-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, TXJ7zjjRfmnk6lZ4xZzoQZV4zC0FENhE8vuA+/Dfwh7g6Na/3VIvAC+LxZ2WCZ/v Ys5u0Zn66BeK36K8rgNHFQ== 0000950120-04-000186.txt : 20040309 0000950120-04-000186.hdr.sgml : 20040309 20040309160810 ACCESSION NUMBER: 0000950120-04-000186 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 20031231 FILED AS OF DATE: 20040309 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHWEST NATURAL GAS CO CENTRAL INDEX KEY: 0000073020 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 930256722 STATE OF INCORPORATION: OR FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-15973 FILM NUMBER: 04657630 BUSINESS ADDRESS: STREET 1: 220 NW SECOND AVE CITY: PORTLAND STATE: OR ZIP: 97209 BUSINESS PHONE: 5032264211 10-K 1 form10_k.txt ANNUAL REPORT SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K (Check One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ___________ to____________ Commission file number 0-994 [GRAPHIC OMITTED][GRAPHIC OMITTED] NORTHWEST NATURAL GAS COMPANY (Exact name of registrant as specified in its charter) OREGON 93-0256722 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 220 N.W. SECOND AVENUE, PORTLAND, OREGON 97209 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (503) 226-4211 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered - ------------------- --------------------- Common Stock, $3 1/6 par value, and Common Share Purchase Rights New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Title of each class Shares outstanding on January 1, 2004 - ------------------- ------------------------------------- Preferred Stock, without par value None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [ X ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [ X ] No [ ] As of June 30, 2003, the registrant had 25,726,379 shares of its Common Stock, $3 1/6 par value, outstanding. The aggregate market value of these shares of Common Stock (based upon the closing price of these shares on the New York Stock Exchange on that date) held by non-affiliates was $695,811,500. Indicate number of shares outstanding of each of registrant's classes of common stock as of February 27, 2004: Common Stock, $3 1/6 par value, and Common Share Purchase Rights 25,989,395 DOCUMENTS INCORPORATED BY REFERENCE List documents incorporated by reference and the Part of the Form 10-K into which the document is incorporated. Portions of the Proxy Statement of Company, to be filed in connection with the 2004 Annual Meeting of Shareholders, are incorporated by reference in Part III. NORTHWEST NATURAL GAS COMPANY Annual Report to Securities and Exchange Commission on Form 10-K For the Fiscal Year Ended December 31, 2003 TABLE OF CONTENTS PART I Item 1. Business General...................................................... 3 Subsidiaries................................................. 3 Gas Supply................................................... 4 Interstate Storage Services.................................. 7 Regulation and Rates......................................... 7 Additions to Infrastructure.................................. 9 Pipeline Safety.............................................. 9 Competition and Marketing....................................10 Environment..................................................12 Employees....................................................12 Available Information........................................12 Item 2. Properties.......................................................13 Item 3. Legal Proceedings................................................13 Item 4. Submission of Matters to a Vote of Security Holders..............14 PART II Item 5. Market for the Registrant's Common Equity........................15 Item 6. Selected Financial Data..........................................16 Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition...........................18 Item 7A. Quantitative and Qualitative Disclosures About Market Risk ......39 Item 8. Financial Statements and Supplementary Data......................42 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..........................77 Item 9A. Controls and Procedures..........................................77 PART III Item 10. Directors and Executive Officers of the Registrant...............78 Item 11. Executive Compensation...........................................79 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters...................79 Item 13. Certain Relationships and Related Transactions...................80 Item 14. Principal Accountant Fees and Services...........................80 PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K .................................................80 SIGNATURES .............................................................81 2 NORTHWEST NATURAL GAS COMPANY PART I ITEM 1. BUSINESS General - ------- Northwest Natural Gas Company (NW Natural or the Company) was incorporated under the laws of Oregon in 1910. The Company and its predecessors have supplied gas service to the public since 1859. Since September 1997, it has been doing business as NW Natural. NW Natural is principally engaged in the distribution of natural gas. The Public Utility Commission of Oregon (OPUC) has allocated to NW Natural as its exclusive service area a major portion of western Oregon, including the Portland metropolitan area, most of the Willamette Valley and the coastal area from Astoria to Coos Bay. NW Natural also holds certificates from the Washington Utilities and Transportation Commission (WUTC) granting it exclusive rights to serve portions of three southern Washington counties bordering the Columbia River. Gas service is provided in 98 cities, together with neighboring communities, in 15 Oregon counties, and in nine cities, together with neighboring communities, in three Washington counties. The city of Portland is the principal retail and manufacturing center in the Columbia River Basin, and is a major port for trade with Asia. NW Natural also is engaged in providing natural gas storage and transportation services to interstate customers using storage capacity that has been developed in advance of core utility customers' (residential, commercial and industrial firm) requirements. These services began in 2001 when the Federal Energy Regulatory Commission (FERC) granted NW Natural a limited jurisdiction blanket certificate permitting it to provide storage and transportation services to customers in interstate commerce. Under agreements with the OPUC and WUTC, NW Natural retains the majority of the net income before tax from interstate storage services and credits the balance to its core utility customers. NW Natural has a contract with an independent energy trading company that seeks to optimize the use of NW Natural's assets by trading temporarily unused portions of its upstream pipeline transportation capacity and gas storage capacity. At year-end 2003, NW Natural had 519,427 residential customers, 57,969 commercial customers and 754 industrial customers. Industries served include pulp, paper and other forest products; the manufacture of electronic, electrochemical and electrometallurgical products; the processing of farm and food products; the production of various mineral products; metal fabrication and casting; the production of machine tools, machinery and textiles; the manufacture of asphalt, concrete and rubber; printing and publishing; nurseries; government and educational institutions; and electric generation. Subsidiaries - ------------ The Company operated only one direct, active subsidiary during 2003, NNG Financial Corporation (Financial Corporation). Financial Corporation, a wholly-owned subsidiary of the Company incorporated in Oregon, holds financial investments including limited partnership interests in three solar electric generating plants and two wind power electric generation projects, all located in California, and in two low-income housing projects in Portland, Oregon. Financial Corporation also has one active, wholly-owned subsidiary, KB Pipeline Company (KB Pipeline), which owns a 10 percent interest in an 18-mile interstate natural gas pipeline. KB Pipeline is the operator of the pipeline; however, in December 2003 it gave notice to the pipeline co-owners that it is resigning as pipeline operator effective in June 2004 due to increased obligations resulting from FERC's final regulations implementing Standards of Conduct for Transmission Providers. Those regulations govern the relationship between interstate natural gas pipelines and their energy affiliates or marketing functions and impose obligations previously inapplicable to KB Pipeline with regard to separation of duties and related matters. The regulations will continue to be applicable to KB Pipeline as a co-owner after its resignation as pipeline operator. A second direct, wholly owned subsidiary of the Company, Northwest Energy Corporation (Northwest Energy), also an Oregon corporation, was formed in 2001 to serve as the holding company of NW Natural and Portland General Electric 3 Company (PGE) if the proposed acquisition of PGE had been completed. The Company's agreement to purchase PGE was terminated in 2002. Northwest Energy had no operations in 2003 or 2002. Gas Supply - ---------- General ------- NW Natural meets the needs of its core utility customers through natural gas purchases from a variety of suppliers. NW Natural has a diverse portfolio of short- and medium-term firm gas supply contracts that it supplements, during periods of peak demand, with gas from storage facilities either owned by or contractually committed to NW Natural. NW Natural's goal in purchasing gas for its core market is to meet customers' needs at competitive prices. NW Natural believes that gas supplies available from suppliers in the western United States and Canada are adequate to serve its core market customers for the foreseeable future, and that its cost of gas generally will track market prices. The cost to NW Natural of gas to supply its core market consists of the purchase price paid to suppliers plus charges paid to pipelines to transport the gas to NW Natural's distribution system. While the rates for pipeline transportation and storage services are subject to federal regulation, the purchase price of gas is not. Although pipeline rates have been relatively stable in recent years, natural gas commodity prices have fluctuated dramatically. NW Natural has sought to mitigate the effect of higher gas commodity prices and price volatility on core utility customers through the use of its underground storage facilities, by entering into gas commodity-based financial hedge contracts, and by crediting gas costs with margin revenues derived from off-system sales of commodity and released transportation capacity in periods when core utility customers do not fully utilize firm pipeline capacity and gas supplies. NW Natural supplies many of its non-core customers (larger industrial interruptible customers with full or partial dual fuel capabilities) through gas transportation service, delivering gas purchased by these customers directly from suppliers. (See "Gas Supply - Transportation," below.) Core Market Basic Supply ------------------------ NW Natural purchases gas for its core market from a variety of suppliers located in the western United States and Canada. About 80 percent of its annual supply comes from Canada, with the balance coming primarily from the U.S. Rocky Mountain region. At Jan. 1, 2004, NW Natural had 31 firm contracts with 12 suppliers with remaining terms ranging from three months to five years, which provided for a maximum of 3,070,000 therms/1/ of firm gas per day during the peak winter season and 1,570,000 therms per day during the remainder of the year. These contracts have a variety of pricing structures and purchase obligations. NW Natural's largest core market gas supply contract was a 15-year agreement that expired in November 2003 with CanWest Gas Supply, Inc., an aggregator for gas producers in British Columbia, Canada. That contract allowed NW Natural to purchase up to 960,000 therms of firm gas per day. Four other long-term firm gas supply agreements that had been entered into during the late 1980s and early 1990s with three suppliers (BP Canada, Burlington Resources Canada and Engage Energy) also expired in 2003. All of these contracts pertained to Canadian supplies purchased in the provinces of British Columbia and Alberta, totaling approximately 1,300,000 therms per day on a year-round basis, with an additional 140,000 therms per day available only during the heating season. - ----------------- 1 One therm is equivalent to 100 cubic feet of natural gas at an assumed heat content of 1,000 British Thermal Units (Btu's) per cubic foot. 4 Over the past two years, 11 new firm year-round contracts were negotiated with a variety of existing and new suppliers so that a seamless transition could take place as the five older contracts expired. Considered together, the new purchase agreements provide a similar amount of gas as the expired contracts, with no single contract amounting to more than 200,000 therms per day. These new firm year-round supply contracts have terms ranging from one to five years, with a volume weighted average term of just over three years. All of the contracts use price formulas tied to monthly index prices, primarily at the AECO C/N.I.T. trading point within Alberta. Using financial instruments, NW Natural hedges the index prices (see "Gas Supply-Hedge Program," below). In addition to the year-round contracts, NW Natural continues to contract in advance for firm gas made available only during the heating season. During 2002 and 2003, new short-term (five-month) purchase agreements were entered into with seven suppliers. These agreements have a variety of pricing structures and provide for a total of up to 1,500,000 therms per day during the 2003-2004 heating season. One of these contracts, providing up to 200,000 therms per day, also extends to the 2004-2005 and 2005-2006 heating seasons. NW Natural intends to enter into new purchase agreements in 2004 for equivalent volumes of gas with its existing or other similar suppliers as needed to replace short-term and one-year contracts that will expire during 2004. NW Natural also buys gas on the spot market (30 days or less) as needed to meet demand. NW Natural has flexibility under the terms of some of its firm supply contracts enabling it to purchase spot gas in lieu of firm contract volumes, thereby allowing it to take advantage of favorable pricing on the spot market from time to time. NW Natural continues to purchase gas from a producer in the Mist gas field in Oregon. The production area is situated near NW Natural's underground gas storage facility. The price for this gas is tied to NW Natural's weighted average cost of gas. Current production is approximately 20,000 therms per day from about 18 wells, supplying about 1 percent of NW Natural's total annual purchase requirements. Production from these wells varies as existing wells are depleted and new wells are drilled. Core Market Peaking Supply -------------------------- NW Natural supplements its firm gas supplies with gas from Company-owned or contracted peaking facilities in which gas is stored during periods of low demand for use during periods of peak demand. In addition to enabling NW Natural to meet its peak demand, these facilities make it possible to lower the annual average cost of gas by allowing NW Natural both to minimize its pipeline transportation contract demand and to purchase gas for storage during the summer months when prices are generally at their lowest. NW Natural has contracts with Williams Gas Pipeline-West (WGP), formerly known as Northwest Pipeline, that expire in 2004 for firm gas storage services from an underground field at Jackson Prairie near Centralia, Washington, and a liquefied natural gas (LNG) facility at Plymouth, Washington. Together, these facilities provide NW Natural with daily firm deliverability of about 1.1 million therms and total seasonal capacity of about 16 million therms. Separate contracts with WGP provide for the transportation of these storage supplies to NW Natural's service territory. These contracts may be extended on an annual basis after the end of their primary terms at NW Natural's option. NW Natural owns and operates two LNG plants that liquefy gas during the summer months for storage until the peak winter season. These two plants provide a maximum daily deliverability of 1.8 million therms and a total seasonal capacity of 17 million therms. NW Natural also provides daily and seasonal peaking from the underground gas storage facility it owns and operates in the Mist gas field. This facility has a maximum daily deliverability of 3.2 million therms and a total seasonal working gas capacity of 115 million therms. NW Natural completed its latest expansion of the Mist storage facility in December 2001. This $10 million project increased the facility's total daily delivery capacity by 29 percent. The increased deliverability is used to serve the needs of NW Natural's core utility customers as well as its interstate storage service customers (see "Interstate Storage Services," below). As the needs of core utility customers 5 grow, existing interstate capacity will be transferred for use by core utility customers and be replaced by newly developed interstate storage capacity. The plan for expansion of NW Natural's storage capability includes an extension of its South Mist Pipeline that is scheduled for completion in 2004 (see "Additions to Infrastructure," below), and further development of existing storage reservoirs. NW Natural also has contracts with an electric generator, two industrial customers, and one gas marketing company that together provide a total of 102,000 therms per day of year-round capacity, plus 900,000 therms per day of recallable capacity and supply. These contracts have remaining terms ranging from two months to seven years. Hedge Program ------------- NW Natural has an active natural gas commodity-price hedge program that is intended to reduce commodity price risk. Under this program, the Company typically enters into commodity swap and call option agreements during the spring and summer seasons, when natural gas prices may be lower. Gains (losses) from commodity hedges are treated for accounting and rate purposes as reductions (increases) to the cost of gas. The intended effect of this program is to lock in prices for a large portion of NW Natural's gas supply portfolio for the following year, at prevailing market prices at the time the swap and call option agreements are entered into. Transportation -------------- Natural gas for NW Natural's core market is transported over the interstate pipeline system of WGP. Most supplies also move over other pipelines upstream of WGP's system in the U.S. and Canada. Rates for transportation are established by the FERC for service under transportation agreements between NW Natural and the U.S. interstate pipelines, and by Canadian federal or provincial authorities for service under agreements with the Canadian pipelines over which NW Natural ships gas. The largest of the transportation agreements with WGP extends through 2013 and provides for firm transportation capacity of up to 2,148,890 therms per day. This agreement provides access to natural gas supplies in British Columbia and the U.S. Rocky Mountains. The Company's second largest transportation agreement with WGP extends through 2011. It provides 1,020,000 therms per day of firm transportation capacity from the point of interconnection of the WGP and PG&E Gas Transmission Northwest (GTN) systems in eastern Oregon to NW Natural's service territory. GTN's pipeline runs from the U.S./Canadian border through northern Idaho, southeastern Washington and central Oregon to the California/Oregon border. NW Natural's total capacity on GTN and two upstream pipelines in Canada (Alberta Natural Gas Company and NOVA Corporation of Alberta, now both units of TransCanada PipeLines Limited) matches this amount of WGP capacity northward into Alberta, Canada. NW Natural also has an agreement with WGP that extends through 2013 for 351,550 therms per day of firm transportation capacity. This agreement accesses gas supplies in the U.S. Rocky Mountain region. In 2002, NW Natural entered into four long-term pipeline transportation contracts, one that commenced in November 2003 and the other three commencing in November 2004. A contract with Duke Energy Gas Transmission (formerly Westcoast Energy, Inc.) (Duke Energy GT) effective in November 2003 and extending through October 2014, provides approximately 600,000 therms per day of firm gas transportation from northern British Columbia to a connection with WGP at the U.S.-Canadian border. A contract with Terasen Gas (formerly BC Gas) effective in November 2004 and extending through October 2020, will provide approximately 470,000 therms per day of firm gas transportation from southeastern British Columbia to the same connection with WGP at the U.S.-Canadian border. NW Natural's capacity with Terasen Gas is matched with companion contracts for pipeline capacity on systems of Alberta Natural Gas Company and NOVA Corporation of Alberta that connect to the gas fields of Alberta, Canada. 6 Since WGP opened its system to the transportation of customer-owned gas in the late 1980s, most of NW Natural's large industrial customers have switched from sales service to transportation service whereby they purchase gas directly from suppliers and ship the gas on the Company's system and those of its pipeline suppliers for a fee. The ability of industrial customers to switch between sales service and transportation service has made it possible for NW Natural to retain some of these customers. Periodic switching between sales and transportation service by these customers has had an adverse effect on NW Natural's results of operations in certain years, and a positive effect in other years, as industrial customers have sought to find the most economical and reliable combination of gas supply and delivery services (see "Competition and Marketing," below). In 2003, NW Natural redesigned its industrial rates in the Oregon general rate case and, as a result, it expects less switching from higher-margin to lower-margin service contracts than it has experienced in the past (see "Regulation and Rates," below). Interstate Storage Services - --------------------------- NW Natural provides gas storage services to interstate customers using storage capacity that has been developed in advance of its core utility customers' requirements. In 2001, the FERC authorized NW Natural to provide firm and interruptible gas storage service and related transportation service to and from the Mist gas storage facility to customers in interstate commerce. In 2003, NW Natural provided storage services to nine interstate customers. The FERC limited jurisdiction certificate enables NW Natural to make its underground gas storage capacity available to help address the region's energy challenges, but NW Natural retains its exemption from full FERC jurisdiction. Regulation and Rates - -------------------- NW Natural is subject to regulation with respect to, among other matters, rates, systems of accounts and issuance of securities by the OPUC and the WUTC. In 2003, 93 percent of NW Natural's utility gas deliveries and 92 percent of its utility operating revenues were derived from Oregon customers and the balance from Washington customers. NW Natural is exempt from the provisions of the Natural Gas Act by order of the Federal Power Commission (now the FERC), except with respect to the terms and conditions associated with its interstate gas storage and related transportation services (see "Interstate Storage Services," above). NW Natural's 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 $2.8 million went into effect on a deferred basis on Nov. 12, 2003 as the first 11.7 miles of the Company's South Mist Pipeline Extension (SMPE) went into service (see "Additions to Infrastructure," below). The remainder will go into effect as all or portions of the SMPE project and the Company's Coos County distribution system project are completed and go into service in 2004. The most recent general rate increase in Washington, which was fully effective in October 2001, authorized rates designed to produce an ROE of 10.8 percent and a revenue increase of $4.3 million per year, or 12.1 percent. On Nov. 19, 2003, NW Natural filed a new general rate case in Washington. The filing proposes a revenue increase of $7.9 million per year from Washington operations through rate increases averaging 15 percent. A decision by the WUTC is expected by the end of October 2004. See Part II, Item 7., "Results of Operations - Regulatory Matters-General Rate Cases." Notwithstanding authorized revenue levels approved by the OPUC or the WUTC, actual revenues are dependent on weather, economic conditions, customer growth, competition and other factors affecting gas usage in NW Natural's service area. In November 2003, NW Natural implemented a weather normalization mechanism in Oregon that helps stabilize the Company's net operating revenues by adjusting current customer billings based on temperature variances from average weather. The weather normalization mechanism approved by the OPUC will be 7 applied to NW Natural's Oregon residential and commercial customers' 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 NW Natural's recovery of its fixed costs and to reduce fluctuations in customers' bills due to colder- or warmer-than-average weather. In Oregon, NW Natural has a Purchased Gas Adjustment (PGA) tariff under which net income derived from Oregon operations may be affected within defined limits by changes in purchased gas costs. The PGA tariff provides for periodic revisions in rates due to changes in the Company's cost of purchased gas. Costs included in the PGA adjustments are based on NW Natural's projected gas requirements and negotiated gas prices for the upcoming gas supply contract year. Under its Washington PGA, NW Natural is permitted to track 100 percent of increases and decreases in gas commodity costs, with the result that net income is not directly affected by changes in commodity costs. In both Oregon and Washington, the PGA mechanism permits NW Natural to recover 100 percent of FERC-approved pipeline transportation costs. The Oregon PGA tariff provides that 67 percent of any difference between actual purchased gas costs and estimated purchased gas costs incorporated into rates will be deferred for amortization in subsequent periods. If actual gas commodity costs exceed those incorporated in rates, NW Natural subsequently will adjust its rates upward to recover 67 percent of the deficiency from core market customers. Similarly, if actual gas commodity costs are lower than those reflected in rates, rates will be adjusted downward to distribute to core utility customers 67 percent of such gas commodity cost savings. In an order issued in 1999, the OPUC formalized a process that tests for excessive earnings in connection with gas utilities' annual filings under their PGA mechanisms. The OPUC confirmed NW Natural's ability to pass through 100 percent of its prudently incurred gas costs into rates. Under this order, NW Natural is authorized to retain all of its earnings up to a threshold level equal to its 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 movements in interest rates. In 2002, the OPUC approved a settlement in a proceeding NW Natural initiated in 2001 with a goal of stabilizing margin revenues in the face of above- or below-normal consumption patterns. Pursuant to the settlement, the OPUC authorized a mechanism for rate changes relating to the impact of price elasticity, starting with small increases to residential and commercial rates that became effective on Oct. 1, 2002. Also under the settlement, the OPUC authorized NW Natural to implement a partial decoupling mechanism effective Oct. 1, 2002. Decoupling mechanisms are used to break the link between a utility's earnings and the energy consumed by its customers so the utility does not have an incentive to discourage customers' conservation efforts. The decoupling mechanism works by adding margin revenues during periods when customer consumptions are lower than baseline consumption or by deducting margin revenues when consumptions are higher than the baseline. Under the partial decoupling mechanism, NW Natural uses a balancing account to defer and subsequently amortize 90 percent of the margin differentials between baseline usage by its residential and commercial customers and weather-normalized actual usage by these customers. The deferred amounts are treated as adjustments to be refunded or collected in future periods. Baseline consumption is based on customer consumption patterns as determined in the Oregon general rate case, adjusted for consumptions 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 mechanism's effectiveness. Also under the settlement, NW Natural agreed to adopt certain service quality measures that establish the Company's performance goal for minimizing complaints by customers where the Company is determined to be at fault. If NW Natural exceeds the prescribed level of at-fault complaints, it will be subject to penalties. The OPUC and WUTC have implemented "integrated resource planning" processes under which utilities develop plans defining alternative growth scenarios and resource acquisition strategies. In 2000 and 2001, respectively, the OPUC and the WUTC acknowledged and accepted NW Natural's submission of its 8 fourth Integrated Resource Plan. Elements of the plan include an evaluation of supply and demand resources; the consideration of uncertainties in the planning process and the need for flexibility to respond to changes; a primary goal of "least cost" service; and consistency with state energy policy. Although the OPUC's order acknowledging an earlier Integrated Resource Plan indicated the order did not constitute ratemaking approval of any specific resource acquisition or expenditure, the OPUC did indicate that it would give considerable weight in prudency reviews to utility actions that are consistent with acknowledged plans. Elements of NW Natural's fourth Integrated Resource Plan demonstrated that the continued development of the Mist underground gas storage facility is the least-cost option for serving customer growth. The OPUC's acceptance of the plan indicated to the Oregon Energy Facility Siting Council (EFSC) that NW Natural required the South Mist Pipeline extension to best serve its customers, thereby satisfying the requirement that NW Natural prove the need for the facility in order to obtain the EFSC's approval to build the pipeline extension (see "Additions to Infrastructure," below). NW Natural will be filing a fifth Integrated Resource Plan in 2004. Additions to Infrastructure - --------------------------- NW Natural expects a high level of capital expenditures for additions to infrastructure over the next five years, reflecting projected customer growth, system replacement, improvement and reinforcement projects and the development of additional gas storage facilities. NW Natural's utility construction expenditures are estimated to total between $500 million and $600 million over the five-year period 2004 through 2008, including an estimated $165 million in 2004. NW Natural continues to be one of the fastest growing gas utilities in the nation (see "Competition and Marketing," below). In 2003 NW Natural grew its customer base by more than 3 percent for the 17th year in a row, and in 2004 it expects to continue that trend with projected capital expenditures of $31 million for the addition of new customers. NW Natural will have significant capital requirements during the next five years for system replacement, improvement and reinforcement projects, including an estimated $38 million in 2004. These include requirements pursuant to new federal legislation as well as expenditures under NW Natural's ongoing pipeline safety program (see "Pipeline Safety," below). The extension of the pipeline from NW Natural's Mist gas storage field, designed to move more gas into growing portions of its service area (see "Gas Supply - Core Market Peaking Supply," "Interstate Storage Services" and "Regulation and Rates," above) has an estimated total cost of $105 million, including $56 million in 2004. The project has a scheduled completion date in late 2004, but the timeline for completion will depend, in part, on obtaining necessary rights-of-way. Following two years of review of NW Natural's application, including extensive public involvement, the EFSC granted a permit for the project, with conditions, in March 2003. Following denial by the Oregon Supreme Court of a motion to stay the effect of the permit, NW Natural proceeded with the construction and completed and placed the first 11.7 miles of the SMPE project into service in November 2003. Also in November 2003, the Oregon Supreme Court affirmed the issuance of the permit that had been appealed by interested parties. NW Natural must obtain easements and rights-of-way for the construction of the remainder of the pipeline and may need to use condemnation proceedings to secure some of them. Pipeline Safety - --------------- The Pipeline Safety Improvement Act of 2002 (Pipeline Safety Act) requires operators of gas transmission pipelines to identify lines located in High Consequence Areas (HCAs) and develop Integrity Management Programs (IMPs) to periodically inspect the integrity of the pipelines and make repairs or replacements as necessary to ensure the ongoing integrity of the pipelines. The legislation requires NW Natural to complete inspection of the 50 percent highest risk pipelines located in its HCAs within the first five years, and the remaining covered pipelines within 10 years of the date of enactment. The Pipeline Safety Act also requires re-inspections of the covered pipelines every seven years thereafter for the life of the pipelines. In December 2003, the U.S. Department of Transportation issued a final rule entitled "Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines)" that specifies the detailed requirements for transmission IMPs as 9 mandated by the Pipeline Safety Act. See Part II., Item 7, "Financial Condition-Cash Flows-Investing Activities." The Pipeline Safety Act also applies to the 18-mile interstate natural gas pipeline that KB Pipeline operates. NW Natural entered into a stipulation with the OPUC in 2001 for an enhanced pipeline safety program that includes an accelerated bare steel replacement program and a geo-hazard safety program. The bare steel replacement program accelerates the replacement of NW Natural's bare steel piping over 20 years instead of 40 years. The geo-hazard safety program includes the identification, assessment and remediation of risks to piping infrastructure created by landslides, washouts, earthquakes or similar occurrences. The stipulation allowed NW Natural to receive deferred accounting rate treatment commencing in October 2002, for costs associated with the programs exceeding $3 million per year, expected to be approximately $1.5 million annually. Competition and Marketing - ------------------------- NW Natural has no direct competition in its service area from other natural gas distributors. For residential customers' heating needs, however, NW Natural competes with electricity, fuel oil, propane and, to a lesser extent, wood. It also competes with electricity and fuel oil for commercial applications. Competition among these forms of energy is based on price, reliability, efficiency and performance. Overall, in 2003 NW Natural maintained its competitive price advantage compared to electricity in both the residential and commercial markets. In 2003, although electricity prices stabilized and electricity became more competitive primarily due to improving end use technology, natural gas retained its relative price advantage compared to electricity provided by the investor-owned utilities that serve approximately 75 percent of the homes in NW Natural's Oregon service area. NW Natural expects to maintain a price advantage compared to electricity provided by the investor-owned electric utilities in its service territory, in part because a growing portion of the electricity sold by these utilities is generated from natural gas. Although there was an increasing price advantage for gas compared to oil in the latter half of 2002, there were fewer residential conversions from heating oil to natural gas during 2003 due to weak economic conditions, volatile gas prices, and a decline in the remaining inventory of potential oil conversion opportunities. The relatively low market saturation of natural gas in residential single-family and attached dwellings in NW Natural's service territory, estimated at 40 to 50 percent, together with the price advantage of natural gas compared with electricity and its operating convenience over fuel oil, provides the potential for continuing growth in the residential and commercial conversion markets. In 2003, 16,025 net residential customers (after subtracting disconnected or terminated services) were added, including 5,534 units of existing residential housing that were converted from oil, electric or propane appliances to natural gas. The net total of all new customers added in 2003 was 18,083. This constituted a growth rate of 3.2 percent, which is about twice the national average for local gas distribution companies (LDCs) as reported by the American Gas Association. Due to weather that was about 7 percent warmer in 2003 than in 2002, and a decrease in weather-sensitive customer consumption due to commodity price-related rate increases in prior years and continuing conservation efforts, natural gas sales volumes to residential and commercial customers in 2003 were about 1 percent lower than in 2002. Temperatures in NW Natural's service territory in 2003, based on heating degree-days, were about 7 percent warmer than the 25-year average. As a result of the deregulation and restructuring of the energy markets during the past decade, the natural gas industry, including producers, interstate pipelines and LDCs, has undergone many changes. Traditionally, LDCs sold a "bundled" product that included both the natural gas commodity and delivery to the meter. However, beginning in the late 1980s, large industrial customers sought to achieve savings by procuring their own supplies of natural gas from producers and contracting with pipelines and LDCs for transportation to their facilities. These changes were intended to promote competition where it is economically beneficial to consumers. Competition to serve the industrial and large commercial market in the Pacific Northwest has been relatively steady since the early 1990s in terms of numbers and types of competitors. Competitors consist of gas marketers, 10 oil/propane sellers and electric utilities. Wood-based fuels continue to lose market share in these markets primarily due to environmental concerns and restrictions. The OPUC and WUTC have approved transportation tariffs under which NW Natural may contract with customers to deliver customer-owned gas. Transportation tariffs available to industrial customers are priced at the Company's cost of providing transportation service. Generally, the Company is unaffected financially if industrial customers transport customer-owned gas rather than purchasing gas from NW Natural, as long as they remain on a tariff or contract with the same quality of service. However, industrial customers may select between firm and interruptible service, among other different levels or qualities of service, and these choices can positively or negatively affect margin revenue from such customers. The relative level and volatility of prices in the natural gas commodity markets, the availability of interstate pipeline capacity to ship customer-owned gas and the cost structure embedded in NW Natural's industrial rates are among the primary factors that have caused some industrial customers to alternate between sales and transportation service or between higher and lower qualities of service. NW Natural re-designed its industrial rates in Oregon as part of its general rate case in 2003, transferring $4.8 million of annual revenue requirement from industrial rates to residential and commercial rates in order to better reflect relative costs of service and to become more competitive in the industrial market. Total industrial throughput, including both sales and transportation of firm and interruptible gas, was 518 million therms in 2003, down 3 percent from 535 million therms in 2002. NW Natural's industrial base includes customers in the high-tech, forest products and other industries that are sensitive to economic conditions and were negatively affected by the weak economy in 2003. In 2003, NW Natural substantially increased deliveries to a high-volume customer served under a new, low margin contract for gas transportation to a cogeneration facility. The mix within NW Natural's industrial market between sales and transportation service was different in 2003 than in 2002. Industrial sales in 2003 were 103 million therms, representing 20 percent of total industrial deliveries, up from 89 million therms or 17 percent of total industrial deliveries in 2002. Most of the transfers from transportation to sales service occurred during the second quarter of 2002, when spot prices in the gas commodity market were higher than the weighted average cost of gas embedded in NW Natural's sales rates for the year. The mix within the industrial market between firm and interruptible service also was different in 2003. Industrial deliveries under tariffs for firm service were 39 percent of total industrial deliveries in 2003, compared to 34 percent of total industrial deliveries in 2002. Total margin from firm industrial deliveries was down by 7 percent in 2003 and total margin from the combination of firm and interruptible deliveries was down by 7 percent. Due to the reclassification of some commercial customers to the industrial category and the cost structure embedded in the industrial rate re-design, 2002 and 2003 industrial deliveries are not comparable. NW Natural and certain of its largest industrial customers have entered into negotiated transportation service agreements. These agreements are designed to provide transportation rates that are competitive with the customer's alternative capital and operating costs of installing direct connections to WGP's interstate pipeline system, "bypassing" NW Natural's gas distribution system. The agreements generally prohibit bypass during their terms. Due to the cost pressures that confront a number of NW Natural's largest customers that compete in global markets, bypass continues to be a threat. Although NW Natural does not expect a significant number of its large customers to bypass its system in the foreseeable future, it may experience further deterioration of margin associated with customers' transfers to contracts with pricing designed to be competitive with bypass. The Pacific Northwest historically has enjoyed some of the lowest electric rates in the nation, primarily due to the proximity of federal hydroelectric facilities. Due to a number of environmental, economic and political limitations on the future use of the hydroelectric infrastructure in the Pacific Northwest, as well as the supply and price dislocations that occurred in the electricity market in the West in 2000 and 2001, a few large gas-fired generation projects are currently in various stages of construction or development in the region. These projects, as well as projects for cogeneration or distributed generation of electricity, may present opportunities for NW Natural to serve new loads. The availability of interstate pipeline transportation capacity, gas storage capacity and economically priced gas supplies could play significant roles in the future development of generation projects. 11 NW Natural is authorized by the OPUC to make off-system commodity sales when seasonal demand is low. This often allows NW Natural to compete effectively with independent gas marketers. Sixty-seven percent of the net revenues (gross revenues less the actual cost of gas) generated from these sales are credited to Oregon core utility gas costs, with the balance benefiting shareholders. Environment - ----------- The Company's properties and facilities are subject to federal, state and local laws and regulations related to environmental matters. These evolving laws and regulations may require expenditures over a long timeframe to control environmental effects. Estimates of liabilities for environmental response costs are difficult to determine with precision because of the various factors that can affect their ultimate level. These factors include, but are not limited to the following: o the complexity of the site; o changes in environmental laws and regulations at the federal, state and local levels; o the number of regulatory agencies or other parties involved; o new technology that renders previous technology obsolete or experience with existing technology that proves ineffective; o the ultimate selection of technology; o the level of remediation required; and o variations between the estimated and actual period of time that must be dedicated to respond to an environmentally-contaminated site. NW Natural owns or previously owned properties currently being investigated that may require environmental response, including property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site), property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Wacker Siltronic Corporation (the Wacker site), and an area adjacent to the Gasco site and the Wacker site along a segment of the Willamette River (the Portland Harbor) that has been listed by the U.S. Environmental Protection Agency as a Superfund site for which the Company has been identified as a potentially responsible party. The Company does not expect that the ultimate resolution of these matters will have a material adverse effect on its financial position, results of operations or cash flows. See Note 12 to the accompanying Consolidated Financial Statements for a further discussion of potential environmental responses and related costs. Employees - --------- At Dec. 31, 2003, NW Natural had 1,291 employees, of which 895 were members of the Office and Professional Employees International Union, Local No. 11. Company management and union employees are currently negotiating a new labor agreement to replace a seven-year Joint Accord labor agreement covering wages, benefits and working conditions that will expire on March 31, 2004. Available Information - --------------------- The Company files annual, quarterly and special reports and other information with the Securities and Exchange Commission (SEC). The Company makes available on its website (http://www.nwnatural.com), free of charge, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as soon as reasonably practicable after it electronically files such material with, or furnishes it to, the SEC. In addition, copies of these documents may be requested, at no cost, by writing or calling Shareholder Services, Northwest Natural Gas Company, One Pacific Square, 220 N.W. Second Avenue, Portland, Oregon 97209, telephone 503-226-4211. The Company has adopted a Code of Ethics for all employees and a Financial Code of Ethics that applies to senior financial employees, both of which are available on the Company's website. The Company's Corporate Governance 12 Standards and additional information about NW Natural also are available on the website. Copies also may be obtained by request to the Corporate Secretary at the address given above. ITEM 2. PROPERTIES NW Natural's natural gas distribution system consists of 12,458 miles of distribution and transmission mains. In addition, the distribution system includes service pipes, meters and regulators, and gas regulating and metering stations. The mains and feeder lines are located in municipal streets or alleys pursuant to valid franchise or occupation ordinances, in county roads or state highways pursuant to valid agreements or permits granted pursuant to statute, or on lands of others pursuant to valid easements obtained from the owners of such lands. NW Natural also holds all necessary permits for the crossing of the Willamette River and a number of smaller rivers by its mains. NW Natural owns service facilities in Portland, as well as various satellite service centers, garages, warehouses and other buildings necessary and useful in the conduct of its business. It leases office space in Portland for its corporate headquarters. District offices are maintained on owned or leased premises at convenient points in the distribution system. NW Natural owns LNG facilities in Portland and near Newport, Oregon. NW Natural holds interests in 7,816 net acres of underground natural gas storage and 2,444 net acres of oil and gas leases in Oregon. NW Natural owns rights to depleted gas reservoirs near Mist, Oregon, that are continuing to be developed as underground gas storage facilities. It also holds an option to purchase future storage rights in certain other areas of the Mist gas field. In order to reduce risks associated with gas leakage in older parts of its system, NW Natural undertook an accelerated pipe replacement program in the 1980s under which it removed or replaced 100 percent of its cast iron main by October 2000. In 2001, NW Natural initiated an accelerated pipe replacement program under which it will reduce the amount of bare steel main in the system. NW Natural considers all of its properties currently used in its operations, both owned and leased, to be well maintained, in good operating condition, and, along with currently planned additions, adequate for its present and foreseeable future needs. NW Natural's Mortgage and Deed of Trust constitutes a first mortgage lien on substantially all of the real property constituting its utility plant. ITEM 3. LEGAL PROCEEDINGS Litigation - ---------- In November 2001, NW Natural commenced a lawsuit, Northwest Natural Gas Company v. Cascade Resources Corporation and Curry, et. al. (United States District Court for the District of Oregon, Case No. CV 01-1620 HU), alleging that the defendants violated obligations regarding the use and disclosure of confidential information and used such information to solicit and secure underground gas storage leases in areas of interest to the Company. Among other remedies, the Company sought to have a constructive trust imposed on such leases and to require the defendants to assign their interest in such leases to the Company. The defendants in this case asserted counterclaims against the Company alleging that by asserting that the defendants misused confidential information, the Company improperly interfered with the defendants' business opportunities. The assertions included claims for violation of antitrust laws for which the defendants sought $15 million in damages, trebled, plus punitive damages and attorneys' fees. In April 2003, NW Natural settled and agreed with Cascade Resources Corporation and Al Curry (collectively, Cascade) to dismiss their respective claims. In November 2003, the court denied the motion of Enerfin Resources Northwest Limited Partnership (Enerfin), a former employer of Al Curry and the 13 remaining defendant in the Action, for Summary Judgment in the case. In January 2004, prior to the scheduled Jan. 20, 2004 trial date, NW Natural and Enerfin agreed to settle their claims in this case. Although the proposed settlement is not yet finalized, under its terms, the lawsuit has been tentatively dismissed, subject to reinstatement should the settlement not be executed by March 15, 2004. Enerfin has agreed to pay NW Natural $465,000, and NW Natural has agreed to transfer to Enerfin certain oil and gas production rights that were acquired from Cascade Resources in the settlement of the original claims in this case. In addition, NW Natural will purchase from Enerfin and its partner certain interests in two reservoirs in the Mist gas field for $1 million. In the settlement, Enerfin also has agreed to dismiss its counterclaims against NW Natural in the Longview Fibre litigation described below. On Oct. 16, 2003, Longview Fibre Company (Longview) filed suit in Federal Court (Longview Fibre Company v. Enerfin Resources Northwest Limited Partnership and Northwest Natural Gas Company (US District Court - Oregon District)) seeking a declaratory judgment regarding the continuing existence of a certain oil and gas lease in the Mist gas field between Longview and Enerfin. NW Natural holds a gas storage lease obtained in the Cascade settlement which covers the same area and has certain rights relative to oil and gas. In response, Enerfin has, among other things, filed counterclaims against NW Natural alleging that NW Natural wrongly interfered with Enerfin's attempts to continue its oil and gas lease with Longview. Enerfin is seeking punitive damages of $2 million. NW Natural believes Enerfin's claims are without merit and expects to defend its rights in this proceeding should the matter not be settled. In the tentative settlement of the Cascade case referenced above, Enerfin has agreed to dismiss its claims against NW Natural in this litigation. The Company is subject to other claims and litigation arising in the ordinary course of business. Although the final outcome of any legal proceeding cannot be predicted with certainty, the Company does not expect disposition of these matters to have a materially adverse effect on the Company's financial position, results of operations or cash flows. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders, through the solicitation of proxies or otherwise, during the fourth quarter of the year ended Dec. 31, 2003. 14 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY (A) NW Natural's common stock is listed and trades on the New York Stock Exchange under the symbol "NWN." The quarterly high and low trades for NW Natural's common stock during the past two years were as follows:
2003 2002 ------------------------- ---------------------- Quarter Ended High Low High Low - ---------------------------------------------------------------------------- March 31 $28.47 $24.05 $28.50 $24.20 June 30 28.88 24.77 30.30 27.60 September 30 30.10 27.02 30.20 23.46 December 31 31.30 28.51 30.70 25.50
The closing quotations for the common stock on Dec. 31, 2003 and 2002 were, $30.75 and $27.06, respectively. (B) As of Dec. 31, 2003, there were 9,695 holders of record of the Company's common stock. (C) 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. Dividends per share paid during the past two years were as follows:
Payment Date 2003 2002 ------------ ------ ------ February 15 $0.315 $0.315 May 15 0.315 0.315 August 15 0.315 0.315 November 15 0.325 0.315 ----- ----- Total per share $1.270 $1.260 ====== ======
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 common stock on a quarterly basis. However, future dividends will be dependent upon NW Natural's earnings, its financial condition and other factors. NW Natural's Dividend Reinvestment and Stock Purchase Plan permits registered owners of common stock to reinvest all or a portion of their quarterly dividends in additional shares of NW Natural's common stock at the current market price. Shareholders also may invest cash on a monthly basis, up to $50,000 per calendar year, in additional shares at the current market price. During 2003, dividend reinvestments and optional cash investments under the Plan aggregated $4.9 million and resulted in the issuance of 178,714 shares of common stock. During the 26 years the Plan has been available, the Company has issued and sold 4,497,312 shares of common stock which produced $98.0 million in additional capital. The Company did not repurchase any of its stock in the fourth quarter of 2003. 15 ITEM 6. SELECTED FINANCIAL DATA The following table sets forth selected financial data concerning the Company's operations and financial condition.
Thousands, except per share amounts and ratio of earnings to fixed charges 2003 2002 2001 2000 1999 - ------------------------------------------------------------------------------------------------------------------------ Sales revenues: Residential $ 328,464 $ 354,735 $ 329,905 $ 280,642 $ 242,952 Commercial 176,385 201,475 190,236 159,660 139,425 Industrial - firm 33,578 42,965 49,662 37,378 35,857 Industrial - interruptible 23,661 15,937 34,283 23,483 17,182 Unbilled revenues 14,474 (12,702) 13,774 12,661 (2,671) ----------- ----------- ----------- ----------- ----------- Total gas sales revenues 576,562 602,410 617,860 513,824 432,745 Transportation 17,962 26,020 20,637 21,491 21,351 Other 7,460 4,018 (2,325) (3,976) 1,194 ----------- ----------- ----------- ----------- ----------- Total gross utility operating revenues 601,984 632,448 636,172 531,339 455,290 Cost of gas sold 323,128 353,034 364,699 273,978 212,021 ----------- ----------- ----------- ----------- ----------- Net utility operating revenues 278,856 279,414 271,473 257,361 243,269 Net non-utility operating revenues 9,210 8,130 4,538 589 368 ----------- ----------- ----------- ----------- ----------- Net operating revenues $ 288,066 $ 287,544 $ 276,011 $ 257,950 $ 243,637 =========== =========== =========== =========== =========== Net income $ 45,983 $ 43,792 $ 50,187 $ 50,224 $ 45,296 Redeemable preferred and preference stock dividend requirements 294 2,280 2,401 2,456 2,515 ----------- ----------- ----------- ----------- ----------- Earnings applicable to common stock $ 45,689 $ 41,512 $ 47,786 $ 47,768 $ 42,781 =========== =========== =========== =========== =========== Average common shares outstanding: Basic 25,741 25,431 25,159 25,183 24,976 Diluted 26,061 25,814 25,612 25,638 25,468 Earnings per share of common stock: Basic $ 1.77 $ 1.63 $ 1.90 $ 1.90 $ 1.71 Diluted $ 1.76 $ 1.62 $ 1.88 $ 1.88 $ 1.70 Dividends per share of common stock $ 1.27 $ 1.26 $ 1.245 $ 1.24 $ 1.225 =========== =========== =========== =========== =========== Total assets - at end of period* $ 1,591,332 $ 1,467,277 $ 1,435,022 $ 1,278,713 $ 1,244,423 =========== =========== =========== =========== =========== Redeemable preferred stock $ - $ 8,250 $ 9,000 $ 9,750 $ 10,564 Redeemable preference stock $ - $ - $ 25,000 $ 25,000 $ 25,000 Long-term debt $ 500,319 $ 445,945 $ 378,377 $ 400,790 $ 396,379 Ratio of earnings to fixed charges** 2.83 2.74 3.01 3.00 2.97 =========== =========== =========== =========== =========== * Certain amounts from prior years have been reclassified to conform, for comparison purposes, with the current financial statement presentation. These reclassifications had no impact on prior year consolidated results of operations. ** Computed using the Securities and Exchange Commission method. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, dividends on all preferred and preference stock, the amortization of debt expense and discount or premium, and the estimated interest portion of rentals charged to income.
16 SELECTED FINANCIAL DATA (continued)
Thousands, except per customer and gas per therm data 2003 2002 2001 2000 1999 - ----------------------------------------------------------------------------------------------------------------------- Capitalization - at end of period Common stock equity $ 506,316 $ 482,392 $ 468,161 $ 452,309 $ 429,596 Redeemable preference stock - - 25,000 25,000 25,000 Redeemable preferred stock - 8,250 9,000 9,750 10,564 Long-term debt 500,319 445,945 378,377 400,790 396,379 ----------- ----------- ----------- ----------- ----------- Total capitalization $ 1,006,635 $ 936,587 $ 880,538 $ 887,849 $ 861,539 =========== =========== =========== =========== =========== Gas sales and transportation deliveries (000 therms): Residential 343,534 357,091 350,065 356,375 352,969 Commercial 226,257 240,155 242,293 250,380 252,382 Industrial - firm 55,314 63,215 79,778 76,559 84,630 Industrial - interruptible 47,994 26,241 63,597 56,632 52,938 Unbilled therms 12,099 (6,617) 1,771 8,691 (9,343) ----------- ----------- ----------- ----------- ----------- Total gas sales 685,198 680,085 737,504 748,637 733,576 Transportation 414,554 445,999 385,783 431,136 480,570 ----------- ----------- ----------- ----------- ----------- Total volumes delivered 1,099,752 1,126,084 1,123,287 1,179,773 1,214,146 =========== =========== =========== =========== =========== Customers (average for period): Residential 510,336 492,871 474,373 456,449 435,959 Commercial 56,504 55,416 54,628 53,617 52,029 Industrial - firm 362 350 377 375 396 Industrial - interruptible 98 74 141 118 118 Transportation 179 190 111 125 127 ----------- ----------- ----------- ----------- ----------- Total customers 567,479 548,901 529,630 510,684 488,629 =========== =========== =========== =========== =========== Customer statistics: Heat requirements*** Actual degree days 3,952 4,232 4,325 4,418 4,256 25-year average degree days 4,238 4,257 4,267 4,274 4,274 Average annual use per customer in therms: Residential 673 725 738 781 810 Commercial 4,004 4,334 4,435 4,670 4,851 Gas purchased cost per therm - net (cents) 46.99 51.07 47.19 37.68 27.85 *** A degree day is the measure of the coldness of the weather experienced based on the extent to which the average of the high and low temperatures for a day falls below 65 degrees Fahrenheit.
17 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION The following is management's assessment of Northwest Natural Gas Company's financial condition including the principal factors that affect results of operations. The discussion refers to the consolidated activities of the Company for the three years ended Dec. 31, 2003. Unless otherwise indicated, references in this discussion to "Notes" are to the notes to the consolidated financial statements. The consolidated financial statements include: Regulated utility: o Northwest Natural Gas Company (NW Natural) Non-regulated wholly owned subsidiaries of NW Natural: o NNG Financial Corporation (Financial Corporation), and its wholly owned subsidiaries o Northwest Energy Corporation (Northwest Energy), and its wholly owned subsidiary Together these businesses are referred to herein as the "Company" (see "Results of Operations--Non-utility Operations," below, and Note 2). In addition to presenting results of operations and earnings amounts in total, certain measures are expressed in cents per share. These amounts reflect factors that directly impact the Company's earnings and are reported net of tax. The Company believes this per share information is useful because it enables readers to better understand the impact of these factors on the Company's earnings. All references in this report to earnings per share are on the basis of diluted shares (see Note 1). Executive Summary - ----------------- Highlights ---------- Among its accomplishments in 2003, the Company: o grew its utility customer base by more than 3 percent for the 17th year in a row, adding 18,083 customers to its gas distribution system during the year; o increased earnings from its business segment for interstate gas storage services from 14 cents a share in 2002 to 17 cents a share in 2003; o secured a permit for the construction of a major extension of its pipeline from the Mist storage field to the Portland metropolitan area and completed the first 11.7-mile segment of the pipeline extension, below budget and on time for the 2003-04 heating season; o successfully completed its general rate case in Oregon with a result that included phased rate increases, the recovery of costs relating to its gas storage investments and higher operating expenses, and approval of a new weather normalization mechanism; o secured reliable and adequate gas supplies during a time of volatile wholesale pricing, at costs that required only relatively small rate increases for customers; and o paid dividends on common stock of $1.27 a share, making 2003 the 48th consecutive year in which the Company's dividend payments have increased. 18 Issues, Challenges and Performance Measures ------------------------------------------- Issues and challenges the Company expects to face in 2004 include the effects and uncertainties relating to a general rate case in Washington; volatile gas commodity prices; continuing weak economic conditions in Oregon and Washington; completion of the remaining portion of the pipeline extension from NW Natural's Mist gas storage field including the acquisition of rights-of-way necessary to build the pipeline; and higher capital and operating costs due to federal mandates in the area of pipeline integrity. In order to deal with these and other issues affecting the business, in 2003 NW Natural completed a new strategic plan to map the Company's course during the next several years. The plan includes strategies for further improving NW Natural's ability to add customers both profitably and at a rapid pace; maintaining NW Natural's reputation for exemplary service; reducing business risk; managing all costs, including capital costs; holding all employees to high performance standards; and judiciously growing beyond the Company's local distribution business where it would complement core assets and competencies. Among the key performance measures the Company will use in monitoring progress against its goals in these areas are utility earnings per share, customer satisfaction ratings, new customer additions, operations and maintenance expense per customer, construction cost per meter connected, and non-revenue producing capital expenditures per customer. Earnings and Dividends - ---------------------- The Company's earnings applicable to common stock in 2003 were $45.7 million, compared to $41.5 million in 2002 and $47.8 million in 2001. Earnings were $1.76 a share in 2003, compared to $1.62 a share in 2002 and $1.88 a share in 2001. Net operating revenues in 2003 were about the same as in 2002, but higher amounts for other income ($17 million) in 2003 more than offset higher operating expenses ($14.5 million). Earnings for 2002 were reduced by charges of $13.9 million (before tax) representing the Company's transaction costs incurred in its efforts to acquire Portland General Electric Company (PGE) from Enron. Excluding these charges, earnings per share from consolidated operations in 2002 would have been $1.95 a share. Earnings for 2001 were the highest on record for the Company. NW Natural earned $1.57 a diluted share from gas utility operations in 2003, compared to $1.76 a share in both 2002 and 2001. Weather conditions in its service territory in 2003 were 7 percent warmer than the 25-year average and 7 percent warmer than 2002. Temperatures in 2002 were very close to average but were 2 percent warmer than 2001. Weather in 2001 was 1 percent colder than average. Results in 2003 from the Company's non-utility operations were earnings of 19 cents a share, including 17 cents a share from NW Natural's gas storage business segment and 2 cents a share from subsidiary and other non-utility operations (see "Results of Operations--Non-utility Operations," below). Non-utility results for 2002 were a loss of 14 cents a share, including earnings of 14 cents a share from the gas storage segment, a loss of 33 cents a share relating to the Company's efforts to purchase PGE, and earnings of 5 cents a share from other subsidiary and non-utility operations. Non-utility results for 2001 were earnings of 12 cents a share, including 8 cents a share from the gas storage segment. For the 48th consecutive year, the Company's dividends paid on common stock increased in 2003. Dividends paid on common stock were $1.27 a share in 2003 compared to $1.26 a share in 2002 and $1.245 a share in 2001. Application of Critical Accounting Policies and Estimates - --------------------------------------------------------- In preparing the Company's financial statements using generally accepted accounting principles in the United States of America (GAAP), management exercises judgment in the selection and application of accounting 19 principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, 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 different 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, and environmental contingencies. 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 policies and estimates are described below. Regulatory Accounting --------------------- NW Natural is regulated by the Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC), which establish rules governing the Company's utility rates and services, and to a certain extent set forth the accounting treatment for certain regulatory transactions. In general, NW Natural uses the same accounting principles as other non-regulated companies reporting under GAAP. However, certain accounting principles, primarily Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," require different accounting treatment for regulated companies to show the effects of regulation. For example, NW Natural accounts for the cost of gas using a deferral and cost recovery mechanism called the Purchased Gas Adjustment (PGA), which is approved annually by the OPUC and WUTC (see "Results of Operations--Cost of Gas Sold," below). There are other expenses or revenues that the OPUC or WUTC may require the Company to defer and recover 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 expense or revenue on the income statement at the same time it realizes the adjustment to amounts included in utility rates and charged to customers. The conditions a regulated company must satisfy to apply the accounting policies and practices of SFAS No. 71 include: o an independent regulator sets rates; o the regulator sets the rates to cover specific costs of delivering service; and o the service territory lacks competitive pressures to reduce rates below the rates set by the regulator. NW Natural applies SFAS No. 71 in accounting for its regulated utility operations. The Company periodically assesses whether it can continue to apply SFAS No. 71. If NW Natural should determine in the future that all or a portion of its regulatory assets and 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 of its regulatory assets and liabilities as a charge to income. Revenue Recognition ------------------- Utility revenues, derived primarily from the sale and transportation of natural gas, are recognized when the gas is delivered to and received by the customer. Revenues are accrued for gas delivered to customers but not yet billed based on estimates of gas deliveries from the last meter reading date to month end (unbilled revenues). Unbilled revenues are dependent upon a number of factors that require management's judgment, including total gas receipts and deliveries, customer usage patterns and weather. Unbilled revenue estimates are 20 reversed the following month when actual billings occur. NW Natural's unbilled revenues at Dec. 31, 2003 and 2002 were $59.1 million and $44.1 million, respectively. In November 2003, NW Natural implemented a weather normalization mechanism in Oregon that helps stabilize the Company's net operating revenues by adjusting current customer billings based on temperature variances from average weather (see "Results of Operations--Regulatory Matters--Rate Mechanisms," below). Non-utility revenues, derived primarily from gas storage services, are recognized upon delivery of the service to customers. Revenues from optimization of excess storage and transportation capacity are recognized over the life of the contract for guaranteed amounts under the contract, or are recognized as earned for amounts above the guaranteed value. Accounting for Derivative Instruments and Hedging Activities ------------------------------------------------------------ The Company's Derivatives Policy sets forth the guidelines for using selected financial derivative products to support prudent risk management strategies within designated parameters (see Note 1). The policy specifically prohibits the use of derivatives for trading or speculative purposes. The Company's primary hedging activities consist of natural gas commodity price and foreign currency exchange rate hedges, which are accounted for as cash flow hedges. The Company's commodity and foreign currency hedge transactions are included in the annual PGA mechanism, and as such all gains and losses are subject to regulatory deferral under SFAS No. 71 (see "Regulatory Accounting," above). The following table summarizes the realized gains and losses from NW Natural's commodity and currency hedge transactions in 2003, 2002 and 2001:
(Thousands) 2003 2002 2001 - --------------------------------------------------------------------------------------------------------------- Gains (losses) on commodity swap contracts $ 29,660 $ (73,922) $ 44,191 Gains (losses) on commodity option contracts 2,723 (1,601) 13,383 ---------- --------- --------- Subtotal 32,383 (75,523) 57,574 Gains on currency contracts 4,129 521 824 ---------- --------- --------- Total gains (losses) on commodity and currency contracts $ 36,512 $ (75,002) $ 58,398 ========== ========= =========
Realized gains (losses) from commodity and foreign currency hedge contracts are recorded as reductions (increases) to the cost of gas and are included in the calculation of annual PGA rate changes. Unrealized gains and losses resulting from mark-to-market valuations are not recognized in current income or other comprehensive income, but are reported as regulatory liabilities or regulatory assets, which are offset by a corresponding balance in non-trading derivative assets or liabilities (see Note 11). Accounting for Pensions ----------------------- NW Natural has two qualified non-contributory defined benefit pension plans covering all regular employees with more than one year of service. These plans are funded through a trust dedicated to providing retirement benefits. Net periodic pension costs and accumulated benefit obligations are determined in accordance with SFAS No. 87, "Employers' Accounting for Pensions" (see "Financial Condition--Pension Cost (Income) and Funding Status," below, and Note 7), using a number of assumptions including the discount rate, the rate of compensation increases, retirement ages, mortality rates and expected long-term return on plan assets. These assumptions have a significant impact on the amounts reported. NW Natural's pension cost consists of service costs, interest costs, amortization of actuarial gains and losses, expected returns on plan assets and, in part, on a market-related valuation of assets. Variances between 21 expected returns and actual investment returns are recognized over a three-year period from the year in which they occur, thereby reducing year-to-year volatility. The Company considers a number of factors in developing its 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 consultants. For the Dec. 31, 2003 measurement date, the Company: o decreased its discount rate assumption from 6.75 percent to 6.25 percent; o lowered its salary and wage increase assumption from a range of 4.25-5.00 percent to a range of 4.00-4.75 percent; and o increased its expected long-term return on plan assets from 8.00 percent to 8.25 percent. Changes in these factors were the primary contributors to a net increase in the Company's accumulated benefit obligation from $172 million at Dec. 31, 2002, to $192 million at Dec. 31, 2003. The Company believes its pension assumptions to be appropriate based upon the above factors. However, if the discount rate were changed by one-quarter percentage point, the net periodic pension cost would be changed by approximately $0.6 million. If the expected return on plan assets were changed by one-quarter percentage point, the net periodic pension cost would be changed by approximately $0.4 million. Contingencies ------------- The Company records loss contingencies as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable. Estimating probable losses requires an analysis of uncertainties that often depend upon judgments about potential actions by third parties. In the normal course of business, the Company records accruals for loss contingencies based on an analysis of potential results, developed in consultation with outside counsel when appropriate, including allowances for uncollectible accounts, environmental claims and property damage and personal injury claims. It is possible, however, that future results of operations could be materially affected by changes in assumptions or estimates regarding these contingencies. With respect to environmental claims, the Company records receivables for anticipated recoveries under insurance contracts, or from future utility rates, when recovery is probable. See Note 12. Results of Operations - --------------------- Regulatory Matters ------------------ NW Natural provides gas utility service in Oregon and Washington, with Oregon representing over 90 percent of its revenues. Future earnings and cash flows from utility operations will be determined 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 expenses, and to obtain reasonable and timely regulatory ratemaking treatment for investments made in utility plant. General Rate Cases ------------------ In August 2003, the OPUC entered an order covering all of the issues in NW Natural's first Oregon general rate case since 1999. The order included, among other things, (i) the settlement of NW Natural's cost of service, including operations and maintenance expenses, (ii) projected investments for the prospective test year, (iii) a capital structure including 49.5 percent common equity, (iv) a return on common shareholders' equity (ROE) of 10.2 percent, (v) a rate redesign that shifted $4.8 million of margin revenue 22 requirement from industrial rate schedules to residential and commercial rate schedules, and (vi) the adoption of a weather normalization mechanism. The order authorized a revenue increase of $13.9 million per year, of which $6.2 million went into effect on Sept. 1, 2003 and $2.8 million went into effect on a deferred basis on Nov. 12, 2003 as the first 11.7 miles of the Company's South Mist Pipeline Extension (SMPE) was placed into service. The remainder will go into effect as all or portions of the SMPE project and the Company's Coos County distribution system project are completed and go into service in 2004 (see "Financial Condition--Investing Activities," below). NW Natural's most recent general rate increase in Washington, which was fully effective in October 2001, authorized rates designed to produce an ROE of 10.8 percent. The WUTC approved a revenue increase of $4.3 million per year, or 12.1 percent. In November 2003, NW Natural filed a new general rate case in Washington. The filing proposes a revenue increase of $7.9 million per year from Washington operations through rate increases averaging 15 percent. The proposed rates are designed to produce an ROE of 11 percent and to recover increases in NW Natural's cost of service including costs for expansion of the Mist gas storage system and construction of a new service center in Vancouver; higher expenses in areas such as pensions, health benefits and insurance; and revenue declines due to changes in customers' consumption patterns. NW Natural also is proposing a decoupling mechanism for residential and commercial customers that includes weather normalization, and a re-design of industrial rates. The schedule for the case provides for settlement conferences in April 2004, the filing of WUTC staff and intervenor testimony in May, hearings in July and a decision by the WUTC determining new rates by the end of October 2004. The Company is unable to determine the extent to which its proposals will be accepted by the WUTC. Rate Mechanisms --------------- The weather normalization mechanism approved by the OPUC will be applied to NW Natural's Oregon residential and commercial customers' bills between Nov. 15 and May 15 of each heating season, beginning November 2003. 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 the recovery of fixed costs and reduce fluctuations in customers' bills due to colder- or warmer-than-average weather. Rate changes are applied each year under the PGA mechanisms in NW Natural's tariffs in Oregon and Washington to reflect changes in the costs of natural gas commodity purchased under contracts with gas producers (see "Comparison of Gas Operations--Cost of Gas Sold," below), the application of temporary rate adjustments to amortize balances in regulatory asset or liability accounts and the removal of temporary rate adjustments effective the previous year. In 2003, the OPUC approved a rate increase averaging 3.5 percent for Oregon sales customers and the WUTC approved a rate increase averaging 16.8 percent for Washington sales customers, both effective on Oct. 1, 2003. In 2002, the OPUC approved PGA rate decreases averaging 14 percent for NW Natural's Oregon sales customers and the WUTC approved PGA rate decreases averaging 25 percent for NW Natural's Washington sales customers, both effective on Oct. 1, 2002. In 2001, the OPUC approved PGA rate increases averaging 22 percent for Oregon sales customers and the WUTC approved PGA rate increases averaging 21 percent for Washington sales customers, both effective on Oct. 1, 2001. In an order issued in 1999, the OPUC formalized a process that tests for excessive earnings in connection with gas utilities' annual filings under their PGA mechanisms. The OPUC confirmed NW Natural's ability to pass through 100 percent of its prudently incurred gas costs into rates. Under this order, NW Natural is authorized to retain all of its earnings up to a threshold level equal to its 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 movements in interest rates. No amounts were identified in this process for refund to customers with respect to NW Natural's earnings results in 2002 or 2001. NW Natural does not 23 expect there will be amounts identified for refund with respect to its earnings in 2003, which will be reviewed by the OPUC in the second quarter of 2004. In 2002, the OPUC approved a rate mechanism designed to stabilize margin revenues in the face of above- or below-normal consumption patterns. NW Natural believes that reductions in recent years in its customers' gas consumptions per degree-day (see "Comparison of Gas Operations--Residential and Commercial," below) were caused by increases in the cost of purchased gas that were passed on to customers as rate increases, and to efforts throughout the region to conserve energy. The mechanism adjusts for rate changes according to the impact of price elasticity, starting with small increases to residential and commercial rates that became effective on Oct. 1, 2002. These rate changes contributed an estimated $3.5 million of margin, equivalent to 8 cents a share of earnings, during the fourth quarter of 2002 and an estimated $6.5 million of margin, equivalent to 15 cents a share of earnings, during the first eight months of 2003 before the Oregon general rate increase took effect. In addition, the OPUC authorized NW Natural to implement a partial decoupling mechanism effective Oct. 1, 2002. Decoupling mechanisms are used to break the link between a utility's earnings and the energy consumed by its customers so the utility does not have an incentive to discourage customers' conservation efforts. The decoupling mechanism works by adding margin revenues during periods when customer consumptions are lower than baseline consumption or by deducting margin revenues when consumptions are higher than the baseline. Under the partial decoupling mechanism, NW Natural uses a balancing account to defer and subsequently amortize 90 percent of the margin differentials between baseline usage by its residential and commercial customers and weather-normalized actual usage by these customers. The deferred amounts are treated as adjustments to be refunded or collected in future periods. Baseline consumption is based on customer consumption patterns determined in the Oregon general rate case, adjusted for consumptions 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 mechanism's effectiveness. In connection with the OPUC's approval of the decoupling mechanism, NW Natural agreed to adopt certain service quality measures that establish the Company's performance goal for minimizing complaints by customers where the Company is determined to be at fault. If NW Natural exceeds the prescribed level of at-fault complaints, it will be subject to penalties. NW Natural was not subject to penalties relating to these measures in 2003. 24 Comparison of Gas 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) 2003 2002 2001 - ------------------------------------------------------------------------------------------------------------------------- Utility gas sales and transportation volumes - therms: - ------------------------------------------------------ Residential and commercial sales 569,791 597,246 592,358 Unbilled volumes 12,099 (6,617) 1,771 ---------- ---------- ---------- Weather-sensitive volumes 581,890 53% 590,629 52% 594,129 53% Industrial firm sales 55,314 5% 63,215 6% 79,778 7% Industrial interruptible sales 47,994 4% 26,241 2% 63,597 6% ---------- --- ---------- --- ---------- --- Total gas sales 685,198 62% 680,085 60% 737,504 66% Transportation deliveries 414,554 38% 445,999 40% 385,783 34% ---------- --- ---------- --- ---------- --- Total volumes sold and delivered 1,099,752 100% 1,126,084 100% 1,123,287 100% ========== === ========== === ========== === Utility operating revenues - dollars: - ------------------------------------- Residential and commercial sales $ 504,849 $ 556,210 $ 520,141 Unbilled revenues 14,474 (12,702) 13,774 ---------- ---------- ---------- Weather-sensitive revenues 519,323 86% 543,508 86% 533,915 84% Industrial firm sales 33,578 6% 42,965 7% 49,662 8% Industrial interruptible sales 23,661 4% 15,937 2% 34,283 5% ---------- --- ---------- --- ---------- --- Total gas sales 576,562 96% 602,410 95% 617,860 97% Transportation revenues 17,962 3% 26,020 4% 20,637 3% Other revenues 7,460 1% 4,018 1% (2,325) - ---------- --- ---------- --- --------- --- Total utility operating revenues $ 601,984 100% $ 632,448 100% $ 636,172 100% ========== === ========== === ========== === Cost of gas sold $ 323,128 $ 353,034 $ 364,699 ========== ========== ========== Utility net operating revenues (margin) $ 278,856 $ 279,414 $ 271,473 ========== ========== ========== Total number of customers (end of period) 578,150 560,067 540,931 ========== ========== ========== Actual degree days 3,952 4,232 4,325 ========== ========== ========== 25-year average degree days 4,238 4,257 4,267 ========== ========== ==========
NW Natural refunded deferred gas cost savings to its Oregon customers through billing credits in June 2002. These refunds were the customers' 67 percent portion of gas cost savings realized between October 2001 and March 2002, which had been deferred, with interest, pursuant to NW Natural's PGA tariff in Oregon (see "Cost of Gas Sold," below). The refunds reduced gross operating revenues during 2002 by $30.4 million, and reduced both cost of gas and deferred gas costs payable by $29.5 million. The refunds also reduced margin by about $0.9 million, but this amount was almost entirely offset by corresponding reductions in franchise tax expense and uncollectible accounts expense such that the effect of the refunds on net income was negligible. 25 Residential and Commercial Sales -------------------------------- NW Natural continued to grow its customer base, with a net increase of 18,083 customers during 2003. This represents a growth rate of 3.2 percent, compared to 3.5 percent in 2002 and 3.3 percent in 2001. In the three years ended Dec. 31, 2003, more than 54,000 customers were added to the system, representing an average annual growth rate of 3.5 percent. The volumes of gas sold to residential and commercial customers were 1 percent lower in 2003 than in 2002, reflecting warmer weather that was partially offset by customer growth and the price elasticity effects of lower rates. Related revenues were 4 percent lower in 2003 than in 2002. Excluding the impact of gas cost refunds totaling $30.4 million to Oregon customers during 2002, related revenues were $54.6 million, or 10 percent, lower in 2003 than in 2002, primarily due to lower rates effective Oct. 1, 2002 (see "Regulatory Matters--Rate Mechanisms," above). The volumes of gas sold to residential and commercial customers were 1 percent lower in 2002 than in 2001, reflecting warmer weather as well as lower consumption patterns by customers due to higher gas commodity prices included in rates in previous years. Excluding the impact of the refunds to Oregon customers during 2002, related revenues increased 7 percent, primarily due to PGA rate increases effective Oct. 1, 2001. Typically, 80 percent or more of NW Natural's annual operating revenues are derived from gas sales to weather-sensitive residential and commercial customers. Accordingly, variations in temperatures between periods will affect volumes of gas sold to these customers. Weather conditions in 2003 were 7 percent warmer than average. Temperatures were very close to average in 2002 and 1 percent colder than average in 2001. Weather in 2003 was 7 percent warmer than 2002 and 2002 was 2 percent warmer than 2001. Average weather conditions are calculated from the most recent 25 years of temperature data measured by heating degree-days. In November 2003, NW Natural implemented a weather normalization mechanism that will be applied to Oregon residential and commercial customers' bills between Nov. 15 and May 15 of each heating season (see "Regulatory Matters--Rate Mechanisms," above). Customers may opt out of the mechanism during a defined period each year; less than 10 percent of NW Natural's Oregon residential and commercial customers opted out during its first heating season. The mechanism contributed $2.1 million of margin in the fourth quarter of 2003 due to warmer-than-average weather. The contribution was equivalent to 5 cents a share of earnings, making up a significant portion of the weather-related margin loss in that quarter. In order to match revenues with related purchased gas costs, NW Natural records unbilled revenues for gas delivered and sold to customers, but not yet billed, through the end of the period. Amounts reported as unbilled revenues reflect the increase or decrease in the balance of unbilled revenues over the prior year-end. Weather conditions, rate changes and customer billing dates from one period to the next affect year-end balances. 26 Industrial Sales and Transportation ----------------------------------- The following table summarizes the delivered volumes and utility net operating revenues (margin) in the industrial and electric generation markets:
(Thousands) 2003 2002 2001 ----------------------------------------------------------------------------------------------- Delivered volumes - therms: ---------------------------- Industrial sales and transportation 519,265 531,195 486,116 Electric generation 1,667 3,400 42,867 --------- --------- --------- Total volumes 520,932 534,595 528,983 ========= ========= ========= Utility net operating revenues - dollars: ------------------------------------------ Industrial sales and transportation $ 37,693 $ 40,666 $ 43,251 Electric generation 6 4,584 4,721 --------- --------- --------- Total margin $ 37,699 $ 45,250 $ 47,972 ========= ========= =========
Total volumes delivered to industrial and electric generation customers were 3 percent lower in 2003 than in 2002, and 1 percent higher in 2002 than in 2001. Combined margins from these customers were 17 percent lower in 2003 than in 2002 and 6 percent lower in 2002 than in 2001. Excluding electric generation customers, volumes delivered to end-use industrial sales and transportation customers were 2 percent lower and margin was 7 percent lower in 2003 than in 2002. Results from the industrial market in 2003 reflect weak economic conditions during the year, as well as some cost-related changes in the design of industrial rates in the Oregon general rate case that reduced industrial margins in the fourth quarter. Volumes delivered to industrial customers were 9 percent higher in 2002 than in 2001, but margin was 6 percent lower. The decline in margin from these customers in 2002 was due to migrations of some industrial customers from higher margin firm service to lower margin interruptible service and to plant shutdowns or cutbacks in the manufacturing sector because of economic conditions. NW Natural re-designed its industrial rates in Oregon as part of its general rate case in 2003, transferring $4.8 million of annual revenue requirement from industrial rates to residential and commercial rates in order to better reflect relative costs of service and to become more competitive in the industrial market. In the electric generation market, margin was negligible in 2003 but was $4.6 million and $4.7 million in 2002 and 2001, respectively, equivalent to 11 cents a share in each year. More than 90 percent of the margin, but only about 14 percent of the gas deliveries, in 2002 and 2001 was from two customers that were served under contracts that went into effect in the second half of 2001 and expired at the end of the second quarter of 2002. Most of the margin from these contracts was from fixed charges. A third electric generation customer used 3.0 million therms in 2002 and 36.8 million therms in 2001 under contracts with low volumetric charges. Other Revenues -------------- Other revenues include revenues and revenue adjustments from sources other than the sale and transportation of gas (see Note 1), including deferrals to and amortizations from regulatory asset and liability accounts and miscellaneous customer fees. In 2003, other revenues contributed $7.5 million to utility operating revenues compared to $4.0 million in 2002 and a negative $2.3 million in 2001. Other revenues in 2003 included positive contributions due to amortizations of regulatory accounts covering customer consumption under NW Natural's decoupling mechanism (see "Regulatory Matters--Rate Mechanisms," above), amortizations of income shared with customers from interstate gas storage services, and customer late payment and collection fees and miscellaneous revenues, partially offset by amortizations from regulatory accounts covering conservation programs and Year 2000 costs. 27 The following table summarizes other revenues by primary category in 2003, 2002 and 2001:
(Thousands) 2003 2002 2001 - -------------------------------------------------------------------------- Rate adjustments: Decoupling deferrals $ 3,466 $ 1,720 $ -- Decoupling amortizations (783) -- -- Interstate storage amortization 3,057 1,212 -- Conservation programs amortization (2,408) (2,074) (4,941) Year 2000 amortization (949) (1,539) (1,236) Miscellaneous revenues: Customer fees 2,919 3,115 2,991 Other 2,158 1,584 861 -------- -------- --------- Total other revenues $ 7,460 $ 4,018 $ (2,325) ======== ======== =========
Cost of Gas Sold ---------------- Natural gas commodity prices have fluctuated dramatically in recent years. NW Natural has sought to mitigate the effect of higher gas commodity prices and price volatility on core utility customers through the use of its underground storage facilities, by entering into gas commodity-based financial hedge contracts, and by making short-term sales of gas commodity and transportation capacity to on-system or off-system customers in periods when core utility customers do not fully utilize firm pipeline capacity and gas supplies. In 2003, the Company replaced all of its expiring long-term contracts with supply contracts for gas purchases of similar aggregate volume levels. All of the new contracts have terms of five years or less and contain commodity price provisions that are tied directly to monthly market index prices for the term of the contract. The Company enters into financial hedge contracts that are intended to have the effect of converting these monthly market index prices into fixed prices for most of its gas purchases under these contracts. The cost per therm of gas sold was 9 percent lower in 2003 than in 2002, and 5 percent higher in 2002 than in 2001. The cost per therm of gas sold includes current gas purchases, gas drawn from storage inventory, gains or losses from commodity hedges, margin from off-system gas sales, demand cost balancing adjustments (demand equalization), regulatory deferrals and company use. Results for 2002 included an adjustment that reduced cost of gas by $29.5 million (see "Comparison of Gas Operations," above). Excluding this adjustment, cost per therm of gas sold was 16 percent lower in 2003 than in 2002, reflecting decreases in gas commodity prices effective in late 2002, and 14 percent higher in 2002 than in 2001, reflecting increases in gas commodity prices effective in late 2001. Results for 2002 also included adjustments reducing cost of gas relating to amounts of deferred expenses for the recovery of pipeline demand charges under NW Natural's PGA mechanism. These adjustments contributed 7 cents a share to earnings in 2002, of which 6 cents a share applied to periods prior to 2002. The rate methodology 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 0.55 percent of gas sendout in 2003, compared to 0.75 percent in 2002. Unaccounted-for gas is the difference between the amount of gas the Company receives from all sources, 28 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 leakage, but it also may be due to cumulative inaccuracies in gas metering, estimates of unbilled gas or other causes. NW Natural considers a normal amount of unaccounted-for gas to be 0.50 percent of its total gas sendout during a period, but the amount may vary within a range around this estimate. During 2003, the lower estimated amount of unaccounted-for gas had the effect of reducing cost of gas and increasing margin by $1.2 million as compared to 2002. NW Natural uses a natural gas commodity-price hedge program under the terms of its Derivatives Policy to help manage its variable price gas commodity contracts (see "Application of Critical Accounting Policies and Estimates--Accounting for Derivative Instruments and Hedging Activities," above). NW Natural recorded net hedging gains of $32.4 million from this program during 2003, compared to net hedging losses of $75.5 million in 2002 and net hedging gains of $57.6 million in 2001, with negligible impact on net income in any of those years. Hedging gains and losses relating to gas commodity purchases are included in cost of gas and factored into NW Natural's annual PGA rate adjustments. Under NW Natural's PGA tariff in Oregon, net income from Oregon operations is affected within defined limits by changes in purchased gas costs. NW Natural is allowed to collect an amount for purchased gas costs based on estimates that are included in current utility rates. If the actual purchased gas costs are higher than the amounts included in rates, NW Natural is not allowed to charge its customers currently for those higher gas costs but is allowed to defer the costs and collect them in the future. Similarly, when the actual purchased gas costs are lower than the amount included in rates, the savings are not immediately passed on to customers but are deferred and refunded in future periods. NW Natural absorbs 33 percent of the higher cost of gas sold, or retains 33 percent of the lower cost, in either case as compared to the projected costs built into rates. The remaining 67 percent of the higher or lower gas costs is recorded as deferred regulatory assets or liabilities for recovery from or refund to customers in future rates. NW Natural's gas costs in 2003 were slightly lower than the gas costs embedded in rates, with the effect that NW Natural's share of the lower costs increased margin by $0.3 million, equivalent to less than 1 cent a share of earnings. In 2002 and 2001, NW Natural's gas costs were much lower than the projected costs built into rates and the Company's share of the savings realized from gas purchases contributed $10.8 million and $4.1 million of margin, equivalent to 26 cents a share and 10 cents a share of earnings, respectively. Due to the warm weather and the reduced gas requirements of its industrial sales customers during 2003, NW Natural was able to use gas supplies that were under contract for the winter season, but were not required for delivery to core market customers, to make off-system gas sales. The Company's purchase prices for this gas had been locked in through commodity swap and call option agreements entered into in the prior year at levels lower than market prices during 2003. Under the PGA tariff, the margin from these sales is treated as a reduction to cost of gas, with the effect that 67 percent is deferred for refund to NW Natural's customers and the remaining 33 percent is retained by the Company. NW Natural's share of the margin from off-system gas sales in 2003 was $4.9 million, equivalent to 11 cents a share of earnings, compared to margin of $0.9 million or 2 cents a share of earnings in 2002 and margin of $1.0 million or 2 cents a share of earnings in 2001. Non-utility Operations ---------------------- At Dec. 31, 2003 and 2002, the Company's non-utility operations consisted of gas storage operations and two wholly-owned subsidiaries, Financial Corporation and Northwest Energy. Of the subsidiaries, only Financial Corporation had active operations during 2002 and 2003. Gas Storage ----------- NW Natural realized net income from its non-utility gas storage business segment in 2003, after regulatory sharing and income taxes, of $4.3 million or 17 cents a share, compared to $3.6 million or 14 cents a share in 2002 and $2.1 million or 8 cents a share in 2001. 29 Gas storage services include sales to off-system interstate customers using storage capacity that has been developed in advance of core utility customers' 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 distribution to its core utility customers. Results for the gas storage business segment also include revenues, net of amounts shared with core utility customers, from a contract with an independent energy trading company that seeks to optimize the use of NW Natural's assets by trading temporarily unused portions of its gas storage capacity and upstream pipeline transportation capacity. NW Natural retains 80 percent of the pre-tax income from the optimization of storage and pipeline transportation capacity when the costs of such capacity have not been included in core utility rates, or 33 percent of the pre-tax income from such capacity when the costs have been included in core utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for distribution to NW Natural's core utility customers. Financial Corporation --------------------- Financial Corporation's operating results in 2003 were net income of $0.7 million, compared to $1.2 million in 2002 and $0.7 million in 2001. The decrease in net income in 2003 compared to 2002 was primarily due to lower income from investments in limited partnerships in wind and solar electric generation projects in California, and lower miscellaneous receivables. The increase in net income in 2002 compared to 2001 was due to higher income from these investments. The Company's investment in Financial Corporation at Dec. 31, 2003, was $5.5 million, compared to $9.1 million and $7.9 million at Dec. 31, 2002 and 2001, respectively. The reduced investment in Financial Corporation at Dec. 31, 2003, was primarily due to a $4.2 million cash dividend that Financial Corporation paid to NW Natural in the fourth quarter of 2003. Northwest Energy ---------------- Northwest Energy was formed in 2001 to serve as the holding company for NW Natural and PGE if the acquisition of PGE had been completed. Northwest Energy recorded nominal expenses for corporate development activities in 2003. Upon the termination of the proposed acquisition effort in 2002, Northwest Energy recorded a loss totaling $8.4 million (after tax) for the transaction costs incurred in connection with this effort. These charges were equivalent to 33 cents a share. Operating Expenses ------------------ Operations and Maintenance -------------------------- Operations and maintenance expenses of $96.4 million in 2003 were $11.3 million, or 13 percent, higher than in 2002. The increase was primarily due to higher operating payroll costs from added positions and wage, salary, vacation and bonus increases ($4.1 million), higher pension costs including the impact of changes in actuarial assumptions ($3.1 million) (see "Financial Condition--Pension Cost (Income) and Funding Status," below), higher premiums for health care and prescription drug coverage ($0.9 million), higher renewal premiums on business risk insurance ($0.9 million), higher employee benefit costs ($0.8 million), higher professional services fees ($0.7 million), and higher expenses relating to workers compensation ($0.5 million) and other operating costs ($1.2 million). These cost increases were partially offset by a decrease in uncollectible accounts expense ($0.9 million) due to lower net write-offs of accounts receivable compared to 2002, when customer bills and subsequent write-offs were impacted by higher gas prices and colder weather. Most of the cost increases NW Natural experienced in 2003 were recognized in the rate increases resulting from the Company's general rate case in Oregon (see "Regulatory Matters--General Rate Cases," above). 30 Operations and maintenance expenses of $85.1 million in 2002 were $1.2 million, or 1 percent, higher than in 2001. The increase in 2002 resulted primarily from higher pension costs ($2.5 million), higher premiums for health care and prescription drug coverage ($1.0 million), higher payroll costs due to wage and salary increases and incentive bonus accruals ($0.8 million) and higher renewal premiums on business risk insurance ($0.3 million), partially offset by a litigation reserve in 2001 ($1.7 million), lower information technology expenses ($1.0 million) and lower uncollectible accounts expense ($0.5 million). Taxes Other Than Income Taxes ----------------------------- Taxes other than income taxes, which are principally comprised of property, franchise and payroll taxes, increased $1.0 million, or 3 percent, in 2003 over 2002. Property taxes increased $0.9 million, or 7 percent, due to utility plant additions and slightly higher property tax rates. Franchise taxes, regulatory fees and payroll tax expenses accounted for the remaining $0.1 million increase. In 2002, taxes other than income taxes increased $1.8 million, or 6 percent, over 2001. Property taxes increased $1.6 million, or 13 percent, due to utility plant additions and higher property tax rates. Depreciation and Amortization ----------------------------- The following table summarizes the increases in total plant and property and total depreciation and amortization for the three years ended Dec. 31, 2003:
(Thousands) 2003 2002 2001 ------------------------------------------------------------------------------------------------------ Plant and property: Utility plant: Depreciable $ 1,598,485 $ 1,498,903 $ 1,434,009 Non-depreciable, including construction work in progress 60,604 41,062 31,070 ----------- ----------- ------------ 1,659,089 1,539,965 1,465,079 ----------- ----------- ------------ Non-utility property: Depreciable 22,353 20,832 18,203 Non-depreciable, including construction work in progress 1,042 -- -- ----------- ----------- ------------ 23,395 20,832 18,203 ----------- ----------- ------------ Total plant and property $ 1,682,484 $ 1,560,797 $ 1,483,282 =========== =========== ============ Depreciation and amortization: Utility plant $ 53,798 $ 51,693 $ 49,413 Non-utility property 451 397 227 ----------- ----------- ------------ Total depreciation and amortization expense $ 54,249 $ 52,090 $ 49,640 =========== =========== ============ Average depreciation rate 3.5% 3.5% 3.5% =========== =========== ============
31 The Company's total depreciation and amortization expense increased by $2.2 million, or 4 percent, in 2003 and by $2.5 million, or 5 percent, in 2002. The increased expense for both years is primarily due to additional investments in utility property that were made to meet continuing customer growth and to expand the use of the Company's Mist gas storage system (see "Financial Condition--Cash Flows--Investing Activities," below). As a percentage of average depreciable plant and property, both total depreciation and amortization expense and utility depreciation and amortization expense was 3.5 percent in each of 2003, 2002 and 2001. Non-utility depreciation and amortization expense as a percentage of average depreciable non-utility property was 2.1 percent in 2003, 2.0 percent in 2002 and 1.7 percent in 2001. Other Income (Expense) ---------------------- Other income (expense) improved by $17.0 million in 2003, primarily due to the $13.9 million pre-tax charge for costs incurred in 2002 for the effort to acquire PGE. Excluding this charge, the Company's other income (expense) increased by $3.1 million in 2003. The increase was primarily due to reductions in interest charges on deferred regulatory account balances ($1.4 million) reflecting 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 market value of equity-based life insurance investments, partially offset by a decrease in earnings from equity investments ($0.5 million) due to lower income from partnership investments held by Financial Corporation. Other income (expense) decreased $16.2 million in 2002 compared to 2001, primarily due to the $13.9 million charge relating to PGE transaction costs. Excluding this charge, other income (expense) decreased $2.3 million in 2002, primarily due to higher interest accrued on deferred regulatory account balances ($2.6 million), an increase in miscellaneous non-operating expenses ($0.6 million) and a decrease in miscellaneous non-operating income ($0.3 million), partially offset by an increase in earnings from Financial Corporation's investments ($1.3 million). Interest Charges - Net ---------------------- The Company's net interest expense in 2003 was $1.0 million, or 3 percent, higher than in 2002. Interest expense in 2003 included dividends paid in the second half of 2003 totaling $0.2 million on the Company's redeemable preferred stock, which were classified as interest expense upon the adoption of SFAS No. 150 (see Note 1). The increase in interest expense in 2003 was primarily due to higher balances of debt outstanding during the period. The increase was partially offset by lower average interest rates and higher amounts of Allowance for Funds Used During Construction (AFUDC) due to higher average balances of construction work in progress (CWIP). The Company's net interest expense in 2002 was $0.3 million, or 1 percent, higher than in 2001, also due to higher balances of debt outstanding. AFUDC represents the cost of funds used for construction work in progress (see Note 1). In 2003, AFUDC reduced interest expense by $0.9 million compared to reductions of $0.6 million in 2002 and $1.0 million in 2001. The average interest rate component of AFUDC, comprised of short-term and long-term borrowing rates, as appropriate, was 2.3 percent in 2003, 2.8 percent in 2002 and 6.2 percent in 2001. Income Taxes ------------ The effective corporate income tax rates were 33.7 percent and 34.9 percent for the years ended Dec. 31, 2003 and 2002, respectively. The lower tax rate for 2003 reflects increased tax benefits from a non-taxable gain on Company- and trust-owned life insurance. Excluding these benefits, the effective tax rate for 2003 would have been 35.0 percent. The tax rate for 2002 includes 32 the effect of the tax benefit from the $13.9 million charge for PGE transaction costs. Excluding this charge, the effective tax rate for 2002 would have been 35.6 percent compared to 35.4 percent for 2001 (see Note 8). Redeemable Preferred and Preference Stock Dividend Requirements --------------------------------------------------------------- Redeemable preferred and preference stock dividend requirements decreased $2.0 million in 2003. In November 2003, NW Natural redeemed all of the outstanding shares of its $7.125 Series of Redeemable Preferred Stock with an aggregate stated value of $7.5 million at the applicable early redemption price of 102.375 percent. In December 2002, NW Natural redeemed all 250,000 outstanding shares ($25 million aggregate stated value) of its $6.95 Series of Redeemable Preference Stock pursuant to the mandatory redemption provisions applicable to that Series. Dividend requirements for the preferred and preference stock decreased by $0.1 million in both 2002 and 2001 due to annual sinking fund redemptions. At Dec. 31, 2003, no shares of redeemable preferred or preference stock were outstanding. Financial Condition - ------------------- Capital Structure ----------------- The Company's goal is to maintain a capital structure comprised of 45 to 50 percent common stock equity, up to 5 percent preferred stock and 45 to 50 percent short-term and long-term debt. When additional capital is required, debt or equity securities are issued depending upon both the target capital structure and market conditions. These sources also are used to meet long-term debt and preferred stock redemption requirements and to pay down outstanding commercial paper (see "Liquidity and Capital Resources," below, and Notes 3 and 5). Liquidity and Capital Resources ------------------------------- At Dec. 31, 2003, the Company had $4.7 million in cash and cash equivalents compared to $7.3 million at Dec. 31, 2002. Short-term liquidity is provided by cash from operations and from the sale of commercial paper notes, which are supported by commercial bank lines of credit. The Company has available through Sept. 30, 2004, committed lines of credit with four commercial banks (see "Lines of Credit," below, and Note 6). NW Natural's capital expenditures are primarily related to utility construction resulting from customer growth and system improvements (see "Cash Flows--Investing Activities," below). In addition, NW Natural has certain contractual commitments under capital leases, operating leases and gas supply purchase and other contracts that require an adequate source of funding. These capital and contractual expenditures are financed through cash from operations and from the issuance of short-term debt, which is periodically refinanced through the sale of long-term debt or equity securities. In October 2002, the Company filed a registration statement with the Securities and Exchange Commission (SEC) registering $150 million of Medium-Term Notes, Series B (MTNs). This filing became effective in January 2003. Pursuant to this registration statement, during 2003 the Company issued $90 million of MTNs and used the proceeds to pay down outstanding commercial paper balances and to fund, in part, NW Natural's ongoing utility construction program (see "Financing Activities," below). In February 2004, the Company filed a universal shelf registration statement with the SEC for the registration of $200 million of securities, which may include First Mortgage Bonds, unsecured debt, preferred stock and common stock. Concurrent with the February 2004 shelf filing, the Company withdrew from registration the $60 million of MTNs remaining on its previous shelf registration. The $200 million universal shelf registration statement became effective in February 2004. Neither NW Natural's Mortgage and Deed of Trust nor the indentures under which other long-term debt is issued contain credit rating triggers or stock price provisions that require the acceleration of debt repayment. Also, 33 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. Off-Balance Sheet Arrangements ------------------------------ The Company has no material off-balance sheet financing arrangements. 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) Payments Due in Years Ending Dec. 31, ------------------------------------------------------------ 2004 2005 2006 2007 2008 Thereafter Total - -------------------------------------------------------------------------------------------------------------------- Commercial paper $ 85,200 $ - $ - $ - $ - $ - $ 85,200 Long-term debt - 15,000 8,000 29,500 5,000 442,819 500,319 Capital leases 125 114 81 15 - - 335 Operating leases 4,289 3,767 3,754 3,686 3,626 55,326 74,448 Gas supply commitments 52,515 56,759 53,991 53,991 52,463 294,464 564,183 SMPE commitments 22,696 - - - - - 22,696 Other purchase commitments 14,330 95 - - - - 14,425 ------------------------------------------------------------------------------------- Total $ 179,155 $ 75,735 $ 65,826 $ 87,192 $ 61,089 $ 792,609 $ 1,261,606 =====================================================================================
SMPE commitments in 2004 primarily consist of obligations NW Natural has to a general contractor to complete the construction of the remaining portion of the SMPE project. A construction contract is in place for one segment of the pipeline and an additional contract is currently being negotiated for the remainder of the project. Other purchase commitments primarily consist of remaining balances under existing purchase orders. These and other contractual 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 MTNs have put options that, if exercised, would accelerate the maturity of long-term debt by $10 million in 2005, $20 million in 2007 and $20 million in 2008. Commercial Paper ---------------- The Company's primary source of short-term funds is commercial paper notes payable. Both NW Natural and Financial Corporation issue commercial paper under agency agreements with a commercial bank. NW Natural's commercial paper is supported by its committed bank lines of credit (see "Lines of Credit," below), while Financial Corporation's commercial paper is supported by committed bank lines of credit and the guaranty of NW Natural (see Note 6). NW Natural had $85.2 million in commercial paper notes outstanding at Dec. 31, 2003, compared to $69.8 million outstanding at Dec. 31, 2002. Financial Corporation had no commercial paper notes outstanding at Dec. 31, 2003 or 2002. 34 Lines of Credit --------------- NW Natural has lines of credit with four commercial banks totaling $150 million. Half of the credit facility with each bank, totaling $75 million, is committed and available through Sept. 30, 2004, and the other $75 million is committed and available through Sept. 30, 2005. NW Natural may be unable to draw upon the two-year portions of the credit lines, totaling $75 million, until filings are made or approvals received from the OPUC or the WUTC with respect to its notes relating to the two-year commitments. NW Natural expects that it will be able to make the necessary filings or secure such approvals, if required. In addition, Financial Corporation has available through Sept. 30, 2004, committed lines of credit with two commercial banks totaling $10 million. Financial Corporation's lines are supported by the guaranty of NW Natural. Under the terms of these lines of credit, NW Natural and Financial Corporation pay commitment fees but are not required to maintain compensating bank balances. The interest rates on borrowings under these lines of credit, if any, are based on current market rates. There were no outstanding balances on either the NW Natural or Financial Corporation lines of credit at Dec. 31, 2003 or 2002. NW Natural's lines of credit require that credit ratings be maintained 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 outstanding under NW Natural's bank lines are tied to credit ratings, which would increase or decrease the cost of bank debt, if any, when ratings are changed. The lines of credit require the Company to maintain an indebtedness to total capitalization ratio of 65 percent or less and to maintain a consolidated net worth at least equal to 80 percent of its net worth at Sept. 30, 2003, plus 50 percent of the Company's net income for each subsequent fiscal quarter. Failure to comply with either of these covenants would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding. The Company was in compliance with both of these covenants at Dec. 31, 2003, and with the equivalent covenants in the prior year's lines of credit at Dec. 31, 2002. Optional Redemptions of Long-Term Debt and Redeemable Preferred Stock --------------------------------------------------------------------- In 2003, the Company exercised early redemption provisions applicable to certain of its long-term debt, including all $4 million of the 7.50% Series B MTNs due 2023, all $11 million of the 7.52% Series B MTNs due 2023, and all $20 million of the 7.25% Series B MTNs due 2023. These MTNs were redeemed in the third quarter of 2003 at 103.75 percent, 103.76 percent and 103.65 percent of their respective principal amounts. In the fourth quarter of 2003, the Company also exercised early redemption provisions applicable to all of the remaining shares of its $7.125 Series of Redeemable 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 premiums 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. 35 Cash Flows ---------- Operating Activities -------------------- Operations provided net cash of $107 million in 2003 compared to $124 million in 2002. The 14 percent decrease was due to a decrease in cash from operations before working capital changes ($19 million), partially offset by an increase in working capital ($2.1 million). The decrease in cash from operations before working capital changes compared to 2002 was primarily due to non-cash adjustments to net income in 2002, including the loss recorded for PGE costs ($13.9 million), combined with a decrease in other assets and liabilities ($27.2 million) compared to an increase in 2002, and a decrease in deferred gas costs ($5.6 million), partially offset by an adjustment to reverse the minimum pension liability recorded in 2002 ($5.0 million), a larger increase in deferred income taxes and investment tax credits ($18.7 million), higher net income from operations ($2.2 million) and higher depreciation and amortization ($2.2 million). The increase in working capital was primarily due to an increase in accrued interest and taxes compared to a decrease in 2002 ($25.9 million), a decrease in inventories compared to an increase in 2002 ($15.9 million), a larger increase in accounts payable ($7.9 million) and a larger decrease in other current assets and liabilities ($4.4 million), partially offset by increases in accounts receivable ($23.1 million) and in accrued unbilled revenue ($28.7 million), in both cases compared to decreases in 2002. NW Natural's refunds to customers of approximately $30.4 million of deferred gas cost savings in 2002 (see "Results of Operations - Comparison of Gas Operations," above) reduced cash flows from operations by that amount, but the reduction was more than offset by the other factors affecting cash flows cited above. Continuing operations provided net cash of $124 million in 2002 compared to $72 million in 2001. The 73 percent increase was due to increased cash from operations before working capital changes ($5.7 million) and lower working capital requirements ($47 million). The increase in cash from operations before working capital changes was due to an increase in deferred income taxes and investment tax credits in 2002 compared to a reduction in 2001 ($22.5 million), the loss provision for the PGE transaction costs ($13.9 million) and higher depreciation and amortization ($2.4 million), largely offset by a small increase in deferred gas cost payables in 2002 compared to a large swing from net gas cost receivables to payables in 2001 ($26.5 million), and lower net income in 2002 ($6.4 million). The decrease in working capital requirements was due to an increase in accounts payable in 2002 compared to a decrease in 2001 ($44 million), a decrease in accrued unbilled revenue in 2002 compared to an increase in 2001 ($26 million), and a decrease in accounts receivable in 2002 compared to an increase in 2001 ($22 million), partially offset by a decrease in accrued interest and taxes in 2002 compared to an increase in 2001 ($40 million) and a larger increase in inventories in 2002 ($6.2 million). 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 Assistance Act) combined with the Jobs and Growth Tax Relief Reconciliation Act of 2003 (the Reconciliation Act), allows an additional first-year tax depreciation deduction on the adjusted basis of "qualified property." The Assistance Act provides for an additional depreciation deduction equal to 30 percent 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 deduction is an acceleration of depreciation deductions that otherwise would have been taken in the later years of an asset's recovery period. In general, the extra first-year depreciation deduction is available for most personal property acquired after Sept. 10, 2001, and before Sept. 11, 2004. The Company anticipates enhanced cash flow from reduced income taxes, totaling an estimated $30 million to $50 million, during the effective period, based on actual and projected plant investments between Sept. 11, 2001 and Sept. 10, 2004. 36 Investing Activities -------------------- Cash requirements for investing activities in 2003 totaled $127 million, up from $84 million in 2002. Cash requirements for 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 NW Natural's SMPE project ($27 million), higher system improvements and support ($12 million) and other special projects to serve new customer load or new service areas ($8.9 million). Cash requirements for investing activities in 2002 totaled $84 million, down from $87 million in 2001, primarily due to lower amounts of cash used for investments in non-utility property ($6.9 million) and for the PGE transaction ($5.2 million), partially offset by higher amounts of cash used for the construction of utility plant ($7.6 million) and lower cash proceeds from the sale of assets ($2.8 million). Cash requirements for utility construction in 2002 totaled $80 million, up from $72 million in 2001, primarily as a result of capital expenditures related to NW Natural's pipeline safety program ($4.7 million) and special projects expanding service to existing customers or into new service areas ($3.4 million). Investments in non-utility property totaled $2.6 million in both 2003 and 2002, including expenditures in both years for certain improvements to the Company's gas pipeline system that were primarily related to interstate storage services. During the five-year period 2004 through 2008, utility construction expenditures are estimated at between $500 million and $600 million. The level of capital expenditures over the next five years reflects projected customer growth, the SMPE project and system improvement projects resulting in part from requirements under the Pipeline Safety Improvement Act of 2002 (Pipeline Safety Act) (see below). An estimated 60 percent of the required funds are expected to be internally generated 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 capital expenditures in 2004 are estimated to total $165 million, including $31 million for customer growth, $38 million for system improvement and support, $71 million for the SMPE and related gas storage projects, $8 million for the construction of a gas distribution system in Coos County, Oregon and $17 million for construction overhead. The SMPE project has a scheduled completion date in late 2004. NW Natural must obtain easements and rights-of-way for the construction of the pipeline and may need to use condemnation proceedings to secure some of them. NW Natural entered into a stipulation with the OPUC in 2001 for an enhanced pipeline safety program that includes an accelerated bare steel replacement program and a geo-hazard safety program. The bare steel replacement program accelerates the replacement of NW Natural's bare steel piping over 20 years instead of 40 years. The geo-hazard safety program includes the identification, assessment and remediation of risks to piping infrastructure created by landslides, washouts, earthquakes or similar occurrences. The stipulation allowed NW Natural to receive deferred accounting rate treatment commencing Oct. 1, 2002, for costs associated with the programs exceeding $3 million per year, expected to be approximately $1.5 million annually. In December 2003, the U.S. Department of Transportation's Office of Pipeline Safety issued a rule that specifies the detailed requirements for transmission pipeline integrity management programs (IMPs) as mandated by the Pipeline Safety Act. The Pipeline Safety Act requires operators of gas 37 transmission pipelines to identify lines located in High Consequence Areas (HCAs) and to develop IMPs to periodically inspect the integrity of the pipelines and make repairs or replacements as necessary to ensure the ongoing integrity of the pipelines. The legislation requires NW Natural to complete inspection of the 50 percent highest risk pipelines located in its HCAs within the first five years, and the remaining covered pipelines within 10 years of the date of the enactment. The Pipeline Safety Act also requires re-inspections of the covered pipelines every seven years thereafter for the life of the pipelines. The capital and operating costs of compliance with the legislation and rules, and the accounting and regulatory treatments for these costs, are uncertain. Currently, however, NW Natural estimates that its IMP will cost $5 million to $8 million in 2004 and $5 million to $15 million per year beginning in 2005, totaling $50 million to $100 million over the next 10 years. Financing Activities -------------------- Cash provided by financing activities in 2003 totaled $17 million, compared to cash used in financing activities in 2002 of $43 million. Factors contributing to the $60 million difference were an increase in short-term debt in 2003 ($15.4 million) compared to a decrease in 2002 ($38.5 million) and the redemption of the $6.95 Series of Preference Stock in 2002 ($25 million), partially offset by a higher amount used for the retirement of long-term debt ($55 million in 2003 compared to $40.5 million in 2002) and the redemption, including the annual sinking fund, of the $7.125 Series of Preferred Stock in 2003 ($8.4 million). Cash used in financing activities in 2002 totaled $43 million, compared to cash provided by financing activities in 2001 of $15 million. Factors contributing to the $58 million difference were a reduction in short-term debt in 2002 ($38 million) compared to an increase in 2001 ($52 million), the redemption of the $6.95 Series of Preference Stock in 2002 ($25 million), and a higher amount used for the retirement of long-term debt ($40.5 million in 2002 compared to $20 million in 2001), partially offset by an increase in long-term debt issued ($90 million in 2002 compared to $18 million in 2001) and a reduction in common stock repurchased ($5.8 million). NW Natural sold $90 million of its secured Medium-Term Notes, Series B (MTNs) in each of 2003 and 2002 and used the proceeds to redeem long-term debt ($55 million in 2003 and $40.5 million in 2002), provide cash for investments in utility plant and reduce short-term borrowings. In 2000, NW Natural commenced a program to repurchase up to 2 million shares, or up to $35 million in value, of NW Natural's common stock through a repurchase program that has been extended through May 2004. The purchases are made in the open market or through privately negotiated transactions. No shares were repurchased in 2002 or in 2003. Since the program's inception the Company has repurchased 355,400 shares of common stock at a total cost of $8.2 million. Pension Cost (Income) and Funding Status ---------------------------------------- Net periodic pension cost is determined in accordance with SFAS No. 87, "Employers' Accounting for Pensions" (see "Application of Critical Accounting Policies - Accounting for Pensions," above). The annual pension cost or income is allocated between operations and maintenance expense and construction overhead. Net periodic pension cost for the Company's qualified defined benefit pension plans was $6.2 million in 2003, compared to net pension income of $0.1 million and $4.1 million in 2002 and 2001, respectively. The increase in pension cost was largely due to investment losses in 2001 and 2002, which are recognized over a three-year period, and to lower discount rates which had the effect of increasing accumulated benefit obligations. The Company is required to make a cash contribution of at least $1.9 million, and may make an additional contribution up to a total of $6.8 million, to its non-bargaining employee pension plan for the 2003 plan year, payable by Sept. 15, 2004. No cash contributions to the qualified plans were required for the 2002 or 2001 plan years. The fair value of the plan assets increased to $168 million at Dec. 31, 2003, from $143 million at Dec. 31, 2002, including $36 million in investment 38 gains, partially offset by $10 million in withdrawals to pay benefits and $0.9 million in eligible expenses of the plans. The present value of benefit obligations under the plans increased from an estimated $172 million to $192 million over that period, however, so the plans remained under-funded by about $24 million at Dec. 31, 2003. Despite the decline from a position of pension income in 2001 and 2002 to a position of pension expense in 2003, and the reductions in recent years in the funded status of the plans, NW Natural believes it will be able to maintain well-funded pension plans. NW Natural does not expect its current or future cash contributions to the plans to have a material adverse effect on its liquidity or financial condition. Ratios of Earnings to Fixed Charges ----------------------------------- For the years ended Dec. 31, 2003, 2002 and 2001, the Company's ratios of earnings to fixed charges, computed using the Securities and Exchange Commission method, were 2.83, 2.74 and 3.01, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed charges consist of interest on all indebtedness, dividends on all preferred and preference stock, 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 regulations related to environmental matters. These evolving laws and regulations may require expenditures over a long timeframe to control environmental impacts. The Company believes, at this time, that appropriate investigation or remediation is being undertaken at all the relevant sites. Based on existing knowledge, the Company does not expect that the ultimate resolution of these matters will have a material adverse effect on its financial condition, results of operations or cash flows. See Note 12. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company's primary market risk exposures associated with activities involving derivative financial instruments and other financial instruments are natural gas commodity price risk, foreign currency exchange risk and interest rate risk. Derivative financial instruments are used as tools to mitigate certain of these market risks (see Notes 1 and 11). Such instruments are used for hedging purposes, not for trading purposes. Market risks associated with the derivative financial instruments are monitored by management personnel who do not directly enter into these contracts and by the Audit Committee of the Board of Directors. Physical and Financial Commodity, Foreign Currency and Interest Rate -------------------------------------------------------------------- Transactions ------------ NW Natural enters into short-term and long-term natural gas purchase contracts with demand and commodity fixed-price and floating-price components, along with associated short-term and long-term natural gas transportation contracts. Foreign currency forward contracts are used to hedge against foreign exchange rate fluctuations on purchases made under these contracts that are denominated in Canadian dollars. Historically, NW Natural has taken physical delivery of at least the minimum quantities specified in its natural gas purchase contracts. The contracts are subject to annual re-pricing, a process that is intended to reflect anticipated market price trends during the next year. NW Natural's PGA mechanism in Oregon provides for the recovery from customers of actual commodity 39 costs in comparison with established benchmark costs, except that NW Natural absorbs 33 percent of the higher cost of gas sold, or retains 33 percent of the lower cost, in either case as compared to projections. At Dec. 31, 2003, differences between notional values and fair values with respect to NW Natural's open positions in derivative financial instruments were not material to the Company's financial position or results of operations because of the treatment of these instruments in regulatory mechanisms relating to gas costs (see "Results of Operations - Comparison of Gas Operations - Cost of Gas," above, and Notes 1 and 11). To the degree that market risks exist due to potential adverse changes in commodity prices, foreign exchange rates and interest rates in relation to these financial and physical contracts, the Company considers the risks to be: Commodity Price Risk -------------------- The prices of natural gas commodity are subject to fluctuations due to unpredictable factors including weather, pipeline transportation congestion and other factors that affect short-term supply and demand. Commodity swap and call option contracts (also known as financial hedge contracts) are used to convert certain natural gas purchase contracts from floating prices to fixed prices. At Dec. 31, 2003 and 2002, notional amounts under these commodity swap and call option contracts totaled $304.1 million and $180.6 million, respectively. At Dec. 31, 2003, five of these commodity hedge contracts extended beyond Dec. 31, 2004. If all of the commodity swap and call option contracts had been settled on Dec. 31, 2003, a regulatory gain of $23.7 million would have been realized (see Note 11). Foreign Currency Risk --------------------- The costs of natural gas commodity and certain pipeline services purchased from Canadian suppliers are subject to changes in the value of Canadian currency in relation to U.S. currency. Foreign currency forward contracts are used to hedge against fluctuations in exchange rates with respect to purchases of natural gas from Canadian suppliers. At Dec. 31, 2003 and 2002, notional amounts under foreign currency forward contracts totaled $6.4 million and $15.5 million, respectively. As of Dec. 31, 2003, no foreign currency forward contracts extended beyond Dec. 31, 2004. If all of the foreign currency forward contracts had been settled on Dec. 31, 2003, a gain of $0.2 million would have been realized (see Note 11). Interest Rate Risk ------------------ Interest rate risk relates to new debt financing needed to fund capital requirements, including maturing debt securities, and to the issuance of commercial paper. Interest rate risk is managed through the issuance of fixed-rate debt with varying maturities and the reduction of debt through optional redemption when interest rates are favorable. No derivative financial instruments to hedge interest rates were in place at Dec. 31, 2003 or 2002. 40 Forward-Looking Statements - -------------------------- This report and other presentations made by the Company from time to time may contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and other statements that are other than statements of historical facts. The Company's expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis. However, each such forward-looking statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause the actual results of the Company to differ materially from those projected in such forward-looking statements: (i) prevailing state and federal governmental policies and regulatory actions, including those of the OPUC, the WUTC and the U.S. Department of Transportation's Office of Pipeline Safety, with respect to allowed rates of return, industry and rate structure, purchased gas and investment recovery, acquisitions and dispositions of assets and facilities, operation and construction of plant facilities, the maintenance of pipeline integrity, present or prospective wholesale and retail competition, changes in tax laws and policies and changes in and compliance with environmental and safety laws, regulations and policies; (ii) weather conditions and other natural phenomena; (iii) unanticipated population growth or decline, and changes in market demand caused by changes in demographic or customer consumption patterns; (iv) competition for retail and wholesale customers; (v) pricing of natural gas relative to other energy sources; (vi) risks resulting from uninsured property damage to Company property, intentional or otherwise; (vii) unanticipated changes in interest or foreign currency exchange rates or in rates of inflation; (viii) economic factors that could cause a severe downturn in certain key industries, thus affecting demand for natural gas; (ix) unanticipated changes in operating expenses and capital expenditures; (x) unanticipated changes in future liabilities relating to employee benefit plans; (xi) capital market conditions, including their effect on pension costs; (xii) competition for new energy development opportunities; (xiii) potential inability to obtain permits, rights of way, easements, leases or other interests or other necessary authority to construct pipelines, develop storage or complete other system expansions; and (xiv) legal and administrative proceedings and settlements. All subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, also are expressly qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for the Company to predict all such factors, nor can it assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. 41 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TABLE OF CONTENTS Page 1. Report of Independent Auditors........................................ 43 2. Consolidated Financial Statements: Consolidated Statements of Income for the Years Ended December 31, 2003, 2002 and 2001...................................... 44 Consolidated Statements of Earnings Invested in the Business and Comprehensive Income for the Years Ended December 31, 2003, 2002 and 2001................................................... 45 Consolidated Balance Sheets, December 31, 2003 and 2002............... 46 Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001................................ 48 Consolidated Statements of Capitalization, December 31, 2003 and 2002......................................................... 49 Notes to Consolidated Financial Statements............................ 50 3. Quarterly Financial Information (unaudited)........................... 75 4. Supplementary Data for the Years Ended December 31, 2003, 2002 and 2001: Financial Statement Schedule Schedule II - Valuation and Qualifying Accounts and Reserves.......... 76 Supplemental Schedules Omitted All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included elsewhere in the financial statements. 42 REPORT OF INDEPENDENT AUDITORS To the Board of Directors and Shareholders of Northwest Natural Gas Company In our opinion, the consolidated financial statements listed in the accompanying table of contents present fairly, in all material respects, the financial position of Northwest Natural Gas Company and its subsidiaries (the "Company") at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying table of contents presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. /s/PricewaterhouseCoopers LLP - ----------------------------- Portland, Oregon February 26, 2004 43 NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME
Thousands, except per share amounts (year ended December 31) 2003 2002 2001 - ----------------------------------------------------------------------------------------------------------- Operating revenues: Gross operating revenues $ 611,256 $ 641,376 $ 650,252 Cost of sales 323,190 353,832 374,241 ---------- --------- --------- Net operating revenues 288,066 287,544 276,011 Operating expenses: Operations and maintenance 96,420 85,120 83,920 Taxes other than income taxes 35,125 34,076 32,240 Depreciation and amortization 54,249 52,090 49,640 ---------- --------- --------- Total operating expenses 185,794 171,286 165,800 ---------- --------- --------- Income from operations 102,272 116,258 110,211 Other income (expense) 2,150 (14,890) 1,334 Interest charges - net of amounts capitalized 35,099 34,132 33,805 ---------- --------- --------- Income before income taxes 69,323 67,236 77,740 Income tax expense 23,340 23,444 27,553 ---------- --------- --------- Net income 45,983 43,792 50,187 Redeemable preferred and preference stock dividend requirements 294 2,280 2,401 ---------- --------- --------- Earnings applicable to common stock $ 45,689 $ 41,512 $ 47,786 ========== ========= ========= Average common shares outstanding: Basic 25,741 25,431 25,159 Diluted 26,061 25,814 25,612 Earnings per share of common stock: Basic $ 1.77 $ 1.63 $ 1.90 Diluted $ 1.76 $ 1.62 $ 1.88
------------------------------------ See Notes to Consolidated Financial Statements. 44 NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF EARNINGS INVESTED IN THE BUSINESS AND COMPREHENSIVE INCOME
Thousands (year ended December 31) 2003 2002 2001 - ------------------------------------------------------------------------------------------------------------------------------ Earnings invested in the business: Balance at beginning of year $ 157,136 $ 147,950 $ 134,189 Net income 45,983 $ 45,983 43,792 $ 43,792 50,187 $ 50,187 Cash dividends paid: Redeemable preferred and preference stock (392) (2,579) (2,410) Common stock (32,655) (32,024) (31,307) Common stock repurchased - - (2,688) Common stock expense (19) (3) (21) --------- --------- --------- Balance at end of year $ 170,053 $ 157,136 $ 147,950 ========= ========= ========= Accumulated other comprehensive income (loss): Balance at beginning of year $ (3,084) $ (375) $ - Other comprehensive income (loss) - net of tax: Minimum pension liability adjustment 2,068 2,068 (2,936) (2,936) (148) (148) Change in unrealized loss from price risk management activities - - 227 227 (227) (227) ------------------- -------------------- --------------------- Comprehensive income $ 48,051 $ 41,083 $ 49,812 ======== ======== ======== Balance at end of year $ (1,016) $ (3,084) $ (375) ========= ========= =========
------------------------------------ See Notes to Consolidated Financial Statements. 45 NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS
Thousands (December 31) 2003 2002 - ---------------------------------------------------------------------------------------- Assets: Plant and property: Utility plant $ 1,659,089 $ 1,539,965 Less accumulated depreciation 471,716 435,601 ----------- ----------- Utility plant - net 1,187,373 1,104,364 ----------- ----------- Non-utility property 23,395 20,832 Less accumulated depreciation and amortization 4,855 4,404 ----------- ----------- Non-utility property - net 18,540 16,428 ----------- ----------- Total plant and property 1,205,913 1,120,792 ----------- ----------- Other investments 12,635 12,703 ----------- ----------- Current assets: Cash and cash equivalents 4,706 7,328 Accounts receivable, less allowance for uncollectible accounts of $1,763 in 2003 and $1,815 in 2002 52,213 46,936 Accrued unbilled revenue 59,109 44,069 Inventories of gas, materials and supplies 50,859 58,030 Prepayments and other current assets 32,661 36,934 ----------- ----------- Total current assets 199,548 193,297 ----------- ----------- Regulatory assets: Income tax asset 63,449 47,975 Unamortized costs on debt redemptions 7,803 6,508 Other 6,020 7,040 ----------- ----------- Total regulatory assets 77,272 61,523 ----------- ----------- Other assets: Investment in life insurance 59,710 54,916 Fair value of non-trading derivatives 23,885 12,426 Other 12,369 11,620 ----------- ----------- Total other assets 95,964 78,962 ----------- ----------- Total assets $ 1,591,332 $ 1,467,277 =========== ===========
----------------------------------- See Notes to Consolidated Financial Statements. 46 NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS
Thousands (December 31) 2003 2002 - ---------------------------------------------------------------------------------------- Capitalization and liabilities: Capitalization Common stock $ 82,137 $ 81,023 Premium on common stock 255,871 248,028 Earnings invested in the business 170,053 157,136 Unearned stock compensation (729) (711) Accumulated other comprehensive income (loss) (1,016) (3,084) ----------- ----------- Total common stock equity 506,316 482,392 Redeemable preferred stock - 8,250 Long-term debt 500,319 445,945 ----------- ----------- Total capitalization 1,006,635 936,587 ----------- ----------- Current liabilities: Notes payable 85,200 69,802 Accounts payable 86,029 74,436 Long-term debt due within one year - 20,000 Taxes accrued 8,605 7,822 Interest accrued 2,998 2,902 Other current and accrued liabilities 31,589 30,045 ----------- ----------- Total current liabilities 214,421 205,007 ----------- ----------- Regulatory liabilities: Accrued asset removal costs 135,638 125,197 Customer advances 1,564 1,791 Deferred gas costs payable 5,627 10,635 Unrealized gain on non-trading derivatives 23,885 12,426 ----------- ----------- Total regulatory liabilities 166,714 150,049 ----------- ----------- Other liabilities: Deferred income taxes 171,797 141,732 Deferred investment tax credits 6,945 7,824 Other 24,820 26,078 ----------- ----------- Total other liabilities 203,562 175,634 ----------- ----------- Commitments and contingencies (see Note 12) - - ----------- ----------- Total capitalization and liabilities $ 1,591,332 $ 1,467,277 =========== ===========
----------------------------------- See Notes to Consolidated Financial Statements. 47 NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
Thousands (year ended December 31) 2003 2002 2001 - ------------------------------------------------------------------------------------------------------------------ Operating activities: Net income from operations $ 45,983 $ 43,792 $ 50,187 Adjustments to reconcile net income to cash provided by operations: Depreciation and amortization 54,249 52,090 49,640 (Gain) loss on sale of assets 10 (221) - Loss for PGE acquisition costs - 13,873 - Minimum pension liability adjustment 2,068 (2,936) (148) Unrealized gain (loss) from price risk management activities - 227 (227) Deferred income taxes and investment tax credits 29,186 10,450 (12,088) Undistributed (earnings) losses from equity investments (474) (988) 321 Allowance for funds used during construction (1,734) (550) (959) Deferred gas costs - net (5,008) 546 27,062 Other (22,599) 4,582 1,345 --------- --------- --------- Cash from operations before working capital changes 101,681 120,865 115,133 Changes in operating assets and liabilities: Accounts receivable - net of allowance for uncollectible accounts (5,277) 17,786 (3,969) Accrued unbilled revenue (15,040) 13,680 (12,130) Inventories of gas, materials and supplies 7,171 (8,693) (2,454) Accounts payable 11,593 3,738 (40,000) Accrued interest and taxes 1,145 (24,725) 15,435 Other current assets and liabilities 5,533 1,176 (494) --------- --------- --------- Cash provided by operating activities 106,806 123,827 71,521 --------- --------- --------- Investing activities: Acquisition and construction of utility plant assets (124,660) (79,530) (71,943) Investment in non-utility property (2,563) (2,629) (9,554) PGE acquisition costs - (4,316) (9,557) Proceeds from sale of assets 18 500 3,256 Other investments 542 1,848 529 --------- --------- --------- Cash used in investing activities (126,663) (84,127) (87,269) --------- --------- --------- Financing activities: Common stock issued 8,331 6,533 5,157 Common stock repurchased - - (5,792) Redeemable preferred and preference stock retired (8,428) (25,750) (750) Long-term debt issued 90,000 90,000 18,000 Long-term debt retired (55,000) (40,500) (20,000) Change in short-term debt 15,398 (38,489) 52,028 Cash dividend payments: Redeemable preferred and preference stock (392) (2,579) (2,410) Common stock (32,655) (32,024) (31,307) Common stock expense (19) (3) (21) --------- --------- --------- Cash provided by (used in) financing activities 17,235 (42,812) 14,905 --------- ---------- --------- Decrease in cash and cash equivalents (2,622) (3,112) (843) Cash and cash equivalents - beginning of year 7,328 10,440 11,283 --------- --------- --------- Cash and cash equivalents - end of year $ 4,706 $ 7,328 $ 10,440 ========= ========= ========= - ----------------------------------------------------------------------------------------------------------------- Supplemental disclosure of cash flow information: Cash paid during the period for: Interest and preferred dividends $ 35,210 $ 34,640 $ 33,034 Income taxes $ 13,940 $ 33,474 $ 25,201 - ----------------------------------------------------------------------------------------------------------------- Supplemental disclosure of non-cash financing activities: Conversion to common stock: 7-1/4 % Series of Convertible Debentures $ 626 $ 1,932 $ 413
------------------------------------ See Notes to Consolidated Financial Statements 48 NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION
Thousands, except share amounts (December 31) 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- Common stock equity: Common stock - par value $3-1/6 per share, authorized 60,000,000 shares: $ 82,137 $ 81,023 outstanding - 2003, 25,938,002 shares; 2002, 25,586,313 shares Premium on common stock 255,871 248,028 Earnings invested in the business 170,053 157,136 Unearned compensation (729) (711) Accumulated other comprehensive income (loss) (1,016) (3,084) ----------- --------- Total common stock equity 506,316 50% 482,392 51% Redeemable preferred stock, authorized 1,500,000 shares: $7.125 Series, stated value $100 per share; outstanding - 2003, none; 2002, 82,500 shares - 0% 8,250 1% Long-term debt: Medium-Term Notes ----------------- First Mortgage Bonds: 6.400% Series B due 2003 - 20,000 6.340% Series B due 2005 5,000 5,000 6.380% Series B due 2005 5,000 5,000 6.450% Series B due 2005 5,000 5,000 6.050% Series B due 2006 8,000 8,000 6.310% Series B due 2007 20,000 20,000 6.800% Series B due 2007 9,500 9,500 6.500% Series B due 2008 5,000 5,000 4.110% Series B due 2010 10,000 - 7.450% Series B due 2010 25,000 25,000 6.665% Series B due 2011 10,000 10,000 7.130% Series B due 2012 40,000 40,000 8.260% Series B due 2014 10,000 10,000 7.000% Series B due 2017 40,000 40,000 6.600% Series B due 2018 22,000 22,000 8.310% Series B due 2019 10,000 10,000 7.630% Series B due 2019 20,000 20,000 9.050% Series A due 2021 10,000 10,000 5.620% Series B due 2023 40,000 - 7.250% Series B due 2023 - 20,000 7.500% Series B due 2023 - 4,000 7.520% Series B due 2023 - 11,000 7.720% Series B due 2025 20,000 20,000 6.520% Series B due 2025 10,000 10,000 7.050% Series B due 2026 20,000 20,000 7.000% Series B due 2027 20,000 20,000 6.650% Series B due 2027 20,000 20,000 6.650% Series B due 2028 10,000 10,000 7.740% Series B due 2030 20,000 20,000 7.850% Series B due 2030 10,000 10,000 5.820% Series B due 2032 30,000 30,000 5.660% Series B due 2033 40,000 - Convertible Debentures ---------------------- 7-1/4% Series due 2012 5,819 6,445 ----------- --------- 500,319 465,945 Less long-term debt due within one year - 20,000 ----------- --------- Total long-term debt 500,319 50% 445,945 48% ----------- --- --------- --- Total capitalization $ 1,006,635 100% $ 936,587 100% =========== === ========= ===
------------------------------------ See Notes to Consolidated Financial Statements. 49 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: ------------------------------------------- Organization and Principles of Consolidation - -------------------------------------------- The consolidated financial statements include the accounts of: Regulated utility: o Northwest Natural Gas Company (NW Natural) Non-regulated wholly-owned subsidiaries of NW Natural: o NNG Financial Corporation (Financial Corporation), and its wholly-owned subsidiaries o Northwest Energy Corporation (Northwest Energy), and its wholly-owned subsidiary Together these businesses are referred to herein as the Company (see Note 2). Intercompany accounts and transactions have been eliminated. Investments in corporate joint ventures and partnerships in which the Company's ownership interest is 50 percent or less and over which the Company does not exercise control are accounted for by the equity method or the cost method (see Note 9). Certain amounts from prior years have been reclassified to conform, for comparison purposes, with the current financial statement presentation. These reclassifications had no impact on prior year consolidated results of operations. Use of Estimates - ---------------- The preparation of financial statements in conformity with 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 statements and accompanying notes. Actual amounts could differ from those estimates, and changes would be reported in future periods. Management believes that the estimates and assumptions used are reasonable. Industry Regulation - ------------------- The Company's principal business is the distribution of natural gas, which is regulated by the Public Utility Commission of Oregon (OPUC) and the Washington Utilities and Transportation Commission (WUTC). Accounting records and practices conform to the requirements and uniform system of accounts prescribed by these regulatory authorities in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." In applying SFAS No. 71, NW Natural capitalizes certain costs and revenues as regulatory assets and liabilities pursuant to orders of the OPUC or WUTC in general rate or expense deferral proceedings, to provide for recovery of revenues or expenses from, or refunds to, utility customers in future periods. At Dec. 31, 2003 and 2002, the amounts deferred as regulatory assets and liabilities were net liabilities of $89.4 million and $88.5 million, respectively. The net amounts recognized at Dec. 31, 2003 and 2002 include $135.6 million and $125.2 million, respectively, of accumulated removal costs, which have been reclassified from accumulated depreciation to regulatory liabilities at Dec. 31, 2003, in accordance with SFAS No. 143, "Accounting for Asset Removal Obligations" (see "New Accounting Standards," below). In addition, the "Income tax asset" balance increased by $15.5 million primarily reflecting the grossed-up tax benefit of removal costs passed through in rate base after Dec. 31, 1992. 50 If NW Natural should determine that all or a portion of these regulatory 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 ----------------- Effective Jan. 1, 2003, the Company 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 material 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. However, the Company's adoption of SFAS No. 143 did result in a balance sheet reclassification of asset removal cost obligations from accumulated depreciation and amortization to regulatory liabilities (see "Plant and Property," below, for a discussion of the Company's policy on asset removal costs). Also effective Jan. 1, 2003, the Company adopted SFAS No. 145, "Rescission of FASB Statement Nos. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections," and SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which replaces Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 145, which updates, clarifies and simplifies existing accounting pronouncements, addresses the reporting of debt extinguishments and accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities, such as lease termination costs and certain employee severance costs, when they are incurred rather than at the date of a commitment to an exit or disposal plan. The primary effect of applying SFAS No. 146, which was effective for all exit or disposal activities initiated after Dec. 31, 2002, is on the timing of recognition of costs associated with exit or disposal activities. The adoption of SFAS Nos. 145 and 146 did not have a material impact on the Company's financial condition or results of operations. Also effective Jan. 1, 2003, the Company adopted the disclosure requirements of SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment to FASB Statement No. 123," but continues to account for its stock-based compensation plans using the intrinsic value method prescribed in Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees," rather than adopt a fair value method of accounting for its stock-based employee compensation. SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value method. In addition, SFAS No. 148 requires prominent disclosures in annual and interim financial statements about the accounting method used for stock-based employee compensation and its effect on reported results. SFAS No. 148 encourages, but does not require, companies to record compensation expense using the fair value method of accounting. The adoption of SFAS No. 148 did not have a material impact on the Company's financial condition or results of operations, and it would not have had a material impact if the Company had elected to adopt a fair value method of accounting for stock-based compensation (see "Stock-Based Compensation," below, and Note 4). Effective July 1, 2003, the Company adopted SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 primarily amends SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," to clarify the definition of a derivative and to require derivative instruments that include up-front cash payments to be classified as financing activity in the statement of cash flows. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated 51 after June 30, 2003. The adoption of SFAS No. 149 did not have a material impact on the Company's financial condition or results of operations. Also effective July 1, 2003, the Company adopted SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity." SFAS No. 150 establishes standards for how an issuer classifies and measures in its financial statements certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires an issuer to classify a financial instrument as a liability if that financial instrument embodies an obligation of the issuer. The adoption of SFAS No. 150 resulted in the Company's reclassifying dividends of $0.2 million after July 1, 2003 on its redeemable preferred stock as interest expense, thus affecting the Company's reported net income for 2003. The Company redeemed its last remaining shares of preferred stock outstanding during the fourth quarter of 2003. The adoption of SFAS No. 150 did not have a material impact on the Company's financial condition or results of operations. In December 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits, an amendment of FASB Statements No. 87, 88, and 106." SFAS No. 132 requires that expanded disclosures on pension and other postretirement benefit plans be included in financial statements for fiscal years ending on or after Dec. 15, 2003. The Company has adopted SFAS No. 132. See Note 7. In November 2002, the FASB issued FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45 clarifies the requirements of FASB Statement No. 5, "Accounting for Contingencies," relating to the guarantor's accounting for, and disclosure of, the issuance of certain types of guarantees. A guarantor must recognize a liability for the fair value of an obligation assumed under a guarantee and provide additional disclosures about the obligations associated with guarantees issued. In connection with the settlement of litigation involving leases in the Mist gas storage field, NW Natural agreed to defend and indemnify a party against claims relating to the validity and enforceability of certain transferred leases. However, NW Natural has no obligation to defend or indemnify the party from any claims for recovery of punitive or other exemplary damages. The Company has provided no other guarantees of indebtedness of others. Accordingly, the application of FIN 45 did not have a material impact on the Company's financial condition or results of operations. In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities." FIN 46 provides guidance on the identification of, and the financial reporting for, entities over which control is achieved through means other than voting rights, known as "variable interest entities." FIN 46 provides guidance for determining whether consolidation is required. Certain variable interest entities must be consolidated by the primary beneficiary if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 was effective immediately for all new variable interest entities created or acquired after Jan. 31, 2003. The Company did not have any significant interests in any variable interest entities during any of the current reporting periods. The application of FIN 46 had no material impact on the Company's financial condition or results of operations. Plant and Property - ------------------ Plant and property is stated at cost, including labor, materials and overhead (see Note 9). The cost of utility plant and interstate storage includes an allowance for funds used during construction in construction overhead to represent the net cost of borrowed funds used for construction purposes (see "Allowance for Funds Used During Construction," below). NW Natural's provision for depreciation of utility property is computed under the straight-line, age-life method in accordance with independent engineering studies and as approved by regulatory authorities. The 52 average depreciation rate was approximately 3.5 percent for each of the years 2003, 2002 and 2001. The depreciation rate reflects the approximate economic life of the utility property. Effective Jan. 1, 2003, the Company adopted SFAS No. 143 (see "New Accounting Standards," above). Among other things, SFAS No. 143 requires that future asset retirement costs (removal costs) that meet the requirements of SFAS No. 71, as amended and supplemented, be classified as a regulatory liability. In accordance with long-standing industry practice, the Company accrues for future removal costs on many long-lived assets through a charge to depreciation expense allowed in rates. Prior to the adoption of SFAS No. 143, the resulting regulatory liabilities were recognized as accruals to accumulated depreciation. At the time when removal costs were incurred, accumulated depreciation was charged with the costs of removal and the book cost of the asset being retired. Upon the adoption of SFAS No.143, the Company reclassified on its Dec. 31, 2003 and 2002 consolidated balance sheets $135.6 million and $125.2 million, respectively, of previously accrued asset removal costs recovered through rates from accumulated depreciation and amortization to regulatory liabilities - accrued asset removal costs. This reclassification is based on the Company's estimate of accumulated removal costs using its most recent depreciation study. The Company will continue to accrue future asset removal costs through depreciation expense, with a corresponding credit to regulatory liabilities - accrued asset removal costs. When the Company retires depreciable utility plant and equipment, it will charge the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred will be charged to regulatory liabilities - accrued asset removal costs. No gain or loss is recognized upon normal 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 interest 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 revenues from rate recovery resulting from higher rate base and higher depreciation expense. NW Natural's composite AFUDC rates were 4.5 percent in 2003, 2.8 percent in 2002 and 6.2 percent in 2001. Cash and Cash Equivalents - ------------------------- For purposes of reporting cash flows, cash and cash equivalents include cash on hand and highly liquid temporary investments with original maturity dates of three months or less. Revenue Recognition - ------------------- Utility revenues, derived primarily from the sale and transportation 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 revenues). 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 Company's accrued unbilled revenues at Dec. 31, 2003 and 2002 were $59.1 million and $44.1 million, respectively. Non-utility revenues, derived primarily from gas storage services, are recognized upon delivery of the service to customers. Revenues from optimization of excess storage and transportation capacity are recognized over the life of the contract for guaranteed amounts under the contract, or are recognized as earned for amounts above the guaranteed value. 53 Inventories - ----------- Inventories, consisting primarily of natural gas in storage, are stated at the lower of average cost or net realizable value. Derivatives Policy - ------------------ NW Natural's Derivatives Policy sets forth the guidelines for using selected financial derivative products to support prudent risk management strategies within designated parameters. The Derivatives Policy allows for the use of derivatives to manage natural gas commodity prices related to natural gas purchases, foreign currency prices related to gas purchase commitments from Canada, oil or propane commodity prices related to gas sales and transportation services under rate schedules pegged to other commodities, and interest rates related to long-term debt maturing in less than five years or expected to be issued in future periods. NW Natural's objective for using derivatives is to decrease the volatility of earnings and cash flows associated with changes in commodity prices, foreign currency prices and interest rates. The use of derivatives is permitted only after the commodity price, exchange rate, and interest rate exposures have been identified, are determined to exceed acceptable tolerance levels and are considered to be unavoidable because they are necessary to support normal business activities (see Note 11). The Policy is intended to prevent speculative risk. NW Natural does not enter into derivative instruments for trading purposes and believes that any increase in market risk created by holding derivatives should be offset by the exposures they modify. In accounting for derivative activities, the Company applies SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," and SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," (collectively referred to as SFAS No. 133). SFAS No. 133 requires that the Company recognize derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. SFAS No. 133 also requires that changes in the fair value of a derivative be recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133 provides an exception for contracts intended for normal purchase and normal sale, other than a financial instrument or derivative instrument for which physical delivery is probable. Many of the Company's gas supply and transportation contracts are derivative 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 comprehensive 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 recognized in current earnings, but only to the extent that the amount is not covered under NW Natural's regulatory deferral mechanism. Effectiveness is measured by comparing changes in cash flows of the hedged item to gains or losses on derivative instruments. NW Natural's primary hedging activities, consisting of natural gas commodity price and foreign currency exchange rate hedges, are principally accounted for as cash flow hedges under SFAS No. 133 and are subject to regulatory deferral under SFAS No. 71. Unrealized gains and losses from mark-to-market valuations of these contracts are not recognized in current income but are reported as derivative assets or liabilities and offset by a corresponding deferred account balance included under "regulatory liabilities" or "regulatory assets." Due to their regulatory deferral treatment, effective portions of changes in the fair value of these derivatives are not recorded in OCI but are recognized as a regulatory asset or liability. Income Taxes - ------------ The Company accounts for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." Under SFAS No. 109, the Company recognizes deferred income taxes for all temporary differences between 54 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 regulatory accounting methods do not provide for current recovery in rates. NW Natural has recorded a regulatory tax asset for amounts pending recovery from customers in future rates, equivalent to $63.4 million and $48 million at Dec. 31, 2003 and 2002, respectively. These amounts are primarily based on differences between the book and tax bases of net utility plant in service. Investment tax credits on utility plant additions and leveraged leases, which reduce income taxes payable, are deferred for financial statement purposes and are amortized over the life of the related plant or lease. Investment and energy tax credits generated by non-regulated subsidiaries are amortized over a period of one to five years. Other Income (Expense) - ---------------------- Other income (expense) consists of interest income, gain on sale of assets, investment income of Financial Corporation, the costs incurred in connection with the Company's effort to acquire Portland General Electric Company (PGE) from Enron Corp. and other miscellaneous income from merchandise sales, rents, 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 are calculated as follows:
Thousands, except per share amounts 2003 2002 2001 -------------------------------------------------------------------------------------------------------------- Net income $ 45,983 $ 43,792 $ 50,187 Redeemable preferred and preference stock dividend requirements 294 2,280 2,401 -------- -------- -------- Earnings applicable to common stock - basic 45,689 41,512 47,786 Debenture interest less taxes 257 285 370 -------- -------- -------- Earnings applicable to common stock - diluted $ 45,946 $ 41,797 $ 48,156 ======== ======== ======== Average common shares outstanding - basic 25,741 25,431 25,159 Stock options 28 59 32 Convertible debentures 292 324 421 -------- -------- -------- Average common shares outstanding - diluted 26,061 25,814 25,612 ======== ======== ======== Earnings per share of common stock - basic $ 1.77 $ 1.63 $ 1.90 ======== ======== ======== Earnings per share of common stock - diluted $ 1.76 $ 1.62 $ 1.88 ========= ======== ========
For the years ended Dec. 31, 2003, 2002 and 2001, 77,500 shares, 84,000 shares and 138,491 shares, respectively, representing the number of stock options the exercise prices for which were greater than the average market prices for the Company's common stock for such years, were excluded from the calculation of diluted earnings per share because the effect was antidilutive. 55 Stock-Based Compensation - ------------------------ The Company applies APB Opinion No. 25, "Accounting for Stock Issued to Employees," to account for its stock-based compensation plans. Accordingly, the Company does not recognize compensation expense for the fair value of its stock option grants. Instead, the Company has elected to continue using the intrinsic value method of accounting for stock options rather than adopting the fair 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 Non-Employee Directors Stock Compensation Plan in the period when shares are earned (see Note 4). 2. CONSOLIDATED SUBSIDIARY OPERATIONS AND SEGMENT INFORMATION: ----------------------------------------------------------- At Dec. 31, 2003, the Company had two direct, wholly-owned subsidiaries, Financial Corporation and 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. Since the acquisition of PGE has been terminated, Northwest Energy remains a non-active subsidiary of the Company. The Company's core business is the distribution and sale of natural gas ("Utility" segment). Another segment, "Gas Storage," represents natural gas storage services provided to interstate customers, including asset optimization services under a contract with an independent energy trading company. The remaining business segment, "Other," primarily consists of non-regulated investments in alternative energy projects in California (see "Financial Corporation," below), a Boeing 737-300 aircraft leased to Continental Airlines and Northwest Energy's limited acquisition activities (see Note 9). Gas Storage - ----------- Gas storage services are provided to off-system interstate 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. Results for the gas storage segment also include revenues, net of amounts shared with core utility customers, from a contract with an independent energy trading company that seeks to optimize the use of NW Natural's assets by trading temporarily unused portions of its gas storage capacity and upstream pipeline transportation capacity. NW Natural retains 80 percent of the pre-tax income from the optimization of storage and pipeline transportation capacity when the costs of such capacity have not been included in core utility rates, or 33 percent of the pre-tax income from such capacity when the costs have been included in core utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a deferred regulatory account for distribution to NW Natural's core utility customers. Financial Corporation - --------------------- Financial Corporation has several financial investments, including 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 $8.0 million and $11.6 million at Dec. 31, 2003 and 2002, respectively. 56 Segment Information Summary - --------------------------- The following table presents summary financial information about the reportable segments for 2003, 2002 and 2001. Inter-segment transactions are insignificant.
--------------------------------------------------------------------------------------------------------- Thousands Utility Gas Storage Other Total --------------------------------------------------------------------------------------------------------- 2003 ---- Net operating revenues $ 278,856 $ 9,036 $ 174 $ 288,066 Depreciation and amortization 53,798 451 - 54,249 Other operating expenses 130,619 804 122 131,545 Income from operations 94,439 7,781 52 102,272 Income from financial investments 3,406 - 474 3,880 Net income 40,913 4,312 758 45,983 Total assets at Dec. 31, 2003 1,558,342 18,464 14,526 1,591,332 2002 ---- Net operating revenues $ 279,414 $ 7,944 186 $ 287,544 Depreciation and amortization 51,693 396 1 52,090 Other operating expenses 118,156 962 78 119,196 Income from operations 109,565 6,586 107 116,258 Income from financial investments 1,390 - 988 2,378 Loss provision for PGE transaction costs - - (8,414) (8,414) Net income (loss) 47,280 3,646 (7,134) 43,792 Total assets at Dec. 31, 2002 1,432,776 16,403 18,098 1,467,277 2001 ---- Net operating revenues $ 271,473 $ 4,368 170 $ 276,011 Depreciation and amortization 49,413 227 - 49,640 Other operating expenses (income) 115,708 489 (37) 116,160 Income from operations 106,352 3,652 207 110,211 Income (loss) from financial investments 1,646 - (321) 1,325 Net income 47,233 2,112 842 50,187 Total assets at Dec. 31, 2001 1,506,787 14,243 29,623 1,550,653
3. CAPITAL STOCK: - ---------------------- Common Stock - ------------ At Dec. 31, 2003, NW Natural had reserved 134,240 shares of common stock for issuance under the Employee Stock Purchase Plan, 353,059 shares for future conversions of its 7-1/4% Convertible Debentures, 389,951 shares under its Dividend Reinvestment and Stock Purchase Plan, 1,751,544 shares under its Restated Stock Option Plan (see Note 4), and 3,000,000 shares under the Shareholder Rights Plan. Redeemable Preferred Stock - -------------------------- On Nov. 14, 2003, NW Natural redeemed all of the remaining shares of its $7.125 Series of Redeemable Preferred Stock with an aggregate stated value of $7.5 million, at a redemption price equivalent 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 from the redemption of the $7.125 Series was recognized as an unamortized cost pursuant to SFAS No. 71 and will be amortized to expense over the life of the new debt. 57 Redeemable Preference Stock - --------------------------- On Dec. 31, 2002, NW Natural redeemed all 250,000 shares of its $6.95 Series of Redeemable Preference Stock with proceeds from the sale of commercial paper. Stock Repurchase Program - ------------------------ NW Natural's Board of Directors approved a stock repurchase program in 2000 to purchase up to 2 million shares, or up to $35 million in value, of NW Natural's common stock in the open market or through privately negotiated transactions. The repurchase program has been extended through May 2004. No shares were repurchased in 2002 or 2003. Since the program's inception, the Company has repurchased 355,400 shares of common stock at a total cost of $8.2 million. Restated Stock Option Plan - -------------------------- In May 2002, the shareholders approved an amendment to the Restated Stock Option Plan that increased the total number of shares authorized for option grants from 1,200,000 to 2,400,000 shares. At Dec. 31, 2003, options on 1,429,500 shares were available for grant and options on 322,044 shares were outstanding. 58 The following table shows the changes in the number of shares of NW Natural's capital stock and the premium on common stock for the years 2003, 2002 and 2001:
--------------------Shares------------------- Premium on Redeemable Redeemable common Common preference preferred stock stock stock stock (thousands) ---------------------------------------------------------- Balance, Dec. 31, 2000 25,233,424 250,000 97,500 $238,215 Sales to employees 30,952 - - 498 Sales to stockholders 177,624 - - 3,854 Exercise of stock options - net 12,289 - - 110 Conversion of convertible debentures to common 20,485 - - 343 Stock repurchases (246,700) - - (2,323) Sinking fund purchases - - (7,500) - -------------- ----------- ------------ ---------- Balance, Dec. 31, 2001 25,228,074 250,000 90,000 240,697 Sales to employees 42,862 - - 748 Sales to stockholders 157,288 - - 3,854 Exercise of stock options - net 61,020 - - 1,105 Conversion of convertible debentures to common 97,069 - - 1,624 Sinking fund purchases - - (7,500) - Redemption - (250,000) - - -------------- ------------ ------------ ---------- Balance, Dec. 31, 2002 25,586,313 - 82,500 248,028 Sales to employees 14,175 - - 425 Sales to stockholders 178,714 - - 4,347 Exercise of stock options - net 127,357 - - 2,545 Conversion of convertible debentures to common 31,443 - - 526 Sinking fund purchases - - (7,500) - Early redemption - - (75,000) - -------------- ------------ ------------ ---------- Balance, Dec. 31, 2003 25,938,002 - - $255,871 ============== ============ ============ ==========
4. STOCK-BASED COMPENSATION: - --------------------------------- NW Natural has the following stock-based compensation plans: the Long-Term Incentive Plan (LTIP); the Restated Stock Option Plan (Restated SOP); the Employee Stock Purchase Plan (ESPP); and the Non-Employee Directors Stock Compensation Plan (NEDSCP). These plans are designed to promote stock ownership in NW Natural by employees, officers and, in the case of the NEDSCP, non-employee directors. NW Natural's shareholders approved the LTIP effective Jan. 1, 2001, to provide a flexible, competitive compensation program for eligible officers. An aggregate of 500,000 shares of common stock was authorized for grants under the LTIP as stock bonus, restricted stock or performance-based stock awards. Shares awarded under the LTIP are purchased on the open market. Through Dec. 31, 2003, NW Natural has granted four performance-based awards, one based on a two-year performance period (2001-02) and three based on three-year performance periods (2001-03, 2002-04 and 2003-05), and one restricted stock award. The aggregate target awards for each of the 2001-02 and the 2001-03 performance-based award periods were 26,000 shares and the maximum awards were 52,000 shares; the aggregate target and maximum awards for the 2002-04 award period were 29,000 and 58,000 shares, respectively; and the aggregate target and maximum awards for the 2003-05 award period were 32,000 and 64,000 shares, respectively. Final awards depend 59 on the attainment of certain return on equity performance goals. At Dec. 31, 2003, the two-year and three-year performance-based awards that started in 2001 lapsed because the performance-based measures were not achieved. The restricted stock award consists of 4,500 shares granted in 2001 with a vesting period of 65 months. The LTIP stock awards are compensatory awards for which compensation expense is recognized based on the market value of performance shares earned, or a pro rata amortization over the vesting period for the restricted stock award. The Restated SOP authorizes an aggregate of 2,400,000 shares of common stock for issuance as incentive or non-statutory stock options. These options may be granted only to officers and key employees designated by a committee of NW Natural's Board of Directors. All options are granted at an option price not less than the market value at the date of grant and may be exercised for a period not exceeding 10 years from the date of grant. Option holders may exchange shares they have owned for at least six months, at the current market price, to purchase shares at the option price. Since inception in 1985, options on 1,100,921 shares of common stock have been granted at prices ranging from $11.75 to $27.875 per share, and options on 130,421 shares have expired. In accordance with APB No. 25, no compensation expense is recognized for options granted under the Restated SOP or shares issued under the ESPP. If compensation expense for awards under these two plans had been determined based on fair value at the grant dates using the method prescribed by SFAS No. 123, "Accounting for Stock-Based Compensation," net income and earnings per share would have been reduced to the pro forma amounts shown below:
Pro Forma Effect of Stock Options: ------------------------------------------------------------------------------------ Thousands, except per share amounts 2003 2002 2001 ------------------------------------------------------------------------------------ Net income as reported $ 45,983 $ 43,792 $ 50,187 Pro forma stock-based compensation expense determined under the fair value based method - net of tax (279) (478) (338) --------- --------- --------- Pro forma net income 45,704 43,314 49,849 Redeemable preferred and preference stock (294) (2,280) (2,401) --------- --------- --------- Pro forma earnings applicable to common stock - basic 45,410 41,034 47,448 Debenture interest less taxes 257 285 370 --------- --------- ---------- Pro forma earnings applicable to common stock - diluted $ 45,667 $ 41,319 $ 47,818 ========= ========= ========== Basic earnings per share As reported $ 1.77 $ 1.63 $ 1.90 Pro forma $ 1.76 $ 1.61 $ 1.89 ------------------------------------------------------------------------------------ Diluted earnings per share As reported $ 1.76 $ 1.62 $ 1.88 Pro forma $ 1.75 $ 1.60 $ 1.87 ------------------------------------------------------------------------------------
The fair value of each stock option grant is estimated on the grant date (there were no stock option grants in 2003) using the Black-Scholes option pricing model with the following weighted average assumptions:
2002 2001 ----------------------------------------------------------------------- Expected life in years 7.0 7.0 Risk-free interest rate 3.6% 5.2% Expected volatility 29.1% 31.0% Dividend yield 4.8% 4.9% Present value of options granted $20.49 $17.34 -----------------------------------------------------------------------
60 Information regarding the Restated SOP's activity is summarized as follows:
---------Price per Share---------------- Weighted-Average Options Range Exercise Price -------------------------------------------------------------------------------------------- Balance outstanding, Dec. 31, 2000 416,005 $20.17 - 27.875 $ 22.75 Granted 15,000 24.91 24.91 Exercised (12,289) 20.17 - 20.920 20.36 Expired (31,625) 20.25 - 27.875 24.31 -------------------------------------------------------------------------------------------- Balance outstanding, Dec. 31, 2001 387,091 20.25 - 27.875 22.79 Granted 163,750 26.07 - 27.850 26.35 Exercised (68,827) 20.25 - 27.875 21.74 Expired (18,200) 20.25 - 27.875 25.43 -------------------------------------------------------------------------------------------- Balance outstanding, Dec. 31, 2002 463,814 20.25 - 27.875 24.10 Exercised (140,470) 20.25 - 27.875 21.14 Expired (1,300) 20.25 20.25 -------------------------------------------------------------------------------------------- Balance outstanding, Dec. 31, 2003 322,044 20.25 - 27.875 $ 25.35 -------------------------------------------------------------------------------------------- Shares available for grant Dec. 31, 2001 373,750 -------------------------------------------------------------------------------------------- Shares available for grant Dec. 31, 2002 1,428,200 -------------------------------------------------------------------------------------------- Shares available for grant Dec. 31, 2003 1,429,500 --------------------------------------------------------------------------------------------
The weighted average remaining contractual life of outstanding stock options at Dec. 31, 2003 was 6.5 years. The characteristics of exercisable stock options at Dec. 31, 2003 were as follows:
Weighted- Range of Exercisable Average Exercise Prices Stock Options Exercise Price ---------------------------------------------------------------------- $20.25-$27.875 213,144 $24.86
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 deduction over a six to 12-month period. Effective Feb. 26, 2004, the NEDSCP was amended to permit non-employee directors to receive stock awards either in cash or in Company stock. If non-employee directors elect to receive their awards in stock, approximately $100,000 worth of the Company's common stock is awarded upon joining the Board. These stock awards are subject to vesting and to restrictions on sale and transferability. The shares vest in monthly installments over the five calendar years following the award. On Jan. 1 of each year following the initial award, non-employee directors who elect to receive awards in Company stock are awarded an additional $20,000 worth of restricted Company stock, which vests in monthly installments in the fifth year following the award (after the previous award has fully vested). The Company holds the certificates for the restricted shares until the non-employee director ceases to be a director. Participants receive all dividends and have full voting rights on both vested and 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 are purchased in the open market by the Company at the time of the award. 61 The following table presents the changes in unearned stock compensation for the years 2003 and 2002, which are reported as a reduction to total common equity in the consolidated balance sheets:
Thousands 2003 2002 ----------------------------------------------------------------------- Unearned stock compensation: Balance at beginning of year $ 711 $ 372 Purchases of restricted stock 328 891 Restricted stock amortizations (310) (552) ---------- ----------- Balance at end of year $ 729 $ 711 ========== ===========
Under a separate plan, non-employee directors also may elect to invest their cash fees and retainers for board service in shares of the Company's common stock. 5. LONG-TERM DEBT: - ----------------------- The issuance of first mortgage debt, including secured medium-term notes, under the Mortgage and Deed of Trust (Mortgage) is limited by property additions, adjusted net earnings and other provisions 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 and redeemable preferred stock outstanding, for each of the 12-month periods through Dec. 31, 2008 amount to: none in 2004; $15 million in 2005; $8 million in 2006; $29.5 million in 2007; and $5 million in 2008. Holders of certain Medium-Term Notes (MTNs) have put options that, if exercised, would accelerate the maturity of long-term debt by $10 million in 2005, $20 million in 2007 and $20 million in 2008. 6. NOTES PAYABLE AND LINES OF CREDIT: - ------------------------------------------ The Company's primary source of short-term funds is commercial paper notes payable. Both NW Natural and Financial Corporation issue commercial paper under agency agreements with a commercial bank. NW Natural's commercial paper is supported by its committed bank lines of credit (see below), while Financial Corporation's commercial paper is supported by committed bank lines of credit and the guaranty of NW Natural. The amounts and average interest rates of commercial paper debt outstanding at Dec. 31 were as follows:
----------2003------ ----------2002---------- Thousands Amount Rate Amount Rate ----------------------------------------------------------------------- NW Natural $85,200 1.1% $69,802 1.4% Financial Corporation - - - - ------- ------- Total $85,200 $69,802 -----------------------------------------------------------------------
NW Natural has lines of credit with four commercial banks totaling $150 million. Half of the credit facility with each bank, totaling $75 million, is committed and available through Sept. 30, 2004, and the other $75 million is committed and available through Sept. 30, 2005. NW Natural may be unable to draw upon the two-year portions of the credit lines, totaling $75 million, until filings are made or approvals received from the OPUC or the WUTC with respect to its notes relating to the two-year commitments. NW Natural expects that it will be able to make the necessary filings or secure such approvals, if required. Financial Corporation has available through Sept. 30, 2004, committed lines of credit with two commercial banks totaling $10 million. Financial Corporation's lines are supported by the guaranty of NW Natural. 62 Under the terms of these lines of credit, NW Natural and Financial Corporation pay commitment fees but are not required to maintain compensating bank balances. The interest rates on borrowings under these lines of credit, if any, are based on current market rates. There were no outstanding balances on either the NW Natural or Financial Corporation lines of credit as of Dec. 31, 2003 or 2002. NW Natural's lines of credit require that credit ratings be maintained 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 outstanding under NW Natural's bank lines are tied to credit ratings, which would increase or decrease the cost of bank debt, if any, when ratings are changed. The lines of credit require the Company to maintain an indebtedness to total capitalization ratio of 65 percent or less and to maintain a consolidated net worth at least equal to 80 percent of its net worth at Sept. 30, 2003, plus 50 percent of the Company's net income for each subsequent fiscal quarter. Failure to comply with either of these covenants would entitle the banks to terminate their lending commitments and to accelerate the maturity of all amounts outstanding. The Company was in compliance with both of these covenants at Dec. 31, 2003, and with the equivalent covenants in the prior year's lines of credit at Dec. 31, 2002. 7. PENSION AND OTHER POSTRETIREMENT BENEFITS: - -------------------------------------------------- NW Natural maintains two qualified non-contributory defined benefit pension plans covering all regular employees with more than one year of service, a non-qualified supplemental pension plan for eligible executive officers and other postretirement benefit plans for its employees. Only the two qualified defined benefit pension plans have plan assets. Those assets are held in a qualified trust to fund retirement benefits. 63 The following table provides a reconciliation of the changes in benefit obligations and fair value of assets, as applicable, for the pension plans and other postretirement benefit plans over the three-year period ended Dec. 31, 2003, and a statement of the funded status and amounts recognized in the consolidated balance sheets, using measurement dates of Dec. 31, 2003, 2002 and 2001: Post-Retirement Benefits - ----------------------------------------------------------------------------------------------------------------------------------- Pension Benefits Other Postretirement Benefits - ----------------------------------------------------------------------------------------------------------------------------------- Thousands 2003 2002 2001 2003 2002 2001 - --------- ---- ---- ---- ---- ---- ---- Change in benefit obligation: Benefit obligation at Jan. 1 $185,124 $166,751 $146,802 $ 18,457 $ 16,987 $ 14,069 Service cost 4,748 4,637 3,964 456 395 325 Interest cost 12,402 11,807 11,332 1,336 1,174 1,116 Expected benefits paid (10,363) (9,453) (9,152) (1,027) (979) (942) Plan amendments - - 1,838 (111) (300) - Net actuarial (gain) loss 13,441 11,382 11,967 4,268 1,180 2,419 ------------- ---------------- --------------- ---------------- ---------------- ---------------- Benefit obligation at Dec. 31 205,352 185,124 166,751 23,379 18,457 16,987 ------------- ---------------- --------------- ---------------- ---------------- ---------------- Change in plan assets: Fair value of plan assets at Jan. 1 143,164 168,964 190,451 - - - Actual return on plan assets 34,520 (17,082) (13,077) - - - Employer contributions 1,003 735 742 1,027 979 942 Benefits paid (10,363) (9,453) (9,152) (1,027) (979) (942) ------------- ---------------- --------------- ---------------- ---------------- ---------------- Fair value of plan assets at Dec. 31 168,324 143,164 168,964 - - - ------------- ---------------- --------------- ---------------- ---------------- ---------------- Funded status: Funded status at Dec. 31 (37,028) (41,960) 2,212 (23,379) (18,457) (16,987) Unrecognized transition obligation - - 351 3,703 4,226 4,795 Unrecognized prior service cost 6,240 7,371 8,575 - - 172 Unrecognized net actuarial (gain) loss 32,156 42,060 (2,956) 8,304 4,437 3,405 ------------- ---------------- --------------- --------------- ---------------- ----------------- Net amount recognized $ 1,368 $ 7,471 $ 8,182 $ (11,372) $ (9,794) $ (8,615) ============= ================ =============== =============== ================ ================= Amounts recognized in the consolidated balance sheets at Dec. 31 Prepaid benefit cost $ 11,113 $ 17,339 $ 17,211 - - - Accrued benefit liability (11,319) (18,741) (9,346) (11,372) (9,794) (8,615) Intangible asset - 4,438 169 - - - Other comprehensive loss 1,574 4,435 148 - - - ------------- --------------- ---------------- ---------------- --------------- ----------------- Net amount recognized $ 1,368 $ 7,471 $ 8,182 $ (11,372) $ (9,794) $ (8,615) ============= =============== ================ ================ =============== =================
64 The Company's qualified defined benefit pension plans had an accumulated benefit obligation in excess of plan assets at Dec. 31, 2003. The plans' aggregate accumulated benefit obligation was $192 million, $172 million and $156 million at Dec. 31, 2003, 2002 and 2001, respectively, and the fair value of plan assets was $168 million, $143 million and $169 million, respectively. The fair value of plan assets increased from Dec. 31, 2002 to Dec. 31, 2003 due to $36 million in investment gains, partially offset by $10 million in withdrawals to pay benefits and $0.9 million to pay eligible expenses of the plans. The combination of investment returns and cash contributions is expected to provide sufficient funds to cover all benefit obligations of the plans. The Company is required to make a cash contribution of at least $1.9 million, and may make an additional contribution up to a total of $6.8 million, to its non-bargaining employee pension plan for the 2003 plan year, payable by Sept. 15, 2004. The Company's investment policy and performance objectives for the qualified pension plan assets (plan assets) held in the Northwest Natural Gas Company Retirement Trust Fund was approved by a retirement committee composed of management employees. The policy sets forth the guidelines and objectives governing the investment of plan assets. Plan assets are invested for total return with appropriate consideration for liquidity and portfolio risk. All investments are expected to satisfy the requirements of the rule of prudent investments as set forth under the Employee Retirement Security Act of 1974 (ERISA). The approved asset classes are cash and short-term investments, fixed income, common stock and convertible securities, absolute 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-balancing 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, 2003 and 2002, and the target allocation and expected long-term rate of return by asset category for 2004 are as follows:
Percentage of Plan Expected Assets Target Long-term Dec. 31, Allocation Rate of Return Asset Category 2003 2002 2004 2004 ----------------------------------------------------------------------- US Large Cap Equity 40.2% 36.3% 40% 9.00% US Small/Mid Cap Equity 7.3% 4.3% 8% 9.50% Non-US Equity 16.0% 17.1% 15% 9.00% Fixed Income 24.8% 34.7% 25% 6.00% Real Estate 3.9% 2.0% 40% 8.00% Absolute Return 7.8% 5.6% 8% 9.00% Weighted Average 8.25%
The Company's non-qualified supplemental pension plan's accumulated benefit obligation was $13.0 million, $12.8 million and $10.7 million at Dec. 31, 2003, 2002 and 2001, respectively. Although this plan is an unfunded plan with no plan assets due to its nature as a non-qualified plan, the Company indirectly funds its obligations with trust-owned life insurance. The amount of life insurance coverage is designed to provide sufficient returns to cover the benefit obligations and other costs of the plan. The Company's plans for providing postretirement benefits other than pensions also are unfunded plans. The aggregate benefit obligation for those plans was $23.4 million, $18.5 million and $17.0 million at Dec. 31, 2003, 2002 and 2001, respectively. 65 The following tables provide the components of net periodic benefit cost (income) for the pension and other postretirement benefit plans for the years ended Dec. 31, 2003, 2002 and 2001, and the assumptions used in measuring these costs and benefit obligations:
Thousands Pension Benefits Other Postretirement Benefits --------- ------------------------------------------------------------------ 2003 2002 2001 2003 2002 2001 ---- ---- ---- ---- ---- ---- Service cost $ 4,748 $ 4,637 $ 3,964 $ 456 $ 395 $ 325 Interest cost 12,402 11,807 11,332 1,336 1,174 1,116 Expected return on plan assets (12,232) (16,335) (17,198) - - - Amortization of transition obligation - 351 351 411 436 436 Amortization of prior service cost 1,132 1,204 1,284 - 6 19 Recognized actuarial (gain) loss 1,058 (216) (2,464) 401 147 75 ------ ------- --------- ----- ----- ----- Net periodic benefit cost (income) $7,108 1,448 $ (2,731) 2,604 2,158 1,971 ------ ------- --------- ----- ----- ----- Assumptions: ----------- Discount rate for net periodic benefit cost (NPBC) 6.75% 7.25% 7.50% 6.75% 7.25% 7.50% Rate of increase in compensation for NPBC 4.25-5.00% 4.25-5.00% 4.25-5.00% n/a n/a n/a Expected long-term rate of return for NPBC 8.00% 9.00% 9.00% n/a n/a n/a Discount rate for determination of funded status 6.25% 6.75% 7.25% 6.25% 6.75% 7.25% Rate of increase in compensation for funded status 4.00-4.75% 4.25-5.00% 4.25-5.00% n/a n/a n/a Expected long-term rate of return for funded status 8.25% 8.00% 9.00% n/a n/a n/a
The assumed annual trend rates used in measuring postretirement benefits as of Dec. 31, 2003 were 9 percent for medical and 14 percent for prescription drugs. Medical costs were assumed to decrease gradually each year to a rate of 4.5 percent for 2008, while prescription drug costs were assumed to decrease gradually each year to a rate of 4.5 percent for 2013. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
Thousands 1% Increase 1% Decrease ----------------------------------------------------------------------- Effect on the total service and interest cost components of net periodic postretirement health care benefit cost $ 71 $ (67) Effect on the health care component of the accumulated postretirement benefit obligation $ 955 $ (858)
66 The following table provides information regarding employer contributions and benefit payments for the pension and other postretirement benefit plans for the years ended Dec. 31, 2003 and 2002, and estimated future payments:
Other Pension Postretirement Thousands Benefits Benefits ----------------------------------------------------------------------- Employer Contributions by Plan Year ----------------------------------- 2002 $ 735 $ 979 2003 2,949 1,027 2004 (estimated) 3,007 1,509 ----------------------------------------------------------------------- Benefit Payments ---------------- 2002 $ 9,440 $ 979 2003 10,363 1,027 ----------------------------------------------------------------------- Estimated Future Benefit Payments --------------------------------- 2004 $11,667 $ 1,509 2005 12,224 1,555 2006 12,698 1,674 2007 12,965 1,770 2008 13,811 1,883 2009-2013 78,915 10,312
NW Natural's Retirement K Savings Plan (RKSP) is a qualified defined contribution plan under Internal Revenue Code Section 401(k). NW Natural also has a non-qualified deferred compensation plan for eligible officers and senior managers. These plans are designed to enhance the retirement program of employees and to assist them in strengthening their financial security by providing an incentive to save and invest regularly. NW Natural's matching contributions to these plans totaled $1.6 million in 2003, $1.4 million in 2002 and $1.3 million in 2001. Effective Jan. 1, 2002, the RKSP was amended to establish an Employee Stock Ownership Plan (ESOP) within the RKSP by converting the existing RKSP Company Stock Fund into an ESOP. This amendment allowed the Company to claim a tax benefit of $0.2 million in both 2003 and 2002 for the dividends paid on the Company's common stock held by the ESOP. In order to claim this deduction, the Company was required to allow RKSP participants the option of receiving the dividends paid on the Company's common stock in the ESOP account in cash rather than having the dividends automatically reinvested (see Note 8). 67 8. INCOME TAXES: - --------------- A reconciliation between income taxes calculated at the statutory federal tax rate and the tax provision reflected in the financial statements is as follows:
Thousands 2003 2002 2001 ------------------------------------------------------------------------------------------------------------------- Computed income taxes based on statutory federal income tax rate of 35% $ 24,263 $ 23,533 $ 27,209 Increase (reduction) in taxes resulting from: Difference between book and tax depreciation 222 222 222 Current state income tax, net of federal tax benefit 2,310 2,299 2,672 Federal income tax credits (357) (362) (362) Amortization of investment tax credits (879) (858) (855) Gains on Company and trust-owned life insurance (1,192) (487) (576) Removal costs (925) (573) (508) Reversal of amounts provided in prior years (226) (240) (72) Other - net 124 (90) (177) --------- -------- -------- Total provision for income taxes $ 23,340 $ 23,444 $ 27,553 ========= ======== ======== Total income taxes paid $ 13,940 $ 33,474 $ 25,201 ========= ======== ========
The provision for income taxes consists of the following:
Thousands 2003 2002 2001 ------------------------------------------------------------------------------------------------------------------- Income taxes currently payable: Federal $ 10,011 $ 9,377 $ 32,682 State 1,175 1,239 5,912 --------- -------- -------- Total 11,186 10,616 38,594 --------- -------- -------- Deferred taxes - net: Federal 10,747 11,476 (8,606) State 2,286 2,210 (1,580) --------- -------- -------- Total 13,033 13,686 (10,186) --------- -------- -------- Investment and energy tax credits restored: From utility operations (801) (800) (800) From subsidiary operations (78) (58) (55) --------- -------- -------- Total (879) (858) (855) --------- -------- -------- Total provision for income taxes $ 23,340 $ 23,444 $ 27,553 ========= ======== ======== Percentage of pretax income 33.7% 34.9% 35.4% ========= ======== ========
68 Deferred tax assets and liabilities are comprised of the following:
Thousands 2003 2002 ------------------------------------------------------------------------------------------------------------------- Deferred tax liabilities: Plant and Property $ 113,781 $ 96,525 Regulatory income tax assets 63,449 47,975 Regulatory liabilities - 319 Other deferred liabilities 6,109 6,569 --------- -------- Total 183,339 151,388 --------- -------- Deferred tax assets: Regulatory assets 970 - Minimum pension liability 557 1,883 Other deferred aasets 10,015 7,773 --------- -------- Total 11,542 9,656 --------- -------- Net accumulated deferred income tax liability $ 171,797 $141,732 ========= ========
Tax benefits of $1.3 million associated with charges for minimum pension liabilities in 2002 were reversed in OCI for the year ended Dec. 31, 2003. 9. PROPERTY AND INVESTMENTS: - --------------------------------- The following table sets forth the major classifications of NW Natural's utility plant and accumulated depreciation at Dec. 31:
2003 2002 -------------------------------------- ----------------------------------- Average Average Depreciation Depreciation Thousands Amount Rate Amount Rate --------------------------------------------------------------------------------------------------------------------- Transmission and distribution $ 1,347,402 3.3% $ 1,254,624 3.4% Utility Storage 107,547 2.7% 107,110 2.7% General 87,107 6.0% 83,878 6.3% Intangible and other 56,429 5.1% 53,291 4.3% ------------- ------------ Utility plant in service 1,598,485 3.5% 1,498,903 3.5% Gas stored long-term 12,778 11,301 Construction work in progress 47,826 29,761 ------------- ------------ Total utility plant 1,659,089 1,539,965 Accumulated depreciation (471,716) (435,601) ------------- ------------ Utility plant-net $ 1,187,373 $ 1,104,364 ============= ============
Accumulated depreciation does not include $135.6 million and $125.2 million at Dec. 31, 2003 and 2002, respectively, due to the reclassification of accumulated depreciation relating to removal costs in accordance with SFAS No. 143 (see Note 1). 69 The following table summarizes the Company's investments in non-utility plant at Dec. 31:
Thousands 2003 2002 ------------------------------------------------------------------------- Non-utility storage $18,507 $17,037 Dock, land, oil station and other 3,846 3,795 Construction work in progress 1,042 - ----------- ----------- Total non-utility plant 23,395 20,832 Less accumulated depreciation 4,855 4,404 ----------- ----------- Non-utility plant - net $18,540 $16,428 =========== =========== -------------------------------------------------------------------------
The following table summarizes the Company's partnership and joint venture investments accounted for under the equity or cost methods, and its investment in an aircraft leveraged lease, at Dec. 31:
Thousands 2003 2002 ------------------------------------------------------------------------- Aircraft leveraged lease $ 6,438 $ 6,489 Gas pipeline and other 2,880 2,950 Electric generation 3,317 3,264 ----------- ----------- Total other investments $12,635 $12,703 =========== =========== -------------------------------------------------------------------------
In 1987, the Company invested in a Boeing 737-300 aircraft, which is leased to Continental Airlines for 20 years under a leveraged lease agreement. A Financial Corporation subsidiary, KB Pipeline Company, has a 10 percent ownership interest in an 18-mile interstate natural gas pipeline and is the operator of this pipeline. In December 2003, KB Pipeline gave notice to the pipeline co-owners that it is resigning as pipeline operator effective in June 2004 due to increased obligations resulting from the Federal Energy Regulatory Commission's final regulations implementing Standards of Conduct for Transmission Providers. Those regulations govern the relationship between interstate natural gas pipelines and their energy affiliates or marketing functions and impose obligations previously inapplicable to KB Pipeline with regard to separation of duties and related matters. The regulations will continue to be applicable to KB Pipeline as a co-owner after its resignation as pipeline operator. Financial Corporation has ownership interests ranging from 4.0 to 5.3 percent in solar electric generation plants located near Barstow, California. Power generated by these plants is sold to Southern California Edison Company under long-term contracts. Financial Corporation also has ownership interests ranging from 25 to 41 percent in wind power electric generation projects located near Livermore and Palm Springs, California. The wind-generated power is sold to Pacific Gas and Electric Company and Southern California Edison Company under long-term contracts. 70 10. FAIR VALUE OF FINANCIAL INSTRUMENTS: - -------------------------------------------- The estimated fair value for NW Natural's financial instruments has been determined using available market information and appropriate valuation methodologies. The following are financial instruments whose carrying values are sensitive to market conditions:
Dec. 31, 2003 Dec. 31, 2002 --------------------------------- -------------------------------- Carrying Estimated Carrying Estimated Thousands Amount Fair Value Amount Fair Value ---------------------------------------------------------------------------------------------------------------------- Redeemable preferred stock $ - $ - $ 8,250 $ 8,333 Long-term debt including amount due within one year $500,319 $562,688 $465,945 $518,495 --------------------------------------------------------------------------------------------------------------
Fair value of the redeemable preferred stock and long-term debt was estimated using market prices in effect on the valuation date. Interest rates for debt with similar terms and remaining maturities were used to estimate fair value for long-term debt issues. 11. USE OF FINANCIAL DERIVATIVES: - ------------------------------------- NW Natural enters into short-term and long-term natural gas purchase contracts with suppliers, including contracts tied to floating prices. As such, NW Natural 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 floating price gas supply contracts. Swap contracts are used to convert certain long-term gas purchase contracts from floating prices to fixed prices. Call option contracts are used to limit the maximum adverse impact from floating price contracts while retaining the potential favorable impact from declining gas prices. The prices embedded in these commodity hedge contracts are incorporated in NW Natural's annual rate changes under its Purchased Gas Adjustment rate mechanisms, thereby limiting customers' exposure to frequent changes in purchased gas costs. The estimated fair value of gains and losses from commodity hedge contracts are recorded as a derivative asset or liability, and are offset by a corresponding amount recorded to a deferred regulatory asset or liability account for the effective portion of each hedge contract. The actual gains and losses realized at settlement of the hedge contracts are used to offset the actual purchase cost from NW Natural's physical supply contracts. Certain natural gas purchases from Canadian suppliers are invoiced in Canadian dollars, including both commodity and demand charges, thereby exposing NW Natural to adverse changes in foreign currency rates. Foreign currency forward contracts are used to minimize the impact of fluctuations in currency rates. Foreign currency contracts for commodity costs are purchased on a month-to-month basis because the Canadian cost is priced at the average noonday exchange rate for each month. Foreign 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 a corresponding amount to a deferred asset or liability account. 71 NW Natural did not use any derivative instruments to hedge oil or propane prices or interest rates during 2003, 2002 or 2001. At Dec. 31, 2003, NW Natural had the following derivatives outstanding covering its exposures to commodity and foreign currency prices: a series of 20 natural gas price swap contracts, three natural gas call option contracts, and 77 foreign currency forward contracts. Each of these contracts was designated as a cash flow hedge. The estimated fair values and the notional amounts of derivative instruments (unrealized gains and losses) outstanding were as follows:
Dec. 31, 2003 Dec. 31, 2002 ------------------------- ------------------------- Fair Value Notional Fair Value Notional Thousands Gain (Loss) Amount Gain (Loss) Amount ----------------------------------------------------------------------------------------------------------------------- Fixed-price natural gas commodity swap contracts $ 23,285 $ 284,317 $ 11,422 $ 159,724 Fixed-price natural gas call option contracts 366 19,761 717 18,084 Physical natural gas supply contract with embedded derivative - - 448 2,754 Foreign currency forward purchase contracts 234 6,417 (161) 15,525 ------------------------- ------------------------- Total $ 23,885 $ 310,495 $ 12,426 $ 196,087 ========================= =========================
In 2003, NW Natural realized net gains of $32.4 million from the settlement of natural gas commodity swap and call option contracts, which were recorded as decreases to the cost of gas, compared to net losses of $75.5 million during 2002 and net gains of $57.6 million during 2001. 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. The change in value of cash flow hedge contracts, not included in regulatory recovery, is included in OCI. The fair value of derivative instruments at Dec. 31, 2003 (see table above) was determined using estimated or quoted market prices for the periods covered by the contracts. Market prices for the natural gas commodity-price swap and call option contracts were obtained from external sources. NW Natural reviews these third-party valuations for reasonableness using fair value calculations 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, 2003, NW Natural had five natural gas commodity price swap contracts extending beyond Dec. 31, 2004, but none extends beyond Oct. 31, 2005. None of the natural gas commodity call option contracts extends beyond March 31, 2004. 12. COMMITMENTS AND CONTINGENCIES: - -------------------------------------- Lease Commitments ----------------- The Company leases land, buildings and equipment under agreements that expire in various years through 2018. Rental expense under operating leases was $4.9 million, $4.8 million and $4.7 million for the years ended Dec. 31, 2003, 2002 and 2001, respectively. The table below reflects the future minimum lease payments due under non-cancelable leases at Dec. 31, 2003. Such payments total $74.5 million for operating leases. The net present value of payments on capital leases less imputed interest was $0.3 million. These commitments principally relate to the lease of the Company's office headquarters, underground gas storage facilities, vehicles and computer equipment. 72
Later Millions 2004 2005 2006 2007 2008 years ----------------------------------------------------------------------------------------------------- Operating leases $ 4.3 $ 3.8 $ 3.8 $ 3.7 $ 3.6 $ 55.3 Capital leases 0.1 0.1 0.1 - - - -------- -------- ------- ------ ------- -------- Minimum lease payments $ 4.4 $ 3.9 $ 3.9 $ 3.7 $ 3.6 $ 55.3 ======== ======== ======= ====== ======= ========
Pipeline Capacity Purchase and Release Commitments -------------------------------------------------- NW Natural has signed agreements providing for the availability 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 entered into long-term sale agreements to release firm pipeline capacity. The aggregate amounts of these agreements were as follows at Dec. 31, 2003:
Pipeline Pipeline Capacity Capacity Purchase Release Thousands Agreements Agreements --------------------------------------------------------------------------------------------------------- 2004 $ 56,296 $ 3,781 2005 60,540 3,782 2006 57,772 3,781 2007 57,773 3,782 2008 56,245 3,781 2009 through 2023 301,397 6,933 ------------- ----------- Total 590,023 25,840 Less: Amount representing interest 128,151 3,463 ------------- ----------- Total at present value $ 461,872 $ 22,377 ============= ===========
NW Natural's total payments of fixed charges under capacity purchase agreements in 2003, 2002 and 2001 were $86.7 million, $86.2 million and $86.5 million, respectively. Included in the amounts for 2003, 2002 and 2001 were reductions for capacity release sales of $3.7 million, $4.2 million and $3.8 million, respectively. In addition, 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 prepayments subject to recovery over a longer term if future purchases exceed the minimum annual requirements. Environmental Matters --------------------- NW Natural owns property in Multnomah County, Oregon that is the site of a former gas manufacturing plant that was closed in 1956 (the Gasco site). The Gasco site has been under investigation by NW Natural for environmental contamination under the Oregon Department of Environmental Quality's (ODEQ) Voluntary Clean-Up Program. On June 30, 2003, the Company filed a Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of the Gasco site. NW Natural will work with the ODEQ to determine the appropriate remedial action from among the alternatives. Based upon the proposed actions in the draft plan, the Company estimates its range of remaining liability, including the cost of investigation, from feasible alternatives, at between $1.5 million and $7 million. At Dec. 31, 2003, NW Natural had liabilities totaling $1.5 million outstanding, regulatory deferred costs of $0.2 million and a $2.5 million insurance 73 receivable, for its estimated costs of investigation and interim remediation at the Gasco site, including consultants' fees, ODEQ oversight reimbursement and legal fees. NW Natural previously owned property adjacent to the Gasco site that now is the location of a manufacturing plant owned by Wacker Siltronic Corporation (the Wacker site). In 2000, the ODEQ issued an order requiring Wacker and NW Natural to determine the nature and extent of releases of hazardous substances to Willamette River sediments from the Wacker site. NW Natural has completed the majority of the studies required under the ODEQ work plan and the agency is reviewing data generated by the studies. At Dec. 31, 2003, NW Natural recorded liabilities totaling $0.3 million for its estimated costs of the investigation and initial remediation on the Wacker site, nearly all of which had been spent as of Dec. 31, 2003. In 1998, the ODEQ and the U.S. Environmental Protection Agency (EPA) completed a study of sediments in a 5.5-mile segment of the Willamette River (the Portland Harbor) that includes the area adjacent to the Gasco site and the Wacker site. In 2000, the EPA listed the Portland Harbor as a Superfund site and notified the Company that it is a potentially responsible party. Between 2000 and 2003, NW Natural recorded liabilities totaling $2.6 million, of which $1.9 million had been spent as of Dec. 31, 2003. The amount of NW Natural's liability is based on estimates of the Company's share of the lower end of a range of probable liability for the costs of the Remedial Investigation/Feasibility Study for the Portland Harbor. Available information is insufficient to determine either the total amount of liability for investigation and remediation of the Portland Harbor or the higher end of a range for NW Natural's estimated share of that liability. On March 1, 2004, the Company received a letter from the EPA requesting that the Company enter into a consent order relating to removal of certain contaminants in the riverbed adjacent to the Gasco site. The Company is reviewing the EPA's request and has not determined what its response will be, or what a reasonable estimate of the cost would be for any action the Company might take in response to the request. The City of Portland notified NW Natural that it was planning a sewer improvement project that would include excavation 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 preliminary assessment of this site performed by a consultant for the EPA in 1987 indicated that it could be assumed that by-product tars may have been disposed of on site. The report concluded, however, that it is likely that waste residues from the plant, if present on the site, were covered by deep fill 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 connection with the sewer project, which has commenced. Available information is insufficient to determine either the total amount of NW Natural's liability or a probable range, if any, of potential liability. In May 2003, the OPUC approved NW Natural's request for deferral of environmental costs associated with specific sites, including the Gasco, Wacker, Portland Gas and Portland Harbor sites. The authorization, effective for a 12-month period beginning April 7, 2003, allows NW Natural to defer and seek recovery of unreimbursed environmental costs in a future general rate case. The Company recorded a cumulative deferral of $1.0 million in environmental costs related to these specific sites in 2003. Additionally, on a cumulative basis through Dec. 31, 2003, the Company has accrued environmental costs totaling $8.0 million relating to the sites, including $5.9 million that has already been disbursed. NW Natural has accrued all material loss contingencies relating to environmental matters that it believes to be probable of assertion and reasonably estimable. Due to the preliminary nature of these environmental investigations, the range of any additional possible loss contingency cannot be currently estimated. NW Natural will first seek to recover the costs of further investigation and remediation for which it may be responsible with respect to the Gasco site, the Wacker site, the Portland Harbor site and the Portland Gas site, if any, from insurance. If these costs are not recovered from insurance, then NW Natural will seek recovery through future rates. At Dec. 31, 2003, NW Natural had a $3.7 million receivable representing an estimate of the 74 environmental costs NW Natural expects to incur and recover from insurance, including $2.5 million for costs relating to the Gasco site and $1.25 million for costs relating to the Portland Harbor site. Enron Gas Supply Contract ------------------------- On Oct. 16, 2003, NW Natural received a demand letter from Enron North America Corp. (Enron) seeking payment of $1.1 million allegedly owed pursuant to a gas supply contract between NW Natural and Enron, which was in effect when Enron filed for bankruptcy in December 2001. The contract was terminated when Enron filed for bankruptcy, and NW Natural does not believe that any amounts are owed to Enron under the contract. NORTHWEST NATURAL GAS COMPANY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Dollars Quarter ended --------------------------------------------------------- (Thousands, except per share amounts) March 31 June 30 Sept. 30 Dec. 31 Total - --------------------------------------------------------------------------------------------------------- 2003 Operating revenues $206,539 $117,489 $69,481 $217,747 $611,256 Net operating revenues 98,588 58,549 39,465 91,464 288,066 Net income (loss) 26,404 4,462 (6,546) 21,663 45,983 Basic earnings (loss) per share 1.03 0.17 (0.25) 0.84 1.77 /*/ Diluted earnings (loss) per share 1.01 0.17 (0.25) 0.83 1.76 /*/ 2002 Operating revenues $278,563 $101,873 $78,717 $182,223 $641,376 Net operating revenues 110,666 56,564 38,059 82,255 287,544 Net income (loss) 34,447 (2,992) (6,008) 18,345 43,792 Basic earnings (loss) per share 1.34 (0.14) (0.26) 0.70 1.63 /*/ Diluted earnings (loss) per share 1.32 (0.14) (0.26) 0.69 1.62 /*/ /*/ Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Because the average number of shares outstanding has changed in each quarter shown, the sum of quarterly earnings (loss) per share may not equal earnings per share for the year. Variations in earnings between quarterly periods are due primarily to the seasonal nature of the Company's business.
75 NORTHWEST NATURAL GAS COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
- ----------------------------------------------------------------------------------------------------------------- COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - ----------------------------------------------------------------------------------------------------------------- Additions Deductions Balance at ----------------------------------------- Balance beginning Charged to Charged to at end of costs other Net of period and expenses accounts write-offs period ------ ------------ -------- ---------- ------- Thousands (year ended December 31) 2003 - ---- Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts $1,815 $1,990 $0 $2,042 $1,763 2002 - ---- Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts $1,962 $2,876 $0 $3,023 $1,815 2001 - ---- Reserves deducted in balance sheet from assets to which they apply: Allowance for uncollectible accounts $1,867 $3,359 $0 $3,264 $1,962
76 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES (a) Evaluation of Disclosure Controls and Procedures As of Dec. 31, 2003, the principal executive officer and principal financial officer of the Company have evaluated the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (Exchange Act)). Based upon that evaluation, the principal executive officer and principal financial officer of the Company have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to the Company and its consolidated subsidiaries required to be included in the Company's reports filed with or furnished to the Securities and Exchange Commission under the Exchange Act. (b) Changes in Internal Control Over Financial Reporting There has been no change in the Company's internal control over financial reporting that occurred during the Company's most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. 77 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information concerning the Company's Board of Directors and the Audit Committee financial expert contained in the Company's definitive Proxy Statement for the May 27, 2004 Annual Meeting of Shareholders is hereby incorporated by reference.
Age at Name December 31, 2003 Positions held during last five years ---- ----------------- ------------------------------------- Mark S. Dodson 58 President and Chief Executive Officer (2003- ); President, Chief Operating Officer and General Counsel (2001-02); Senior Vice President, Public Affairs and General Counsel (1998-01); Senior Vice President (1997). Michael S. McCoy 60 Executive Vice President, Customer and Utility Operations (2000- ); Senior Vice President, Customer and Utility Operations (1999-00); Senior Vice President, Customer Services (1992-99). Bruce R. DeBolt 56 Senior Vice President, Finance, and Chief Financial Officer (1990- ). Gregg S. Kantor 46 Senior Vice President, Public and Regulatory Affairs (2003- ); Vice President, Public Affairs and Communications (1998-02). Beth A. Ugoretz 48 Senior Vice President and General Counsel (2003- ); Executive Vice President, Kindercare Learning Centers, Inc. (1997-00). Lea Anne Doolittle 48 Vice President, Human Resources (2000- ); Director of Compensation (1993-2000), PacifiCorp. Stephen P. Feltz 48 Treasurer and Controller (1999- ); Assistant Treasurer (1996-99); Manager, General Accounting (1996-99). C. J. Rue 58 Secretary (1982- ); Assistant Treasurer (1987- ). Richelle T. Luther 35 Assistant Secretary (2002- ); Associate, Stoel Rives, LLP (1997-02).
Each executive officer serves successive annual terms; present terms end May 27, 2004. There are no family relationships among the Company's executive officers. The Company has adopted a Code of Ethics for all employees and a Financial Code of Ethics that applies to senior financial employees, both of which are available on the Company's website at www.nwnatural.com. 78 ITEM 11. EXECUTIVE COMPENSATION Information concerning Executive Compensation contained in the Company's definitive Proxy Statement for the May 27, 2004 Annual Meeting of Shareholders is hereby incorporated by reference. Information related to Executive Officers as of December 31, 2003 is reflected in Part III, Item 10, above. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The following table sets forth information regarding compensation plans under which equity securities of the Company are authorized for issuance as of Dec. 31, 2003 (see Note 12 to the Consolidated Financial Statements):
(A) (B) (C) Number of securities remaining available for Number of securities future issuance under to be issued upon Weighted-average equity compensation exercise of exercise price of plans (excluding outstanding options, outstanding options, securities reflected Plan Category warrants and rights warrants and rights in column (a)) - ------------------------------------------------------------------------------------------------------------------ Equity compensation plans approved by security holders: Long-Term Incentive Plan (LTIP)(Target Award)/1/ 61,000 N/A 434,500 Restated Stock Option Plan 322,044 $25.35 1,429,500 Employee Stock Purchase Plan 30,956 $24.70 103,284 Equity compensation plans not approved by security holders: Executive Deferred Compensation Plan (EDCP)/2/ 9,202 N/A N/A Directors Deferred Compensation Plan (DDCP)/2/ 72,003 N/A N/A Non-Employee Directors Stock Compensation Plan/3/ N/A N/A N/A ------------------- --------------------- Total 495,205 $25.30 1,967,284 =================== ===================== Certain other information called for by Item 12 is incorporated herein by reference to portions of the Company's definitive Proxy Statement for the May 27, 2004 Annual Meeting of Shareholders. - -------------------- /1/ Shares issued pursuant to the LTIP do not include an exercise price, but are payable by the Company when the award criteria are satisfied. If the maximum awards were paid pursuant to awards outstanding at Dec. 31, 2003, the number of shares shown in column (a) would increase by 61,000 shares and the number of shares shown in column (c) would decrease by 61,000 shares. /2/ At the participant's election, deferred amounts may be credited to either a "cash account" or a Company "stock account." If deferred amounts are credited to stock accounts, such accounts are credited with a number of shares based on the purchase price of the Common Stock on the next purchase date under the Company's Dividend Reinvestment and Stock Purchase Plan, and such accounts are credited with additional shares based on the deemed reinvestment of dividends. At the election of the participant, deferred balances in the stock accounts are payable after termination of Board service or employment in a lump sum, in installments over a period not to exceed 10 years in the case of the DDCP, or 15 years in the case of the EDCP, or in a combination of lump sum and installments. The Company has contributed Common Stock to the trustee of the Umbrella Trust such that the Umbrella Trust holds the number of shares of Common Stock equal to the number of shares credited to all participants' stock accounts. /3/ The material features of this plan are more particularly described in Note 4 to the Consolidated Financial Statements included in this report.
79 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information captioned "Certain Relationships and Related Transactions" in the Company's definitive Proxy Statement for the May 27, 2004 Annual Meeting of Shareholders is hereby incorporated by reference. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The information captioned "Other Matters-Selection of Independent Auditors" in the Company's definitive Proxy Statement for the May 27, 2004 Annual Meeting of Shareholders is hereby incorporated by reference. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this report: 1. A list of all Financial Statements and Supplemental Schedules is incorporated by reference to Item 8. 2. List of Exhibits filed: Reference is made to the Exhibit Index commencing on page 82. (b) Reports on Form 8-K. A report on Form 8-K dated Nov. 4, 2003 was furnished to the SEC on November 4, 2004 regarding a press release issued by the Company concerning earnings for the quarter and nine months ended Sept. 30, 2003. The report was furnished under Item 12, "Results of Operations and Financial Condition." A report on Form 8-K dated Jan. 29, 2004 was filed with the SEC on Jan. 29, 2004 regarding a press release issued by the Company concerning earnings for the fiscal year ended Dec. 31, 2003. Information in the report was filed with respect to disclosure under Item 5, "Other Events and Regulation FD Disclosure" and furnished with respect to disclosure under Item 12, "Results of Operations and Financial Condition." 80 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. NORTHWEST NATURAL GAS COMPANY Date: March 9, 2004 By: /s/ Mark S. Dodson --------------------------------- Mark S. Dodson, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
SIGNATURE TITLE DATE - ------------------------------------------------------------------------------------------------------ /s/ Mark S. Dodson Principal Executive Officer and Director March 9, 2004 - -------------------------------- Mark S. Dodson, President and Chief Executive Officer /s/ Bruce R. DeBolt Principal Financial Officer March 9, 2004 - -------------------------------- Bruce R. DeBolt Senior Vice President, Finance, and Chief Financial Officer /s/ Stephen P. Feltz Principal Accounting Officer March 9, 2004 - -------------------------------- Stephen P. Feltz Treasurer and Controller /s/ Timothy P. Boyle Director ) - -------------------------------- ) Timothy P. Boyle ) ) /s/ John D. Carter Director ) - -------------------------------- ) John D. Carter ) ) /s/ C. Scott Gibson Director ) - -------------------------------- ) C. Scott Gibson ) ) /s/ Tod R. Hamachek Director ) - -------------------------------- ) Tod R. Hamachek ) ) /s/ Randall C. Pape Director ) March 9, 2004 - -------------------------------- ) Randall C. Pape ) ) /s/ Richard G. Reiten Director ) - -------------------------------- ) Richard G. Reiten ) ) /s/ Robert L. Ridgley Director ) - -------------------------------- ) Robert L. Ridgley ) ) /s/ Melody C. Teppola Director ) - -------------------------------- ) Melody C. Teppola ) ) /s/ Russell F. Tromley Director ) - -------------------------------- ) Russell F. Tromley ) ) /s/ Richard L. Woolworth Director ) - -------------------------------- Richard L. Woolworth
81 EXHIBIT INDEX ------------- To Annual Report on Form 10-K For Fiscal Year Ended December 31, 2003 Exhibit Number Document -------------- -------- *(3a.) Restated Articles of Incorporation, as filed and effective June 24, 1988 and amended December 8, 1992, December 1, 1993 and May 27, 1994 (incorporated herein by reference to Exhibit (3a.) to Form 10-K for 1994, File No. 0-994). *(3b.) Bylaws as amended December 18, 2003 (incorporated herein by reference to Exhibit 4(b) in File No. 333-112604). *(4a.) Copy of Mortgage and Deed of Trust, dated as of July 1, 1946, to Bankers Trust and R. G. Page (to whom Stanley Burg is now successor), Trustees (incorporated herein by reference to Exhibit 7(j) in File No. 2-6494); and copies of Supplemental Indentures Nos. 1 through 14 to the Mortgage and Deed of Trust, dated respectively, as of June 1, 1949, March 1, 1954, April 1, 1956, February 1, 1959, July 1, 1961, January 1, 1964, March 1, 1966, December 1, 1969, April 1, 1971, January 1, 1975, December 1, 1975, July 1, 1981, June 1, 1985 and November 1, 1985 (incorporated herein by reference to Exhibit 4(d) in File No. 33-1929); Supplemental Indenture No. 15 to the Mortgage and Deed of Trust, dated as of July 1, 1986 (filed as Exhibit (4)(c) in File No. 33-24168); Supplemental Indentures Nos. 16, 17 and 18 to the Mortgage and Deed of Trust, dated, respectively, as of November 1, 1988, October 1, 1989 and July 1, 1990 (incorporated herein by reference to Exhibit (4)(c) in File No. 33-40482); Supplemental Indenture No. 19 to the Mortgage and Deed of Trust, dated as of June 1, 1991 (incorporated herein by reference to Exhibit 4(c) in File No. 33-64014); and Supplemental Indenture No. 20 to the Mortgage and Deed of Trust, dated as of June 1, 1993 (incorporated herein by reference to Exhibit 4(c) in File No. 33-53795). *(4d.) Copy of Indenture, dated as of June 1, 1991, between the Company and Bankers Trust Company, Trustee, relating to the Company's Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4(e) in File No. 33-64014). *(4e.) Officers' Certificate dated June 12, 1991 creating Series A of the Company's Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit (4e.) to Form 10-K for 1993, File No. 0-994). *(4f.) Officers' Certificate dated June 18, 1993 creating Series B of the Company's Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit (4f.) to Form 10-K for 1993, File No. 0-994). *(4f.(1)) Officers' Certificate dated January 17, 2003 relating to Series B of the Company's Unsecured Medium-Term Notes and supplementing the Officers' Certificate dated June 18, 1993 (incorporated herein by reference to Exhibit (4f.(1)) to Form 10-K for 2002, File No. 0-994). 82 Exhibit Number Document -------------- -------- *(4g.) Rights Agreement, dated as of February 27, 1996, between the Company and Boatmen's Trust Company (Mellon Investor Services LLC, successor), which includes as Exhibit A thereto the form of a Right Certificate and as Exhibit B thereto the Summary of Rights to Purchase Common Shares (incorporated herein by reference to Exhibit 1 to Form 8-A, dated February 27, 1996, File No. 0-994). *(4h.) Amendment No. 1, dated October 5, 2001, to Rights Agreement, dated February 27, 1996, between the Company and Boatmen's Trust Company (Mellon Investor Services LLC, successor) (incorporated herein by reference to Exhibit 4 to Form 10-Q for quarter ended September 30, 2001, File No. 0-994). *(10j.) Transportation Agreement, dated June 29, 1990, between the Company and Northwest Pipeline Corporation (incorporated herein by reference to Exhibit (10j.) to Form 10-K for 1993, File No. 0-994). *(10j.(1)) Replacement Firm Transportation Agreement, dated July 31, 1991, between the Company and Northwest Pipeline Corporation (incorporated herein by reference to Exhibit (10j.(2)) to Form 10-K for 1992, File No. 0-994). *(10j.(2)) Firm Transportation Service Agreement, dated November 10, 1993, between the Company and Pacific Gas Transmission Company (incorporated herein by reference to Exhibit (10j.(2)) to Form 10-K for 1993, File No. 0-994). *(10j.(3)) Service Agreement, dated June 17, 1993, between Northwest Pipeline Corporation and the Company (incorporated herein by reference to Exhibit (10j.(3)) to Form 10-K for 1994, File No. 0-994). *(10j.(5)) Firm Transportation Service Agreement, dated June 22, 1994, between Pacific Gas Transmission Company and the Company (incorporated herein by reference to Exhibit (10j.(5)) to Form 10-K for 1995, File No. 0-994). *(10j.(6)) Firm Service Agreement between the Company and Westcoast Energy Inc., dated as of April 1, 2003 (incorporated herein by reference to Exhibit (10) to Form 10-Q for quarter ended March 31, 2003, File No. 0-994). (11) Statement re computation of per share earnings. (12) Statement re computation of ratios of earnings to fixed charges. (23) Consent of PricewaterhouseCoopers LLP. (31.1) Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002. 83 Exhibit Number Document -------------- -------- (31.2) Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002. (32.1) Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Executive Compensation Plans and Arrangements: *(10b.) Executive Supplemental Retirement Income Plan, 1995 Restatement (incorporated herein by reference to Exhibit (10b.) to Form 10-K for 1994, File No. 0-994). *(10b.-1) 1995 Amendment to Executive Supplemental Retirement Income Plan (1995 Restatement) (incorporated herein by reference to Exhibit (10b.-1) to Form 10-K for 1995, File No. 0-994). *(10b.-2) Amendment 1998-1 to the Executive Supplemental Retirement Income Plan (1995 Restatement) (incorporated herein by reference to Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 1998, File No. 0-994). *(10b.-3) ESRIP Change in Control Amendment to the Executive Supplemental Retirement Income Plan (1995 Restatement) (incorporated herein by reference to Exhibit 10(b) to Form 10-Q for the quarter ended September 30, 1998, File No. 0-994). *(10c.) Restated Stock Option Plan, as amended effective May 23, 2002 (incorporated herein by reference to Exhibit 10(a) to Form 10-Q for quarter ended September 30, 2002, File No. 0-994). *(10e.) ExecutiveDeferred Compensation Plan, effective as of January 1, 1987, Restated as of January 1, 2003 (incorporated herein by reference to Exhibit (10 e.) to Form 10-K for 2002, File No. 0-994). .. (10f.) Directors Deferred Compensation Plan, effective June 1, 1981, restated as of February 26, 2004 *(10g.) Form of Indemnity Agreement as entered into between the Company and each director and executive officer (incorporated herein by reference to Exhibit (10g.) to Form 10-K for 1988, File No. 0-994). (10i.) Non-Employee Directors Stock Compensation Plan, as amended effective February 26, 2004. *(10k.) Executive Annual Incentive Plan, effective January 1, 2003 (incorporated herein by reference to Exhibit (10 k) to Form 10-K for 2002, File No. 0-994). .. *(10n.) Employment agreement dated November 2, 1995, as amended February 27, 1996, between the Company and an executive officer (incorporated herein by reference to Exhibit (10n.) to Form 10-K for 1995, File No. 0-994). 84 Exhibit Number Document -------------- -------- *(10n.-1) Amendment dated December 18, 1997 to employment agreement dated November 2, 1995, as previously amended February 27, 1996, between the Company and an executive officer (incorporated herein by reference to Exhibit (10n.-1) to Form 10-K for 1997, File No. 0-994). *(10n.-2) Amendment dated September 24, 1998 to employment agreement dated November 2, 1995, as previously amended, between the Company and an executive officer (incorporated herein by reference to Exhibit 10(e) to Form 10-Q for the quarter ended September 30, 1998, File No. 0-994). *(10n.-3) Summary of Compensation Arrangements for Chairman of the Board, March 1, 2003 - February 28, 2005 (incorporated herein by reference to Exhibit (10n.-3)) to Form 10-K for 2002, File No. 0-994). *(10o.) Form of amended and restated executive change in control severance agreement as entered into between the Company and each executive officer (incorporated herein by reference to Exhibit 10(a) to Form 10-Q for the quarter ended June 30, 2001, File No. 0-994). *(10o.(1)) Form of change in control letter agreement as entered into between the Company and each executive officer (incorporated herein by reference to Exhibit 10(a) to Form 10-Q for the quarter ended September 30, 2001, File No. 0-994). *(10p.) Employment Agreement dated July 2, 1997, between the Company and an executive officer (incorporated herein by reference to Exhibit 10(a) for Form 10-Q for the quarter ended September 30, 1997, File No. 0-994). *(10p.-1) Amendment dated December 18, 1997 to employment agreement dated July 2, 1997, between the Company and an executive officer (incorporated herein by reference to Exhibit (10p.-1) to Form 10-K for 1997, File No. 0-994). *(10p.-2) Amendment dated September 24, 1998 to employment agreement dated July 2, 1997, as previously amended, between the Company and an executive officer (incorporated herein by reference to Exhibit 10(g) to Form 10-Q for the quarter ended September 30, 1998, File No. 0-994). *(10p.-3) Employment Agreement dated December 20, 2002, between the Company and an executive officer (incorporated herein by reference to Exhibit (10p.-3) to Form 10-K for 2002, File No. 0-994). .. *(10r.) Employment agreement dated May 11, 1999, between the Company and an executive officer (incorporated herein by reference to Exhibit 10 to Form 10-Q for the quarter ended June 30, 1999, File No. 0-994). *(10u.) Separation Agreement and Mutual Release of All Claims between the Company and an executive officer, dated February 28, 2001 (incorporated herein by reference to Exhibit (10u.) to Form 10-K for 2000, File No. 0-994). 85 Exhibit Number Document -------------- -------- *(10v.) Northwest Natural Gas Company Long-Term Incentive Plan, as amended and restated effective July 26, 2001 (incorporated herein by reference to Exhibit 10(c) to Form 10-Q for the quarter ended June 30, 2001, File No. 0-994). *(10w.) Restricted stock retention agreement, dated August 1, 2001, as entered into between the Company and an executive officer (incorporated herein by reference to Exhibit 10(b) to Form 10-Q for the quarter ended June 30, 2001, File No. 0-994). The Company agrees to furnish the Commission, upon request, a copy of certain instruments defining rights of holders of long-term debt of the Company or its consolidated subsidiaries which authorize securities thereunder in amounts which do not exceed 10% of the total assets of the Company. - ------------------------------------- *Incorporated herein by reference as indicated EX-10 3 ex10f.txt EX. 10F - DIRECTORS DEFERRED COMPENSATION PLAN EXHIBIT (10f.) NORTHWEST NATURAL GAS COMPANY DIRECTORS DEFERRED COMPENSATION PLAN EFFECTIVE JUNE 1, 1981 RESTATED AS OF FEBRUARY 26, 2004 TABLE OF CONTENTS Page ---- 1. Restatement.......................................................... 1 2. Election by Directors................................................ 1 3. Accounts ............................................................ 2 4. Interest ............................................................ 4 5. Terms of Payment..................................................... 4 6. Death of Director.................................................... 6 7. Administration....................................................... 6 8. Definitions; Change in Control; Corporate Transaction................ 6 9. Amendment and Termination of the Plan................................ 8 10. Miscellaneous........................................................ 9 NORTHWEST NATURAL GAS COMPANY DIRECTORS DEFERRED COMPENSATION PLAN 1. Restatement. The Board of Directors (the "Board") of Northwest Natural Gas Company (hereinafter, the "Company") adopted a Director's Deferred Compensation Plan (hereinafter, the "Plan") effective June 1, 1981, which was previously restated effective as of January 1, 1988, December 1, 1997 and December 1, 2001, and then amended effective as of July 1, 2002. The existing Plan is amended by this Restatement, effective as of February 26, 2004. 2. Election by Directors. (a) Eligibility. Any director of the Company or any corporation or other entity affiliated with or subsidiary to it (a "Director") is eligible to elect to defer receipt of all or part of (i) the fees paid to him or her as a Director or as a member of a committee of the Board ("Fees"), or (ii) the shares ("NEDSCP Shares") of restricted common stock of the Company ("Common Stock") awarded to the Director under the Company's Non-Employee Directors Stock Compensation Plan ("NEDSCP"). In addition, a Director may elect under the NEDSCP to receive awards under that plan as deferred cash credits ("NEDSCP Cash Credits") rather than as NEDSCP Shares. (b) Deferral of Fees. Any Director may elect, prior to the beginning of any calendar year, to defer receipt of fees for that calendar year, whether or not the fees are actually payable in that calendar year; and any newly elected Director prior to assuming office may elect to defer receipt of fees commencing after the date on which the Director assumes office. Any election under the preceding sentence shall apply only to fees earned subsequent to the date the election is filed. Total deferrals of Fees by a Director in a calendar year must be at least $1,500. (c) Deferral of NEDSCP Shares. Any Director may elect, prior to the beginning of any calendar year, to defer receipt of unvested NEDSCP Shares that are scheduled to vest in that calendar year; and any newly elected Director prior to assuming office may elect to defer receipt of NEDSCP Shares that will vest in the remainder of the calendar year after the date on which the Director assumes office. Total deferrals of NEDSCP Shares by a Director in a calendar year must be at least 100% of the NEDSCP Shares scheduled to vest in that year. No deferral shall be allowed of NEDSCP Shares as to which a Director has made an election under Section 83(b) of the Internal Revenue Code. (d) Continuation and Modification. An election to defer Fees or NEDSCP Shares by a Director shall automatically continue from year to year unless the Director terminates or modifies the election by written request. Any such termination or modification shall not become applicable until the calendar year following the year in which such written termination or modification is filed. In the event of a termination of a deferral election, any amounts already deferred by a Director shall not be paid until he or she ceases to serve as a Director, and then only pursuant to the terms, conditions, limitations and restrictions of the Plan. 1 3. Accounts. (a) Accounts. The Company shall establish on its books one, two or three separate accounts (individually, an "Account" and collectively, the "Accounts") for each Director who participates in the Plan: a Stock Account, a Cash Account, and/or for each person who is a Director as of January 1, 1998, a Retirement Benefit Account. The number of NEDSCP Shares deferred by a Director shall be credited to the Stock Account. Any NEDSCP Cash Credits shall be credited to the Cash Account. Fees deferred by a Director shall be credited to the Stock Account or the Cash Account as elected by the Director at the time the Director elects to defer Fees. Such election may be divided between the two Accounts in increments of 25 percent of the deferred Fees covered by the election. An election between the Stock Account and the Cash Account shall be irrevocable as to the deferred Fees covered by the election and no transfers between the Stock Account and the Cash Account shall be permitted except as otherwise provided in Paragraph 3(f)(iv). The credit for deferred Fees shall be entered on the Company's books of account each month at the time that Fees are paid to other Directors who do not elect to defer the payment of such Fees. The credit for deferred NEDSCP Shares shall be entered on the Company's books of account as soon as practicable after January 1 of the year subject to the deferral. The credit for an NEDSCP Cash Credit shall be entered on the Company's books of account effective as of the award date for such credit under the NEDSCP. No special fund shall be established nor shall any notes or securities be issued by the Company with respect to a Director's Accounts. (b) Stock Account. A Director's Stock Account shall be denominated in shares of Common Stock, including fractional shares. With respect to each amount of Fees deferred to a Director's Stock Account, the Stock Account shall be credited with a number of shares equal to the deferred Fees divided by the purchase price for shares of Common Stock under the Company's Dividend Reinvestment and Stock Purchase Plan (the "DRSPP") on the Investment Date (as defined in the DRSPP) next succeeding the day the deferred Fees would have been paid if not for the deferral. As of each date for payment of dividends on the Common Stock, the Stock Accounts shall be credited with an additional number of shares (including fractional shares) equal to the amount of dividends that would be paid on the number of shares recorded as the balance of the Stock Account as of the record date for such dividend divided by the purchase price for shares of Common Stock under the DRSPP for dividends reinvested on such payment date. (c) Forfeiture of NEDSCP Shares or NEDSCP Cash Credits. If any NEDSCP Shares deferred by a Director under this Plan are forfeited under the terms of the NEDSCP, the Director's Stock Account shall be reduced by the number of shares so forfeited. If any NEDSCP Cash Credits of a Director are forfeited under the terms of the NEDSCP, the Director's Cash Account shall be reduced by the amount of NEDSCP Cash Credits so forfeited. (d) Retirement Benefit Account. A Director's Retirement Benefit Account shall be denominated in shares of Common Stock, including fractional shares. Effective as of January 1, 1998, Section 5 of Article III of the Company's Bylaws has been amended to eliminate with respect to all persons who are Directors as of January 1, 1998 a provision for a retirement benefit payable 2 to Directors who retire from the Board at age 72 with at least 10 years of service. Effective as of January 1, 1998, the Retirement Benefit Account of each person who is a Director on that date shall be credited with a number a shares of Common Stock determined by the Company as a replacement for the prior retirement benefit. As of each date for payment of dividends on the Common Stock, the Retirement Benefit Accounts shall be credited with an additional number of shares (including fractional shares) equal to the amount of dividends that would be paid on the number of shares recorded as the balance of the Retirement Benefit Account as of the record date for such dividend divided by the purchase price for shares of Common Stock under the DRSPP for dividends reinvested on such payment date. The Retirement Benefit Account of a Director shall be canceled, and all amounts credited to such account shall be forfeited, if the Director ceases to be a Director before reaching age 70 or before serving as a Director for 10 years; provided, however, that each Director's Retirement Benefit Account will be fully vested and noncancellable upon the death of the Director, the disability (within the meaning of Section 22(e)(3) of the Internal Revenue Code) of the Director, or a Change in Control as defined in Paragraph 8. (e) Statement of Account. At the end of each calendar quarter, a report shall be issued by the Company to each participating Director setting forth the balances of the Director's Accounts under the Plan. The credit entries made to a Director's Accounts constitute merely a general obligation of the Company to pay such Accounts to the Director, or to his or her beneficiary or estate when due under the Plan. (f) Effect of Corporate Transaction on Stock Accounts and Retirement Benefit Accounts. At the time of consummation of a Corporate Transaction, if any, the amount credited to a Director's Stock Account and Retirement Benefit Account shall be converted into a credit for cash or common stock of the acquiring company ("Acquiror Stock") based on the consideration received by shareholders of the Company in the Corporate Transaction, as follows: (i) Stock Transaction. If holders of Common Stock receive Acquiror Stock in the Corporate Transaction, then (1) the amount credited to each Director's Stock Account and/or Retirement Benefit Account shall be converted into a credit for the number of shares of Acquiror Stock that the Director would have received as a result of the Corporate Transaction if the Director had actually held the Common Stock credited to his or her Stock Account and/or Retirement Benefit Account immediately prior to the consummation of the Corporate Transaction, and (2) Stock Accounts and Retirement Benefit Accounts will thereafter be denominated in shares of Acquiror Stock and ongoing deferrals of Fees and NEDSCP Shares, if any, shall continue to be made in accordance with outstanding deferral elections into the Stock Accounts as so denominated. (ii) Cash or Other Property Transaction. If holders of Common Stock receive cash or other property in the Corporate Transaction, then (1) the amount credited to a Director's Stock Account and/or Retirement Benefit Account shall be transferred to the Director's Cash Account and converted into a cash credit for the amount of cash or the value of the property that the Director would have received as a result of the Corporate Transaction if the Director had actually held the Common Stock credited to his or her Stock Account and/or Retirement Benefit Account immediately prior to the consummation of the Corporate Transaction, and (2) Stock Accounts shall no longer exist under the 3 Plan and all ongoing deferrals, if any, shall thereafter be made into Cash Accounts. (iii) Combination Transaction. If holders of Common Stock receive Acquiror Stock and cash or other property in the Corporate Transaction, then (1) the amount credited to each Director's Stock Account and/or Retirement Benefit Account shall be converted in part into a credit for Acquiror Stock under Paragraph 3(f)(i) and in part into a credit for cash under Paragraph 3(f)(ii) in the same proportion as such consideration is received by shareholders, and (2) ongoing deferrals of Fees and NEDSCP Shares, if any, shall continue to be made in accordance with outstanding deferral elections into Stock Accounts in accordance with Paragraph 3(f)(i). (iv) Election Following Stock Transaction. For a period of 12 months following the consummation of any Corporate Transaction which results in Directors having Stock Accounts and/or Retirement Benefit Accounts denominated in Acquiror Stock, each Director shall have a one-time right to elect to transfer the entire amount in the Director's Stock Account and Retirement Benefit Account into the Director's Cash Account. Such election shall be made by written notice to the Company and shall be effective on the date received by the Company. If such an election is made, the amount of cash to be credited to the Director's Cash Account shall be determined by multiplying the number of shares of Acquiror Stock in the Director's Stock Account and Retirement Benefit Account by the closing market price of the Acquiror Stock reported for the last trading day preceding the effective date of the election. 4. Interest. Interest shall be credited to the Cash Account balance (including both principal and interest) of each participating Director based on the balance at the end of each calendar quarter. The rate of interest to be applied at the end of each calendar quarter shall be the quarterly equivalent of an annual yield that is two (2%) percentage points higher than the annual yield on Moody's Average Corporate Bond Yield for the preceding quarter, as published by the Moody's Investors Service, Inc. (or any successor thereto), or if such index is no longer published, a substantially similar index selected by the Board. At no time shall the interest rate be less than six percent (6%) annually. The interest credit shall continue to be applied to the Cash Account of a Director, even if ceasing to serve as a Director, until all amounts credited to his or her Cash Account have been paid. Said interest shall be calculated quarterly, based upon the average daily balance of the Director's Cash Account since the preceding calendar quarter, after giving effect to any reduction in the Cash Account as a result of any payments. The remaining annual payments will be recomputed to reflect the additional interest credits. 5. Terms of Payment. (a) Plan Benefits. The amounts contained in a Director's Accounts are subject to the terms of payment as set forth in this paragraph. When a Director ceases to serve as a Director of the Company, either by retirement or otherwise, the individual shall be entitled to payment of the amounts in his or her Accounts. (b) Timing of Benefit Payment. At the time the Director elects to defer Fees or NEDSCP Shares or to receive NEDSCP Cash Credits in lieu of NEDSCP Shares, and with respect to Retirement Benefit Accounts before January 1, 1998, 4 the Director may designate the number of annual installments, not to exceed ten, in which the applicable Account balance shall be paid, or the Director may elect to receive such Account balance in a lump sum payment, or in a combination of a partial lump sum and the remainder in installment payments. A Director may elect to modify such election by filing a change of payment designation which shall supersede the prior form of payment designation for any one (1) or more deferral periods. If the Director's most recent change of payment designation has not been filed one (1) full calendar year prior to the year in which the Director ceases to serve as a Director of the Company, the prior election shall be used to determine the form of payment. For example, a Director leaving the Board in 2003 must file a written request with the Committee by December 31, 2001 to change his form of payment designation. (c) Form of Benefit Payment. Benefits payable to a Director from a Stock Account or a Retirement Benefit Account shall only be paid to such Director as a distribution of Common Stock plus cash for fractional shares. Benefits payable to a Director from a Cash Account shall only be paid to such Director in cash. (d) Commencement of Payment. Any lump sum payment or the first annual installment payment owed to a Director shall not be due earlier than the first business day of January in the year following the year in which he or she ceases to serve as a Director of the Company. In the event a Director terminates the election to defer Fees or NEDSCP Shares, any Fees or NEDSCP Shares already deferred shall not be payable to the Director until such time as he or she ceases to serve as a Director, and then only subject to the terms and conditions contained herein. The provisions of this paragraph are subject to the terms of Paragraph 6 covering the death of a Director and to the terms of Paragraph 8 covering a Change in Control. (e) Payment to Guardian. If a benefit under the Plan is payable to a minor or a person declared incompetent or to a person incapable of handling the disposition of his property, the Committee may direct payment of such Plan benefit to the guardian, legal representative or person responsible for the care and custody of such minor, incompetent or person. The Committee may require proof of incompetence, minority, incapacity or guardianship as it may deem appropriate prior to distribution of the Plan benefit. Such distribution shall completely discharge the Committee and the Company from all liability with respect to such benefit. (f) Withholding; Payroll Taxes. The Company shall withhold from payments made hereunder any taxes required to be withheld from such payments under federal, state or local law. (g) Accelerated Distribution. Notwithstanding any other provision of the Plan, a Director shall be entitled to receive, upon written request to the Committee, a lump sum distribution equal to ninety percent (90%) of the vested Account balance as of the last day of the calendar quarter immediately preceding the day on which the Committee receives the written request. The remaining balance shall be forfeited by the Director. A Director who receives a distribution under this section shall be suspended from participation in the Plan for 12 months, but such suspension shall not apply to crediting of NEDSCP Cash Credits. The amount payable under this section shall be paid in a lump sum 5 within 65 days following the receipt of the notice by the Committee from the Director. 6. Death of Director. (a) Plan Death Benefit. Upon the death of a Director or a former Director prior to the receipt of the full amount credited to his or her Accounts, the balance of the Director's Accounts shall be paid to the designated beneficiary or beneficiaries in the manner elected in writing by the Director at the time of the deferral election, or if no such election is made, by lump sum payment. (b) Beneficiary. At the time a Director elects to defer payment of Fees or NEDSCP Shares or to receive NEDSCP Cash Credits in lieu of NEDSCP Shares, and with respect to Retirement Benefit Accounts before January 1, 1998, the Director may designate a beneficiary or beneficiaries. If greater than 50% of the benefit is designated to a beneficiary other than the Director's spouse, such beneficiary designation shall be consented to by the Director's spouse. Such designation may be changed by the Director at any time without the consent of a beneficiary, subject to the spousal consent requirement above. If no designated beneficiary survives the Director or former Director, the balance of the Director's Accounts shall be paid to the Director's estate. 7. Administration. (a) Committee Duties. This Plan shall be administered by the Organization and Executive Compensation Committee of the Board (the "Committee"). The Committee shall have responsibility for the general administration of the Plan and for carrying out its intent and provisions. The Committee shall interpret the Plan and have such powers and duties as may be necessary to discharge its responsibilities. The Committee may, from time to time, employ other agents and delegate to them such administrative duties as it sees fit, and may from time to time consult with counsel who may be counsel to the Company. (b) Binding Effect of Decisions. The decision or action of the Committee in respect of any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan. (c) Indemnity of Committee. To the extent permitted by applicable law, the Company shall indemnify, hold harmless and defend the members of the Committee against any and all claims, loss, damage, expense or liability arising from any action or failure to act with respect to this Plan, provided that the members of the Committee were acting in accordance with the applicable standard of care. 8. Definitions; Change in Control; Corporate Transaction. (a) For purposes of this Plan, a "Change in Control" of the Company shall mean the occurrence of any of the following events: 6 (i) The approval by the shareholders of the Company of: (A) any consolidation, merger or plan of share exchange involving the Company (a "Merger") as a result of which the holders of outstanding securities of the Company ordinarily having the right to vote for the election of directors ("Voting Securities") immediately prior to the Merger do not continue to hold at least 50% of the combined voting power of the outstanding Voting Securities of the surviving corporation or a parent corporation of the surviving corporation immediately after the Merger, disregarding any Voting Securities issued to or retained by such holders in respect of securities of any other party to the Merger; (B) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets of the Company; or (C) the adoption of any plan or proposal for the liquidation or dissolution of the Company; (ii) At any time during a period of two consecutive years, individuals who at the beginning of such period constituted the board of directors of the Company ("Incumbent Directors") shall cease for any reason to constitute at least a majority thereof; provided, however, that the term "Incumbent Director" shall also include each new director elected during such two-year period whose nomination or election was approved by two-thirds of the Incumbent Directors then in office; or (iii) Any person (as such term is used in Section 14(d) of the Securities Exchange Act of 1934, other than the Company or any employee benefit plan sponsored by the Company) shall, as a result of a tender or exchange offer, open market purchases or privately negotiated purchases from anyone other than the Company, have become the beneficial owner (within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934), directly or indirectly, of Voting Securities representing twenty percent (20%) or more of the combined voting power of the then outstanding Voting Securities. (b) For purposes of this Plan, a "Corporate Transaction" shall mean any of the following: (i) any consolidation, merger or plan of share exchange involving the Company (a "Merger") pursuant to which shares of Common Stock would be converted into cash, securities or other property; (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets of the Company; or (iii) the adoption of any plan or proposal for the liquidation or dissolution of the Company. 7 9. Amendment and Termination of the Plan. (a) Amendment. The Board may at any time amend the Plan in whole or in part; provided, however, that upon a Change in Control, no amendment shall be effective to change the payout schedule in Paragraph 9(b)(ii), and further provided that no amendment shall decrease or restrict the amount credited to any Account maintained under the Plan as of the date of amendment. An amendment affecting the interest rate credited under Paragraph 4 shall not become effective before the first day of the calendar year which follows the adoption of the amendment and at least 30 days written notice of the amendment to the Director. An amendment affecting the interest rate credited under Paragraph 4 that is adopted after a Change in Control shall apply only to those amounts credited to Directors' Accounts after the Change in Control. (b) Termination. The Board may at any time partially or completely terminate the Plan if, in its judgment, the tax, accounting, or other effects of the continuance of the Plan, or potential payments thereunder, would not be in the best interests of the Company. (i) Partial Termination. The Board may partially terminate the Plan by instructing the Committee not to accept any additional deferrals. In the event of such a partial termination, the Plan shall continue to operate and be effective with regard to deferrals entered into prior to the effective date of such partial termination. (ii) Complete Termination. The Board may completely terminate the Plan by instructing the Committee not to accept any additional deferrals, and terminate all ongoing deferrals. The Plan shall cease to operate and the Committee shall pay out to each Director the balance in each of his or her Accounts in a lump sum or in equal annual installments amortized over the period listed in the payout schedule below based on the balance in the particular Account at the time of such complete termination: PAYOUT SCHEDULE - -------------------------------------------------------------------------------- APPROPRIATE ACCOUNT BALANCE PAYOUT PERIOD - -------------------------------------------------------------------------------- Less than $10,000 Lump sum $10,000 but less than $50,000 Lesser of 5 years or period elected in Participation Agreement More than $50,000 Period elected in Participation Agreement ================================================================================
Interest earned on the unpaid balance in the Director's Cash Account shall be the applicable interest rate at the end of the calendar quarter immediately preceding the effective date of such complete termination. 8 10. Miscellaneous. (a) Unsecured General Creditor. The Accounts shall be established solely for the purpose of measuring the amounts owed to a Director or beneficiary under the Plan. Directors and their beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interest or claims in any property or assets of the Company, nor shall they be beneficiaries of, or have any rights, claims or interests in any life insurance policies, annuity contracts or the proceeds therefrom owned or which may be acquired by the Company. Except as may be provided in Paragraph 10(b), such policies, annuity contracts or other assets of the Company shall not be held under any trust for the benefit of the Directors, their beneficiaries, heirs, successors or assigns, or held in any way as collateral security for the fulfilling of the obligations of the Company under this Plan. Any and all of the Company's assets and policies shall be, and remain, the general, unpledged, unrestricted assets of the Company. The Company's obligation under the Plan shall be that of an unfunded and unsecured promise to pay money in the future. (b) Trust Fund. The Company shall be responsible for the payment of all benefits provided under the Plan. At its discretion, the Company may establish one or more trusts, with such trustees as the Board may approve, for the purpose of providing for the payment of such benefits. Such trust or trusts may be irrevocable, but the assets thereof shall be subject to the claims of the Company's creditors. To the extent any benefits provided under the Plan are actually paid from any such trust, the Company shall have no further obligation with respect thereto, but to the extent not so paid, such benefits shall remain the obligation of, and shall be paid by, the Company. (c) Nonassignability. No assignment or alienation may be made of any deferred fees or interest thereon, except in accordance with Paragraph 6. (d) Governing Law. The provisions of this Plan shall be construed and interpreted according to the laws of the State of Oregon. (e) Successors. The provisions of this Plan shall bind and inure to the benefit of the Company and its successors and assigns. The term successors as used herein shall include any corporate or other business entity which shall, whether by merger, consolidation, purchase or otherwise acquire all or substantially all of the business and assets of the Company, and successors of any such corporation or other business entity. (f) The foregoing restatement of the Plan was approved by the Board of Directors of Northwest Natural Gas Company on February 26, 2004. NORTHWEST NATURAL GAS COMPANY By: /s/ Mark S. Dodson ------------------------------- Attest: /s/ C.J. Rue ------------------------ 9 EX-10 4 ex10i.txt EX. 10I - NON-EMPLOYEE DIRECTORS STOCK COMP. PLAN EXHIBIT (10i.) NORTHWEST NATURAL GAS COMPANY NON-EMPLOYEE DIRECTORS STOCK COMPENSATION PLAN January 1, 1989 Northwest Natural Gas Company an Oregon corporation 220 NW Second Avenue Portland, OR 97209 the Company The Company believes it desirable that members of its board of directors, who represent the Company's shareholders, be themselves shareholders. To supplement the efforts of the directors towards this end, the Company wishes to increase the ownership interest of non-employee directors through awards of Company Common Stock. The Company, however, recognizes that a director may believe that he or she has a sufficient ownership interest in Company Common Stock, and therefore permits directors to receive awards under the plan in the form of deferred cash rather than stock. The following plan is therefore adopted: 1. Administration. -------------- Unless otherwise determined pursuant to this section, this plan shall be administered by the corporate secretary of the Company (the Administrator), who may delegate all or part of that authority and responsibility. The Administrator shall interpret the plan, arrange for the purchase and delivery of shares, determine forfeitures, and otherwise assume general responsibility for administration of the plan. Any decision by the Administrator shall be final and bind all parties. The Administrator may be replaced from time to time in the discretion of the chief executive officer of the Company. 2. Awards. ------ 2.1 Each non-employee director of the Company, including those directors who have been employees of the Company in the past but are not employees at the time of any award under this plan, shall receive awards under this plan as of the following award dates: (a) January 1, 1989; or (b) In the case of (i) directors elected after January 1, 1989 and (ii) persons who become non-employee directors after January 1, 1989 by ceasing to be employees of the Company, the date on which such director is first elected, whether by the shareholders or board of directors of the Company, or ceases to be an employee of the Company, as the case may be; and (c) On January 1 of each year thereafter, commencing with January 1, 1998. 2.2 As of each award date, a participant shall receive an award calculated in the following manner. The "Number of Award Months" shall be determined by subtracting the number of full or partial calendar months remaining until all, if any, previous awards to the participant under this plan will be vested from the number of full or partial calendar months remaining until the fifth year end after the award date; provided, however, that if, assuming the participant were reelected, a participant's term as a director would end because of age before the fifth year end after the award date, the "Number of Award Months" shall be determined by subtracting the number of full or partial calendar months remaining until all, if any, previous awards to the participant under this plan will be vested from the number of full or partial calendar months remaining until the participant's term will end because of age. The amount awarded shall then be calculated by multiplying the Number of Award Months by an amount that, effective as of October 1, 2002, shall be $1,666.67. For purposes of this plan, "full or partial calendar months remaining" for any period includes the calendar month in which the award date falls and the calendar month in which the last day of the period falls and all calendar months in between. 2.3 As of each award date, the dollar amount calculated under 2.2 shall be awarded to the participant as follows: (a) With respect to award dates after February 26, 2004, each participant may elect at any time prior to an award date to receive the entire amount to be awarded on that date in deferred cash rather than in Company Common Stock. No partial elections shall be permitted. Any such election must be in writing delivered to the Administrator prior to the award date. If such an election is made, the dollar amount calculated under 2.2 shall be credited to the participant's Cash Account under the Company's Directors Deferred Compensation Plan (the "DDCP") effective as of the award date. The deferred cash amounts shall be subject to vesting under 3, but any interest credited with respect to these amounts under the DDCP shall be fully vested and nonforfeitable at all times. The deferred cash amounts shall otherwise be subject to all of the terms and conditions of the DDCP. (b) If a participant does not timely elect to receive an award in deferred cash, the dollar amount calculated under 2.2 shall be awarded to the participant in Common Stock as follows: (i) As soon as practicable after the award date, the Administrator shall deliver cash in the amount of the award and applicable commissions to one or more brokers or other persons with instructions to purchase Company Common Stock in the open market. It is understood that market conditions or regulations affecting the purchases by a corporation of its own shares may extend the period of purchase over several days or weeks. (ii) When several participants have the same award date, all of the stock shall be purchased and then divided among the participants in proportion to their respective awards, regardless of any changes in price that occur while purchases are being carried out. 2 (iii) When all of the stock has been purchased with respect to any award date, certificates in the names of the participants for their respective shares shall be delivered to the Administrator. Each participant shall deliver to the Administrator a blank stock power duly executed in a form satisfactory to the Administrator for each certificate for shares issued in the participant's name. (iv) The Administrator shall hold the certificates and stock powers until the shares are vested and released as provided in 3.4. 2.4 Upon any amendment of this plan to increase the dollar amount of awards set forth in 2.2, each participant shall receive an additional award in accordance with the procedures set forth in 2.3. The amount of the additional award for each participant shall be determined by multiplying the amount of the increase in the award amount by the number of full or partial calendar months remaining until the participant's most recent prior award under this plan will be fully vested. The resulting dollar amount shall then be either used to purchase Common Stock for the participant or credited under the DDCP as set forth in 2.3. 3. Vesting; Delivery of Shares; Forfeitures. ---------------------------------------- 3.1 For each award under 2.2 and 2.3, the number of awarded shares or the amount of awarded cash, as applicable, that will vest per month shall be determined by dividing the number of awarded shares or the amount of awarded cash by the Number of Award Months. This monthly amount shall vest as of the first day of each calendar month commencing with the later of the month in which the award is made or the first month after all previous awards to the participant under this plan shall have vested. If an award is made other than on the first day of a month, the award date shall be considered the first day of that month for purposes of 3.1 and 3.2. 3.2 For each award under 2.3 and 2.4, the number of awarded shares or the amount of awarded cash, as applicable, that will vest per month shall be determined by dividing the number of awarded shares or the amount of awarded cash by the number of full or partial calendar months remaining until the participant's most recent prior award under 2.2 and 2.3 will be fully vested. This monthly amount shall vest as of the first day of each calendar month commencing with the month in which the award is made. 3.3 Notwithstanding 3.1 and 3.2, all awarded shares and awarded cash shall vest upon a change in control of the Company. For purposes of this plan, a "change in control" of the Company shall mean the occurrence of any of the following events: (a) The approval by the shareholders of the Company of: (1) any consolidation, merger or plan of share exchange involving the Company (a "Merger") as a result of which the holders of outstanding securities of the Company ordinarily having the right to vote for the election of directors ("Voting Securities") immediately prior to the Merger do not continue to hold at least 50% of the combined voting power of the outstanding Voting Securities of the surviving corporation or a parent corporation of the surviving corporation immediately after the 3 Merger, disregarding any Voting Securities issued to or retained by such holders in respect of securities of any other party to the Merger; (2) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all, or substantially all, the assets of the Company; or (3) the adoption of any plan or proposal for the liquidation or dissolution of the Company; (b) At any time during a period of two consecutive years, individuals who at the beginning of such period constituted the board of directors of the Company ("Incumbent Directors") shall cease for any reason to constitute at least a majority thereof; provided, however, that the term "Incumbent Director" shall also include each new director elected during such two-year period whose nomination or election was approved by two-thirds of the Incumbent Directors then in office; or (c) Any person (as such term is used in Section 14(d) of the Securities Exchange Act of 1934, other than the Company or any employee benefit plan sponsored by the Company) shall, as a result of a tender or exchange offer, open market purchases or privately negotiated purchases from anyone other than the Company, have become the beneficial owner (within the meaning of Rule 13d-3 under the Securities Exchange Act of 1934), directly or indirectly, of Voting Securities representing twenty percent (20%) or more of the combined voting power of the then outstanding Voting Securities. 3.4 The certificate and stock power for vested shares shall be delivered to the participant or in accordance with 5.2 as soon as practicable after the participant ceases to be a director of the Company or, if earlier, as soon as practicable after a change in control of the Company. Payment of vested deferred cash shall be governed by the terms of the DDCP. 3.5 If a participant ceases to be a director (other than pursuant to a simultaneous change in control of the Company), awarded shares and awarded cash remaining unvested shall be forfeited. The Administrator, acting for the participant pursuant to the executed stock power, shall transfer the unvested shares to the Company, and these shares shall be cancelled. The participant or the participant's representative shall execute any documents reasonably requested by the Administrator to facilitate the transfer. The participant's Cash Account under the DDCP shall be reduced by the amount of unvested cash that is forfeited. 4. Status Before Full Vesting; Transfer of Shares. ---------------------------------------------- 4.1 Each participant shall be a shareholder of record with respect to all shares awarded, whether or not vested, and shall be entitled to all of the rights of such a holder, except that a participant's share certificates shall be held by the Administrator until delivered in accordance with 3.4. 4.2 Any dividends or communications to shareholders received by the Administrator with respect to shares held by the Administrator shall promptly be transmitted to the participant. 4 4.3 No participant may transfer any interest in unvested shares to any person other than the Company. 4.4 No participant may transfer any interest in any shares awarded under this plan, whether vested or not, until he or she ceases to be a director of the Company. 4.5 Notwithstanding 2.3(b)(iv), 3.4, 4.1, 4.3 and 4.4, if a participant in the DDCP elects under the DDCP to defer shares of Company Common Stock awarded to the participant under this plan, promptly after the deferral election becomes irrevocable the Administrator shall cause the Common Stock subject to such irrevocable deferral to be transferred to the trustee of the Northwest Natural Gas Company Umbrella Trust(TM) For Directors. The Common Stock so transferred shall nevertheless remain subject to forfeiture under 3.5 if the participant ceases to be a director prior to vesting of the shares. 5. Death of a Participant. ---------------------- 5.1 Any vested shares held by the Administrator for a participant who has died shall be delivered as soon as practicable to the participant's death beneficiary under 5.2. 5.2 Any vested shares to be delivered on death of a participant under 5.1 shall go to a participant's beneficiary in the following order of priority: (a) To the surviving beneficiary designated by the participant in writing to the Administrator; (b) To the participant's surviving spouse; or (c) To the participant's estate. 6. Amendment or Termination; Miscellaneous. --------------------------------------- 6.1 The board of directors of the Company may amend or terminate this plan at any time. No amendment or termination shall adversely affect any outstanding award. 6.2 Subject to the rights of amendment and termination in 6.1, this plan shall continue indefinitely and future awards will be made in accordance with 2.1. 6.3 Nothing in this plan shall create any obligation on the part of the board of directors of the Company to nominate any director for reelection by the shareholders or the board of directors. Adopted by the board of directors of Northwest Natural Gas Company on November 17, 1988, effective January 1, 1989. Amended by the board of directors of Northwest Natural Gas Company on May 23, 1991, effective July 1, 1991. Amended by the board of directors of Northwest Natural Gas Company on July 24, 1997, effective July 1, 1997. Amended by the board of directors of Northwest Natural Gas Company on December 18, 1997, effective January 1, 1998. Amended by 5 the board of directors of Northwest Natural Gas Company on September 26, 2002, effective October 1, 2002. Amended by the board of directors of Northwest Natural Gas Company on February 26, 2004, effective February 26, 2004. 6 EX-11 5 ex11.txt EX. 11 - STATEMENT RE: COMPUTATION OF EARNINGS EXHIBIT (11) NORTHWEST NATURAL GAS COMPANY Statement Re: Computation of Per Share Earnings (Thousands, except per share amounts) (Unaudited)
Thousands, except per share amounts 2003 2002 2001 - -------------------------------------------------------------------------------------- Net income $ 45,983 $ 43,792 $ 50,187 Redeemable preferred and preference stock dividend requirements 294 2,280 2,401 -------- -------- -------- Earnings applicable to common stock - basic 45,689 41,512 47,786 Debenture interest less taxes 257 285 370 -------- -------- -------- Earnings applicable to common stock - diluted $ 45,946 $ 41,797 $ 48,156 ======== ======== ======== Average common shares outstanding - basic 25,741 25,431 25,159 Stock options 28 59 32 Convertible debentures 292 324 421 -------- -------- -------- Average common shares outstanding - diluted 26,061 25,814 25,612 ======== ======== ======== Earnings per share of common stock - basic $ 1.77 $ 1.63 $ 1.90 ======== ======== ======== Earnings per share of common stock - diluted $ 1.76 $ 1.62 $ 1.88 ======== ======== ========
For the years ended Dec. 31, 2003, 2002 and 2001, 77,500 shares, 84,000 shares and 138,491 shares, respectively, representing the number of stock options the exercise prices for which were greater than the average market prices for such years, were excluded from the calculation of diluted earnings per share because the effect was antidilutive. EX-12 6 ex12.txt COMPUTATION OF RATIOS Exhibit (12) NORTHWEST NATURAL GAS COMPANY Computation of Ratio of Earnings to Fixed Charges January 1, 1999 - December 31, 2003 (Thousands, except ratio of earnings to fixed charges) (Unaudited)
Year Ended December 31 -------------------------------------------------------------------- 2003 2002 2001 2000 1999 ---- ---- ---- ---- ---- Fixed Charges, as Defined: Interest on Long-Term Debt $ 33,258 $ 32,264 $ 30,224 $ 29,987 $ 27,728 Other Interest 2,048 1,620 3,772 3,628 2,778 Preferred and Preference Stock Dividends 294 2,280 2,401 2,456 2,515 Amortization of Debt Discount and Expense 696 799 768 735 699 Interest Portion of Rentals 1,622 1,578 1,572 1,628 1,707 ----------- ----------- ----------- ----------- ----------- Total Fixed Charges, as defined $ 37,918 $ 38,541 $ 38,737 $ 38,434 $ 35,427 =========== =========== =========== =========== =========== Earnings, as Defined: Net Income $ 45,983 $ 43,792 $ 50,187 $ 50,224 $ 45,296 Taxes on Income 23,340 23,444 27,553 26,829 24,591 Fixed Charges, as above 37,918 38,541 38,737 38,434 35,427 ----------- ----------- ----------- ----------- ----------- Total Earnings, as defined $ 107,241 $ 105,777 $ 116,477 $ 115,487 $ 105,314 =========== =========== =========== =========== =========== Ratio of Earnings to Fixed Charges 2.83 2.74 3.01 3.00 2.97 =========== =========== =========== =========== ===========
For consistency in reporting, total fixed charges in all years include dividends on redeemable preferred and preferense stock, which were reclassified as interest expense beginning July 1, 2003, upon adoption of SFAS No. 150. EX-23 7 ex23.txt EX. 23 - CONSENT OF INDEPENDENT ACCOUNTANTS EXHIBIT (23) CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 33-63017, 333-46430, 333-55002, 333-70218 and 333-100885, and Post-Effective Amendment No. 1 to Registration Statement No. 2-76276) and in the Registration Statements on Form S-3 (Nos. 33-53795 and 333-112604, and Post-Effective Amendment No. 1 to Registration Statement Nos. 33-1304, 33-20384, and 333-68184) of Northwest Natural Gas Company of our report dated February 26, 2004 relating to the consolidated financial statements and financial statement schedule, which appears in this Form 10-K. /s/ PricewaterhouseCoopers LLP Portland, Oregon March 9, 2004 EX-31 8 ex31_1.txt EX. 31.1 - CERT. OF PRESIDENT AND CEO EXHIBIT (31.1) CERTIFICATION I, Mark S. Dodson, certify that: 1. I have reviewed this annual report on Form 10-K of Northwest Natural Gas Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 9, 2004 /s/ Mark S. Dodson - ------------------------------------- Mark S. Dodson President and Chief Executive Officer EX-31 9 ex31_2.txt EX. 31.2 - CERT. OF SENIOR VP, FINANCE AND CFO EXHIBIT (31.2) CERTIFICATION I, Bruce R. DeBolt, certify that: 1. I have reviewed this annual report on Form 10-K of Northwest Natural Gas Company; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: March 9, 2004 /s/ Bruce R. DeBolt - ---------------------------------- Bruce R. DeBolt Senior Vice President, Finance and Chief Financial Officer EX-32 10 ex32_1.txt EX. 32.1 - CERTIFICATE PURSUANT TO SECTION 906 EXHIBIT (32.1) NORTHWEST NATURAL GAS COMPANY Certificate Pursuant to Section 906 of Sarbanes - Oxley Act of 2002 Each of the undersigned, MARK S. DODSON, the President and Chief Executive Officer, and BRUCE R. DEBOLT, the Senior Vice President, Finance, and Chief Financial Officer, of NORTHWEST NATURAL GAS COMPANY (the Company), DOES HEREBY CERTIFY that: 1. The Company's Annual Report on Form 10-K for the year ended December 31, 2003 (the Report) fully complies with the requirements of section 13(a) of the Securities Exchange Act of 1934, as amended; and 2. Information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company. IN WITNESS WHEREOF, each of the undersigned has caused this instrument to be executed this 9th day of March 2004. /s/ Mark S. Dodson ----------------------------------- President and Chief Executive Officer /s/ Bruce R. DeBolt ----------------------------------- Senior Vice President, Finance, and Chief Financial Officer A signed original of this written statement required by Section 906 has been provided to Northwest Natural Gas Company and will be retained by Northwest Natural Gas Company and furnished to the Securities and Exchange Commission or its staff upon request. -----END PRIVACY-ENHANCED MESSAGE-----