 61-mile extension of the South Mist Pipeline. Both projects open new doors for customer growth and bring returns on our capital investments. We completed the South Mist Pipeline Extension weeks early, and its costs were rolled into rates in both Oregon and Washington. That we achieved this milestone without a significant hitch is a testament to our project management abilities.  Farther south, NW Natural created a backbone distribution system for four cities in Coos County. When the County needed to replace its contractor building the transmission line connect- ing to our system, we stepped up to help, providing project management support to oversee the county pipe- line’s completion. The Company began recovering the cost of the Coos Bay distribution system in November. Regulatory strategies prove their value While NW Natural was planning system expansions, it also was prepar- ing to strengthen and stabilize its revenues. Regulatory changes that took effect in the previous two years showed their value in 2004. The Conservation Tariff, approved by the Public Utility Commission of Oregon in 2002, earned the Company national recognition last year. The Weather Adjusted Rate Mechanism (WARM), which took effect in Oregon in 2003, added 20 cents per share by helping to compensate for weather in 2004 that was 8 percent warmer than average. Support by Oregon regulators for these strategies has helped NW Natural overcome two of the greatest challenges facing utilities today— uncertainty from weather and lower per capita consumption. Also in 2004, Oregon regulators approved our request to include the costs of complying with federal pipe- line integrity regulations in our rates. The decision allows us both to recover and earn on pipeline integrity invest- ments that will be made in the coming years. With these rate mechanisms in place, NW Natural is in an excellent position to focus its efforts on gaining more customers, more profitably. More customers, greater profitability NW Natural grew its customer base by more than 3 percent in 2004, double the average of local distribution companies nationally. Even more significantly, the Company continued to increase the value added by each new customer. Profitability of new resi- dential customer acquisitions increased from 14 percent in 2003 to 17 percent in 2004, and customer growth added approximately $7 million to margin. Our drive for lower costs and enhanced customer profitability was boosted further when regulators in Oregon and Washington gave us greater flexibility in responding to gas service requests for new development. We call it the Open Pathway program. Now, builders and developers must provide a pathway—an open trench or conduit—for service lines and mains. We expect this program to cut in half the cost of conventional service connections, providing savings that TOTAL CUSTOMERS IN THOUSANDS PROFITABILITY OF NEW RESIDENTIAL CUSTOMER ACQUISITIONS IN % ROE 600 550 500 450 400 350 300 20% 15% 10% 5% will allow us to reach even more customers, more profitably. Last year, NW Natural adopted a new software package, Prospector Pro, which added consistency and disci- pline to our evaluation of requests for new gas service. In addition, we started using a computerized Assumed Return on Equity (AROE) Study to identify new neighborhoods to target for growth. AROE can help the Company reduce investment risk while proactive- ly seeking new customers. It is one thing to add large numbers of new customers; it is another to deliver great service. Customer satisfaction continues to be a top priority for NW Natural. We were pleased to learn that we ranked ninth out of 55 gas utilities nationally in J.D. Power’s 2004 Gas Utility Resi- dential Customer Satisfaction Study. The Company ranked first in the West and second in the nation on billing and payment. Employees get it done The year 2004 started out with ice storms and record-breaking demand for natural gas, creating a showcase for NW Natural’s employees. Only about 60 of more than 580,000 customers experienced outages, and those for only a few hours. Employees GAS SALES AND TRANSPORTATION DELIVERIES IN MILLIONS OF THERMS 1,350 1,200 1,050 900 750 600 450 300 150 94 95 96 97 98 99 00 01 02 03 04 NW Natural added 18,485 new customers in 2004, expanding our customer base by 3.2 percent. This marks the 18th consecutive year of customer growth in excess of 3 percent, compared to the national average of 1.5 percent. 00 01 02 03 04 NW Natural has improved its return on equity from new residential customers in the past three years by targeting the most profitable customers and managing main extension costs. 94 95 96 97 98 99 00 01 02 03 04 RESIDENTIAL, COMMERCIAL AND INDUSTRIAL FIRM SALES INDUSTRIAL INTERRUPTIBLE SALES TRANSPORTATION Gas sales and transportation deliveries were 1.1 billion therms in 2004. 3 investments in pipeline integrity. Our customer growth remains strong and is increasingly profitable. And our inter- state storage business, which has newly added capacity, remains a growth opportunity we expect to add signifi- cantly to our bottom line in the future. As importantly, with weather normalization and the Conservation Tariff, the foundation we’ve created is largely protected from warmer-than- normal weather and declining consumption due to conservation. We enter 2005 as purposeful as ever. We know who we are. We know where we’re going. We know what you expect from us, and we know how to deliver. This year we will keep looking ahead, managing our costs, excelling at business basics and adding customers profitably. In short, we will be unwavering in our focus on the core business. But that doesn’t mean we won’t look out at the horizon as well. We will continue to search for new growth opportunities. In the same way we pursued underground storage, then leveraged the Mist storage field to create an interstate storage business, we will keep looking for ways to build on our core strengths. We’re ready for the challenges, and the opportunities. After 146 years of excellence, we’re ahead of the curve — and we intend to stay there. Sincerely, Mark S. Dodson President and Chief Executive Officer March 15, 2005 adjusted valves, climbed roofs to clear vents and helped stranded motorists. Some employees didn’t make it home for three days, staying near the Portland office to make sure the phones got answered. Although the weather let up within a week, our employees never did. In every part of the Company, our employees stepped forward to get the tough things done. A great example is the year-long effort to comply with the Sarbanes-Oxley Act. Our finance and accounting departments, along with a host of others across the Company, worked tirelessly to comply with the act. Our outside auditor, PricewaterhouseCoopers LLP, agreed with management’s assessment that in fact we did. In a year when we were once again named one of Oregon’s 100 Best Places to work by Oregon Business Magazine, we also reached agreement on a five- year contract, called the Joint Accord, with members of the Office and Professional Employees International Union, Local 11. It is a balanced agreement that advances the interests of the Company and its employees. The challenges ahead High gas prices are of great concern, both to us and to our customers. Locally, NW Natural is doing what it can to offset high prices. In 2004, as part of a disciplined gas purchasing strategy, we used our Mist underground storage to maximum advantage, buying supplies when prices were most favorable. As a result, today our weighted average cost of gas is the lowest in Oregon and Washington. Our Conservation Tariff has aligned shareholder and customer interests around energy efficiency, and we are actively working with the Energy Trust of Oregon to help customers use natural gas as efficiently as possible. In 2005, we will be working to renew this innovative tariff. We have commis- sioned a study of the tariff that will serve as a basis for a filing this year to continue the mechanism. As a local distribution company, 4 we are price takers, not price makers when it comes to wholesale natural gas prices. Our challenge is to demon- strate to customers that they receive superior value from our products and services. And we’re doing that in a number of ways. We’re strengthening our energy efficiency communications, unveiling an improved web site that offers useful tools such as a bill analyz- er and reorganizing our consumer call centers for faster, easier solutions and a better customer experience. We enter 2005 as purposeful as ever. We know who we are. We know where we’re going. We know what you expect from us, and we know how to deliver. At the national level, we see some hopeful signs of progress in addressing the supply imbalance that exists today. These include the increasing number of liquefied natural gas import proposals moving through the permitting process and new incentives passed by Congress to build an Alaskan pipeline. Clearly, the country needs a compre- hensive energy strategy. NW Natural will work closely this year with the American Gas Association to advance national energy policies aimed at reducing gas price volatility. Around the next curve While we are proud of what the years of planning and hard work meant to our performance in 2004, we are even more excited about what they mean for 2005 and beyond. We have built a strong foundation on which to grow our Company. The South Mist Pipeline Extension and the Coos Bay distribution system are in rates and contributing to our earnings. We can now recover and earn on our Focusing on mutual gains Interview with Gregg Kantor, Senior Vice President 1. What is NW Natural’s regulatory strategy, and how has the Company been pursuing it? A major focus has been reducing business risks from factors outside the Company’s control. To that end, we’ve introduced a number of innovative regulatory mechanisms, each built on our commitment to meet the needs of both customers and shareholders. For example, when natural gas prices increased significant- ly in 2000 and 2001, we stepped forward to help customers use our product more efficiently. But as usage declined so did our revenues. It made no sense that doing what was right for customers should hurt the company. So we developed a mechanism we called the Conservation Tariff. In 2002, the Public Utility Commission of Oregon (OPUC) approved the Conservation Tariff, which partially decouples our margins from how much gas we sell. In the end, it aligns the interests of shareholders with those of customers. Weather is a challenge we’ve faced for a long time. In 2003, we developed our own weather normalization mechanism, called the Weather Adjusted Rate Mechanism (WARM). With the backing of customer groups, we secured approval from the OPUC. WARM helps protect customers against high gas bills during unusually cold winters and protects shareholders from revenue losses during unusually warm winters. Both the Conservation Tariff and WARM demonstrate what can be accomplished when solutions create a win for customers and shareholders. 2. How have pipeline safety issues impacted your regulatory efforts? NW Natural has taken a proactive approach to pipeline safety. We completed removal of all cast-iron pipe in our system several years ago and are now replacing bare-steel pipe. The OPUC has supported these efforts by allowing the recovery of a substantial portion of the costs associated with the cast-iron pipe and bare-steel work. The new federal pipeline safety mandates increased significantly the work to be done on transmission lines. The cost of complying with these new requirements is a major concern to every gas utility. However, we have secured OPUC approval for the next four years to roll yearly pipeline integrity costs, including return, into rates each October. 3. What are the Company’s newest regulatory initiatives? In late 2004, the Washington and Oregon commissions approved our Open Pathways tariff. This mechanism holds Gregg Kantor, Senior Vice President of Public and Regulatory Affairs, at the state capitol in Salem, leads the team that works with regulators in Oregon and Washington. the customer responsible for providing a pathway for gas lines to new buildings or developments. The customer is required to make a trench or conduit available for gas services or mains or compensate the Company for its excavation time. This reflects requirements already in place for electric service and represents a major breakthrough for us. We expect it will cut in half the cost of installing service installations where joint trenching isn’t being used. In January 2005, the OPUC approved a combined heat and power tariff. This tariff allows NW Natural to sell natural gas at a discounted rate to fuel microturbines, fuel cells and other small-scale electrical generating equipment. We hope this incentive will stimulate interest from both manufacturers and customers in these energy- saving technologies. 4. How would you describe your relations with Oregon and Washington regulators and consumer advocates? Our relationships are quite positive. We are fortunate to have regulators and consumer advocates who, while tough and passionate about their duties, are also knowledgeable, fair and open-minded. They understand utilities must attract investment capital if they are to maintain safe, reliable service, and they are open to pursuing ideas that benefit customers while keeping utilities strong. 5 Undergraduates Ben Coppel, Nicole Frostad, Stephanie Stradley and Matt Steel enjoy a warm fall day at the University of Oregon. Most students were just as comfortable in January 2004 during the severe cold snap. NW Natural’s newest transmission line allowed the Company to serve its largest customers such as the university, despite record-breaking demand. 6 Ahead of the curve Maybe “innovative” isn’t the first word that comes to mind when you think of a natural gas utility. But think again. Like most gas utilities, NW Natural is focused on providing safe, reliable, low-cost natural gas service to its customers. It’s how we do it that stands out. We’re not afraid to try new approaches to meet customers’ needs. There’s the new mechanism we developed to help customers keep their bills down when weather is colder than normal... the new energy systems we’ve developed to increase efficient use…even the month-early completion of a pipeline expansion, which made the critical difference in assuring reliable service to customers like the University of Oregon during the bitter winter storm of January 2004. We’re a natural gas utility — but we’re also bold enough to innovate and bold enough to lead. That’s what puts us ahead of the curve. 7 Opening new markets Some dreams refuse to die. For 39 years, NW Natural held fast to its vision of serving Coos Bay, a Southern Oregon coast community for which the Company held a franchise. In 2004, that dream came true. There were plenty of ups and downs in building public support, securing funding and coordinating construction of NW Natural’s distribution system with the completion of the county’s transmission line. It took a commitment of dollars from the Oregon Legislature and a vote of Coos County residents to bring a transmission line across the Oregon Coast Range. But despite the obstacles, in 2004 NW Natural installed its new Coos County distribution system, comprising more than 250,000 feet of pipeline. Building the backbone NW Natural started building its local distribution system in Coos County in August 2003. At the same time, the county began building the transmission line to connect Coos County customers to the interstate pipeline. NW Natural outpaced the county’s progress, and the local distribution system was ready to go by summer. Before the transmission line was completed, NW Natural began serving customers with trucked-in compressed natural gas. By November, 12 customers identified as having the most pressing need for natural gas were receiving supplies trucked from Portland in CNG tankers. NW Natural began to recoup through rates its Coos County investment of nearly $12 million. Finally, the connection On Jan. 14, 2005, the county’s transmission line was ready for use. Coos County contractors had tested the line, and soon natural gas was flowing from the interstate pipeline to Coos County. NW Natural Customer Consultant Linda Kennedy and Commercial Service Technician Dan Hutchens are key participants in the Company’s efforts to attract and serve more customers in the Coos Bay area. “It’s exciting and fun,” said Hutchens. “Coos County has had one of the highest unemployment rates in the state. I think once people see things starting to happen and new businesses coming in, they’ll understand why the county commissioners have been wanting to do this.” At right, restaurant owner Elizabeth Kinzie looks forward to cooking with natural gas. 8  Several weeks after gas was flowing, NW Natural had more than 400 homes and businesses signed up for gas service. The Company set a goal of serving 1,000 customers in the cities of Coos Bay, Myrtle Point, Coquille and North Bend by the end of 2005. Under the bay One of the milestones in building the Coos Bay distribution system was crossing under Coos Bay to bring gas to the North Spit industrial area. The promise of natural gas already helped sway the decision of Southport Forest Products, which plans to build an expanded plant on the spit. In addition, Energy Products Development, LLC announced plans to build a liquefied natural gas plant on the spit specifically to take advantage of new gas lines to that area. 9 Leading with innovation New technologies are providing new ways for customers to use energy wisely and for NW Natural to grow. Combined heat and power NW Natural is a regional leader in promoting distributed generation and combined heat and power (CHP) projects. Distributed generation means the small- scale generation of electricity at the location of its use rather than at a centralized power plant. CHP systems go a step farther by capturing waste heat from the generating process and using it to heat space or water. CHP is one of today’s most efficient and cost-effective ways to generate energy. NW Natural is a central player in a consortium of organizations and businesses promoting distributed generation and CHP. The Company’s newest project, to be completed in 2005, is a five-microturbine system at an Oregon Health Sciences University building. NW Natural anticipates long-range business benefits from promoting distributed generation and CHP. First, CHP offers NW Natural new ways to serve industrial customers. Second, CHP reduces the use of inefficient, centralized electric generation. This, in turn, reduces the demand for natural gas to generate electricity. In 2004, the Public Utility Commission of Oregon approved a tariff proposed by NW Natural that will provide rate incentives for industrial customers using gas-powered distributed generation. The Company foresees an increase in the demand for onsite generation 10 as electric rates go up and generating equipment costs come down. Prospecting for profitability To make sure customer growth benefits the Company’s bottom line, NW Natural uses innovative tools to target its marketing and infrastructure investments. Two programs, Prospector Pro and AROE (Assumed Return on Equity), are NW Natural’s newest electronic tools for ensuring profitable growth. Prospector Pro, adopted in August 2004, allows NW Natural’s marketing representatives to calculate more accurately the cost of hooking up a new customer. With Prospector Pro, a marketing representative can estimate how much gas the new customer will use and then calculate costs and benefits. The program adds accuracy, consistency and discipline to customer acquisition efforts. While Prospector Pro responds to service requests, NW Natural uses AROE for proactive marketing. Using tax assessor data, an employee can estimate a home’s gas usage. AROE then overlays data from NW Natural’s propensity study to learn which homeowners are most likely to switch to natural gas. Now, NW Natural can focus direct mailings on neighborhoods with high percentages of likely, profitable customers. AROE also guides the selection of existing neighborhoods for new main construction. We’ll call you back In November, NW Natural became the first utility in our region to offer customers the option of receiving a call back, rather than waiting on hold to talk with a service representative. The launch of Virtual Hold Technology software won rave reviews from customers who were freed from waiting on their telephones but could still count on talking soon with a NW Natural employee. During November and December, just under half our customers chose the callback option. Swim team member Theresa Likarish glides through her practice in the pool at Lewis & Clark College’s Swim Pavilion, now heated by a natural gas-fired microturbine. In 2004, Chris Galati, NW Natural’s Director of Conservation and Technology, coordinated placement of the 30 kW microturbine in the Portland college’s newest building, where it generates electricity for the campus. Waste heat from the microturbine warms the water in the pool. 11 Promoting wise energy use The Wall Street Journal subsequently featured an article on the mechanism and the unusual consumer-corporate partnership behind it. Cavanagh later joined NW Natural in advocating the tariff to the Washington Utilities and Transportation Commission. At the same time, the Company described to Washington regulators the Weather Adjusted Rate Mechanism (WARM), another innovative regulatory mechanism, which took effect in Oregon in October 2003. NW Natural introduced WARM as a way to help protect customers from extremely high bills when In 2004, investor-owned utilities around the nation turned to NW Natural for a potential solution to a chronic problem: How can we encourage customers to use energy more efficiently without reducing Company revenues? NW Natural’s Conservation Tariff, launched in 2002, recognizes that customers are using less natural gas as appliances become more efficient and as gas prices increase. The tariff provides a mechanism for protecting Company earnings as natural gas use declines. In 2004, it added $3.5 million to earnings, translating to 7 cents a share. By protecting earnings, the Conservation Tariff frees NW Natural to promote more aggressive energy efficiency programs. In 2004, NW Natural worked with the Energy Trust of Oregon to deliver high- efficiency programs to reduce natural gas use by more than a million therms. One of NW Natural’s Conservation Tariff’s most vocal supporters is Ralph Cavanagh of the Natural Resources Defense Council. In the summer of 2004, Cavanagh and NW Natural President and CEO Mark Dodson addressed a national conference of state regulators to discuss the tariff’s benefits for consumers and utilities. Steve Bicker, (left) Energy Efficiency Services Program Manager, and Onita King, Rates & Regulatory Manager, help NW Natural satisfy both shareholders and customers through regulatory mechanisms that encourage wise energy use. Hot Lips Pizza, known for its sustain- able business practices, enjoys lower energy bills by reusing waste heat from its gas-fired pizza ovens to heat its water. At right, customer Stewart Clark samples the results. winter weather is colder than expected, and to help protect shareholders from reduced Company revenues when winter weather is warmer than normal. Unlike many parts of the country, utility weather normalization is not common in the Pacific Northwest. Consumer advocates supported WARM because they understand how it helps protect consumers from high winter bills. They also like the fact that the Company’s unique proposal trues up bills immediately, thus giving customers relief on their next bills. Most utilities don’t apply weather adjustments to customer bills until the following heating season. WARM played an important role in the Company’s financial results for the year, and especially for the second quarter of 2004, which was 31 percent warmer than average. For the year, WARM contributed $9 million of margin, equivalent to 20 cents a share. 13 Building for the future It was another milestone year for Mist, NW Natural’s premium underground gas storage facility. In the 1970s, when NW Natural began preparing the Mist storage field, management could not have envisioned all the benefits the Company’s investment would yield. Nor could they know how underground storage would give them more control over peak- demand gas supplies and future gas costs. By 2004, the decision to invest at Mist has never looked better. Last fall, the Company completed the biggest capital construction project in its history: a 61-mile extension of the South Mist pipeline, expanding Mist’s takeaway capacity and bolstering the Company’s service to its fast-growing customer base. Underground storage supplements NW Natural’s gas supplies in high-demand periods. It also allows the Company to reduce its need for year-round interstate pipeline capacity, and provides a way for NW Natural to purchase and store gas when prices are lowest. NW Natural also sells gas storage services on the interstate market. In this way, the Company has diversified its revenue streams while leveraging its core assets and expertise. SMPE finale After six years of planning, permitting and construc- tion, the South Mist Pipeline Extension (SMPE) officially went on line on Sept. 22, 2004. The Company rolled SMPE into rates on Oct. 1. Built for about $110 million, the 24-inch-diameter SMPE doubles deliverability from the Mist underground storage field to the Portland metropolitan area and provides another connection to the interstate pipeline. Construction was a major challenge, as the pipeline crossed sensitive environmental areas, rich farmland and populous suburbs. Yet the team completed the project five weeks ahead of schedule after contractors 14 successfully managed the longest large-diameter underground bore in Oregon history. The bore passed through more than a mile of solid rock, but it was finished ahead of schedule and on budget. Timing is everything The SMPE’s first 11.7-mile segment began operating Nov. 6, 2003. On Jan. 5, 2004, extremely cold tempera- tures sent gas demand soaring, and NW Natural set a new one-day sendout record of 8.9 million therms. The new pipeline was critical to the Company’s ability to avoid outages and reliably serve its customers. The SMPE helps NW Natural serve some of Oregon’s fastest-growing communities. Its completion puts NW Natural ahead of demand, allowing it to absorb new residential, commercial and industrial customers in both suburban and rural areas near Portland. Jewels in the making The year included improvements to the Mist storage facilities as well. In 2004, NW Natural completed the expansion of its Sapphire phase. This $9.1 million project expanded capacity and deliverability of the Mist facilities. Sapphire’s immediate purpose is to make new storage capacity available for the interstate market. As NW Natural’s core market grows, the Company expects to reallocate Sapphire’s resources to serve its core distribution customers. Interstate customer growth As NW Natural continues to develop storage infrastructure, it also expands its interstate business. The Company currently has 10 interstate storage customers across the Western United States and Canada, with customers on both firm and interruptible service contracts. Customers include local distribution companies, energy marketers and power generators. Among the residents Senior Project Engineer Roy Rogers wanted to keep happy during SMPE construction were some four-legged ones. NW Natural conducted extensive research and worked with equestrian facilities like Sherwood Forest in Wilsonville, Oregon, to assure that neither the construction nor the new pipeline would disturb the horses. Rogers and the construction team also restored horse pastures and paths to their previous condition – or better. Profiting from smart growth Jamison Park draws visitors of all ages to the heart of Portland’s new River District, a bustling community of upscale as well as affordable multi- family housing, cafes, shops, boutiques and galleries, nearly all served by NW Natural. Brenda Hartzog, Residential New Construction Consultant, and Grant Yoshihara, Director of Utility Services, help bring natural gas service to the homes and businesses in this thriving neighborhood. 16  NW Natural is benefiting from strengthened relation- ships with architects, engineers and developers. The Company reaches out to these groups through seminars and newsletters to educate them about economical and space-saving natural gas technology. Finally, the Company’s efforts to target idle services are returning some commercial buildings back to gas service. Open pathways reduce construction costs For years, builders and homeowners in the Northwest have been required to provide a trench to bring electricity to new buildings. This has not been the case with natural gas. That changed in 2004, when Oregon and Washington regu- lators agreed to require customers to provide an open trench or conduit for natural gas service lines and mains to new buildings. This means NW Natural will lower its costs and realize higher margins from all new construction. While sharing trenches with electric and telecommunication providers already is common practice in many parts of the service territory, each year crews are required to dig an estimated 7,000 trenches to install gas services. NW Natural’s contribution to the cost of residential service installation is expected to fall from an average $726 to $339. As an added incentive, NW Natural now offers a guaranteed installation date when a contractor notifies the Company in advance that a pathway will be ready for our pipeline. Natural gas is still the fuel of choice in the Northwest, and NW Natural has the customer growth to prove it. In 2004, the Company’s customer base grew by more than 3 percent for the 18th consecutive year. At the same time, the Company continued to improve the profitability of its customer additions. The growing multifamily sector Because of Oregon’s unique land use planning system, Portland is growing up, not just out. With suburban development contained by a conservative urban growth boundary, high-density multifamily construction is the hottest trend in Portland’s housing market. To help attract empty nesters and young professionals to townhouses and condominiums, developers are investing in natural gas space and water heating as well as cooktops and hearths. In 2004, NW Natural significantly exceeded its goals for new multifamily services. Affordable housing developers prefer gas, too High-end developers aren’t the only ones choosing gas. Developers of affordable housing have realized that high- efficiency natural gas appliances can reduce tenants’ fuel bills. New natural gas technologies such as compact on-demand water heaters save space as well as energy. In 2004, the Portland Develop- ment Commission (PDC) updated its “Green Building” guidelines. Affordable projects receiving PDC funds are encouraged to use high-efficiency combo systems and natural gas furnaces. Commercial conversions present new opportunities Although new commercial development has been slow to improve, NW Natural has seen an increase in commercial conversions. With the limited supply of buildable land in the Portland area, developers are renovating existing buildings rather than constructing new ones. These renovations often include a switch to natural gas. 17 Management’s Discussion and Analysis of Financial Condition and Results of Operations The following is management’s assessment of Northwest Natu- ral Gas Company’s financial condition including the principal fac- tors that affect results of operations. The discussion refers to the consolidated activities of the Company for the three years ended Dec. 31, 2004. Unless otherwise indicated, references in this dis- cussion to “Notes” are to the notes to the consolidated financial statements in this report. The consolidated financial statements include the regulated par- ent company, Northwest Natural Gas Company (NW Natural), and its non-regulated wholly-owned subsidiaries: ■ 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 “Com- pany.” In this report, the term “utility” is used to describe the Com- pany’s regulated gas distribution business and the term “non-util- ity” is used to describe its interstate gas storage business and other non-regulated activities (see Note 2). In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact earnings. The Company believes this per share information is useful because it enables readers to better understand the impact of these factors on earnings. All references in this report to earnings per share are on the basis of diluted shares (see Note 1). EXECUTIVE SUMMARY The Company’s strategy in 2004 was to strengthen its financial position and remain focused on profitably growing its regulated gas distribution business and interstate gas storage business. Highlights of 2004 include: ■ overall earnings growth of 11 percent over 2003 despite weather conditions that were 3 percent warmer; ■ the addition of 18,485 customers, for a growth rate in excess of 3 percent for the 18th consecutive year; ■ the issuance of $40 million in common stock through a public offering to help fund major construction projects and maintain a balanced capital structure; ■ the upgrade of the Company’s long-term debt rating to A+ by the Standard & Poor’s Rating Services; ■ the completion ahead of schedule of the Company’s largest construction project to date, the 61-mile South Mist Pipeline Ex- tension (SMPE), which received timely regulatory approval for recovering its costs through customer rates in both Oregon and Washington; ■ regulatory approval to track future pipeline integrity manage- ment costs into rates in Oregon; ■ a new 5-year labor agreement, also known as the Joint Accord; ■ the settlement and early implementation of the Washington general rate case; ■ expansion of the Company’s gas distribution system into Coos County, Oregon, an area targeted for natural gas service for over three decades; and ■ the development of additional gas storage capacity at Mist for interstate storage services, replacing capacity that had been re- called to meet core utility customer requirements. Issues, Challenges and Performance Measures There are a number of factors that affect the Company’s opera- tions and financial performance. The most significant issues and challenges the Company expects to face in 2005 include high gas commodity prices, unpredictable weather conditions, the impact of regulatory actions or policy changes, managing gas supplies and storage capacity, maintaining a competitive advantage over alter- 18 N W N AT U R A L nate fuels, managing environmental risks and exposures, an un- certain economic recovery and higher interest rates. For a detailed listing of other risks facing the Company, see “Forward-Looking Statements” and “Quantitative and Qualitative Disclosures About Market Risk,” below. In order to deal with these and other issues affecting the busi- ness, the Company’s strategic plan includes strategies for: ■ improving NW Natural’s ability to add customers both profit- ably and at a rapid pace; ■ maintaining NW Natural’s reputation for exemplary service; ■ reducing business risk; ■ managing all costs, including capital expenditures; ■ setting high performance standards for all employees; and ■ judiciously growing beyond the Company’s local distribution business where such growth would complement core assets and competencies. In addition to return on equity (ROE) and common equity ratio as key indicators of the Company’s operating performance and fi- nancial condition, other key performance measures the Company uses in monitoring progress against its goals are utility earnings per share, customer satisfaction ratings, new customer additions, operations and maintenance expense per customer, construction cost per meter installed, and non-revenue producing capital expen- ditures per customer. $2.00 $1.25 $1.50 $1.75 DILUTED EARNINGS PER SHARE IN DOLLARS EARNINGS AND DIVIDENDS Earnings applicable to common stock were $50.6 million, or $1.86 a diluted share, for the year ended Dec. 31, 2004, compared to $45.7 million, or $1.76 a share, and $41.5 million, or $1.62 a share, for the years ended Dec. 31, 2003 and 2002, respectively. Re- turns on average common equity for these three years were 9.4 percent, 9.3 percent and 8.7 percent, respectively. Primary factors affecting earnings, and the re- sulting positive (negative) im- pact include: 2004 compared to 2003: ■ increased the contribution to net operating revenues (margin) from residential and commercial customers primarily resulting from the Oregon and Washington general rate increases, including rate increases for the SMPE investment and a full year effect of the weather normalization mechanism – $26 million; ■ increased margin contri- bution from industrial customers resulting from rate redesigns in the 2003 Oregon general rate case and a recovering economy – $4.8 million; ■ decreased margin from other utility operating revenues due to changes in and amortizations under the Company’s regulatory deferral mechanisms – ($7.8 million); ■ increased franchise tax expense due to higher gross revenues – ($2.2 million); ■ increased payroll and related payroll tax, pension and health care costs primarily due to wage and salary increases and certain benefit cost increases – ($4.6 million); ■ internal development costs and external audit fees relating to the implementation of Section 404 of the Sarbanes-Oxley Act of Diluted earnings were $1.86 per share in 2004, up 6 percent over 2003. 94 95 96 97 98 99 00 01 02 03 $0.25 $0.50 $1.00 $0.75 04 16% 14% 12% 10% TOTAL SHAREHOLDER RETURNS ANNUALIZED AS A PERCENT 2002, including compliance documentation and testing require- ments – ($1.5 million); ■ increases in depreciation and property taxes due to added utility plant – ($3.8 million); ■ decreased margin from interstate gas storage services due to less volatility in natural gas price differentials – ($2.6 million); ■ reduced income before tax from non-utility subsidiary invest- ments, including a $0.5 million charge for an impending sale of solar electric generating investments – ($0.3 million); and ■ increased income taxes – ($3.2 million). 2003 compared to 2002: ■ earnings for 2002 were reduced by special charges totaling $13.9 million before tax, or $8.4 million after tax, representing the Company’s transaction costs incurred in its effort to acquire Portland General Electric Company (PGE) from its parent, Enron; ■ increased margin contribu- tion from residential and commercial customers primarily resulting from rate increases – $9.9 million; ■ increased gains in market value of equity-based life insurance investments – $2.0 million; ■ reductions in interest charges on deferred regula- tory account balances result- ing from lower balances due to a $30 million cus- tomer refund in 2002 from accumulated gas cost savings – $1.4 million; ■ increased income before tax from the interstate gas storage segment – $1.1 million; ■ increased payroll and related payroll tax, pension, health care and other benefit costs – ($8.1 million); ■ increases in other operations and maintenance costs – ($2.4 million); ■ decreased margin contribution from industrial customers due to weak economic conditions – ($3.0 million); ■ increases in depreciation expense and property taxes relating to added utility plant – ($3.1 million); ■ increases in other employee benefit costs – ($0.8 million); and ■ reduced income before tax from non-utility subsidiary invest- ments – ($0.5 million). Dividends paid on common stock were $1.30 a share in 2004, compared to $1.27 a share in 2003 and $1.26 a share in 2002. The 2004 increase in dividends paid marks the 49th consecutive year of dividend increases. The Company’s total return — dividends plus stock appreciation — was 14.5 percent in 2004, 14.3 percent over the past five years, and 10.9 percent over ten years. Five Years 1999-2004 Ten Years 1994-2004 One Year 2004 8% 6% APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES In preparing the Company’s financial statements using gener- ally accepted accounting principles in the United States of America (GAAP), management exercises judgment in the selection and ap- plication 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 management’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 regulatory cost recovery, unbilled revenues, derivative instruments, pension assumptions, income taxes and environmental contingen- cies. Management has discussed the estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board. The Company’s critical accounting poli- cies and estimates are described below. Within the context of the Company’s critical accounting policies and estimates, management is not currently aware of any reason- ably likely events or circumstances that would result in materially different amounts being reported. Regulatory Accounting NW Natural is regulated by the Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC), which establish the Company’s utility rates and rules governing utility services provided to customers, and to a certain extent set forth the accounting treatment for certain regu- latory transactions. In general, NW Natural uses the same account- ing 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 ac- counting 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 mechanism called the Purchased Gas Adjustment (PGA), which is submitted for approval annually to the OPUC and WUTC (see “Results of Operations – Regulatory Matters – Rate Mechanisms,” below). There are other expenses or revenues that the OPUC or WUTC may require the Company to de- fer for recovery or refund in future periods. SFAS No. 71 requires the Company to account for these types of deferred expenses (or deferred revenues) 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 ex- pense or revenue on the income statement at the same time it re- alizes the adjustment to amounts included in utility rates and charged to customers. The conditions a company must satisfy to adopt the accounting policies and practices of SFAS No. 71 applicable to regulated com- panies include: ■ an independent regulator sets rates; ■ the regulator sets the rates to cover specific costs of delivering service; and ■ the service territory lacks competitive pressures to reduce rates below the rates set by the regulator. NW Natural continues to apply SFAS No. 71 in accounting for its regulated utility operations. Future regulatory changes or changes in the competitive environment could result in the Company dis- continuing the application of SFAS No. 71 for some or all of its reg- ulated business. This would require the write-off of those regula- tory assets and liabilities that would no longer be probable of recovery from or refund to customers. Based on current regulatory and competitive conditions, NW Natural believes that it is reason- able to expect continued application of SFAS No. 71 for its regulated activities, and that all of its regulatory assets and liabilities at Dec. 31, 2004 and 2003 are recoverable or refundable through future customer rates. N W N AT U R A L 19 Management’s Discussion and Analysis 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 primarily based on the Company’s percent- age estimate of its unbilled gas each month, which is dependent upon a number of factors that require management’s judgment. These factors include total gas receipts and deliveries, customer meter reading dates, customer usage patterns and weather. Un- billed revenue estimates are reversed the following month when actual billings occur. Estimated unbilled revenues at Dec. 31, 2004 and 2003 were $64.4 million and $59.1 million, respectively. The increase in unbilled revenues at year-end 2004 was primarily due to higher gas prices included in customer rates, partially offset by lower unbilled volumes reflecting warmer weather and decreases in customer usage due to higher prices. If the estimated percentage of unbilled gas at Dec. 31, 2004 were adjusted up (or down) by 1 percent, then the Company’s unbilled revenues, net operating rev- enues and net income would have increased (or decreased) by an estimated $1.0 million, $0.5 million and $0.3 million, respectively. In November 2003, NW Natural implemented a weather normal- ization mechanism in Oregon that helps stabilize net operating rev- enues by adjusting current customer billings based on temperature variances from average weather (see “Results of Operations – Reg- ulatory Matters – Rate Mechanisms,” below). Weather normaliza- tion is also included in unbilled revenues at the end of each account- ing period using management’s judgments as discussed above. Non-utility revenues, derived primarily from interstate 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 they are earned for amounts above the guaranteed value based on estimates pro- vided by the independent energy marketing company. Accounting for Derivative Instruments and Hedging Activities In providing gas distribution services, NW Natural enters into forward contracts to buy and sell natural gas. These contracts qual- ify as normal purchases and normal sales under SFAS No. 133, “Ac- counting for Derivative Instruments and Hedging Activities,” be- cause they provide for a purchase or sale, and subsequent delivery, of natural gas in quantities that are probable of delivery over a rea- sonable period of time in the normal course of business (see Note 1, “Derivatives Policy”). Accordingly, these contracts are accounted for at the time of settlement and are not reflected on the Company’s balance sheet or income statement prior to settlement. The Company has an established Derivatives Policy that 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. Hedging activi- ties consist of natural gas commodity price and foreign currency exchange rate hedges which are accounted for as cash flow hedges. These contracts that qualify as derivative instruments are recorded on the balance sheet at fair value. Generally, most of these con- tracts are subject to regulatory deferral mechanisms, and as such any change in the fair value of these contracts is recorded as regu- latory assets or regulatory liabilities pursuant to SFAS No. 71 (see Note 1, “Derivatives Policy”). The Company’s estimate of fair value is determined from period to period based on prices available from external sources and internal modeling based on index prices that 20 N W N AT U R A L are subject to market volatility. For estimated fair values at Dec. 31, 2004 and 2003, see Note 11. The following table summarizes the realized gains and losses from commodity price and currency hedge transactions in the years ended Dec. 31, 2004, 2003 and 2002: Thousands 2004 2003 2002 Gains (losses) on commodity price swap contracts Gains (losses) on commodity price option contracts Subtotal Gains (losses) on swaps related to interstate gas storage Gains on foreign currency contracts Total gains (losses) $ 44,888 $ 29,660 $ (73,922) (2,464) __________ 42,424 2,723 __________ 32,383 (1,601) __________ (75,523) (186) 219 __________ 42,457 $ $ __________ __________ – 4,129 __________ 36,512 $ __________ __________ – 521 __________ (75,002) __________ __________ Realized gains (losses) from commodity price and foreign cur- rency 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-mar- ket valuations are not recognized in current income or other com- prehensive income, but are recorded 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 The Company has two qualified, non-contributory defined ben- efit pension plans covering all regular employees with more than one year of service. These plans are funded through a trust dedi- cated to providing retiree pension benefits. The Company also has several non-qualified supplemental pension plans for eligible ex- ecutive officers and certain key employees. These non-qualified plans are unfunded. Net periodic pension cost (NPPC) and accumulated benefit ob- ligations (ABO) are determined in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” using a number of key as- sumptions including the discount rate, the rate of compensation increases, retirement ages, mortality rates and the expected long- term return on plan assets (see “Financial Condition – Pension Cost (Income) and Funding Status,” below, and Note 7). These key as- sumptions have a significant impact on the amounts reported. NPPC consists of service costs, interest costs, the amortization of actuarial gains and losses, expected returns on plan assets and, in part, on a market-related valuation of assets. The market-related valuation reflects differences between expected returns and actual investment returns, which are recognized over a three-year period from the year in which they occur, thereby reducing year-to-year NPPC volatility. A number of factors are considered in developing pension 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 current market conditions and input from actuaries and other con- sultants. For the Dec. 31, 2004 measurement date, the Company: ■ decreased the discount rate assumption from 6.25 percent to 6.00 percent; ■ maintained the rate of compensation increase in a range of 4.00-5.00 percent; and ■ maintained the expected long-term return on plan assets at 8.25 percent. The change in discount rate was the primary factor contribut- ing to the increase in the plans’ ABO from $205 million at Dec. 31, 2003 to $223 million at Dec. 31, 2004. The Company believes its pension assumptions to be appropri- ate based on plan design and an assessment of market conditions. However, the following reflects the sensitivity of NPPC and ABO to changes in certain actuarial assumptions: Thousands Change in Assumption Impact on ABO at Impact on 2004 NPPC Dec. 31, 2004 Discount rate Expected long-term return on plan assets (0.25%) $ (0.25%) $ 608 $ 403 5,255 N/A The impact of a change in NPPC on operating results would be less than the amounts shown above because about 60 percent of NPPC is charged to operations and maintenance expense. The re- maining 40 percent is capitalized as construction overhead and in- cluded in utility plant, which is amortized to expense over the use- ful life of the asset placed into service. Accounting for Income Taxes Income taxes are accounted for in accordance with SFAS No. 109, “Accounting for Income Taxes,” by recognizing deferred in- come taxes for all temporary differences between the book and tax basis of assets and liabilities at current income tax rates. SFAS No. 109 also requires the recognition of additional deferred income tax assets and liabilities for temporary differences where regulators flow-through deferred income tax benefits or expenses in the ratemaking process of the regulated utility (regulatory tax assets and liabilities). This is consistent with ratemaking policies of the OPUC and WUTC. Regulatory tax assets and liabilities are recorded to the extent the Company believes they will be recover- able from or refunded to customers in future rates. At Dec. 31, 2004 and 2003, the Company had regulatory assets representing differ- ences between book and tax basis related to pre-1981 property of $64.7 million and $63.4 million, respectively, and has recorded an offsetting deferred tax liability for the same amounts (see Note 1). NW Natural believes that it is reasonable to expect recovery of these regulatory assets through future customer rates. However, future regulatory changes could require the write-off of all or a por- tion of these regulatory assets should they no longer be probable of recovery in future rates. Contingencies Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is rea- sonably estimable in accordance with SFAS No. 5, “Accounting for Contingencies.” 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, accruals are recorded for loss contingencies based on an analysis of poten- tial results, developed in consultation with outside counsel when appropriate, including allowances for uncollectible accounts, envi- ronmental claims and property damage and personal injury claims. Where information is sufficient to estimate only a range of prob- able liability, and no point within the range is more likely than any other, the Company recognizes an accrued liability at the lower end of the range. It is possible, however, that future results of opera- tions could be materially affected by changes in assumptions or estimates regarding these contingencies. With respect to environ- mental claims and related litigation costs, receivables are recorded for anticipated recoveries under insurance contracts based on amounts the Company estimates are probable of recovery. If these amounts are not recovered from insurance, the Company believes that recovery is probable from future utility rates based on current approval by the OPUC to defer these costs as a regulatory asset. See Note 12. RESULTS OF OPERATIONS Regulatory Matters NW Natural provides gas utility service in Oregon and Wash- ington, with Oregon representing over 90 percent of its revenues. Future earnings and cash flows from utility operations will be de- termined largely by the pace of continued growth in the residential and commercial markets and by NW Natural’s ability to remain price competitive in the large industrial market, to control ex- penses, and to obtain reasonable and timely regulatory ratemaking treatment for its operating and maintenance costs and investments made in utility plant. General Rate Cases NW Natural’s most recent general rate increase in Oregon, which was effective Sept. 1, 2003, authorized rates designed to produce a return on shareholders’ equity (ROE) of 10.2 percent. The OPUC approved a revenue increase of $13.9 million per year, of which $6.2 million went into effect on Sept. 1, 2003, and $2.7 million went into effect on a deferred basis on Nov. 12, 2003 as the first 11.7 miles of the Company’s southern portion of SMPE went into service. The remaining $3.8 million for the southern portion of the SMPE went into effect on Oct. 1, 2004, upon the completion and placement into service of the last segment of the SMPE proj- ect. Recovery for the Company’s Coos County distribution system project of $1.2 million went into effect on Nov. 1, 2004, on a de- ferred basis. While not included in the rate case result, an addi- tional annual rate recovery of $7.5 million associated with the northern portion of SMPE became effective Oct. 1, 2004. In November 2003, NW Natural filed a general rate case in Washington that proposed a revenue increase of $7.9 million per year from Washington operations through rate increases averag- ing 15 percent. In June 2004, the WUTC approved a settlement agreement entered into by the parties to NW Natural’s Washing- ton general rate case, which became effective on July 1, 2004, au- thorizing a revenue increase of $3.5 million per year, or 6.5 per- cent. In addition, the settlement authorized NW Natural to include the SMPE cost of service of approximately $0.7 million per year in rates, subject to audit, concurrent with the annual Washington PGA filing, which became effective on Nov. 1, 2004. See “Rate Mechanisms,” below. Notwithstanding authorized revenue levels approved by the OPUC or the WUTC, actual revenues are dependent on weather, economic conditions, customer growth, competition and other fac- tors affecting gas usage in NW Natural’s service area. In January 2005, the Company filed a rate case with the Federal Energy Regulatory Commission (FERC) proposing an update of maximum rates for the Company’s interstate storage services op- eration and new service offerings. The requested new rates are de- signed to reflect the costs related to the further development of the Mist gas storage facilities and costs associated with the SMPE proj- ect. This filing was made to satisfy FERC’s requirement that there be a cost and revenue review in three years following its original storage service rate authorization. Rate Mechanisms WEATHER NORMALIZATION. In November 2003, NW Natural im- plemented a weather normalization mechanism in Oregon that helps stabilize net operating revenues, or margin, by adjusting cur- rent customer billings based on temperature variances from aver- age weather. The weather normalization mechanism approved by the OPUC is applied to Oregon residential and commercial custom- ers’ bills between Nov. 15 and May 15 of each heating season. The mechanism adjusts the margin 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 fixed costs and to reduce fluctuations in customers’ bills due to colder- or warmer-than-average weather. In October 2004, the mechanism was modified to limit the upward or downward adjustments to individual bills to certain specified ranges, with any excess amounts being deferred (see “Residential and Commercial Sales,” below). N W N AT U R A L 21 Management’s Discussion and Analysis PURCHASED GAS ADJUSTMENT. 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 com- modity purchased under contracts with gas producers (see “Com- parison of Gas Operations – Cost of Gas Sold,” below), the appli- cation of temporary rate adjustments to amortize balances in regulatory asset or liability accounts and the removal of temporary rate adjustments effective the previous year. Pursuant to the PGA tariffs, in September 2004, the OPUC approved rate increases ef- fective Oct. 1, 2004 averaging 20.1 percent for Oregon residential sales customers, and in October 2004, the WUTC approved rate in- creases effective Nov. 1, 2004 averaging 19.5 percent for Washing- ton residential sales customers. These rate increases include de- ferred revenue from the costs related to the SMPE project, which was completed and placed into service on Sept. 22, 2004. The Oregon increase of 20.1 percent consisted of recovery of gas costs (13.9 percent), temporary rate adjustments (2.5 percent, including deferrals for SMPE) and the recovery of SMPE costs of service (3.7 percent). The Washington increase of 19.5 percent consisted of the recovery of gas costs (12.0 percent), temporary rate adjustments (6.3 percent), and the recovery of SMPE costs (1.2 percent). The inclusion of SMPE costs in Oregon and Washington rates resulted in additional revenue increases totaling $14.7 million per year. Dur- ing the fourth quarter of 2004, the staff of the OPUC initiated a re- view of gas purchasing strategies for all three local gas distribution companies serving Oregon. The schedule, scope and potential find- ings, including the matter of whether the review will lead to formal proceedings before the OPUC, remain uncertain. In 2003, the OPUC approved a PGA rate increase averaging 3.5 percent for Oregon sales customers and the WUTC approved a PGA rate increase averaging 16.8 percent for Washington sales custom- ers, both effective on Oct. 1, 2003. In 2002, the OPUC approved PGA rate decreases averaging 14 percent for Oregon sales customers and the WUTC approved PGA rate decreases averaging 25 percent for Washington sales customers, both effective on Oct. 1, 2002. The OPUC has formalized a process that tests for excessive earn- ings in connection with gas utilities’ annual filings under their PGA mechanisms. The OPUC has confirmed NW Natural’s ability to pass through 100 percent of its prudently incurred gas costs into rates. Under this requirement, NW Natural is authorized to retain all of its earnings up to a threshold level equal to its authorized 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 2003 or 2002 earnings re- sults. NW Natural does not expect that amounts will be identified for refund with respect to its earnings in 2004, which will be re- viewed by the OPUC in the second quarter of 2005. CONSERVATION TARIFF. Effective Oct. 1, 2002, the OPUC autho- rized NW Natural to implement a “conservation tariff,” a mecha- nism designed to recover lost margin due to changes in residential and commercial customers’ consumption patterns. The tariff is a partial decoupling mechanism that breaks the link between the Company’s earnings and the quantity of energy consumed by its customers, so the Company does not have an incentive to discour- age customers’ conservation efforts. The conservation tariff includes two components. The first, a price elasticity factor, adjusts for increases or decreases in con- sumption attributable to annual changes in commodity costs or periodic changes in the Company’s general rates. The second is a conservation adjustment calculated on a monthly basis to account for deviations between actual and expected volumes. Additional 22 N W N AT U R A L revenues or credits to customers produced by the conservation ad- justment are booked to a deferral account that is reconciled as part of the Company’s annual PGA. Baseline consumption is based on customer consumption patterns as determined in the 2003 Oregon general rate case, adjusted for consumption resulting from new customers. The partial 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 mech- anism’s effectiveness. Work on the independent review, which in- volves interested parties, is in process and is expected to be com- pleted by the end of March 2005. The study is expected to provide the basis for the Company’s filing to renew the tariff. PIPELINE INTEGRITY COST RECOVERY. In July 2004, the OPUC ap- proved applications by NW Natural relating to the accounting treat- ment and full recovery for the Company’s cost of its pipeline integ- rity management program (IMP) as mandated by the Pipeline Safety Improvement Act of 2002 (Pipeline Safety Act) and related rules adopted by the U.S. Department of Transportation’s Office of Pipeline Safety (see “Financial Condition – Cash Flows – Investing Activities,” below). Under the applications as approved, NW Nat- ural classifies its IMP costs as either capital expenditures or regu- latory assets, accumulates the costs over each 12-month period ending June 30, and recovers the costs, subject to audit, through rate changes effective on October 1 of each year commencing Oct. 1, 2004. The approved accounting and rate treatment for these costs extends through Sept. 30, 2008, and may be reviewed for po- tential extension after that date. NW Natural will begin including IMP costs in rates in 2005. OPEN PATHWAY TARIFF. The open pathway tariff, approved by the OPUC on Dec. 7, 2004, requires developers to provide the Company with a trench for installation of mains and services in new devel- opments. If a trench is not provided, the tariff requires the devel- oper to pay NW Natural’s costs of trenching. In the past, provision of a trench or reimbursement was not required. Implementation of the tariff began in early 2005. OPUC Investigation In August 2004, the OPUC approved a stipulation among NW Natural, the OPUC staff and two parties in the 2003 Oregon general rate case, providing for the settlement of issues raised in an inves- tigation initiated by the OPUC in 2003. These issues relate to trans- actions or interests in certain properties involving NW Natural in the vicinity of its headquarters building in downtown Portland, and the use of some of these properties for employee parking. The pri- mary effect of the stipulation was to reverse cost recovery as of Sept. 1, 2003, for certain properties that should not have been in- cluded in rate base in the 2003 Oregon general rate case, and for certain employee parking costs. Pursuant to the stipulation, NW Natural commenced paying refunds in the amount of $1.3 million to Oregon customers on Oct. 1, 2004, in connection with the an- nual Oregon PGA filing effective on that date. Approximately $0.3 million of that amount was charged to a reserve in 2003 and the first quarter of 2004; approximately $0.9 million was recognized as a reduction in other revenues in the second quarter of 2004; and the balance of $0.1 million was recognized as a reduction in other revenues in the third quarter of 2004. Effective Oct. 1, 2004, Oregon revenues were reduced by about $0.3 million per year to eliminate these costs from future rates. NW Natural agreed in the stipulation to undergo an audit in 2005 funded by the Company, which is ex- pected to focus on ratemaking issues relating to the inclusion of assets in rate base and NW Natural’s transactions with any affili- ated interests. The OPUC staff informed the Company that the re- quired audit will be performed during the third quarter of 2005. Comparison of Gas Distribution Operations The following table summarizes the composition of gas utility volumes and revenues for the three years ended Dec. 31: Thousands, except customers and degree days 2004 2003 2002 Utility volumes – therms: Residential and commercial sales Industrial sales and transportation Total utility volumes sold and delivered 574,925 51% 581,890 53% 590,629 52% 535,455 48% 517,862 47% __________ _____ __________ _____ __________ _____ 556,941 49% 1,131,866 100% 1,126,084 100% 1,099,752 100% __________ _____ __________ _____ __________ _____ __________ _____ __________ _____ __________ _____ Utility operating revenues – dollars: Residential and commercial sales Industrial sales and transportation Other revenues Total utility 3,185 $ 585,100 83% $ 519,323 86% $ 543,508 86% 84,922 13% 75,201 13% 1% 1% 7,460 __________ _____ __________ _____ __________ _____ 112,660 16% 1% 4,018 operating revenues $ 700,945 100% $ 601,984 100% $ 632,448 100% _____ _____ _____ _____ _____ _____ 399,176 __________ $ 301,769 __________ __________ Cost of gas sold Utility net operating revenues (margin) Total number of customers (end of year) 596,635 Actual degree days 3,853 Percent colder (warmer) than normal (25-year average degree days is used as normal) (8%) 323,128 __________ 353,034 __________ $ 278,856 __________ __________ $ 279,414 __________ __________ 578,150 3,952 560,067 4,232 (7%) (1%) NW Natural continued to grow its customer base, with a net in- crease of 18,485 customers during 2004. The growth rate for both 2004 and 2003 was 3.2 percent, compared to 3.5 percent in 2002. In the three years ended Dec. 31, 2004, more than 55,000 custom- ers were added to the system, representing an average annual growth rate of 3.4 percent. Residential and Commercial Sales The following table summarizes the utility volumes and utility operating revenues in the residential and commercial markets. The primary factors that impact the results of operations in these mar- kets are seasonal weather patterns, competitive factors in the energy industry and economic conditions in the Company’s service areas. Thousands, except customer data 2004 2003 2002 343,534 226,257 12,099 __________ 581,890 __________ __________ 357,091 240,155 (6,617) __________ 590,629 __________ __________ Utility volumes – therms: 356,199 Residential sales 226,490 Commercial sales (7,764) Change in unbilled sales __________ Total weather-sensitive utility volumes 574,925 __________ __________ Utility operating revenues – dollars: Residential sales Commercial sales Change in unbilled sales Total weather-sensitive utility revenues Total number of residential and commercial customers (end of year) 595,700 $ 381,526 $ 328,464 $ 354,735 201,475 176,385 199,725 (12,702) 14,474 3,849 __________ __________ __________ $ 585,100 $ 519,323 $ 543,508 __________ __________ __________ __________ __________ __________ 577,396 559,489 2004 compared to 2003: ■ volumes sold were 1 percent lower, reflecting the effect of 3 percent warmer weather that was partially offset by the impact of 3 percent customer growth; and ■ operating revenues were 13 percent higher, primarily due to higher rates effective Oct. 1, 2003 and Oct. 1, 2004 (see “Regula- tory Matters – Rate Mechanisms,” above). 2003 compared to 2002: ■ volumes sold were 1 percent lower, reflecting the effects of 7 percent warmer weather that was partially offset by the impact of 3 percent customer growth and the price elasticity effect of lower rates effective Oct. 1, 2002; and ■ operating revenues were 4 percent lower in 2003 than in 2002. Excluding the impact of gas cost refunds totaling $30.4 million during 2002, revenues were $54.6 million, or 10 percent, lower in 2003 than in 2002, primarily due to lower rates effective Oct. 1, 2002. Typically, 80 percent or more of annual utility operating reve- nues are derived from gas sales to weather-sensitive residential and commercial customers. Although variations in temperatures be- tween periods will affect volumes of gas sold to these customers, the effect on margin and net income was significantly reduced with the implementation of the weather normalization mechanism in Oregon beginning in November 2003 (see “Regulatory Matters – Rate Mechanisms,” above). This mechanism applies to meter read- ings of participating Oregon customers taken between Nov. 15 and May 15. Approximately 10 percent of NW Natural’s residential and commercial customers are in Washington, where the mechanism is not in effect, and about 8 percent of the eligible Oregon custom- ers elected not to be covered by the mechanism, so the mechanism does not fully insulate the Company from utility earnings volatility due to weather. The mechanism contributed a net $9.0 million of margin, equivalent to 20 cents a share of earnings, in the twelve month period ended Dec. 31, 2004, making up a significant portion of the margin that otherwise would have been lost from warmer- than-average weather. In 2003, the mechanism contributed $1.9 million of margin, equivalent to 5 cents a share of earnings, in the two-months after becoming effective in November 2003. Total utility operating revenues include accruals for gas deliv- ered but not yet billed to customers (unbilled revenues) based on estimates of gas deliveries from that month’s meter reading dates to month end. Amounts reported as unbilled revenues reflect the increase or decrease in the balance of accrued unbilled revenues compared to the prior year-end. Weather conditions, rate changes and customer billing dates affect the balance of accrued unbilled revenue at the end of each month. At Dec. 31, 2004, accrued un- billed revenue was $64.4 million, compared to $59.1 million at Dec. 31, 2003. Industrial Sales and Transportation The following table summarizes the delivered volumes and util- ity operating revenues in the industrial and electric generation markets: Thousands, except customers 2004 2003 2002 Utility volumes – therms: Industrial firm sales Industrial interruptible sales Electric generation sales and transportation Transportation Total utility volumes Utility operating revenues – dollars: Industrial firm sales Industrial interruptible sales Electric generation sales and transportation Transportation Total utility revenues Total number of industrial sales and transportation customers (end of year) 63,149 104,278 55,314 46,327 63,215 22,841 – 389,514 __________ 556,941 __________ __________ 1,667 414,554 __________ 517,862 __________ __________ 3,400 445,999 __________ 535,455 __________ __________ $ 44,625 $ 55,380 33,578 $ 23,655 42,965 11,346 – 12,655 __________ $ 112,660 $ __________ __________ 6 17,962 __________ 75,201 $ __________ __________ 4,591 26,020 __________ 84,922 __________ __________ 935 754 578 Total volumes delivered to industrial and electric generation customers were 39 million therms, or 7 percent, higher in 2004 than in 2003, and utility operating revenues were up $37 million, or 50 percent. The higher volumes and revenues partially reflect an improving economy, but results primarily reflect a continued shift from transportation to sales volumes and the reclassification of a relatively large number of commercial customers to the indus- trial customer category over the past 24 months resulting from new N W N AT U R A L 23 Management’s Discussion and Analysis rate design changes in Oregon. Over the past two years, the num- ber of industrial customers increased 30 percent from 2002 to 2003, and 24 percent from 2003 to 2004. Industrial rates in Oregon were redesigned as part of the 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 improve the competitiveness of the Company’s rates in the industrial market. Total volumes delivered to industrial and electric generation cus- tomers were 18 million therms, or 3 percent, lower in 2003 than in 2002, and utility operating revenues were down $10 million, or 11 percent. Results from the industrial market in 2003 reflect weaker economic conditions during the year, and most of the incremental revenue decline was due to a shift from higher margin firm sched- ules to lower margin interruptible schedules and industrial rate de- creases effective in September 2003. The decline in volumes and operating revenues from the elec- tric generation market primarily reflect the winding down of a temporary market that emerged in response to the 2001-2002 en- ergy crisis. The volumes and operating revenues in 2002 were re- lated to two customers 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 revenues from these contracts were derived from fixed charges. A third electric generation customer used 3.0 million therms in 2002 under a contract with low volu- metric charges. Other Revenues Other revenues include miscellaneous fee income as well as revenue adjustments reflecting deferrals to, or amortizations from, regulatory asset or liability accounts other than deferrals relating to gas costs (see Note 1). Other revenues increased net operating revenues by $3.2 million in 2004, compared to $7.5 million in 2003 and $4.0 million in 2002. The following table summarizes other revenues by primary category for the three years ended Dec. 31, 2004, 2003 and 2002: Thousands 2004 2003 2002 Revenue adjustments: Current deferrals: Decoupling SMPE OPUC investigation Coos Bay Other Current amortizations: Interstate gas storage credits Decoupling SMPE Conservation programs Year 2000 technology costs Other Net revenue adjustments Miscellaneous revenues: Customer fees Other Total miscellaneous revenues Total other revenues $ 681 $ 1,475 (690) 244 35 3,466 $ 643 – – 82 1,720 – – – – 5,324 (2,952) (601) (2,835) (1,293) 298 __________ (314) __________ 3,057 (783) – (2,408) (949) 558 __________ 3,666 __________ 1,212 – – (2,074) (1,539) – __________ (681) __________ 3,245 254 __________ 3,499 __________ 3,185 $ $ __________ __________ 3,327 467 __________ 3,794 __________ 7,460 $ __________ __________ 3,115 1,584 __________ 4,699 __________ 4,018 __________ __________ Other revenues in 2004 were $4.3 million lower than in 2003 primarily due to the change in decoupling deferrals under the de- coupling mechanism (down $2.8 million) (see “Regulatory Mat- ters – Rate Mechanisms,” above), the amortization of decoupling deferrals from prior periods (up $2.2 million) and an increase in other miscellaneous amortizations (up $1.6 million), partially off- set by higher interstate storage credits from revenue sharing from the Company’s interstate gas storage services (up $2.3 million). Other revenues in 2003 included positive contributions due to the change in decoupling deferrals (up $1.7 million), the amortiza- 24 N W N AT U R A L tion of income shared with customers from interstate gas storage services (up $1.8 million), and customer late payment and collec- tion fees and miscellaneous revenues, partially offset by amortiza- tions from regulatory accounts covering conservation programs and Year 2000 technology costs. Cost of Gas Sold Natural gas commodity prices have fluctuated significantly in recent years. The effects of higher gas commodity prices and price volatility on core utility customers are mitigated through the use of underground storage facilities, gas commodity-price financial hedge contracts, and short-term sales of gas commodity and trans- portation capacity to on-system or off-system customers in periods when core utility customers do not require the full firm pipeline capacity and gas supplies. The Company regularly renews or replaces its expiring long- term and medium-term contracts with new agreements with a va- riety of existing and new suppliers. No single contract amounts to more than 200,000 therms per day or 10 percent of the Company’s average daily contract volumes. Firm year-round supply contracts have terms ranging from one to ten years. All of the contracts use price formulas tied to monthly index prices, primarily at the NOVA Inventory Transfer trading point in Alberta. NW Natural hedges a majority of its contracts each year using financial instruments as part of its gas purchase strategy. The total cost of gas sold was $399.2 million in 2004, an in- crease of $76.1 million or 24 percent compared to 2003 and, 2003 was $29.9 million or 8 percent lower than 2002. The cost per therm of gas sold was 14 percent higher in 2004 than in 2003 and 9 per- cent lower in 2003 than in 2002. The cost per therm of gas sold in- cludes 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 equaliza- tion), regulatory deferrals and company use. Results for 2002 in- cluded an adjustment that reduced cost of gas by $29.5 million, a result of a refund to customers. Excluding this adjustment, cost per therm of gas sold was 16 percent lower in 2003 than in 2002, re- flecting decreases in gas commodity prices effective in late 2002. Results for 2002 also included adjustments reducing cost of gas relating to amounts of deferred expenses for the recovery of pipe- line demand charges under the 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 methodol- ogy represented 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 0.51 percent of gas sendout in 2004, compared to 0.55 percent in 2003 and 0.75 percent in 2002. Unaccounted-for gas is the difference be- tween 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 customers or other delivery points. Unaccounted-for gas may be caused in part by physical gas leak- age, but it also may be due to cumulative inaccuracies in gas me- tering, estimates of unbilled gas or other causes. A normal amount of unaccounted-for gas is considered to be 0.50 percent of total gas sendout during a period, but the amounts may vary within a range around this estimate. During 2004, the lower estimated amount of unaccounted-for gas had the effect of increasing cost of gas and decreasing margin by $0.4 million as compared to 2003. 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. The estimated percentages of unaccounted- for gas in 2004 and 2003 were lower than 2002, partially due to improvements in gas measurement and estimating.  NW Natural uses a natural gas commodity-price hedge program under the terms of its Derivatives Policy to help manage its vari- able price gas commodity contracts (see “Application of Critical Accounting Policies and Estimates – Accounting for Derivative In- struments and Hedging Activities,” above). NW Natural recorded net hedging gains of $42.4 million from this program during 2004, compared to net hedging gains of $32.4 million in 2003 and net hedging losses of $75.5 million in 2002. Hedging gains and losses relating to gas commodity purchases are included in cost of gas and factored into NW Natural’s annual PGA rate changes, and therefore have no material impact on net income. Under NW Natural’s PGA tariff in Oregon, net income is affected within defined limits by changes in purchased gas costs. NW Nat- ural 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 cus- tomers in future rates. In 2004 and 2003, NW Natural’s gas costs 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 $0.6 million and $0.3 million, equivalent to 1 cent a share and less than 1 cent a share of earnings, respectively. In 2002, NW Nat- ural’s gas costs were much lower than the projected costs built into rates and the Company’s share of the savings realized from gas purchases contributed $10.8 million of margin, equivalent to 26 cents a share of earnings. NW Natural uses gas supplies and transportation capacity that are not required for core utility residential, commercial and indus- trial firm customers to make off-system sales. Under the PGA tariff in Oregon, NW Natural retains 33 percent of the margins realized from its off-system gas sales and records the remaining 67 percent as a deferred regulatory asset or liability for recovery from or re- fund to customers in future rates. NW Natural’s share of margin from off-system gas sales in 2004 resulted in a loss of $0.3 million, equivalent to less than 1 cent a share. NW Natural’s share of mar- gin from off-system gas sales in 2003 was $4.9 million, equivalent to 11 cents a share of earnings. Results for 2003 reflected a higher volume of off-system gas sales because of warmer weather in the first quarter and higher gas prices. NW Natural was able to use gas supplies that were available under contract for the winter season, but not required for delivery to core utility market customers, to make these off-system sales. NW Natural’s purchase price for this gas had been fixed through commodity swap and call option con- tracts entered into earlier at levels substantially below the market prices in 2003. NW Natural’s share of margin from off-system sales in 2002 was $0.9 million or 2 cents a share. Business Segments Other than Local Gas Distribution Interstate Gas Storage NW Natural earned net income from its non-utility interstate gas storage business segment in 2004, after regulatory sharing and in- come taxes, of $2.9 million or 11 cents a share, compared to $4.3 million or 17 cents a share in 2003 and $3.6 million or 14 cents a share in 2002 (see Note 2). Earnings from this business segment were lower in 2004 primarily due to a lower contribution from a contract with an independent energy marketing company that op- timizes the value of NW Natural’s assets by engaging in trading ac- tivities using temporarily unused portions of its upstream pipeline transportation capacity and gas storage capacity. The lower contri- bution was primarily due to a change in market conditions in which gas price differentials were less volatile in 2004 compared to 2003. In Oregon, NW Natural retains 80 percent of the pre-tax income from the interstate storage services and optimization of storage and pipeline transportation capacity when the costs of such capacity have not been included in core utility rates, and 33 percent of the pre-tax income from such optimization when the capacity 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. NW Natural has a similar sharing mechanism in Washington for revenue derived from third party optimization services. Subsidiaries Financial Corporation Financial Corporation’s operating results in 2004 were net in- come of $0.2 million, compared to $0.7 million in 2003 and $1.2 million in 2002. The decrease in net income in 2004 compared to 2003 was primarily due to a $0.5 million write-down of its limited partnership interests in three solar electric generation projects. The write-down related to an agreement to sell these projects on Jan. 31, 2005. The decrease in net income in 2003 compared to 2002 was due to lower income from investments in limited partnerships in wind and solar electric generation projects in California. The Company’s investment in Financial Corporation was $5.7 million at Dec. 31, 2004, compared to $5.5 million at Dec. 31, 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 corporate development activities in 2004. 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 in- curred in connection with this effort. These charges were equiva- lent to 33 cents a share. Northwest Energy was inactive during both 2004 and 2003. Operating Expenses Operations and Maintenance Operations and maintenance expenses increased $5.7 million, or 6 percent, in 2004 compared to 2003, and increased $11.3 mil- lion, or 13 percent, in 2003 compared to 2002. The following sum- marizes the major factors that contributed to changes in operations and maintenance expense: 2004 compared to 2003 ■ payroll and payroll-related expenses, including pension and health care costs, increased by $3.5 million due to salary and wage increases averaging 3 to 4 percent; and a change in the pension discount rate assumption and rising health care premi- ums (see Note 7); ■ expenses for compliance activities relating to the Sarbanes- Oxley Act of 2002 increased by $1.5 million; ■ uncollectible accounts expense increased by $1.3 million due to increases in gross revenues stemming from higher rates; ■ gas technology research costs increased by $0.3 million; ■ workers compensation expense decreased by $0.4 million; and ■ energy efficiency rebate costs decreased by $0.8 million. 2003 compared to 2002 ■ payroll and payroll-related expenses including pension and health care costs, increased by $8.9 million due to salary, wage and bonus increases, increased vacation accruals and increased pension costs due to a change in the pension discount rate as- sumption and pension fund losses in 2001 and 2002 (see Note 7); N W N AT U R A L 25 Management’s Discussion and Analysis ■ business risk insurance and workers compensation insurance premiums increased by $1.2 million; ■ professional service fees and contract labor increased by $1.2 million; ■ workers compensation claims expense increased by $0.5 mil- lion primarily due to a single claim incurred in 2003; ■ other operating costs increased $0.4 million; and ■ uncollectible accounts expense decreased by $0.9 million due to improvements in collection rates and lower net write-offs of accounts receivable. Most of the cost increases NW Natural experienced in 2004 and 2003 were included in the rate increases approved in the Compa- ny’s general rate cases in Oregon and Washington (see “Regulatory Matters – General Rate Cases,” above). Taxes Other Than Income Taxes Taxes other than income taxes, which are principally comprised of property, franchise and payroll taxes, increased $3.7 million, or 11 percent, in 2004 compared to 2003, and increased $1.0 million, or 3 percent, in 2003 compared to 2002. The following table sum- marizes the changes in taxes other than income taxes: Thousands Franchise taxes Payroll taxes Property taxes Other taxes Total increase –––– Increase (Decrease) –––– 2003 2004 $ 2,215 $ 1,078 732 (342) __________ 3,683 $ __________ __________ (92) 232 930 (21) __________ 1,049 __________ __________ $ The increase in franchise taxes in 2004 is primarily related to the increase in total utility operating revenues resulting from higher gas rates (see “Comparison of Gas Distribution Operations,” above); the increase in payroll taxes is primarily related to the increase in payroll expense (see “Operations and Maintenance,” above); and the increase in property taxes is primarily related to increased util- ity plant in service (see Note 9). 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, 2004: Thousands 2004 2003 2002 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 Weighted average depreciation rate – utility Weighted average depreciation rate – non-utility $ 1,771,890 $ 1,595,759 $ 1,498,903 23,082 __________ 1,794,972 __________ 61,830 __________ 1,657,589 __________ 41,062 __________ 1,539,965 __________ 29,628 22,353 20,832 – 1,042 4,335 __________ __________ __________ 23,395 33,963 20,832 __________ __________ __________ $ 1,828,935 $ 1,680,984 $ 1,560,797 __________ __________ __________ __________ __________ __________ $ 56,899 $ 472 __________ 53,798 $ 451 __________ 51,693 397 __________ $ __________ __________ 57,371 $ __________ __________ 54,249 $ 52,090 __________ __________ 3.4% 2.3% 3.5% 2.3% 3.5% 1.9% The Company’s total depreciation and amortization expense in- creased by $3.1 million, or 6 percent, in 2004 and by $2.2 million, or 4 percent, in 2003. The increased expense for both years is pri- marily due to additional investments in utility property that were made to meet continuing customer growth, including the Compa- ny’s investment in the SMPE that was put into service in Novem- ber 2003 and September 2004 (see “Financial Condition – Cash 26 N W N AT U R A L Flows – Investing Activities,” below). Other Income (Expense) Other income (expense) improved by $0.7 million in 2004. The increase was primarily due to reductions in interest charges on de- ferred regulatory account balances ($1.1 million) reflecting lower net credit balances outstanding in these accounts. This increase was partially offset by a decrease in gains from Company-owned life insurance ($0.6 million) due to decreases in the market value of equity-based life insurance investments. Other income (expense) improved by $17.0 million in 2003, pri- marily due to the $13.9 million pre-tax charge in 2002 for costs in- curred in the effort to acquire PGE. Excluding this charge, 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 lower net credit balances outstanding in these accounts, and an increase in gains from Company-owned life insurance ($2.0 million) due to increases in the market value of equity-based life insurance invest- ments, partially offset by a decrease in earnings from equity invest- ments ($0.5 million) due to lower income from partnership invest- ments held by Financial Corporation. Interest Charges – Net of Amounts Capitalized Interest charges–net of amounts capitalized in 2004 was $0.7 million, or 2 percent, higher than in 2003. The increase in 2004 was primarily due to higher balances of debt outstanding during the period. The increase was partially offset by lower average in- terest rates and higher amounts of Allowance for Funds Used Dur- ing Construction (AFUDC) due to higher average balances of con- struction work in progress (CWIP). AFUDC represents the cost of funds used for CWIP (see Note 1). In 2004, AFUDC reduced inter- est expense by $1.0 million compared to reductions of $0.9 million in 2003 and $0.6 million in 2002. The average interest rate compo- nent of AFUDC, comprised of short-term and long-term borrowing rates, as appropriate, was 3.0 percent in 2004, 2.3 percent in 2003 and 2.8 percent in 2002. Interest charges–net of amounts capitalized in 2003 was $1.0 million, or 3 percent, higher than in 2002, also due to higher bal- ances of debt outstanding and to the inclusion of dividends paid in the second half of 2003 totaling $0.2 million on the Company’s redeemable preferred stock, due to their classification as interest expense upon the adoption of SFAS No. 150, “Accounting for Cer- tain Financial Instruments with Characteristics of both Liabilities and Equity.” Income Taxes The effective corporate income tax rates were 34.4 percent, 33.7 percent and 34.9 percent for the years ended Dec. 31, 2004, 2003 and 2002, respectively. The higher rate in 2004 reflects the effect of decreased tax benefits from a non-taxable gain on Company- and trust-owned life insurance ($0.6 million), decreased tax benefits attributed to tax adjustments recorded in the prior year ($0.3 mil- lion), decreased tax benefits resulting from a taxable gain on the surrender of certain Company-owned life insurance ($0.1 million) and the expiration of a federal low-income housing tax credit ($0.1 million), partially offset by the effect of increased tax benefits from an adjustment of the Company’s deferred income tax balances ($0.5 million). Excluding the impact of these tax benefits taken into account during 2004, the effective tax rate for 2004 would have been 35.0 percent. 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 benefits from the $13.9 million charge for PGE transaction costs. Excluding this charge, the effective tax rate for 2002 would have been 35.6 percent. Redeemable Preferred and Preference Stock Dividend Requirements Redeemable preferred and preference stock dividend require- ments decreased $0.3 million in 2004 compared to 2003 due to the redemption in November 2003 of all outstanding shares of the Company’s $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 percent. No shares of redeemable preferred or preference stock were outstanding at any time dur- ing 2004. Redeemable preferred and preference stock dividend require- ments decreased $2.0 million in 2003 compared to 2002 due to the redemption in December 2002 of all of the outstanding shares ($25 million aggregate stated value) of the Company’s $6.95 Series of Redeemable Preference Stock pursuant to the mandatory redemp- tion provisions applicable to that Series. FINANCIAL CONDITION Capital Structure The Company’s goal is to maintain a target capital structure comprised of 45 to 50 percent common stock equity and 50 to 55 percent long-term and short-term debt. When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources also are used to meet long-term debt redemption requirements and short-term commercial paper maturities (see “Liquidity and Capi- tal Resources,” below, and Notes 3 and 5). The Company’s con- solidated capital structure at Dec. 31 was as follows: 2004 Year ended December 31, 2003 Common stock equity Long-term debt Short-term debt, including current maturities of long-term debt Total 48.7% 41.3% 46.4% 45.8% 10.0% __________ 100.0% __________ __________ 7.8% __________ 100.0% __________ __________ Achieving the target capital structure and maintaining sufficient liquidity are necessary to maintain attractive credit ratings and have access to capital markets at reasonable costs. Liquidity and Capital Resources At Dec. 31, 2004, the Company had $5.2 million in cash and cash equivalents compared to $4.7 million at Dec. 31, 2003. Short- term liquidity is provided by cash from operations and from the sale of commercial paper notes, which are supported b y commit- ted bank lines of credit. The Company has available through Sept. 30, 2005 committed lines of credit totaling $150 million with four commercial banks (see “Lines of Credit,” below, and Note 6). Short-term debt balances typically are reduced toward the end of the winter heating season as a significant amount of the Company’s current assets, including accounts receivable and natural gas in- ventories, are converted into cash. Capital expenditures primarily relate to utility construction re- sulting from customer growth and system improvements (see “Cash Flows – Investing Activities,” below). Certain contractual commit- ments under capital leases, operating leases and gas supply pur- chase and other contracts 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 refinanced through the sale of long-term debt or equity securities. To provide long-term financing, in February 2004 the Company filed a universal shelf registration with the Securities and Exchange Commission (SEC) providing for the issuance and sale of up to $200 million of securities, which may consist of secured debt (First Mortgage Bonds), unsecured debt, preferred stock or common stock. Concurrent with this shelf filing, the Company deregistered the $60 million of Medium-Term Notes (MTNs) remaining on its previous shelf registration. The $200 million universal shelf regis- tration statement became effective in February 2004. In April 2004, the Company issued $40 million of common stock under the shelf registration, leaving $160 million available for the issuance of debt or equity securities (see “Financing Activities,” below). Neither NW Natural’s Mortgage and Deed of Trust nor the in- dentures under which other long-term debt is issued contain credit rating triggers or stock price provisions that require the acceleration of debt repayment. Also, there are no rating triggers or stock price provisions contained in contracts or other agreements with third parties, except for agreements with certain counter-parties under NW Natural’s Derivatives Policy which require the affected party to provide substitute collateral such as cash, guaranty or letter of credit if credit ratings are lowered to non-investment grade, or in some cases if the mark-to-market value exceeds a certain threshold. Based on the availability of short-term credit facilities and the ability to issue long-term debt and equity securities, the Company believes it has sufficient liquidity to satisfy its anticipated cash re- quirements, including the contractual obligations and investing and financing activities discussed below. Dividend Policy NW Natural has paid quarterly dividends on its common stock in each year since the stock first was issued to the public in 1951. Annual common dividend payments have increased each year since 1956. The amount and timing of dividends payable on the Company’s common stock are within the sole discretion of the Company’s Board of Directors. It is the intention of the Board of Directors to continue to pay cash dividends on the Company’s com- mon stock on a quarterly basis. However, future dividends will be dependent upon NW Natural’s earnings, its financial condition and other factors. Off-Balance Sheet Arrangements The Company has no material off-balance sheet financing ar- rangements. Contractual Obligations 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 Contractual Obligations Commercial paper Long–term debt Interest on long–term debt Capital leases Operating leases Gas purchase contracts1 Gas pipeline commitments Other purchase commitments Total ---------------------------------------------------- Payments Due in Years Ending Dec. 31, ---------------------------------------------------- 2009 2008 2006 2005 2007 $ 102,500 15,000 33,213 230 4,491 277,371 62,988 12,162 __________ $ 507,955 __________ __________ $ – 8,000 32,561 189 4,136 184,572 57,800 147 __________ $ 287,405 __________ __________ $ – 29,500 31,085 97 3,967 167,093 58,981 – __________ $ 290,723 __________ __________ $ – 5,000 30,268 29 3,836 150,898 57,234 – __________ $ 247,265 __________ __________ $ – – 30,052 – 3,834 62,155 50,702 – __________ $ 146,743 __________ __________ Thereafter $ – 441,527 373,744 – 38,908 112,684 271,796 – __________ $ 1,238,659 __________ __________ Total $ 102,500 499,027 530,923 545 59,172 954,773 559,501 12,309 __________ $ 2,718,750 __________ __________ 1All gas purchase contracts use price formulas tied to monthly index prices. Commitment amounts are based on index prices at Dec. 31, 2004. N W N AT U R A L 27 Management’s Discussion and Analysis Other purchase commitments primarily consist of remaining balances under existing purchase orders and remaining payments due to a general contractor for the construction of the remaining portion of the SMPE project. These and other contractual obligations 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 long-term debt have put options that, if exer- cised, would accelerate the maturities by $10 million in 2005 and by $20 million in each of 2007, 2008 and 2009. The interest coupon rate on the long-term debt issues with put options range between 6.52 percent and 7.05 percent. On March 12, 2004, NW Natural employees who are members of the OPEIU, Local No. 11, approved a new labor agreement (Joint Accord) covering wages, benefits and working conditions that will expire on May 31, 2009. In accordance with the terms of the Joint Accord, beginning Jan. 1, 2005, the Company will commence mak- ing contributions to a multi-employer trust that will provide addi- tional retirement benefits to its bargaining unit employees. Commercial Paper The Company’s primary source of short-term funds is from the sale of commercial paper notes payable. In addition to issuing com- mercial paper to meet seasonal working capital requirements, in- cluding the financing of gas purchases and accounts receivable, short-term debt is also used temporarily to fund capital require- ments. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. NW Natural’s outstand- ing commercial paper, which is sold under an agency agreement with a commercial bank, is supported by committed bank lines of credit (see “Lines of Credit,” below). NW Natural had $102.5 mil- lion in commercial paper notes outstanding at Dec. 31, 2004, com- pared to $85.2 million outstanding at Dec. 31, 2003. Lines of Credit Effective Oct. 1, 2004, NW Natural entered into lines of credit with Bank of America, N.A., JP Morgan Chase Bank, U.S. Bank National Association, and Wells Fargo Bank, totaling $150 million in aggregate. Half of the credit facility with each bank, or $75 mil- lion, is committed and available through Sept. 30, 2005, and the other $75 million is committed and available through Sept. 30, 2007. Bank of America, N.A., JP Morgan Chase Bank, and U.S. Bank Na- tional Association have each committed $20 million for each of their 2005 and 2007 lines of credit, and Wells Fargo Bank has com- mitted $15 million for each of its 2005 and 2007 lines of credit. Under the terms of these lines of credit, NW Natural pays com- mitment fees but is not required to maintain compensating bank balances. The interest rates on any outstanding borrowings under these lines of credit are based on current market rates. There were no outstanding balances on these lines of credit at Dec. 31, 2004 or 2003. 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 credit rating is not an event of default, nor is the maintenance of a specific 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 debt outstanding under these lines of credit, if any, when ratings 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, 2004, plus 50 percent of the Company’s 28 N W N AT U R A L net income for each subsequent fiscal quarter. NW Natural was in compliance with the covenants as of Dec. 31, 2004, with an indebt- edness to total capitalization ratio of 52 percent and a net worth of $568.5 million compared to a required $452.1 million. The Com- pany was also in compliance with these covenants under previous line of credit agreements in effect as of Dec. 31, 2003. Failure to comply with either of these covenants would entitle the banks to terminate their lending commitments and to accelerate the matu- rity of all amounts outstanding. Credit Ratings The table below summarizes NW Natural’s credit ratings from three rating agencies, Standard and Poor’s Rating Services (S&P), Moody’s Investor Service (Moody’s) and Fitch Ratings (Fitch). Rating Agency Moody’s Fitch S&P Commercial Paper (short-term debt) Senior Secured (long-term debt) Senior Unsecured (long-term debt) Ratings Outlook A-1 A+ A Stable P-1 A2 A3 Stable F1 A A- Stable In December 2004, NW Natural’s corporate credit rating was upgraded by S&P to “A+” from “A”, which also assigned NW Nat- ural a business profile score of “1” on a scale of “1” to “10”, where “1” is the strongest score. Each of the rating agencies has assigned NW Natural an investment grade rating. These credit ratings and business profile scores are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of these credit ratings is not a recommenda- tion to buy, sell or hold the Company’s securities. Each rating should be evaluated independently of any other rating. 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 quar- ter 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 Preferred 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 Year-over-year changes in the Company’s operating cash flows are primarily affected by net income and non-cash adjustments to net income. In 2004, net income and non-cash adjustments to net income increased by $18 million, but the cash flow increase was offset by increases in working capital requirements within the util- ity segment resulting from warmer weather, higher prices of natu- ral gas, and the timing of customer collections, payments for natu- ral gas purchases and deferred gas cost recoveries. In 2003, net income and non-cash adjustments to net income decreased by $18 million primarily due to a $13.9 million non-cash write-down of PGE acquisition costs.  The following table summarizes cash provided by operating ac- tivities for the years ended Dec. 31, 2004, 2003 and 2002: Thousands (year ended December 31) 2004 2003 2002 Net income Non-cash adjustments to net income Changes in operating assets and 4,228 liabilities (working capital sources) __________ Cash provided by operating activities $ 107,739 $ 108,193 $ 124,323 __________ __________ (12,049) __________ __________ __________ 6,375 __________ __________ __________ 50,572 $ 69,216 45,983 $ 55,835 43,792 76,303 $ The overall change in cash flow from operations was negligible in 2004 compared to 2003, but decreased by $16 million in 2003 compared to 2002. The significant factors contributing to the cash flow changes between years are as follows: 2004 compared to 2003 ■ an increase in net income added $4.6 million to cash flow; ■ an increase in deferred tax expense added $23.0 million to cash flow, reflecting higher tax benefits from accelerated bonus depreciation on large capital additions that were placed into ser- vice in 2004; ■ an increase in inventories reduced cash flow by $22.8 million, primarily reflecting higher volumes and higher unit prices on gas inventories in storage facilities (see “Results of Operations – Comparison of Gas Operations,” above); ■ an increase in regulatory receivables for deferred gas costs reduced cash flow by $10.2 million, reflecting different patterns of activity between the two years with respect to purchased gas cost savings and off-system gas sales under NW Natural’s PGA tariff (see “Results of Operations – Comparison of Gas Operations – Cost of Gas Sold,” above); ■ an increase in accounts receivable also reduced cash flows by $8.1 million, reflecting the impact of higher rates compared to the prior year (see “Results of Operations – Regulatory Mat- ters,” above); ■ cash contributions to the Company’s non-bargaining unit de- fined benefit pension plan lowered cash flows by $8.3 million, compared to no contributions in 2003 or 2002 (see “Pension Cost (Income) and Funding Status,” below); ■ a smaller increase in accrued unbilled revenue added $9.7 million to cash flow, reflecting higher gas prices, partially offset by lower unbilled volumes because of warmer weather and decreases in customer usage because of higher prices; ■ an increase in other long term liabilities added $8.2 million to cash flow, reflecting an increase in accruals for environmental and other claims, as well as increases in accruals for unfunded liabilities for pension and post-retirement benefits; ■ an increase in income taxes receivable reduced cash flow by $7.3 million; and ■ a decrease in prepayments and other current assets increased cash flow by $3.5 million. 2003 compared to 2002 ■ an increase in net income added $2.2 million to cash flow; ■ a non-cash adjustment to net income in 2002 for the loss recorded for PGE costs resulted in a net decrease in 2003 of $13.9 million; ■ a significant increase in accrued unbilled revenue reduced cash flow by $28.7 million, reflecting a combination of higher gas prices and colder weather in December 2003 compared to December 2002; ■ a significant increase in accounts receivable reduced cash flow by $22.9 million, primarily reflecting the higher gas prices and the timing of customer account collections; ■ a decrease in deferred gas costs payable reduced cash flow by $5.6 million, largely due to a significant refund to customers in 2002 of accumulated gas cost savings; ■ a decrease in accrued interest and taxes payable added $16.4 million to cash flow, primarily reflecting higher tax benefits from accelerated bonus depreciation; ■ a decrease in inventories of gas, materials and supplies added $15.9 million to cash flow, primarily due to lower volumes of natural gas in storage, partially offset by higher gas commodity prices; ■ a decrease in prepaid income taxes added $9.5 million to cash flow; and ■ an increase in accounts payable added $7.9 million to cash flow. The Company has lease and purchase commitments relating to its operating activities that are financed with cash flows from operations (see “Liquidity and Capital Resources,” above, and Note 12). The Job Creation and Worker Assistance Act of 2002 (the As- sistance Act) combined with the Jobs and Growth Tax Relief Rec- onciliation Act of 2003 (the Reconciliation Act), allowed for an ad- ditional first-year tax depreciation deduction on the adjusted basis of “qualified property.” The Assistance Act provided for an addi- tional depreciation deduction equal to 30 percent of an asset’s ad- justed basis. The Reconciliation Act increased this first-year addi- tional depreciation deduction to 50 percent of an asset’s adjusted basis. The additional first-year depreciation deduction is an accel- eration of depreciation deductions that otherwise would have been taken in the later years of an asset’s recovery period. The acceler- ated depreciation provisions provided by both the Assistance Act and the Reconciliation Act expired at Dec. 31, 2004. The Company realized enhanced cash flow from reduced income taxes totaling an estimated $55 million during the effective period, based on plant investments made between Sept. 11, 2001 and Dec. 31, 2004. Investing Activities Cash requirements for investing activities in 2004 totaled $136 million, up from $128 million in the same period of 2003. Cash re- quirements for the acquisition and construction of utility plant to- taled $141 million, up from $125 million in 2003. The increase in cash requirements for utility construction in 2004 was primarily the result of higher capital expenditures relating to NW Natural’s SMPE project to extend the pipeline from its Mist gas storage field to serve growing portions of its service area ($22 million). The SMPE was completed and placed into service in September 2004. The total cost of the project was approximately $110 million, which includes amounts reflected in investing activities over the past few years. The cost of service associated with the SMPE project, net of deferred tax benefits, was included in customer rates starting in the fourth quarter of 2004. Cash requirements for investing activities in 2003 totaled $128 million, up from $85 million in 2002. Cash requirements for the acquisition and construction of utility plant totaled $125 million, up from $80 million in 2002. The increase in cash requirements for utility construction in 2003 was primarily the result of higher capital expenditures relating to the SMPE project ($27 million), higher system improvements and support ($12 million) and other special projects to serve new customer load or new service areas ($9 million). Investments in the Company’s pipeline integrity management program (IMP) were $1.6 million in 2004, compared to $0.9 mil- lion in 2003. IMP costs are estimated at approximately $50 million to $100 million over a ten-year period (see discussion below). IMP costs are classified as either capital expenditures or regulatory as- sets. The costs are accumulated over each 12-month period ending June 30, and the costs, subject to audit, are recovered through rate changes effective on Oct. 1 of each year commencing Oct. 1, 2004. The approved accounting and rate treatment for these costs extends through Sept. 30, 2008, and it may be reviewed for potential exten- sion after that date. N W N AT U R A L 29 Management’s Discussion and Analysis Investments in non-utility property totaled $10.6 million in 2004, compared to $2.6 million in 2003. The higher investments in 2004 compared to 2003 were primarily for certain improvements to the Company’s gas pipeline system that were related to interstate gas storage services. In December 2004, the Company received proceeds from the sur- render of certain life insurance policies and proceeds from the set- tlement of life insurance benefits totaling $17.6 million. During the five-year period 2005 through 2009, 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 high customer growth and system improvement projects resulting in part from requirements under the Pipeline Safety Improvement Act of 2002 (Pipeline Safety Act) (see below). A majority of the required funds is expected to be internally gener- ated over the five-year period; the remainder 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 and non-utility capital expenditures in 2005 are estimated to total $110 million, including $28 million for cus- tomer growth, $21 million for system improvement and support, $15 million for equipment, facilities and information technology, $10 million for IMP costs, $6 million for the SMPE and related gas storage projects, $9 million for utility and non-utility storage and $21 million for construction overhead. In December 2003, the U.S. Department of Transportation’s Office of Pipeline Safety issued a rule that specifies the detailed re- quirements for transmission pipeline IMPs as mandated by the Pipeline Safety Act. The Pipeline Safety Act requires operators of gas transmission pipelines to identify lines located in High Conse- quence 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 leg- islation requires NW Natural to inspect the 50 percent highest risk pipelines located in its HCAs within the first five years, and to in- spect the remaining covered pipelines within 10 years of the date of the enactment. The Pipeline Safety Act also requires re-inspec- tions of the covered pipelines every seven years from the date of the previous inspection for the life of the pipelines. Financing Activities Cash provided by financing activities in 2004 totaled $29 mil- lion, compared to $17 million in 2003. Factors contributing to the $12 million increase were the net proceeds ($38.5 million) from a common stock offering in April 2004 (see below), combined with last year’s redemption of the $7.125 Series of Preferred Stock ($8.4 million), offset by last year’s increase in long-term debt balances ($35.0 million). Cash provided by financing activities in 2003 totaled $17 mil- lion, 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 mil- lion in 2003 compared to $40.5 million in 2002) and the redemp- tion, including the annual sinking fund, of the $7.125 Series of Preferred Stock in 2003 ($8.4 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), to provide cash for investments in utility plant and to re- duce short-term borrowings. In April 2004, the Company issued and sold 1,290,000 shares of its common stock in an underwritten public offering, and used 30 N W N AT U R A L the net proceeds of $38.5 million from the offering to reduce short- term indebtedness by about $29 million and to fund, in part, NW Natural’s utility construction program. The offering of com- mon stock was made pursuant to NW Natural’s universal shelf registration statement providing for the registration of $200 million of securities, which became effective in February 2004. After the common stock offering, approximately $160 million remains avail- able under the shelf registration statement for the Company to is- sue additional securities, which may include First Mortgage Bonds and unsecured debt. In 2000, NW Natural commenced a program to repurchase up to 2 million shares, or up to $35 million in value, of its com- mon stock through a repurchase program that has been extended through May 2005. The purchases are made in the open market or through privately negotiated transactions. No shares were repur- chased in 2003 or in 2004. 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 (NPPC) is determined in accordance with SFAS No. 87, “Employers’ Accounting for Pensions” (see “Ap- plication of Critical Accounting Policies – Accounting for Pensions,” above). The annual pension cost or income is allocated between operations and maintenance expense and construction overhead. NPPC for the Company’s two qualified defined benefit plans to- taled $6.6 million in 2004, an increase of $0.4 million over NPPC for these plans of $6.2 million in 2003. The increased NPPC was primarily due to the use of a lower discount rate (6.25 percent in 2004 compared to 6.75 percent in 2003) which had the effect of increasing the two plans’ accumulated benefit obligations. During 2004, the Company contributed $5.3 million to its Retire- ment Plan for Non-Bargaining Unit Employees (NBU Plan) for plan year 2004, of which $1.0 million represented the minimum re- quired funding. The Company was not required to make any con- tribution to its Retirement Plan for Bargaining Unit Employees (BU Plan) for that year. The Company’s funding policy is to contribute at least the minimum amount required by the Employee Retirement Income Security Act of 1974, as amended. For accounting expense recognition, the Company uses an asset valuation (market-related valuation) method that spreads variances between expected re- turns and actual investment returns over a three-year period, but for funding purposes the Company spreads these differences over a five-year period. In 2004, the Company made additional tax-de- ductible contributions to improve the funded status of its qualified pension plans. In 2005, no contributions are required to be made to fund either the NBU Plan or the BU Plan, and the Company does not anticipate making any additional voluntary contributions for the 2004 plan year. The fair market value of the two plans’ assets increased to $186.8 million at Dec. 31, 2004, up from $168.3 million at Dec. 31, 2003. The increase included $22.5 million in investment gains and employer contributions of $8.3 million, which were offset in part by $11.2 million in withdrawals to pay benefits and $1.1 million in eligible expenses of the two plans. The present value of benefit obligations under the two plans increased from an estimated $192 million to $209 million during 2004, however, so the two plans re- mained under-funded in aggregate by about $22 million at Dec. 31, 2004. NPPC for the NBU Plan and the BU Plan was $6.2 million in 2003, compared to net periodic pension income of $0.1 million in 2002. The increased NPPC in 2003 was largely due to investment losses in 2002, which are recognized over a three-year period, and to the use of a lower discount rate (6.75 percent in 2003 compared to 7.25 percent in 2002) which increased the plans’ accumulated benefit obligations. During 2004, the Company made a cash con- tribution of $2.9 million to the NBU Plan for the 2003 plan year, of which $1.9 million represented the minimum required funding. No contributions were required to be made to either the NBU Plan or the BU Plan for the 2002 plan year. At Dec. 31, 2003, the fair market value of the assets of the NBU Plan and the BU Plan totaled $168.3 million, up from $143.2 mil- lion at Dec. 31, 2002. The increased market value included $36 mil- lion in investment gains, which was partially offset by $10 million in withdrawals to pay benefits and $0.9 million in eligible expenses of the plans. At Dec. 31, 2003, the present value of benefit obligations under the two plans totaled $192 million and thus were under- funded in aggregate by about $24 million. Despite the increase in NPPC and the current under-funded sta- tus of the NBU Plan, NW Natural believes it will be able to main- tain well-funded qualified pension plans. NW Natural does not expect its current or future cash contribution requirements to the two plans to have a material adverse effect on its liquidity or finan- cial condition (see Note 7). Ratios of Earnings to Fixed Charges For the years ended Dec. 31, 2004, 2003 and 2002, the Compa- ny’s ratios of earnings to fixed charges, computed using the Secu- rities and Exchange Commission method, were 3.02, 2.84 and 2.85, respectively. For this purpose, earnings consist of net income be- fore taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, the amortization of debt expense and discount or premium and the estimated interest portion of rentals charged to income. 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 that appropri- ate investigation or remediation is being undertaken at all the rel- evant sites. Based on existing knowledge, the Company does not expect that the ultimate resolution of these matters will have a ma- terial adverse effect on its financial condition, results of operations or cash flows (see Note 12). In May 2003, the OPUC approved NW Natural’s request for de- ferral of environmental costs associated with specific sites. The authorization, which has been extended through April 2005, allows NW Natural to defer and seek recovery of unreimbursed environ- mental costs in a future general rate case. NW Natural has filed a request with the OPUC to extend this authority through January 2006. On a cumulative basis through Dec. 31, 2004, the Company paid out a total of $3.3 million relating to the sites since the effec- tive date of the deferral authorization (see Note 12). NW Natural will first seek to recover the costs of investigation and remediation for which it may be responsible with respect to environmental matters, if any, from insurance. If these costs are not recovered from insurance, then NW Natural will seek recovery through future rates subject to approval by the OPUC. At Dec. 31, 2004, NW Natural had an $8.5 million receivable representing an estimate of the environmental costs it expects to incur and recover from insurance (see Note 12). QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to various forms of market risk includ- ing commodity supply risk, weather risk, and interest rate risk. The following describes the Company’s exposure to these risks. Commodity Supply Risk NW Natural enters into short-term, medium-term and long-term natural gas supply contracts, along with associated short-, medium- and long-term transportation capacity contracts. Historically, NW Natural has taken physical delivery of at least the minimum quan- tities specified in its natural gas supply contracts. These contracts are primarily index-based and subject to annual re-pricing, a pro- cess that is intended to reflect anticipated market price trends dur- ing the next year. NW Natural’s PGA mechanism in Oregon and Washington provides for the recovery from customers of actual commodity costs, except that, for Oregon customers, NW Natural absorbs 33 percent of the higher cost of gas sold, or retains 33 per- cent of the lower cost, in either case as compared to the annual PGA price built into customer rates. To the degree that market risks exist due to potential adverse changes in commodity prices, foreign exchange rates or counter- party credit quality in relation to these financial and physical con- tracts, 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-price swap and call option contracts (fi- nancial hedge contracts) are used to convert certain natural gas supply contracts from floating prices to fixed prices. These finan- cial hedge contracts are included in the Company’s annual PGA filing, subject to a prudency review. At Dec. 31, 2004 and 2003, no- tional amounts under these commodity swap and call option con- tracts totaled $413.0 million and $304.1 million, respectively. At Dec. 31, 2004, five of these financial hedge contracts extended be- yond Dec. 31, 2005. If all of the commodity-price swap and call op- tion contracts had been settled on Dec. 31, 2004, a regulatory gain of $10.5 million would have been realized (see Note 11). Foreign Currency Risk The costs of natural gas commodity and certain pipeline ser- vices purchased from Canadian suppliers are subject to changes in the value of the Canadian currency in relation to the U.S. currency. Foreign currency forward contracts are used to hedge against fluc- tuations in exchange rates with respect to the purchases of natural gas from Canadian suppliers. At Dec. 31, 2004 and 2003, notional amounts under foreign currency forward contracts totaled $14.5 million and $6.4 million, respectively. As of Dec. 31, 2004, no for- eign currency forward contracts extended beyond Dec. 31, 2005. If all of the foreign currency forward contracts had been settled on Dec. 31, 2004, a gain of $0.4 million would have been realized (see Note 11). Counterparty Credit Risk Certain suppliers that sell gas to NW Natural have either rela- tively low credit ratings or are not rated by major credit rating agen- cies. To manage this supply risk, the Company purchases gas from a number of different suppliers, with no single supplier accounting for more than 20 percent of the Company’s total purchases for a given monthly period. The Company also evaluates suppliers’ cred- itworthiness and maintains the ability to require additional financial assurances, including deposits, letters of credit, or surety bonds in case a supplier defaults. In the event of a supplier’s failure to deliver contracted volumes of gas, the regulated utility would need to re- place those volumes at prevailing market prices, which may be higher or lower than the original transaction prices. These costs would be subject to the PGA sharing mechanism discussed above. Since most of the Company’s commodity supply contracts are priced at the monthly market index price, and the Company has significant storage flexibility, it is unlikely that a supplier default would have a materially adverse impact on the Company’s financial condition. N W N AT U R A L 31 Management’s Discussion and Analysis With respect to the financial counterparties the Company uses for entering into commodity price hedge contracts, NW Natural’s Derivatives Policy requires each counterparty to be at least two rat- ing grades above non-investment grade. Because counterparty rat- ings are subject to change at any time, the Company could have contracts outstanding with counterparties whose ratings are non- investment grade. NW Natural’s counterparty credit exposure as of Dec. 31, 2004 was as follows: Thousands Credit Exposure Investment grade counterparties Non-investment grade counterparties Total $ 15,957 – __________ 15,957 __________ __________ $ Due to the volatility of natural gas commodity prices, the mar- ket value and credit exposure of certain derivative contracts could exceed the Company’s credit limits established in its Derivatives Policy. If such credit limits were exceeded, the Company would have the ability to require collateral from the counterparty and would not enter into any further contracts with that counterparty until it was within the limits. If a counterparty failed to perform under its contract, NW Natural could sustain a loss which would be included in the annual PGA adjustment, subject to a regulatory prudency review. Under certain circumstances, a counterparty de- fault could result in a material loss. However, based on the Com- pany’s current regulatory mechanism, the absence of any signifi- cant position with a single counterparty and the strength of the counterparties’ current credit ratings, any such loss is not expected to have a material impact on the Company’s financial condition. Weather Risk The Company is exposed to weather risk primarily from its reg- ulated utility business. A large portion of the Company’s net oper- ating revenues (margin) is volume driven, and current rates are based on an assumption of normal weather. In 2003, the OPUC ap- proved a weather normalization mechanism for residential and commercial customers. This mechanism affects customer bills be- tween Nov. 15 through May 15 of each winter heating season, in- creasing or decreasing the margin 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 the utility’s fixed costs and reduce fluc- tuations in customers’ bills due to colder or warmer than average weather. Customers in Oregon are allowed to opt out of the weather normalization mechanism. As of Dec. 31, 2004, about 8 percent of the Company’s Oregon customers had opted out. In addition to the Oregon customers opting out, the Company’s Washington custom- ers are not covered by weather normalization. The combination of Oregon and Washington customers not covered by weather nor- malization mechanism is less than 20 percent of all residential and commercial customers. Interest Rate Risk The Company is exposed to interest-rate risk associated with new debt financing needed to fund capital requirements, including future contractual obligations and maturities of long-term and short-term debt. Interest rate risk is managed through the issuance of fixed-rate debt with varying maturities and, if permitted, the re- duction of debt through optional redemption when interest rates are favorable. At Dec. 31, 2004 and 2003, the Company had no vari- able-rate long-term debt and no derivative financial instruments to hedge interest rates. Holders of certain long-term debt have put op- tions that, if exercised, would accelerate maturities by $10 million in 2005 and by $20 million in each of 2007, 2008 and 2009. Management’s Report on Internal Control over Financial Reporting Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial re- porting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial state- ments for external purposes in accordance with generally accepted accounting principles in the United States of America (GAAP). The Company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions involving the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in ac- cordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and the Board of Directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of the unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projec- tions of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Management assessed the effectiveness of the Company’s internal control over financial reporting as of Dec. 31, 2004. In making this assessment, management used the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment and those criteria, management has concluded that the Company maintained effective internal control over financial reporting as of Dec. 31, 2004. Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of Dec. 31, 2004 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which ap- pears herein. Mark S. Dodson President and Chief Executive Officer 32 N W N AT U R A L David H. Anderson Senior Vice President and Chief Financial Officer Report of Independent Registered Public Accounting Firm To the Board of Directors and Shareholders of Northwest Natural Gas Company: We have completed an integrated audit of Northwest Natural Gas Company’s 2004 consolidated financial statements and of its in- ternal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in ac- cordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below. Consolidated financial statements In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of shareholders’ equity and comprehensive income, of cash flows and of capitalization present fairly, in all material respects, the financial position of Northwest Natural Gas Company (doing business as NW Natural) and its subsidiaries (“the Company”) at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements 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 statement presentation. We believe that our audits provide a reasonable basis for our opinion. Internal control over financial reporting Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting ap- pearing on page 32 of the 2004 Annual Report to Shareholders, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Fur- thermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of De- cember 31, 2004, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Company’s man- agement is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit pro- vides a reasonable basis for our opinions. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted account- ing principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the main- tenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accor- dance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accor- dance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the fi- nancial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projec- tions of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Portland, Oregon March 1, 2005 N W N AT U R A L 33 Consolidated Statements of Income Thousands, except per share amounts (year ended December 31) 2004 2003 2002 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. $ 707,604 399,244 __________ 308,360 $ 611,256 323,190 __________ 288,066 $ 641,376 353,832 __________ 287,544 102,155 38,808 57,371 __________ 198,334 __________ 110,026 2,828 35,751 __________ 77,103 26,531 __________ 50,572 – __________ 50,572 $ __________ __________ 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 $ __________ __________ 27,016 27,283 25,741 26,061 25,431 25,814 $ $ 1.87 1.86 $ $ 1.77 1.76 $ $ 1.63 1.62 34 N W N AT 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 2004 2003 $ 1,794,972 505,286 __________ 1,289,686 __________ 33,963 5,244 __________ 28,719 __________ 1,318,405 __________ $ 1,657,589 471,716 __________ 1,185,873 __________ 23,395 4,855 __________ 18,540 __________ 1,204,413 __________ 60,618 __________ 73,845 __________ Current assets: Cash and cash equivalents Accounts receivable, less allowance for uncollectible accounts of $2,434 in 2004 and $1,763 in 2003 Accrued unbilled revenue Inventories of gas, materials and supplies Income tax receivable Prepayments and other current assets Total current assets Regulatory assets: Income tax asset Deferred gas costs receivable Unamortized costs on debt redemptions Other Total regulatory assets Other assets: Fair value of non-trading derivatives Other Total other assets Total assets 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 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 Fair value of non-trading derivatives Other Total other liabilities Commitments and contingencies (see Note 12) Total capitalization and liabilities See Notes to Consolidated Financial Statements. 5,248 60,675 64,401 66,477 15,970 24,346 __________ 237,117 __________ 4,706 48,499 59,109 50,859 8,986 23, 675 __________ 195,834 __________ 64,734 9,551 7,332 3,321 __________ 84,938 __________ 63,449 – 7,803 6,020 __________ 77,272 __________ 16,399 14,718 __________ 31,117 __________ $ 1,732,195 __________ __________ 23,885 10,130 __________ 34,015 __________ $ 1,585,379 __________ __________ $ 87,231 300,034 183,932 (862) (1,818) __________ 568,517 484,027 __________ 1,052,544 __________ $ 82,137 255,871 170,053 (729) (1,016) __________ 506,316 500,319 __________ 1,006,635 __________ 102,500 102,478 15,000 10,242 2,897 34,168 __________ 267,285 __________ 85,200 86,029 – 8,605 2,998 31,589 __________ 214,421 __________ 153,258 1,529 – 10,912 __________ 165,699 __________ 135,638 1,564 5,627 23,885 __________ 166,714 __________ 210,715 6,025 5,487 24,440 __________ 246,667 __________ – __________ $ 1,732,195 __________ __________ 171,797 6,945 – 18,867 __________ 197,609 __________ – __________ $ 1,585,379 __________ __________ N W N AT U R A L 35 Consolidated Statements of Shareholders’ Equity and Comprehensive Income Thousands Balance at Dec. 31, 2001 Net Income Common Stock and Premium $ 320,586 – Earnings Invested in the Business Unearned Stock Compensation Accumulated Other Comprehensive Income (Loss) Total Shareholders’ Comprehensive Income Equity $ 147,950 43,792 $ (372) – $ (375) – $ 467,789 43,792 $ 43,792 Minimum pension liability adjustment – net of tax Change in unrealized loss from price risk management activities – net of tax Purchases of restricted stock Restricted stock amortizations Cash dividends paid: Redeemable preferred and – – – – preference stock Common stock Issuance of common stock Conversion of debentures Common stock expense Balance at Dec. 31, 2002 – – 6,533 1,932 – _________ 329,051 Net Income Minimum pension liability adjustment – net of tax Purchases of restricted stock Restricted stock amortizations Cash dividends paid: Redeemable preferred stock Common stock – – – – – – Tax benefits from employee stock option plan Issuance of common stock Conversion of debentures Common stock expense Balance at Dec. 31, 2003 401 7,930 626 – _________ 338,008 – – – – (2,579) (32,024) – – (3) _________ 157,136 45,983 – – – (392) (32,655) – – – (19) _________ 170,053 – (2,936) (2,936) (2,936) – (891) 552 227 – – 227 (891) 552 227 – – – – – _________ (711) – – – – – _________ (3,084) (2,579) (32,024) 6,533 1,932 (3) _________ 482,392 _________ $ 41,083 _________ _________ – – (328) 310 – – – 45,983 $ 45,983 2,068 2,068 – – 2,068 (328) 310 – – (392) (32,655) – – – – _________ (729) – – – – _________ (1,016) 401 7,930 626 (19) _________ 506,316 _________ $ 48,051 _________ _________ – 50,572 – (55) – – (51) – – (35,105) – – (431) 298 – 872 47,148 1,292 – _________ $ 387,265 _________ _________ – – – (1,537) _________ $ 183,932 _________ _________ – – – – _________ $ (862) _________ _________ – – – – _________ $ (1,818) _________ _________ – 50,572 $ 50,572 (802) – – (802) (537) 298 (35,105) 872 47,148 1,292 (1,537) _________ $ 568,517 _________ _________ (802) _________ $ 49,770 _________ _________ Net Income Minimum pension liability adjustment – net of tax Purchases of restricted stock Restricted stock amortizations Cash dividends paid: Common stock Tax benefits from employee stock option plan Issuance of common stock Conversion of debentures Common stock expense Balance at Dec. 31, 2004 See Notes to Consolidated Financial Statements. 36 N W N AT U R A L Consolidated Statements of Cash Flows Thousands (year ended December 31) 2004 2003 2002 Operating activities: Net income Adjustments to reconcile net income to cash provided by operations: Depreciation and amortization Loss for PGE acquisition costs Minimum pension liability adjustment Deferred income taxes and investment tax credits Undistributed earnings from equity investments Allowance for funds used during construction Deferred gas costs – net Contribution to Company-sponsored pension plan Other Changes in operating assets and liabilities: Accounts receivable – net of allowance for uncollectible accounts Accrued unbilled revenue Inventories of gas, materials and supplies Income tax receivable Prepayments and other current assets Accounts payable Accrued interest and taxes Other current and accrued 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 (investment in) life insurance – net Other investments Cash used in investing activities Financing activities: Common stock issued Restricted stock purchased Restricted stock amortization 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 Increase (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. $ 50,572 $ 45,983 $ 43,792 57,371 – (802) 36,713 (181) (1,690) (15,178) (8,261) 1,244 54,249 – 2,068 13,712 (474) (1,734) (5,008) – (6,978) 52,090 13,873 (2,936) 10,944 (988) (550) 546 – 3,324 (12,176) (5,292) (15,618) (6,984) 7,457 16,449 1,536 2,579 __________ 107,739 __________ (4,027) (15,040) 7,171 266 3,989 11,593 879 1,544 __________ 108,193 __________ 18,886 13,680 (8,693) (9,252) (307) 3,738 (15,473) 1,649 __________ 124,323 __________ (141,485) (10,568) – 17,575 (1,291) __________ (135,769) __________ (124,660) (2,563) – (1,387) 560 __________ (128,050) __________ (79,530) (2,629) (4,316) (496) 2,348 __________ (84,623) __________ 48,153 (537) 298 – – – 17,300 8,349 (328) 310 (8,428) 90,000 (55,000) 15,398 6,872 (891) 552 (25,750) 90,000 (40,500) (38,489) – (35,105) (1,537) __________ 28,572 __________ (392) (32,655) (19) __________ 17,235 __________ (2,579) (32,024) (3) __________ (42,812) __________ 542 4,706 __________ 5,248 $ __________ __________ (2,622) 7,328 __________ 4,706 $ __________ __________ (3,112) 10,440 __________ 7,328 $ __________ __________ $ $ 36,061 2,500 $ $ 35,210 13,940 $ $ 34,640 33,474 $ 1,292 $ 626 $ 1,932 N W N AT U R A L 37 Consolidated Statements of Capitalization Thousands, except share amounts (December 31) 2004 2003 $ 87,231 300,034 183,932 (862) (1,818) __________ 568,517 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 $ 82,137 255,871 170,053 (729) (1,016) __________ 506,316 54% 50% 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 4,527 __________ 499,027 15,000 __________ 484,027 __________ 5,819 __________ 500,319 – __________ 46% 50% 500,319 _____ __________ _____ $ 1,052,544 __________ __________ 100% $ 1,006,635 100% _____ __________ _____ _____ __________ _____ Common stock equity: Common stock – par value $3-1/6 per share, authorized 60,000,000 shares: outstanding – 2004, 27,546,720 shares; 2003, 25,938,002 shares Premium on common stock Earnings invested in the business Unearned compensation Accumulated other comprehensive income (loss) Total common stock equity Long-term debt: Medium-Term Notes First Mortgage Bonds: 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 7.720% 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. 38 N W N AT 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 the regulated parent company, Northwest Natural Gas Company (NW Natural), and its non-regulated wholly-owned subsidiaries: ■ 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 “Com- pany.” In this report, the term “utility” is used to describe the reg- ulated gas distribution business of the Company and the term “non-utility” is used to describe the interstate gas storage business and other non-regulated activities (see Note 2). Intercompany ac- counts 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 state- ment presentation. These reclassifications had no impact on prior year consolidated results of operations. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect reported amounts in the consolidated financial state- ments 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 re- quirements 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.” NW Natural’s utility business seg- ment is authorized by the OPUC and the WUTC to earn a reason- able return on invested capital. 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 proceed- ings, to provide for recovery of revenues or expenses from, or re- funds to, utility customers in future periods, including a return or a carrying charge. At Dec. 31, 2004 and 2003, the amounts deferred as regulatory assets and liabilities were net liabilities of $80.8 mil- lion and $89.4 million, respectively. The net amounts recognized at Dec. 31, 2004 and 2003 include $153.2 million and $135.6 mil- lion, respectively, of accumulated removal costs, which have been included in regulatory liabilities, in accordance with SFAS No. 143, “Accounting for Asset Removal Obligations.” See “New Accounting Standards – Adopted Standards,” below. NW Natural believes that continued application of SFAS No. 71 for its regulated activities is appropriate and consistent with the current regulatory environment, and that all of its regulated assets and liabilities at Dec. 31, 2004 and 2003 are recoverable or refund- able through future utility rates. NW Natural also believes that it will continue to be able to earn a reasonable rate of return or a car- rying charge on its regulated assets, net of regulatory liabilities. If NW Natural should determine that all or a portion of these regu- latory assets or liabilities no longer meet the criteria for continued application of SFAS No. 71, then it would be required to write off the net unrecoverable balances against earnings. New Accounting Standards Adopted Standards ASSET RETIREMENT OBLIGATIONS. Effective Jan. 1, 2003, the Com- pany adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires 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 incurred. 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 related asset. The Company did not have any ma- terial legal obligations 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. The Company’s adoption of SFAS No. 143 resulted in a balance sheet reclassification of asset removal cost obligations from accumulated depreciation and amor- tization to regulatory liabilities. The adoption of SFAS No. 143 and the reclassification of asset removal cost obligations had no mate- rial impact on the Company’s financial condition, results of opera- tions or cash flows (see “Plant and Property,” below, for a discus- sion of the Company’s policy on asset removal costs). FINANCIAL INSTRUMENTS WITH EQUITY AND DEBT CHARACTERIS- TICS. 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. The Company redeemed its 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, results of operations or cash flows. VARIABLE INTEREST ENTITIES. In December 2003, the Financial Accounting Standards Board (FASB) revised FASB Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities” (FIN 46R), to clarify the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements.” FIN 46R provides addi- tional guidance for the identification and consolidation of variable interest entities (VIEs), and for financial reporting by enterprises involved with VIEs. The Company adopted the original provisions of FIN 46 during 2003, and adopted the additional guidance of FIN 46R in 2004. The Company has certain equity investments that are variable interests and some of these entities are potentially VIEs. N W N AT U R A L 39 Notes to Consolidated Financial Statements However, because the Company is not the primary beneficiary, it is not required to consolidate the VIEs. The Company’s variable interests primarily consist of limited liability interests with invest- ments in alternative energy projects, low income housing and other real estate. These investments were entered into between the years 1988 and 2000 and have been accounted for under the equity method or cost method. The Company’s maximum exposure to loss for these investments is $6.2 million at December 31, 2004, an amount that represents the Company’s current investment balance minus its minimum net realizable value. The Company’s invest- ment risk is thus limited because all such investments are non-re- course to the Company. The adoption of FIN 46R had no material impact on the Company’s financial condition, results of operations or cash flows. MEDICARE PRESCRIPTION DRUG, IMPROVEMENT AND MODERNIZA- TION ACT. In May 2004, the FASB issued Staff Position (FSP) No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” (the Act). FSP No. FAS 106-2 provides specific guid- ance on accounting for the effects of the Act for employers that sponsor postretirement health care plans that provide prescription drug benefits. FSP No. FAS 106-2 also requires certain disclosures regarding the effects of a federal subsidy provided by the Act. Effective July 1, 2004, the Company adopted FSP No. 106-2 with no material impact on the Company’s cash flows, accumulated postretirement benefit obligations or net periodic postretirement benefit costs. Based on current guidance and existing plan design, the Company, with input from its actuary, determined that the pre- scription drug benefit provided by the Company’s postretirement benefit plan did not qualify it for a federal subsidy. While the Com- pany provides certain prescription drug benefits to retirees, it was determined that the Company’s contributions would be less than 40 percent of the plan’s expected claims cost, and therefore is not eligible for the subsidy in 2006, the first year the subsidy is avail- able. The Company will continue to reevaluate its plan contribu- tions and claims experience to determine whether the plan quali- fies for the federal subsidy in future years. OTHER THAN TEMPORARY IMPAIRMENTS. In March 2004, the Emerging Issues Task Force (EITF) ratified EITF No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF No. 03-1). EITF No. 03-1 provides guidance for evaluating whether an investment is impaired, whether the impairment is other than temporary, and the measurement of such impairment. The guidance also includes accounting consid- erations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures in annual financial statements about unrealized losses that have not been recognized as other-than-temporary impairments. The adoption of EITF 03-1, which was effective for reporting periods beginning after June 15, 2004, had no material impact on the Company’s financial condi- tion, results of operations or cash flows. 40 N W N AT U R A L INCOME TAXES. In December 2004, the FASB issued staff posi- tions (FSP) FSP SFAS No. 109-1, to provide guidance on the appli- cation of SFAS No. 109, “Accounting for Income Taxes,” to the pro- visions within the American Jobs Creation Act of 2004 (the Jobs Act) that provides a tax deduction on qualified production activi- ties. The Jobs Act became effective on Oct. 23, 2004 and provides for a tax deduction of up to nine percent (when fully phased-in) of the lesser of (a) “qualified production activities income,” as defined in the Jobs Act, or (b) taxable income (after the deduction for the utilization of any net operating loss carryforwards). The Company has determined that application of the provisions within the Jobs Act will not have a material impact on the Company’s financial condition, results of operations or cash flows. Recent Accounting Pronouncements INVENTORY COSTS. In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” SFAS No. 151 amends the guidance on inventory pricing to require that abnormal amounts of idle facility expense, freight, handling costs and wasted material be charged to current period expense rather than capitalized as inventory costs. SFAS No. 151 also re- quires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production fa- cilities. SFAS No. 151 is effective for inventory costs incurred dur- ing fiscal years beginning after June 15, 2005. The Company is evaluating the impact this new standard may have on its financial statements, but it is expected that its implementation will not have a material impact upon the Company’s financial condition, results of operations or cash flows. SHARE BASED PAYMENTS. In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share Based Payment” (SFAS No. 123R), that requires companies to expense the fair value of em- ployee stock options and similar awards. Under SFAS No. 123R, share based payment awards will be measured at fair value on the date of grant based on the estimated number of awards expected to vest. The estimated fair value will be recognized as compensa- tion expense over the period an employee is required to provide service in exchange for the award, usually referred to as the vest- ing period. The expense would be adjusted for actual forfeitures that occur before vesting, but would not be adjusted for awards that expire or terminate after vesting. The Company is evaluating different option-pricing models to determine the most appropriate measure of fair value for its share based payment awards under the new standard. Disclosures of estimated fair value and compen- sation expense using the Black-Scholes option pricing model, and its corresponding impact on the financial statements, is provided in Note 4. The Company also is evaluating the effect of the adop- tion and implementation of SFAS No. 123R, which is not expected to have a material impact on the Company’s financial condition, results of operations or cash flows. SFAS No. 123R is effective for interim or annual reporting periods beginning after June 15, 2005. The Company expects to adopt the provisions of SFAS No. 123R in the first quarter of 2005. NON-MONETARY TRANSACTIONS. Also in December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of Accounting Principles Board (APB) Opinion No. 29, Accounting for Nonmonetary Transactions.” SFAS No. 153 redefines the types of nonmonetary exchanges that require fair value mea- surement. SFAS No. 153 is effective for nonmonetary transactions entered into on or after July 1, 2005. The Company is evaluating the impact of this statement, but adoption of this new accounting stan- dard in 2005 is not expected to have a material impact on the Com- pany’s financial condition, results of operations or cash flows. 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 regula- tory authorities. The weighted average depreciation rate was ap- proximately 3.4 percent for the year ended Dec. 31, 2004 and 3.5 percent for each of the years 2003 and 2002. The depreciation rate reflects the approximate economic life of the utility property. Effective Jan. 1, 2003, the Company adopted SFAS No. 143, “Ac- counting for Asset Retirement Obligations.” 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 supplemented, be classified as a regulatory liability. In accordance with long-standing industry practice, the Company accrues for fu- ture 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 ac- cruals 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. At Dec. 31, 2004 and 2003, the Company recognized accrued asset removal costs of $153.2 million and $135.6 million, respectively, through depreciation expense from accumulated depreciation and amortization. The Company’s estimate of accumulated removal costs was based on rates using its most recent depreciation study. The Company will continue to accrue future asset removal costs through depreciation expense, with a corresponding credit to regu- latory liabilities – accrued asset removal costs. When the Company retires depreciable utility plant and equipment, it charges the as- sociated original costs to accumulated depreciation and amortiza- tion, and any related removal costs incurred are charged to regula- tory liabilities – accrued asset removal costs. No gain or loss is recognized upon normal retirement. 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 actual 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 inter- est charges, and a return on equity funds, shown as other income, is used to compute AFUDC. While cash is not realized currently from AFUDC, it is realized in future years through increased reve- nues from rate recovery resulting from higher rate base and higher depreciation expense. NW Natural’s composite AFUDC rates were 3.0 percent in 2004, 4.5 percent in 2003 and 2.8 percent in 2002. 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 transpor- tation 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 reve- nues). Unbilled revenues are dependent upon a number of factors that require management judgment, including total gas receipts and deliveries, customer use and weather. Unbilled revenues are reversed the following month when actual billings occur. The Com- pany’s accrued unbilled revenues at Dec. 31, 2004 and 2003 were $64.4 million and $59.1 million, respectively. 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 un- der the contract, or are recognized as they are earned for amounts above the guaranteed value based on estimates provided by the in- dependent energy marketing company (see Note 2). Accounts Receivable and Allowance for Uncollectible Accounts Accounts receivable consist primarily of amounts due to NW Natural for gas sales and transportation services to residential, commercial and industrial customers, plus amounts due for inter- state gas storage services and other miscellaneous receivables. With respect to these trade receivables, the Company establishes an allowance for uncollectible accounts (allowance) based on the aging of receivables, its collection experience of past due accounts on payment plans, and historical trends of write-offs as a percent of revenues. With respect to large individual customer receivables, a specific allowance is established and added to the general allow- ance when amounts are identified as unlikely to be recovered. In- active accounts are written-off against the allowance after 120 days past due or when deemed to be uncollectible. Differences between the Company’s estimated allowance and actual write-offs will oc- cur based on changes in general economic conditions, customer credit issues and the level of natural gas prices, but these differ- ences are not currently expected to have a material impact on the Company’s financial condition or results of operation. Inventories Inventories, consisting primarily of natural gas in storage, are stated at the moving average cost. Regulatory treatment of gas in- ventories provides full recovery in rates for the value of gas inven- tory at the moving average cost. All other inventories are stated at the lower of average cost or net realizable value. Derivatives Policy NW Natural’s Derivatives Policy sets forth the guidelines for us- ing 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 cur- rency prices related to gas purchase commitments from Canada, oil or propane commodity prices related to gas sales and transpor- tation 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 earn- ings and cash flows associated with changes in commodity prices, foreign currency prices and interest rates. The use of derivatives is permitted only after the commodity price, exchange rate, and in- terest rate exposures have been identified, are determined to exceed acceptable tolerance levels and are considered to be unavoidable because they are necessary to support normal business activities (see Note 11). The Derivatives Policy is intended to prevent specu- lative 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. N W N AT U R A L 41 Notes to Consolidated Financial Statements In accounting for derivative activities, the Company applies SFAS No. 133, “Accounting for Derivative Instruments and Hedg- ing Activities,” as amended by SFAS No. 138, “Accounting for Cer- tain Derivative Instruments and Certain Hedging Activities,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instru- ments and Hedging Activities,” (collectively referred to as SFAS No. 133). SFAS No. 133 requires that the Company recognize deriva- tives 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 provides an exception for contracts intended for normal purchase and normal sale, other than a financial instrument or de- rivative instrument for which physical delivery is probable. Many of the Company’s gas supply and transportation contracts are de- rivative 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 mechanisms. 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. Un- realized 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 “regula- tory assets.” Due to their regulatory deferral treatment, effective portions of changes in the fair value of these derivatives are not re- corded 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 regulatory 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 $64.7 million and $63.4 million at Dec. 31, 2004 and 2003, respec- tively. These amounts are primarily based on differences between the book and tax bases of net utility plant in service. 42 N W N AT U R A L 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 re- lated 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 Port- land General Electric Company (PGE) from Enron Corp. and other miscellaneous income from merchandise sales, rents, leases and other items. Earnings Per Share 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 per share are calculated as follows: Thousands, except per share amounts 2004 2003 2002 Net income Redeemable preferred and preference stock dividend requirements Earnings applicable to common stock – basic Debenture interest less taxes Earnings applicable to common stock – diluted Average common shares outstanding – basic Stock options Convertible debentures Average common shares outstanding – diluted Earnings per share of common stock – basic Earnings per share of common stock – diluted $ 50,572 $ 45,983 $ 43,792 – __________ 294 __________ 2,280 __________ 50,572 200 __________ 45,689 257 __________ 41,512 285 __________ $ __________ __________ 50,772 $ __________ __________ 45,946 $ 41,797 __________ __________ 27,016 40 227 __________ 25,741 28 292 __________ 25,431 59 324 __________ 27,283 __________ __________ 26,061 __________ __________ 25,814 __________ __________ $ __________ __________ 1.87 $ __________ __________ 1.77 $ 1.63 __________ __________ $ __________ __________ 1.86 $ __________ __________ 1.76 $ 1.62 __________ __________ For the years ended Dec. 31, 2004, 2003 and 2002, 201,800 shares, 77,500 shares and 84,000 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 earnings 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 com- pensation 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 value 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 the Non-Employee Directors Stock Compensation Plan in the period when the shares are earned (see “New Accounting Standards – Recent Accounting Pronouncements – Share Based Payments,” above, and Note 4). 2. CONSOLIDATED SUBSIDIARY OPERATIONS AND SEGMENT INFORMATION: At Dec. 31, 2004, 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 was terminated, Northwest Energy has remained a non-active subsidiary of the Company. The Company’s core business segment, Local Gas Distribution (LDC), involves the distribution and sale of natural gas. The Local Gas Distribution segment is also referred to as the “utility”. Another segment, Interstate Gas Storage, represents natural gas storage ser- vices provided to interstate customers, including asset optimiza- tion services under a contract with an independent energy market- ing company. The remaining business segment, Other, primarily consists of non-regulated investments in alternative energy proj- ects in California (see “Financial Corporation,” below), a Boeing 737-300 aircraft leased to Continental Airlines, low-income hous- ing in Portland, Oregon and Northwest Energy’s limited activities (see Note 9). Interstate Gas Storage Interstate gas storage services are provided to off-system inter- state customers using Company-owned storage capacity that has been developed 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. For each of the years ended Dec. 31, 2004, 2003 and 2002, this business segment derived a majority of its revenues from fewer than five customers. The larg- est of these customers is served under a long-term contract. Results for the interstate gas storage segment also include rev- enues, net of amounts shared with core utility customers, from a contract with an independent energy marketing company that op- timizes the use of NW Natural’s assets by engaging in trading ac- tivities using temporarily unused portions of its upstream pipeline transportation capacity and gas storage capacity. In Oregon, NW Natural retains 80 percent of the pre-tax income from the optimi- zation of storage and pipeline transportation capacity when the costs of such capacity have not been included in core utility rates, and 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 reg- ulatory account for distribution to NW Natural’s core utility cus- tomers. NW Natural has a similar sharing mechanism in Washing- ton for revenue derived from interstate storage services and third party optimization services. Financial Corporation Financial Corporation has several financial investments, includ- ing investments as a limited partner in solar electric generating systems, windpower electric generating projects and low-income housing projects. Financial Corporation’s total assets were $7.6 million and $8.0 million at Dec. 31, 2004 and 2003, respectively. On Jan. 31, 2005 Financial Corporation sold its limited partner- ship interests in three solar electric generating systems for approx- imately $3 million, which resulted in a $0.5 million write-down of these systems in the fourth quarter of 2004. These systems are lo- cated in the Mojave Desert in California. NW Natural invested in the projects between 1986 and 1988. Financial Corporation’s own- ership interests ranged from 4.0 percent to 5.3 percent. Segment Information Summary The following table presents summary financial information about the reportable segments for 2004, 2003 and 2002. Inter-seg- ment transactions are insignificant. Thousands 2004 Net operating revenues Depreciation and amortization Other operating expenses Income (loss) from operations Income from financial investments Net income Total assets at Dec. 31, 2004 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 Interstate Utility Gas Storage Other Total $ 301,769 $ 56,899 140,089 104,781 6,423 $ 472 652 5,299 168 $ 308,360 57,371 140,963 110,026 – 222 (54) 2,855 47,090 1,688,688 – 2,880 28,361 181 602 15,146 3,036 50,572 1,732,195 $ 278,856 $ 53,798 130,619 94,439 9,036 $ 451 804 7,781 174 $ 288,066 54,249 131,545 102,272 – 122 52 3,406 40,913 1,551,817 – 4,312 19,036 474 758 14,526 3,880 45,983 1,585,379 $ 279,414 $ 51,693 118,156 109,565 7,944 $ 396 962 6,586 186 $ 287,544 52,090 119,196 116,258 1 78 107 1,390 – 988 2,378 – 47,280 1,432,777 – 3,646 16,403 (8,414) (7,134) 18,097 (8,414) 43,792 1,467,277 3. CAPITAL STOCK: Common Stock At Dec. 31, 2004, NW Natural had reserved 106,699 shares of common stock for issuance under the Employee Stock Purchase Plan, 288,155 shares for future conversions of its 7-1/4% Convert- ible Debentures, 232,827 shares under its Dividend Reinvestment and Stock Purchase Plan, 1,659,470 shares under its Restated Stock Option Plan (see Note 4), and 3,000,000 shares under the Share- holder Rights Plan. In April 2004, the Company issued and sold 1,290,000 shares of its common stock in an underwritten public offering and used the net proceeds of $38.5 million from the offering primarily to re- duce short-term indebtedness and to fund, in part, NW Natural’s utility construction program. 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 redemption premium was recognized as an unamortized cost pur- suant to SFAS No. 71 and is being 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. N W N AT U R A L 43 61,020 – – 1,105 2003 2004 2003-05 2004-06 – – 7,000 7,750 28,000 31,000 56,000 62,000 Notes to Consolidated Financial Statements 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 2005. No shares were re- purchased in 2003 or 2004. Since the program’s inception, the Com- pany 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 shares. At Dec. 31, 2004, options on 1,228,000 shares were avail- able for grant and options on 431,470 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 2004, 2003 and 2002: ––––––––––––––––– Shares ––––––––––––––––– Premium Redeemable Redeemable on common stock (thousands) preference stock preferred stock Common stock 25,228,074 42,862 157,288 250,000 – – 90,000 $ 240,697 748 3,854 – – 1,624 – 97,069 – – – – (250,000) – __________ __________ __________ __________ 248,028 – 25,586,313 425 – 14,175 4,347 – 178,714 – (7,500) – 82,500 – – 127,357 – – 2,545 – 526 31,443 – – – – – – __________ __________ __________ __________ 255,871 – 25,938,002 35,905 – 1,290,000 605 – 27,541 4,323 – 157,124 – (7,500) (75,000) – – – – 73,649 – – 2,285 1,086 – – 64,904 (41) – – (4,500) __________ __________ __________ __________ 27,546,720 – $ 300,034 – __________ __________ __________ __________ __________ __________ __________ __________ 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 Sales to public Sales to employees Sales to stockholders Exercise of stock options – net Conversion of convertible debentures to common Repurchase Balance, Dec. 31, 2004 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 (NED- SCP). These plans are designed to promote stock ownership in NW Natural by employees and officers and, in the case of the NEDSCP, by non-employee directors. LONG-TERM INCENTIVE PLAN. The LTIP is intended 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, restricted stock or perfor- mance-based stock awards. Shares awarded under the LTIP are purchased on the open market. 44 N W N AT U R A L At year-end 2004, a total of 436,000 shares of common stock were available for award under the LTIP, assuming that current performance based grants are awarded at the target level. 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 amortization over the vesting period for the restricted stock awards. Performance-based Stock Awards. Since the Plan’s inception in 2001, through December 31, 2004, five performance-based stock awards have been granted, one based on a two-year performance period (2001-02) and four based on three-year performance periods (2001-03, 2002-04, 2003-05 and 2004-06). At Dec. 31, 2004, all per- formance-based stock awards other than those covering the 2003- 05 and 2004-06 periods had lapsed because the performance-based measures were not achieved. If the performance-based measures are achieved, participants will also receive dividend equivalent cash payments equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share by the Company during the performance period. At Dec. 31, 2004, the aggregate number of performance-based shares awarded and outstanding at the minimum, threshold, target and maximum levels were as follows: Performance Year Period Awarded –––––––– No. of Performance Shares Awarded –––––––– Target Maximum Minimum Threshold For the 2003-05 performance period, a series of performance targets were established based on the Company’s average annual return on equity (ROE) for the performance period corresponding to award opportunities ranging from 0 percent to 200 percent of the target awards. No awards are payable unless the threshold an- nual average ROE level, tied to the Company’s authorized ROE, is achieved during the award period. The maximum awards are pay- able only upon the achievement of an average annual ROE 200 ba- sis points above the Company’s authorized ROE. For the 2004-06 performance period, awards will be based on total shareholder re- turn relative to a peer group of gas distribution companies over the three-year performance period and performance milestones rela- tive to the Company’s core and non-core strategies. Restricted Stock Awards. Restricted stock awards also have been granted under the LTIP. A restricted stock award consisting of 4,500 shares granted in 2001 lapsed in 2004, and a restricted stock award was granted in 2004 consisting of 5,000 shares that is scheduled to vest ratably over five years beginning in 2005. RESTATED STOCK OPTION PLAN. The Restated SOP authorizes an aggregate of 2,400,000 shares of common stock for issuance as in- centive or non-statutory stock options. These options may be granted only to officers and key employees designated by a com- mittee 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 holders may exchange shares they have owned for at least six months, at the current market price, to pur- chase shares at the option price. Since inception in 1985, options on 1,303,721 shares of common stock have been granted at prices ranging from $11.75 to $32.02 per share, and options on 131,721 shares have expired. EMPLOYEE STOCK PURCHASE PLAN. The ESPP allows employees to purchase common stock at 85 percent of the closing price on the trading day immediately preceding the subscription date, which is set annually. Each eligible employee may purchase up to $24,000 worth of stock through payroll deductions over a six- to 12-month period. In accordance with APB Opinion No. 25, no compensation ex- pense was recognized for options granted under the Restated SOP or shares issued under the ESPP during 2004 or earlier years (see Note 1, “New Accounting Standards – Recent Accounting Pronounce- ments”). 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: Thousands, except per share amounts 2004 2003 2002 Net income as reported 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 $ 50,572 $ 45,983 $ 43,792 (423) __________ 50,149 (279) __________ 45,704 (478) __________ 43,314 – __________ (294) __________ (2,280) __________ 50,149 200 __________ 45,410 257 __________ 41,034 285 __________ $ __________ __________ 50,349 $ __________ __________ 45,667 $ 41,319 __________ __________ $ $ $ $ 1.87 $ 1.86 $ 1.86 $ 1.85 $ 1.77 $ 1.76 $ 1.76 $ 1.75 $ 1.63 1.61 1.62 1.60 The fair value of each stock option 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: Expected life in years Risk-free interest rate Expected volatility Dividend yield Present value of options granted 2004 7.0 3.6% 25.2% 4.1% 2002 7.0 3.6% 29.1% 4.8% $ 24.55 $ 20.49 Information regarding the Restated SOP’s activity is summarized as follows: ––––––– Price per Share ––––––– Weighted- Average Exercise Price Range Option Shares Balance outstanding, Dec. 31, 2001 Granted Exercised Expired 387,091 $ 20.25 - 27.875 $ 22.79 26.35 26.07 - 27.850 163,750 21.74 20.25 - 27.875 (68,827) 25.43 20.25 - 27.875 (18,200) _________ Balance outstanding, Dec. 31, 2002 Exercised Expired Balance outstanding, Dec. 31, 2003 Granted Exercised Expired 463,814 (140,470) (1,300) _________ 322,044 202,800 (92,074) (1,300) _________ 20.25 - 27.875 20.25 - 27.875 20.25 20.25 - 27.875 31.34 - 32.020 20.25 - 27.875 26.30 - 31.340 24.10 21.14 20.25 25.35 31.40 24.39 30.18 Balance outstanding, Dec. 31, 2004 431,470 $ 20.25 - 32.020 $ 28.38 Shares available for grant Dec. 31, 2002 Shares available for grant Dec. 31, 2003 Shares available for grant Dec. 31, 2004 1,428,200 1,429,500 1,228,000 The weighted average remaining life of outstanding stock op- tions at December 31, 2004 was 7.3 years. The characteristics of exercisable stock options at Dec. 31, 2004 were as follows: Range of Exercise Prices $20.25 – $27.875 Exercisable Stock Options Weighted- Average Exercise Price 185,120 $ 25.56 NON-EMPLOYEE DIRECTORS STOCK COMPENSATION PLAN. In Feb- ruary 2004, the NEDSCP was amended to permit non-employee directors to receive stock awards either in cash or in Company stock. As a result of modifications to the directors’ compensation arrangements, the NEDSCP was further amended in September 2004 to eliminate any further awards, either in cash or stock, on and after Jan. 1, 2005. Prior to the latter amendment to the NEDSCP, if non-employee directors elected to receive their awards in stock, approximately $100,000 worth of the Company’s common stock was awarded upon joining the Board. These stock awards were subject to vest- ing and to restrictions on sale and transferability. The shares vested in monthly installments over the five calendar years following the award. On January 1 of each year following the initial award, non- employee directors who elected to receive their awards in Company stock were awarded an additional $20,000 worth of restricted Com- pany stock, which vested 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 re- ceive all dividends and have full voting rights on both vested and unvested shares. All awards vest immediately upon a change in control of the Company. Any unvested shares are considered to be unearned compensation, and thus are forfeited if the recipient ceases to be a director. The shares were 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 2004 and 2003, which are reported as a reduction to total common equity in the consolidated balance sheets: Thousands 2004 2003 Unearned stock compensation: Balance at beginning of year Purchases of restricted stock Restricted stock amortizations Balance at end of year $ 729 $ 431 (298) __________ 862 $ __________ __________ 711 328 (310) __________ 729 __________ __________ $ Under a separate plan, prior to Jan. 1, 2005, non-employee di- rectors could elect to invest their cash fees and retainers for board service in shares of the Company’s common stock. Under a new deferral plan effective Jan. 1, 2005, such fees and retainers will be deferred to a cash account. Cash account balances may be trans- ferred to and invested in a Company stock account, at the election of the director, up to four times per year. N W N AT U R A L 45 Notes to Consolidated Financial Statements 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 converted 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 outstanding, for each of the 12-month periods through Dec. 31, 2009 amount to: $15 million in 2005; $8 million in 2006; $29.5 million in 2007, $5 million in 2008; and none in 2009. Holders of certain long-term debt have put options that, if exercised, would accelerate the maturities by $10 million in 2005 and $20 million in each of 2007, 2008 and 2009. 6. NOTES PAYABLE AND LINES OF CREDIT: The Company’s primary source of short-term funds is commer- cial paper notes payable. NW Natural issues commercial paper un- der agency agreements with a commercial bank and such commer- cial paper is supported by its committed bank lines of credit (see below). At Dec. 31, 2004 and 2003, the amounts and average inter- est rates of commercial paper debt outstanding were $102.5 million and 2.3 percent and $85.2 million and 1.1 percent, respectively. NW Natural has lines of credit with four commercial banks to- taling $150 million. Half of the credit facility with each bank, total- ing $75 million, is committed and available through Sept. 30, 2005, and the other $75 million is committed and available through Sept. 30, 2007. Three of these commercial banks have each committed $20 million for each of their 2005 and 2007 lines of credit and the fourth commercial bank has committed $15 million for each of its 2005 and 2007 lines of credit. 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 credit rating is not an event of default, nor is the maintenance of a specific 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 main- tain a consolidated net worth at least equal to 80 percent of its net worth at Sept. 30, 2004, plus 50 percent of the Company’s net in- come 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, 2004, and with the equivalent covenants in the prior year’s lines of credit at Dec. 31, 2003. 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, several non-qualified supplemental pen- sion plans for eligible executive officers and certain key employees and other postretirement benefit plans for its employees. Only the two qualified defined benefit pension plans have plan assets which are held in a qualified trust to fund retirement benefits. 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, 2004, and a statement of the funded status and amounts recognized in the consolidated balance sheets, using measurement dates of Dec. 31, 2004, 2003 and 2002: Thousands Change in benefit obligation: Benefit obligation at Jan. 1 Service cost Interest cost Special termination benefits 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 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 ––––––––––––––––––––––––––––––––––––––––––––– Post-Retirement Benefits –––––––––––––––––––––––––––––––––––––––––––– ––––––––––– Other Postretirement Benefits ––––––––––– ––––––––––––––––– Pension Benefits ––––––––––––––––– 2002 2002 2004 2004 2003 2003 $ 205,352 5,428 12,690 237 (10,682) – 9,923 __________ $ 185,124 4,748 12,402 – (10,363) – 13,441 __________ $ 166,751 4,637 11,807 – (9,453) – 11,382 __________ $ 23,379 457 1,232 – (1,040) – (1,299) __________ $ 18,457 456 1,336 – (1,027) (111) 4,268 __________ $ 16,987 395 1,174 – (979) (300) 1,180 __________ 222,948 __________ 205,352 __________ 185,124 __________ 22,729 __________ 23,379 __________ 18,457 __________ 168,324 19,835 9,310 (10,682) __________ 143,164 34,520 1,003 (10,363) __________ 168,964 (17,082) 735 (9,453) __________ – – 1,040 (1,040) __________ – – 1,027 (1,027) __________ – – 979 (979) __________ 186,787 __________ 168,324 __________ 143,164 __________ – __________ – __________ – __________ (36,162) – 5,146 33,897 __________ (37,028) – 6,240 32,156 __________ (41,960) – 7,371 42,060 __________ (22,729) 3,292 – 6,717 __________ (23,379) 3,703 – 8,304 __________ (18,457) 4,226 – 4,437 __________ $ 2,881 __________ __________ $ 1,368 __________ __________ $ 7,471 __________ __________ $ (12,720) __________ __________ $ (11,372) __________ __________ $ (9,794) __________ __________ $ 12,745 (12,919) – 3,055 __________ $ 11,113 (11,319) – 1,574 __________ $ 17,339 (18,741) 4,438 4,435 __________ $ – (12,720) – – __________ $ – (11,372) – – __________ $ – (9,794) – – __________ Net amount recognized $ 2,881 __________ __________ $ 1,368 __________ __________ $ 7,471 __________ __________ $ (12,720) __________ __________ $ (11,372) __________ __________ $ (9,794) __________ __________ 46 N W N AT U R A L  The Company’s qualified defined benefit pension plans had an accumulated benefit obligation in excess of plan assets at Dec. 31, 2004. The plans’ aggregate accumulated benefit obligation was $209 million, $192 million and $172 million at Dec. 31, 2004, 2003 and 2002, respectively, and the fair value of plan assets was $186.8 million, $168.3 million and $143.2 million, respectively. The fair value of plan assets increased from Dec. 31, 2003 to Dec. 31, 2004 due to $22.5 million in investment gains and employer contribu- tions of $8.3 million, partially offset by $11.2 million in withdraw- als to pay benefits and $1.1 million to pay eligible expenses of the plans. The combination of investment returns and cash contribu- tions is expected to provide sufficient funds to cover all benefit obligations of the plans. The Company is not required to make a cash contribution to either of its qualified pension plans for the 2005 plan year. The Company’s investment policy and performance objectives for the qualified pension plan assets (plan assets) held in the Retire- ment Trust Fund was approved by the retirement committee which is 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 consider- ation 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 Income Security Act of 1974 (ERISA). The approved asset classes are cash and short-term investments, fixed income, common stock and convertible securi- ties, absolute and real return strategies, real estate and investments in securities of NW Natural, and may be invested in separately managed accounts or in commingled or mutual funds. Re-balanc- ing will take place at least annually, or when significant cash flows occur, in order to maintain the allocation of assets within the stated target allocation ranges. The Retirement Trust Fund is not currently invested in any NW Natural securities. The Company’s pension plan asset allocation at Dec. 31, 2004 and 2003, and the target allocation and expected long-term rate of return by asset category for 2005 are as follows: Asset Category US Large Cap Equity US Small/Mid Cap Equity Non-US Equity Fixed Income Real Estate Absolute Return Real Return Weighted Average Percent of Plan Assets ——— Dec. 31,——— 2003 2004 Target Allocation 2005 36.3% 9.2% 19.2% 19.8% 3.6% 7.3% 4.6% 40.2% 7.3% 16.0% 24.8% 3.9% 7.8% – 35% 8% 15% 25% 4% 8% 5% Expected Long-term Rate of Return 2005 9.00% 9.50% 9.00% 5.75% 8.00% 9.00% 8.25% 8.25% The Company’s non-qualified supplemental pension plans’ ac- cumulated benefit obligations were $13.6 million, $13.0 million and $12.8 million at Dec. 31, 2004, 2003 and 2002, respectively. Although the plans are unfunded plans with no plan assets due to their nature as non-qualified plans, the Company indirectly funds its obligations with trust-owned life insurance. The Company’s plans for providing postretirement benefits other than pensions also are unfunded plans. The aggregate ben- efit obligation for those plans was $22.7 million, $23.4 million and $18.5 million at Dec. 31, 2004, 2003 and 2002, respectively. The following tables provide the components of net periodic benefit cost for the qualified and non-qualified pension and other postretirement benefit plans for the years ended Dec. 31, 2004, 2003 and 2002, and the assumptions used in measuring these costs and benefit obligations: Thousands 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 (NPBC) Assumptions: Discount rate for 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 ––––––––––––––––––––––––––––––––––––––––––––– Post-Retirement Benefits –––––––––––––––––––––––––––––––––––––––––––– ––––––––––– Other Postretirement Benefits ––––––––––– ––––––––––––––––– Pension Benefits ––––––––––––––––– 2002 2002 2004 2004 2003 2003 $ 5,428 12,689 (13,284) – 1,094 1,631 __________ 7,558 $ __________ __________ $ 4,748 12,402 (12,232) – 1,132 1,058 __________ $ 7,108 __________ __________ $ 4,637 11,807 (16,335) 351 1,204 (216) __________ $ 1,448 __________ __________ $ 457 1,232 – 411 – 288 __________ $ 2,388 __________ __________ 6.25% 4.00 – 5.00% 8.25% 6.00% 4.00 – 5.00% 8.25% 6.75% 4.25 – 5.00% 8.00% 6.25% 4.00 – 5.00% 8.25% 7.25% 4.25 – 5.00% 9.00% 6.75% 4.25 – 5.00% 8.00% 6.25% n/a n/a 6.00% n/a n/a $ 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 N W N AT U R A L 47 8. INCOME TAXES: A reconciliation between income taxes calculated at the statu- tory federal tax rate and the tax provision reflected in the financial statements is as follows: Thousands 2004 2003 2002 $ Computed income taxes based on statutory federal income tax rate of 35% Increase (reduction) in taxes resulting from: 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 26,986 $ 24,263 $ 23,533 222 222 222 2,554 (210) (920) (955) (813) 2,310 (357) (879) (1,192) (925) 2,299 (362) (858) (487) (573) (392) 59 __________ 26,531 $ $ __________ __________ 2,500 $ $ (226) 124 __________ 23,340 $ __________ __________ 13,940 $ (240) (90) __________ 23,444 __________ __________ 33,474 The provision for income taxes consists of the following: Thousands, except percentages 2004 2003 2002 Income taxes currently payable (receivable): 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 (9,607) $ $ (1,111) __________ (10,718) __________ 10,011 $ 1,175 __________ 11,186 __________ 9,377 1,239 __________ 10,616 __________ 33,602 4,567 __________ 38,169 __________ 10,747 2,286 __________ 13,033 __________ 11,476 2,210 __________ 13,686 __________ (800) (120) __________ (920) __________ 26,531 $ $ __________ __________ 34.4% (801) (78) __________ (879) __________ 23,340 $ __________ __________ 33.7% (800) (58) __________ (858) __________ 23,444 __________ __________ 34.9% Deferred tax assets and liabilities are comprised of the follow- ing: Thousands 2004 2003 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 Alternative minimum tax credit carryforward Loss and credit carryforwards Total Net accumulated deferred income tax liability $ 146,657 $ 113,781 63,449 – 6,109 __________ 183,339 __________ 64,734 5,730 5,534 __________ 222,655 __________ 970 557 10,015 – – __________ 11,542 __________ $ 210,715 $ 171,797 __________ __________ – 1,068 7,330 1,631 1,911 __________ 11,940 __________ __________ __________ Notes to Consolidated Financial Statements The assumed annual increase in trend rates used in measuring postretirement benefits as of Dec. 31, 2004 were 10 percent for medical and 13 percent for prescription drugs. Medical costs were assumed to decrease gradually each year to a rate of 4.5 percent for 2012, 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 percent- age point change in assumed health care cost trend rates would have the following effects: Thousands 1% Decrease 1% Increase Effect on the total service and interest cost components of net periodic postretirement health care benefit cost Effect on the health care cost component of the accumulated postretirement benefit obligation $ $ 48 901 $ (47) $ (815) The following table provides information regarding employer contributions and benefit payments for the two qualified pension plans, the non-qualified pension plans and the other postretirement benefit plans for the years ended Dec. 31, 2004 and 2003, and es- timated future payments: Thousands Employer Contributions by Plan Year 2003 2004 2005 (estimated) Benefit Payments 2002 2003 2004 Estimated Future Payments 2005 2006 2007 2008 2009 2010 – 2014 Pension Benefits Other Benefits $ 3,922 6,390 1,620 $ 9,453 10,363 10,682 $ 12,404 12,817 13,106 13,892 14,325 82,578 $ 1,027 1,040 1,452 $ 979 1,027 1,040 $ 1,452 1,561 1,641 1,738 1,794 9,667 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 non-qualified deferred compensation plans for eligible officers and senior managers. These plans are de- signed to enhance the retirement program of employees and to as- sist them in strengthening their financial security by providing an incentive to save and invest regularly. NW Natural’s matching con- tributions to these plans totaled $1.7 million in 2004, $1.6 million in 2003 and $1.4 million in 2002. Effective Jan. 1, 2002, the RKSP was amended to establish an Employee Stock Ownership Plan (ESOP) within the RKSP by converting the existing RKSP Company Stock Fund into an ESOP. Effective Jan. 1, 2005, the Company will make a contribution of 25 cents per compensable hour on behalf of each union employee to the Western States Office and Professional Employees Pension Fund, which contributions will increase 3 percent each year, up to 30 cents per compensable hour. 48 N W N AT U R A L  The amount of income taxes paid in 2004 and 2003 decreased significantly as compared to the total provision for income taxes, primarily due to the effects of accelerated depreciation provisions provided by the Job Creation and Worker Assistance Act of 2002 (the Assistance Act) and the Jobs and Growth Tax Relief Recon- ciliation Act of 2003 (the Reconciliation Act). The Assistance Act provided for an additional depreciation deduction equal to 30 per- cent of an asset’s adjusted basis. The Reconciliation Act increased this first-year additional depreciation deduction to 50 percent of an asset’s adjusted basis. The additional first-year depreciation deduc- tion is an acceleration of depreciation deductions that otherwise would have been taken in the later years of an asset’s recovery pe- riod. The accelerated depreciation provisions provided by both the Assistance Act and the Reconciliation Act expired at Dec. 31, 2004. The Company realized enhanced cash flow from reduced income taxes totaling an estimated $55 million during the effective period, based on plant investments made between Sept. 11, 2001 and Dec. 31, 2004. For the year ended Dec. 31, 2004, the Company had an estimated federal net operating loss (NOL) of $15.4 million and an Oregon NOL of $18.6 million, primarily due to the effects of accelerated tax depreciation provided by the Assistance Act and the Reconcil- iation Act. The federal NOL will be carried back to 2002 for a re- fund of taxes paid in prior years, and the Oregon NOL will be used to reduce future Oregon taxable income. The Oregon NOL will ex- pire in 2019. At Dec. 31, 2004 the Company had $1.6 million of alternative minimum tax credit carryforwards to offset regular federal income tax payable in future years. In addition, the Company had certain tax credits of approximately $0.7 million which are available to re- duce certain federal and state income tax liabilities through 2011. The Company anticipates that it will be able to utilize all loss and credit carryforwards in future years. 9. PROPERTY AND INVESTMENTS: The following table sets forth the major classifications of NW Natural’s utility plant and accumulated depreciation at Dec. 31: ––––––––– 2003 ––––––––– Weighted Average Depreciation Rate ––––––––– 2004 ––––––––– Weighted Average Depreciation Rate Thousands, except percentages Amount Amount Transmission and distribution Utility storage General Intangible and other Utility plant in service Gas stored long-term Held for future use Construction work in progress Total utility plant Accumulated depreciation Regulatory liability – accrued asset removal costs Utility plant – net $ 1,509,475 109,613 91,229 61,573 __________ 1,771,890 13,434 1,833 7,815 __________ 1,794,972 (658,544) 153,258 __________ $ 1,289,686 __________ __________ 3.2% $ 1,347,402 107,547 2.6% 84,381 3.4% 56,429 8.5% __________ 1,595,759 3.4% 12,778 1,226 47,826 __________ 1,657,589 (607,354) 135,638 __________ $ 1,185,873 __________ __________ 3.3% 2.7% 6.0% 5.1% 3.5% Accumulated depreciation does not include $153.3 million and $135.6 million at Dec. 31, 2004 and 2003, respectively, which rep- resent accrued asset removal costs and are reflected on the balance sheets as a regulatory liability (see Note 1). The following table summarizes the Company’s investments in non-utility plant at Dec. 31: Thousands, except percentages Non-utility storage Dock, land, oil station and other Non-utility plant in service Construction work in progress Total non-utility plant Less accumulated depreciation Non-utility plant – net ––––––––– 2004 ––––––––– Weighted Average Depreciation Rate Amount ––––––––– 2003 ––––––––– Weighted Average Depreciation Rate Amount $ 24,900 $ 18,507 4,728 __________ 29,628 4,335 __________ 33,963 5,244 __________ 28,719 $ __________ __________ 3,846 __________ 22,353 2.3% 2.3% 1,042 __________ 23,395 4,855 _______–__ 18,540 $ __________ __________ The following table summarizes the Company’s other long-term investments, including financial investments in life insurance pol- icies accounted for at fair value based on cash surrender values, equity investments in certain partnerships and joint ventures ac- counted for under the equity or cost methods, and a leveraged lease investment in an aircraft, at Dec. 31: Thousands 2004 2003 Life insurance Aircraft leveraged lease Real estate partnership Note receivable Gas pipeline and other Electric generation Total other investments $ 45,011 $ 6,621 1,500 1,240 3,263 2,983 __________ 60,618 $ __________ __________ 59,710 6,438 1,500 – 2,880 3,317 __________ 73,845 __________ __________ $ 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 (KB Pipeline), owns a 10 percent interest in an 18-mile interstate natu- ral gas pipeline. KB Pipeline operated the pipeline for twelve years until Dec. 1, 2004, when a third party gas distribution company became the operator. KB Pipeline resigned as pipeline operator due, in part, to increased obligations resulting from final Federal Energy Regulatory Commission regulations implementing Standards of Conduct for Transmission Providers. Those regulations govern the relationship between interstate natural gas pipelines and their en- ergy affiliates or marketing functions and impose obligations pre- viously inapplicable to KB Pipeline with regard to separation of duties and related matters. FERC granted KB Pipeline an exemp- tion from most of the requirements of the Standards of Conduct; however, the remainder of the regulations continue to be applicable to KB Pipeline as a co-owner of the pipeline. At Dec. 31, 2004, Financial Corporation held ownership inter- ests ranging from 4.0 to 5.3 percent in three solar electric genera- tion 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 in- terests ranging from 25 to 41 percent in wind power electric gen- eration projects located near Livermore and Palm Springs, Califor- nia. The wind-generated power is sold to Pacific Gas and Electric Company and Southern California Edison Company under long- term contracts. Financial Corporation sold its interests in the solar electric generation plants on Jan. 31, 2005 (see Note 2). N W N AT U R A L 49 Notes to Consolidated Financial Statements FASB Interpretation No. 46, “Consolidation of Variable Interest Entities,” provides guidance for determining whether consolidation is required for entities over which control is achieved through means other than voting rights, known as “variable interest enti- ties.” The Company does not have any significant interests in vari- able interest entities for which it is a primary beneficiary. 10. FAIR VALUE OF FINANCIAL INSTRUMENTS: The estimated fair value of 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, 2004 ––––– –––––– Dec. 31, 2003 –––––– Estimated Fair Value Estimated Fair Value Carrying Amount Carrying Amount Thousands Long-term debt including amount due within one year $ 499,027 $ 567,926 $ 500,319 $ 562,688 Fair value of the long-term debt was estimated using market prices on the valuation date for debt with similar credit ratings, maturities, interest rates and other terms. 11. USE OF FINANCIAL DERIVATIVES: NW Natural enters into short-term, medium-term and long-term natural gas purchase contracts with suppliers, including contracts tied to market-based index prices, and thus is exposed to changes in commodity 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 float- ing 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 annual rate changes under the PGA rate mechanisms, thereby limiting customers’ exposure to frequent changes in purchased gas costs. The estimated fair value of gains and losses from commod- ity 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 gas purchase cost from NW Natural’s physical supply contracts. Certain natural gas purchases from Canadian suppliers are in- voiced in Canadian dollars, including both commodity and demand charges, thereby exposing NW Natural to adverse changes in for- eign 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 currency contracts for demand costs have terms ranging up to 24 months. The gains and losses on the shorter-term currency contracts 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 recording a cor- responding amount to a deferred asset or liability account. 50 N W N AT U R A L NW Natural did not use any derivative instruments to hedge oil or propane prices or interest rates during 2004, 2003 or 2002. At Dec. 31, 2004, NW Natural had the following derivatives out- standing: a series of 24 fixed-price natural gas commodity price fi- nancial swap contracts; four fixed-price natural gas financial call option contracts; and 62 foreign currency forward purchase con- tracts. All of these contracts were designated as cash flow hedges covering exposures to commodity purchase and sale contracts. Un- realized 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 de- ferred account balance under regulatory liabilities or regulatory as- sets because regulatory mechanisms include the realized gains or losses at settlement in utility gas costs subject to regulatory defer- ral treatment. NW Natural also had outstanding at Dec. 31, 2004 two natural gas physical supply contracts with embedded options which did not qualify as a normal purchase or normal sale. The physical supply contracts were entered into using excess gas stor- age and pipeline transportation capacity under the Company’s op- timization program. The estimated fair values (unrealized gains and losses) and the notional amounts of derivative instruments outstanding were as follows: Thousands –––––– Dec. 31, 2004 ––––– –––––– Dec. 31, 2003 –––––– Notional Amount Notional Fair Value Amount Gain (Loss) Fair Value Gain (Loss) Fixed-price natural gas financial swap contracts Fixed-price natural gas financial call option contracts Natural gas physical supply contracts with embedded options Fixed-price natural gas financial swap contracts – gas storage Foreign currency forward purchase contracts Total $ 11,983 $ 375,975 $ 23,285 $ 284,317 (2,195) 28,357 366 19,761 24 4,250 658 4,406 – – – – 442 6,417 __________ __________ __________ __________ 23,885 $ 310,495 $ __________ __________ __________ __________ __________ __________ __________ __________ 10,912 $ 427,448 $ 14,460 234 In 2004 and 2003, NW Natural realized net gains of $42.4 mil- lion and $32.4 million, respectively, from the settlement of natural gas commodity swap and call option contracts, which were re- corded as decreases to the cost of gas, compared to net losses of $75.5 million during 2002, which were recorded as increases to the cost of gas. The currency exchange rate in all foreign 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. Any change in value of cash flow hedge contracts that is not included in regulatory recovery is in- cluded in OCI. The fair value of derivative instruments at Dec. 31, 2004 and 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 cal- culations for other contracts with similar terms and conditions. The market prices for the foreign currency forward contracts were based on currency exchange rates quoted by The Bank of Canada. As of Dec. 31, 2004, five of the natural gas commodity price swap contracts extended beyond Dec. 31, 2005, and two extended beyond Oct. 31, 2006. None of the natural gas commodity call op- tion contracts extends beyond March 31, 2005. 12. COMMITMENTS AND CONTINGENCIES: Lease Commitments The Company leases land, buildings and equipment under agreements that expire in various years through 2018. Rental ex- pense under operating leases was $4.5 million, $4.9 million and $4.8 million for the years ended Dec. 31, 2004, 2003 and 2002, re- spectively. The table below reflects the future minimum lease pay- ments due under non-cancelable leases at Dec. 31, 2004. Such pay- ments total $60.8 million for operating leases. The net present value of payments on capital leases less imputed interest was $0.5 million. These commitments principally relate to the lease of the Company’s office headquarters, underground gas storage facilities, vehicles and computer equipment. Millions 2005 2006 2007 2008 2009 Later years Operating leases Capital leases Minimum lease payments $ 4.5 $ 4.2 $ 4.1 $ 4.0 $ 3.9 $ 39.6 – 0.2 ______ ______ ______ ______ ______ ______ 0.2 0.1 – – $ 4.7 $ 4.4 $ 4.2 $ 4.0 $ 3.9 $ 39.6 ______ ______ ______ ______ ______ ______ ______ ______ ______ ______ ______ ______ Pipeline Capacity Purchase and Release Commitments NW Natural has signed agreements providing for the reserva- tion of firm pipeline capacity under which it must make fixed monthly payments for contracted capacity. The pricing component of the monthly payment is established, subject to change, by U.S. or Canadian regulatory bodies. In addition, NW Natural has en- tered into long-term sale agreements to release firm pipeline capac- ity. The aggregate amounts of these agreements were as follows at Dec. 31, 2004: Thousands 2005 2006 2007 2008 2009 2010 through 2024 Total Less: Amount representing interest Total at present value Pipeline Capacity Purchase Agreements Pipeline Capacity Release Agreements $ 66,703 $ 61,514 62,696 60,949 54,417 274,891 __________ 581,170 113,024 __________ $ 468,146 $ __________ __________ 3,715 3,715 3,715 3,715 3,715 3,095 __________ 21,670 2,369 __________ 19,301 __________ __________ NW Natural’s total payments of fixed charges under capacity purchase agreements in 2004, 2003 and 2002 were $89.3 million, $86.7 million and $86.2 million, respectively. Included in the amounts for 2004, 2003 and 2002 were reductions for capacity release sales of $3.7 million, $3.7 million and $4.2 million, respectively. In ad- dition, per-unit charges are required to be paid based on the actual quantities shipped under the agreements. In certain take-or-pay purchase commitments, annual deficiencies may be offset by pre- payments subject to recovery over a longer term if future purchases exceed the minimum annual requirements. Environmental Matters NW Natural owns or previously owned properties currently be- ing investigated that may require environmental response. NW Natural has accrued all material loss contingencies relating to en- vironmental matters that it believes to be probable of assertion and reasonably estimable. The Company continues to study the extent of its environmental liabilities, but due to the preliminary nature of the environmental investigations being conducted, the range of loss contingencies beyond the amounts currently accrued, and the probabilities thereof, cannot be reasonably estimated. GASCO SITE. 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 un- der investigation by NW Natural for environmental contamination under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 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 continues to 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 esti- mates its range of remaining liability, including the cost of investi- gation, from among feasible alternatives, at between $1.3 million and $7 million. WACKER SITE. NW Natural previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Siltronic Corporation, formerly Wacker Siltronic Corpo- ration (the Wacker site). In 2000, the ODEQ issued an order requir- ing Wacker and NW Natural to determine the nature and extent of releases of hazardous substances to Willamette River sediments from the Wacker site. In 2004, consultant studies indicated that some benzene is present in the soil at the Wacker site. The ODEQ requested that NW Natural conduct further tests of groundwater and indoor air quality. The work plan for the implementation of the benzene indoor air-sampling program was approved by the ODEQ in November 2004. NW Natural recorded expenses in 2004 totaling $0.1 million for its estimated costs of investigation and ini- tial remediation at the Wacker site. PORTLAND HARBOR. In 1998, the ODEQ and the U.S. Environ- mental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (the Portland Har- bor) that includes the area adjacent to the Gasco site and the Wacker site. In 2000, the EPA listed the Portland Harbor as a Su- perfund site and notified the Company that it is a potentially re- sponsible party. Subsequently, the EPA approved the Programmatic Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor Remedial Investigation/Feasibility Study. NW Natural’s share of the estimated budget to complete the first phase of the work is $1.0 million, which is expected to be com- pleted in 2007. The EPA has indicated that further study in a sec- ond phase will be required; however, the scope of the work to be completed in a second phase has yet to be determined. In April 2004 the Company entered into an Administrative Or- der on Consent (AOC) providing for early action removal of a body of tar in the river sediments adjacent to the Gasco site. In July 2004, the EPA approved an initial work plan for the early action removal. The Company continues to negotiate with the EPA regarding the method and timing of the removal of the body of tar. The Company currently estimates the removal cost to be in the range of $3.0 mil- lion to $5.0 million. In addition, the Company has agreed with the ODEQ to do additional work, if necessary, on the Gasco site in con- junction with the EPA early action remediation work. N W N AT U R A L 51 Notes to Consolidated Financial Statements During 2004, NW Natural accrued additional loss contingencies totaling $4.3 million for the above-described study work and the revised estimate of tar body remediation costs. NW Natural’s liabil- ity is based on its best estimate of probable costs, and if a specific amount is no more or less likely than another amount in the range of probable liability, then the Company recognizes its liability at the lower end of the range of probable liability. Currently available information is insufficient to determine either the total amount of liability, or the higher end of a range for NW Natural’s estimated share of potential future remediation related to the Portland Harbor site. The Company expects to receive additional information when the Remedial Investigation/Feasibility Study report is completed. A preliminary report is expected to be available during 2005. PORTLAND GAS SITE. The City of Portland notified NW Natural that it was planning a sewer improvement project that would in- clude excavation within 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 prelimi- nary 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 during 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 remediation might be required on the site in connec- tion with the sewer project, which has commenced. Available in- formation is insufficient to determine either the total amount of NW Natural’s liability or a probable range, if any, of potential liability. OREGON STEEL MILLS SITE. On Dec. 20, 2004, the Company was served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940’s and 1950’s petroleum wastes generated by the Company’s predecessor, Portland Gas & Coke Company, and nine other third-party defen- dants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The Port’s complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil dis- posal facility as well as a declaratory judgment allocating liability for future remedial action costs. NW Natural does not believe there are facts sufficient to constitute a claim against the Company. CORPS OF ENGINEERS NOTICE OF NONCOMPLIANCE. On July 2, 2004, the U.S. Army Corps of Engineers (Corps) issued to the Com- pany a Notice of Noncompliance (Notice) for discharges of drilling mud into three streams during drilling operations on the Compa- ny’s South Mist Pipeline Extension (SMPE) project. The Corps’ No- tice claimed that the discharges violated the scope of work in per- mits for the drilling. The Company cooperated with the Corps in its investigation and worked closely with the Corps and other state and federal agencies to minimize impacts from the unintended dis- charges. The final disposition of this matter resulted in the payment of a nominal fine. 52 N W N AT U R A L REGULATORY AND INSURANCE RECOVERY FOR ENVIRONMENTAL MATTERS. In May 2003, the OPUC approved NW Natural’s request for deferral of environmental costs associated with specific sites, including the Gasco, Wacker, Portland Harbor and Portland Gas sites. The authorization, which has been extended through April 2005, allows NW Natural to defer and seek recovery of unreim- bursed environmental costs in a future general rate case. On a cu- mulative basis through Dec. 31, 2004, the Company paid out a to- tal of $3.3 million relating to the named sites since the effective date of the deferral authorization. NW Natural will first seek to re- cover the costs of investigation and remediation for which it may be responsible with respect to the Gasco, Wacker, Portland Harbor and Portland Gas sites, if any, from insurance. If these costs are not recovered from insurance, then NW Natural will seek OPUC ap- proval to recover them through future rates. At Dec. 31, 2004, NW Natural had a receivable of $8.5 million representing an estimate of the environmental costs it expects to recover from insurance, consisting of $2.8 million for costs relating to the Gasco site, $5.5 million for costs relating to the Portland Harbor site and $0.2 mil- lion relating to the Oregon Steel Mills site. On Jan. 27, 2005, NW Natural filed a request with the OPUC for authorization to defer costs associated with the Oregon Steel Mills site and to extend the deferral authority for the other named envi- ronmental sites through Jan. 26, 2006. The following table summarizes the insurance receivables and the accrued liabilities relating to environmental matters at Dec. 31, 2004 and 2003. Millions Gasco site Wacker site Portland Harbor site Portland Gas site Oregon Steel Mills site Total –– Insurance Receivable –– –––– Accrued Liability –––– 12/31/03 12/31/04 12/31/04 12/31/03 $ 1.5 2.5 $ – – 0.6 1.2 – – – – __________ __________ __________ __________ 2.1 3.7 $ $ __________ __________ __________ __________ __________ __________ __________ __________ 1.3 $ 0.1 3.4 – 0.2 5.0 $ 2.8 $ – 5.5 – 0.2 8.5 $ Legal Proceedings Litigation On October 16, 2003, Longview Fibre Company (Longview) filed suit in Federal Court (Longview Fibre Company v. Enerfin Re- sources Northwest Limited Partnership and Northwest Natural Gas Company (US District Court – Oregon District)) seeking a declara- tory judgment regarding the continuing existence of a certain oil and gas lease in the Mist gas field between Longview and Enerfin Resources Northwest Limited Partnership (Enerfin). NW Natural holds a gas storage lease from Longview (the Cascade Lease), which covers the same land as the Enerfin lease, and which grants the right to produce native oil and gas. Enerfin originally filed crossclaims against NW Natural alleging that NW Natural wrongly interfered with Enerfin’s attempts to continue its oil and gas lease with Longview; however, Enerfin agreed to dismiss those claims in a previous settlement with NW Natural. In that settlement, NW Natural subleased portions of the Cascade Lease to Enerfin for the purpose of producing native gas. In September 2004, NW Natural and Enerfin filed claims and counterclaims against Longview, and Longview filed claims and counterclaims against NW Natural and Enerfin. The claims that Longview made against NW Natural in- volved allegations of unpaid royalties under the Cascade Lease.  On Dec. 20, 2004, the Company was served with a third-party complaint by the Port of Portland (Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940’s and 1950’s petroleum wastes generated by the Company’s predecessor, Portland Gas & Coke Company, and nine other third-party defendants were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The Port’s complaint seeks contribution for unspecified past remedial action costs in- curred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future re- medial action costs. NW Natural does not believe there are facts sufficient to constitute a claim against the Company. In connection with the construction of the SMPE, NW Natural continues to negotiate with some land owners regarding valuation of easements and rights-of-way obtained pursuant to condemna- tion proceedings. In some cases, compensation will be determined in individual court proceedings that have been scheduled through June 2005. The Company is unable to determine the likelihood of unfavorable outcomes of these matters, but believes that the ag- gregate amount of compensation ultimately paid will not be mate- rial to the Company’s financial condition, results of operations or cash flows. The Company is subject to other claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, the Company does not expect that the ultimate disposition of these matters will have a materially adverse effect on the Company’s fi- nancial condition, results of operations or cash flows. All parties to the Longview litigation entered into a Settlement Agreement, effective Jan. 11, 2005. As part of the settlement, Longview granted NW Natural an easement for use in producing oil and gas from the lands covered by the Cascade Lease. Other than payments made in respect of the easement, and royalty pay- ments under the relevant leases and subleases, which were not material, no payments were made in connection with the Longview settlement. All claims were dismissed on Jan. 28, 2005 pursuant to the Settlement Agreement. On May 28, 2004, a lawsuit was filed against the Company (Kerry Law, Arnold Zuehlke and Kenneth Cooper, on behalf of them- selves and all others similarly situated v. Northwest Natural Gas Company (U.S. Dist. Ct. D. Or., Case No. CV-04-728-AS)) by three individuals alleging violation of the Fair Labor Standards Act for failure to pay overtime. The suit was subsequently amended to in- clude state wage and hour claims. The plaintiffs are or have been independent backhoe operators who performed services for the Company under contract. In the lawsuit, the plaintiffs claim that they, and others similarly situated, should have been considered “employees” of the Company instead of independent contractors. The plaintiffs seek overtime and interest in amounts to be deter- mined, liquidated damages equal to the overtime award, civil pen- alties and attorneys fees and costs. The plaintiffs sought to certify this case as a collective action under the Fair Labor Standards Act; however, on Oct. 5, 2004, plaintiffs’ motion for collective action certification was denied. As a result of this ruling, the case is pro- ceeding with the three current plaintiffs, and any others who wish to join must do so individually. Although no other claims have been filed in this lawsuit, plaintiffs’ counsel has indicated to the court their intention to file additional claims seeking employee ben- efits allegedly due to plaintiffs. In addition, the claims in the law- suit described below may be consolidated with this lawsuit. The Company intends to vigorously contest the claims. There is insuf- ficient information at this point in the litigation to reasonably esti- mate the amount of liability, if any, from this claim. On Feb. 18, 2005, a lawsuit was filed against the Company (Kasey Cooper, Kevin Cooper, C.G. Nick Courtney, John V. Shooter, Ike Whittlesey and Roger Whittlesey v. Northwest Natural (U.S. Dist. Ct. D. Or., Case No. CV-05-241-KI)) by six additional individual in- dependent backhoe operators who have performed services for the Company under contract. Like the plaintiffs in the claim described above, these plaintiffs allege that they should have been considered “employees” of the Company. They seek overtime wages under the Fair Labor Standards Act and interest in amounts to be determined, liquidated damages equal to the overtime award, civil penalties and attorneys fees and costs. In addition, the plaintiffs allege that fail- ure to classify them as employees constituted a breach of contract under certain of the Company’s employee benefit programs, agree- ments and plans, which conferred employment-related compensa- tion, rights and benefits. They seek an unspecified amount of dam- ages for the value of what they would have received under these programs, agreements and plans if they had been classified as em- ployees. The Company intends to vigorously contest the claims. There is insufficient information at this point in the litigation to rea- sonably estimate the amount of liability, if any, from this claim. N W N AT U R A L 53 Comparative Consolidated Income Statements Thousands, except per share amounts (year ended December 31) 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 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 Total operating expenses Income from continuing operations 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 See Notes to Consolidated Financial Statements. $ 707,604 399,244 __________ 308,360 $ 611,256 323,190 __________ 288,066 102,155 38,808 57,371 __________ 198,334 __________ 110,026 2,828 35,751 __________ 77,103 __________ 26,531 __________ 50,572 96,420 35,125 54,249 __________ 185,794 __________ 102,272 2,150 35,099 __________ 69,323 __________ 23,340 __________ 45,983 – – __________ 50,572 – – __________ 45,983 – __________ 50,572 $ __________ __________ 294 __________ 45,689 $ __________ __________ 27,016 27,283 25,741 26,061 $ 1.87 – – __________ 1.87 $ __________ __________ $ 1.77 – – __________ 1.77 $ __________ __________ $ 1.86 – – __________ 1.86 $ __________ __________ $ 1.30 __________ __________ $ 1.76 – – __________ 1.76 $ __________ __________ $ 1.27 __________ __________ *Interest on deferred regulatory accounts for years prior to 1998 was reclassified from gross operating revenues or cost of sales to other income (expense). $ 641,376 353,832 __________ 287,544 $ 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 85,120 34,076 __________ 52,090 171,286 __________ 116,258 (14,890) __________ 34,132 __________ 67,236 __________ 23,444 43,792 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 78,226 21,939 73,864 19,952 76,204 21,597 72,018 24,181 70,881 24,263 __________ 51,008 148,869 __________ __________ 43,937 144,102 __________ __________ 39,051 132,867 __________ __________ 37,971 135,772 __________ __________ 40,594 136,793 __________ __________ 38,058 133,202 __________ 94,768 4,816 86,864 (13,723) 88,243 4,138 93,212 6,891 76,809 9,055 72,460 8,393 __________ 30,052 __________ 69,532 __________ 24,591 44,941 __________ 31,586 __________ 41,555 __________ 14,604 26,951 __________ 28,469 __________ 63,912 __________ 21,034 42,878 __________ 26,711 __________ 73,392 __________ 27,118 46,274 __________ 25,679 __________ 60,185 __________ 22,120 38,065 __________ 24,919 __________ 55,934 __________ 20,473 35,461 – – – 355 350 181 519 – – __________ – __________ – __________ 2,412 __________ – __________ – __________ – __________ – __________ – __________ – 43,792 50,187 50,224 45,296 27,301 43,059 46,793 38,065 35,461 __________ 2,280 $ __________ __________ 41,512 __________ 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 25,431 25,814 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 – – – – – – $ 1.63 $ 1.90 $ 1.80 $ $ 1.70 0.01 $ 1.01 0.01 $ 1.77 0.01 1.95 0.02 $ 1.62 $ __________ – $ __________ __________ 1.63 __________ – $ __________ __________ 1.90 __________ 0.10 $ __________ __________ 1.90 __________ – $ __________ __________ 1.71 __________ – $ __________ __________ 1.02 __________ – $ __________ __________ 1.78 __________ – $ __________ __________ 1.97 __________ – $ __________ __________ 1.62 __________ – $ __________ __________ 1.63 $ 1.62 $ 1.88 $ 1.79 $ $ 1.69 0.01 $ 1.01 0.01 $ 1.75 0.01 1.92 0.02 $ 1.60 $ 1.61 – __________ – $ __________ __________ 1.62 $ __________ __________ 1.26 __________ – $ __________ __________ 1.88 $ __________ __________ 1.245 __________ 0.09 $ __________ __________ 1.88 $ __________ __________ 1.24 __________ – $ __________ __________ 1.70 $ __________ __________ 1.225 __________ – $ __________ __________ 1.02 $ __________ __________ 1.22 __________ – $ __________ __________ 1.76 $ __________ __________ 1.205 __________ – $ __________ __________ 1.94 $ __________ __________ 1.20 __________ – $ __________ __________ 1.60 $ __________ __________ 1.18 __________ – $ __________ __________ 1.61 $ __________ __________ 1.173 19,943 20,577 1.63 – – – UTILITY GAS REVENUES BY CUSTOMER CLASS 2004 8% 2% 90% 8% 4% 1994 88% RESIDENTIAL, COMMERCIAL AND INDUSTRIAL FIRM INDUSTRIAL INTERRUPTIBLE TRANSPORTATION Revenues from residential, commercial and industrial firm sales customers exceed 90 percent of total gas revenues. NET INCOME IN MILLIONS OF DOLLARS $70 $60 $50 $40 $30 $20 $10 94 95 96 97 98 99 00 01 02 03 04 The Company earned $50.6 million in net income in 2004. 54 N W N AT U R A L Thousands, except per share amounts (year ended December 31) 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 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 Total operating expenses Income from continuing operations 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 See Notes to Consolidated Financial Statements. $ 707,604 399,244 __________ 308,360 $ 611,256 323,190 __________ 288,066 102,155 38,808 __________ 57,371 198,334 __________ 110,026 2,828 __________ 35,751 __________ 77,103 __________ 26,531 50,572 96,420 35,125 __________ 54,249 185,794 __________ 102,272 2,150 __________ 35,099 __________ 69,323 __________ 23,340 45,983 – – __________ – __________ – 50,572 45,983 __________ – $ __________ __________ 50,572 __________ 294 $ __________ __________ 45,689 27,016 27,283 25,741 26,061 1.77 – $ 1.87 $ – – __________ – $ __________ __________ 1.87 __________ – $ __________ __________ 1.77 $ 1.86 $ 1.76 – __________ – $ __________ __________ 1.86 $ __________ __________ 1.30 __________ – $ __________ __________ 1.76 $ __________ __________ 1.27 *Interest on deferred regulatory accounts for years prior to 1998 was reclassified from gross operating revenues or cost of sales to other income (expense). $ 641,376 353,832 __________ 287,544 $ 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 85,120 34,076 52,090 __________ 171,286 __________ 116,258 (14,890) 34,132 __________ 67,236 __________ 23,444 __________ 43,792 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 – – __________ 43,792 – – __________ 50,187 – 2,412 __________ 50,224 355 – __________ 45,296 350 – __________ 27,301 181 – __________ 43,059 519 – __________ 46,793 – – __________ 38,065 – – __________ 35,461 2,280 __________ 41,512 $ __________ __________ 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 $ __________ __________ 25,431 25,814 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 $ 1.63 – – __________ 1.63 $ __________ __________ $ 1.90 – – __________ 1.90 $ __________ __________ $ 1.80 – 0.10 __________ 1.90 $ __________ __________ $ 1.70 0.01 – __________ 1.71 $ __________ __________ $ 1.01 0.01 – __________ 1.02 $ __________ __________ $ 1.77 0.01 – __________ 1.78 $ __________ __________ $ 1.95 0.02 – __________ 1.97 $ __________ __________ $ 1.62 – – __________ 1.62 $ __________ __________ $ 1.63 – – __________ 1.63 $ __________ __________ $ 1.62 – – __________ 1.62 $ __________ __________ $ 1.26 __________ __________ $ 1.88 – – __________ 1.88 $ __________ __________ $ 1.245 __________ __________ $ 1.79 – 0.09 __________ 1.88 $ __________ __________ $ 1.24 __________ __________ $ 1.69 0.01 – __________ 1.70 $ __________ __________ $ 1.225 __________ __________ $ 1.01 0.01 – __________ 1.02 $ __________ __________ $ 1.22 __________ __________ $ 1.75 0.01 – __________ 1.76 $ __________ __________ $ 1.205 __________ __________ $ 1.92 0.02 – __________ 1.94 $ __________ __________ $ 1.20 __________ __________ $ 1.60 – – __________ 1.60 $ __________ __________ $ 1.18 __________ __________ $ 1.61 – – __________ 1.61 $ __________ __________ $ 1.173 __________ __________ N W N AT U R A L 55 Comparative Consolidated Balance Sheets Thousands of dollars (December 31) 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 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 Total capital stock 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 $ 1,794,972 505,286 __________ 1,289,686 __________ 33,963 5,244 __________ 28,719 __________ 1,318,405 __________ 60,618 __________ 5,248 60,675 64,401 66,477 – – 40,316 __________ 237,117 __________ 64,734 __________ 9,551 __________ – __________ 41,770 __________ $ 1,732,195 __________ __________ $ 568,517 – – __________ 568,517 __________ 479,500 4,527 __________ 484,027 __________ 1,052,544 __________ – __________ 102,500 102,478 15,000 10,242 2,897 34,168 __________ 267,285 __________ 6,025 __________ 210,715 __________ 5,487 __________ – __________ 153,258 __________ 36,881 __________ $ 1,732,195 __________ __________ $ 1,657,589 471,716 __________ 1,185,873 __________ 23,395 4,855 __________ 18,540 __________ 1,204,413 __________ 73,845 __________ 4,706 48,499 59,109 50,859 – – 32,661 __________ 195,834 __________ 63,449 __________ – __________ – __________ 47,838 __________ $ 1,585,379 __________ __________ $ 506,316 – – __________ 506,316 __________ 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 __________ 44,316 __________ $ 1,585,379 __________ __________ *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 accrued asset removal costs. $ 1,539,965 435,601 __________ 1,104,364 __________ 20,832 __________ 4,404 __________ 16,428 1,120,792 __________ __________ 67,619 $ 1,465,079 398,668 __________ 1,066,411 __________ 18,203 __________ 4,007 __________ 14,196 1,080,607 __________ __________ 76,266 $ 1,406,970 371,437 __________ 1,035,533 __________ 8,649 __________ 3,451 __________ 5,198 1,040,731 __________ __________ 63,638 $ 1,331,415 337,995 __________ 993,420 __________ 8,548 __________ 7,654 __________ 894 994,314 __________ __________ 61,289 $ 1,239,690 313,149 __________ 926,541 __________ 89,050 __________ 29,927 __________ 59,123 985,664 __________ __________ 53,370 $ 1,164,499 283,495 __________ 881,004 __________ 52,422 __________ 22,843 __________ 29,579 910,583 __________ __________ 67,625 $ 1,055,112 260,089 __________ 795,023 __________ 45,689 __________ 19,388 __________ 26,301 821,324 __________ __________ 63,548 $ 969,075 239,493 __________ 729,582 __________ 53,807 __________ 16,997 __________ 36,810 766,392 __________ __________ 62,743 $ 908,238 __________ 216,711 691,527 __________ 49,586 __________ 24,456 __________ 25,130 716,657 __________ __________ 61,420 7,328 46,936 44,069 58,030 – – 10,440 64,722 57,749 49,337 – – 11,283 60,753 45,619 46,883 – – 10,013 43,349 31,550 33,919 29,163 16,712 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 – – __________ 36,934 193,297 __________ __________ 47,975 __________ – __________ – __________ 37,594 $ 1,467,277 __________ __________ __________ 28,086 210,334 __________ __________ 48,469 __________ – __________ 111,641 __________ 23,336 $ 1,550,653 __________ __________ __________ 22,834 187,372 __________ __________ 49,515 __________ 16,973 __________ – __________ 27,185 $ 1,385,414 __________ __________ __________ 18,349 183,055 __________ __________ 51,060 __________ 20,950 __________ – __________ 32,146 $ 1,342,814 __________ __________ __________ 16,105 126,480 __________ __________ 56,860 __________ 27,795 __________ – __________ 32,535 $ 1,282,704 __________ __________ __________ 17,226 104,673 __________ __________ 56,860 __________ 28,628 __________ – __________ 26,360 $ 1,194,729 __________ __________ __________ 12,483 __________ 98,314 __________ 57,940 __________ – __________ – __________ 23,795 $ 1,064,921 __________ __________ __________ 12,396 __________ 90,310 __________ 60,430 __________ – __________ – __________ 18,611 $ 998,486 __________ __________ __________ 10,041 __________ 95,539 __________ 60,430 __________ * __________ – __________ 17,659 $ 951,705 __________ __________ $ 482,392 $ 468,161 $ 452,309 $ 429,596 $ 412,404 $ 366,265 $ 346,778 $ 323,552 $ 274,408 – __________ 8,250 490,642 __________ 439,500 __________ 6,445 445,945 __________ 936,587 __________ __________ – 69,802 74,436 20,000 7,822 2,902 __________ 30,045 205,007 __________ __________ 7,824 141,732 __________ __________ – __________ 10,635 125,197 __________ __________ 40,295 $ 1,467,277 __________ __________ 25,000 __________ 9,000 502,161 __________ 370,000 __________ 8,377 378,377 __________ 880,538 __________ __________ – 108,291 70,698 40,000 22,539 3,658 __________ 28,396 273,582 __________ __________ 8,682 130,424 __________ __________ 111,868 __________ 10,089 115,631 __________ __________ 19,839 $ 1,550,653 __________ __________ 25,000 __________ 9,750 487,059 __________ 382,000 __________ 18,790 400,790 __________ 887,849 __________ __________ – 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 __________ __________ 25,000 __________ 10,564 465,160 __________ 377,000 __________ 19,379 396,379 __________ 861,539 __________ __________ – 25,000 __________ 11,499 448,903 __________ 347,000 __________ 19,738 366,738 __________ 815,641 __________ __________ 16,322 25,000 __________ 12,429 403,694 __________ 324,000 __________ 20,303 344,303 __________ 747,997 __________ __________ – 25,000 __________ 13,749 385,527 __________ 236,000 __________ 35,838 271,838 __________ 657,365 __________ __________ – 25,000 __________ 14,840 363,392 __________ 238,000 __________ 41,945 279,945 __________ 643,337 __________ __________ – 26,252 __________ 15,950 316,610 __________ 234,000 __________ 57,076 291,076 __________ 607,686 __________ __________ – 94,149 68,163 10,000 4,101 4,673 87,264 56,039 10,000 7,486 6,204 89,317 58,775 16,000 4,656 6,058 50,058 64,795 26,000 3,196 5,396 28,832 41,784 21,000 10,281 4,617 53,654 48,517 1,000 6,584 4,570 __________ 39,153 220,239 __________ __________ 10,393 136,150 __________ __________ – __________ – __________ 98,391 __________ 16,102 $ 1,342,814 __________ __________ __________ 23,477 190,470 __________ __________ 11,248 140,310 __________ __________ – __________ – __________ 90,968 __________ 17,745 $ 1,282,704 __________ __________ __________ 21,390 196,196 __________ __________ 11,949 139,953 __________ __________ – __________ – __________ 83,112 __________ 15,522 $ 1,194,729 __________ __________ __________ 19,418 168,863 __________ __________ 11,668 123,625 __________ __________ – __________ 8,058 __________ 76,052 __________ 19,290 $ 1,064,921 __________ __________ __________ 13,204 119,718 __________ __________ 12,493 118,692 __________ __________ – __________ 19,914 __________ 69,209 __________ 15,123 $ 998,486 __________ __________ __________ 11,757 126,082 __________ __________ 13,530 112,433 __________ __________ – __________ * __________ 62,401 __________ 29,573 $ 951,705 __________ __________ NET UTILITY PLANT IN MILLIONS OF DOLLARS $1,250 $1,000 $750 $500 $250 94 95 96 97 98 99 00 01 02 03 04 Utility plant continued to increase in 2004 as a result of customer growth and investments in infrastructure and gas storage. CAPITALIZATION IN MILLIONS OF DOLLARS $1200 $1000 $800 $600 $400 $200 94 95 96 97 98 99 00 01 02 03 04 COMMON EQUITY PREFERRED AND PREFERENCE STOCK LONG-TERM DEBT SHORT-TERM DEBT $35.1 million in cash dividends were paid to common share- holders in 2004; $40 million in new common equity was issued; no long-term debt was issued or retired. 56 N W N AT U R A L Thousands of dollars (December 31) 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 Assets: Plant and property: Utility plant Utility plant – net Non-utility property Less accumulated depreciation** 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 Unrealized loss on non-trading derivatives Total current assets Regulatory tax assets Deferred gas costs receivable Deferred debits and other Total assets Capitalization and liabilities: Capitalization: Common stock equity Redeemable preference stock Redeemable preferred stock Total capital stock First mortgage bonds Unsecured debt Total long-term debt Total capitalization Minority interest Current liabilities: Notes payable Accounts payable Taxes accrued Interest accrued Long-term debt due within one year 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 $ 1,794,972 505,286 __________ 1,289,686 __________ 33,963 __________ 5,244 __________ 28,719 1,318,405 __________ __________ 60,618 $ 1,657,589 471,716 __________ 1,185,873 __________ 23,395 __________ 4,855 __________ 18,540 1,204,413 __________ __________ 73,845 5,248 60,675 64,401 66,477 – – 4,706 48,499 59,109 50,859 – – __________ 40,316 237,117 __________ __________ 64,734 __________ 9,551 __________ – __________ 41,770 $ 1,732,195 __________ __________ __________ 32,661 195,834 __________ __________ 63,449 __________ – __________ – __________ 47,838 $ 1,585,379 __________ __________ $ 568,517 $ 506,316 – __________ – 568,517 __________ 479,500 __________ 4,527 484,027 __________ 1,052,544 __________ __________ – 102,500 102,478 15,000 10,242 2,897 __________ 34,168 267,285 __________ __________ 6,025 210,715 __________ __________ 5,487 __________ – 153,258 __________ __________ 36,881 $ 1,732,195 __________ __________ – __________ – 506,316 __________ 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 __________ __________ 44,316 $ 1,585,379 __________ __________ *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 accrued asset removal costs. $ 1,539,965 435,601 __________ 1,104,364 __________ 20,832 4,404 __________ 16,428 __________ 1,120,792 __________ 67,619 __________ 7,328 46,936 44,069 58,030 – – 36,934 __________ 193,297 __________ 47,975 __________ – __________ – __________ 37,594 __________ $ 1,467,277 __________ __________ $ 482,392 – 8,250 __________ 490,642 __________ 439,500 6,445 __________ 445,945 __________ 936,587 __________ – __________ 69,802 74,436 20,000 7,822 2,902 30,045 __________ 205,007 __________ 7,824 __________ 141,732 __________ – __________ 10,635 __________ 125,197 __________ 40,295 __________ $ 1,467,277 __________ __________ $ 1,465,079 398,668 __________ 1,066,411 __________ 18,203 4,007 __________ 14,196 __________ 1,080,607 __________ 76,266 __________ 10,440 64,722 57,749 49,337 – – 28,086 __________ 210,334 __________ 48,469 __________ – __________ 111,641 __________ 23,336 __________ $ 1,550,653 __________ __________ $ 468,161 25,000 9,000 __________ 502,161 __________ 370,000 8,377 __________ 378,377 __________ 880,538 __________ – __________ 108,291 70,698 40,000 22,539 3,658 28,396 __________ 273,582 __________ 8,682 __________ 130,424 __________ 111,868 __________ 10,089 __________ 115,631 __________ 19,839 __________ $ 1,550,653 __________ __________ $ 1,406,970 371,437 __________ 1,035,533 __________ 8,649 3,451 __________ 5,198 __________ 1,040,731 __________ 63,638 __________ 11,283 60,753 45,619 46,883 – – 22,834 __________ 187,372 __________ 49,515 __________ 16,973 __________ – __________ 27,185 __________ $ 1,385,414 __________ __________ $ 452,309 25,000 9,750 __________ 487,059 __________ 382,000 18,790 __________ 400,790 __________ 887,849 __________ – __________ 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 __________ __________ $ 1,331,415 337,995 __________ 993,420 __________ 8,548 7,654 __________ 894 __________ 994,314 __________ 61,289 __________ 10,013 43,349 31,550 33,919 29,163 16,712 18,349 __________ 183,055 __________ 51,060 __________ 20,950 __________ – __________ 32,146 __________ $ 1,342,814 __________ __________ $ 429,596 25,000 10,564 __________ 465,160 __________ 377,000 19,379 __________ 396,379 __________ 861,539 __________ – __________ 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 __________ __________ $ 1,239,690 313,149 __________ 926,541 __________ 89,050 29,927 __________ 59,123 __________ 985,664 __________ 53,370 __________ 7,383 47,476 34,258 21,258 – – 16,105 __________ 126,480 __________ 56,860 __________ 27,795 __________ – __________ 32,535 __________ $ 1,282,704 __________ __________ $ 412,404 25,000 11,499 __________ 448,903 __________ 347,000 19,738 __________ 366,738 __________ 815,641 __________ 16,322 __________ 87,264 56,039 10,000 7,486 6,204 23,477 __________ 190,470 __________ 11,248 __________ 140,310 __________ – __________ – __________ 90,968 __________ 17,745 __________ $ 1,282,704 __________ __________ $ 1,164,499 283,495 __________ 881,004 __________ 52,422 22,843 __________ 29,579 __________ 910,583 __________ 67,625 __________ 6,731 39,420 23,911 17,385 – – 17,226 __________ 104,673 __________ 56,860 __________ 28,628 __________ – __________ 26,360 __________ $ 1,194,729 __________ __________ $ 366,265 25,000 12,429 __________ 403,694 __________ 324,000 20,303 __________ 344,303 __________ 747,997 __________ – __________ 89,317 58,775 16,000 4,656 6,058 21,390 __________ 196,196 __________ 11,949 __________ 139,953 __________ – __________ – __________ 83,112 __________ 15,522 __________ $ 1,194,729 __________ __________ $ 1,055,112 260,089 __________ 795,023 __________ 45,689 19,388 __________ 26,301 __________ 821,324 __________ 63,548 __________ 8,219 40,833 22,340 14,439 – – 12,483 __________ 98,314 __________ 57,940 __________ – __________ – __________ 23,795 __________ $ 1,064,921 __________ __________ $ 346,778 25,000 13,749 __________ 385,527 __________ 236,000 35,838 __________ 271,838 __________ 657,365 __________ – __________ 50,058 64,795 26,000 3,196 5,396 19,418 __________ 168,863 __________ 11,668 __________ 123,625 __________ – __________ 8,058 __________ 76,052 __________ 19,290 __________ $ 1,064,921 __________ __________ $ 969,075 239,493 __________ 729,582 __________ 53,807 16,997 __________ 36,810 __________ 766,392 __________ 62,743 __________ 7,782 34,385 21,493 14,254 – – 12,396 __________ 90,310 __________ 60,430 __________ – __________ – __________ 18,611 __________ $ 998,486 __________ __________ $ 323,552 25,000 14,840 __________ 363,392 __________ 238,000 41,945 __________ 279,945 __________ 643,337 __________ – __________ 28,832 41,784 21,000 10,281 4,617 13,204 __________ 119,718 __________ 12,493 __________ 118,692 __________ – __________ 19,914 __________ 69,209 __________ 15,123 __________ $ 998,486 __________ __________ $ 908,238 216,711 __________ 691,527 __________ 49,586 24,456 __________ 25,130 __________ 716,657 __________ 61,420 __________ 8,068 42,152 20,320 14,958 – – 10,041 __________ 95,539 __________ 60,430 __________ * __________ – __________ 17,659 __________ $ 951,705 __________ __________ $ 274,408 26,252 15,950 __________ 316,610 __________ 234,000 57,076 __________ 291,076 __________ 607,686 __________ – __________ 53,654 48,517 1,000 6,584 4,570 11,757 __________ 126,082 __________ 13,530 __________ 112,433 __________ – __________ * __________ 62,401 __________ 29,573 __________ $ 951,705 __________ __________ N W N AT U R A L 57 Comparative Financial Statistics YEAR-END MARKET PRICE & BOOK VALUE PER SHARE IN DOLLARS $35 $30 $25 $20 $15 $10 $5 94 95 96 97 98 99 00 01 02 03 04 BOOK VALUE PER SHARE EXCESS OF MARKET PRICE OVER BOOK VALUE PER SHARE The 2004 year-end market-to-book ratio was 1.63x, and the average was 1.53x over the past 10 years. Total return to shareholders (dividends paid plus market appreciation) was 10.9 percent over the 10-year period. HIGH/LOW MARKET PRICE PER SHARE (IN DOLLARS) $35 $30 $25 $20 $15 $10 94 95 96 97 98 99 00 01 02 03 04 HIGH LOW YEAR-END 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 Common stock Ratios – year-end: Price/earnings ratio Dividend yield at year-end rate – % Dividend payout – % Return on average common equity – % Per share data – ($): 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 Capital expenditures (000) $ Depreciation – % of avg depreciable utility plant Accumulated depreciation – % of depreciable utility plant 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 stock Total capital structure 18.0 3.9 69.5 9.4 1.87 1.86 1.30 1.30 20.64 34.13 27.46 33.74 31.061 27,547 27,016 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 3.02 3.07 2.84 2.89 $ 141,485 3.4 $ 124,660 3.5 37.2 38.0 45.6 0.4 ______ 46.0 ______ – – 54.0 ______ 54.0 ______ 100.0 ______ ______ 49.0 0.7 ______ 49.7 ______ – – 50.3 ______ 50.3 ______ 100.0 ______ ______ 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 2.85* 3.29 3.5 37.3 46.9 ______ 0.7 ______ 47.6 0.9 – ______ 51.5 ______ 52.4 100.0 ______ ______ 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 3.14 3.30 3.5 35.8 42.0 ______ 1.0 ______ 43.0 1.0 2.8 ______ 53.2 ______ 57.0 100.0 ______ ______ 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 3.14 3.16 3.5 34.9 44.1 ______ 1.0 ______ 45.1 1.1 2.8 ______ 51.0 ______ 54.9 100.0 ______ ______ 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 3.12 3.19 4.0 33.4 43.6 ______ 2.3 ______ 45.9 1.2 2.9 ______ 50.0 ______ 54.1 100.0 ______ ______ 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 2.20* 2.72 3.9 33.2 42.6 ______ 2.4 ______ 45.0 1.4 3.1 ______ 50.5 ______ 55.0 100.0 ______ ______ 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 2.99 3.05 3.8 32.6 43.3 ______ 2.7 ______ 46.0 1.7 3.3 ______ 49.0 ______ 54.0 100.0 ______ ______ 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 3.53 3.71 3.8 33.2 35.9 ______ 5.5 ______ 41.4 2.1 3.8 ______ 52.7 ______ 58.6 100.0 ______ ______ 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 3.15 2.87 4.2 32.8 37.0 ______ 6.5 ______ 43.5 2.3 3.9 ______ 50.3 ______ 56.5 100.0 ______ ______ 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 3.08 2.98 4.1 31.7 38.5 ______ 9.4 ______ 47.9 2.6 4.3 ______ 45.2 ______ 52.1 100.0 ______ ______ $ 79,530 $ 71,943 $ 80,444 $ 109,144 $ 80,022 $ 115,886 $ 83,400 $ 67,163 $ 77,668 Price per share at year-end increased 72 percent in 10 years. Effective tax rate Effective tax rate – % of pretax income 34% ______ 34% ______ ______ 35% ______ 35% ______ 36% ______ 35% ______ 35% ______ 33% ______ 37% ______ 37% ______ 37% *Includes losses of $0.50 per share in 1998 due to asset write-downs for Financial Corporation and Canor, and a loss of $0.33 per share in 2002 for PGE acquisition costs. 58 N W N AT U R A L 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 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 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 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 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 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 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 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 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 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 2.85* 3.29 3.14 3.30 3.14 3.16 3.12 3.19 2.20* 2.72 2.99 3.05 3.53 3.71 3.15 2.87 3.08 2.98 $ 141,485 $ 124,660 $ 79,530 3.5 $ 71,943 3.5 $ 80,444 3.5 $ 109,144 4.0 $ 80,022 3.9 $ 115,886 3.8 $ 83,400 3.8 $ 67,163 4.2 $ 77,668 4.1 37.3 35.8 34.9 33.4 33.2 32.6 33.2 32.8 31.7 46.9 0.7 ______ 47.6 ______ 0.9 – 51.5 ______ 52.4 ______ 100.0 ______ ______ 42.0 1.0 ______ 43.0 ______ 1.0 2.8 53.2 ______ 57.0 ______ 100.0 ______ ______ 44.1 1.0 ______ 45.1 ______ 1.1 2.8 51.0 ______ 54.9 ______ 100.0 ______ ______ 43.6 2.3 ______ 45.9 ______ 1.2 2.9 50.0 ______ 54.1 ______ 100.0 ______ ______ 42.6 2.4 ______ 45.0 ______ 1.4 3.1 50.5 ______ 55.0 ______ 100.0 ______ ______ 43.3 2.7 ______ 46.0 ______ 1.7 3.3 49.0 ______ 54.0 ______ 100.0 ______ ______ 35.9 5.5 ______ 41.4 ______ 2.1 3.8 52.7 ______ 58.6 ______ 100.0 ______ ______ 37.0 6.5 ______ 43.5 ______ 2.3 3.9 50.3 ______ 56.5 ______ 100.0 ______ ______ 38.5 9.4 ______ 47.9 ______ 2.6 4.3 45.2 ______ 52.1 ______ 100.0 ______ ______ Effective tax rate – % of pretax income ______ 34% ______ 34% 35% ______ 35% ______ 36% ______ 35% ______ 35% ______ 33% ______ 37% ______ 37% ______ 37% ______ Number of shares of common stock outstanding (000): 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 Year-end Average Coverage data – times earned Fixed charges – Securities and Exchange Commission Fixed charges – Standard & Poor’s Utility plant Capital expenditures (000) $ Depreciation – % of avg depreciable utility plant Accumulated depreciation – % of depreciable utility plant 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 stock Total capital structure Effective tax rate 18.0 3.9 69.5 9.4 1.87 1.86 1.30 1.30 20.64 34.13 27.46 33.74 31.061 27,547 27,016 3.02 3.07 3.4 37.2 45.6 ______ 0.4 ______ 46.0 – – ______ 54.0 ______ 54.0 100.0 ______ ______ 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 2.84 2.89 3.5 38.0 49.0 ______ 0.7 ______ 49.7 – – ______ 50.3 ______ 50.3 100.0 ______ ______ *Includes losses of $0.50 per share in 1998 due to asset write-downs for Financial Corporation and Canor, and a loss of $0.33 per share in 2002 for PGE acquisition costs. N W N AT U R A L 59 Comparative Operating Statistics COST OF PURCHASED GAS IN CENTS PER THERM $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 94 95 96 97 98 99 00 01 02 03 04 Cost of gas, including demand charges, increased 20 percent in 2004 and was 141 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 94 95 96 97 98 99 00 01 02 03 04 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. 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 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 537,152 58,548 658 193 __________ 596,551 84 __________ 596,635 __________ __________ 519,427 57,969 478 165 __________ 578,039 111 __________ 578,150 __________ __________ 356,199 226,490 63,149 104,278 __________ 750,116 389,514 (7,764) __________ 1,131,866 __________ __________ 343,534 226,257 55,314 47,994 __________ 673,099 414,554 12,099 __________ 1,099,752 __________ __________ $ 381,526 199,725 44,625 55,380 __________ 681,256 12,655 3,849 3,185 __________ 700,945 399,176 __________ 301,769 6,591 __________ $ 308,360 __________ __________ $ 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 __________ __________ 3,853 4,202 677 3,907 107.1 88.2 70.7 53.1 90.8 3,952 4,236 673 4,004 95.6 78.0 60.7 49.3 83.5 756,672 56.60 53.77 7,177 8,913 683,331 46.99 47.16 4,851 6,310 47,837 $ 27,309 __________ 75,146 $ __________ __________ 1,288 721 43,993 $ 27,450 __________ 71,443 $ __________ __________ 1,291 724 503,402 485,207 468,087 447,659 425,606 407,061 385,213 363,903 346,950 56,087 306 55,096 383 54,684 384 52,870 388 51,159 411 50,315 403 47,309 407 45,402 410 44,078 401 __________ 31 __________ 148 __________ 126 __________ 115 __________ 108 __________ 122 __________ 119 __________ 143 __________ 142 559,826 __________ 241 560,067 __________ __________ 540,834 __________ 97 540,931 __________ __________ 523,281 __________ 125 523,406 __________ __________ 501,032 __________ 131 501,163 __________ __________ 477,284 __________ 123 477,407 __________ __________ 457,901 __________ 120 458,021 __________ __________ 433,048 __________ 121 433,169 __________ __________ 409,858 __________ 91 409,949 __________ __________ 391,571 __________ 67 391,638 __________ __________ 357,091 240,155 63,215 350,065 242,293 79,778 356,375 250,380 76,559 352,969 252,382 84,630 315,686 229,124 87,275 306,356 225,249 84,523 306,310 225,115 91,122 256,462 196,723 82,958 260,218 201,925 81,348 __________ 26,241 __________ 63,597 __________ 56,632 __________ 52,938 __________ 51,521 __________ 53,929 __________ 63,261 __________ 84,173 __________ 89,899 686,702 445,999 735,733 385,783 __________ (6,617) __________ 1,771 1,126,084 __________ __________ 1,123,287 __________ __________ 739,946 431,136 __________ 8,691 1,179,773 __________ __________ 742,919 480,570 683,606 446,165 __________ (9,343) __________ 8,645 1,214,146 __________ __________ 1,138,416 __________ __________ 670,057 440,452 __________ 3,615 1,114,124 __________ __________ 685,808 410,062 __________ 3,759 1,099,629 __________ __________ 620,316 379,116 __________ 4,946 1,004,378 __________ __________ 633,390 364,461 __________ (7,519) 990,332 __________ __________ $ 354,735 $ 329,905 $ 280,642 $ 242,952 $ 205,388 $ 177,835 $ 183,802 $ 165,662 $ 176,510 201,475 190,236 159,660 139,425 117,889 100,677 104,582 42,965 49,662 37,378 35,857 34,303 27,025 30,672 99,079 31,268 108,452 34,443 __________ 15,937 __________ 34,283 __________ 23,483 __________ 17,182 __________ 15,337 __________ 13,944 __________ 17,097 __________ 24,113 __________ 27,361 615,112 604,086 501,163 435,416 372,917 319,481 336,153 320,122 346,766 26,020 (12,702) 20,637 13,774 21,491 12,661 21,351 (2,671) 19,958 8,314 22,029 1,647 22,533 1,627 16,650 1,173 14,702 (5,571) __________ 4,018 __________ (2,325) __________ (3,976) __________ 1,194 __________ 2,617 __________ 7,884 __________ 9,824 __________ 9,411 __________ 429 632,448 636,172 531,339 455,290 403,806 351,041 370,137 347,356 356,326 353,034 __________ 364,699 __________ 273,978 __________ 212,021 __________ 173,242 __________ 130,381 __________ 141,789 __________ 142,025 __________ 162,437 __________ 279,414 __________ 8,130 $ 287,544 __________ __________ 271,473 __________ 4,538 $ 276,011 __________ __________ 257,361 __________ 589 $ 257,950 __________ __________ 243,269 __________ 368 $ 243,637 __________ __________ 230,564 __________ 402 $ 230,966 __________ __________ 220,660 __________ 450 $ __________ __________ 221,110 228,348 __________ 636 $ 228,984 __________ __________ 205,331 __________ 8,271 $ 213,602 __________ __________ 193,889 __________ 11,773 $ 205,662 __________ __________ 4,232 4,255 725 4,334 99.3 83.9 68.0 61.7 89.6 51.07 51.91 4,249 6,172 4,325 4,265 738 4,435 94.2 78.5 62.2 54.0 82.1 47.19 49.45 4,247 5,996 4,416 4,273 781 4,670 78.7 63.8 48.8 41.5 67.7 37.68 36.60 4,691 5,814 4,256 4,273 810 4,851 68.8 55.2 42.4 32.5 58.6 27.85 28.90 4,144 6,211 4,011 4,282 749 4,540 65.1 51.5 39.3 29.6 54.6 25.09 25.03 6,414 7,446 4,092 4,297 777 4,670 58.0 44.7 32.0 25.9 47.7 24.05 19.35 4,447 5,744 4,427 4,311 823 4,874 60.0 46.5 33.7 27.0 49.0 22.25 20.56 5,997 7,422 3,779 4,338 726 4,420 64.6 50.4 37.7 28.6 51.6 20.67 22.71 4,375 5,717 4,020 4,364 776 4,680 67.8 53.7 42.3 30.4 54.7 23.44 25.95 3,920 5,291 708,796 739,620 745,582 773,258 712,602 702,820 692,894 640,976 642,607 $ 42,268 $ 40,856 $ 38,979 $ 38,066 $ 37,573 $ 35,669 $ 34,037 $ 33,669 $ 33,888 __________ 26,044 $ __________ __________ 68,312 __________ 25,626 $ __________ __________ 66,482 __________ 24,756 $ __________ __________ 63,735 __________ 24,322 $ __________ __________ 62,388 __________ 24,625 $ __________ __________ 62,198 __________ 24,630 $ __________ __________ 60,299 __________ 22,920 $ __________ __________ 56,957 __________ 22,074 $ __________ __________ 55,743 __________ 20,795 $ __________ __________ 54,683 1,261 714 1,284 671 1,315 646 1,275 643 1,303 611 1,337 583 1,304 560 1,288 533 1,338 478 *Interest on deferred regulatory accounts for years prior to 1998 was reclassified from gross operating revenues or cost of sales to other income (expense). 60 N W N AT U R A L Gas sales and transportation deliveries (000 therms) Selected Utility Data Customers at year-end Residential Commercial Industrial firm Industrial interruptible Total sales customers Transportation customers Total customers Residential Commercial Industrial firm Industrial interruptible Total gas sales Transportation Unbilled therms Total volumes delivered Sales revenues: Residential Commercial Industrial firm Industrial interruptible Total gas sales revenues Transportation Unbilled revenues Other Operating revenues and cost of sales (000)* 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: Average rate per therm (cents): Residential Commercial 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 537,152 519,427 58,548 658 57,969 478 __________ 193 __________ 165 596,551 __________ 84 596,635 __________ __________ 578,039 __________ 111 578,150 __________ __________ 356,199 226,490 63,149 343,534 226,257 55,314 104,278 __________ __________ 47,994 750,116 389,514 673,099 414,554 __________ (7,764) __________ 12,099 1,131,866 __________ __________ 1,099,752 __________ __________ $ 381,526 $ 328,464 199,725 176,385 44,625 33,578 __________ 55,380 __________ 23,661 681,256 562,088 12,655 3,849 17,962 14,474 __________ 3,185 __________ 7,460 700,945 601,984 399,176 __________ 323,128 __________ 301,769 __________ 6,591 $ 308,360 __________ __________ 278,856 __________ 9,210 $ 288,066 __________ __________ 3,853 4,202 677 3,907 107.1 88.2 70.7 53.1 90.8 56.60 53.77 7,177 8,913 3,952 4,236 673 4,004 95.6 78.0 60.7 49.3 83.5 46.99 47.16 4,851 6,310 756,672 683,331 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 503,402 56,087 306 31 __________ 559,826 241 __________ 560,067 __________ __________ 485,207 55,096 383 148 __________ 540,834 97 __________ 540,931 __________ __________ 468,087 54,684 384 126 __________ 523,281 125 __________ 523,406 __________ __________ 447,659 52,870 388 115 __________ 501,032 131 __________ 501,163 __________ __________ 425,606 51,159 411 108 __________ 477,284 123 __________ 477,407 __________ __________ 407,061 50,315 403 122 __________ 457,901 120 __________ 458,021 __________ __________ 385,213 47,309 407 119 __________ 433,048 121 __________ 433,169 __________ __________ 363,903 45,402 410 143 __________ 409,858 91 __________ 409,949 __________ __________ 346,950 44,078 401 142 __________ 391,571 67 __________ 391,638 __________ __________ 357,091 240,155 63,215 26,241 __________ 686,702 445,999 (6,617) __________ 1,126,084 __________ __________ 350,065 242,293 79,778 63,597 __________ 735,733 385,783 1,771 __________ 1,123,287 __________ __________ 356,375 250,380 76,559 56,632 __________ 739,946 431,136 8,691 __________ 1,179,773 __________ __________ 352,969 252,382 84,630 52,938 __________ 742,919 480,570 (9,343) __________ 1,214,146 __________ __________ 315,686 229,124 87,275 51,521 __________ 683,606 446,165 8,645 __________ 1,138,416 __________ __________ 306,356 225,249 84,523 53,929 __________ 670,057 440,452 3,615 __________ 1,114,124 __________ __________ 306,310 225,115 91,122 63,261 __________ 685,808 410,062 3,759 __________ 1,099,629 __________ __________ 256,462 196,723 82,958 84,173 __________ 620,316 379,116 4,946 __________ 1,004,378 __________ __________ 260,218 201,925 81,348 89,899 __________ 633,390 364,461 (7,519) __________ 990,332 __________ __________ $ 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 __________ __________ $ 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 __________ __________ $ 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 __________ __________ $ 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 $ __________ __________ $ 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 __________ __________ $ 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 __________ __________ $ 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 __________ __________ 4,232 4,255 725 4,334 99.3 83.9 68.0 61.7 89.6 4,325 4,265 738 4,435 94.2 78.5 62.2 54.0 82.1 4,416 4,273 781 4,670 78.7 63.8 48.8 41.5 67.7 4,256 4,273 810 4,851 68.8 55.2 42.4 32.5 58.6 4,011 4,282 749 4,540 65.1 51.5 39.3 29.6 54.6 4,092 4,297 777 4,670 58.0 44.7 32.0 25.9 47.7 4,427 4,311 823 4,874 60.0 46.5 33.7 27.0 49.0 3,779 4,338 726 4,420 64.6 50.4 37.7 28.6 51.6 4,020 4,364 776 4,680 67.8 53.7 42.3 30.4 54.7 708,796 51.07 51.91 4,249 6,172 739,620 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 Number of customers served by each operating employee *Interest on deferred regulatory accounts for years prior to 1998 was reclassified from gross operating revenues or cost of sales to other income (expense). $ 47,837 $ 43,993 __________ 27,309 $ __________ __________ 75,146 __________ 27,450 $ __________ __________ 71,443 1,288 721 1,291 724 42,268 $ 26,044 __________ 68,312 $ __________ __________ 1,261 714 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 N W N AT U R A L 61 Board of Directors Timothy Boyle Timothy P. Boyle, 55, 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. Martha (Stormy) Byorum Ms. Byorum, 56, is Senior Managing Director, Stephens Cori Capital Advisors, a private equity advisory and investment banking firm located in New York City. She was elected to the Board in 2004 and serves as a member of the Finance Committee. John Carter A member of the NW Natural Board since 2002, John D. Carter, 59, chairs the Board’s Governance Committee. He is also a member of the Audit and Finance Committees. Mr. Carter is a principal with Imeson & 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, 60. Previously he served as NW Natural’s General Counsel and Senior Vice President, Public Affairs. He has served on the Board since 2003. Scott Gibson C. Scott Gibson, 52, is President of Gibson Enterprises, a company that manages private investments in Portland, Oregon. Mr. Gibson joined the NW Natural Board in 2002. He is Chair of the Public Affairs and Environmental Policy Committee and a member of the Strategic Planning Committee and the Organization and Executive Compensation Committee. Tod Hamachek Chair of the Strategic Planning Committee, Tod R. Hamachek, 59, has served on the NW Natural Board since 1986. Mr. Hamachek is also a member of the Board’s Audit and Governance Committees. Until February 2005, he served as Chairman and Chief Executive Officer of Penwest Pharmaceuticals Company, a firm that develops pharma- ceutical drug delivery products and tech- nologies in Danbury, Connecticut. Randall Papé A member of the Board since 1996, Randall C. Papé, 54, 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 its Public Affairs and Environmental Policy Committee. Richard Reiten Retired Chairman of the Board, Richard G. Reiten, 65, has been a member of the Board since 1996. Mr. Reiten was President and Chief Executive Officer of NW Natural. He also served as President and Chief Operating Officer of Portland General Electric from 1992-1995. 62 Richard Woolworth Elected to the Board in 2000, Richard L. Woolworth, 63, chairs the Audit Committee, and was selected to serve as Chair of the Board effective March 1, 2005. He also serves on the Governance Committee and the Organization 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. Below: (left to right) John Carter, Richard Reiten, Scott Gibson, Richard Woolworth, Russell Tromley, Tod Hamachek, Randall Papé, Mark Dodson, Stormy Byorum and Timothy Boyle. Kenneth Thrasher, not pictured. Mr. Reiten serves on the Finance Committee, the Public Affairs and Environmental Policy Committee and the Strategic Planning Committee. Kenneth Thrasher Elected to the Board of Directors in February 2005, Ken Thrasher, 55, is Chairman and Chief Executive Officer of Compli Corporation, a software solution provider for corporate compliance man- agement in employment practices and governance. Mr. Thrasher served as an executive for 19 years with Fred Meyer, Inc., including President and Chief Executive Officer from 1999-2001. Russell Tromley The Chair of the Organization and Executive Compensation Committee is Russell F. Tromley, 65. 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 non- ferrous metals. In Memoriam Ronald Miller 1919-2004 President and CEO 1975-1984 Chairman of the Board 1984-1988 Melody Teppola 1942-2004 Director 1987-2004 Corporate Officers David H. Anderson, 43 [2004] Senior Vice President and Chief Financial Officer (2004- ) Senior Vice President and Chief Financial Officer, TXU Gas (2004) Corporate Controller & Principal Accounting Officer, TXU Corp. (2003-2004) Vice President, Investor Relations & Shareholder Services, TXU Corp. (1997-2003) Mark S. Dodson, 60 [1997] President, Chief Executive Officer (2003- ) President, Chief Operating Officer (2001-2002) General Counsel (1997-2002) Senior Vice President, Public Affairs (1997-2001) Lea Anne Doolittle, 50 [2000] Vice President, Human Resources (2000- ) Director of Compensation, PacifiCorp (1993-2000) Stephen P. Feltz, 49 [1982] Treasurer and Controller (1999- ) Assistant Treasurer and Manager, General Accounting (1996-1999) Gregg S. Kantor, 47 [1996] Senior Vice President, Public and Regulatory Affairs (2003- ) Vice President, Public Affairs and Communications (1998-2002) Richelle T. Luther, 36 [2002] Assistant Secretary (2002- ) Associate, Stoel Rives LLP (1997-2002) Michael S. McCoy, 61 [1969] Executive Vice President, Customer and Utility Operations (2000- ) Senior Vice President, Customer and Utility Operations (1999-2000) 64 C. J. Rue, 59 [1974] Secretary (1982- ) Assistant Treasurer (1987- ) [Date joined NW Natural] Corporate Profile NW Natural is a 146-year-old natural gas local distribution company headquartered in Portland, Oregon. The Company has added customers at a rate of 3 percent or more per year for 18 consecutive years. NW Natural serves about 600,000 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 distribu- tion system in the past 10 years. In keeping with its steady growth, the Company has increased annual dividends paid to shareholders every year for 49 consecutive years. NW Natural purchases natural gas for its core market from a variety of suppliers in the western United States and Canada. The Company also operates an underground gas storage facility in Columbia County, Oregon, and contracts for additional gas storage outside its service area. NW Natural operates two liquefied natural gas plants in its service area. The Company also provides interstate storage services to other energy companies in the Northwest interstate market, using capacity that has been developed in advance of its core customers’ needs. Service Territory Earnings Financial facts ($000): Net operating revenues Net income Earnings aplicable to common stock Financial ratios (%): Return on average common equity Capital structure at year-end Long-term debt Preferred and preference stock Common stock equity Common stock Shareholder data: Common shareholders Average shares outstanding (000) Per share data ($): Basic earnings Diluted earnings Dividends paid on common stock Book value at year-end Market value at year-end Operating highlights Gas sales and transportation deliveries (000 therms) Degree days (25-year average, 4,202) Customers at year-end Number of utility employees Dividends paid on common stock Payment date (per share) February 15 May 15 August 15 November 15 Total dividends paid 2004 2003 Percent increase (decrease) 7 10 11 1 (3) 5 6 6 2 6 10 3 (3) 3 – 308,360 50,572 50,572 288,066 45,983 45,689 9.4 46.0 – 54.0 9.3 49.7 – 50.3 9,359 27,016 9,695 25,741 1.87 1.86 1.30 20.64 33.74 1.77 1.76 1.27 19.52 30.75 1,131,866 1,099,752 3,952 578,150 1,291 3,853 596,635 1,288 2004 2003 $ 0.325 $ 0.315 $ 0.325 $ 0.315 $ 0.325 $ 0.315 $ 0.325 $ 0.325 ________ ________ $ 1.300 $ 1.270 ________ ________ ________ ________ Astoria Mist WASHINGTON 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 Coos County Pipeline Service territory LNG plant District offices Mist underground storage $1.30 $1.29 $1.28 $1.27 $1.26 $1.25 $1.24 $1.23 $1.22 $1.21 $1.20 DIVIDENDS PAID PER SHARE IN DOLLARS DILUTED EARNINGS PER SHARE IN DOLLARS $2.00 $1.75 $1.50 $1.25 $1.00 $0.75 $0.50 $0.25 On the cover: A NW Natural truck strikes out for new territory — the southern Oregon coast. Coos County residents welcomed natural gas service to their communities in 2004. Annual dividends paid per share in 2004 increased for the 49th consecutive year, a growth record matched by few companies. Diluted earnings per share were $1.86 per share in 2004, up 6 percent over 2003. 99 00 01 02 03 04 99 00 01 02 03 04 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 r e d l 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 o e v n e C 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 Corporate Information Notice of Annual Meeting The 2005 Annual Meeting will be held at 2 p.m., Thursday, May 26, in the Colonel Lindbergh Room of the Embassy Suites Hotel, 319 S.W. Pine Street, Portland, Oregon. A meeting notice and proxy statement will be sent to all shareholders in mid-April. Stock Transfer Agent and Registrar For the Common Stock: American Stock Transfer & Trust Company 59 Maiden Lane New York, New York 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 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 15, 2005 May 13, 2005 August 15, 2005 November 15, 2005 Common Stock Prices The Company’s common stock is listed and trades on the New York Stock Exchange (NYSE) under the symbol NWN. The quarterly high and low trading range during 2003 and 2004 was: 2004 Quarter 1 2 3 4 High $ 33.00 31.65 32.37 34.13 Low $ 29.95 27.46 28.84 30.77 2003 Quarter 1 2 3 4 High $ 28.47 28.88 30.11 31.30 Low $ 24.05 24.77 27.02 28.51 Certifications The Chief Executive Officer certified to the NYSE on June 7, 2004 that, as of that date, he was not aware of any violation by the Company of NYSE’s corporate governance listing standards, and the Company has filed with the Securities and Exchange Commission, as exhibits 31.1 and 31.2 to its Annual Report on Form 10-K for the year ended Dec. 31, 2004, the certificates of the Chief Executive Officer and the Chief Financial Officer of the Company certifying the quality of the Company’s public disclosure. 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 Director Independence Standards Code of Ethics Board Committee Charters 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. Quarterly Financial Information (unaudited) Dollars (thousands except per share amounts) March 31 ———————— Quarter ended ———————— June 30 Sept. 30 Dec. 31 Total 2004 Operating revenues Net operating revenues Net income (loss) Basic earnings (loss) per share Diluted earnings (loss) per share 2003 Operating revenues Net operating revenues Net income (loss) Basic earnings (loss) per share Diluted earnings (loss) per share $ 254,450 $ 106,659 $ 112,034 32,612 1.26 1.24 52,629 (716) (0.03) (0.03) 81,441 $ 262,054 $ 704,604 308,360 39,483 50,572 (8,285) 1.87* (0.30) 1.86* (0.30) 104,214 26,961 0.98 0.97 $ 206,539 $ 117,489 $ 98,588 26,404 1.03 1.01 58,549 4,462 0.17 0.17 69,481 $ 217,747 $ 611,256 288,066 91,464 39,465 45,983 21,663 (6,546) 1.77* 0.84 (0.25) 1.76* 0.83 (0.25) *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 may not equal earnings per share for the year. Variations in earnings between quarterly periods are due primarily to the seasonal nature of the Company’s business. Shareholder Information James R. Boehlke Investor Relations (503) 721-2451 (800) 422-4012, Ext. 2451 jrb@nwnatural.com Carol M. Frary Shareholder Services (503) 220-2590 (800) 422-4012, Ext. 3412 cmf@nwnatural.com 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 Company’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 Commission on Forms 10-K and 10-Q. 220 NW Second Avenue Portland, Oregon 97209 www.nwnatural.com N W N a t u r a l 2 0 0 4 A n n u a l R e p o r t 2004 Annual Report Ahead of the curve 

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